Item 1A.
Risk Factors
Risks Related to Our Business
Our trading policies cannot eliminate all price risks. In addition, any non-compliance with our trading policies could result in significant financial losses.
Generally, it is our policy that we establish a margin for crude oil we purchase by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation under futures contracts on the NYMEX, ICE and over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. Our policy is generally not to acquire and hold physical inventory, futures contracts or derivative products for the purpose of speculating on commodity price changes. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply of crude oil could expose us to risk of loss resulting from price changes. We are also exposed to basis risk when crude oil is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on certain of our inventory, such as linefill, which must be maintained in order to transport crude oil on our pipelines. In addition, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. Although this activity is monitored independently by our risk management function, it exposes us to price risks within predefined limits and authorizations.
In addition, our trading operations involve the risk of non-compliance with our trading policies. For example, we discovered in November 1999 that our trading policy was violated by one of our former employees, which resulted in aggregate losses of approximately $181.0 million. We have taken steps within our organization to enhance our processes and procedures to detect future unauthorized trading. We cannot assure you, however, that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception or other intentional misconduct is involved.
The nature of our business and assets exposes us to significant compliance costs and liabilities. Our asset base has more than tripled within the last three years. We have experienced a corresponding increase in the relative number of releases of crude oil to the environment. Substantial expenditures may be required to maintain the integrity of aged and aging pipelines and terminals at acceptable levels.
Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons, including crude oil and refined products, as well as our operations involving the storage of natural gas, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety and related matters. Compliance with all of these laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit our operations, or claims of damages to property or persons resulting from our operations. The laws and regulations applicable to our operations are subject to change and interpretation by the relevant governmental agency. Any such
change or interpretation adverse to us could have a material adverse effect on our operations, revenues and profitability.
Today we own approximately three times the miles of pipeline we owned three years ago. As we have expanded our pipeline assets, we have observed a corresponding increase in the number of releases of crude oil to the environment. These releases expose us to potentially substantial expense, including clean-up and remediation costs, fines and penalties, and third party claims for personal injury or property damage related to past or future releases. Some of these expenses could increase by amounts disproportionately higher than the relative increase in pipeline mileage and the increase in revenues associated therewith. During 2006, we entered the refined products pipeline and terminalling businesses through the acquisition of three products pipeline systems in West Texas and New Mexico and through the acquisition of Pacific, which had refined product assets in California, the U.S. Rockies and Pennsylvania. These businesses are also subject to significant compliance costs and liabilities. In addition, because of their increased volatility and tendency to migrate farther and faster than crude oil, releases of refined products into the environment can have more significant impact than crude oil and require significantly higher expenditures to respond and remediate. The incurrence of such expenses not covered by insurance, indemnity or reserves could materially adversely affect our results of operations.
We currently spend substantial amounts to comply with DOT-mandated pipeline integrity rules. The 2006 Pipeline Safety Act, enacted in December 2006, requires the DOT to issue regulations for certain pipelines that were not previously subject to regulation. These regulations could include requirements for the establishment of additional pipeline integrity management programs for these newly regulated pipelines. We do not currently know what, if any, impact this will have on our operating expenses.
In addition to performing DOT-mandated pipeline integrity evaluations, during 2006, we expanded an internal review process started in 2005 pursuant to which we review various aspects of our pipeline and gathering systems that are not subject to the DOT pipeline integrity management rules. The purpose of this process is to review the surrounding environment, condition and operating history of these pipeline and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, we could be required (as a result of additional DOT regulation) or we may elect (as a result of our own internal initiatives) to spend substantial sums to ensure the integrity of and upgrade our pipeline systems to maintain environmental compliance and, in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.
Loss of credit rating or the ability to receive open credit could negatively affect our ability to use the counter-cyclical aspects of our asset base or to capitalize on a volatile market.
We believe that, because of our strategic asset base and complementary business model, we will continue to benefit from swings in market prices and shifts in market structure during periods of volatility in the crude oil market. Our ability to capture that benefit, however, is subject to numerous risks and uncertainties, including our maintaining an attractive credit rating and continuing to receive open credit from our suppliers and trade counter-parties.
We may not be able to fully implement or capitalize upon planned growth projects.
We have a number of organic growth projects that require the expenditure of significant amounts of capital, including the Pier 400 project, the Salt Lake City expansion, the Cheyenne pipeline project, the Pine Prairie joint venture and the St. James, Cushing and Patoka terminal projects. Many of these projects involve numerous regulatory, environmental, weather-related, political and legal uncertainties that will be beyond our control. As these projects are undertaken, required approvals may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, revenues associated with these organic growth projects will not increase immediately upon the expenditures of funds with respect to a particular project and these projects may be completed behind schedule or in excess of budgeted cost. Because of continuing increased demand for materials, equipment and services, there could be shortages and cost increases associated with construction projects. We may construct pipelines, facilities or other assets in anticipation
of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.
The level of our profitability is dependent upon an adequate supply of crude oil from fields located offshore and onshore California. A shut-in of this production due to economic limitations or a significant event could adversely affect our profitability. In addition, these offshore fields have experienced substantial production declines since 1995.
A significant portion of our segment profit is derived from pipeline transportation margins associated with the Santa Ynez and Point Arguello fields located offshore California and the onshore fields in the San Joaquin Valley. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. We estimate that a 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual transportation segment profit of approximately $6.1 million. A similar decline in volumes shipped from the San Joaquin Valley would result in an estimated $3.2 million decrease in annual transportation segment profit. In addition, any significant production disruption from the outer continental shelf fields and the San Joaquin Valley due to production problems, transportation problems or other reasons could have a material adverse effect on our business.
Our profitability depends on the volume of crude oil, refined product and LPG shipped, purchased and gathered.
Third party shippers generally do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. For example, we estimate that an average 20,000 barrel per day variance in the Basin Pipeline System within the current operating window, equivalent to an approximate 7% volume variance on that system, would change annualized segment profit by approximately $1.8 million. In addition, we estimate that an average 10,000 barrel per day variance on the Capline Pipeline System, equivalent to an approximate 8% volume variance on that system, would change annualized segment profit by approximately $1.3 million.
To maintain the volumes of crude oil we purchase in connection with our operations, we must continue to contract for new supplies of crude oil to offset volumes lost because of natural declines in crude oil production from depleting wells or volumes lost to competitors. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where relationships already exist between producers and other gatherers and purchasers of crude oil. We estimate that a 15,000 barrel per day decrease in barrels gathered by us would have an approximate $2.7 million per year negative impact on segment profit. This impact assumes a reasonable margin throughout various market conditions. Actual margins vary based on the location of the crude oil, the strength or weakness of the market and the grade or quality of crude oil. We estimate that a $0.01 variance in the average segment profit per barrel would have an approximate $4.2 million annual effect on segment profit.
Fluctuations in demand can negatively affect our operating results.
Demand for crude oil is dependent upon the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. Demand also depends on the ability and willingness of shippers having access to our transportation assets to satisfy their demand by deliveries through those assets.
Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdown, can have a negative effect on our operating results. Specifically, reduced demand in an area serviced by our transmission systems will negatively affect the throughput on such systems. Although the negative impact may be mitigated or overcome by
our ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.
If we do not make acquisitions on economically acceptable terms our future growth may be limited.
Our ability to grow depends in part on our ability to make acquisitions that result in an increase in adjusted operating surplus per unit. If we are unable to make such accretive acquisitions either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the sellers, (ii) unable to raise financing for such acquisitions on economically acceptable terms or (iii) outbid by competitors, our future growth will be limited. In particular, competition for midstream assets and businesses has intensified substantially and as a consequence such assets and businesses have become more costly. As a result, we may not be able to complete the number or size of acquisitions that we have targeted internally or to continue to grow as quickly as we have historically.
Our acquisition strategy requires access to new capital. Tightened capital markets or other factors that increase our cost of capital could impair our ability to grow through acquisitions.
We continuously consider and enter into discussions regarding potential acquisitions. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. Any material acquisition will require access to capital. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our ability to execute our acquisition strategy. Our ability to maintain our targeted credit profile, including maintaining our credit ratings, could affect our cost of capital as well as our ability to execute our acquisition strategy.
Our acquisition strategy involves risks that may adversely affect our business.
Any acquisition involves potential risks, including:
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performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
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a significant increase in our indebtedness and working capital requirements;
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the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
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the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition;
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risks associated with operating in lines of business that are distinct and separate from our historical operations;
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customer or key employee loss from the acquired businesses; and
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the diversion of management’s attention from other business concerns.
Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits and our ability to pay distributions or meet our debt service requirements.
Our pipeline assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates we charge on our domestic interstate pipeline system may reduce the amount of cash we generate.
Our domestic interstate common carrier pipelines are subject to regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be just and reasonable and non-discriminatory. We are also subject to the Pipeline Safety Regulations of the DOT. Our intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.
The EPAct, among other things, deems “just and reasonable” within the meaning of the Interstate Commerce Act any oil pipeline rate in effect for the 365-day period ending on the date of the enactment of EPAct if the rate in effect was not subject to protest, investigation, or complaint during such 365-day period. (That is, the EPAct “grandfathers” any such rates.) The EPAct further protects any rate meeting this requirement from complaint unless the complainant can show that a substantial change occurred after the enactment of EPAct in the economic circumstances of the oil pipeline which were the basis for the rate or in the nature of the services provided which were a basis for the rate. This grandfathering protection does not apply, under certain specified circumstances, when the person filing the complaint was under a contractual prohibition against the filing of a complaint.
For our domestic interstate common carrier pipelines subject to FERC regulation under the Interstate Commerce Act, shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority and for rates that remain grandfathered under EPAct, the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level when taking into consideration the pipeline system’s cost of service. In addition, shippers may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. The FERC’s ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.
The potential for a challenge to the status of our grandfathered rates under EPAct (by showing a substantial change in circumstances) or a challenge to our indexed rates creates the risk that the FERC might find some of our rates to be in excess of a just and reasonable level - that is, a level justified by our cost of service. In such an event, the FERC could order us to reduce any such rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.
Our Canadian pipelines are subject to regulation by the NEB or by provincial authorities. Under the National Energy Board Act, the NEB could investigate the tariff rates or the terms and conditions of service relating to a jurisdictional pipeline on its own initiative upon the filing of a toll or tariff application, or upon the filing of a written complaint. If it found the rates or terms of service relating to such pipeline to be unjust or unreasonable or unjustly discriminatory, the NEB could require us to change our rates, provide access to other shippers, or change our terms of service. A provincial authority could, on the application of a shipper or other interested party, investigate the tariff rates or our terms and conditions of service relating to our provincially regulated proprietary pipelines. If it found our rates or terms of service to be contrary to statutory requirements, it could impose conditions it considers appropriate. A provincial authority could declare a pipeline to be a common carrier pipeline, and require us to change our rates, provide access to other shippers, or otherwise alter our terms of service. Any reduction in our tariff rates would result in lower revenue and cash flows.
Some of our operations cross the U.S./Canada border and are subject to cross border regulation.
Our cross border activities with our Canadian subsidiaries subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.
We face competition in our transportation, facilities and marketing activities.
Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control greater supplies of crude oil.
With respect to our natural gas storage operations, we compete with other storage providers, including local distribution companies (“LDCs”), utilities and affiliates of LDCs and utilities. Certain major pipeline companies have existing storage facilities connected to their systems that compete with certain of our facilities. Third-party construction of new capacity could have an adverse impact on our competitive position.
We are exposed to the credit risk of our customers in the ordinary course of our marketing activities.
There can be no assurance that we have adequately assessed the creditworthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their creditworthiness, which could have an adverse impact on us.
In those cases in which we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties.
We may in the future encounter increased costs related to, and lack of availability of, insurance.
Over the last several years, as the scale and scope of our business activities has expanded, the breadth and depth of available insurance markets has contracted. Some of this may be attributable to the events of September 11, 2001 and the effects of hurricanes along the Gulf Coast during 2005, which adversely impacted the availability and costs of certain types of coverage. We can give no assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. The occurrence of a significant event not fully insured could materially and adversely affect our operations and financial condition.
Marine transportation of crude oil and refined product has inherent operating risks.
Our gathering and marketing operations include purchasing crude oil that is carried on third-party tankers. Our waterborne cargoes of crude oil are at risk of being damaged or lost because of events such as marine disaster, bad weather, mechanical failures, grounding or collision, fire, explosion, environmental accidents, piracy, terrorism and political instability. Such occurrences could result in death or injury to persons, loss of property or environmental damage, delays in the delivery of cargo, loss of revenues from or termination of charter contracts, governmental fines, penalties or restrictions on conducting business, higher insurance rates and damage to our reputation and customer relationships generally. Although certain of these risks may be covered under our insurance program, any of these circumstances or events could increase our costs or lower our revenues.
In instances in which cargoes are purchased FOB (title transfers when the oil is loaded onto a vessel chartered by the purchaser) the contract to purchase is typically made prior to the vessel being chartered. In such circumstances we take the risk of higher than anticipated charter costs. We are also exposed to increased transit time and unanticipated demurrage charges, which involve extra payment to the owner of a vessel for delays in offloading, circumstances that we may not control.
Maritime claimants could arrest the vessels carrying our cargoes.
Crew members, suppliers of goods and services to a vessel, other shippers of cargo and other parties may be entitled to a maritime lien against that vessel for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lienholder may enforce its lien by arresting a vessel through foreclosure proceedings. The arrest or attachment of a vessel carrying a cargo of our oil could substantially delay our shipment.
In addition, in some jurisdictions, under the “sister ship” theory of liability, a claimant may arrest both the vessel that is subject to the claimant’s maritime lien and any “associated” vessel, which is any vessel owned or controlled by the same owner. Claimants could try to assert “sister ship” liability against one vessel carrying our cargo for claims relating to a vessel with which we have no relation.
We are dependent on use of a third-party marine dock for delivery of waterborne crude oil into our storage and distribution facilities in the Los Angeles basin.
A portion of our storage and distribution business conducted in the Los Angeles basin (acquired in connection with the Pacific acquisition) is dependent on our ability to receive waterborne crude oil, a major portion of which is presently being received through dock facilities operated by Shell Oil Products in the Port of Long Beach. We are currently a hold-over tenant with respect to such facilities. If we are unable to renew the agreement that allows us to utilize these dock facilities, and if other alternative dock access cannot be arranged, the volumes of crude oil that we
presently receive from our customers in the Los Angeles basin may be reduced, which could result in a reduction of facilities segment revenue and cash flow.
The terms of our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
As of December 31, 2006, our total outstanding long-term debt was approximately $2.6 billion. Various limitations in certain of our debt instruments may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Changes in currency exchange rates could adversely affect our operating results.
Because we conduct operations in Canada, we are exposed to currency fluctuations and exchange rate risks that may adversely affect our results of operations.
Terrorist attacks aimed at our facilities could adversely affect our business.
Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments will subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
An impairment of goodwill could reduce our earnings.
We recorded a significant amount of goodwill upon completion of our merger with Pacific, but our preliminary estimate is subject to change pending the completion of an independent appraisal. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the acquired tangible and separately measurable intangible net assets. U.S. generally accepted accounting principles, or GAAP, requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. If we were to determine that any of our remaining balance of goodwill was impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.
Our natural gas storage facilities are new and have limited operating history.
Although we believe that our operating natural gas storage facilities are designed substantially to meet our contractual obligations with respect to injection and withdrawal volumes and specifications, the facilities are new and have a limited operating history. If we fail to receive or deliver natural gas at contracted rates, or cannot deliver natural gas consistent with contractual quality specifications, we could incur significant costs to maintain compliance with our contracts.
We have a limited history of operating natural gas storage facilities and transporting, storing and marketing refined products.
Although many aspects of the natural gas storage and refined products industries are similar to our crude oil operations, our current management has little experience in operating natural gas storage facilities or in the refined products business. There are significant risks and costs inherent in our efforts to engage in these operations, including the risk that our new lines of business may not be profitable and that we might not be able to operate them or implement our operating policies and strategies successfully.
The devotion of capital, management time and other resources to natural gas storage and refined products operations could adversely affect our existing business. Entering into the natural gas storage and refined products industries may require substantial changes, including acquisition costs, capital development expenditures, adding skilled management and employees and realigning our current organization to reflect these new lines of business.
Entering into the natural gas storage industry will require an investment in personnel and assets and the assumption of risks that may be greater than we have previously assumed.
Federal, state or local regulatory measures could adversely affect our natural gas storage business.
Our natural gas storage operations are subject to federal, state and local regulation. Specifically, our natural gas storage facilities and related assets are subject to regulation by the FERC, the Michigan Public Service Commission and various Louisiana state agencies. Our facilities essentially have market-based rate authority from such agencies. Any loss of market-based rate authority could have an adverse impact on our revenues associated with providing storage services. In addition, failure to comply with applicable regulations under the Natural Gas Act, and certain other state laws could result in the imposition of administrative, civil and criminal remedies.
Our gas storage business depends on third party pipelines to transport natural gas.
We depend on third party pipelines to move natural gas for our customers to and from our facilities. Any interruption of service on the pipelines or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities, and could have a corresponding material adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipeline for transportation to and from our facilities could affect the utilization and value of our storage services. Significant changes in the rates charged by the pipeline or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
We may not be able to retain existing natural gas storage customers or acquire new customers, which would reduce our revenues and limit our future profitability.
The renewal or replacement of existing contracts with our customers at rates sufficient to maintain or exceed current or anticipated revenues and cash flows depends on a number of factors beyond our control, including competition from other storage providers and the supply of and demand for natural gas in the markets we serve. The inability to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
Joint venture structures can create operational difficulties.
Our natural gas storage operations are conducted through PAA/Vulcan, a joint venture between us and a subsidiary of Vulcan Capital. We are also engaged in a joint venture arrangement with Settoon Towing.
As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions or in failures to agree on major matters, potentially adversely affecting the business and operations of the joint ventures and in turn our business and operations.
Risks Inherent in an Investment in Plains All American Pipeline, L.P.
Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.
Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.
Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter
will depend on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
Unitholders may not be able to remove our general partner even if they wish to do so.
Our general partner manages and operates the Partnership. Unlike the holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.
Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units (including units held by our general partner or its affiliates). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.
In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:
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generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
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limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of management.
As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
We may issue additional common units without unitholder approval, which would dilute a unitholder’s existing ownership interests.
Our general partner may cause us to issue an unlimited number of common units, without unitholder approval (subject to applicable NYSE rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
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an existing unitholder’s proportionate ownership interest in the Partnership will decrease;
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the amount of cash available for distribution on each unit may decrease;
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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 their units at an undesirable time or price.
If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Conflicts of interest could arise among our general partner and us or the unitholders.
These conflicts may include the following:
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we do not have any employees and we rely solely on employees of the general partner or, in the case of Plains Marketing Canada, employees of PMC (Nova Scotia) Company;
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under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
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the amount of cash expenditures, borrowings and reserves in any quarter may affect available cash to pay quarterly distributions to unitholders;
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the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability; under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arms length negotiations; and
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the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.
The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.
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 our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers with its own choices and to control their decisions and actions.
In addition, a change of control would constitute an event of default under the indentures governing certain issues of our senior notes and under our revolving credit agreement. An event of default under certain of our indentures could require us to make an offer to purchase the senior notes issued thereunder at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest, if any, to the date of purchase. During the continuance of an event of default under our revolving credit agreement, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us under our revolving credit facility and/or declare all amounts payable by us under our revolving credit facility immediately due and payable. A change of control also may trigger payment obligations under various compensation arrangements with our officers.
Risks Related to an Investment in Our Debt Securities
The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the notes.
Our debt securities are effectively subordinated to claims of our secured creditors and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although substantially all of our operating subsidiaries, other than minor subsidiaries and those regulated by the CPUC, have guaranteed such debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities would be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.
Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
Our leverage is significant in relation to our partners’ capital. At December 31, 2006, our total outstanding long-term debt and short-term debt under our revolving credit facility was approximately $3.6 billion. We will be prohibited from making cash distributions during an event of default under any of our indebtedness. Various limitations in our credit facilities may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
Our leverage could have important consequences to investors in our debt securities. We will require substantial cash flow to meet our principal and interest obligations with respect to the notes and our other consolidated indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our bank credit facility to service our indebtedness, although the principal amount of the notes will likely need to be refinanced at maturity in whole or in part. However, a significant downturn in the hydrocarbon industry or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or portion of our debt or sell assets. We can give no assurance that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable. In addition, if one or more rating agencies were to lower our debt ratings, we could be required by some of our counterparties to post additional collateral, which would reduce our available liquidity and cash flow.
Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
A court may use fraudulent conveyance considerations to avoid or subordinate the subsidiary guarantees.
Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use fraudulent conveyance laws to subordinate or avoid the subsidiary guarantees of our debt securities issued by any of our subsidiary guarantors. It is also possible that under certain circumstances a court could hold that the direct
obligations of a subsidiary guaranteeing our debt securities could be superior to the obligations under that guarantee.
A court could avoid or subordinate the guarantee of our debt securities by any of our subsidiaries in favor of that subsidiary’s other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee:
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that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
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that subsidiary did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary:
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was insolvent or rendered insolvent by reason of the issuance of the guarantee;
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was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital; or
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intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.
The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation, or if the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and matured.
Among other things, a legal challenge of a subsidiary’s guarantee of our debt securities on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our issuance of our debt securities. To the extent a subsidiary’s guarantee of our debt securities is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of our debt securities would cease to have any claim in respect of that guarantee.
The ability to transfer our debt securities may be limited by the absence of a trading market.
We do not currently intend to apply for listing of our debt securities on any securities exchange or stock market. The liquidity of any market for our debt securities will depend on the number of holders of those debt securities, the interest of securities dealers in making a market in those debt securities and other factors. Accordingly, we can give no assurance as to the development or liquidity of any market for the debt securities.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make required payments on our debt securities depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to the credit facilities, we may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under our credit facilities. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the debt securities, or to repurchase the debt securities upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that we would be able to refinance the debt securities.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt securities or to repay them at maturity.
Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner 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 our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs);
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to provide funds for distributions to our unitholders and the 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 our loan or other agreements.
Although our payment obligations to our unitholders are subordinate to our payment obligations to debtholders, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. and Canadian federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available to pay distributions and our debt obligations.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, the cash available for distributions or to pay our debt obligations would be substantially reduced.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we will be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax upon us as an entity by Texas or any other state will reduce the cash available for distributions or to pay our debt obligations.
Proposed changes in Canadian tax law could subject our Canadian subsidiaries to entity-level tax, which would reduce the amount of cash available to pay distributions and our debt obligations.
In response to the perceived proliferation of “income trusts” in Canada, the Canadian government has issued proposed regulations that impose entity-level taxes on certain types of flow-through entities. At this point, final regulations have not been issued and it is not clear what impact the final regulations will have on our Canadian subsidiaries. Any entity-level taxation of our Canadian subsidiaries would reduce the cash available for distributions or to pay our debt obligations.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all of our unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution or debt service.
We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not concur with our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne by us and directly or indirectly by the unitholders and the general partner because the costs will reduce our cash available for distribution or debt service.
Our unitholders may be required to pay taxes 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 that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
Tax gain or loss on disposition of common units could be different than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated to a unitholder for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price the unitholder receives is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder. Should the IRS successfully contest some positions we take, the unitholder could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (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 individual retirement accounts 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 United States federal tax returns and pay tax on their share of our taxable income.
We treat each purchaser of common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that do not conform with all aspects of the 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 a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to a unitholder’s tax return.
Our unitholders will likely be subject to foreign, state and local taxes and tax return filing requirements in jurisdictions where they do not live as a result of an investment in our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign taxes, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property and in which they do not reside. We own property and conduct business in Canada and in most states in the United States. Unitholders will be required to file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes in respect of our Canadian source income earned through partnership entities. A unitholder may also be required to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we conduct business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all United States federal, state, local and foreign tax returns.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 3.
Item 3.
Legal Proceedings
Pipeline Releases. In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the U.S. Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0 million to $3.5 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice (the “DOJ”) for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating in the investigation. Our assessment is that it is probable we will pay penalties related to the two releases. We have accrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that the loss contingency may exceed our estimate with respect to penalties assessed by the DOJ; however, we have no indication from EPA or the DOJ of what penalties might be sought. As a result, we are unable to estimate the range of a reasonably possible loss contingency in excess of our accrual.
On November 15, 2006, we completed the Pacific acquisition. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.
The People of the State of California v. Pacific Pipeline System, LLC (“PPS”). In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger.
The release occurred when Line 63 was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. As of December 31, 2006, $26 million of remediation costs had been incurred. We estimate additional remediation costs of approximately $1 to $2 million, substantially all of which we expect to incur before June 2007. We anticipate that the majority of costs associated with this release will be covered under a pre-existing PPS pollution liability insurance policy.
In March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleges the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. The fines that can be assessed against PPS for the violations of the strict liability statutes are based, in large measure, on the volume of unrecovered crude oil that was released into the environment, and, therefore, the maximum state fine that can be assessed is estimated to be approximately $1,100,000, in the aggregate. This amount is subject to a downward adjustment with respect to actual volumes of recovered crude oil, and the State of California has the discretion to further reduce the fine after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the strict liability offenses cannot be ascertained. We will defend against these charges. In addition to these fines, the State of California has indicated that it may seek to recover approximately $150,000 in natural resource damages against PPS in connection with this matter. The mitigating factors may also serve as a basis for a downward adjustment of the natural resource damages amount. We believe that certain of the alleged violations are without merit and intend to defend against them, and that mitigating factors should apply.
In December 2006 we were informed that the EPA may be intending to refer this matter to the DOJ for the initiation of proceedings to assess civil penalties against PPS. The DOJ has accepted the referral. We understand that the maximum permissible penalty that the EPA could assess under relevant statutes would be approximately $3.7 million. We believe that several mitigating circumstances and factors exist that could substantially reduce the penalty, and intend to pursue discussions with the EPA regarding such mitigating circumstances and factors. Because of the uncertainty associated with these factors, the final amount of the penalty that will be assessed by the EPA cannot be ascertained. Discussions with the DOJ to resolve this matter have commenced.
Kosseff v. Pacific Energy, et al, case no. BC 3544016. On June 15, 2006, a lawsuit was filed in the Superior court of California, County of Los Angeles, in which the plaintiff alleged that he was a unitholder of Pacific and he sought to represent a class comprising all of Pacific’s unitholders. The complaint named as defendants Pacific and certain of the officers and directors of Pacific’s general partner, and asserted claims of self-dealing and breach of fiduciary duty in connection with the pending merger with us and related transactions. The plaintiff sought injunctive relief against completing the merger or, if the merger was completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. On September 14, 2006, Pacific and the other defendants entered into a memorandum of settlement with the plaintiff to settle the lawsuit. As part of the settlement, Pacific and the other defendants deny all allegations of wrongdoing and express willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement is subject to customary conditions, including court approval. As part of the settlement, we (as successor to Pacific) will pay $0.5 million to the plaintiff’s counsel for their fees and expenses, and incur the cost of mailing materials to former Pacific unitholders. If finally approved by the court, the settlement will resolve all claims that were or could have been brought on behalf of the proposed settlement class in the actions being settled, including all claims relating to the merger, the merger agreement and any disclosure made by Pacific in connection with the merger. The settlement did not change any of the terms or conditions of the merger.
Air Quality Permits. In connection with the Pacific merger, we acquired Pacific Atlantic Terminals LLC (“PAT”), which is now one of our subsidiaries. PAT owns crude oil and refined products terminals in northern California. In the process of integrating PAT’s assets into our operations, we identified certain aspects of the operations at the terminals that appeared to be out of compliance with specifications under the relevant air quality permit. We conducted a prompt review of the circumstances and self-reported the apparent historical occurrences of non-compliance to the Bay Area Air Quality Management District. We are cooperating with the District’s review of these matters.
General. We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
On November 9, 2006, the Partnership held a special meeting of its unitholders for the following purposes:
1. To consider and vote upon the approval and adoption of the Agreement and Plan of Merger dated as of June 11, 2006 by and among the Partnership, Plains AAP, L.P., Plains All American GP LLC, Pacific, Pacific Energy Management LLC and Pacific Energy GP, LP, as it may be amended from time to time (the “Merger Agreement”); and
2. To consider and vote upon the approval of the issuance of our common units to the common unitholders of Pacific (other than LB Pacific, LP), as provided in the Merger Agreement.
Holders of over 65% of our outstanding common units voted in favor of both proposals. The voting results were as follows:
PART II
Item 5.
Item 5.
Market For Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol “PAA.” On February 20, 2007, the closing market price for our common units was $54.67 per unit and there were approximately 70,000 record holders and beneficial owners (held in street name). As of February 20, 2007, there were 109,405,178 common units outstanding.
The following table sets forth high and low sales prices for our common units and the cash distributions declared per common unit for the periods indicated:
(1)
Cash distributions for a quarter are declared and paid in the following calendar quarter.
Our common units are used as a form of compensation to our employees. Additional information regarding our equity compensation plans is included in Part III of this report under Item 13. “Certain Relationships and Related Transactions, and Director Independence.”
Cash Distribution Policy
We will distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:
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provide for the proper conduct of our business;
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comply with applicable law or any partnership debt instrument or other agreement; or
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provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
In addition to distributions on its 2% general partner interest, our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication and except for the agreed upon adjustment discussed below, to 15% of amounts we distribute in excess of $0.450 per unit, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit.
Upon closing of the Pacific acquisition, our general partner agreed to reduce the amounts due it as incentive distributions. The reduction will be effective for five years, as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million. The first quarterly reduction took place in connection with the distribution paid in February 2007.
We paid $33.1 million to the general partner in incentive distributions in 2006. On February 14, 2007, we paid a quarterly distribution of $0.80 per unit applicable to the fourth quarter of 2006. See Item 13. “Certain Relationships and Related Transactions, and Director Independence - Our General Partner.”
Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Credit Facilities and Long-term Debt.”
Issuer Purchases of Equity Securities
We did not repurchase any of our common units during the fourth quarter of fiscal 2006.
Item 6.
Item 6.
Selected Financial Data
The historical financial information below was derived from our audited consolidated financial statements as of December 31, 2006, 2005, 2004, 2003 and 2002 and for the years then ended. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes.
Our discussion and analysis includes the following:
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Executive Summary
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Acquisitions and Internal Growth Projects
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Critical Accounting Policies and Estimates
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Recent Accounting Pronouncements and Change in Accounting Principle
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Results of Operations
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Outlook
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Liquidity and Capital Resources
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Off-Balance Sheet Arrangements
Executive Summary
Company Overview
We are engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products (liquefied petroleum gas and other natural gas related petroleum products are collectively referred to as “LPG”). In addition, through our 50% equity ownership in PAA/Vulcan, we develop and operate natural gas storage facilities. We were formed in September 1998, and our operations are conducted directly and indirectly through our operating subsidiaries.
Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines and gathering systems. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements. Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products and LPG, as well as LPG fractionation and isomerization services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements. Our marketing segment operations generally consist of merchant activities associated primarily with the purchase and sale of crude oil and LPG. Our marketing activities are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside exposure to opportunities inherent in volatile market conditions. These activities utilize storage facilities at major interchange and terminalling locations and various hedging strategies to reduce the negative impact of market volatility and provide counter-cyclical balance.
Overview of Operating Results, Capital Spending and Significant Activities
During 2006, we recognized net income of $285.1 million and earnings per diluted limited partner unit of $2.88, compared to net income of $217.8 million and earnings per diluted limited partner unit of $2.72 during 2005.
Both 2006 and 2005 were substantial increases over 2004. Net income was $130.0 million and earnings per diluted limited partner unit was $1.89 for 2004. Key items impacting 2006 include:
Balance Sheet and Capital Structure
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The completion of the Pacific acquisition for approximately $2.5 billion (including the equity issuance and assumption of debt discussed below), and six other acquisitions for aggregate consideration of approximately $565 million.
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The issuance of 22 million limited partner units (valued at $1.0 billion) in exchange for Pacific limited partner units as part of the Pacific acquisition and the sale of 13.4 million limited partner units for net proceeds of approximately $621 million.
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The assumption of $433 million of senior notes as part of the Pacific acquisition and the issuance of $1,250 million of Senior Notes for net proceeds of approximately $1,243 million.
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Capital expenditures (excluding acquisitions and maintenance capital) of $332 million.
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Limited partner distributions of $224.9 million ($2.87 per limited partner unit) and General Partner distributions of $37.7 million paid during 2006.
Income Statement
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Favorable execution of our risk management strategies in our marketing segment in a pronounced contango market with a high level of overall crude oil volatility.
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Increased volumes and related tariff revenues on our pipeline systems.
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An increase in field operating costs and general and administrative expenses primarily associated with continued growth from acquisitions as well as internal growth projects and an increase of $17 million in 2006 related to our Long-Term Incentive Plans. See “- Critical Accounting Policies and Estimates - Critical Accounting Estimates - Long-Term Incentive Plan Accruals.”
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A charge of approximately $4 million in 2006 resulting from the mark-to-market of open derivative instruments pursuant to SFAS 133.
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A gain of approximately $6 million resulting from the reduction of our obligation for outstanding LTIP awards, which was recorded as a cumulative effect of change in accounting principle pursuant to the adoption of SFAS No. 123(R) (revised 2004), “Share-Based Payment.”
Prospects for the Future
Access to storage tankage by our marketing segment provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow associated with this segment. The strategic use of our terminalling and storage assets in conjunction with our gathering and marketing operations generally provides us with the flexibility to maintain a base level of margin irrespective of crude oil market conditions and, in certain circumstances, to realize incremental margin during volatile market conditions.
During 2006, we strengthened our business by expanding our asset base through approximately $3 billion of acquisitions and $332 million of internal growth projects. In 2007, we intend to spend approximately $500 million on internal growth projects and also to continue to develop our inventory of projects for implementation beyond 2007. Several of the larger storage tank projects for 2007, such as the construction or expansion of the Patoka, Cushing and St. James terminals, are well positioned to benefit from the importation of waterborne foreign crude oil into the Gulf Coast as well as the importation of Canadian crude oil. We also believe there are opportunities for us to grow our LPG business. In addition, our 2005 entry into the natural gas storage business and our 2006 entries into the refined products transportation and storage business and the barge transportation business are consistent with our stated strategy of leveraging our assets, business model, knowledge and expertise into businesses that are complementary to our existing activities. We will continue to look for ways to grow these businesses and continue to evaluate opportunities in other complementary midstream business activities. Specifically, we intend to apply our
business model to the refined products business by establishing and growing a marketing and distribution business to complement our strategically located assets. We believe we have access to equity and debt capital and that we are well situated to optimize our position in and around our existing assets and to expand our asset base by continuing to consolidate, rationalize and optimize the North American midstream infrastructure.
Although we believe that we are well situated in the North American midstream infrastructure, we face various operational, regulatory and financial challenges that may impact our ability to execute our strategy as planned. In addition, we operate in a mature industry and believe that acquisitions will play an important role in our potential growth. We will continue to pursue the purchase of midstream assets, and we will also continue to initiate expansion projects designed to optimize product flows in the areas in which we operate. However, we can give no assurance that our current or future acquisition or expansion efforts will be successful. See Item 1A. “Risk Factors - Risks Related to Our Business.”
Acquisitions and Internal Growth Projects
We completed a number of acquisitions and capital expansion projects in 2006, 2005 and 2004 that have impacted our results of operations and enabled us to enhance our liquidity, as discussed herein. The following table summarizes our capital expenditures for acquisitions (including equity investments), capital expansion (internal growth projects) and maintenance capital for the periods indicated (in millions):
(1)
Acquisition capital includes deposits in the year the acquisition closed, rather than the year the deposit was paid. Deposits paid were approximately $12 million for the Shell Gulf Coast Pipeline Systems acquisition in 2004.
Internal Growth Projects
As a result of capital expansion opportunities originating from prior acquisitions, we increased our annual level of spending on these projects by 123% in 2006 compared to 2005. The following table summarizes our 2006 and 2005 projects (in millions):
Our 2006 projects included the construction and expansion of pipeline systems and crude oil storage and terminal facilities (notably Cushing and St. James). We expect internal growth capital projects to expand further in 2007. See “- Liquidity and Capital Resources - Capital Expenditures and Distributions Paid to Unitholders and General Partners - 2007 Capital Expansion Projects.”
Acquisitions
Acquisitions are financed using a combination of equity and debt, including borrowings under our credit facilities and the issuance of senior notes. The businesses acquired impacted our results of operations commencing on the effective date of each acquisition as indicated in the table below. Our ongoing acquisitions and capital expansion activities are discussed further in “- Liquidity and Capital Resources.” See Note 3 to our Consolidated Financial Statements for additional information about our acquisition activities.
Acquisitions
In 2006, we completed several acquisitions for aggregate consideration of approximately $3.0 billion. The Pacific merger was material to our operations. See Note 3 to our Consolidated Financial Statements. The following table summarizes the acquisitions that were completed in 2006, and a description of our material acquisitions follows the table (in millions):
Pacific. On November 15, 2006 we completed our acquisition of Pacific pursuant to an Agreement and Plan of Merger dated June 11, 2006. The merger-related transactions included: (i) the acquisition from LB Pacific of the general partner interest and incentive distribution rights of Pacific as well as approximately 5.2 million Pacific common units and approximately 5.2 million Pacific subordinated units for a total of $700 million and (ii) the acquisition of the balance of Pacific’s equity through a unit-for-unit exchange in which each Pacific unitholder (other than LB Pacific) received 0.77 newly issued common units of the Partnership for each Pacific common unit. The total value of the transaction was approximately $2.5 billion, including the assumption of debt and estimated transaction costs. Upon completion of the merger-related transactions, the general partner and limited partner ownership interests in Pacific were extinguished and Pacific was merged with and into the Partnership. The assets acquired in the Pacific acquisition included approximately 4,500 miles of active crude oil pipeline and gathering systems and 550 miles of refined products pipelines, over 13 million barrels of active crude oil storage capacity and 9 million barrels of refined products storage capacity, a fleet of approximately 75 owned or leased trucks and approximately 1.9 million barrels of crude oil and refined products linefill and working inventory. The Pacific assets complement our existing asset base in California, the Rocky Mountains and Canada, with minimal asset overlap but attractive potential vertical integration opportunities. The results of operations and assets and liabilities from the Pacific acquisition have been included in our consolidated financial statements since November 15, 2006. The purchase price allocation related to the Pacific acquisition is preliminary and subject to change. See Note 3 to our Consolidated Financial Statements.
The purchase price was allocated as follows (in millions):
(1)
Includes investment banking fees, costs associated with a severance plan in conjunction with the acquisition and various other direct acquisition costs.
(1)
Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy.
The majority of the acquisition costs associated with the Pacific acquisition was incurred as of December 31, 2006, resulting in total cash paid during 2006 of approximately $723 million.
The following table shows our calculation of the sources of funding for the acquisition (in millions):
(1)
The assumption of Pacific’s debt and credit facility at fair value was $433.1 million and $290.7 million, respectively. We paid off the credit facility in connection with closing of the transaction.
Other 2006 Acquisitions. During 2006, we completed six additional acquisitions for aggregate consideration of approximately $565 million. These acquisitions included (i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana (SemCrude), (iii) interests in various crude oil pipeline systems in Canada and the U.S. including a 100% interest in the BOA Pipeline, various interests in HIPS and a 64.35% interest in the CAM Pipeline system, and (iv) three refined products pipeline systems.
In addition, in November 2006, we purchased a 50% interest in Settoon Towing for approximately $33 million. Settoon Towing owns and operates a fleet of 57 transport and storage barges as well as 30 transport tugs. Its core business is the gathering and transportation of crude oil and produced water from inland production facilities across the Gulf Coast.
Acquisitions
We completed six small transactions in 2005 for aggregate consideration of approximately $40.3 million. The transactions included crude oil trucking operations and several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. These acquisitions did not materially impact our results of operations, either individually or in the aggregate. The following table summarizes our acquisitions that were completed in 2005 (in millions):
(1)
A $12 million deposit for the Shell Gulf Coast Pipeline Systems acquisition was paid into escrow in December 2004.
In addition, in September 2005, PAA/Vulcan acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We own 50% of PAA/Vulcan and the remaining 50% is owned by a subsidiary of Vulcan Capital. We made a $112.5 million capital contribution to PAA/Vulcan and we account for the investment in PAA/Vulcan under the equity method in accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
Acquisitions
In 2004, we completed several acquisitions for aggregate consideration of approximately $563.9 million. The Link and Capline acquisitions were material to our operations. See Note 3 to our Consolidated Financial Statements. The following table summarizes our acquisitions that were completed in 2004, and a description of our material acquisitions follows the table (in millions):
(1)
Includes a deposit of approximately $16 million which was paid in December 2003 for the Capline acquisition.
(2)
Includes approximately $14.4 million of LPG operating inventory acquired.
Capline and Capwood Pipeline Systems. The principal assets acquired are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 58-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S. and delivered to several refineries and other pipelines.
Link Energy LLC. The Link crude oil business we acquired consisted of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of active crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions.
Critical Accounting Policies and Estimates
Critical Accounting Policies
We have adopted various accounting policies to prepare our consolidated financial statements in accordance with generally accepted accounting principles in the United States. These critical accounting policies are discussed in Note 2 to the Consolidated Financial Statements.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. The critical accounting policies that we have identified are discussed below.
Purchase and Sales Accruals. We routinely make accruals based on estimates for certain components of our revenues and cost of sales due to the timing of compiling billing information, receiving third party information and reconciling our records with those of third parties. Where applicable, these accruals are based on nominated volumes expected to be purchased, transported and subsequently sold. Uncertainties involved in these estimates include levels of production at the wellhead, access to certain qualities of crude oil, pipeline capacities and delivery times, utilization of truck fleets to transport volumes to their destinations, weather, market conditions and other forces beyond our control. These estimates are generally associated with a portion of the last month of each reporting period. We currently estimate that less than 2% of total annual revenues and cost of sales are recorded using estimates. Accordingly, a variance from this estimate of 10% would impact the respective line items by less than 1% on an annual basis. In addition, we estimate that less than 4% of total operating income and less than 5% of total net income are recorded using estimates. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.
Mark-to-Market Accrual. In situations where we are required to mark-to-market derivatives pursuant to SFAS 133, the estimates of gains or losses at a particular period end do not reflect the end results of particular transactions, and will most likely not reflect the actual gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. A portion of the estimates we use are based on internal models or models of third parties because they are not quoted on a national market. Additionally, values may vary among different models due to a difference in assumptions applied, such as the estimate of prevailing market prices, volatility, correlations and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from these models. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Contingent Liability Accruals. We accrue reserves for contingent liabilities including, but not limited to, environmental remediation and governmental penalties, insurance claims, asset retirement obligations, taxes, and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the
necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, costs of medical care associated with worker’s compensation and employee health insurance claims, and the possibility of existing legal claims giving rise to additional claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A variance of 10% in our aggregate estimate for the contingent liabilities discussed above would have an approximate $5.2 million impact on earnings. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In conjunction with each acquisition, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. We also estimate the amount of transaction costs that will be incurred in connection with each acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, in conjunction with the adoption of SFAS 141, we are required to recognize intangible assets separately from goodwill. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment. The impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of market conditions including pricing, demand, competition, operating costs and other factors. Intangible assets with finite lives are amortized over the estimated useful life determined by management. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. The purchase price allocation related to the Pacific acquisition is preliminary and subject to change. See Note 3 to our Consolidated Financial Statements.
Long-Term Incentive Plan Accruals. We also make accruals to recognize the fair value of our outstanding LTIP awards as compensation expense. Under generally accepted accounting principles, we are required to estimate the fair value of our outstanding LTIP awards and recognize that fair value as compensation expense over the course of the LTIP award’s vesting period. For LTIP awards that contain a performance condition, the fair value of the LTIP award is recognized as compensation expense only if the attainment of the performance condition is considered probable. The amount of the actual charge to compensation expense will be determined by the unit price on the date vesting occurs (or, in some cases, the average unit price for a range of dates preceding the vesting date) multiplied by the number of units, plus our share of associated employment taxes. Uncertainties involved in this estimate include the actual unit price at time of settlement, whether or not a performance condition will be attained and the continued employment of personnel subject to the vestings.
We achieved a $3.20 annualized distribution rate and therefore we are accruing compensation expense for LTIP awards that vest upon the attainment of that rate. We recognized total compensation expense of approximately $42.7 million in 2006 and $26.1 million in 2005 related to awards granted under our various LTIP plans. We cannot provide assurance that the actual fair value of our LTIP awards will not vary significantly from estimated amounts. See Note 10 to our Consolidated Financial Statements.
Goodwill. We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable. We consider the estimate of fair value to be a critical accounting estimate because (a) a goodwill impairment could have a material impact on our financial position and results of operations and (b) the estimate is based on a number of highly subjective judgments and assumptions.
Property, Plant and Equipment and Depreciation Expense. We compute depreciation using the straight-line method based on estimated useful lives. We periodically evaluate property, plant and equipment for impairment
when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:
•
whether there is an indication of impairment;
•
the grouping of assets;
•
the intention of “holding” versus “selling” an asset;
•
the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
•
if an impairment exists, the fair value of the asset or asset group.
Asset Retirement Obligation
We account for asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense and (4) subsequent measurement of the liability. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.
Some of our assets, primarily related to our transportation segment, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. The timing of the obligations is determined relative to the date on which the asset is abandoned.
Many of our pipelines are trunk and interstate systems that transport crude oil. The pipelines with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for this transportation will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations are related to assets that are inactive or that we plan to take out of service and although the ultimate timing and costs to settle these obligations are not known with certainty, we can reasonably estimate the obligation.
Recent Accounting Pronouncements and Change in Accounting Principle
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will impact us, see Note 2 to our Consolidated Financial Statements.
Changes in Accounting Principle
Stock-Based Compensation
In December 2004, SFAS 123(R) was issued, which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from such share-based payment transactions be recognized in the financial statements at fair value. Following our general partner’s adoption of Emerging Issues Task Force Issue No. 04-05, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we are now part of the same consolidated group and thus SFAS 123(R) is applicable to our general partner’s long-term incentive plan. We
adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our LTIP life-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Our LTIPs are administered by our general partner. We are required to reimburse all costs incurred by our general partner through LTIP settlements. As a result, our LTIP awards are classified as liabilities under SFAS 123(R). Under the modified prospective transition method, we are not required to adjust our prior period financial statements for our LTIP awards.
Linefill
During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we did not include linefill barrels in the same average costing calculation as our operating inventory, but instead carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we historically classified as a portion of Pipeline Linefill on the face of the balance sheet (a long-term asset) and carried at historical cost, is included in Inventory (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of Inventory (a current asset), at average cost, and into Inventory in Third-Party Assets (a long-term asset), which is now reflected as a separate line item on the consolidated balance sheet.
This change in accounting principle was effective January 1, 2004 and is reflected as a cumulative change in our consolidated statement of operations for the year ended December 31, 2004. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory in Third-Party Assets of $28.9 million.
Results of Operations
Analysis of Operating Segments
Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business most notably in conjunction with the Pacific acquisition, we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. Prior period disclosures have been revised to reflect our change in segments.
We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative (“G&A”) expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which mitigate the actual decline in the value of our principal fixed assets. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash,” consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are considered expansion capital expenditures,
not maintenance capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. See Note 15 to our Consolidated Financial Statements for a reconciliation of segment profit to consolidated income before cumulative effect of change in accounting principle.
Our segment analysis involves an element of judgment relating to the allocations between segments. In connection with its operations, the marketing segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers under month-to-month and multi-year arrangements. Inter-segment transportation service rates are based on posted tariffs for pipeline transportation services. Facilities segment services are also obtained at rates consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates are discounted to our marketing segment to reflect the fact that these services may be canceled on short notice to enable the facilities segment to provide services to third parties. We believe that the estimates with respect to the rates that are charged by our facilities segment to our marketing segment are reasonable. We also allocate certain operating expense and general and administrative overheads between segments. We believe that the estimates with respect to the allocations are reasonable.
Transportation
As of December 31, 2006, we owned approximately 20,000 miles of active gathering and mainline crude oil and refined products pipelines located throughout the United States and Canada as well as approximately 60 million barrels of active above-ground crude oil, refined products and LPG storage tanks, of which approximately 30 million barrels are utilized in our transportation segment. Our activities from transportation operations generally consist of transporting crude oil and refined products for a fee and third-party leases of pipeline capacity (collectively referred to as “tariff activities”), as well as barrel exchanges and buy/sell arrangements (collectively referred to as “pipeline margin activities”). In addition, we transport crude oil for third parties for a fee using our trucks and barges. These barge transportation services are provided through our 50% owned entity, Settoon Towing. Our transportation segment also includes our equity in earnings from our investment in Settoon Towing, Butte and Frontier. Butte and Frontier are pipeline systems in which we own approximately 22% and 22%, respectively. In connection with certain of our merchant activities conducted under our marketing business, we are also shippers on a number of of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.
The following table sets forth our operating results from our transportation segment for the periods indicated:
(1)
Revenues and purchases include intersegment amounts.
(2)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.
(3)
Compensation expense related to our 1998 Long-Term Incentive Plan (“1998 LTIP”), our 2005 Long-Term Incentive Plan (“2005 LTIP”), and our 2006 Long-Term Incentive Tracking Unit Plan (“2006 Plan” and, together with the 1998 Plan and 2005 Plan, the “Long-Term Incentive Plans” or “LTIP”).
(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.
(5)
The aggregate of multiple systems in the West Texas/New Mexico area.
Segment profit, our primary measure of segment performance, was impacted by the following:
•
Increased volumes and related tariff revenues - The increase in tariff revenues resulted from (i) higher volumes primarily from multi-year contracts on our Basin and Capline systems entered into during the third quarter of 2006 and the second quarter of 2006, respectively, (ii) increased volumes associated with the acquisition of the BOA/CAM/HIPS systems, (iii) higher volumes on various other systems, and (iv) increased revenues from loss allowance oil. As is common in the industry, our crude oil tariffs incorporate a “loss allowance factor” that is intended to offset losses due to evaporation, measurement and other losses in transit. The loss allowance factor averages approximately 0.2%, by volume. We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. Gains or losses on subsequent sales of allowance oil barrels are also included in tariff revenues. Increased volumes and higher crude oil prices during 2006 as compared to 2005 have resulted in increased revenues related to loss allowance oil. The average NYMEX crude oil price for 2006 was $66.27 per barrel versus $56.65 in 2005 and $41.29 in 2004. The increase in volumes and related tariff revenues in 2005 versus 2004 is primarily related to the Link acquisition and other acquisitions completed during 2005 and 2004. The increase primarily resulted from the inclusion of the related assets for the entire 2005 period versus only a portion of the 2004 period.
•
Increased field operating costs - Field operating costs have increased for most categories of costs for 2006 as we have continued to grow through acquisitions and expansion projects. The most significant cost increases in 2006 have been related to (i) payroll and benefits, (ii) utilities, (iii) integrity work, and (iv) property taxes. Utilities increased approximately $10 million in 2006 over the prior year due to a variety of factors including (i) an increase in electricity consumption related to increased volumes, partially offset by lower electricity market prices and (ii) a true-up of prior and current accruals following receipt of final billing information upon expiration of an existing term arrangement with a significant electricity provider. Our costs increased in 2005 as compared to 2004, primarily from the Link acquisition and other acquisitions completed during 2004. The 2005 increased costs primarily relate to (i) payroll and benefits, (ii) emergency response and environmental remediation of pipeline releases, (iii) maintenance and (iv) utilities.
•
Increased segment G&A expenses - Segment G&A expenses excluding LTIP charges were relatively flat in 2006 compared to 2005. The increase in segment G&A expenses in 2005 is primarily related to the acquisition activity.
•
Increased LTIP expenses - LTIP charges included in field operating costs and segment G&A expenses increased approximately $9 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP-related charges increased approximately $8 million in 2005 over 2004, primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit. See Note 10 to our Consolidated Financial Statements.
As discussed above, the increase in transportation segment profit is largely related to our acquisition activities. We have completed a number of acquisitions during 2006, 2005 and 2004 that have impacted our results of operations. The following table summarizes the year-over-year impact that recent acquisitions and expansion projects have had on tariff revenue and volumes:
(1)
Revenues include intersegment amounts.
(2)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the year.
(3)
To the extent there has been an expansion to one of our existing pipeline systems, any incremental revenues and volumes from the expansion are included in the category for the period that the pipeline was acquired. For new pipeline systems that we construct, incremental revenues and volumes are included in the period the system became operational.
In 2006, average daily volumes from our tariff activities increased by approximately 300 thousand barrels per day or 17% and tariff revenues increased by approximately $68 million or 18%. The increase in volumes and tariff revenues is attributable to a combination of the following factors:
•
Pipeline systems acquired or brought into service during 2006, which contributed approximately 178,000 barrels per day and $33 million of revenues during 2006;
•
Revenues from some of the Canadian pipeline systems increased approximately $9 million in 2006 primarily due to the appreciation of Canadian currency (the Canadian to US dollar exchange rate appreciated to an average of 1.13 to 1 for 2006 compared to an average of 1.21 to 1 in 2005);
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An increase of approximately $7 million from our loss allowance oil primarily resulting from higher crude oil prices;
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Volumes and revenues from pipeline systems in which we entered into new multi-year contracts with shippers, which contributed approximately 70,000 barrels per day and approximately $4 million of revenues during 2006; and
•
Increased volumes and revenues from the North Dakota/Trenton pipeline system resulting from our expansion activities on that system.
In 2005, average daily volumes from our tariff activities increased by approximately 300 thousand barrels per day or 22% and revenues from our tariff activities increased by approximately $71 million or 23%. The increase in total revenues is attributable to a combination of the following factors:
•
Pipeline systems acquired or brought into service during 2005, which contributed approximately 96,000 barrels per day and $14.1 million of revenues during 2005. Approximately 66,000 barrels per day and $7.2 million of revenues are attributable to our recently constructed Cushing to Broome pipeline system.
•
Volumes and revenues from pipeline systems acquired in 2004 increased in 2005 as compared to 2004, reflecting the following:
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An increase of 118,000 barrels per day and $15.8 million of revenues from the pipelines acquired in the Link acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period. The 2005 period also includes (i) increased revenues from our loss allowance oil resulting from higher crude oil prices and (ii) increased revenues from the North Dakota/Trenton pipeline system resulting from our expansion activities on that system. These increases were partially offset by the impact of a reduction in tariff rates that were voluntarily lowered to encourage third party shippers. Transportation segment profit was reduced by approximately $12.0 million because of these market rate adjustments. As a result of these lower tariffs on barrels shipped by us in connection with our gathering and marketing activities, segment profit from marketing was increased by a comparable amount,
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An increase of 17,000 barrels per day and $4.4 million of revenues from the pipelines acquired in the Capline acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period, and
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An increase of 5,000 barrels per day and $2.4 million of revenues from other businesses acquired in 2004.
•
Volumes and revenues from pipeline systems acquired in 2003 increased in 2005 as compared to 2004, reflecting the following:
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An increase of 5,000 barrels per day and $5.2 million of revenues from the Red River pipeline system acquisition, reflecting increased tariff rates on the system, partially related to the quality of crude oil shipped,
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An increase of $3.0 million of revenues related to higher realized prices on our loss allowance oil, and
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An increase of 12,000 barrels per day and $4.8 million of revenues in 2005 compared to 2004 from other businesses acquired in 2003, primarily related to higher volumes.
•
Revenues from all other pipeline systems also increased in 2005, along with a slight increase in volumes. The increase in revenues is related to several items including:
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The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.21 to 1 for 2005 compared to an average of 1.30 to 1 in 2004), and
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Volume increases on certain of our systems, partially related to a shift of certain minor pipeline systems from our marketing segment.
Maintenance Capital
For the years ended December 31, 2006, 2005 and 2004, maintenance capital expenditures for our transportation segment were approximately $20.0 million, $8.5 million and $7.7 million, respectively. The increase in 2006 is due to our continued growth through acquisitions and expansion projects.
Facilities
As of December 31, 2006, we owned approximately 60 million barrels of active above-ground crude oil, refined products and LPG storage tanks, of which approximately 30 million barrels are included in our facilities segment. The remaining tanks are utilized in our transportation segment. At year end 2006, the Partnership was in the process of constructing approximately 12.5 million barrels of additional above ground terminalling and storage facilities, which we expect to place in service during 2007 and 2008.
Our facilities segment generally consists of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products and LPG, as well as LPG fractionation and isomerization
services. On a stand-alone basis, segment profit from facilities activities is dependent on the storage capacity leased, volume of throughput and the level of fees for such services.
We generate fees through a combination of month-to-month and multi-year leases and processing arrangements. Fees generated in this segment include (i) storage fees that are generated when we lease tank capacity and (ii) terminalling fees, or throughput fees, that are generated when we receive crude oil or refined products from one connecting pipeline and redeliver crude oil or refined products to another connecting carrier.
Our facilities segment also includes our equity earnings from our investment in PAA/Vulcan. At December 31, 2006, PAA/Vulcan owned and operated approximately 25.7 billion cubic feet of underground storage capacity and was constructing an additional 24 billion cubic feet of underground storage capacity.
Total revenues for our facilities segment have increased over the three-year period ended December 31, 2006. The revenue increase in each period is driven primarily by increased volumes resulting from our acquisition activities and, to a lesser extent, tankage construction projects completed in 2005 and 2006.
The following table sets forth our operating results from our facilities segment for the periods indicated:
(1)
Revenues include intersegment amounts.
(2)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.
(3)
Compensation expense related to our Long-Term Incentive Plans.
(4)
Volumes associated with acquisitions represent total volumes for the number of months we actually owned the assets divided by the number of months in the period.
(5)
Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude oil barrel ratio; and (iii) LPG processing
volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.
Segment profit (our primary measure of segment performance) and revenues were impacted in 2006 by the following:
•
Increased revenues from crude facilities - The increase in volumes and related revenues during 2006 primarily relates to (i) increased volumes stored due to a pronounced contango market, (ii) the Pacific acquisition and other acquisitions completed during 2006 and 2005, and (iii) the utilization of capacity at the Mobile facility that was acquired from Link in 2004 but not used extensively until 2006;
•
Increased revenues from LPG facilities - The increase in volumes and related revenues during 2006 primarily relates to four LPG facilities that were brought into service during 2005 but were operational for the entire 2006 period compared to only a portion of 2005;
•
Increased revenues from refined product storage and terminalling - The Pacific acquisition introduced a refined products storage and terminalling revenue stream in 2006, which contributed additional revenues of $5.3 million; and
•
Increased revenues from LPG processing - The acquisition of the Shafter processing facility during 2006 resulted in additional processing revenues of approximately $24 million.
Segment profit was also impacted in 2006 by the following:
•
Increased field operating costs - Our continued growth, primarily from the acquisitions completed during 2006 and 2005 and the additional tankage added in 2006 and 2005, is the principal cause of the increase in field operating costs in 2006. Of the total increase, $10.9 million relates to the operating costs associated with the Shafter processing facility. The remainder of the increase in operating costs primarily relate to (i) payroll and benefits, (ii) maintenance and (iii) utilities;
•
Increased segment G&A expenses - Segment G&A expenses excluding LTIP charges increased in 2006 compared to 2005 primarily as a result of an increase in the indirect costs allocated to the facilities segment in 2006 as the operations have grown in that period;
•
Increased LTIP expenses - LTIP charges included in field operating costs and segment G&A expenses increased approximately $3.6 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP related charges increased approximately $1.1 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit (see Note 10 to our Consolidated Financial Statements); and
•
Increased equity in earnings from unconsolidated entities - Our investment in PAA/Vulcan contributed $4.8 million in additional earnings, reflecting the inclusion of this investment for the entire 2006 period compared to only two months in 2005.
Segment profit and revenues also increased in 2005 compared to 2004 and were impacted by the following:
•
Increased revenues from crude facilities - The increase in volumes and related revenues during 2005 primarily relates to (i) increased volumes stored due to a pronounced contango market, (ii) acquisitions completed during 2005 and 2004, and (iii) increased throughput at our Cushing terminal; and
•
Increased revenues from LPG facilities - The increase in volumes and related revenues during 2005 primarily relates to acquisitions of new facilities completed during 2005; at the end of 2005, we owned ten facilities compared to four at the beginning of 2004.
Segment profit in 2005 was also impacted by the following:
•
Increased field operating costs - Our continued growth, primarily from the acquisitions completed during 2005 and 2004 and the additional tankage added in 2005 and 2004, is the principal cause of the increase in
field operating costs in 2005. The increased costs primarily relate to (i) payroll and benefits, (ii) maintenance and (iii) utilities; and
•
Increased segment G&A expenses - Segment G&A expenses excluding LTIP charges increased in 2005 compared to 2004 primarily as a result of an increase in the indirect costs allocated to the facilities segment in 2005 as the operations grew in that period. LTIP related charges increased approximately $1.1 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit.
Maintenance Capital
For the years ended December 31, 2006, 2005 and 2004, maintenance capital expenditures for our facilities segment were approximately $4.9 million, $1.1 million and $2.0 million, respectively. The increase in 2006 is primarily due to additional maintenance requirements at our Alto and Shafter facilities.
Marketing
Our revenues from marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG volumes, as well as marketing of natural gas liquids, plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices. However, the margins related to those purchases and sales will not necessarily have corresponding increases and decreases. We do not anticipate that future changes in revenues will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in our marketing segment volumes (which consist of (i) lease gathered volumes, (ii) LPG sales, and (iii) waterborne foreign crude imported) as well as the overall volatility and strength or weakness of market condition and the allocation of our assets among our various hedge positions. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. Although we believe that the combination of our lease gathered business and our hedging activities provides a counter-cyclical balance that provides stability in our margins, these margins are not fixed and may vary from period to period.
Revenues from our marketing operations were approximately $22.1 billion, $30.9 billion and $20.8 billion for the years ended December 31, 2006, 2005 and 2004, respectively. Total revenues for our marketing segment decreased in 2006 as compared to 2005 due to a combination of the following factors:
•
A decrease in our 2006 revenues due to the adoption of EITF 04-13 which was equally offset with purchases and related costs and does not impact segment profit (see Note 2 to our Consolidated Financial Statements); offset by
•
An increase in the average NYMEX price for crude oil in 2006 as compared to 2005. The average NYMEX price for crude oil was $66.27, $56.65 and $41.29 per barrel for the years ended December 31, 2006, 2005 and 2004, respectively. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales.
In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit, (ii) marketing segment volumes and (iii) segment profit per barrel calculated on these volumes. The following table sets forth our operating results from our marketing segment for the comparable periods indicated:
(1)
Revenues and purchases and related costs include intersegment amounts.
(2)
Includes revenues associated with buy/sell arrangements of $4,761.9 million, $16,274.9 million and $11,396.8 million for the years ended December 31, 2006, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 919,500, 851,900 and 800,700 barrels per day for the years ended December 31, 2006, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances. See Note 2 to our Consolidated Financial Statements.
(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit.
(4)
Includes purchases associated with buy/sell arrangements of $4,795.1 million, $16,106.5 million and $11,280.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 926,800, 851,900 and 800,700 barrels per day for the years ended December 31, 2006, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances. See Note 2 to our Consolidated Financial Statements.
(5)
Purchases and related costs include interest expense on contango inventory purchases of $49.2 million, $23.7 million and $2.0 million for the years ended December 31, 2006, 2005 and 2004, respectively.
(6)
Compensation expense related to our Long-Term Incentive Plans.
(7)
Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.
(8)
Calculated based on crude oil lease gathered volumes, LPG sales volumes, and waterborne foreign crude volumes.
(9)
Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
Segment profit for 2006 ($228.0 million) exceeded the segment profit for 2005 ($175.4 million). The increase was primarily related to very favorable market conditions and successful execution of risk management strategies coupled with increased volumes and synergies realized from businesses acquired in the last two years.
The primary factors affecting current period results were:
•
Acquisitions - During 2006 we purchased certain crude oil gathering assets and related contracts in South Louisiana and Andrews Petroleum and Lone Star Trucking. The Andrews acquisition impacted our facilities, marketing and transportation segments. See Note 3 to our Consolidated Financial Statements.
•
Favorable market conditions and execution of our risk management strategies - During 2006 and 2005, the crude oil market experienced significantly high volatility in prices and market structure. The NYMEX benchmark price of crude oil ranged from $54.86 to $78.40 during 2006. The volatile market allowed us to utilize risk management strategies to optimize and enhance the margins of our gathering and marketing activities. The market was in contango for most of 2006 and the time spread of prices averaged approximately $1.22 versus $0.72 for 2005; this increase in spreads was partially offset by an increase in the cost to carry the inventory that was not only impacted by the increase in LIBOR rates but also by the increase in NYMEX prices. Marketing segment profit includes contango and other hedged inventory related interest expense of approximately $49.2 million for 2006 incurred to store the crude oil. This cost is included in Purchases and related costs in the table above.
•
SFAS 133 mark-to-market - 2006 includes SFAS 133 mark-to-market losses of $4.4 million compared to a loss of $18.9 million for 2005. See Note 6 to our Consolidated Financial Statements.
•
Inventory Adjustment - In 2006, we recognized a $5.9 million non-cash charge primarily associated with declines in oil prices and other product prices during the third and fourth quarters of 2006 and the related decline in the valuation of working inventory volumes. Approximately $3.4 million of the charge relates to crude oil inventory in pipelines owned by third parties and the remainder relates to LPG and other products inventory.
•
Field operating costs and segment G&A expenses - Field operating costs (excluding LTIP charges) increased in 2006 compared to 2005, primarily as a result of increases in (i) payroll and benefits and contract transportation as a result of 2006 acquisitions, (ii) fuel costs and (iii) maintenance costs. The increase in general and administrative expenses (excluding LTIP charges) is primarily the result of an increase in the indirect costs allocated to the marketing segment in 2006 as the operations have grown. The increase in field operating costs in 2005 compared to 2004 was primarily the result of an increase in (i) fuel costs and (ii) payroll and benefits.
•
Increased LTIP expenses - LTIP charges included in field operating costs and segment G&A expenses increased approximately $3.8 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP related charges increased approximately $9.5 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit. See Note 10 to our Consolidated Financial Statements.
Segment profit per barrel (calculated based on our marketing volumes included in the table above) was $0.80 for 2006, compared to $0.66 for 2005 and $0.34 for 2004. As discussed above, our current period results were impacted by favorable market conditions. We are not able to predict with any reasonable level of accuracy whether market conditions will remain as favorable as have recently been experienced, and these operating results may not be indicative of sustainable performance.
Maintenance capital
For the years ended December 31, 2006, 2005 and 2004, maintenance capital expenditures were approximately $3.3 million, $4.4 million, and $1.6 million, respectively, for our marketing segment.
Other Income and Expenses
Depreciation and Amortization
Depreciation and amortization expense was $100.4 million for the year ended December 31, 2006, compared to $83.5 million and $68.7 million for the years ended December 31, 2005 and 2004, respectively. The increases in 2006 and 2005 related primarily to an increased amount of depreciable assets resulting from our acquisition activities and capital projects. Also contributing to the increase in 2005 was a non-cash loss related to sales of assets. Amortization of debt issue costs was $2.5 million in 2006, $2.8 million in 2005, and $2.5 million in 2004.
Interest Expense
Interest expense was $85.6 million for the year ended December 31, 2006, compared to $59.4 million and $46.7 million for the years ended December 31, 2005 and 2004, respectively. Interest expense is primarily impacted by:
•
our average debt balances;
•
the level and maturity of fixed rate debt and interest rates associated therewith;
•
market interest rates and our interest rate hedging activities on floating rate debt; and
•
interest capitalized on capital projects.
The following table summarizes selected components of our average debt balances:
(1)
Weighted average face amount of senior notes, exclusive of discounts.
(2)
Excludes borrowings under our senior secured hedged inventory facility and capital leases.
The issuance of senior notes and the assumption of Pacific’s debt in 2006 resulted in an increase in the average amount of longer term and higher cost fixed-rate debt outstanding in 2006. The overall higher average debt balances in 2006 and 2005 were primarily related to the portion of our acquisitions that were not financed with equity, coupled with borrowings related to other capital projects. During 2006, 2005 and 2004, the average LIBOR rate was 5.0%, 3.2%, and 1.6%, respectively. Our weighted average interest rate, excluding commitment and other fees, was approximately 6.1% in 2006, compared to 5.6% and 5.0% in 2005 and 2004, respectively. The impact of the increased debt balance was an increase in interest expense of $26.0 million, and the impact of the higher weighted-average interest rate was an increase in interest expense of $4.7 million. Both of these increases were primarily offset by an increase in capitalized interest of $4.2 million. The net impact of the items discussed above was an increase in interest expense in 2006 of approximately $26.2 million.
The higher average debt balance in 2005 as compared to 2004 resulted in additional interest expense of approximately $12.7 million, while at the same time our commitment and other fees decreased by approximately $1.8 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 5.6% for 2005 compared to 5.0% for 2004. The higher weighted average rate increased interest expense by approximately $12.7 million in 2005 compared to 2004.
Interest costs attributable to borrowings for inventory stored in a contango market are included in purchases and related costs in our marketing segment profit as we consider interest on these borrowings a direct cost to storing the inventory. These borrowings are primarily under our senior secured hedged inventory facility. These costs were approximately $49.2 million, $23.7 million and $2.0 million for the years ended December 31, 2006, 2005 and 2004, respectively.
Outlook
This section identifies certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.
Ongoing Acquisition Activities. Consistent with our business strategy, we are continuously engaged in discussions regarding potential acquisitions by us of transportation, gathering, terminalling or storage assets and related midstream businesses. These acquisition efforts often involve assets that, if acquired, could have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass midstream businesses outside of the scope of our current operations, but with respect to which these resources effectively can be applied. For example, during 2006 we entered the refined products transportation and storage business as well as the barge transportation business. We are presently engaged in discussions and negotiations with various parties regarding the acquisition of assets and businesses described above, but we can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.
Pipeline Integrity and Storage Tank Testing Compliance. Although we believe our short-term estimates of costs under the pipeline integrity management rules and API 653 (and similar regulations in Canada) are reasonable, a high degree of uncertainty exists with respect to estimating such costs, as we continue to test existing assets and as we acquire additional assets.
In September 2006, the DOT published a Notice of Proposed Rulemaking (“NPRM”) that proposed to regulate certain hazardous liquid gathering and low stress pipeline systems that are not currently subject to regulation. On December 6, 2006, the Congress passed, and on December 29, 2006 President Bush signed into law, H.R. 5782, the “Pipeline Inspection, Protection, Enforcement and Safety Act of 2006” (2006 Pipeline Safety Act), which reauthorizes and amends the DOT’s pipeline safety programs. Included in the 2006 Pipeline Safety Act is a provision eliminating the regulatory exemption for hazardous liquid pipelines operated at low stress, which was one of the focal points of the September 2006 NPRM. The Act requires DOT to issue regulations by December 31, 2007 for those hazardous liquid low stress pipelines now subject to regulation pursuant to the Act. Regulations issued by December 31, 2007 with respect to hazardous liquid low stress pipelines as well as any future regulation of hazardous liquid gathering lines could include requirements for the establishment of additional pipeline integrity management programs for these newly regulated pipelines. We do not currently know what, if any, impact these developments will have on our operating expenses and, thus, cannot provide any assurances that future costs related to these programs will not be material.
In addition to performing DOT-mandated pipeline integrity evaluations, during 2006, we expanded an internal review process started in 2005 in which we are reviewing various aspects of our pipeline and gathering systems that are not subject to the DOT pipeline integrity management rule. The purpose of this process is to review the surrounding environment, condition and operating history of these pipelines and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, we may be required (as a result of additional DOT regulation) or we may elect (as a result of our own initiatives) to spend substantial sums to ensure the integrity of and upgrade our pipeline systems to maintain environmental compliance and, in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.
Longer-Term Outlook. Our longer-term outlook, spanning a period of five or more years, is influenced by many factors affecting the North American midstream energy sector. Some of the more significant trends and factors relating to crude oil include:
•
Continued overall depletion of U.S. crude oil production.
•
The continuing convergence of worldwide crude oil supply and demand trends.
•
The expected extension of DOT regulations to low stress and gathering pipelines.
•
Industry compliance with the DOT’s adoption of API 653 for testing and maintenance of storage tanks, which will require significant investments to maintain existing crude oil storage capacity or, alternatively, will result in a reduction of existing storage capacity by 2009.
•
The addition of inspection requirements by EPA for storage tanks not subject to DOT’s API 653 requirements.
•
The expectation of increased crude oil production from certain North American regions (primarily Canadian oil sands and deepwater Gulf of Mexico sources) that will, of economic necessity, compete for U.S. markets currently being supplied by non-North American foreign crude imports.
We believe the collective impact of these trends, factors and developments, many of which are beyond our control, will result in an increasingly volatile crude oil market that is subject to more frequent short-term swings in market prices and grade differentials and shifts in market structure. In an environment of tight supply and demand balances, even relatively minor supply disruptions can cause significant price swings, which were evident in 2005. Conversely, despite a relatively balanced market on a global basis, competition within a given region of the U.S. could cause downward pricing pressure and significantly impact regional crude oil price differentials among crude oil grades and locations. Although we believe our business strategy is designed to manage these trends, factors and potential developments, and that we are strategically positioned to benefit from certain of these developments, there can be no assurance that we will not be negatively affected.
We are also regularly evaluating midstream businesses that are complementary to our existing businesses and that possess attractive long-term growth prospects. Through PAA/Vulcan’s acquisition of ECI in 2005, the Partnership entered the natural gas storage business. Although our investment in natural gas storage assets is currently relatively small when considering the Partnership’s overall size, we intend to grow this portion of our business through future acquisitions and expansion projects. We believe that strategically located natural gas storage facilities will become increasingly important in supporting the reliability of gas service needs in the United States. Rising demand for natural gas is outpacing domestic natural gas production, creating an increased need for imported natural gas. A continuation of this trend will result in increased natural gas imports from Canada and the Gulf of Mexico, and LNG imports. We believe our business strategy and expertise in hydrocarbon storage will allow us to grow our natural gas storage platform and benefit from these trends.
During 2006, we entered the refined products transportation and storage business. We believe that this business will be driven by increased demand for refined products, growth in the capacity of refineries and increased reliance on imports. We believe that demand for refined products will increase as a result of multiple specifications of existing products (also referred to as boutique gasoline blends), specification changes to existing products, such as ultra low sulfur diesel, and new products, such as bio-fuels. In addition, “capacity creep” as well as large expansion projects at existing refineries will likely necessitate construction of additional refined products transportation and storage infrastructure. We intend to grow our asset base in the refined products business through future acquisitions and expansion projects. We also intend to apply our business model to the refined products business by establishing and growing a marketing and distribution business to complement our strategically located assets.
Liquidity and Capital Resources
The Partnership has a defined financial growth strategy that states how we intend to finance our growth and sets forth targeted credit metrics. We have also established a targeted credit rating. See Items 1 and 2. “Business and Properties - Financial Strategy.”
Cash flow from operations and our credit facilities are our primary sources of liquidity. At December 31, 2006, we had working capital of approximately $133 million, approximately $1.25 billion of availability under our committed revolving credit facilities and approximately $0.4 million of availability under our uncommitted hedged inventory facility. Usage of the credit facilities is subject to ongoing compliance with covenants. We believe we are currently in compliance with all covenants.
Cash flow from operations
The crude oil market was in contango for much of 2006 and 2005. Because we own crude oil storage capacity, during a contango market we can buy crude oil in the current month and simultaneously hedge the crude by selling it forward for delivery in a subsequent month. This activity can cause significant fluctuations in our cash flow from operating activities as described below.
The primary drivers of cash flow from our operations are (i) the collection of amounts related to the sale of crude oil and other products, the transportation of crude oil and other products for a fee, and storage and terminalling services, and (ii) the payment of amounts related to the purchase of crude oil and other products and other expenses, principally field operating costs and general and administrative expenses. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except (i) in the months that we store the purchased crude oil and hedge it by selling it forward for delivery in a subsequent month because of contango market conditions or (ii) in months in which we increase our share of linefill in third party pipelines. The storage of crude oil in periods of a contango market can have a material negative impact on our cash flows from operating activities for the period in which we pay for and store the crude oil (as is the case for much of 2006, including at December 31, 2006) and a material positive impact in the subsequent period in which we receive proceeds from the sale of the crude oil. In the month we pay for the stored crude oil, we borrow under our credit facilities (or pay from cash on hand) to pay for the crude oil, which negatively impacts our operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, but to a lesser extent, the level of LPG and other product inventory stored and held for resale at period end affects our cash flow from operating activities.
In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it. Our accounts payable and accounts receivable generally vary proportionately because we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. However, when the market is in contango, our accounts receivable, accounts payable, inventory and short-term debt balances are all impacted, depending on the point of the cycle at any particular period end. As a result, we can have significant fluctuations in those working capital accounts, as we buy, store and sell crude oil.
Our cash flow used in operating activities in 2006 was $275.3 million compared to cash provided by operating activities of $24.1 million in 2005. This change reflects cash generated by our recurring operations offset by an increase in certain working capital items of approximately $703 million. In 2006, the market was in contango and we increased our storage of crude oil and other products (financed through borrowings under our credit facilities), resulting in a negative impact on our cash flows from operating activities for the period, as explained above. The fluctuations in accounts receivable and other and accounts payable and other current liabilities are primarily related to purchases and sales of crude oil that generally vary proportionately.
Cash flow from operating activities was $24.1 million in 2005 and reflects cash generated by our recurring operations (as indicated above in describing the primary drivers of cash generated from operations), offset by changes in components of working capital, including an increase in inventory. A significant portion of the increased inventory has been purchased and stored due to contango market conditions and was paid for during the period via borrowings under our credit facilities or from cash on hand. As mentioned above, this activity has a negative impact in the period that we pay for and store the inventory. In addition, there was a change in working capital resulting from higher NYMEX margin deposits paid during 2005 that had a negative impact on our cash flows from operations. The fluctuations in accounts receivable and other and accounts payable and other current liabilities are primarily related to purchases and sales of crude oil that generally vary proportionately.
Cash flow from operating activities was $104.0 million in 2004 and reflects cash generated by our recurring operations that was offset negatively by several factors totaling approximately $100 million. The primary factor was a net increase in hedged crude oil and LPG inventory and linefill in third party assets that was financed with borrowings under our credit facilities (approximately $75 million net). Cash flow from operations was also negatively impacted by a decrease of approximately $20 million in prepayments received from counterparties to mitigate credit risk.
Cash provided by equity and debt financing activities
We periodically access the capital markets for both equity and debt financing. We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $2 billion of debt or equity securities. At December 31, 2006, we have approximately $1.1 billion of unissued securities remaining available under this registration statement.
Cash provided by financing activities was $1,927.0 million, $270.6 million and $554.5 million for each of the last three years, respectively. Our financing activities primarily relate to funding (i) acquisitions, (ii) internal capital projects and (iii) short-term working capital and hedged inventory borrowings related to our contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings under our credit facilities. During 2006, we borrowed under our credit facilities to pay for the storage of crude oil and other products under contango market conditions.
Equity Offerings. During the last three years we completed several equity offerings as summarized in the table below. Certain of these offerings involved related parties. See Note 9 to our Consolidated Financial Statements:
(1)
Includes our general partner’s proportionate capital contribution and is net of costs associated with the offering.
(2)
Excludes the common units issued and our general partner’s proportionate capital contribution of $21.6 million pertaining to the equity exchange for the Pacific acquisition.
Senior Notes and Credit Facilities. During the three years ended December 31, 2006 we completed the sale of senior unsecured notes as summarized in the table below.
(1)
Face value of notes less the applicable discount (before deducting for initial purchaser discounts, commissions and offering expenses).
During the year ended December 31, 2006, we had net working capital and hedged inventory borrowings of approximately $618.8 million. These borrowings are used primarily for purchases of crude oil inventory that was stored. See “- Cash flow from operations.” During 2006 and 2005, we also had net repayments on our long-term revolving credit facility of approximately $298.5 million and $143.7 million, respectively, resulting from cash generated from our operations and other financing activities. During 2004, we had net borrowings on our long-term revolving credit facility of approximately $64.9 million. During 2005, we had net working capital and hedged inventory borrowings of approximately $206.1 million and during 2004 we had net borrowings of approximately $42.8 million. For further discussion related to our credit facilities and long-term debt, see “- Credit Facilities and Long-term Debt.”
Capital Expenditures and Distributions Paid to Unitholders and General Partner
We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above. Our primary uses of cash are for our acquisition activities, capital expenditures for internal growth projects and distributions paid to our unitholders and general partner. See “- Acquisitions and Internal Growth Projects.” The price of the acquisitions includes cash paid, transaction costs and assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisition and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the year.
Distributions to unitholders and general partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Total cash distributions made during the last three years were as follows (in millions, except per unit amounts):
(1)
The subordinated units were converted to common units in 2004.
2007 Capital Expansion Projects. Our 2007 projects include the following projects with the estimated cost for the entire year (in millions):
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.
Credit Facilities and Long-term Debt
In July 2006, we amended our senior unsecured revolving credit facility to increase the aggregate capacity from $1.0 billion to $1.6 billion and the sub-facility for Canadian borrowings from $400 million to $600 million. The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and has a final maturity of July 2011.
In November 2006, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $800 million to $1.0 billion. We also extended the maturity of the senior secured hedged inventory facility to November 2007.
We also have several issues of senior debt outstanding that total $2.6 billion, excluding premium or discount, and range in size from $150 million to $600 million and mature at various dates through 2037. See Note 9 to our Consolidated Financial Statements.
In November 2006, in conjunction with the Pacific merger, we assumed two issues of Senior Notes with an aggregate principal balance of $425 million. Interest payments on the $175 million of 6.25% Senior Notes are due on March 15 and September 15 of each year. The notes mature on September 15, 2015. Interest payments on the $250 million of 7.125% Senior Notes are due on June 15 and December 15 of each year. The notes mature on June 15, 2014. We have the option to redeem the notes, in whole or in part, at any time on or after the date noted at the following redemption prices:
In October 2006, we issued $400 million of 6.125% Senior Notes due 2017 and $600 million of 6.65% Senior Notes due 2037. The notes were sold at 99.56% and 99.17% of face value, respectively. Interest payments are due on January 15 and July 15 of each year. We used the proceeds to fund the cash portion of our merger with Pacific. Net proceeds in excess of the cash portion of the merger consideration were used to repay amounts outstanding under our credit facilities and for general partnership purposes. In anticipation of the issuance of these notes, we had entered into $200 million notional principal amount of U.S. treasury locks to hedge the treasury rate portion of the interest rate on a portion of the notes. The treasury locks were entered into at an interest rate of 4.97%.
During May 2006, we completed the sale of $250 million aggregate principal amount of 6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
All our notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for two subsidiaries with assets regulated by the California Public Utility Commission, and certain minor subsidiaries. See Note 12 to our Consolidated Financial Statements.
Our credit agreements and the indentures governing our senior notes contain cross default provisions. Our credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:
•
incur indebtedness if certain financial ratios are not maintained;
•
grant liens;
•
engage in transactions with affiliates;
•
enter into sale-leaseback transactions; and
•
sell substantially all of our assets or enter into a merger or consolidation.
Our credit facility treats a change of control as an event of default and also requires us to maintain a debt coverage ratio that will not be greater than 4.75 to 1.0 on all outstanding debt and 5.25 to 1.0 on outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).
For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.
A default under our credit facility would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. We are currently in compliance with the covenants contained in our credit agreements and indentures.
Contingencies
See Note 11 to our Consolidated Financial Statements.
Commitments
Contractual Obligations. In the ordinary course of doing business we purchase crude oil and LPG from third parties under contracts, the majority of which range in term from thirty-day evergreen to three years. We establish a margin for these purchases by entering into various types of physical and financial sale and exchange transactions through which we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The table below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and those subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to creditworthy entities.
The following table includes our best estimate of the amount and timing of these payments as well as others due under the specified contractual obligations as of December 31, 2006.
(1)
Includes debt service payments, interest payments due on our senior notes and the commitment fee on our revolving credit facility. Although there is an outstanding balance on our revolving credit facility at December 31, 2006 (this amount is included in the amounts above), we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no amounts were outstanding on the facility) in the amounts above.
(2)
Leases are primarily for office rent and trucks used in our gathering activities.
(3)
Excludes approximately $21.4 million non-current liability related to SFAS 133 included in crude oil and LPG purchases.
(4)
Amounts are based on estimated volumes and market prices. The actual physical volume purchased and actual settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.
Letters of Credit. In connection with our crude oil marketing, we provide certain suppliers with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2006, we had outstanding letters of credit of approximately $185.8 million.
Capital Contributions to PAA/Vulcan Gas Storage, LLC. We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the
obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time. See Note 8 to our Consolidated Financial Statements.
Distributions. We plan to distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter, less reserves established in the discretion of our general partner for future requirements. On February 14, 2007, we paid a cash distribution of $0.80 per unit on all outstanding units. The total distribution paid was approximately $104.6 million, with approximately $87.5 million paid to our common unitholders and approximately $17.1 million paid to our general partner for its general partner interest ($1.8 million) and incentive distribution interest ($15.3 million).
Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per limited partner unit, 25% of amounts we distribute in excess of $0.495 per limited partner unit and 50% of amounts we distribute in excess of $0.675 per limited partner unit.
Upon closing of the Pacific acquisition, our general partner agreed to reduce the amounts of its incentive distributions commencing with the earlier to occur of (i) the payment date of the first quarterly distribution declared and paid after the closing date that equals or exceeds $0.80 per unit or (ii) the payment date of the second quarterly distribution declared and paid after the closing date. Such adjustment shall be as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. Pursuant to this agreement, the incentive distribution paid to the general partner on February 14, 2007 was reduced by $5 million. The total reduction in incentive distributions will be $65 million.
In 2006, we paid $33.1 million in incentive distributions to our general partner. See Item 13. “Certain Relationships and Related Transactions, and Director Independence - Our General Partner.”
Off-Balance Sheet Arrangements
We have invested in certain entities (PAA/Vulcan, Butte, Settoon Towing and Frontier) that are not consolidated in our financial statements. In conjunction with these investments, from time to time we may elect to provide financial and performance guarantees or other forms of credit support. See Note 9 to our Consolidated Financial Statements for more information concerning our obligations as they relate to our investment in PAA/Vulcan.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, including volatility in (i) crude oil, refined products, natural gas and LPG commodity prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage such exposure and, in certain circumstances, to realize incremental margin during volatile market conditions. In analyzing our risk management activities, we draw a distinction between enterprise level risks and trading related risks. Enterprise level risks are those that underlie our core businesses and may be managed based on whether there is value in doing so. Conversely, trading related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in the core business; rather, those risks arise as a result of engaging in the trading activity. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, ICE and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure our hedging activities address our market risks. We have a risk management function that has direct responsibility and authority for our risk policies and our trading
controls and procedures and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. With the exception of the controlled trading program discussed below, our approved strategies are intended to mitigate enterprise level risks that are inherent in our core businesses of gathering and marketing and storage. To hedge the risks discussed above we engage in risk management activities that we categorize by the risks we are hedging. The following discussion addresses each category of risk.
Commodity Price Risk
We hedge our exposure to price fluctuations with respect to crude oil, refined products, natural gas and LPG in storage, and expected purchases and sales of these commodities (relating primarily to crude oil and LPGs at this time). The derivative instruments utilized consist primarily of futures and option contracts traded on the NYMEX, ICE and over-the-counter transactions, including swap and option contracts entered into with financial institutions and other energy companies. Our policy is to purchase only commodity products for which we have a market, and to structure our sales contracts so that price fluctuations for those products do not materially affect the segment profit we receive. Except for the controlled trading program discussed below, we do not acquire and hold futures contracts or other derivative products for the purpose of speculating on price changes, as these activities could expose us to significant losses.
Although we seek to maintain a position that is substantially balanced within our various commodity purchase and sales activities (which mainly relate to crude oil and LPGs), we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil.
Although the intent of our risk-management strategies is to hedge our margin, not all of our derivatives qualify for hedge accounting. In such instances, changes in the fair values of these derivatives will receive mark-to-market treatment in current earnings, and result in greater potential for earnings volatility. This accounting treatment is discussed further under Note 2 to our Consolidated Financial Statements.
All of our open commodity price risk derivatives at December 31, 2006 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a 10 percent price increase are shown in the table below:
The fair value of futures contracts is based on quoted market prices obtained from the NYMEX or ICE. The fair value of swaps and option contracts is estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at year end. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. The assumptions used in these estimates as well as the source for the estimates are maintained by the independent risk control function. All hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent increase in price regardless of term or
historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
Interest Rate Risk
We use both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we use interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. In addition, in connection with the Pacific merger, we assumed interest rate swaps with an aggregate notional amount of $80 million. The interest rate swaps are a hedge against changes in the fair value of the 7.125% Senior Notes resulting from market fluctuations to LIBOR. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at December 31, 2006. All of our senior notes are fixed rate notes and thus not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance rate plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 2006. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates, and the credit spread on outstanding borrowings reflects market.
Currency Exchange Risk
Our cash flow stream relating to our Canadian operations is based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
Because a significant portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of changes in the exchange rate. These instruments may include forward exchange contracts and cross currency swaps.
We estimate the fair value of these instruments based on current termination values. The table shown below summarizes the fair value of our foreign currency hedges by year of maturity (in millions):
Item 8.
Item 8.
Financial Statements and Supplementary Data
See “Index to the Consolidated Financial Statements” on page.
Item 9.
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A.
Controls and Procedures
We maintain written “disclosure controls and procedures,” which we refer to as our “DCP.” The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations
and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure.
Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP. Management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our DCP as of December 31, 2006, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.
In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. Although we have made various enhancements to our controls during preparation for our assertion on internal control over financial reporting, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this report as Exhibits 32.1 and 32.2.
Management is responsible for establishing and maintaining adequate internal control over financial reporting. “Internal control over financial reporting” is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our management, including our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2006. See Management’s Report on Internal Control Over Financial Reporting on page.
Item 9B.
Item 9B.
Other Information
There was no information that was required to be disclosed in a report on Form 8-K during the fourth quarter of 2006 that has not previously been reported.
PART III
Item 10.
Item 10.
Directors and Executive Officers of Our General Partner and Corporate Governance
Partnership Management and Governance
As is the case with many publicly traded partnerships, we do not directly have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Plains All American GP LLC (“GP LLC”), which employs our management and operational personnel (other than our Canadian personnel who are employed by PMC (Nova Scotia) Company). References to our general partner, unless the context otherwise requires, include GP LLC. References to our officers, directors and employees are references to the officers, directors and employees of GP LLC (or, in the case of our Canadian operations, PMC (Nova Scotia) Company).
Our general partner manages our operations and activities. Unitholders are limited partners and do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders, as limited by our partnership agreement. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Our general partner has the sole discretion to incur indebtedness or other obligations on our behalf on a non-recourse basis to the general partner.
Our partnership agreement provides that the general partner will manage and operate us and that, unlike holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business or governance. The corporate governance of GP LLC is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement. Specifically, our partnership agreement defines “Board of Directors” to mean the board of directors of GP LLC, which consists of up to eight directors elected by the members of GP LLC, and not by our unitholders. The Board currently consists of seven directors. Under the Second Amended and Restated Limited Liability Company Agreement of GP LLC (the “GP LLC Agreement”), three of the members of GP LLC have the right to designate one director each and our CEO is a director by virtue of holding the office. In addition, the GP LLC Agreement provides that three independent directors (and an eighth seat that is currently vacant) are elected, and may be removed, by a majority of the membership interest. The vacant seat is not required to be independent.
In August 2005, a former member’s 19% interest in the general partner was sold pro rata to the other general partner owners, resulting in Vulcan Energy’s ownership interest increasing from 44% to 54%. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters - Beneficial Ownership of General Partner Interest.”
In connection with this transaction, Vulcan Energy entered into an agreement with GP LLC pursuant to which Vulcan Energy has agreed to restrict certain of its voting rights to help preserve a balanced board. Vulcan Energy has agreed that, with respect to any action taken involving the election or removal of an independent director, Vulcan Energy will vote all of its interest in excess of 49.9% in the same way and proportionate to the votes of all membership interests other than Vulcan Energy’s. Without the voting agreement, Vulcan Energy’s ownership interest would allow Vulcan Energy, in effect, to unilaterally elect five of the eight board seats: the Vulcan Energy designee, the currently vacant seat and the three independent directors (subject, in the case of the independent directors, to the qualification requirements of the GP LLC Agreement, our partnership agreement, NYSE listing standards and SEC regulations). Vulcan Energy has the right at any time to give notice of termination of the agreement. The time between notice and termination depends on the circumstances, but would never be longer than one year. In connection with the August 2005 transaction, Messrs. Armstrong and Pefanis entered into waivers of the change in control provisions of their employment agreements, which otherwise would have been triggered by the transaction. These waivers were contingent upon Vulcan’s execution of the voting agreement, and will terminate upon any breach or termination by Vulcan Energy of, or notice of termination under, the voting agreement. See Item 11.
Item 11.
Executive Compensation
Compensation Discussion and Analysis
Background
All of our officers and employees (other than Canadian personnel) are employed by Plains All American GP LLC. Our Canadian personnel are employed by PMC (Nova Scotia) Company, which is a wholly owned subsidiary. Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all employment-related costs, including compensation for executive officers.
Objectives
Since our inception, we have employed a compensation philosophy that emphasizes pay for performance, both on an individual and entity level, and places the majority of each Named Executive Officer’s (defined below) compensation at risk. The primary long-term measure of the Partnership’s performance is its ability to increase its sustainable quarterly distribution to its unitholders. We believe our pay-for-performance approach aligns the interests of executive officers with that of our unitholders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance is below expectations. Our executive compensation is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals. We use three primary elements of compensation to fulfill that design - salary, cash bonus and long-term
equity incentive awards. In practice, our salaries are moderate relative to the broad spectrum of energy industry competitors for similar talent, but are generally competitive with the narrower universe of large-cap MLP peers. The determination of specific individuals’ cash bonus is based on their relative contribution to achieving or exceeding annual goals and the determination of specific individuals’ long-term incentive awards is based on their expected contribution in respect of longer term performance benchmarks. Cash bonuses and equity incentives (as opposed to salary) represent the truly performance-driven elements. They are also flexible in application and can be tailored to serve more than one purpose. We do not maintain a defined benefit or pension plan for our executive officers as we believe such plans primarily reward longevity and not performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. In instances considered necessary for the execution of their job responsibilities, we also reimburse certain of our executive officers and other employees for club dues and similar expenses. We consider these benefits and reimbursements to be typical of other employers, and we do not believe they are distinctive of our compensation program.
Elements of Compensation
Salary. We do not “benchmark” our salary or bonus amounts. In practice, our salaries are moderate relative to the broad spectrum of energy industry competitors for similar talent, but are generally competitive with the narrower universe of large-cap MLP peers.
Cash Bonuses. Our cash bonuses consist of annual discretionary bonuses in which all Named Executive Officers potentially participate and a formula-based quarterly bonus program in which Messrs. Coiner and vonBerg participate.
Long-Term Incentive Awards. The primary long-term measure of the Partnership’s performance is its ability to increase its sustainable quarterly distribution to its equity holders. The Partnership uses performance-indexed phantom unit grants to encourage and reward timely achievement of targeted distribution levels and align the long-term interests of the Named Executive Officers with those of the Partnership’s equity owners. These grants also contain minimum service periods as further described below in order to encourage long-term retention. A phantom unit is the right to receive, upon the satisfaction of any vesting criteria specified in the grant, a common unit (or cash equivalent) of the Partnership. The Partnership does not use options as a form of incentive compensation. Unlike “vesting” of an option, vesting of a phantom unit results in delivery of a common unit or cash of equivalent value as opposed to a right to exercise. Terms of historical phantom unit grants have varied, but generally phantom units vest upon the later of achievement of targeted distribution threshold levels and continued employment for periods ranging from two to six years. These distribution performance thresholds are generally consistent with the Partnership’s targeted range for distribution growth. To encourage accelerated performance, if the Partnership meets certain distribution thresholds prior to meeting the minimum service requirement for vesting, the named executive officers have the right to receive distributions on phantom unit grants prior to vesting in the underlying units (referred to as distribution equivalent rights, or “DERs”).
Relation of Compensation Elements to Compensation Objectives
Our compensation program is designed to motivate, reward and retain our executive officers. Cash bonuses serve as a near-term motivation and reward for achieving the annual goals established at the beginning of each year. Phantom unit awards and associated DERs provide motivation and reward over both the near-term and long-term for achieving performance thresholds necessary for vesting. The level of annual bonus and phantom unit awards reflect the moderate salary profile and the significant weighting towards performance-based, at-risk compensation. Salaries and cash bonuses (particularly quarterly bonuses), as well as currently payable DERs associated with unvested phantom units, serve as near-term retention tools. Longer-term retention is facilitated by the minimum service periods of up to five years associated with phantom unit awards and, in the case of Mr. Coiner and Mr. vonBerg, annual bonuses that are payable over a three-year period. To facilitate the compensation committee in reviewing and making recommendations with respect to compensation of Named Executive Officers, the committee is provided a compensation “tally sheet” for such officers.
We stress performance-based compensation elements to attempt to create a performance-driven environment in which our executive officers are (i) motivated to perform over both the short term and the long term,
(ii) appropriately rewarded for their services and (iii) encouraged to remain with the Partnership even after meeting long-term performance thresholds in order to meet the minimum service periods and by the promise of rewards yet to come. We believe our compensation philosophy as implemented by application of the three primary compensation elements aligns the interests of the Named Executive Officers with our equity holders and positions the Partnership to achieve its business goals.
We believe these compensation practices have been successful in achieving our objectives. Over the five-year period ended December 31, 2006, our annual distribution per limited partner unit has grown at a compound annual rate of 8.3% and the total return realized by our limited partner unitholders for that period averaged approximately 23%. Our retention rate for Named Executive Officers over the same period has been 100%.
Application of Compensation Elements
Salary. We do not make systematic annual adjustments to the salaries of the Named Executive Officers. Instead, when indicated as a result of adding new senior management members to keep pace with our overall growth, necessary salary adjustments are made to maintain hierarchical relationships between senior management levels and the new senior management members. Since May 1999, Messrs. Armstrong and Pefanis have received one salary adjustment and Messrs. Coiner and Kramer have received two salary adjustments.
Cash Bonuses.
Annual Discretionary Bonuses. Annual discretionary bonuses are determined based on the Partnership’s performance relative to its annual plan forecast and public guidance, its distribution growth targets and other quantitative and qualitative goals established at the beginning of each year. Such annual objectives are discussed and reviewed with the board in conjunction with the review and authorization of the annual plan.
At the end of each year, our CEO performs a quantitative and qualitative assessment of the Partnership’s performance relative to its goals. Key quantitative measures include earnings before interest, taxes, depreciation and amortization, excluding items affecting comparability (“EBITDA”), relative to established guidance, as well as the growth in the annualized quarterly distribution level per limited partner unit relative to annual growth targets. Our primary performance metric is our ability to generate increasing and sustainable cash distributions to our equity owners. Accordingly, although net income and net income per unit are monitored to highlight inconsistencies with primary performance metrics, as is the Partnership’s market performance relative to our MLP peers and major indices, these metrics are considered secondary performance measures. Our CEO’s written analysis of our performance examines the Partnership’s accomplishments, shortfalls and overall performance against opportunity, taking into account controllable and non-controllable factors encountered during the year.
The resulting document and supporting detail is submitted to our board of directors for review and comment. Based on the conclusions set forth in the annual performance review, our CEO submits recommendations to the compensation committee for bonuses to Named Executive Officers, taking into account the relative contribution of the individual officer. Except as described below for Messrs. Coiner and vonBerg, there are no set formulas for determining the annual discretionary bonus for Named Executive Officers. Factors considered by our CEO in determining the level of bonus in general include (i) whether or not we achieved the goals established for the year and any notable shortfalls relative to expectations; (ii) the level of difficulty associated with achieving such objectives based on the opportunities and challenges encountered during the year; (iii) current year operating and financial performance relative to both public guidance and prior year’s performance; (iv) significant transactions or accomplishments for the period not included in the goals for the year; (v) our relative prospects at the end of the year with respect to future growth and performance; and (vi) our positioning at the end of the year with respect to our targeted credit profile. Our CEO takes these factors into consideration as well as the relative contributions of each of the Named Executive Officers to the year’s performance in developing his recommendations for bonus amounts.
These recommendations are discussed with the compensation committee, adjusted as appropriate, and submitted to the board for its review and approval. Similarly, the compensation committee assesses the CEO’s contribution toward meeting the Partnership’s goals, and recommends a bonus for the CEO it believes to be commensurate with such contribution. In several instances, the CEO has requested that the bonus amount
recommended by the compensation committee be reduced to maintain a closer relationship to bonuses awarded to the other Named Executive Officers.
Quarterly Bonus based on Adjusted EBITDA. Mr. Coiner, Mr. vonBerg and certain other members of our U.S. based senior management team are directly involved in activities that generate earnings for the Partnership. These individuals, along with approximately 80 other employees in our marketing and business development groups participate in a quarterly bonus pool based on adjusted EBITDA,1 which directly rewards for quarterly performance the commercial and asset-managing employees who participate. This quarterly incentive provides a direct incentive to optimize quarterly performance even when, on an annual basis, other factors might negatively affect bonus potential. Allocation of quarterly bonus amounts among all participants based on relative contribution is recommended by Mr. Coiner and reviewed, modified and approved by Mr. Pefanis, as appropriate. Mr. Pefanis does not participate in the quarterly bonus. The quarterly bonus amounts for Mr. Coiner and Mr. vonBerg are taken into consideration in determining the recommended annual discretionary bonus submitted by the CEO to the compensation committee.
Long-Term Incentive Awards. The Partnership does not make systematic annual phantom unit awards to the Named Executive Officers. Instead, our objective is to time the granting of awards such that as performance thresholds are met for existing awards, additional long-term incentives are created. Thus, performance is rewarded by relatively greater frequency of awards and lack of performance by relatively lesser frequency of awards. Generally, we believe that a three- to four-year grant cycle (and extended time-vesting requirements) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officer. Achievement of performance targets does not shorten the minimum service period requirement. If top performance targets on outstanding awards are achieved in the early part of this four-year cycle, new awards are granted with higher performance thresholds, and the minimum service periods of the new awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the Named Executive Officers. Accordingly, these new arrangements inherently take into account the value of awards where performance levels have been achieved but have not yet vested due to ongoing service period requirements, but do not take into consideration previous awards that have fully vested.
Application in 2006
At the beginning of 2006, the Partnership publicly established the following five goals for 2006:
1. Deliver operating and financial performance in line with guidance furnished at the beginning of 2006 on a Form 8-K dated February 23, 2006;
2. Maintain and improve our present credit rating and further expand our liquidity and financial flexibility to accommodate future growth;
3. Optimize our existing asset base and operations and expand our inventory of internal expansion projects;
4. Pursue our target of averaging $200 to $300 million of accretive and strategic acquisitions; and
5. Increase our distribution paid to unitholders by 10% over 2005 payments.
The Partnership met or substantially exceeded each of these goals in 2006. Excluding the impact of unforecasted acquisitions, our adjusted EBITDA exceeded the original guidance for 2006 by approximately 24%. Including the impact of unforecasted acquisitions, our adjusted EBITDA exceeded original guidance for 2006 by approximately 40%. We exceeded our acquisition target for 2006 by completing seven acquisitions aggregating approximately $3.0 billion. We also took several steps to optimize our asset base and expand our inventory of organic growth projects as we successfully implemented an expanded capital program totaling approximately $332 million, an increase of 44% as compared to the original capital program for 2006 of approximately
1 Adjusted EBITDA excludes the effect of certain non-cash items such as the effect of FAS 133 and accrual of LTIP expenses. Any bonus amounts that are deducted in calculating EBITDA are added back for purposes of calculating the bonus pool.
$230 million. Despite a year of significant acquisition and expansion activity, we maintained a strong capital structure and an investment grade credit rating and expanded the Partnership’s liquidity and financial flexibility. Finally, we exceeded our goal for unitholder distributions as total distributions paid in 2006 increased by approximately 11.5% over distributions paid in 2005. The total return to our limited partners (unit price appreciation plus distributions received) was approximately 38% in 2006 as compared to 25.8%, 15.8% and 19.0% for the MLP peer index, the S&P 500 and the Dow Jones Industrial Index, respectively.
For 2006, the elements of compensation were applied as follows:
Salary. No salary adjustments were recommended or made in 2006.
Cash Bonuses. Based on our CEO’s annual performance review and the individual performance of each of our Named Executive Officers, our compensation committee recommended to the board and the board approved the annual bonuses reflected in the “Summary Compensation Table” and notes thereto. The aggregate annual and, where applicable, quarterly bonus amounts reflected in the Summary Compensation Table are approximately 11% to 28% higher than amounts paid in 2005, which was considered a year of strong performance. Such amounts take into account the significant overperformance relative to each of the five goals established for 2006, the absence of any notable shortfalls relative to expectations; the level of difficulty associated with achieving such objectives; our relative positioning at the end of the year with respect to future growth and performance; the significant transactions or accomplishments for the period not included in the goals for the year; and our positioning at the end of the year with respect to our targeted credit profile. In the case of Mr. Coiner and Mr. vonBerg, the aggregate bonus amount represented 39.8% and 37.5% in annual bonus and 60.2% and 62.5% in quarterly bonus, respectively.
Long-Term Incentive Awards. No awards were made in 2006. Effective with the November 2006 distribution, however, we achieved the highest performance threshold ($3.00 per limited partner unit annualized) contained in substantially all pre-2006 phantom unit awards. Vesting of these pre-2006 awards remains subject to continued employment, and the service-period vesting requirements will be met in various increments over the next three to four years with the final vesting in May 2010. The compensation expense recognized in 2006 related to such awards is reflected on an individual basis in the Summary Compensation Table that follows. The vesting requirements are described in the footnotes to the Outstanding Equity Awards Table that follows.
Consistent with our policy of issuing new grants (with extended time-vesting periods) when the highest performance threshold of existing grants has been reached, in February of 2007 our board of directors granted awards with a top performance threshold of $4.00 per limited partner unit, representing a 33% increase over the November 2006 distribution level of $3.00 per unit. Such grants are intended to encourage continued growth and fundamental performance that will support future distribution growth. Specifically, the terms of the awards provide that, subject to meeting the service period requirement, the phantom unit grants will vest in one-third increments upon achieving annualized quarterly distribution levels of $3.50 per unit, $3.75 per unit and $4.00 per unit, respectively. Tandem DERs vest in 25% increments upon achieving annualized quarterly distribution levels of $3.40, $3.60, $3.80 and $4.00 per unit. Approximately two-thirds of the awards are eligible to vest in 2011 and one-third are eligible to vest in 2012. If any of the performance thresholds are not achieved prior to the May 2014 distribution date, such awards will expire. Upon vesting, the phantom units are payable on a one-for-one basis in common units of the partnership (or cash equivalent depending on the form of grant). The 2007 awards included grants to the Named Executive Officers as follows: Mr. Armstrong, 180,000; Mr. Pefanis, 120,000; Mr. Kramer, 60,000; Mr. Coiner, 90,000 and Mr. vonBerg, 54,000. The number of phantom units awarded to the Named Executive Officers represents approximately 60% of their outstanding pre-2006 awards.
Other Compensation Related Matters
Equity Ownership. As of December 31, 2006, each of the Named Executive Officers owned substantial equity in the partnership. Although the Partnership encourages its Named Executive Officers to retain ownership in the Partnership, it does not have a policy requiring maintenance of a specified equity ownership level. The Partnership’s policies prohibit the Named Executive Officers from using puts, calls or options to hedge the
economic risk of their ownership. In the aggregate, as of December 31, 2006, the Named Executive Officers beneficially owned an aggregate of approximately 556,475 limited partner units, excluding any unvested equity awards, as well as an aggregate 3% indirect ownership interest in the general partner. Based on the market price of the limited partner units at December 31, 2006 and an implied valuation for their collective general partner interest using similar valuation metrics, the value of the equity ownership of these individuals was approximately 45 times their aggregate 2006 salaries and approximately 3.9 times the combined aggregate salaries and bonuses for 2006.
Recovery of Prior Awards. Except as provided by applicable laws and regulations, the Partnership does not have a policy with respect to adjustment or recovery of awards or payments if relevant company performance measures upon which previous awards were based are restated or otherwise adjusted in a manner that would reduce the size of such award or payment.
Section 162(m). With respect to the deduction limitations under Section 162(m) of the Code, Plains is a limited partnership and does not meet the definition of a “corporation” under Section 162(m). Nonetheless, the salaries for each of the Named Executive Officers are substantially less than the Section 162(m) threshold of $1,000,000 and we believe the bonus compensation and long-term incentive compensation would qualify for performance-based compensation under Reg. 1.162-27(e) and therefore would not be additive to salaries for purposes of measuring the $1,000,000 tax limitation.
Change in Control Triggers. The employment agreements for Messrs. Armstrong and Pefanis and the long-term incentive plan grants to the Named Executive Officers include severance payment provisions or accelerated vesting triggered upon a change of control, as defined in the respective agreement. In the case of the long-term incentive plan grants, the provision becomes operative only if the change in control is accompanied by a change in status (such as the termination of employment by the general partner). We believe this “double trigger” arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. The provisions in the employment agreements for Messrs. Armstrong and Pefanis become operative only if the executive terminates employment within three months of the change in control. Messrs. Armstrong and Pefanis agreed to a conditional waiver of these provisions with respect to a transaction in 2005 that would have constituted a change in control. See ‘‘- Potential Payments upon Termination or Change-in-Control” and “- Employment Agreements.”
Summary Compensation Table
The following table sets forth certain compensation information for our Chief Executive Officer, Chief Financial Officer and the three other most highly compensated executive officers in 2006 (the “Named Executive Officers”). We reimburse our general partner and its affiliates for expenses incurred on our behalf, including the costs of officer compensation.
Summary Compensation Table
(1)
Dollar amounts represent the compensation expense recognized in 2006 with respect to outstanding phantom unit grants under our LTIP, whether or not granted during 2006. See Note 10 to our Consolidated Financial
Statements for a discussion of the assumptions made in determining these amounts. While substantially all of the performance thresholds for earning the phantom units represented by these amounts had been met as of December 29, 2006, none of the amounts included in this column were vested as of such date as they contain ongoing service requirements and, subject to meeting those requirements, will vest in various increments in 2007, 2008, 2009 and 2010.
(2)
Our general partner matches 100% of employees’ contributions to its 401(k) plan in cash, subject to certain limitations in the plan. All Other Compensation for Messrs. Armstrong, Pefanis, Kramer, Coiner and vonBerg includes $15,000 in such contributions. The remaining amount represents premium payments on behalf of the Named Executive Officer for group term life insurance.
(3)
Includes quarterly bonuses aggregating $2,040,100 and an annual bonus of $1,350,000. The annual bonus is payable 60% at the time of award and 20% in each of the two succeeding years.
(4)
Includes quarterly bonuses aggregating $1,834,700 and an annual bonus of $1,100,000. The annual bonus is payable 60% at the time of award and 20% in each of the two succeeding years.
Grants of Plan-Based Awards Table
This table has been omitted because no plan-based awards were made in 2006. See “- Compensation Discussion and Analysis.”
Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table
A discussion of 2006 salaries and bonuses is included in “- Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.
2006 Salary - As discussed in our CD&A, we do not make systematic annual adjustments to the salaries of the Named Executive Officers. Accordingly, no salary adjustments were made for any of our executive officers in 2006.
Employment Contracts
Mr. Armstrong is employed as Chairman and Chief Executive Officer. The initial three-year term of Mr. Armstrong’s employment agreement commenced on June 30, 2001, and is automatically extended for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Armstrong receives notice from the chairman of the compensation committee that the board of directors has elected not to extend the agreement. Mr. Armstrong has agreed, during the term of the agreement and for five years thereafter, not to disclose (subject to typical exceptions, including, but not limited to, requirement of law or prior disclosure by a third party) any confidential information obtained by him while employed under the agreement. The agreement provided for a base salary of $330,000 per year, subject to annual review. In 2005, Mr. Armstrong’s annual salary was increased to $375,000. See “- Compensation Discussion and Analysis” for a discussion of how salary and bonus are used to achieve compensation objectives. See “- Potential Payments Upon Termination or Change-In-Control” for a discussion of the provisions in Mr. Armstrong’s employment agreement related to termination, change of control and related payment obligations.
Mr. Pefanis is employed as President and Chief Operating Officer. The initial three-year term of Mr. Pefanis’ employment agreement commenced on June 30, 2001, and is automatically extended for one year on June 30 of each year (such that the term is reset to three years) unless Mr. Pefanis receives notice from the chairman of the board of directors that the board has elected not to extend the agreement. Mr. Pefanis has agreed, during the term of the agreement and for one year thereafter, not to disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement. The agreement provided for a base salary of $235,000 per year, subject to annual review. In 2005, Mr. Pefanis’ annual salary was increased to $300,000. See “- Compensation Discussion and Analysis” for a discussion of how salary and bonus are used to achieve compensation objectives. See “- Potential Payments Upon Termination or Change-In-Control” for a discussion of the provisions in Mr. Pefanis’ employment agreement related to termination, change of control and related payment obligations.
In connection with Mr. vonBerg’s employment in January 2002, our general partner and Mr. vonBerg entered into a letter agreement setting forth the terms of his employment. Such letter agreement provided for Mr. vonBerg’s position to be Director, Trading at a base salary of $200,000 per year and his participation in a quarterly bonus pool based on gross margin generated by the employee’s business unit, discretionary annual bonus pool and employee benefits provided to all employees generally. See “- Compensation Discussion and Analysis” for a discussion of how salary and bonus are used to achieve compensation objectives. The letter agreement expired in accordance with its terms in January 2007. Mr. vonBerg also entered into an ancillary agreement which provides that for a period of one year following his termination, he will not disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement and he will not, for one year after termination, engage in certain transactions with certain suppliers and customers.
Outstanding Equity Awards at Fiscal Year-End
The following table sets forth certain information with respect to outstanding equity awards at December 31, 2006 with respect to the Named Executive Officers:
Outstanding Equity Awards at Fiscal Year-End
(1)
Market value of stock reported in this column is calculated by multiplying the closing market price ($51.20) of the Partnership’s common units at December 29, 2006 (the last trading day of the fiscal year) by the number of units. Approximately one third of the value reflected in this column is also reflected in the Summary Compensation Table.
(2)
The units underlying the options were contributed to our general partner by its owners. We have no obligation to reimburse our general partners for the units upon exercise of the options. Mr. Armstrong vested in 18,750 options on April 22, 2002 and 18,750 options on July 21, 2004. Mr. Pefanis vested in 13,750 options on each of the same dates. Mr. Kramer vested in 11,250 options on each of the same dates. Mr. Coiner vested in 10,625 options on each of the same dates.
(3)
These phantom units will vest 30%, 30% and 40% solely upon achievement by the Partnership of annualized distributions of $2.60, $2.80 and $3.00 per unit and continued employment through May 2007, May 2009 and May 2010, respectively. Any phantom units that have not vested (and all associated DERs) as of the May 2012 distribution date will be forfeited. DERs associated with these phantom units become payable 30%, 15%, 15%,
20% and 20% upon the earlier to occur of annualized distributions of $2.60 or May 2007, $2.70 or May 2008, $2.80 or May 2009, $2.90 or May 2010, and $3.00 or May 2010, respectively.
(4)
These phantom units will vest 40%, 30% and 30% upon achievement by the Partnership of annualized distributions of $2.60, $2.80 and $3.00 per unit and continued employment through May 2007, May 2009 and May 2010, respectively. Any phantom units that have not previously vested will fully vest on the May 2011 distribution date, subject to continued employment through such date. DERs associated with these phantom units become payable 40%, 15%, 15%, 15% and 15% upon the earlier to occur of annualized distributions of $2.60 or May 2007, $2.70 or May 2008, $2.80 or May 2009, $2.90 or May 2010, and $3.00 or May 2010, respectively.
(5)
These phantom units will vest in equal one-third increments solely upon achievement by the Partnership of annualized distributions of $2.90, $3.00 and $3.10 per unit and continued employment through May 2008, May 2009 and May 2010, respectively. DERs associated with these phantom units vest and become payable in equal one-third increments solely upon the payment of annualized distributions of $2.90, $3.00, and $3.10, respectively. Any phantom units that have not vested (and all associated DERs) as of the May 2012 distribution date will be forfeited.
Option Exercises and Stock Vested Table
This table has been omitted because there were no exercises of options by or vestings of LTIPs for the Named Executive Officers in 2006.
Pension Benefits
The Partnership sponsors a 401(k) plan that is available to all U.S. employees, but does not maintain a pension or defined benefit program.
Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans
The Partnership does not have a nonqualified deferred compensation plan or program for its officers or employees.
Potential Payments upon Termination or Change-in-Control
The following table sets forth potential amounts payable to our current Named Executive Officers upon termination of employment under various circumstances, and as if terminated on December 29, 2006.
Potential Payments upon Termination or Change-in-Control
(1)
The employment agreements between our general partner and Messrs. Armstrong and Pefanis provide that if (i) their employment with our general partner is terminated as a result of their death, (ii) they terminate their employment with our general partner (a) because of a disability (as defined below) or (b) for good reason (as defined below), or (iii) our general partner terminates their employment without cause (as defined below), they are entitled to a lump-sum amount equal to the product of (1) the sum of their (a) highest annual base salary paid prior to their date of termination and (b) highest annual bonus paid or payable for any of the three years prior to the date of termination, and (2) the lesser of (i) two or (ii) the number of days remaining in the term of their employment agreement divided by 360. The amount provided in the table assumes for each executive a termination date of December 29, 2006, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,000,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $2,750,000 for Mr. Pefanis.
The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “disability” as the impairment of health to an extent that makes the continued performance of their duties hazardous to physical or mental health or life.
The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “cause” as (i) willfully engaging in gross misconduct, or (ii) conviction of a felony involving moral turpitude. Notwithstanding, no act, or failure to act, on their part is “willful” unless done, or omitted to be done, not in good faith and without reasonable belief that such act or omission was in the best interest of our general partner or otherwise likely to result in no material injury to our general partner. However, neither Mr. Armstrong or Mr. Pefanis will be deemed to have been terminated for cause unless and until there is delivered to them a copy of a resolution of the board of directors of our general partner at a meeting held for that purpose (after
reasonable notice and an opportunity to be heard), finding that Mr. Armstrong or Mr. Pefanis, as applicable, was guilty of the conduct described above, and specifying the basis for that finding.
The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “good reason” as the occurrence of any of the following circumstances: (i) removal by our general partner from, or failure to re-elect them to, the positions to which Messrs. Armstrong and Pefanis were appointed pursuant to their respective employment agreements, except in connection with their termination for cause (as defined above); (ii) (a) a reduction in their rate of base salary (other than in connection with across-the-board salary reductions for all executive officers of our general partner, unless such reduction reduces their base salary to less than 85% of their current base salary, (b) a material reduction in their fringe benefits, or (c) any other material failure by our general partner to comply with its obligations under their employment agreements to pay their annual salary and bonus, reimburse their business expenses, provide for their participation in certain employee benefit plans and arrangements, furnish them with suitable office space and support staff, or allow them no less than 15 business days of paid vacation annually; or (iii) the failure of our general partner to obtain the express assumption of the employment agreements by a successor entity (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of our general partner.
(2)
Pursuant to their employment agreements, if Messrs. Armstrong and Pefanis terminate their employment with our general partner within three (3) months of a change in control (as defined below), they are entitled to a lump-sum payment in an amount equal to the product of (i) three and (ii) the sum of (a) their highest annual base salary previously paid to them and (b) their highest annual bonus paid or payable for any of the three years prior to the date of such termination. The amount provided in the table assumes a change in control and termination date of December 29, 2006, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,000,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $2,750,000 for Mr. Pefanis.
For this purpose a “change in control” means (i) the acquisition by an entity or group (other than Plains Resources Inc. or a wholly owned subsidiary thereof) of 50% or more of the membership interest of our general partner or (ii) the existing owners of the membership interests of our general partner ceasing to own more than 50% of the membership interests of our general partner.
In August 2005, Vulcan Energy increased its interest in our general partner from approximately 44% to approximately 54%. The consummation of the transaction constituted a change of control under the employment agreements with Messrs. Armstrong and Pefanis. However, Messrs. Armstrong and Pefanis entered into agreements with our general partner waiving their rights to payments under their employment agreements in connection with the change of control, contingent on the execution and performance by Vulcan Energy of a voting agreement with GP LLC that restricts certain of Vulcan’s voting rights. Upon a breach, termination, or notice of termination of the voting agreement by Vulcan Energy these waivers will automatically terminate and the executive officer will be paid a lump sum as if he had terminated his employment for good reason. Upon any termination by the Company without cause or by the executive for good reason, such executive officer would also vest in all outstanding phantom units under our LTIPs.
(3)
The letters evidencing the 2005 phantom unit grants to the Named Executive Officers provide that in the event of their death or disability (as defined below), all of their then outstanding phantom units and associated DERs will be deemed 100% nonforfeitable, and such phantom units and associated DERs will vest (i.e., the phantom units will become payable in the form of one common unit and the associated DERs will become payable in a cash lump-sum payment) as provided in Footnote 3 to the “Outstanding Equity Awards at Fiscal Year-End” table. For this purpose “disability” means a physical or mental disability that impairs the ability to perform duties for a period of eighteen (18) months or that the general partner otherwise determines constitutes a disability.
The dollar value amount provided assumes the death or disability occurred on December 29, 2006. As a result, all phantom units and the associated DERs of the Named Executive Officers would have become nonforfeitable effective as of December 29, 2006, and vested at the time(s) described in Footnote 3 to the “Outstanding Equity Awards at Fiscal Year-End” table. The dollar value given is based on the market value on December 29, 2006 ($51.20 per unit) without discount for vesting period.
(4)
Pursuant to the 2005 phantom unit grants to the Named Executive Officers, in the event their employment is terminated other than in connection with a change in control (as defined in Footnote 5, below) or by reason of death or disability (as defined in Footnote 3, above), all of the DERs (regardless of vesting) and phantom units then outstanding under their respective 2005 phantom unit grants would automatically be forfeited as of the date of termination; provided, however, that if our general partner terminated their employment other than for cause (as defined below), any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would be deemed nonforfeitable and would vest on the next following distribution date. The dollar value amount provided assumes that the Named Executive Officers were terminated without cause on December 29, 2006. As a result, all of the outstanding phantom units held by Messrs. Armstrong, Pefanis and Kramer would be deemed nonforfeitable and would vest on the February 2007 distribution date. All outstanding phantom units, except for 23,334 and 13,334 held by Messrs. Coiner and vonBerg, respectively, would be deemed nonforfeitable and would vest on the February 2007 distribution date. The dollar value given is based on the market value on December 29, 2006 of $51.20 per unit, without discount for vesting period.
(5)
The 2005 phantom unit grants to the Named Executive Officers provide that in the event of a change of status (as defined below), all of the then outstanding phantom units and tandem DERs will be deemed 100% nonforfeitable, and such phantom units will vest in full (i.e., become payable in the form of one common unit of our general partner for each phantom unit) upon the next distribution date. Assuming the change in status occurred on December 29, 2006, all outstanding phantom units and the associated DERs would have become nonforfeitable as of December 29, 2006, and such phantom units and tandem DERs would vest (i.e., become payable) on the February 2007 distribution date.
The phrase “change in status” means, with respect to a Named Executive Officer, the occurrence, during the period beginning three months prior to and ending one year following a change of control (as defined below), of any of the following: (i) termination of employment by our general partner other than a termination for cause (as defined below); (ii) without consent, the removal from, or any failure to re-elect them to, the position(s) held by them (or substantially equivalent position(s)) immediately prior to the change in control; (iii) any reduction in their base salaries; or (iv) any material reduction in their fringe benefits.
The phrase “change of control” means, and is deemed to have occurred upon the occurrence of, one or more of the following events; (i) GP LLC ceasing to be the general partner of our general partner; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Partnership or GP LLC to any person and/or its affiliates, other than to the Partnership or GP LLC, including any employee benefit plan thereof; (iii) the consolidation, reorganization, merger, or any other similar transaction involving (A) a person other than the Partnership or GP LLC and (B) the Partnership, GP LLC or both; (iv) the persons who own membership interests in GP LLC ceasing to beneficially own, directly or indirectly, more than 50% of the membership interests of GP LLC; or (v) any person, including any partnership, limited partnership, syndicate or other group deemed a “person” for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended, becoming the beneficial owner, directly or indirectly, of more than 49.9% of the membership interest in GP LLC. With respect to the lattermost event, the grant letter makes an exception for any existing member of GP LLC if the member signs a voting agreement such as that executed by Vulcan in August 2005 (such exception not applying to the November 2005 grants to Messrs. Coiner and vonBerg).
The term “cause” means (i) the failure to perform a job function in accordance with standards described in writing, or (ii) the violation of our general partner’s Code of Business Conduct (unless waived in accordance with the terms thereof), in each case, with the specific failure or violation described in writing.
(6)
Pursuant to their employment agreements with our general partner, if Messrs. Armstrong or Pefanis are terminated other than (i) for cause (as defined in Footnote 1, above), (ii) by reason of death or (iii) by resignation (unless such resignation is due to a disability or for good reason (each as defined in Footnote 1, above)), then they are entitled to continue to participate, for a period which is the lesser of two years from the date of termination or the remaining term of the employment agreement, in such health and accident plans or arrangements as is made available by our general partner to its executive officers generally. The amounts provided in the table assume a termination date of December 29, 2006.
(7)
Pursuant to their employment agreements, Messrs. Armstrong and Pefanis will be reimbursed for any excise tax due under Section 4999 of the Code as a result of compensation (parachute) payments made under their respective employment agreements. The range of values of this benefit assumes that Messrs. Armstrong and Pefanis were terminated in connection with a change in control effective as of December 29, 2006.
Confidentiality, Non-compete and Non-solicitation Arrangements
Pursuant to his employment agreement, Mr. Armstrong has agreed to maintain the confidentiality of company information for a period of five years after the termination of his employment. Mr. Pefanis has agreed to a similar restriction for a period of one year following the termination of his employment. Mr. Coiner has agreed to maintain confidentiality and not to solicit customers or employees for a period of two years after the termination of his employment. Mr. vonBerg has agreed to maintain confidentiality and not to solicit customers for a period of one year following termination of his employment.
Compensation of Directors
The following table sets forth a summary of the compensation we paid to our non-employee directors in 2006:
Director Compensation
(1)
During the last fiscal year, Messrs. Goyanes, Smith and Symonds were granted 2,500 units and Mr. Sinnott was granted 1,250 units, by virtue of the automatic re-grant of LTIP awards vested during the fiscal year. In addition, each member of the audit committee was awarded 5,000 units, which vest annually in 25% increments; these units are also subject to an automatic re-grant of the amount vested such that in each future fiscal year 1,250 units will simultaneous vest and be re-granted. Upon any vesting (other than the incremental audit committee awards), a cash equivalent payment is made to Vulcan Capital and an affiliate of EnCap as directed by Mr. Capobianco and Mr. Petersen, respectively. Each audit committee member (currently Messrs. Goyanes, Smith and Symonds) has 10,000 units outstanding. Because these awards are subject to an automatic re-grant of units upon any vesting, each audit committee member will always have outstanding an award of 10,000 units. Mr. Sinnott has 5,000 units outstanding, and because this award is subject to an automatic re-grant of units upon any vesting, Mr. Sinnott will always have outstanding an award of 5,000 units. The dollar value of these awards and other awards granted in prior years is presented in the table reflecting the dollar amount of compensation expense recognized by us for 2006. See Note 10 to our Consolidated Financial Statements for a discussion of the assumptions made in determining these amounts.
(2)
Mr. Capobianco assigns to Vulcan Capital any compensation attributable to his service as director. Mr. Petersen assigns to EnCap Energy Capital Fund III, L.P. any compensation attributable to his service as director.
Each director of our general partner who is not an employee of our general partner is reimbursed for any travel, lodging and other out-of-pocket expenses related to meeting attendance or otherwise related to service on the board (including, without limitation, reimbursement for continuing education expenses). Each non-employee director is currently paid an annual retainer fee of $45,000. Mr. Armstrong is otherwise compensated for his services as an
employee and therefore receives no separate compensation for his services as a director. In addition to the annual retainer, each committee chairman (other than the chairman of the audit committee) receives $2,000 annually. The chairman of the audit committee receives $30,000 annually, and the other members of the audit committee receive $15,000 annually, in each case, in addition to the annual retainer.
Our non-employee directors receive LTIP awards or cash equivalent awards as part of their compensation. The LTIP awards vest annually in 25% increments over a four-year period and have an automatic re-grant feature such that as they vest, an equivalent amount is granted. The three non-employee directors who serve on our audit committee each received a grant of 10,000 units (vesting 2,500 units per year). Mr. Sinnott received a grant of 5,000 units (vesting 1,250 per year). Mr. Petersen and Mr. Capobianco each have assigned all director compensation to an affiliate of the GP LLC member that appointed him as a director. Such affiliates receive an annual cash payment equivalent in value to the annual vesting of Mr. Sinnott’s award.
All LTIP awards held by a director will vest in full upon the next vesting date after the death or disability (as determined in good faith by the board) of the director. For any “independent” directors (as defined in the GP LLC Agreement, and currently including Messrs. Goyanes, Smith and Symonds), the awards will also vest in full if such director (i) retires (no longer with full-time employment and no longer serving as an officer or director of any public company) or (ii) is removed from the Board or is not reelected to the Board, unless such removal or failure to reelect is for “good cause,” as defined in the letter granting the units.
Reimbursement of Expenses of Our General Partner and its Affiliates
We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. See Item 13. “Certain Relationships and Related Transactions, and Director Independence - Our General Partner.”
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Beneficial Ownership of Limited Partner Interest
Our common units outstanding represent 98% of our equity (limited partner interest). The 2% general partner interest is discussed separately below under “- Beneficial Ownership of General Partner Interest.” The following table sets forth the beneficial ownership of limited partner units held by beneficial owners of 5% or more of the units, directors, the Named Executive Officers, and all directors and executive officers as a group as of February 20, 2007.
(1)
Limited partner units constitute 98% of our equity, with the remaining 2% held by our general partner. The beneficial ownership of our general partner is set forth in the table below under “- Beneficial Ownership of General Partner Interest.” Giving effect to the indirect ownership by Vulcan Energy Corporation of a portion of our general partner, Mr. Allen may be deemed to beneficially own approximately 14% of our total equity. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.
(2)
Mr. Allen owns approximately 80.1% of the outstanding shares of common stock of Vulcan Energy Corporation. Mr. Allen also controls Vulcan Capital Private Equity I LLC (“Vulcan LLC”), which is the record holder of 1,995,954 common units. The address for Mr. Allen and Vulcan LLC is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.
(3)
The address for Vulcan Energy Corporation is c/o Plains All American GP LLC, 333 Clay Street, Suite 1600, Houston, Texas 77002.
(4)
Richard A. Kayne is Chief Executive Officer and Director of Kayne Anderson Investment Management, Inc., which is the general partner of Kayne Anderson Capital Advisors, L.P. (“KACALP”). Various accounts (including KAFU Holdings, L.P., which owns a portion of our general partner) under the management or control of KACALP own 9,238,534 common units. Mr. Kayne may be deemed to beneficially own such units. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 270,365 common units. Mr. Kayne disclaims beneficial ownership of any of our partner interests other than units held by him or interests attributable to him by virtue of his interests in the accounts that own our partner interests. The address
for Mr. Kayne and Kayne Anderson Investment Management, Inc. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.
(5)
Does not include approximately 173,444 common units owned by our general partner in connection with its Performance Option Plan. Mr. Armstrong disclaims any beneficial ownership of such units beyond his rights as a grantee under the plan. See Item 13.
Item 13. “Certain Relationships and Related Transactions, and Director Independence - General Partner’s Performance Option Plan.”
(6)
Does not include unvested phantom units granted under the 2005 LTIP, none of which will vest within 60 days of the date hereof. See “- Outstanding Equity Awards at Fiscal Year-End.”
(7)
Includes the following vested, unexercised options to purchase common units under the general partner’s Performance Option Plan. Mr. Armstrong: 37,500; Mr. Pefanis: 27,500; Mr. Kramer: 22,500; Mr. Coiner: 21,250; and all directors and executive officers as a group: 126,250.
(8)
Less than one percent.
(9)
The GP LLC Agreement specifies that certain of the owners of our general partner have the right to designate a member of our board of directors. Mr. Capobianco has been designated as one of our directors by Vulcan Energy Corporation, of which he is Chairman of the Board. Mr. Capobianco owns an equity interest in Vulcan LLC and has the right to receive a performance-based fee based on the performance of the holdings of Vulcan LLC and Vulcan Energy Corporation. Mr. Capobianco disclaims any deemed beneficial ownership of our common units held by Vulcan Energy Corporation and Vulcan LLC or any of their affiliates beyond his pecuniary interest therein, if any. By virtue of its 54% ownership in the general partner, Vulcan Energy Corporation has the right at any time to cause the election of an additional director to the Board.
(10)
Pursuant to the GP LLC Agreement, Mr. Petersen has been designated one of our directors by E-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is Senior Managing Director. Mr. Petersen disclaims any deemed beneficial ownership of the 618,896 common units held by E-Holdings III, L.P. and E-Holdings V, L.P. or other affiliates of EnCap Investments L.P. beyond his pecuniary interest. The address for E-Holdings III, L.P. and E-Holdings V, L.P. is 1100 Louisiana, Suite 3150, Houston, Texas 77002.
(11)
Pursuant to the GP LLC Agreement, Mr. Sinnott has been designated one of our directors by KAFU Holdings, L.P., which is controlled by Kayne Anderson Investment Management, Inc., of which he is President. Mr. Sinnott disclaims any deemed beneficial ownership of any common units held by KAFU Holdings, L.P. or its affiliates, other than through his 4.5% limited partner interest in KAFU Holdings, L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.
(12)
As of February 23, 2007, no units were pledged by directors or Named Executive Officers. Certain of the directors and Named Executive Officers hold units in a marginable broker’s account, but none of the units were margined as of February 23, 2007.
Beneficial Ownership of General Partner Interest
Plains AAP, L.P. owns all of our 2% general partner interest and all of our incentive distribution rights. The following table sets forth the effective ownership of Plains AAP, L.P. (after giving effect to proportionate ownership of Plains All American GP LLC, its 1% general partner).
(1)
Mr. Allen owns approximately 80.1% of the outstanding shares of common stock of Vulcan Energy Corporation. Vulcan Energy GP Holdings Inc., a subsidiary of Vulcan Energy Corporation, owns 54.3% of the equity of our general partner. Vulcan Energy Corporation has pledged all of its equity interest in Vulcan Energy GP Holdings Inc. as security for its obligations under the Second Amended and Restated Credit Agreement dated as of August 12, 2005 among Vulcan Energy Corporation, Bank of America, N.A. and the lenders party thereto (the “VEC Credit Agreement”). A default by Vulcan Energy Corporation under the VEC Credit Agreement could result in an indirect change in control of our general partner. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.
(2)
Mr. Capobianco disclaims any deemed beneficial ownership of the interests held by Vulcan Energy Corporation and its affiliates beyond his pecuniary interest therein, if any.
(3)
Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU Holdings, L.P. other than through his 4.5% limited partner interest in KAFU Holdings, L.P.
(4)
Mr. Petersen disclaims any deemed beneficial ownership of the interests owned by E-Holdings III, L.P. and E-Holdings V, L.P. beyond his pecuniary interest.
(5)
PAA Management, L.P. is owned entirely by certain members of senior management, including Messrs. Armstrong (approximately 25%), Pefanis (approximately 14%), Kramer (approximately 9%), Coiner (approximately 9%) and vonBerg (approximately 4%). Other than Mr. Armstrong, no directors own any interest in PAA Management, L.P. Directors and executive officers as a group own approximately 76% of PAA Management, L.P. Mr. Armstrong disclaims any beneficial ownership of the general partner interest owned by Plains AAP, L.P., other than through his ownership interest in PAA Management, L.P.
Equity Compensation Plan Information
The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2006. For a description of these plans, see Item 13. “Certain Relationships and Related Transactions, and Director Independence - Equity-Based Long-Term Incentive Plans.”
(1)
As originally instituted by our former general partner prior to our initial public offering, the 1998 LTIP contemplated the issuance of up to 975,000 common units to satisfy awards of phantom units. Upon vesting, these awards could be satisfied either by (i) primary issuance of units by us or (ii) cash settlement or purchase of units by our general partner with the cost reimbursed by us. In 2000, the 1998 LTIP was amended, as provided in the plan, without unitholder approval to increase the maximum awards to 1,425,000 phantom units; however, we can issue no more than 975,000 new units to satisfy the awards. Any additional units must be purchased by our general partner in the open market or in private transactions and be reimbursed by us. As of December 31, 2006, we have issued approximately 427,742 common units in satisfaction of vesting under the 1998 LTIP. The number of units presented in column (a) assumes that all remaining grants will be satisfied by the issuance of new units upon vesting. In fact, a substantial number of phantom units that have vested were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).
(2)
Phantom unit awards under the 1998 LTIP and 2005 LTIP vest without payment by recipients.
(3)
In accordance with Item 201(d) of Regulation S-K, column (c) excludes the securities disclosed in column (a). However, as discussed in footnotes (1) and (4), any phantom units represented in column (a) that are not satisfied by the issuance of units become “available for future issuance.”
(4)
The 2005 Long Term Incentive Plan was approved by our unitholders in January 2005. The 2005 LTIP contemplates the issuance or delivery of up to 3,000,000 units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units upon vesting. In fact, some portion of the phantom units may be settled in cash and some portion will be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).
(5)
Although awards for units may from time to time be outstanding under the portion of the 1998 LTIP not approved by unitholders, all of these awards must be satisfied in cash or out of units purchased by our general partner and reimbursed by us. None will be satisfied by “units issued upon exercise/vesting.”
(6)
Awards for up to 387,032 phantom units may be granted under the portion of the 1998 LTIP not approved by unitholders; however, no common units are “available for future issuance” under the plan, because all such awards must be satisfied with cash or out of units purchased by our general partner and reimbursed by us.
(7)
Our general partner has adopted a Performance Option Plan for officers and key employees pursuant to which optionees have the right to purchase units from the general partner. The 450,000 units that were originally authorized to be sold under the plan were contributed to the general partner by certain of its owners in connection with the transfer of a majority of our general partner interest in 2001 without economic cost to the Partnership. Thus, there will be no units “issued upon exercise/vesting of outstanding options.” Options for approximately 161,500 units are currently outstanding. All are vested, and no units remain available for future grant. See Item 13. “Certain Relationships and Related Transactions, and Director Independence - General Partner’s Performance Option Plan.”
(8)
As of December 31, 2006, the strike price for all outstanding options under the general partner’s Performance Option Plan was approximately $11.55 per unit. The strike price decreases as distributions are paid. See Item 13. “Certain Relationships and Related Transactions, and Director Independence - General Partner’s Performance Option Plan.”
(9)
In connection with the Pacific merger, under applicable stock exchange rules, we carried over the available units under the Pacific LTIP (applying the conversion ratio of 0.77 PAA units for each Pacific unit). In that regard, we have adopted the Plains All American PPX Successor Long-Term Incentive Plan (the “PPX Successor LTIP”). Potential awards under such plan include options and phantom units (with or without tandem DERs). The provisions of such plan are substantially the same as the 2005 LTIP, except that awards under the PPX Successor LTIP may only be made to employees who were working for Pacific at the time of the merger or to employees hired after the date of the Pacific acquisition.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
For a discussion of director independence, see Item 10 “Directors and Executive Officers of Our General Partner and Corporate Governance.”
Our General Partner
Our operations and activities are managed, and our officers and personnel are employed, by our general partner (or, in the case of our Canadian operations, PMC (Nova Scotia) Company). We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf. Total costs reimbursed by us to our general partner for the year ended December 31, 2006 were approximately $204.6 million.
Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 ($1.80 annualized) per unit, 25% of the amounts we distribute in excess of $0.495 ($1.98 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit. In connection with the Pacific merger, our general partner agreed to a temporary reduction in the amount of incentive distribution right otherwise payable to it. The aggregate reduction will be $65 million over a five-year period, with a reduction of $20 million, $15 million, $15 million, $10 million and $5 million in years one through five, respectively. The first reduction was made in connection with the distribution paid on February 14, 2007.
The following table illustrates the allocation of aggregate distributions at different per-unit levels, excluding the effect of the incentive distribution reductions:
(1)
In thousands.
(2)
Assumes 110,000,000 units outstanding. Actual number of units outstanding as of December 31, 2006 was 109,405,178. An increase in the number of units outstanding would increase both the distribution to unitholders and the distribution to the general partner of any given level of distribution per unit.
(3)
Includes distributions attributable to the 2% general partner interest and the incentive distribution rights.
Equity-Based Long-Term Incentive Plans
Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 LTIP”) and the Plains All American GP LLC 2005 Long-Term Incentive Plan (the “2005 LTIP” and, together with the 1998 LTIP, the “Plans”) for employees and directors of our general partner and its affiliates who perform services for us. Awards contemplated by the Plans include phantom units (referred to as restricted units in the 1998 LTIP), distribution equivalent rights (DERs) and unit options. As amended, the 1998 LTIP authorizes the grant of awards covering an aggregate of 1,425,000 common units deliverable upon vesting or exercise (as applicable) of such awards. The 2005 LTIP authorizes the grant of awards covering an aggregate of 3,000,000 common units deliverable upon vesting or exercise (as applicable) of such awards. Our general partner’s board of directors has the right to alter or amend the Plans from time to time, including, subject to any applicable NYSE listing requirements, increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.
Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market or in private transactions, common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. In addition, over the term of the plan we may issue new common units to satisfy delivery obligations under the grants. When we issue new common units upon vesting of grants, the total number of common units outstanding increases.
Phantom Units. A phantom unit entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on the terms of the grant).
As of December 31, 2006, giving effect to vested grants, grants of approximately 40,550 and 2,195,700 unvested phantom units remain outstanding under the 1998 LTIP and 2005 LTIP, respectively, and approximately 893,740 and 804,300 remain available for future grant, respectively. In addition, the PPX Successor LTIP has available 999,809 units that were adopted from the Pacific LTIP. These units can be used only in awards to former Pacific employees or employees hired after the date of the Pacific acquisition. The compensation committee or board of directors may, in the future, make additional grants under the Plans to employees and directors containing such terms as the compensation committee or board of directors shall determine, including DERs with respect to phantom units. DERs entitle the grantee to a cash payment, either while the award is outstanding or upon vesting, equal to any cash distributions paid on a unit while the award is outstanding.
The issuance of the common units upon vesting of phantom units is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration is paid to us by the plan participants upon receipt of the common units.
Unit Options. Although the Plans currently permit the grant of options covering common units, no options have been granted under the Plans to date. However, the compensation committee or board of directors may, in the future, make grants under the plan to employees and directors containing such terms as the compensation committee or board of directors shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.
General Partner’s Performance Option Plan
In 2001, certain owners of the general partner contributed an aggregate of 450,000 subordinated units (now converted into common units) to the general partner to provide a pool of units available for the grant of options to management and key employees. In that regard, the general partner adopted the Plains All American 2001 Performance Option Plan. As of December 31, 2006, 171,000 options remain outstanding under the plan, all of which are fully vested. No units remain available for future grant. The original exercise price of the options was $22 per unit, declining over time by an amount equal to 80% of each quarterly distribution per unit. As of December 31, 2006, the exercise price was approximately $11.55 per unit. Because the units underlying the plan were contributed to the general partner, we have no obligation to reimburse the general partner for the cost of the units upon exercise of the options.
Transactions with Related Persons
Vulcan Energy
As of December 31, 2006, Vulcan Energy and its affiliates owned approximately 54% of our general partner interest, as well as approximately 11.3% of our outstanding limited partner units.
Voting Agreement
In August 2005, one of the owners of our general partner notified the remaining owners of its intent to sell its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was purchased pro rata by all remaining owners. As a result of the transaction, the interest of Vulcan Energy increased from 44% to approximately 54%. At the closing of the transaction, Vulcan Energy entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed, subject to certain ongoing conditions, to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest. These ownership changes to our general partner had no material impact on us.
Administrative Services Agreement
On October 14, 2005, GP LLC and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for consideration of an annual fee, plus certain expenses. Effective October 1, 2006, the annual fee for providing these services was increased to $1.0 million. The Services Agreement extends through October 2008, at which time it will automatically renew for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, Vulcan Energy has appointed certain employees of GP LLC as officers of Vulcan Energy for administrative efficiency. Under the Services Agreement, Vulcan Energy acknowledges that conflicts may arise between itself and GP LLC. If GP LLC believes that a specific service is in conflict with the best interest of GP LLC or its affiliates then GP LLC is entitled to suspend the provision of that service and such a suspension will not constitute a breach of the Services Agreement. Vulcan Gas Storage LLC (discussed below) operates separately from Vulcan Energy, and services we provide to Vulcan Gas Storage LLC are not covered under the Services Agreement.
Predecessor Agreements
In 2001, Plains Resources, Inc. transferred a portion of its indirect interest in our general partner to certain of the current owners. As successor in interest to Plains Resources, Vulcan Energy is party to certain agreements related to such transfer, including the following:
•
a separation agreement entered into in 2001 in connection with the transfer of interests in our general partner pursuant to which (i) Vulcan indemnifies us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001, or (b) claims related to the upstream business, whenever arising, and (ii) we indemnify Vulcan for claims related to the midstream business, whenever arising. Vulcan also indemnifies, and maintains liability insurance (through June 8, 2007) for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.
•
a Pension and Employee Benefits Assumption and Transition Services Agreement that provided for the transfer to our general partner of the employees of our former general partner and certain headquarters employees of Plains Resources.
•
an Omnibus Agreement that provides for the resolution of certain conflicts of interest, including certain non-compete obligations.
Crude Oil Purchases
Until August 12, 2005, Vulcan Energy owned 100% of Calumet Florida L.L.C. Calumet is now owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. We purchase crude oil from Calumet. We paid approximately $45.1 million to Calumet in 2006. Calumet may request from time to time that we provide fixed pricing or a range of pricing for a portion of its production. When we offer such an arrangement, we protect our position by placing hedges on equivalent amounts, and charge Calumet a fee of $0.20 per barrel. No such arrangements were in place during 2006.
Other
In addition to those relationships described above, we have engaged in other transactions with affiliates of Vulcan Energy. See “- Equity Offerings” and “- Investment in Natural Gas Storage Joint Venture.”
Equity Offerings
In December 2006, we sold 6,163,960 common units, approximately 10% and 10% of which were sold to investment funds affiliated with KACALP and Encap Investments, L.P., respectively. In July and August 2006, we sold a total of 3,720,930 common units, approximately 12.5% and 18.7% of which were sold to investment funds affiliated with KACALP and Vulcan Capital, respectively. In addition, in March and April 2006, we sold 3,504,672 common units, approximately 20% of which were sold to investment funds affiliated with KACALP. KAFU Holdings, L.P., which owns 20.3% of our general partner and has a representative on our board of directors, is managed by KACALP. Vulcan Capital, the investment arm of Paul G. Allen, and its subsidiaries own approximately 54% of our general partner interest and has a representative on our board of directors. Affiliates of EnCap own approximately 11.1% of our general partner and have a representative on our board of directors.
In September 2005, we sold 4,500,000 units in a public offering at a unit price to the public of $42.20. We received net proceeds of approximately $182.3 million, or $40.512 per unit after underwriters’ discounts and commissions. Concurrently with the public offering, we sold 679,000 common units pursuant to our existing shelf registration statement to investment funds affiliated with KACALP in a privately negotiated transaction for a purchase price of $40.512 per unit (equivalent to the public offering price less underwriting discounts and commissions). On February 25, 2005, we issued 575,000 common units in a private placement to a subsidiary of Vulcan Capital. The sale price was $38.13 per unit, which represented a 2.8% discount to the closing price of the units on February 24, 2005.
Tank Car Lease and CANPET
In July 2001, we acquired the assets of CANPET Energy Group Inc., a Calgary-based Canadian crude oil and LPG marketing company (the “CANPET acquisition”), for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. Mr. W. David Duckett, the President of PMC (Nova Scotia) Company, the general partner of Plains Marketing Canada, L.P., owns approximately 37.8% of CANPET. In connection with the CANPET acquisition, Plains Marketing Canada, L.P. assumed CANPET’s rights and obligations under a Master Railcar Leasing Agreement between CANPET and Pivotal Enterprises Corporation (“Pivotal”). The agreement provides for Plains Marketing Canada, L.P. to lease approximately 57 railcars from Pivotal at a lease price of $1,000 (Canadian) per month, per car. The lease extends until June of 2008, with an option for Pivotal to extend the term of the lease for an additional five years. Pivotal is substantially owned by former employees of CANPET, including Mr. Duckett. Mr. Duckett owns a 23.4% interest in Pivotal.
Class C Common Units
In April 2004, we sold 3,245,700 unregistered Class C common units (the “Class C common units”) to a group of investors consisting of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital pursuant to Rule 4(2) under the Securities Act. For more detailed information with respect to our relationship with Kayne Anderson Capital Advisors and Vulcan Capital, see Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.” We received $30.81 per Class C common unit, an amount which represented 94% of the average closing price of our common units for the twenty trading days immediately ending on and including March 26, 2004. Net proceeds from the private placement, including the general partner’s proportionate capital contribution and expenses associated with the sale, were approximately $101 million. We used the net proceeds from the offering to repay indebtedness under our revolving credit facility incurred in connection with the Link acquisition. In January 2005, our common unitholders approved a change in the terms of the Class C common units such that they were immediately convertible into an equal number of common units at the option of the holders, and in February 2005, all of the Class C common units converted.
Investment in Natural Gas Storage Joint Venture
PAA/Vulcan, a limited liability company, was formed in the third quarter of 2005. We own 50% of PAA/Vulcan and the remaining 50% is owned by Vulcan Gas Storage LLC, a subsidiary of Vulcan Capital, the investment arm of Paul G. Allen. The Board of Directors of PAA/Vulcan consists of an equal number of our representatives and representatives of Vulcan Gas Storage, and is responsible for providing strategic direction and policy-making. We, as the managing member, are responsible for the day-to-day operations.
In September 2005, PAA/Vulcan acquired ECI, an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We and Vulcan Gas Storage LLC each made an initial cash investment of approximately $112.5 million, and Bluewater Natural Gas Holdings, LLC a subsidiary of PAA/Vulcan (“Bluewater”) entered into a $90 million credit facility contemporaneously with closing. Approximately $25.4 million was outstanding under this credit facility as of February 20, 2007. We currently have no direct or contingent obligations under the Bluewater credit facility.
PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “base gas”). During the first quarter of 2006, we arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We received a fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.
We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to
which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time.
In conjunction with formation of PAA/Vulcan and the acquisition of ECI, PAA and Paul G. Allen provided performance and financial guarantees to the seller with respect to PAA/Vulcan’s performance under the purchase agreement, as well as in support of continuing guarantees of the seller with respect to ECI’s obligations under certain gas storage and other contracts. PAA and Paul G. Allen would be required to perform under these guarantees only if ECI was unable to perform. In addition, we provided a guarantee under one contract with an indefinite life for which neither Vulcan Capital nor Paul G. Allen provided a guarantee. In exchange for the disproportionate guarantee, PAA will receive preference distributions totaling $1.0 million over ten years from PAA/Vulcan (distributions that would otherwise have been paid to Vulcan Gas Storage LLC). We believe that the fair value of the obligation to stand ready to perform is minimal. In addition, we believe the probability that we would be required to perform under the guaranty is extremely remote; however, there is no dollar limitation on potential future payments that fall under this obligation.
PAA/Vulcan will reimburse us for the allocated costs of PAA’s non-officer staff associated with the management and day-to-day operations of PAA/Vulcan and all out-of-pocket costs. In addition, in the first fiscal year that EBITDA (as defined in the PAA/Vulcan LLC agreement) of PAA/Vulcan exceeds $75.0 million, we will receive a distribution from PAA/Vulcan equal to $6.0 million per year for each year since formation of the joint venture, subject to a maximum of 5 years or $30 million. Thereafter, we will receive annually a distribution equal to the greater of $2 million per year or two percent of the EBITDA of PAA/Vulcan.
Other
Thomas Coiner, an employee in our marketing department, is the son of George R. Coiner, Senior Group Vice President. In 2006, Thomas Coiner received compensation in excess of $120,000.
Review, Approval or Ratification of Transactions with Related Persons
Pursuant to our Governance Guidelines, a director is expected to bring to the attention of the CEO or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and the Partnership or GP LLC on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
If a conflict or potential conflict of interest arises between the Partnership and GP LLC, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of the Partnership Agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement. Such resolution may include resolution of any derivative conflicts created by an executive officer’s ownership of interests in GP LLC or a director’s appointment by an owner of GP LLC.
Pursuant to our Code of Business Conduct, any Executive Officer must avoid conflicts of interest unless approved by the board of directors.
In the case of any sale of equity in which an owner or affiliate of an owner of our general partner participates, our practice is to obtain general approval of the full board for the transaction. The board typically delegates authority to set the specific terms to a pricing committee, consisting of the CEO and one independent director. Actions by the pricing committee require unanimous approval.
Item 14.
Item 14.
Principal Accountant Fees and Services
All services provided by our independent auditor are subject to pre-approval by our audit committee. The audit committee has instituted a policy that describes certain pre-approved non-audit services. We believe that the
description of services is designed to be sufficiently detailed as to particular services provided, such that (i) management is not required to exercise judgment as to whether a proposed service fits within the description and (ii) the audit committee knows what services it is being asked to pre-approve. The audit committee is informed of each engagement of the independent auditor to provide services under the policy.
The following table details the aggregate fees billed for professional services rendered by our independent auditor: (in millions)
(1)
Audit fees include those related to our annual audit (including internal control evaluation and reporting), audits of our general partner and certain joint ventures of which we are the operator, and work performed on our registration of publicly-held debt and equity.
(2)
Audit-related fees primarily relate to audits of our benefit plans and carve-out audits of acquired companies.
(3)
Tax fees are related to tax processing as well as the preparation of Forms K-1 for our unitholders and includes incremental activity assumed with the issuance of Forms K-1 for former Pacific unitholders.
(4)
All other fees primarily consist of those associated with due diligence performed on our behalf and evaluating potential acquisitions.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)
(1) Financial Statements
See “Index to the Consolidated Financial Statements” set forth on Page.
(2) Financial Statement Schedules
All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
(3) Exhibits
.19
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Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report on Form 8-K filed September 28, 2005).
.20
-
First Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 23, 2005, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed November 21, 2006).
.21
-
Registration Rights Agreement dated as of July 26, 2006 among Plains All American Pipeline, L.P., Vulcan Capital Private Equity I LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.13 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
.22
-
Registration Rights Agreement dated as of December 19, 2006 among Plains All American Pipeline, L.P., E-Holdings III, L.P., E-Holdings V, L.P., Kayne Anderson MLP Investment Company and Kayne Anderson Energy Development Company (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-3/A, File No, 333-138888).
.23
-
Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities, LLC, Wedbush Morgan Securities Inc. and Wells Fargo Securities, LLC relating to the 2017 Notes (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed October 30, 2006).
.24
-
Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities Inc. and Wells Fargo Securities, LLC relating to the 2037 Notes (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K filed October 30, 2006).

Filed herewith
**
Management compensatory plan or arrangement
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Plains All American Pipeline, L.P.
By:
Plains AAP, L.P.,
its general partner
By:
Plains All American GP LLC,
its general partner
By:
/s/ Greg L. Armstrong
Greg L. Armstrong,
Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)
March 1, 2007
By:
/s/ Phillip D. Kramer
Phillip D. Kramer,
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
(Principal Financial Officer)
March 1, 2007
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Plains All American Pipeline, L.P.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
Management has used the framework set forth in the report entitled “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2006. This evaluation did not include the internal control over financial reporting related to the purchase business combination of the operations acquired in conjunction with the Pacific merger on November 15, 2006 (the “Pacific Acquisition”). The revenues for the year ended December 31, 2006 and the total assets as of December 31, 2006 recorded for the Pacific Acquisition operations as a percentage of the Partnership’s revenues and total assets represent approximately 1% and 29%, respectively. Management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
/s/ Greg L. Armstrong
Greg L. Armstrong
Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC
(Principal Executive Officer)
/s/ Phillip D. Kramer
Phillip D. Kramer
Executive Vice President and Chief Financial Officer of Plains All American GP LLC
(Principal Financial Officer)
March 1, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors of the General Partner and Unitholders of
Plains All American Pipeline, L.P.:
We have completed integrated audits of Plains All American Pipeline, L.P.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows, of changes in partners’ capital, of comprehensive income and of changes in accumulated other comprehensive income present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 2 to the consolidated financial statements, the Partnership changed the manner in which it accounts for pipeline linefill in 2004 and the manner in which it accounts for equity-based compensation and purchases and sales with the same counterparty in 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Partnership maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Partnership’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. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the businesses acquired in the acquisition of Pacific Energy Partners, L.P. (the “Pacific Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2006 because these businesses were acquired by the Partnership in a purchase business combination during 2006. We have also excluded the Pacific Acquisition from our audit of internal control over financial reporting. Pacific Acquisition are wholly-owned businesses whose total assets and total revenues represent 29% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2006.
PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2007
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED
OTHER COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization and Basis of Presentation
Organization
Plains All American Pipeline, L.P. is a Delaware limited partnership formed in September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in this Form 10-K, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise.
We are engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas-related petroleum products. We refer to liquefied petroleum gas and other natural gas related petroleum products collectively as “LPG.” Through our 50% equity ownership in PAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we develop and operate natural gas storage facilities. Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing.
Our 2% general partner interest is held by Plains AAP, L.P., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.’s general partner. Plains All American GP LLC manages our operations and activities and employs our domestic officers and personnel. Our Canadian officers and employees are employed by our subsidiary PMC (Nova Scotia) Company, the general partner of Plains Marketing Canada, L.P. Unless the context otherwise requires, we use the term “general partner” to refer to both Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by seven owners with interests ranging from 54.3% to 1.2%.
Basis of Consolidation and Presentation
The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2006 and 2005, and the consolidated results of our operations, cash flows, changes in partners’ capital, comprehensive income and changes in accumulated other comprehensive income for the years ended December 31, 2006, 2005 and 2004. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the previous years to conform to the 2006 presentation of the financial statements. These reclassifications do not affect net income. The accompanying consolidated financial statements of PAA include PAA and all of its wholly owned subsidiaries. Investments in 50% or less owned entities over which we have significant influence but not control are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with APB 18: The Equity Method of Accounting for Investments in Common Stock. An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.
Changes in Accounting Principle
Stock-Based Compensation
In December 2004, SFAS 123(R) was issued, which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from such share-based payment transactions be recognized in the financial statements at fair value. Following our general partner’s adoption of Emerging Issues Task Force Issue No. 04-05, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we are now part of the same consolidated group and thus SFAS 123(R) is applicable to our general partner’s long-term incentive plan. We adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our LTIP life-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Our LTIPs are administered by our general partner. We are required to reimburse all costs incurred by our general partner related to LTIP settlements. Our LTIP awards are classified as liabilities under SFAS 123(R) as the awards are primarily paid in cash. Under the modified prospective transition method, we are not required to adjust our prior period financial statements for this change in accounting principle.
Linefill
During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third-party assets. Historically, we viewed pipeline linefill, whether in our assets or third-party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we did not include linefill barrels in the same average costing calculation as our operating inventory, but instead carried linefill at historical cost. Following this change in accounting principle, the linefill in third-party assets that we historically classified as a portion of Pipeline Linefill on the face of the balance sheet (a long-term asset) and carried at historical cost, is included in Inventory (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the linefill in third-party assets not expected to be liquidated within the succeeding twelve months out of Inventory (a current asset), at average cost, and into Inventory in Third-Party Assets (a long-term asset), which is now reflected as a separate line item on the consolidated balance sheet.
This change in accounting principle was effective January 1, 2004 and is reflected as a cumulative change in our consolidated statement of operations for the year ended December 31, 2004. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory in Third-Party Assets of $28.9 million.
Note 2 - Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates we make include: (i) accruals related to purchases and sales, (ii) mark-to-market estimates pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting For Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), (iii) contingent liability accruals, (iv) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (v) accruals related to our Long-Term Incentive Plans, (vi) property, plant, and equipment and depreciation expense, and (vii) accruals related to deferred tax assets, valuation allowances and tax liabilities. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition
Transportation Segment Revenues. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff as well as revenues associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line-lease fees are recognized in the month to which the lease applies, whether or not the space is actually utilized. All pipeline tariff and fee revenues are based on actual volumes and rates. Pipeline margin
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
activities primarily consist of the purchase and sale of crude oil shipped on our San Joaquin Valley system using barrel exchanges and buy/sell arrangements. Revenues associated with these activities are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. All of our pipeline margin activities revenues are based on actual volumes and prices.
Facilities Segment Revenues. Storage and terminalling revenues (which are included within Other Revenues on our Consolidated Statements of Operations) consist of (i) storage fees from actual storage used on a month-to-month basis; (ii) storage fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput charges to pump to connecting carriers. Revenues on storage are recognized ratably over the term of the contract. Terminal throughput charges are recognized as the crude oil, LPG or refined product exits the terminal and is delivered to the connecting carrier or third-party terminal. Any throughput volumes in transit at the end of a given month are treated as third party inventory and do not incur storage fees. All terminalling and storage revenues are based on actual volumes and rates.
Marketing Segment Revenues. Revenues from sales of crude oil, LPG and other products are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and LPG consist of outright sales contracts and buy/sell arrangements as well as barrel exchanges. In September 2005, the Emerging Issues Task Force (“EITF”) issued Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that inventory purchases and sales transactions with the same counterparty should be combined for accounting purposes if they were entered into in contemplation of each other. The EITF provided indicators to be considered for purposes of determining whether such transactions are entered into in contemplation of each other. Guidance was also provided on the circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF 04-13 became effective in reporting periods beginning after March 15, 2006.
We adopted EITF 04-13 on April 1, 2006. The adoption of EITF 04-13 resulted in inventory purchases and sales under buy/sell transactions, which historically would have been recorded gross as purchases and sales, to be treated as inventory exchanges in our consolidated statement of operations. In conformity with EITF 04-13, prior periods are not affected, although we have parenthetically disclosed prior period buy/sell transactions in our consolidated statements of operations. The treatment of buy/sell transactions under EITF 04-13 reduces both revenues and purchases on our income statement but does not impact our financial position, net income, or liquidity.
Purchases and Related Costs
Purchases and related costs include: (i) the cost of crude oil and LPG purchased in outright purchases as well as buy/sell arrangements prior to the adoption of EITF 04-13; (ii) third-party transportation and storage, whether by pipeline, truck or barge; (iii) interest cost attributable to borrowings for inventory stored in a contango market; (iv) performance related bonus accruals; and (v) expenses of issuing letters of credit to support these purchases. These purchases are accrued at the time title transfers to us.
Operating Expenses and General and Administrative Expenses
Operating expenses consist of various field and pipeline operating expenses including fuel and power costs, telecommunications, payroll and benefit costs for truck drivers and pipeline field personnel, maintenance costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs, certain information system and legal costs, office rent, contract and consultant costs, and audit and tax fees.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Foreign Currency Transactions
Assets and liabilities of subsidiaries with a functional currency other than the U.S. Dollar are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income in partners’ capital. Gains and losses from foreign currency transactions (transactions denominated in a currency other than the entity’s functional currency) are included in the consolidated statement of operations. The foreign currency transactions resulted in a loss of approximately $4.1 million, a loss of approximately $2.1 million, and a gain of approximately $5.0 million for the years ended December 31, 2006, 2005, and 2004, respectively.
Cash and Cash Equivalents
Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that the credit risk is minimal.
Accounts Receivable
Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG. The majority of our accounts receivable relate to our marketing activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or “parental” guarantees. At December 31, 2006 and 2005, we had received approximately $28.3 million and $52.5 million, respectively, of advance cash payments and prepayments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.
We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2006 and 2005, substantially all of our net accounts receivable classified as current were less than 60 days past their scheduled invoice date, and our allowance for doubtful accounts receivable (the entire balance of which is classified as current) totaled $0.7 million and $0.8 million, respectively. Although we consider our allowance for doubtful trade accounts receivable to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts. Following is a reconciliation of the changes in our allowance for doubtful accounts balances (in millions):
Inventory and Pipeline Linefill
Inventory primarily consists of crude oil, refined products and LPG in pipelines, storage tanks and rail cars that is valued at the lower of cost or market, with cost determined using an average cost method. During 2006, we recorded a $5.9 million noncash charge related to the writedown of our crude oil and LPG inventory due to declines in oil prices during the third and fourth quarters of 2006. During the fourth quarter of 2004, we recorded a
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
$2.0 million noncash charge related to the writedown of our LPG inventory. There was no such charge in 2005. Linefill and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil and LPG used to pack the pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location, as well as the minimum amount of crude oil necessary to operate our storage and terminalling facilities.
Minimum working inventory requirements in third-party assets are included in Inventory (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the inventory in third party assets not expected to be liquidated within the succeeding twelve months out of Inventory, at average cost, and into Inventory in Third-Party Assets (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.
At December 31, 2006 and 2005, inventory and linefill consisted of:
(1)
Includes the impact of inventory hedges on a portion of our volumes.
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Property and equipment
Property and equipment, net is stated at cost and consisted of the following:
Depreciation expense for each of the three years in the period ended December 31, 2006 was $91.3 million, $79.2 million and $64.8 million, respectively.
We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year. Also, gains/losses on sales of assets and asset impairments are included as a component of depreciation and amortization in the consolidated statements of operations.
In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. For the years ended December 31, 2006, 2005 and 2004, capitalized interest was $6.0 million, $1.8 million and $0.5 million, respectively. In addition, costs required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives are capitalized and classified as maintenance capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.
Equity Method of Accounting
Our investments in PAA/Vulcan, Frontier Pipeline Company (“Frontier”), Settoon Towing, LLC (“Settoon Towing”) and Butte Pipe Line Company (“Butte”) are accounted for under the equity method of accounting. Our ownership interests in PAA/Vulcan, Frontier, Settoon Towing and Butte are 50%, 22%, 50% and 22%, respectively. We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on the income statement and will increase or decrease, as applicable, the carrying value of our investments on the balance sheet. Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flow statement.
Asset Retirement Obligation
We account for asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.
Some of our assets, primarily related to our transportation segment, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. The timing of the obligations is determined relative to the date on which the asset is abandoned. Many of our pipelines are trunk and interstate systems that transport crude oil. The pipelines with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for this transportation will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations are related to assets that are inactive or that we plan to take out of service and although the ultimate timing and costs to settle these obligations are not known with certainty, we can reasonably estimate the obligation. We have estimated that the fair value of these obligations is approximately $4.7 million and $4.6 million at December 31, 2006 and 2005, respectively.
Impairment of Long-Lived Assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. Impairments were not material in 2006 and 2005. In 2004, we recognized a charge of approximately $2.0 million associated with taking our pipeline in the Illinois Basin out of service. The impairments, which were predominantly related to assets that will be taken out of service, are included as a component of depreciation and amortization in the consolidated statements of operations. These assets did not support spending the capital necessary to continue service and we utilized other assets to handle these activities.
We periodically evaluate property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:
•
whether there is an indication of impairment;
•
the grouping of assets;
•
the intention of “holding” versus “selling” an asset;
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
•
the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
•
if an impairment exists, the fair value of the asset or asset group.
Goodwill and Other Intangible Assets
In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” we test goodwill at least annually (on June 30) to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. Pursuant to SFAS 142, a reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are one level below our operating segments. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. Fair value is assessed based on multiples of earnings or revenue. An impairment loss is recognized if the carrying amount is not recoverable and its carrying amount exceeds its fair value. Since adoption of SFAS 142, we have not recognized any impairment of goodwill.
The table below reflects our changes in goodwill:
(1)
The purchase price allocation related to the Pacific acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.
Intangible assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets consist of the following:
Our amortization expense for finite-lived intangible assets for the years ended December 31, 2006, 2005 and 2004 was $4.8 million, $0.3 million and $0.3, respectively.
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We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):
Other assets, net
Other assets, net of accumulated amortization consist of the following:
(1)
The majority of the increase in 2006 relates to acquisitions. See the table above and Note 3.
Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $13.2 million, $3.3 million and $5.9 million in 2006, 2005 and 2004, respectively. In addition, during 2006 we wrote off approximately $1.4 million of fully amortized costs and the related accumulated amortization. During 2006, 2005 and 2004, we wrote off unamortized costs totaling $0, $1.4 million and $0.7 million, respectively.
Amortization expense related to other assets (including finite-lived intangible assets) for each of the three years in the period ended December 31, 2006, was $9.1 million, $4.3 million and $3.9 million, respectively.
Environmental Matters
We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.
We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. See Note 13.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income and Other Taxes
No provision for U.S. federal income taxes related to our operations is included in the accompanying consolidated financial statements. As a partnership we are not subject to federal or state income tax and the tax effect of our activities accrues to the unitholders. Except for the Canadian operations acquired in the Pacific acquisition, the Partnership’s Canadian operations are conducted through an operating limited partnership, of which our wholly owned subsidiary PMC (Nova Scotia) Company is the general partner. For Canadian tax purposes, the general partner is taxed as a corporation, subject to income taxes and a capital-based tax at federal and provincial levels. For the years presented, these amounts were immaterial. The Canadian entities acquired in the Pacific acquisition are corporations for Canadian tax purposes, thus their operations are subject to income taxes in Canada. For 2006, the income tax provision associated with these operations was not material.
We estimate (a) income taxes in the jurisdictions in which we operate, (b) net deferred tax assets and liabilities based on expected future taxes in the jurisdictions in which we operate, (c) valuation allowances for deferred tax assets and (d) contingent tax liabilities for estimated exposures related to our current tax positions. These estimates are considered a critical accounting estimate because they require projecting future operating results (which is inherently imprecise). Also, these estimates depend on assumptions regarding our ability to generate future taxable income during the periods in which temporary differences are deductible. See Note 7.
As of December 31, 2006, we have not recorded a valuation allowance against our deferred tax assets for federal net operating loss carryforwards. Management believes that it is more likely than not that we will realize the deferred tax assets associated with the federal net operating loss. Key factors in this assessment include an evaluation of our recent history of taxable earnings and losses (as adjusted), future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies.
Recent Accounting Pronouncements
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FAS 115” (“SFAS 159”). SFAS 159 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS 159 will be effective for fiscal years beginning after November 15, 2007. We are evaluating the impact of adoption of SFAS 159 but do not currently expect the adoption to have a material impact on our financial position, results of operations or cash flows.
In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. SAB 108 requires registrants to quantify misstatements using both the balance sheet and income statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. The provisions of SAB 108 are effective for the fiscal years ending after November 15, 2006. The adoption of SAB 108 did not have a material impact on our consolidated financial position, results of operations or cash flows.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. SFAS 157 does not add any new fair value measurements, but it does change current practice and is intended to increase consistency and comparability in such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The impact, if any, to the company from the adoption of FAS 157 in 2008 will depend on the company’s assets and liabilities that are required to be measured at fair value at that time.
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In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized as an adjustment to the opening balance of retained earnings (or other appropriate components of equity) for that fiscal year. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are evaluating the impact of the adoption of FIN 48 but do not currently expect the adoption of this new standard to have a material impact on our financial position, results of operations or cash flows.
Derivative Instruments and Hedging Activities
We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled commodity trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. We record all derivative instruments on the balance sheet as either assets or liabilities measured at their fair value under the provisions of SFAS 133. SFAS 133 requires that changes in derivative instruments fair value be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, changes in fair value are deferred to Accumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying transaction affects earnings. Accordingly, changes in fair value are included in the current period for (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that are not highly effective in offsetting changes in cash flows of hedged items. See Note 6 for further discussion.
Net Income Per Unit
Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest) by the weighted average number of outstanding limited partner units during the period. Subject to applicability of Emerging Issues Task Force Issue No. 03-06 (“EITF 03-06”), “Participating Securities and the Two-Class Method under FASB Statement No. 128,” as discussed below, Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership.
EITF 03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF 03-06 provides that in any accounting period where our aggregate net income exceeds our aggregate distribution for such period, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF 03-06 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings is allocated (as if distributed) to our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF 03-06 does not have any impact on our earnings per unit calculation.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following sets forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average limited partner units outstanding have been adjusted for instruments considered common unit equivalents at 2006, 2005 and 2004.
(1)
Our LTIP awards described in Note 10 that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. The dilutive securities are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in SFAS 128, “Earnings per Share.”
Note 3 -
Acquisitions and Dispositions
The following acquisitions were accounted for using the purchase method of accounting and the purchase price was allocated in accordance with such method.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Significant Acquisitions
Pacific Energy Partners, L.P.
On November 15, 2006 we completed our acquisition of Pacific Energy Partners, L.P. (“Pacific”) pursuant to an Agreement and Plan of Merger dated June 11, 2006. The merger-related transactions included: (i) the acquisition from LB Pacific, LP and its affiliates (“LB Pacific”) of the general partner interest and incentive distribution rights of Pacific as well as approximately 5.2 million Pacific common units and approximately 5.2 million Pacific subordinated units for a total of $700 million and (ii) the acquisition of the balance of Pacific’s equity through a unit-for-unit exchange in which each Pacific unitholder (other than LB Pacific) received 0.77 newly issued common units of the Partnership for each Pacific common unit. The total value of the transaction was approximately $2.5 billion, including the assumption of debt and estimated transaction costs. Upon completion of the merger-related transactions, the general partner and limited partner ownership interests in Pacific were extinguished and Pacific was merged with and into the Partnership. The assets acquired in the Pacific acquisition included approximately 4,500 miles of active crude oil pipeline and gathering systems and 550 miles of refined products pipelines, over 13 million barrels of active crude oil and 9 million barrels of refined products storage capacity, a fleet of approximately 75 owned or leased trucks and approximately 1.9 million barrels of crude oil and refined products linefill and working inventory. The Pacific assets complement our existing asset base in California, the Rocky Mountains and Canada, with minimal asset overlap but attractive potential vertical integration opportunities. The results of operations and assets and liabilities from this acquisition (the “Pacific acquisition”) have been included in our consolidated financial statements and all three of our segments since November 15, 2006. The purchase price allocation related to the Pacific acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.
The purchase price was calculated as follows (in millions):
(1)
Valued at $45.02, which represents the average closing price of Plains common units two days immediately prior and two days immediately after the merger was announced on June 12, 2006.
(2)
Includes investment banking fees, costs associated with a severance plan in conjunction with the acquisition and various other direct acquisition costs.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Consists of customer relationships, emissions credits and environmental permits.
(2)
Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy. See Note 2.
The majority of the acquisition costs associated with the Pacific acquisition was incurred as of December 31, 2006, resulting in total cash paid during 2006 of approximately $723 million.
The following table shows our calculation of the sources of funding for the acquisition (in millions):
(1)
The assumption of Pacific’s debt and credit facility at fair value was $433.1 million and $290.7 million, respectively. We paid off the credit facility in connection with closing of the transaction.
Link Energy LLC
On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC (“Link”) for approximately $332.3 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $64 million of net liabilities assumed and acquisition-related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of active crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets and liabilities from this acquisition have been included in our consolidated financial statements and in all three of our segments since April 1, 2004.
The purchase price was allocated as follows and includes goodwill primarily attributed to Link’s gathering and marketing operations (in millions):
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Cash paid does not include the subsequent payment of various transaction and other acquisition related costs.
(2)
Accounts receivable and accounts payable are gross and do not reflect the adjustment of approximately $250 million to net settle, based on contractual agreements with our counterparties.
The total purchase price included (i) approximately $9.4 million in transaction costs, (ii) approximately $7.4 million related to a plan to terminate and relocate employees in conjunction with the acquisition, and (iii) approximately $11.0 million related to costs to terminate a contract assumed in the acquisition. These activities were substantially complete and the majority of the related costs were incurred as of December 31, 2004, resulting in total cash paid during 2004 of approximately $294 million.
The acquisition was initially funded with cash on hand, borrowings under our then existing revolving credit facilities and under a new $200 million, 364-day credit facility. In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors. During the third quarter of 2004, we completed a public offering of common units and the sale of an aggregate of $350 million of senior notes. A portion of the proceeds from these transactions was used to retire the $200 million, 364-day credit facility.
Capline and Capwood Pipeline Systems
In March 2004, we completed the acquisition of all of Shell Pipeline Company LP’s interests in two entities for approximately $158.5 million in cash (including a deposit of approximately $16 million paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.
The principal assets of these entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 58-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets and liabilities from this acquisition have been included in our consolidated financial statements and in our transportation segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S., and delivered to several refineries and other pipelines.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The purchase price was allocated as follows (in millions):
Other Acquisitions
Acquisitions
During 2006, in addition to the Pacific acquisition, we completed six additional acquisitions for aggregate consideration of approximately $565 million. These acquisitions included (i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana (“SemCrude”), (iii) interests in various crude oil pipeline systems in Canada and the U.S. including a 100% interest in the Bay Marchand-to-Ostrica-to-Alliance (“BOA”) Pipeline, 64.35% interest in the Clovelly-to-Meraux (“CAM”) Pipeline system and various interests in the High Island Pipeline System (“HIPS”), and (iv) three refined products pipeline systems from Chevron Pipe Line Company.
The purchase prices of these acquisitions, in aggregate were allocated as follows (in millions):
(1)
Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy. See Note 2.
(2)
Consists of customer relationships.
In addition, in November 2006, we acquired a 50% interest in Settoon Towing for approximately $33 million.
Pro Forma Data
The following table presents selected unaudited pro forma financial information incorporating the historical (pre-merger) results of Pacific and our other 2006 business combination transactions. The following pro forma information has been prepared as if the Pacific Merger and our other business combination transactions in 2006 had been completed on January 1, 2005 as opposed to the actual dates that these acquisitions occurred. The pro forma information is based upon available data and includes certain estimates and assumptions made by management. As a result, this pro forma information is not necessarily indicative of our financial results had the transactions actually
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
occurred on this date. Likewise, the following unaudited pro forma financial information is not necessarily indicative of our future financial results.
Acquisitions
During 2005, we completed six small transactions for aggregate consideration of approximately $40.3 million. The transactions included crude oil trucking operations and several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. In addition, in September 2005, PAA/Vulcan acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250 million. We own 50% of PAA/Vulcan and a subsidiary of Vulcan Capital owns the other 50%. See Note 9 “Related Party Transactions.”
Acquisitions
During 2004, in addition to the Link and Capline acquisitions, we completed several other acquisitions for aggregate consideration totaling $73.1 million including transaction costs and approximately $14.4 million of LPG operating inventory acquired. These acquisitions include crude oil mainline and gathering pipelines and propane storage facilities. The aggregate purchase price was allocated to property and equipment.
Dispositions
During 2006, 2005 and 2004, we sold various property and equipment for proceeds totaling approximately $4.4 million, $9.4 million and $3.0 million, respectively. A gain of approximately $2.1 million, a loss of $3.2 million, and a gain of $0.6 million were recognized in 2006, 2005, and 2004, respectively. These gains and losses are included as a component of depreciation and amortization in the consolidated statements of operations.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4 - Debt
Debt consists of the following:
(1)
At December 31, 2006 and 2005, we have classified $158.2 million and $155.4 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and IntercontinentalExchange (“ICE”) margin deposits.
(2)
At December 31, 2006, the aggregate fair value of our fixed-rate senior notes is estimated to be approximately $2,671.6 million. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates, and the credit spread on outstanding borrowings reflect market.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Credit Facilities
In July 2006, we amended our senior unsecured revolving credit facility to increase the aggregate capacity from $1.0 billion to $1.6 billion and the sub-facility for Canadian borrowings from $400 million to $600 million. The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and has a final maturity of July 2011. At December 31, 2006, 2005 and 2004, borrowings of approximately $158.2 million, $155.4 million and $231.8 million, respectively, were outstanding under this facility.
In November 2006, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $800 million to $1.0 billion. We also extended the maturity of the senior secured hedged inventory facility to November 2007. This facility is an uncommitted working capital facility, which is used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility are collateralized by the inventory purchased under the facility and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory.
Senior Notes
In November 2006, in conjunction with the Pacific merger, we assumed two issues of Senior Notes with an aggregate principal balance of $425 million. The $175 million of 6.25% Senior Notes are due September 15, 2015 and the $250 million of 7.125% Senior Notes are due June 15, 2014. Interest payments on the 6.25% Senior Notes are due on March 15 and September 15 of each year, and interest payments on the 7.125% Senior Notes are due on June 15 and December 15 of each year. These notes were recorded at fair value for an aggregate amount of $433 million.
In October 2006, we issued $400 million of 6.125% Senior Notes due 2017 and $600 million of 6.65% Senior Notes due 2037. The notes were sold at 99.56% and 99.17% of face value, respectively. Interest payments are due on January 15 and July 15 of each year. We used the proceeds to fund the cash portion of the merger with Pacific including repayment of amounts outstanding under Pacific’s credit facility. Net proceeds in excess of the cash portion of the merger consideration were used to repay amounts outstanding under our credit facilities and for general partnership purposes. In anticipation of the issuance of these notes, we had entered into $200 million notional principal amount of U.S. treasury locks to hedge the treasury rate portion of the interest rate on a portion of the notes. The treasury locks were entered into at an interest rate of 4.97%. See Note 6.
During May 2006, we completed the sale of $250 million aggregate principal amount of 6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
During May 2005, we completed the issuance of $150 million of 5.25% senior notes due 2015. The notes were issued at 99.5% of face value. Interest payments are due on June 15 and December 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
In each instance, the notes were co-issued by Plains All American Pipeline, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) and are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for two subsidiaries with assets regulated by the California Public Utility Commission, and certain other minor subsidiaries. See Note 12.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Covenants and Compliance
Our credit agreements and the indentures governing the senior notes contain cross default provisions. Our credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:
•
incur indebtedness if certain financial ratios are not maintained;
•
grant liens;
•
engage in transactions with affiliates;
•
enter into sale-leaseback transactions; and
•
sell substantially all of our assets or enter into a merger or consolidation.
Our credit facility treats a change of control as an event of default and also requires us to maintain a debt-to-EBITDA coverage ratio which will not be greater than 4.75 to 1.0 on outstanding debt, and 5.25 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).
For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.
A default under our credit facility would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, our ability to make distributions of available cash is not restricted. We are currently in compliance with the covenants contained in our credit agreements and indentures.
Letters of Credit
As is customary in our industry, and in connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. These letters of credit are issued under our credit facility, and our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for periods of up to seventy days and are terminated upon completion of each transaction. At December 31, 2006 and 2005, we had outstanding letters of credit of approximately $185.8 million and $55.5 million, respectively.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Maturities
The weighted average life of our long-term debt outstanding at December 31, 2006 was approximately 14.8 years and the aggregate maturities for the next five years are as follows (in millions):
(1)
Excludes aggregate unamortized discount of $1.8 million on our various senior notes.
Note 5 -
Partners’ Capital and Distributions
Units Outstanding
Partners’ capital at December 31, 2006 consists of 109,405,178 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.
Conversion of Class B and Class C Common Units
In accordance with a common unitholder vote at a special meeting on January 20, 2005, each Class B common unit and Class C common unit became convertible into one common unit upon request of the holder. In February 2005, all of the Class B and Class C common units converted into common units. The Class B common units and Class C common units were pari passu with common units with respect to quarterly distributions.
Conversion of Subordinated Units
Pursuant to the terms of our Partnership Agreement and having satisfied the financial tests contained therein, in November 2003, 25% of the subordinated units converted to common units on a one-for-one basis. In February 2004, all of the remaining subordinated units converted to common units on a one-for-one basis.
The subordinated units had a debit balance in Partners’ capital of approximately $39.9 million at December 31, 2003. The debit balance was the result of several different factors including: (i) a low initial capital balance in connection with the formation of the Partnership as a result of a low carry-over book basis in the assets contributed to the Partnership at the date of formation, (ii) a significant net loss in 1999 and (iii) distributions to unitholders that exceeded net income allocated to unitholders.
Distributions
We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter, less reserves established by our general partner for future requirements.
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General Partner Incentive Distributions
Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally the general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit, referred to as our minimum quarterly distributions (“MQD”), 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as “incentive distributions”).
Upon closing of the Pacific acquisition, our general partner agreed to reduce the amount of its incentive distributions as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. Pursuant to this agreement, the first reduction was with respect to the incentive distribution paid to the general partner on February 14, 2007, which was reduced by $5 million. The total reduction in incentive distributions will be $65 million.
Per unit cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:
(1)
Distributions represent those declared and paid in the applicable period.
Total cash distributions made were as follows (in millions, except per unit amounts):
(1)
The subordinated units converted to common units in 2004.
On January 16, 2007, we declared a cash distribution of $0.8000 per unit on our outstanding common units. The distribution was paid on February 14, 2007 to unitholders of record on February 2, 2007, for the period October 1, 2006 through December 31, 2006. The total distribution paid was approximately $104.6 million, with approximately $87.5 million paid to our common unitholders and $1.8 million and $15.3 million paid to our general partner for its general partner and incentive distribution interests, respectively.
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Equity Offerings
During the three years ended December 31, 2006, we completed the following equity offerings of our common units.
(1)
These offerings involved related parties. See Note 9 “Related Party Transactions.”
Payment of Deferred Acquisition Price
In connection with the CANPET acquisition in July 2001, $26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and an increase to goodwill for this liability was recorded as of that date. The liability was satisfied on April 30, 2004 with the issuance of approximately 385,000 common units and the payment of $6.5 million in cash. The number of common units issued in satisfaction of the deferred payment was based upon $34.02 per unit, the average trading price of our common units for the ten-day trading period prior to the payment date, and a Canadian dollar to U.S. dollar exchange rate of 1.35 to 1, the average noon-day exchange rate for the ten-day trading period prior to the payment date. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition.
Note 6 -
Derivatives and Financial Instruments
We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled commodity trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, ICE and over-the-counter positions, as well as physical volumes, grades, locations and delivery schedules to help ensure that our hedging activities address our market risks. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows or the fair value of hedged items.
Summary of Financial Impact
The majority of our derivative activity is related to our commodity price-risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG and natural gas as well as with respect to expected purchases, sales and transportation of these commodities. The majority of the instruments that
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qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is not highly effective, as defined in SFAS 133, in offsetting changes in cash flows of the hedged items, are marked-to-market in revenues each period.
A summary of the earnings impact of all derivative activities, including the change in fair value of open derivatives and settled derivatives taken to earnings during 2006 and 2005, is as follows (in millions, losses designated in brackets):
The breakdown of the net mark-to-market impact to earnings between derivatives that do not qualify for hedge accounting and the ineffective portion of cash flow hedges is as follows (in millions, losses designated in brackets):
The majority of the derivatives that do not qualify for hedge accounting treatment are related to activities associated with our storage assets as these contracts will not necessarily result in physical delivery.
The following table summarizes the net assets and liabilities on our consolidated balance sheet that are related to the fair value of our open derivative positions (in millions):
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The net liability related to the fair value of our open derivative positions consists of unrealized gains/losses recognized in earnings and unrealized gains/losses deferred to AOCI as follows, by category (in millions, losses designated in brackets):
In addition to the $13.6 million of unrealized losses deferred to AOCI for open derivative positions, AOCI also includes a deferred loss of approximately $6.2 million that relates to terminated interest rate swaps that were cash settled in connection with the refinancing of debt agreements over the past four years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the terminated instruments.
The total amount of deferred net losses recorded in AOCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. Of the total net loss deferred in AOCI at December 31, 2006, a net loss of $14.3 million will be reclassified into earnings in the next twelve months; the remaining net loss will be reclassified at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and 2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts is based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. During the year ended December 31, 2006 and 2005, no amounts were reclassified to earnings from AOCI in connection with forecasted transactions that were no longer considered probable of occurring.
The following sections discuss our risk management activities in the indicated categories.
Commodity Price-Risk Hedging
We hedge our exposure to price fluctuations with respect to crude oil, LPG, refined products, and natural gas, and expected purchases, sales and transportation of these commodities. The derivative instruments we use consist primarily of futures and option contracts traded on the NYMEX, ICE and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS 133, these derivative instruments are recognized on the balance sheet at fair value. The majority of the instruments that qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into AOCI and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.
The majority of the unrealized losses that have been recognized in earnings relate to activities associated with our storage assets. In general, revenue from storing crude oil is reduced in a backwardated market (when oil prices for future deliveries are lower than for current deliveries), as there is less incentive to store crude oil from month-to-month. We enter into derivative contracts that will offset the reduction in revenue by generating offsetting gains in a backwardated market structure. These derivatives do not qualify for hedge accounting because the
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contracts will not necessarily result in physical delivery. A portion of the net liability as of December 31, 2006 was caused by a reduction in backwardation (a decrease in the amount that the price of future deliveries are lower than current deliveries) from the time that we entered into the derivative contracts to the end of the year. The net gain or loss related to these instruments will offset storage revenue in the period that the derivative instruments are hedging.
The unrealized losses deferred in AOCI are related to inventory hedges which are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from AOCI in the same period that the underlying physical inventory is sold.
Controlled Trading Program
Although we seek to maintain a position that is substantially balanced within our crude oil lease purchase activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.
Interest Rate Risk Hedging
In November 2006, in conjunction with the Pacific merger, we assumed interest rate swap agreements with an aggregate notional principal amount of $80.0 million to receive interest at a fixed rate of 7.125% and to pay interest at an average variable rate of six month LIBOR plus 1.67% (set in advance or in arrears depending on the swap transaction). The interest rate swaps mature June 15, 2014 and are callable at the same dates and terms as the 7.125% senior notes. We designated these swaps as a hedge against changes in the fair value of the 7.125% Senior Notes resulting from market fluctuations to LIBOR. The changes in fair values of the interest rate swaps are recorded in earnings each period. Similarly, the change in fair value of the underlying $80.0 million of senior notes, which are expected to be offsetting to changes in the fair value of the interest swaps, are recorded into earnings each period. For the year ended December 31, 2006 we had an immaterial amount of ineffectiveness relating to these interest rate swaps.
During August 2006, we entered into two treasury locks with large creditworthy financial institutions in anticipation of a debt issuance in conjunction with our acquisition of Pacific. A treasury lock is a financial derivative instrument that enables a company to lock in the U.S. Treasury Note rate. The U.S. Treasury Note rate was the benchmark interest rate for our anticipated debt issuance. The two treasury locks had a combined notional principal amount of $200 million and an effective interest rate of 4.97%. The treasury locks were designated as cash flow hedges and the changes in fair value of the treasury locks were therefore deferred in AOCI. In October 2006, both treasury locks were terminated prior to maturity in connection with the debt issuance in October 2006 for an aggregate cash payment of $2.4 million.
AOCI includes a deferred loss of approximately $6.2 million that relates to terminated interest rate swaps that were cash settled in connection with the refinancing of debt agreements over the past four years. The deferred loss related to these instruments is being amortized to interest expense over the original terms of the terminated instruments.
Currency Exchange Rate Risk Hedging
Because a significant portion of our Canadian business is conducted in Canadian dollars and, at times, a portion of our debt is denominated in Canadian dollars, we use certain financial instruments to minimize the risks of
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unfavorable changes in exchange rates. These instruments include forward exchange contracts and cross currency swaps. The open foreign currency derivatives that were assumed in the Pacific merger do not qualify for hedge accounting in accordance with SFAS 133. At December 31, 2006, our open foreign exchange derivatives consisted of forward exchange contracts that exchange Canadian dollars (“Cdn”) and US dollars on a net basis as follows (in millions):
(1)
Of these amounts, Cdn $108.3 was exchanged for US $93.0 on a net basis on January 2, 2007 at an average exchange rate of Cdn $1.16 to US $1.00.
These financial instruments are placed with large, creditworthy financial institutions.
Fair Value of Financial Instruments
The carrying amount of our derivative financial instruments approximate fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. Our derivative financial instruments currently include: (i) forward exchange contracts for which fair values are based on current liquidation values; (ii) over-the-counter option and swap contracts for which fair values are estimated based on various sources such as independent reporting services, industry publications and brokers; and (iii) NYMEX futures and options for which the fair values are based on quoted market prices. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used.
Note 7 -
Income Taxes
Our U.S. and Canadian subsidiaries are not taxable entities in the U.S. and are not subject to U.S. federal or state income taxes as the tax effect of operations is passed through to our unitholders. However, certain of our Canadian subsidiaries (acquired through the Pacific acquisition in 2006) are taxable entities in Canada and are subject to Canadian federal and provincial income taxes.
Components of the income tax expense for the year are as follows (in millions):
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The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions):
Deferred tax assets and liabilities, which are included within other long-term liabilities and deferred credits in our consolidated balance sheet, result from the following (in millions):
Note 8 -
Major Customers and Concentration of Credit Risk
Marathon Petroleum Company, LLC (“Marathon”) accounted for 14%, 11% and 10% of our revenues for each of the three years in the period ended December 31, 2006. Valero Marketing & Supply Company (“Valero”) accounted for 10% of our revenues for the year ended December 31, 2006. BP Oil Supply accounted for 14% and 10% of our revenues for the years ended December 31, 2005 and 2004, respectively. No other customers accounted for 10% or more of our revenues during any of the three years. The majority of revenues from Marathon, Valero and BP Oil Supply pertain to our marketing operations. We believe that the loss of these customers would have only a short-term impact on our operating results. There can be no assurance, however, that we would be able to identify and access a replacement market at comparable margins.
Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered creditworthy, unless the credit risk can otherwise be reduced.
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Note 9 -
Related Party Transactions
Reimbursement of Expenses of Our General Partner and its Affiliates
We do not pay our general partner a management fee, but we do reimburse our general partner for all direct and indirect costs of services provided to us, incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us, as well as all other expenses necessary or appropriate to the conduct of our business, allocable to us. We record these costs on the accrual basis in the period in which our general partner incurs them. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Total costs reimbursed by us to our general partner for the years ended December 31, 2006, 2005 and 2004 were $204.6 million, $165.2 million and $151.0 million respectively. Amounts due to our general partner at December 31, 2006 and 2005 were $0.8 million and $6.8 million, respectively.
Vulcan Energy Corporation
As of December 31, 2006, Vulcan Energy Corporation (“Vulcan Energy”) and its affiliates owned approximately 54% of our general partner interest, as well as approximately 11.3% of our outstanding limited partner units.
Voting Agreement
In August 2005, one of the owners of our general partner notified the remaining owners of its intent to sell its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was purchased pro rata by all remaining owners. As a result of the transaction, the interest of Vulcan Energy increased from 44% to approximately 54%. At the closing of the transaction, Vulcan Energy entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed, subject to certain ongoing conditions, to waive certain change-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest. These ownership changes to our general partner had no impact on us.
Administrative Services Agreement
On October 14, 2005, Plains All American GP LLC (“GP LLC”) and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for consideration of an annual fee, plus certain expenses. Effective October 1, 2006, the annual fee for providing these services was increased to $1 million. The Services Agreement extends through October 2008, at which time it will automatically renew for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, Vulcan Energy has appointed certain employees of GP LLC as officers of Vulcan Energy for administrative efficiency. Under the Services Agreement, Vulcan Energy acknowledges that conflicts may arise between itself and GP LLC. If GP LLC believes that a specific service is in conflict with the best interest of GP LLC or its affiliates then GP LLC is entitled to suspend the provision of that service and such a suspension will not constitute a breach of the Services Agreement.
Crude Oil Purchases from Calumet Florida L.L.C.
Until August 12, 2005, Vulcan Energy owned 100% of Calumet Florida L.L.C. (“Calumet”). Calumet is now owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. We purchase crude oil from Calumet and paid approximately $45.1 million, $38.1 million and $28.3 million to Calumet in 2006, 2005 and 2004, respectively.
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Investment in PAA/Vulcan Gas Storage, LLC
PAA/Vulcan, a limited liability company, was formed in 2005. PAA/Vulcan is owned 50% by us and the other 50% is owned by Vulcan Gas Storage LLC, a subsidiary of Vulcan Capital, which is an affiliate of Vulcan Energy. The Board of Directors of PAA/Vulcan is comprised of an equal number of our representatives and representatives of Vulcan Gas Storage and is responsible for providing strategic direction and policy-making. We are responsible for the day-to-day operations. PAA/Vulcan is not a variable interest entity, and we do not have the ability to control the entity; therefore, we account for the investment under the equity method in accordance with APB 18. This investment is reflected in investments in unconsolidated entities in our consolidated balance sheet.
In September 2005, PAA/Vulcan acquired ECI, an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We and Vulcan Gas Storage LLC each made an initial cash investment of approximately $112.5 million, and Bluewater Natural Gas Holdings, LLC, a subsidiary of PAA/Vulcan (“Bluewater”) entered into a $90 million credit facility contemporaneously with closing. We currently have no direct or contingent obligations under the Bluewater credit facility.
PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “base gas”). During the first quarter of 2006, we arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We received a fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.
We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time.
In conjunction with the formation of PAA/Vulcan and the acquisition of ECI, PAA and Paul G. Allen provided performance and financial guarantees to the seller with respect to PAA/Vulcan’s performance under the purchase agreement, as well as in support of continuing guarantees of the seller with respect to ECI’s obligations under certain gas storage and other contracts. PAA and Paul G. Allen would be required to perform under these guarantees only if ECI was unable to perform. In addition, we provided a guarantee under one contract with an indefinite life for which neither Vulcan Capital nor Paul G. Allen provided a guarantee. In exchange for the disproportionate guarantee, PAA will receive preference distributions totaling $1.0 million over ten years from PAA/Vulcan (distributions that would otherwise have been paid to Vulcan Gas Storage LLC). We believe that the fair value of the obligation to stand ready to perform is minimal. In addition, we believe the probability that we would be required to perform under the guaranty is extremely remote; however, there is no dollar limitation on potential future payments that fall under this obligation.
PAA/Vulcan will reimburse us for the allocated costs of PAA’s non-officer staff associated with the management and day-to-day operations of PAA/Vulcan and all out-of-pocket costs. In addition, in the first fiscal year that EBITDA (as defined in the PAA/Vulcan LLC agreement) of PAA/Vulcan exceeds $75.0 million, we will receive a distribution from PAA/Vulcan equal to $6.0 million per year for each year since formation of the joint venture, subject to a maximum of 5 years or $30 million. Thereafter, we will receive annually a distribution equal to the greater of $2 million per year or two percent of the EBITDA of PAA/Vulcan.
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Equity Offerings
In December 2006, we sold 6,163,960 common units, approximately 10% and 10% of which were sold to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. (“KACALP”) and Encap Investments, L.P., respectively. The net proceeds were used to fund capital expenditures, to reduce indebtedness and for general partnership purposes. KAFU Holdings, L.P., which owns a portion of our general partner and has a representative on our board of directors, is managed by KACALP. Affiliates of Encap own a portion of our general partner and have a representative on our board of directors.
In July and August 2006, we sold a total of 3,720,930 common units, approximately 18.7% and 12.5% of which were sold to investment funds affiliated with Vulcan Capital and KACALP, respectively. The proceeds from this offering were used to fund acquisition costs, repay indebtedness under our credit facility and for general partnership purposes.
In March and April 2006, we sold 3,504,672 common units, approximately 20% of which were sold to investment funds affiliated with KACALP. The net proceeds were used to fund a portion of the Andrews acquisition, to reduce indebtedness and for general partnership purposes.
Concurrently with our public offering of equity in September 2005, we sold 679,000 common units pursuant to our existing shelf registration statement to investment funds affiliated with KACALP in a privately negotiated transaction for a purchase price of $40.512 per unit (equivalent to the public offering price less underwriting discounts and commissions).
On February 25, 2005, we issued 575,000 common units in a private placement to a subsidiary of Vulcan Capital. The sale price was $38.13 per unit, which represented a 2.8% discount to the closing price of the units on February 24, 2005. The sale resulted in net proceeds, including the general partner’s proportionate capital contribution ($0.5 million) and net of expenses associated with the sale, of approximately $22.3 million.
In April 2004, we sold 3,245,700 unregistered Class C common units to a group of investors affiliated with KACALP, Vulcan Capital and Tortoise Capital pursuant to Rule 4(2) under the Securities Act. Total proceeds from the transaction, after deducting transaction costs and including the general partner’s proportionate contribution, were approximately $101 million.
Note 10 - Long-Term Incentive Plans
Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan, the 2005 Long-Term Incentive Plan and the PPX Successor Long-Term Incentive Plan for employees and directors and the Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan for non-officer employees. The 1998 Plan, 2005 Plan and PPX Successor Plan authorize the grant of an aggregate of 5.4 million common units deliverable upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom” units, which mature into the right to receive common units (or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.Our general partner will be entitled to reimbursement by us for any costs incurred in settling obligations under the plans.
We adopted SFAS 123(R) on January 1, 2006 (see Note 1 for a discussion of changes in accounting principles). Under SFAS 123(R) the fair value of the awards, which are subject to liability classification, is calculated based on the market price of our units at the balance sheet date adjusted for (i) the present value of any distributions that are estimated to occur on the underlying units over the vesting period that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is then expensed over the period the awards are earned. For awards with performance conditions, we recognize LTIP expense only if the achievement of the performance condition is considered probable. When awards with performance conditions that were previously
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considered improbable of occurring become probable of occurring, we incur additional LTIP expense necessary to adjust the life-to-date accrued liability associated with these awards. In addition, we recognize compensation expense for DER payments in the period the payment is earned.
As of December 31, 2006, there were outstanding awards of approximately 3.0 million with a weighted average grant-date fair value of approximately $31.94 per unit. Our LTIP awards typically contain performance conditions relative to our annualized distribution level and vest upon the latter of a certain date or upon the attainment of a certain annualized distribution level. Upon our February 2007 annualized distribution of $3.20, approximately 2.2 million of our outstanding awards will have satisfied all performance conditions necessary for vesting and will vest in various increments over the next 5 years. Approximately 0.8 million of our outstanding awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and $4.00 which is not yet considered probable of occurring. However, certain of these awards still outstanding in 2012 will vest regardless of whether or not the performance condition is attained. Provided the performance conditions associated with these awards are ultimately attained, these awards will vest in various increments between 2010 and 2012. Approximately 1.6 million of our outstanding awards include DERs. Our DER awards typically contain performance conditions relative to our annualized distribution level and vest upon the earlier of a certain date or a certain annualized distribution level. The DERs terminate with the vesting or forfeiture of the underlying award.
Our LTIP activity is summarized in the following table (in millions except weighted average grant date fair values):
(1)
For 2006, approximately 0.8 million of the awards granted will cash settle upon vesting.
We recognized expense related to our LTIP of approximately $43 million, $26 million and $8 million during 2006, 2005 and 2004, respectively. As of December 31, 2006, we have an accrued liability of approximately $58 million associated with our LTIP. Cash payments associated with LTIP vestings and DER awards were approximately $2 million and $3 million in 2006, $4 million and $1 million in 2005 and $29 million and $0 in 2004, respectively. Based on our unit price on the applicable vesting date, the total fair value of vested awards was approximately $1.4 million, $4.4 million and $28.3 million during 2006, 2005 and 2004, respectively. No units were issued during 2006 in connection with the settlement of vested awards.
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As of December 31, 2006, the weighted average remaining contractual life of our outstanding awards was approximately three years based on expected vesting dates. Based on the December 31, 2006 fair value measurement and probability assessment regarding future distributions, we expect to recognize an additional $64 million of expense over the life of our outstanding awards related to the remaining unrecognized fair value. This estimate is based on the market price of our limited partner units at December 31, 2006 and actual amounts may differ materially as a result of a change in market price. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):
(1)
Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2006.
Note 11 - Commitments and Contingencies
Commitments
We lease certain real property, equipment and operating facilities under various operating and capital leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2006, are summarized below (in millions):
Expenditures related to leases for 2006, 2005 and 2004 were $37.7 million, $25.7 million and $20.1 million, respectively.
Contingencies
Pipeline Releases. In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the U.S. Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conducted clean-up
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operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0 million to $3.5 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Justice (the “DOJ”) for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating in the investigation. Our assessment is that it is probable we will pay penalties related to the two releases. We have accrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that the loss contingency may exceed our estimate with respect to penalties assessed by the DOJ; however, we have no indication from EPA or the DOJ of what penalties might be sought. As a result, we are unable to estimate the range of a reasonably possible loss contingency in excess of our accrual.
On November 15, 2006, we completed the Pacific acquisition. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.
The People of the State of California v. Pacific Pipeline System, LLC (“PPS”). In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when Line 63 was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. As of December 31, 2006, $26 million of remediation costs had been incurred. We estimate additional remediation costs of approximately $1 to $2 million, substantially all of which we expect to incur before June 2007. We anticipate that the majority of costs associated with this release will be covered under a pre-existing PPS pollution liability insurance policy.
In March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleges the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. The fines that can be assessed against PPS for the violations of the strict liability statutes are based, in large measure, on the volume of unrecovered crude oil that was released into the environment, and, therefore, the maximum state fine that can be assessed is estimated to be approximately $1,100,000, in the aggregate. This amount is subject to a downward adjustment with respect to actual volumes of recovered crude oil, and the State of California has the discretion to further reduce the fine after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the strict liability offenses cannot be ascertained. We will defend against these charges. In addition to these fines, the State of California has indicated that it may seek to recover approximately $150,000 in natural resource damages against PPS in connection with this matter. The mitigating factors may also serve as a basis for a downward adjustment of the natural resource damages amount. We believe that certain of the alleged violations are without merit and intend to defend against them, and that mitigating factors should apply.
In December 2006 we were informed that the EPA may be intending to refer this matter to the DOJ for the initiation of proceedings to assess civil penalties against PPS. The DOJ has accepted the referral. We understand that the maximum permissible penalty that the EPA could assess under relevant statutes would be approximately $3.7 million. We believe that several mitigating circumstances and factors exist that could substantially reduce the penalty, and intend to pursue discussions with the EPA regarding such mitigating circumstances and factors. Because of the uncertainty associated with these factors, the final amount of the penalty that will be assessed by the EPA cannot be ascertained. Discussions with the DOJ to resolve this matter have commenced.
Kosseff v. Pacific Energy, et al, case no. BC 3544016. On June 15, 2006, a lawsuit was filed in the Superior court of California, County of Los Angeles, in which the plaintiff alleged that he was a unitholder of Pacific and he sought to represent a class comprising all of Pacific’s unitholders. The complaint named as defendants Pacific and
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certain of the officers and directors of Pacific’s general partner, and asserted claims of self-dealing and breach of fiduciary duty in connection with the pending merger with us and related transactions. The plaintiff sought injunctive relief against completing the merger or, if the merger was completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. On September 14, 2006, Pacific and the other defendants entered into a memorandum of settlement with the plaintiff to settle the lawsuit. As part of the settlement, Pacific and the other defendants deny all allegations of wrongdoing and express willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement is subject to customary conditions, including court approval. As part of the settlement, we (as successor to Pacific) will pay $0.5 million to the plaintiff’s counsel for their fees and expenses, and incur the cost of mailing materials to former Pacific unitholders. If finally approved by the court, the settlement will resolve all claims that were or could have been brought on behalf of the proposed settlement class in the actions being settled, including all claims relating to the merger, the merger agreement and any disclosure made by Pacific in connection with the merger. The settlement did not change any of the terms or conditions of the merger.
Air Quality Permits. In connection with the Pacific merger, we acquired Pacific Atlantic Terminals LLC (“PAT”), which is now one of our subsidiaries. PAT owns crude oil and refined products terminals in northern California. In the process of integrating PAT’s assets into our operations, we identified certain aspects of the operations at the terminals that appeared to be out of compliance with specifications under the relevant air quality permit. We conducted a prompt review of the circumstances and self-reported the apparent historical occurrences of non-compliance to the Bay Area Air Quality Management District. We are cooperating with the District’s review of these matters.
General. We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
Environmental. We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the purchase of assets from Link Energy LLC in April 2004, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations. See “- Pipeline Releases” above.
At December 31, 2006, our reserve for environmental liabilities totaled approximately $39.1 million. At December 31, 2006, we have recorded receivables totaling approximately $11.6 million for amounts which are probable of recovery under insurance and from third parties under indemnification agreements. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows. See Note 13.
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Other. A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The overall trend in the environmental insurance industry appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities or incorporate higher retention in our insurance arrangements.
The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.
Note 12 - Supplemental Condensed Consolidating Financial Information
In conjunction with the Pacific acquisition, some but not all of our 100% owned subsidiaries have issued full, unconditional, and joint and several guarantees of our Senior Notes. Given that certain, but not all, subsidiaries are guarantors of our Senior Notes, we are required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, we are referred to as “Parent”, while the “Guarantor Subsidiaries” are PAA Finance Corp.; Plains Marketing, L.P.; Plains Pipeline, L.P.; Plains Marketing GP Inc.; Plains Marketing Canada LLC; Plains Marketing Canada, L.P.; PMC (Nova Scotia) Company; Basin Holdings GP LLC; Basin Pipeline Holdings, L.P.; Rancho Holdings GP LLC; Rancho Pipeline Holdings L.P.; Plains LPG Services GP LLC; Plains LPG Services, L.P.; Lone Star Trucking, LLC; Plains Marketing International GP LLC; Plains Marketing International, L.P; Plains LPG Marketing, L.P.; Rocky Mountain Pipeline System, LLC; Pacific Marketing and Transportation LLC; Pacific Atlantic Terminals LLC; Pacific LA Marine Terminal, LLC; Ranch Pipeline LLC; PEG Canada GP LLC; PEG Canada, L.P.; Pacific Energy Group LLC; Pacific Energy Finance Corporation; Rangeland Pipeline Company; Rangeland Marketing Company; Rangeland Northern Pipeline Company; Rangeland Pipeline Partnership; and Aurora Pipeline Company, Ltd. and “Non-Guarantor Subsidiaries” are Atchafalaya Pipeline, L.L.C.; Andrews Partners, LLC; Pacific Pipeline System, LLC, Pacific Terminals, LLC, Pacific Energy Management LLC and Pacific Energy GP LP.
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The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Parent’s Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting:
Condensed Consolidating Balance Sheet
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Condensed Consolidating Statement of Operations
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Condensed Consolidating Statements of Cash Flows
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At December 31, 2005 and for the years ended December 31, 2005 and December 31, 2004, the Non-Guarantor Subsidiaries were considered minor, as defined by Regulation S-X rule 3-10(h)(6) and thus, supplemental condensed consolidating financial information is not presented for those periods.
Note 13 - Environmental Remediation
We currently own or lease properties where hazardous liquids, including hydrocarbons, are being or have been handled. These properties and the hazardous liquids or associated generated wastes disposed thereon may be subject to CERCLA, RCRA and analogous state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate hazardous liquids or associated generated wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.
In addition, we have entered into indemnification agreements with various counterparties in conjunction with several of our acquisitions. Allocation of environmental liability is an issue negotiated in connection with each of our acquisition transactions. In each case, we make an assessment of potential environmental exposure based on available information. Based on that assessment and relevant economic and risk factors, we determine whether to negotiate an indemnity, what the terms of any indemnity should be (for example, minimum thresholds or caps on exposure) and whether to obtain insurance, if available. In some cases, we have received contractual protections in the form of environmental indemnifications from several predecessor operators for properties acquired by us that are contaminated as a result of historical operations. These contractual indemnifications typically are subject to specific monetary requirements that must be satisfied before indemnification will apply and have term and total dollar limits.
For instance, in connection with the purchase of assets from Link in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million. A substantial portion of these environmental liabilities are associated with the former Texas New Mexico (“TNM”) pipeline assets. On the effective date of the acquisition, we and TNM entered into a cost-sharing agreement whereby, on a tiered basis, we agreed to bear $11 million of the first $20 million of pre-May 1999 environmental issues. We also agreed to bear the first $25,000 per site for new sites which were not identified at the time we entered into the agreement (capped at 100 sites). TNM agreed to pay all costs in excess of $20 million (excluding the deductible for new sites). TNM’s obligations are guaranteed by Shell Oil Products (“SOP”). As of December 31, 2006, we had incurred approximately $7 million of remediation costs associated with these sites; SOP’s share is approximately $1.5 million.
In connection with the acquisition of certain crude oil transmission and gathering assets from SOP in 2002, SOP purchased an environmental insurance policy covering known and unknown environmental matters associated with operations prior to closing. We are a named beneficiary under the policy, which has a $100,000 deductible per site, an aggregate coverage limit of $70 million, and expires in 2012. SOP made a claim against the policy; however, we do not believe that the claim substantially reduced our coverage under the policy.
In connection with our 1999 acquisition of Scurlock Permian LLC from MAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock’s business or properties that occurred prior to the date of the closing of the acquisition. Other than with respect to liabilities associated with two Superfund sites at which it is alleged that Scurlock deposited waste oils, this indemnity has expired or was terminated by agreement.
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As a result of our merger with Pacific, we have assumed liability for a number of ongoing remediation sites, associated with releases from pipeline or storage operations. These sites had been managed by Pacific prior to the merger, and in general there is no insurance or indemnification to cover ongoing costs to address these sites (with the exception of the Pyramid Lake crude oil release). We have evaluated each of the sites requiring remediation, through review of technical and regulatory documents, discussions with Pacific, and our experience at investigating and remediating releases from pipeline and storage operations. We have developed reserve estimates for the Pacific sites based on this evaluation, including determination of current and long-term reserve amounts, which total approximately $21.8 million.
Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified.
We have in the past experienced and in the future likely will experience releases of crude oil or petroleum products into the environment from our pipeline and storage operations. We also may discover environmental impacts from past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the Link acquisition, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under CleanWater Act Section 308), commensurate with the scale and scope of our pipeline operations.
At December 31, 2006, our reserve for environmental liabilities totaled approximately $39.1 million (approximately $21.8 million of this reserve is related to liabilities assumed as part of the Pacific merger, and $10.4 million is related to liabilities assumed as part of the Link acquisition). Approximately $19.5 million of our environmental reserve is classified as current (within other current liabilities on our Consolidated Balance Sheets) and $19.6 million is classified as long-term (within Other long-term liabilities and deferred credits on our Consolidated Balance Sheets). At December 31, 2006, we have recorded receivables totaling approximately $11.6 million for amounts recoverable under insurance and from third parties under indemnification agreements.
In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, no assurances can be made that any costs incurred in excess of this reserve or outside of the indemnifications would not have a material adverse effect on our financial condition, results of operations, or cash flows.
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Note 14 - Quarterly Financial Data (Unaudited):
(1)
The sum of the four quarters does not equal the total year due to rounding.
(2)
Includes buy/sell transactions. See Note 2.
(3)
Represents cash distributions declared and paid in the applicable period.
Note 15 - Operating Segments
Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. Prior period disclosures have been revised to reflect our change in segments.
We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative (“G&A”) expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our “available cash” (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period’s earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which mitigate the actual decline in the value of our principal fixed assets. These maintenance costs are a component of field
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operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash,” consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are considered expansion capital expenditures, not maintenance capital. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. The following table reflects certain financial data for each segment for the periods indicated.
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(1)
Amounts related to SFAS 133 are included in marketing revenues and impact segment profit.
(2)
Intersegment sales are conducted at arms length.
(3)
Marketing segment profit includes interest expense on contango inventory purchases of $49.2 million, $23.7 million, and $2.0 million for the twelve months ended December 31, 2006, 2005 and 2004, respectively.
(4)
The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle (in millions):
Geographic Data
We have operations in the United States and Canada. Set forth below are revenues and long lived assets attributable to these geographic areas (in millions):
EXHIBIT INDEX
.18
-
Third Supplemental Indenture dated November 15, 2006 to Indenture dated as of June 16, 2004, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed November 21, 2006).
.19
-
Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report on Form 8-K filed September 28, 2005).
.20
-
First Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 23, 2005, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed November 21, 2006).
.21
-
Registration Rights Agreement dated as of July 26, 2006 among Plains All American Pipeline, L.P., Vulcan Capital Private Equity I LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.13 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
.22
-
Registration Rights Agreement dated as of December 19, 2006 among Plains All American Pipeline, L.P., E-Holdings III, L.P., E-Holdings V, L.P., Kayne Anderson MLP Investment Company and Kayne Anderson Energy Development Company (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-3/A, File No, 333-138888).
.23
-
Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities, LLC, Wedbush Morgan Securities Inc. and Wells Fargo Securities, LLC relating to the 2017 Notes (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K filed October 30, 2006).

Filed herewith
**
Management compensatory plan or arrangement