ITEM 1A. Risk Factors
Risks Inherent in Our Business
We may not have sufficient cash from operations to pay the minimum quarterly distribution following establishment of cash reserves and after payment of fees and expenses, including payments to our General Partner.
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution on all units. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:
•the volume of crude oil and refined products we transport through our pipelines;
•the tariff rates we charge on our pipelines;
•the percentage of storage capacity we have under lease;
•the lease rates we charge on our storage tanks;
•margins in our gathering and marketing business;
•the level of our operating costs, including payments to our General Partner;
•changes in currency exchange rates and foreign currency restrictions and shortages;
•the level of competition from other pipelines; and
•prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, such as:
•the level of capital expenditures we make;
•the restrictions contained in our debt agreements and our debt service requirements;
•fluctuations in our working capital needs;
•the cost of acquisitions, if any;
•our ability to borrow under our working capital facility to make distributions; and
•the amount, if any, of cash reserves established by our General Partner, in its discretion.
The amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss and may not make cash distributions during periods when we record net income.
A material decline in the volume of crude oil processed by any of the refineries we serve could reduce our ability to make distributions to our unitholders.
Any significant reduction in the volume of crude oil processed at the refineries we serve could reduce the volume of crude oil and refined products we transport on our pipelines and result in our realizing materially lower levels of revenue and cash flow. This reduction could occur for a number of reasons, including:
•A sustained decrease in demand for refined products, which could result from:
•a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline, diesel fuel and jet fuel;
•an increase in the market price of crude oil that leads to higher refined product prices, resulting in lower demand;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products; or
•a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or alternative fuel sources, or otherwise.
•Refineries we serve could partially or completely shut down their operations, temporarily or permanently, due to factors affecting their ability to produce refined products such as:
•voluntary shutdown of a refinery for economic or other reasons;
•unscheduled maintenance or catastrophic events at a refinery, such as a fire, flood, explosion or power outage;
•labor difficulties that result in a work stoppage or slowdown at a refinery;
•environmental litigation or other proceedings that require the halting of all or a portion of the operations at a refinery;
•increasingly stringent environmental regulations, such as the Environmental Protection Agency's gasoline and diesel sulfur control requirements that limit the concentration of sulfur in motor gasoline and diesel fuel;
•a governmental ban or other limitation on the use of any important feedstock or product of a refinery; or
•other legislation or regulation that adversely impacts the economics of refinery operations.
•The refineries we serve may be unsuccessful in competing against other existing or future sources of refined products in their markets, such as pipelines or marine barges or tankers that deliver refined products into the Los Angeles Basin or the Rocky Mountain region from refineries in other areas.
A material decrease in the production of crude oil from the oil fields served by our pipelines could materially reduce our ability to make distributions to our unitholders.
The throughput on our crude oil pipelines depends on the availability of attractively priced crude oil produced from the oil fields served by such pipelines, or through connections with pipelines owned by third parties. Crude oil production may decline for a number of reasons, including natural declines due to depleting wells, a material decrease in the price of crude oil, or the inability of producers to obtain necessary drilling or other permits from applicable governmental authorities. If we do not replace volumes lost due to a temporary or permanent material decrease in production from the oil fields served by our crude oil pipelines, our throughput would decline, reducing our revenue and cash flow and adversely affecting our ability to make cash distributions to our unitholders.
Certain of the crude oil producing fields served by our pipelines are experiencing a decline in production. In addition, declining production may impact us in the future if shippers elect to replace Alaskan North Slope crude oil in San Francisco with crude oil produced in the San Joaquin Valley and California Outer Continental Shelf.
We may be unable to attract new volumes of crude oil, including Canadian synthetic crude oil, to the Rangeland and U.S. Rocky Mountain systems. In such an event, we may be unable to replace the crude oil production currently being gathered by these systems, which production is expected to decline.
A decrease in the price of crude oil, on either a temporary or permanent basis, may also affect the total volume of crude oil produced from the fields served by our crude oil pipelines. If crude oil prices were to decline significantly, as they did in 1998 and other periods in the past, production from certain of the fields served by our pipelines may cease to be profitable and crude oil producers may decide to decrease or stop production. In addition, an increase in the price of natural gas or electricity, both of which are used in connection with an advanced recovery technique known as steam-flooding, could result in a decrease in steam-flood operations in certain of the fields served by our pipelines and therefore reduce production. Natural gas is also used in the process of producing synthetic crude oil.
To maintain our throughput, new supplies of crude oil must be available to offset volumes lost because of declines in crude oil production. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is declining and competition to gather available production is intense. It is difficult to attract producers to a new gathering system if the producer is
already connected to an existing system. As a result, we or third-party shippers on our pipeline systems may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil.
We depend on refineries and petroleum products pipelines owned and operated by others to supply our refined products pipeline and terminals.
We depend on connections with refineries and petroleum products pipelines owned and operated by third parties as the primary source of supply for our refined products facilities. Outages at these refineries or reduced throughput on these pipelines because of testing, line repair, damage to pipelines, reduced operating pressures or other causes could result in our being unable to deliver products to our customers from our terminals or receive products for storage and could adversely affect our ability to meet our financial obligations and pay cash distributions.
If the refineries we serve process crude oil from locations to which our pipelines do not directly or indirectly connect, throughput on our crude oil pipelines could materially decline.
Throughput on our West Coast pipelines serving the Los Angeles Basin decreases to the extent refineries in the Los Angeles Basin choose to process more Alaskan North Slope and foreign crude oil and less California crude oil. Refineries in the Los Angeles Basin currently process crude oil produced in California, Alaska and various foreign nations. Marine barges and tankers deliver Alaskan North Slope and foreign crude oil to the Ports of Los Angeles and Long Beach. This crude oil is then directed through third-party pipelines to the various refineries and terminal facilities serving the Los Angeles Basin. These waterborne deliveries compete with crude oil produced in the San Joaquin Valley and California Outer Continental Shelf that is transported to the Los Angeles Basin on our Line 2000 and Line 63 system. To the extent waterborne deliveries reduce the demand for our transportation services, this decreases our West Coast operations' revenue and cash flow and could impair our ability to make distributions.
The refineries we serve may not be able to secure adequate supplies of crude oil from the crude oil producing areas served by our crude oil pipelines. For example, the refineries in the Los Angeles Basin that are served by our Line 2000 and Line 63 pipelines compete with refineries in the San Francisco Bay and central California areas for supplies of crude oil produced in the San Joaquin Valley and California Outer Continental Shelf; and to the extent this crude oil is directed to the San Francisco refiners, a decision over which we have no control, our throughput volumes and revenue would be adversely affected.
New competing pipeline systems could also be built or existing pipeline systems expanded that could deliver crude oil from other locations to the refineries that we serve. This could cause us to reduce our tariff rates or to experience reduced throughput.
If new sources of crude oil that are not connected to our pipelines become available to the refineries we serve, throughput on our pipelines could materially decline.
New sources of crude oil that are available to the refineries we serve could be discovered and developed. If a new source of crude oil is not connected to our existing crude oil pipelines, the throughput on our pipelines could materially decline. For example, wells have recently been successfully drilled and completed in a previously undeveloped oil field approximately one hundred miles south of Salt Lake City, an area that is not served by any of our pipelines. The extent of the oil reserves in this field are presently unknown, but if they are significant, they could compete with the oil expected to be delivered to the Salt Lake City refineries through our crude oil pipelines.
Due to our lack of asset diversification, adverse developments in our transportation and storage businesses could reduce our ability to make distributions to our unitholders.
We generate revenue primarily by charging tariff rates for transporting crude oil and refined products on our pipelines and by leasing capacity in our storage facilities. Due to our lack of asset diversification, an adverse development in one of these businesses would have a significantly greater impact on our financial condition and results of operations than if we operated more diverse assets.
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 our nation's pipeline infrastructure, may be future targets of terrorist organizations. These developments have subjected 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.
Tariff rate regulation or a successful challenge to our tariff rates may reduce the tariff rates we charge and the amount of cash available for distribution to our unitholders.
The FERC regulates the tariff rates for our interstate common carrier operations. Shippers may protest our tariffs, and the FERC may investigate the lawfulness of new or changed tariff rates. The FERC may also investigate tariff rates that have become final and effective and require refunds of amounts collected under tariff rates ultimately found unlawful. The FERC's ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the use of tariff rates that reflect increased costs.
In May 2005, FERC issued a statement of general policy. According to the policy statement, a pipeline, including one organized as a partnership, can include in computing its cost of service an income tax allowance if the pipeline's owners have an actual or potential income tax liability on their income from the pipeline. FERC said it would determine on a case-by-case basis whether a particular partner has an actual or potential income tax liability and what assumptions should determine the related income tax rate. In December 2005, in a proceeding involving SFPP, L.P., FERC provided further clarification regarding the manner in which the income tax allowance policy statement would be applied to a pipeline owned by a partnership. Application of FERC's policy statement in individual cases may be subject to further FERC action or review in the appropriate Court of Appeals. Therefore, whether a partnership will ultimately be entitled to recover an income tax allowance in its cost of service is not certain. If we were required to defend our rates on a cost of service basis, whether because we filed new rates supported by a cost of service calculation or because a person claimed by complaint that our rates exceed a just and reasonable level, we would be required to establish pursuant to the new policy statement that the inclusion of an income tax allowance in our cost of service was just and reasonable. We can provide no assurance that we will be able to establish that our unitholders or our unitholders' owners are subject to United States federal income taxation on the income generated by us. If we are unable to do so, FERC could disallow a substantial portion of our income tax allowance, in which case it is likely that the level of maximum lawful rates would decrease from current levels.
Most of our U.S. intrastate pipeline and terminal operations are subject to regulation by state public utility commissions. A state commission may investigate our intrastate tariff rates or our terms and conditions of service on its own initiative or at the urging of a shipper or other interested party. If a state commission found that our tariff rates were not justified, the state commission could order us to reduce our tariff rates. If a state commission were to withdraw or modify our authority or use certain non-cost based rates, such as market based rates or the authority to negotiate or enter into individual
customer contracts, our revenue and cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
Our Canadian pipelines are subject to regulation by the EUB and, in the case of the Aurora pipeline, the NEB. Under the National Energy Board Act, the Aurora pipeline is a common carrier. The NEB could investigate the tariff rates or our terms and conditions of service relating to the Aurora pipeline on its own initiative or at the urging of a shipper or other interested party and, if it found our rates or terms of service unjust or unreasonable or unjustly discriminatory, require us to reduce our rates, provide access to other shippers, or change our terms of service. The EUB 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 proprietary pipelines and, if it found our rates or terms of service unreasonable or unjustly discriminatory, declare our pipelines to be common carrier pipelines and require us to reduce our rates, provide access to other shippers, or otherwise change our terms of service. Any reduction in our tariff rates would most likely result in lower revenue and cash flows and may reduce our ability to make cash distributions to our unitholders.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
Refined products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications for refined products could reduce our throughput volume on our refined products pipelines and terminals, require us to incur additional handling costs or require the expenditure of capital. For instance, different product specifications for different markets impact the fungibility of the system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our revenue and cash flows may be adversely affected, which could adversely affect our ability to make distributions to our unitholders.
Our Canadian operations are subject to the jurisdiction of Canadian federal and provincial regulatory authorities.
The oil industry in Canada, including our operations, is subject to regulation and intervention by the Canadian federal and provincial regulatory authorities in such matters as environmental protection controls, control over the abandonment of pipelines, transportation rates and, possibly, expropriation or cancellation of contract rights. These regulatory authorities may impose regulations on or otherwise intervene in the oil industry with respect to prices, taxes, transportation rates and the exportation of oil. Such regulations may be changed from time to time in response to complaints or economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil industry could reduce demand for crude oil, increase our costs and may have a material adverse impact on our operations.
We may be unsuccessful in competing against existing or future pipelines in the areas in which we currently operate or may operate in the future.
Our principal competitors for large volume shipments of crude oil and refined products are other pipelines. For example, we compete with Express pipeline in transporting Canadian crude oil to the U.S. Rocky Mountain region. New crude oil and refined pipelines could also be constructed in the areas served by our pipelines. Holly Energy Partners, L.P. and Enbridge Inc. have announced that they are studying a project for the construction of a pipeline that would transport crude oil from the terminus of the Frontier Pipeline to the Salt Lake City refineries, which, if constructed, would compete against certain of our Rocky Mountain pipelines. Competition among common carrier pipelines is based primarily on transportation charges, access to producing areas and refineries and customer
demand for crude oil and refined products. We compete to a lesser extent with trucks that deliver crude oil and refined products in several areas in which we serve. Some of our competitors have greater financial and other resources than we have. If we are unsuccessful in competing against other pipelines or trucking operations, throughput in our pipelines could be reduced and we may be unable to make cash distributions to our unitholders. Please read "Items 1 and 2-Business and Properties-West Coast Business Unit-Competition" and "-Rocky Mountain Business Unit-Competition" for a further discussion of the competition we face.
We are exposed to the credit risk of our customers in the ordinary course of our business.
In our gathering and marketing business, when we purchase crude oil at the wellhead, we sometimes pay all or a portion of the production proceeds to an operator, who then distributes those proceeds to the various interest owners. This arrangement may expose us to operator credit risk, and we must determine whether the operators have sufficient financial resources to make these payments and distributions and to indemnify and defend us in case of a protest, action or complaint. Even if our credit review and analysis mechanisms work properly, we may experience losses in dealings with operators and other parties.
Our U.S. operations are subject to federal, state and local laws and regulations, including those relating to environmental protection, operations and safety, that could require us to make substantial expenditures.
Our U.S. operations are subject to federal, state and local laws and regulations relating to environmental protection, operations and safety. Many of these laws and regulations impose increasingly stringent permitting and operating requirements. In addition, these laws and regulations are subject to change, which change could result in an increase in our ongoing cost of compliance and have an adverse effect on our operations. We could, therefore, be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from compliance with future required operating permits. Failure to comply with these environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties and, in some instances, the issuance of injunctions to limit or cease operations.
There are risks of accidental releases associated with our operations, such as leaks or spills of crude oil or refined products from our pipelines or storage facilities, which could result in significant liabilities arising from environmental cleanup and restoration costs and claims for personal injury and property damage. If we were unable to recover such costs through insurance or increased tariff rates, cash distributions to our unitholders could be adversely affected.
We also own or lease a number of U.S. properties that have been used to store or distribute crude oil or refined products for many years. Crude oil, refined products and wastes associated with these historical activities may have been disposed of or released into the environment at these properties or at other locations where such materials may have been taken for disposal. In addition, most of these properties have been operated by third parties whose handling, disposal and release of crude oil, refined products and waste materials were not under our control. We could incur significant liabilities for cleanup and restoration costs and claims for personal injury and property damage related to these historical activities. Please read "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations."
Our U.S. operations are also subject to extensive operations and safety regulation. Many departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the petroleum industry and its individual participants. The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the crude oil and refined products industry increases our cost of doing business and, consequently,
affects our profitability. Please read "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations."
Our Canadian operations are subject to Canadian environmental laws and regulations.
All phases of the oil industry in Canada are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances into the environment. These laws and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, changes to existing projects may require the submission and approval of environmental assessments or permit applications. Failure to comply with these environmental laws and regulations could result in the assessment of administrative, civil or criminal penalties and, in some instances, the issuance of injunctions to limit or cease operations. A release associated with the operation of the Rangeland system could result in significant liabilities arising from environmental cleanup and claims for personal injury or property damage.
The Rangeland system includes pipelines, gathering systems and storage facilities that have been used to transport and store crude oil for many years. Historical spills and releases from or at the Rangeland system properties have resulted in soil and groundwater contamination in certain locations. Any historical contamination found on, under or originating from the properties may be subject to remediation requirements under Canadian laws or under our contracts with the sellers of the Rangeland system and the MAPL pipeline. There can be no assurance that the actual remediation costs or associated liabilities will not exceed estimated amounts provided for, or will not otherwise be significant.
In December 2002, the Canadian federal government ratified the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which requires Canada to reduce its greenhouse gas emissions to 6% below 1990 levels over the 2008-2012 period. Although the Canadian government has not yet provided significant guidance on how it intends to meet these reduction targets, the energy industry has been identified as one of the areas that will be affected through the Large Industrial Emitters program. The final rules, once known, could affect our operations and profitability.
Our operations are subject to cross-border regulations.
Our cross-border activities with our Canadian subsidiaries subject us to regulatory matters including 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 license, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S., Canadian, state and local tax requirements could lead to the imposition of additional taxes, interest and penalties.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
Our operations are subject to operational hazards and unforeseen interruptions, such as earthquakes, landslides, floods and other natural disasters, accidents, fires, explosions, hazardous materials releases, acts of terrorism or other events beyond our control. A casualty might result in personal injury or loss of life, loss of equipment or loss of or extensive damage to property, as well as an interruption in our operations or the operations of the refineries to which we deliver. A significant
portion of our assets are located in California, which has a high incidence of earthquakes. Many of our assets operate near rivers, streams, waterways, oceans, and other marine environments that are susceptible to greater damage and more costly cleanup in the event of a petroleum related release. In addition, we may not be able to maintain our existing insurance coverage or obtain new coverage of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. Certain insurance is now or could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. We have elected not to extend our pollution liability insurance to cover terrorist attacks. Our other liability insurance has exclusions for certain types of terrorism. If we were to incur a significant liability for which we were not fully insured, it could adversely affect our business, financial condition or results of operations.
Actual costs incurred in connection with the release of crude oil on Line 63 in excess of our total estimated cost could have a material adverse effect on our financial condition, results of operations or cash flows.
The estimates of oil containment and clean-up of the areas impacted by the crude oil release on Line 63 are based on facts known at the time of estimation and our assessment of the ultimate outcome. Among the many uncertainties that impact the estimates are the necessary regulatory approvals for, and potential modification of, remediation plans, the ongoing assessment of the impact of soil and water contamination, changes in costs associated with environmental remediation services and equipment, and the possibility of third-party legal claims giving rise to additional expenses. Therefore, no assurance can be made that any costs incurred in excess of the total estimated cost for oil containment and clean-up of the impacted areas not covered by insurance, if any, would not have a material adverse effect on our financial condition, results of operations or cash flows.
Any reduction in the capability of, or the allocations to our shippers on, connecting, third-party pipelines could cause a reduction of throughput on our pipelines and could reduce the amount of cash available for distribution to our unitholders.
We depend upon connections to third-party pipelines to transport and store crude oil and refined products. Any reduction of capabilities in these connecting pipelines due to testing, line repair, reduced operating pressures, a decline in production associated with the third-party system or other causes could result in reduced throughput on pipelines. Similarly, any reduction in the allocations to our shippers on these connecting pipelines because additional shippers begin transporting volumes over the pipelines could also result in reduced throughput on our pipelines. Any reduction in throughput on our pipelines could adversely affect our revenue and cash flow and our ability to make distributions to our unitholders.
We are dependent on a small number of customers for a substantial portion of our revenue.
In 2005, the following customers represented greater than 10% of transportation and storage revenue for our West Coast operations: BP America Production Company; Chevron; Shell Trading Company and Valero Marketing and Supply Company. In addition, the following customers represented greater than 10% of net revenue for our Rocky Mountain pipeline transportation operations: Chevron and Tesoro. The loss of any of these customers, a decline in their credit worthiness or a substantial reduction in their shipments on our pipelines, could adversely affect our results of operations and cash flows and our ability to make distributions to our unitholders.
We are dependent on use of a third-party marine dock for delivery of waterborne products 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 is dependent on our ability to receive waterborne crude oil and other dark products, a major portion of which are presently being received through dock facilities operated by Shell Oil Products US in the Port of Long Beach. The agreement that allows us to utilize these dock facilities expires in October 2006, and there is no guarantee that it will be renewed. If this agreement is not renewed and if other alternative dock access cannot be arranged, the volumes of crude oil and other dark products that we presently receive from our customers in the Los Angeles Basin may be reduced, which could result in a reduction of storage and distribution revenue and cash flow and adversely affect our ability to make distributions to our unitholders.
Our ability to execute our acquisition or project development strategy may be impaired if we are unable to complete accretive acquisitions or projects on acceptable terms or access new capital to finance these activities.
Our ability to grow will depend principally on our ability to complete accretive acquisitions and development projects. We may be unable to identify attractive acquisition or project candidates or to complete acquisitions or projects on economically acceptable terms. Acquisition transactions can occur quickly and at any time and may be significant in size relative to the size of our existing asset base. We may need new capital to finance these acquisitions and development projects, and limitations on our ability to access new sources of capital may impair our ability to make acquisitions or undertake projects. If we are able to access new sources of capital, but only at more expensive rates, our ability to make accretive acquisitions or undertake projects will be limited. Our ability to maintain our capital structure may impact the market value of our common units.
The completion and success of our Pier 400 project remains subject to a number of risks unique to it, including (1) an exhaustive permitting process that may not result in the issuance of a permit and, even if successful, could result in the imposition of requirements and conditions that could adversely affect the feasibility and economic returns expected of the project, (2) political and legal risks posed by the many interest groups and constituencies that have an interest in the Port of Los Angeles and the project, one of which has declared its opposition to the project, and (3) our ability to obtain the financing necessary to construct the project, which may depend on the ability to obtain other long-term commitments from creditworthy customers, which is not assured.
Our results of operations could be adversely affected by changes in currency exchange rates.
We operate in the United States and Canada and thus our financial results may be impacted by fluctuations in currency exchange rates. Significant fluctuations in the value of the Canadian dollar versus the U.S. dollar could materially affect our results of operations and financial condition.
Risks Inherent in an Investment in Us
Cost reimbursements to our General Partner, which are determined in our General Partner's sole discretion, may be substantial and reduce our cash available for distribution to you.
Our General Partner is entitled to be reimbursed for all expenses it incurs on our behalf and has sole discretion in determining the amount of these reimbursements. Our obligation to reimburse our General Partner for expenses may be substantial. These cost reimbursements to our General Partner reduce the amount of available cash for distribution to our unitholders. Our General Partner and its affiliates also may provide us other services for which we will be charged fees as determined by our General Partner.
Our General Partner's discretion in establishing cash reserves may reduce the amount of cash available for distribution to you.
Our partnership agreement requires our General Partner to deduct from operating surplus cash reserves that, in its reasonable discretion, are necessary to fund our future operating expenditures. In addition, our partnership agreement permits our General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves affect the amount of cash available for distribution to you.
LBP and its affiliates have conflicts of interest with, and limited fiduciary responsibilities to, our unitholders, which may permit them to favor their own interests to your detriment.
LBMB controls LBP, which owns our General Partner. Based on our ownership, conflicts of interest may arise between LBP and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
•neither our partnership agreement nor any other agreement requires LBP to pursue a business strategy that favors us or utilizes our assets. The directors and officers of LBP have a fiduciary duty to make decisions in the best interests of the owners of LBP;
•LBP and its affiliates may engage in limited competition with us;
•our General Partner is allowed to take into account the interests of parties other than us, such as LBP, in resolving conflicts of interest;
•under Delaware law, our General Partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
•our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash, if any, that is distributed to our unitholders;
•our General Partner determines which costs incurred by it and its affiliates are reimbursable by us;
•our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
•our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates; and
•our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our General Partner's fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that waive or consent to conduct by our General Partner and its affiliates that reduce the obligations to which our General Partner would otherwise be held by state-law fiduciary duty standards. For example, our partnership agreement:
•permits our General Partner to make a number of decisions in its "sole discretion." This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
•provides that our General Partner is entitled to make other decisions in its "reasonable discretion";
•generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our General Partner may consider the interests of all parties involved, including its own; and
•provides that our General Partner and its officers and directors are not liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our General Partner and those other persons acted in good faith.
In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.
Even if unitholders are dissatisfied, they cannot easily remove our General Partner, which could lower the trading price of the common units.
Our General Partner manages and operates us. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management's decisions regarding our business. Unitholders did not elect our General Partner or its Board of Directors and have no right to elect our General Partner or the Board of Directors on an annual or other continuing basis.
The Board of Directors is chosen by LBP. The directors of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to LBP, the ultimate owner of our General Partner.
Furthermore, if unitholders are dissatisfied with the performance of our General Partner, they have limited ability to remove our General Partner. Our General Partner generally may not be removed except upon the vote of the holders of at least 662/3% of the outstanding units voting together as a single class. Because LBP controls 26.6% of all the units representing limited partner interests (equivalent to 26.1% of the total limited and General Partner interests in the Partnership), our General Partner currently cannot be removed unless a sufficient number of other limited partners so act. Also, if our General Partner is removed without cause during the subordination period and units held by our General Partner and its affiliates, including LBP, are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of the General Partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which preferences would otherwise have continued until we had met certain distribution and performance tests.
Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our General Partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our General Partner. Cause does not include most cases of charges of poor management of the business, so the removal of our General Partner because of our unitholders' dissatisfaction with our General Partner's performance in managing our partnership will most likely result in the early termination of the subordination period.
Furthermore, unitholders' voting rights are further restricted by the partnership agreement provision which states that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.
As a result of these provisions, the price at which the common units trade may be lower because of the absence or reduction of a takeover premium in the trading price.
The control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on LBP's ability, as the ultimate owner of our General Partner, to transfer its ownership 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 the decisions made and actions taken by the Board of Directors and officers.
A change of control would constitute an event of default under our senior notes' indentures, and our revolving credit facility. An event of default under the indentures relating to our senior notes could require us to make an offer to purchase all of our senior notes then outstanding 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 facility, the administrative agent may (and upon written instructions from lenders providing a majority of the loan commitments or the outstanding loan amount shall), 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.
We may issue additional units without your approval, which would dilute your ownership interests.
During the subordination period, our General Partner may cause us to issue up to 5,232,500 additional common units without unitholder approval. Our General Partner may also cause us to issue an unlimited number of additional common units or other partnership securities of equal rank with the common units, without unitholder approval, in a number of circumstances such as:
•the issuance of common units in connection with acquisitions or capital improvements that our General Partner determines would increase the amount of cash flow from operations per unit on a pro forma or estimated pro forma basis;
•the conversion of subordinated units into common units;
•the conversion of units of equal rank with the common units into common units under some circumstances;
•the conversion of the general partner interest and the incentive distribution rights into common units as a result of the withdrawal of our General Partner;
•issuances of common units pursuant to employee benefit plans; or
•issuances of common units to repay certain indebtedness.
Upon the expiration of the subordination period, we may issue an unlimited number of common units or other partnership securities without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of partnership securities ranking junior to the common units at any time.
The issuance of additional common units or other partnership securities of equal or senior rank will have the following effects:
•our unitholders' proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each unit may decrease;
•because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of the common units may decline.
Our General Partner may cause us to borrow funds in order to make cash distributions, even if the purpose or effect of the borrowing benefits the general partner or its affiliates.
In some instances, our General Partner may cause us to borrow funds from affiliates of LBP or from third parties to make cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.
The owner of our General Partner has a substantial amount of debt. A default under such debt could result in a change of control of our General Partner, which would be an event of default under the instruments governing our long-term indebtedness.
LBP, the owner of our General Partner, financed its purchase of our General Partner through a combination of equity capital and the proceeds from a senior secured credit and guaranty agreement. LBP's existing credit and guaranty agreement is secured by pledges of substantially all of its assets, including the interest in our General Partner. LBP's indebtedness under its credit and guaranty agreement is rated B- by Standard & Poor's Rating Services ("S&P") and B1 by Moody's Investor Service, Inc. ("Moody's"). If LBP were to default on its obligations under its credit and guaranty agreement, the lenders could exercise their rights under these pledges, which could result in a change of control of our General Partner and a change of control of us. A change of control would constitute an event of default under our indentures, and our revolving credit facility. An event of default under the indentures could require us to make an offer to purchase all of our senior notes then outstanding 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 facility, the administrative agent may (and upon written instructions from lenders providing a majority of the loan commitments or the outstanding loan amount shall), 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.
Our General Partner has a limited right to buy out minority unitholders if it owns more than 80% of the common units, which may require unitholders to sell their common units against their will and at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of the common units, our General Partner will have the right, but not the obligation, to acquire all, but not less than all, of the remaining common units held by unaffiliated unitholders. As a result, unitholders may be required to sell their common units against their will and at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their common units.
If our General Partner exercises its buy out right, the common units will be purchased at the greater of:
•the most recent 20-day average trading price ending on the date three days prior to the date the notice of purchase is mailed; or
•the highest price paid by our General Partner or its affiliates to acquire common units during the prior 90 days.
Our General Partner can assign its limited call right to an affiliate or to us.
Unitholders' liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for our obligations as if you were a general partner if:
•a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or
•unitholders' right to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 and 17-804 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Assignees who become substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the assignee at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks
The IRS could treat us as a corporation for tax purposes, which would substantially reduce any cash available for distribution to our unitholders.
The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gain, loss, or deduction would flow through to our unitholders. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore would likely result in a substantial reduction in the value of our common units. Moreover, treating us as a corporation would materially and adversely affect our ability to make payments on our debt securities.
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, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution would be reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amount will be adjusted to reflect the impact of that law on us.
A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will reduce cash available for distribution to our unitholders and our General Partner.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may disagree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and our General Partner and thus will be borne indirectly by our unitholders and our General Partner.
Unitholders may be required to pay taxes on their share of our income from us even if they do not receive any cash distributions from us.
Unitholders will be required to pay any federal income taxes and, in some cases, state, local and foreign income taxes on their share of our taxable income, whether or not they receive 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 tax liability that results from the taxation of their share of our taxable income.
Tax gain or loss on disposition of our common units could be different than expected.
A unitholder who sells common units will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated to that unitholder, which decreased the tax basis in that unitholder's common unit, will, in effect, become taxable income to that unitholder if the common unit is sold at a price greater than that unitholder's tax basis in that common unit, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to that unitholder.
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Recent legislation generally treats net income derived from the ownership of publicly traded partnerships as qualifying income to a regulated investment company. However, this legislation is only effective for taxable years beginning after October 22, 2004, the date of enactment. For taxable years beginning prior to the date of enactment, very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective tax rate applicable to individuals, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders' tax returns.
Unitholders may be subject to state and local taxes and return filing requirements.
In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We own assets and do business principally in California, Colorado, Montana, New Jersey, Pennsylvania, South Dakota, Utah and Wyoming, and Alberta, Canada. Of these states, only Wyoming does not currently impose a personal income tax. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Under certain circumstances, unitholders may be subject to foreign taxes and be required to file foreign tax returns.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3.
ITEM 3. Legal Proceedings
In August 2005, RPC learned that a Statement of Claim was filed by Desiree Meier and Robert Meier in the Alberta Court of Queen's Bench, Judicial District of Red Deer, naming RPC as defendant, and alleging personal injury and property damage caused by an alleged release of petroleum substances onto plaintiff's land by a prior owner and operator of the pipeline that is currently owned and operated by us. The claim seeks Cdn$1 million (approximately U.S.$0.9 million at December 31, 2005) in general damages, Cdn$2 million (approximately U.S.$1.7 million at December 31, 2005) in special damages, and, in addition, unspecified amounts for punitive, exemplary and aggravated damages, costs and interest. The Statement of Claim has not been served on RPC, so RPC has not been required to file an answer. RPC believes the claim is without merit, and intends to vigorously defend against it. RPC also believes that certain of the claims, if successfully proven by the plaintiffs, would be liabilities retained by the pipeline's prior owner under the terms of the agreement whereby we acquired the pipeline in question.
In connection with the Valero Acquisition, we assumed responsibility for the defense of a lawsuit filed in 2003 against Support Terminals Services, Inc., ("ST Services") by ExxonMobil Corporation ("ExxonMobil") in New Jersey state court. We have also assumed any liability that might be imposed on ST Services as a result of the suit. In the suit, ExxonMobil seeks reimbursement of approximately $400,000 for remediation costs it has incurred, from GATX Corporation, Kinder Morgan Liquid Terminals, the successor in interest to GATX Terminals Corporation, and ST Services. ExxonMobil also seeks a ruling imposing liability for any future remediation and related liabilities on the same defendants. These costs are associated with the Paulsboro, New Jersey terminal that was acquired by us on September 30, 2005. ExxonMobil claims that the costs and future remediation requirements are related to releases at the site subsequent to its sale of the terminal to GATX in 1990 and that, therefore, any remaining remediation requirements are the responsibility of GATX Corporation, Kinder Morgan and ST Services. We believe the claims against ST Services are without merit, and intend to vigorously defend against them.
We are involved in various other regulatory disputes, litigation and claims arising out of our operations in the normal course of business. However, we are not currently a party to any legal or regulatory proceedings, the resolution of which we could expect to have a material adverse effect on our business, consolidated financial condition, liquidity or results of operations.
ITEM 4.
ITEM 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of our unitholders during the fourth quarter of 2005.
Part II
ITEM 5.
ITEM 5. Market Price for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Our common units are listed on the New York Stock Exchange under the symbol "PPX." At the close of business on December 31, 2005, we had 210 holders of record of our common units, representing approximately 22,000 beneficial owners. The high and low sales price ranges per common unit, as reported on the New York Stock Exchange, and the amount of distributions declared by quarter for the years ended December 31, 2005 and 2004 are as follows:
(1)Distributions declared associated with each respective quarter. For equity compensation plan information, see "Item 12 - Security Ownership of Beneficial Owners and Management and Related Unitholder Matters."
We are party to credit agreements and indentures governing our senior notes which contain certain financial covenants that may restrict our ability to make distributions to our unitholders. For a discussion regarding our credit agreements and senior notes, see "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations-Credit Facilities and Long-term Debt Incurred in 2005."
Distributions of Available Cash
General. Within 45 days after the end of each quarter, we will distribute all of our available cash, if any, to unitholders of record on the applicable record date.
Definition of Available Cash. Available cash generally means, for each fiscal quarter:
•all cash on hand at the end of the quarter; less
•the amount of cash reserves that our General Partner determines in its reasonable discretion is necessary or appropriate to:
•provide for the proper conduct of our business;
•comply with applicable law, any of our debt instruments or other agreements; and
•provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters; plus
•all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are
generally borrowings that are made under our credit facilities and in all cases are used solely for working capital purposes or to pay distributions to partners.
Intent to Distribute Minimum Quarterly Distribution. We intend to distribute to holders of common units and subordinated units on a quarterly basis at least a minimum quarterly distribution of $0.4625 per unit per quarter, or $1.85 per unit per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter and we are prohibited from making any distribution to unitholders if it would cause an event of default, or if an event of default is existing, under our revolving credit facility or pursuant to the indenture for our senior notes.
Operating Surplus, Capital Surplus and Adjusted Operating Surplus
General. All cash distributed to unitholders will be characterized as either operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus.
Definition of Operating Surplus. For any period, operating surplus generally means:
•our cash balance on July 26, 2002, the closing date of our initial public offering; plus
•$15.0 million (as described below); plus
•all of our cash receipts since the closing of our initial public offering, excluding cash from borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus
•working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for that quarter; less
•all of our operating expenses since the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less
•the amount of cash reserves that our General Partner deems necessary or advisable to provide funds for future operating expenditures.
Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.
Adjusted operating surplus for any period generally means:
•operating surplus generated with respect to that period; less
•any net increase in working capital borrowings with respect to that period; less
•any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
•any net decrease in working capital borrowings with respect to that period; plus
•any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
Definition of Capital Surplus. Capital surplus will generally be generated only by:
•borrowings other than working capital borrowings;
•sales of debt and equity securities; and
•sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
Characterizations of Cash Distributions. We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $15.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather this amount permits us, if we choose, to make limited distributions of cash from non-operating sources, such as asset sales, issuances of securities and long-term borrowings, which would otherwise be considered distributions of capital surplus. Any distributions of capital surplus would trigger certain adjustment provisions in our partnership agreement. We do not anticipate making any distributions from capital surplus.
Subordination Period
General. During the subordination period, the common units are entitled to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.4625 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, to the extent we have sufficient cash from our operations after payment of fees and expenses, including payments to our General Partner and establishment of cash reserves, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
Definition of Subordination Period. The subordination period will generally expire on the first day of any quarter beginning after June 30, 2007, that each of the following tests are met:
•distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis plus the related distribution on the 2% general partner interest during those periods; and
•there are no arrearages in payment of the minimum quarterly distribution on the common units.
Early Conversion of Subordination Units. On August 12, 2005, 25% of the then outstanding subordinated units (2,616,250 units) were converted to common units in accordance with the terms of our partnership agreement. Prior to the end of the subordination period, one-third of the remaining subordinated units, or an additional 2,616,250 subordinated units, may convert into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after June 30, 2006.
The early conversion will occur if, at the end of the applicable quarter, each of the following three tests are met:
•distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
•the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis plus the related distribution on the 2% general partner interest during those periods; and
•there are no arrearages in payment of the minimum quarterly distribution on the common units.
In addition, if the unitholders remove our General Partner other than for cause and units held by our General Partner and its affiliates are not voted in favor of that removal:
•the subordination period will end and each outstanding subordinated unit will immediately convert into one common unit;
•any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
•our General Partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
Effect of Expiration of the Subordination Period. Upon expiration of the subordination period, each outstanding subordinated unit will automatically convert into one common unit and will then participate, pro rata, with the other common units in any distributions of available cash.
Distributions of Available Cash from Operating Surplus During the Subordination Period
We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
•First, 98% to the common unitholders, pro rata, and 2% to our General Partner, until we have distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
•Second, 98% to the common unitholders, pro rata, and 2% to our General Partner, until we have distributed for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
•Third, 98% to the subordinated unitholders, pro rata, and 2% to our General Partner, until we have distributed for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
•Thereafter, in the manner described in "Incentive Distribution Rights" below.
Distributions of Available Cash from Operating Surplus After the Subordination Period
We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
•First, 98% to all unitholders, pro rata, and 2% to our General Partner, until we have distributed for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
•Thereafter, in the manner described in "Incentive Distribution Rights" below.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus, up to 48%, after the minimum quarterly distribution and the target distribution levels have been achieved. Our General Partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.
If for any quarter:
•we have distributed available cash from operating surplus on each common unit and subordinated unit in an amount equal to the minimum quarterly distribution; and
•we have distributed available cash from operating surplus on each outstanding common unit in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders, our General Partner and the holders of the incentive distribution rights (if other than our General Partner) in the following manner:
•First, 98% to all unitholders, pro rata, and 2% to our General Partner, until each unitholder has received a total of $0.5125 per unit for that quarter (the "first target distribution");
•Second, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to our General Partner, until each unitholder has received a total of $0.5875 per unit for that quarter (the "second target distribution");
•Third, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to our General Partner, until each unitholder has received a total of $0.7000 per unit for that quarter (the "third target distribution"); and
•Thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to our General Partner.
In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution.
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our General Partner up to the various target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our General Partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Target Amount," until available cash we distribute reaches the next target distribution level, if any. The
percentage interests shown for the unitholders and our General Partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests shown for our General Partner include its 2% general partner interest and assume that our General Partner has not transferred the incentive distribution rights.
In January 2006, the Partnership declared a cash distribution of $0.555 per limited partner unit for the fourth quarter of 2005, which was paid on February 14, 2006 to unitholders of record as of January 31, 2006. The fourth quarter 2005 distribution was the first quarterly distribution that exceeded $0.5125 per limited partner unit and, accordingly, the General Partner received an incentive distribution of approximately $255,000 in addition to its 2% interest distribution.
ITEM 6.
ITEM 6. Selected Financial Data
General
The following table shows selected financial and operating data of Pacific Energy Partners, L.P. (the "Partnership"), the successor to Pacific Energy and subsidiaries (Predecessor) (as defined below) for the periods and as of the dates indicated. The data consists of the consolidated financial and operating data of the Partnership and its 100% ownership interest in Pacific Energy Group LLC ("PEG") and PEG Canada GP LLC. PEG's subsidiaries consist of:
(i)Pacific Pipeline System LLC ("PPS"), owner of Line 2000 and the Line 63 system;
(ii)Pacific Terminals LLC ("PT"), owner of the Pacific Terminals storage and distribution system acquired on July 31, 2003;
(iii)Pacific Atlantic Terminals ("PAT"), which was formed for the purpose of acquiring the California and East Coast terminal assets we purchased on September 30, 2005 (see "Item 7
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion of the financial condition and results of operations of Pacific Energy Partners, L.P. should be read together with the consolidated financial statements and the notes thereto set forth elsewhere in this report. The discussion set forth in this section pertains to our consolidated financial position, statements of income, statements of cash flows and statement of partners' capital.
The financial data included herein reflects (i) the ownership and results of operations of the assets comprising the Pacific Terminals ("PT") storage and distribution system for the period from July 31, 2003; (ii) the ownership and results of operations of the Rangeland system for the period from May 11, 2004; (iii) the ownership of the MAPL pipeline for the period from June 30, 2004; and (iv) the ownership of the Pacific Atlantic Terminals and Rocky Mountain Products Pipeline assets for the period from September 30, 2005. Each of these acquisitions closed on the date indicated.
Overview
We are a publicly traded partnership engaged principally in the business of gathering, transporting, storing, and distributing crude oil, refined products and other related products. We generate revenue primarily by transporting such commodities on our pipelines, by leasing capacity in our storage tanks, and by providing other terminaling services. We also buy and sell crude oil, activities that are generally complementary to our other crude oil operations. We conduct our business through two business units, the West Coast Business Unit, which includes activities in California and the Philadelphia, Pennsylvania area, and the Rocky Mountain Business Unit, which includes activities in five Rocky Mountain states and Alberta, Canada.
We are managed by our general partner, Pacific Energy GP, LP, which is in turn managed by its general partner, Pacific Energy Management LLC. See "Significant Developments in 2005" below. References to our "General Partner" refer to Pacific Energy GP, Inc. prior to March 3, 2005, and from and after March 3, 2005 to Pacific Energy GP, LP and/or Pacific Energy Management LLC, the general partner of Pacific Energy GP, LP, as appropriate.
Our West Coast Business Unit consists of (i) Line 2000, (ii) the Line 63 system, (iii) the Pacific Terminals storage and distribution system, (v) the PMT gathering system and crude oil marketing activities, and (iv) Pacific Atlantic Terminals, which was acquired on September 30, 2005 (see "Significant Developments in 2005-Acquisition of Assets from Valero, L.P."). Line 2000 and Line 63 are the only common carrier pipelines delivering crude oil produced in the San Joaquin Valley and the two primary California Outer Continental Shelf producing fields, Point Arguello and Santa Ynez, to the Los Angeles Basin and Bakersfield. The Pacific Terminals storage and distribution system is a crude oil and dark products storage and pipeline distribution system servicing the Los Angeles Basin, and the PMT gathering system is a proprietary gathering operation in the San Joaquin Valley. We have integrated the recently acquired San Francisco area terminals and Philadelphia area terminals ("Pacific Atlantic Terminals") with our existing West Coast Business Unit, and we are currently seeking permits for the development of a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles ("POLA").
Our Rocky Mountain Business Unit consists of (i) the Rangeland system, (ii) certain undivided interests in the Western Corridor system, (iii) the Salt Lake City Core system, (iv) our interest in Frontier Pipeline Company, and (v) the Rocky Mountain Products Pipeline, which was acquired on September 30, 2005 (See "Significant Developments in 2005-Acquisition of Assets from Valero, L.P.). Our Rocky Mountain crude oil pipeline systems transport crude oil produced in Canada and the U.S. Rocky Mountain region to refineries in Montana, Wyoming, Colorado and Utah. Deliveries are also made to the refining and marketing center of Edmonton, Alberta through our Rangeland system. Deliveries of crude oil are made to refineries directly through our pipelines or indirectly through
connections with third-party pipelines. The Rocky Mountain Products Pipeline supplies refined products to the South Dakota, Wyoming and Colorado markets.
Cash Distributions
Our principal business objective is to generate stable and increasing cash flows by being a leading provider of pipeline transportation and other midstream services to the North American energy industry. We seek to achieve our objective by executing the following strategies:
•Use our strategic position in our core market areas to maximize throughput on our pipelines and utilization of our storage and terminaling facilities.
•Control our operating and capital costs while maintaining the safety and operational integrity of our assets.
•Pursue strategic and accretive acquisitions and new projects that enhance and expand our core business.
•Minimize our exposure to commodity price volatility.
Our ability to execute this acquisition and development strategy successfully is dependent on the price we pay for the acquisitions and the cost of development relative to the future cash flows the new assets generate.
Our cash distributions to unitholders may vary over time with the cash flow from our operating activities. Our operating cash flow is impacted by the revenue and cost variables described below. Our cash distributions may also vary over time with the level of sustaining capital expenditures. These expenditures are required to replace partially or fully depreciated assets in order to maintain the existing operating capacity or efficiency of our assets and extend their useful lives.
During the subordination period, which will generally not expire until after June 30, 2007, subject to early termination under certain conditions, the common units are entitled to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.4625 per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, to the extent we have sufficient cash from our operations after payment of fees and expenses, including payments to our General Partner and establishment of cash reserves, before any distributions of available cash from operating surplus may be made on the subordinated units. The existence of the subordinated units increases the likelihood that during the subordination period there will be available cash to distribute the minimum quarterly distribution to the holders of the common units. See "Item 5 - Market Price for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities" regarding subordinated units and the subordination period.
Significant Developments in 2005
Acquisition of Assets from Valero, L.P.
On September 30, 2005, we completed the purchase of certain terminal and pipeline assets (the "Valero Acquisition") from Support Terminals Operating Partnership, L.P., Kaneb Pipe Line Operating Partnership, L.P. and Shore Terminals LLC (the "Sellers") for an aggregate purchase price of $455.0 million, plus $11.5 million for the assumption of certain environmental and operating liabilities and $3.7 million for closing costs. Valero, L.P. was required to divest these assets pursuant to an order from the Federal Trade Commission in connection with its acquisition of the Kaneb group of companies. The purchased assets consist of (i) the Martinez terminal and Richmond terminal in the San Francisco, California area, (ii) the North Philadelphia and South Philadelphia terminals and the
Paulsboro, New Jersey terminal in the Philadelphia, Pennsylvania area, and (iii) a 550-mile refined products pipeline with four terminals in the U.S. Rocky Mountains (collectively the "Valero Assets").
The Martinez and Richmond terminals currently have 4.1 million barrels of combined storage capacity. The terminals handle refined products, blend stocks and crude oil, and are connected to a network of owned and third-party pipelines that carry crude oil and light products to and from area refineries. These terminals also receive and deliver crude oil and light products by marine vessel or barge. The Richmond terminal has a rail spur for delivery and receipt of light products and a truck rack for product delivery.
The North Philadelphia, South Philadelphia and Paulsboro, New Jersey terminals handle refined products and have a combined storage capacity of 3.1 million barrels. The terminals receive product via connections to third-party pipelines and have truck racks for deliveries. The North Philadelphia and Paulsboro terminals can also deliver and receive products by marine vessel or barge.
The Rocky Mountain Products Pipeline, formerly known as the West Pipeline System, consists of 550 miles of pipeline extending from Casper, Wyoming east to Rapid City, South Dakota and south to Colorado Springs, Colorado. There are products terminals at Rapid City, South Dakota, Cheyenne, Wyoming and Denver and Colorado Springs, Colorado with a combined storage capacity of 1.7 million barrels. The pipeline system has various segments with different receipt and delivery points.
We have integrated the operations, maintenance, marketing and business development of the Rocky Mountain Products Pipeline with our existing pipeline activities in the Rocky Mountain Business Unit. Similarly, we have integrated the San Francisco area and Philadelphia area terminals with our existing pipeline and terminal activities in our West Coast Business Unit.
We funded the Valero Acquisition through a combination of proceeds from a private placement of 4.3 million common units, a public equity offering of 5.2 million common units, a private placement of $175.0 million of senior unsecured notes, and borrowings under our new revolving credit facility (see below for a discussion of these new financing arrangements).
Equity and Debt Offerings
On September 14, 2005, we sold 4,550,000 common units at a public offering price of $32.00 per unit. On September 16, 2005, the underwriters exercised their over-allotment option and purchased an additional 682,500 common units at the same price. Net proceeds from the offering and exercise of the underwriters option, including the General Partner's contribution of $3.4 million, totaled approximately $163.2 million after deducting underwriting fees and offering expenses of $7.6 million. We used net proceeds from the equity offering to partially fund the Valero Acquisition.
On September 23, 2005, we completed the sale of $175.0 million of 61/4% senior unsecured notes due September 15, 2015. The notes were sold in a private offering to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933 ("Securities Act") and to non-U.S. persons under Regulation S of the Securities Act of 1933. The notes were sold for 99.544% of face value resulting in an effective interest rate of 6.3125% to maturity. Net proceeds of $170.9 million from the sale of the notes, after deducting $0.8 million discount and offering expenses of $3.3 million, were used to partially fund the Valero Acquisition. In January 2006, the notes were exchanged for new notes with materially identical terms that have been registered under the Securities Act but are not listed on any securities exchange.
On September 30, 2005, we sold 4,300,000 units pursuant to a Common Unit Purchase Agreement with certain institutional investors at a price of $30.75 per unit. We received net proceeds of $131.8 million from the sale of the common units, including the General Partner's contribution of $2.7 million, which were used to partially fund the Valero Acquisition. We filed a registration statement
in December 2005 with the Securities and Exchange Commission ("SEC") which allows for the resale by the investors from time to time of the privately placed common units.
New Revolving Credit Facility
On September 30, 2005, we entered into a new five-year $400 million senior secured revolving credit facility (the "New Credit Facility") that replaced our previous U.S. and Canadian revolving credit facilities. The New Credit Facility is available for general partnership purposes in the U.S. and Canada, including working capital, letters of credit and distributions to unitholders (subject to certain limitations). The New Credit Facility matures on September 30, 2010, and we may prepay all loans under the New Credit Facility without premium or penalty. Obligations under the New Credit Facility are guaranteed by all of our subsidiaries except those for which regulatory approval is required and are secured by substantially all of our assets, excluding property held by the non-guaranteeing subsidiaries. The New Credit Facility is recourse to us and the guarantors, but non-recourse to our General Partner.
Included in the New Credit Facility is a Canadian sub-facility. The Canadian sub-facility currently has a limit of U.S.$100 million, but can be adjusted from time to time by us. The Canadian sub-facility includes an option for us to receive loans in either U.S. dollars or Canadian dollars.
Purchase of Crude Oil and Contracts
On July 1, 2005, we through our Pacific Marketing and Transportation ("PMT") subsidiary purchased certain crude oil contracts and crude oil inventories for approximately $3.8 million plus contingent payments to be measured over the period from July 1, 2005 through December 31, 2008 based on specified performance criteria.
Line 63 Crude Oil Release
On March 23, 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63 when it was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. We expect to incur an estimated total of $25.6 million for oil containment and clean-up of the impacted areas, future monitoring costs, potential third-party claims and penalties, and other costs, excluding pipeline repair costs. As of December 31, 2005, we had incurred approximately $19 million of the total expected costs related to the oil release for work performed through that date. We estimate that $4.4 million of the remaining costs will be incurred in 2006 and $2.2 million will be incurred in 2007.
We have a pollution liability insurance policy with a $2.0 million deductible that covers containment and clean up costs, third-party claims and penalties. The insurance carrier has, subject to the terms of the insurance policy, acknowledged coverage of the incident and is processing and paying invoices related to the clean-up. Although we believe we are entitled, subject to the $2.0 million deductible, to recover substantially all of our clean-up costs and third-party claims associated with the release, we can make no assurance that this will be the case. As of December 31, 2005, we have recovered $12.3 million from the insurance carrier and recorded receivables of $11.3 million for insurance recoveries we deem probable, of which $2.2 million is considered long-term. As new information becomes available in future periods, our initial estimates of costs and recoveries may change.
We recorded $2.0 million in net costs in "Line 63 oil release costs" in the accompanying consolidated statements of income for the year ended December 31, 2005. The $2.0 million net oil release costs reflects the per-occurrence deductible under that coverage and consists of $25.6 million of total anticipated costs relating to the release, less insurance recoveries and accrued insurance receipts.
During the time the pipeline was out of service, we transferred significant volumes of light crude oil, on a temporary basis, from Line 63 to Line 2000, to mitigate the impact on customers and limit the potential loss of revenue. We also asked our customers to shift volumes of Outer Continental Shelf crude oil from Line 63 to Line 2000. The permanent repair of Line 63 was completed in October 2005. We expensed $0.7 million, all in the second quarter, for the repair of Line 63 and incurred $2.2 million of Line 63 capital improvements in the third and fourth quarters of 2005.
Effective August 1, 2005, with the approval of the California Public Utilities Commission (the "CPUC"), we began collecting a temporary surcharge of $0.10 per barrel on our Line 63 long-haul tariff rates to recover our uninsured costs relating to this release together with costs incurred or to be incurred as a result of other problems caused to Line 63 by rain-related earth movement and stream erosion during the 2004-2005 winter. We were required under the terms of the CPUC decision that approved the collection of the surcharge to substantiate in a subsequent advice letter filing with the CPUC that the actual costs incurred by us were necessary and reasonable and otherwise recoverable. PPS filed its advice letter filing on January 27, 2006, which was approved by the CPUC on February 22, 2006.
Sale of The Anschutz Corporation's Interest in Us
On March 3, 2005, The Anschutz Corporation completed the sale of its interest in us to LB Pacific, LP ("LBP"), an entity formed by Lehman Brothers Merchant Banking Group ("LBMB"). The acquisition by LBP (the "LB Acquisition") included the purchase of a 100% ownership interest in Pacific Energy GP, Inc. (predecessor of Pacific Energy GP, LP), which owned (i) a 2% general partner interest in us and the incentive distribution rights, and (ii) 10,465,000 subordinated units of the Partnership. Immediately prior to the closing of the LB Acquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, a Delaware limited liability company; and immediately after the closing of the LB Acquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP, a Delaware limited partnership. The general partner of Pacific Energy GP, LP is Pacific Energy Management LLC, a Delaware limited liability company, which is owned by LBP. Immediately following the closing of the LB Acquisition, our General Partner distributed the 10,465,000 subordinated units of the Partnership to LBP.
In connection with the conversion of our general partner to a limited partnership, our general partner ceased to have a board of directors, and is now managed by its general partner, Pacific Energy Management LLC, a Delaware limited liability company ("PEM"), which is 100% owned by LBP. PEM has a board of directors (the "Board of Directors" or "Board") that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of our General Partner and the Partnership. For further discussion of the Board of Directors, see "Item 10 - Directors and Executive Officers". All of the officers and employees of our general partner were transferred to fill the same positions with PEM, and the PEM Board established the same committees as had been maintained by Pacific Energy GP, Inc. prior to the LB Acquisition. PEM also adopted Pacific Energy GP, Inc.'s governance guidelines and its compensation structure and employee benefits plans and policies.
Pursuant to an Ancillary Agreement entered into in connection with the LB Acquisition, LBP and The Anschutz Corporation reimbursed us $2.4 million, which represents the cost incurred by us in connection with a consent solicitation prepared and delivered to the holders of our 71/8% senior notes, due 2014 to approve certain amendments to the governing indenture, and for severance and other costs incurred in connection with the sale of our General Partner. In accordance with generally accepted accounting principles we recorded $0.6 million of the costs as capitalized deferred financing costs and $1.8 million as an expense. The reimbursements were recorded as the General Partner's capital contribution.
Additionally, in connection with the change in control of our General Partner, all restricted units outstanding under the Long-Term Incentive Plan immediately vested pursuant to the terms of the grants. As a result, we issued 99,583 common units and recorded a compensation expense of $3.1 million.
Business Fundamentals
Pipeline Transportation
We generate pipeline transportation revenue by charging tariff rates for transporting crude oil and refined products on our common carrier pipelines. The fundamental items impacting our pipeline transportation revenue are the volume of crude oil and refined products, or throughput, we transport on our pipelines, and our tariff rates. Throughput on our pipelines fluctuates based on the volume of crude oil and refined products available for transportation on our pipelines, the demand for such products, refinery downtime, the availability of alternate sources of crude oil for the refineries we serve and the availability of refined products from other sources.
Our shippers determine the amount of crude oil and refined products we transport on our pipelines, but we can influence these volumes through the level and type of service we provide and the rates we charge. Our rates need to be competitive to transportation alternatives, which are mostly other pipelines.
The tariff rates we charge on Line 2000 and the Line 63 system are regulated by the CPUC. Tariffs on Line 2000 are established based on market considerations, subject to certain contractual limitations. Tariffs on Line 63, which are cost-of-service based tariffs, are based upon the costs to operate and maintain the pipeline, as well as charges for the depreciation of the capital investment in the pipeline and the authorized rate of return. The tariff rates charged on our U.S. Rocky Mountain crude oil pipelines are regulated by either the FERC or the Wyoming Public Service Commission, generally under a cost-of-service approach. The FERC, Wyoming PSC, and the Colorado PUC each regulate various tariffs on the Rocky Mountain Products Pipeline.
Although the tariff rates we charge on the system are regulated, competitive forces may also limit the amount of our filed rates. The FERC tariff rates are generally adjusted, effective July 1 of each year, by the amount of change in the Producer Price Index for Finished Goods.
Following are recent tariff rate increases on our pipelines:
•Effective August 1, 2005, we implemented a temporary surcharge of $0.10 per barrel on our Line 63 long-haul tariff rates to recover our costs relating to the oil release (see "Line 63 Crude Oil Release" above) together with other costs incurred or to be incurred as a result of rain-related earth movement and stream erosion.
•On July 1, 2005, we increased the FERC tariff rates on our U.S. Rocky Mountain crude oil pipelines by 3.6% based on the FERC index adjustment.
•On May 1, 2005 we increased the tariff rates on our Line 2000 by approximately 4.8%.
•Effective November 1, 2004, we increased the tariff rates on our Line 63 system by 9.5%. This increase was the first for Line 63 since 2001.
These tariff rate increases on our West Coast pipelines partially mitigate the impact of declining throughput.
The availability of crude oil for transportation on our pipelines is dependent, in part, on the amount of drilling and enhanced recovery activity in the production fields we serve in our West Coast operations and in parts of our Rocky Mountain operations. With the passage of time, production of crude oil in an individual well naturally declines, which can, in the short term, be offset in whole or in
part, by additional drilling or the implementation of recovery enhancement measures. In the San Joaquin Valley and in the California Outer Continental Shelf, total production is generally declining.
In the Rocky Mountains, our pipelines are connected to Canadian sources of crude oil, and in 2004 we completed the acquisition of the Rangeland system in Alberta, giving us greater access to significant supplies of Canadian crude oil, including synthetic crude oil, which we believe will replace any long term U.S. Rocky Mountain production declines and meet growing demand in the U.S. Rocky Mountain region. Our initiating pump station in Edmonton, as well as a connection to a third-party pipeline providing access to synthetic crude oil, was completed in March 2006. It appears in recent months that production in the U.S. Rocky Mountains may be increasing with the increased amount of natural gas related drilling, which results in increased volumes of crude oil and condensate. We believe, however, that the longer term production of crude oil in the U.S. Rocky Mountains will resume its historical decline.
The Rocky Mountain Products Pipeline (formerly the West Pipeline System) acquired from Valero in 2005 is a common carrier petroleum products pipeline and terminals network. The system generates revenues through transportation tariffs for volumes of petroleum products it ships. These tariffs vary depending upon where the product originates and, where ultimate delivery occurs. All transportation rates are market-based rates or published tariffs filed with the FERC and other state agencies. The products terminals on the pipeline system also earn revenues by providing additional services.
Storage and Terminaling
We provide storage and terminaling services to refineries in the Los Angeles Basin and San Francisco areas in California and in the Philadelphia, Pennsylvania area. The fundamental items impacting our storage and terminaling revenue are the amount of storage capacity we have under lease, the lease rates for that capacity and the length of each lease.
Demand for crude oil storage capacity tends to be more stable over time and leases for crude oil storage capacity are usually long term (more than one year). Demand for storage capacity for other dark products is less stable than for crude oil storage and varies depending on, among other things, refinery production runs and maintenance activities. Leases for other dark products storage capacity are usually short term (less that one year). One of our business goals is to convert a number of dark products tanks to more flexible crude oil service (which can also accommodate other dark products); we are currently completing one such tank conversion. While PT's rates are subject to regulation by the CPUC, the CPUC has allowed PT to establish rates based on market conditions through negotiated contracts.
The Martinez, Richmond, Paulsboro and Philadelphia terminals that we purchased from Valero are refined product (and, in the case of Martinez, crude oil) storage and terminaling facilities that generate revenues primarily from fees that we charge customers for storage, throughput and other services. Demand for refined products storage capacity, mostly at the Philadelphia area terminals, depends on connections with refineries and petroleum products pipelines owned and operated by third parties.
Demand for refined products storage at our San Francisco area terminals tends to be stable over time as most of their lease contracts are evergreen contracts for a year or more. Additionally, the San Francisco area terminals are not overly reliant on local area refinery production to satisfy their supply of refined products. The San Francisco area terminals receive a significant amount of their supplies from imported refined products into the San Francisco harbor. The Martinez terminal is permitted for an additional 1.3 million barrels of storage capacity and one of our goals is to increase its storage capacity. We have begun construction of three 150,000 barrel tanks which we expect to place in service in July 2006.
The throughput service business of our Philadelphia area terminals, which receive products from local refineries, the U.S. Gulf Coast and New York Harbor is dependent on the demand for gasoline and other products in the Philadelphia market. In addition, our Philadelphia area terminals provide storage services for local refineries and other marketers.
Pipeline Buy/Sell Transportation
Throughput on our Rangeland system, which was acquired in the second quarter of 2004 and which includes the Rangeland and MAPL pipelines, varies with many of the same factors described in "Pipeline Transportation" above.
We are making significant changes to the revenue-generating capability of the Rangeland system by (i) combining and fully integrating all of our Canadian and U.S. Rocky Mountain pipeline assets under common management, (ii) establishing connections with other pipelines, thereby expanding the throughput capacity of the Rangeland system, and (iii) constructing a pump station and receiving terminal in Edmonton, Alberta. Following completion of our Edmonton, Alberta initiation station in March 2006, throughput will vary with our success in attracting new supplies of synthetic crude oil to our system.
The Rangeland system operates as a proprietary system and, therefore, we take title to the crude oil that is gathered and transported. Pursuant to a transportation service agreement between two of our subsidiaries, Rangeland Marketing Company ("RMC") and Rangeland Pipeline Partnership, RMC controls the entire capacity of Rangeland pipeline. Customers who wish to transport product on Rangeland pipeline must either: (i) sell product to RMC at an inlet point and repurchase such product at agreed upon delivery points for the price paid at the inlet to the pipeline plus an established location differential; or (ii) sell product to RMC at the inlet to the pipeline without repurchasing product from RMC.
Virtually all of the pipelines that comprise the Rangeland system are subject to the jurisdiction of the Alberta Energy and Utilities Board ("EUB"). A short segment of the Rangeland system that connects to the Western Corridor system at the U.S.-Canadian border is subject to the jurisdiction of the Canadian National Energy Board ("NEB"). Neither the EUB nor the NEB will generally review rates set by a crude oil pipeline operator unless it receives a complaint relating to transportation rates.
Effective December 1, 2005, we increased the location differentials on the Rangeland pipeline by an average of 6.9%.
Gathering Activities and Marketing Business
Through our Pacific Marketing and Transportation ("PMT") subsidiary, we purchase, gather, and resell crude oil, principally in California's San Joaquin Valley and in the Rocky Mountain area in the vicinity of our pipelines. In the third quarter of 2005, we began selectively purchasing and reselling crude oil in other areas as well, although this is not a primary focus.
In California, our PMT gathering system is a proprietary intrastate operation that is not regulated by the CPUC or the FERC. It is complementary to our pipeline transportation business. The California gathering network effectively extends our pipeline network to capture supplies of crude oil bound for transportation to Los Angeles that might not otherwise be shipped through our pipelines. In the U.S. and Canadian Rocky Mountain area, PMT facilitates transportation on our Canadian and U.S. Rocky Mountain pipelines by purchasing crude oil from Canada for resale in Rocky Mountain marketplaces.
The contribution of our PMT gathering operations is, for several reasons, a variable part of our income. First, it varies with the price differential between the cost of the varying grades of crude oil that PMT buys for use in its gathering operations, and the price of the crude oil it sells. Costs and sales prices are generally impacted by crude oil prices, as well as by local supply and demand forces,
including regulations affecting refined product specifications. Second, it varies with the price differential between crude oil purchased on one price basis and sold on another price basis. Finally, it varies with the volumes gathered. We seek to control these variations through our risk management policy, which provides specific guidelines for our crude oil marketing and hedging activities and requires oversight by our senior management.
Acquisitions and New Projects
We intend to continue to pursue acquisitions and new projects for development of additional midstream assets, including pipeline, storage and terminal facilities. In 2006, we have a $106 million expansion capital budget as detailed in "Liquidity and Capital Resources-Capital Requirements" below. We also intend to expand, principally by acquisition, into the natural gas storage and transportation businesses. We expect the acquisitions and new projects will be accretive to our cash flow and complement our existing business. We expect to fund acquisitions and new projects with a combination of debt and additional Partnership units, including common units. We expect to maintain a debt to total capitalization ratio of approximately 50 percent over time.
Operating Expenses
Many of our operating expenses, including the cost of field and support personnel, maintenance, control systems, telecommunications, rights-of-way and insurance, are relatively fixed and vary little with changes in throughput. Certain of our costs, however, do vary with throughput, the most material being the cost of power used to operate pump stations along our pipelines. Major maintenance costs can vary depending on a particular asset's age and also with regulatory requirements, such as mandatory inspections at defined intervals. Unanticipated costs can include the costs of cleanup of any oil or product release to the extent they are not covered by insurance, and repairs caused by severe weather as we experienced in California and Alberta, Canada in 2005.
We do not have any employees, except in Canada. Our General Partner provides employees to conduct our U.S. operations. We and our General Partner collectively employ approximately 440 individuals who directly support our operations. We consider employee relations to be good. None of these employees are subject to a collective bargaining agreement, except for eight employees at our Paulsboro, New Jersey, terminal, who are members of USW District 10-286 (Steel Workers), with whom we have a collective bargaining agreement that will end on October 1, 2009. Our General Partner does not conduct any business other than with respect to the Partnership. All expenses incurred by our General Partner are charged to us.
Impact of Foreign Exchange Rates
Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of each reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. The reported cash flow of our Canadian operations is based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. The results of our Canadian operations and distributions from our Canadian subsidiaries to the Partnership may vary in U.S. dollar terms based on fluctuations in currency exchange rates irrespective of our Canadian subsidiaries' underlying operating results. In addition, the amount of monies we repatriate from Canada will vary with fluctuations in currency exchange rates and may impact the cash available for distribution to our unitholders. We have entered into certain foreign exchange contracts to mitigate currency exchange risks (see "Item 7A
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk, interest rate risk and currency exchange risk. We use derivative financial instruments to reduce our exposure to adverse fluctuations in
commodity prices, interest rates and foreign exchange rates. We formally designate and document the financial instruments as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transactions. We formally assesses, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposure. All of our derivatives are commonly used over-the-counter instruments with liquid markets or are traded on the New York Mercantile Exchange. We do not enter into derivative financial instruments for trading or speculative purposes.
Commodity Price Risk Hedging
We may use derivatives, principally futures and options, to hedge our exposure to market price volatility related to our inventory or future sales of crude oil. Derivatives used to hedge market price volatility related to inventory are generally designated as fair value hedges, and derivatives related to future sale of crude oil are generally classified as cash flow hedges. Derivative instruments are included in "Other assets" in the accompanying consolidated balance sheets.
Changes in the fair value of our derivative instruments related to crude oil inventory are recognized in net income. For the years ended December 31, 2005, 2004 and 2003, "crude oil sales, net of purchases" were net of $0.8 million, $2.7 million and $0.3 million in losses, respectively, reflecting changes in the fair value of derivative instruments held as hedges related to crude oil marketing activities. Losses on derivatives were generally offset by gains in physical crude oil inventory positions. Changes in the fair value of our derivative instruments related to the future sale of crude oil are deferred and reflected in "accumulated other comprehensive income," a component of partners' capital in the balance sheet, until the related revenue is reflected in the consolidated statements of income. As of December 31, 2005, a $0.1 million loss relating to the change in the fair value of highly effective derivative instruments was included in "accumulated other comprehensive income" and is expected to be reclassified to earnings in 2006. Since these amounts are based on market prices at December 31, 2005, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.
Interest Rate Risk Hedging
In connection with the issuance of our 71/8% senior notes due 2014, we entered into interest rate swap agreements with an aggregate notional principal amount of $80.0 million to receive interest at a fixed rate of 71/8% and to pay interest at an average variable rate of six month LIBOR plus 1.6681% (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 71/8% senior notes. We designated these swaps as a hedge of the change in the senior notes fair value attributable to changes in the six month LIBOR interest rate. Changes in fair values of the interest rate swaps are recorded into earnings each period. Similarly, changes in the 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. At December 31, 2005 the Partnership recorded an increase of $0.6 million in the fair value of interest rate swaps with an equal offsetting entry to the $80.0 million of senior notes. During the year ended December 31, 2005, we recognized reductions in interest expense of $1.3 million related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. As of December 31, 2005, we had an immaterial amount of ineffectiveness relating to these interest rate swaps.
We are subject to risks resulting from interest rate fluctuations as the interest cost on our credit facilities and the $80 million interest swap on the senior notes are based on variable rates. If our interest rates were to increase 1.0% in 2006 as compared to the rate at December 31, 2005, our
interest expense for 2006 would increase $2.2 million based on our outstanding debt balances at December 31, 2005.
Currency Exchange Rate Risk Hedging
The purpose of our foreign currency hedging activities is to reduce the risk that our cash inflows resulting from interest payments from our Canadian subsidiaries on intercompany debt will be adversely affected by changes in the U.S./Canadian exchange rate.
We entered into forward exchange contracts to hedge receipt of forecasted interest payments denominated in Canadian dollars. The effective portion of the change in fair value of this contract, which has been designated as a cash flow hedge, is reported in "accumulated other comprehensive income" in the accompanying balance sheet and will be reclassified into earnings in "Other income" in the same period during which the hedged transaction affects earnings. The ineffective portion, if any, of the change in fair value of this instrument will be immediately recognized in earnings. These foreign exchange contracts are as follows:
Credit Risks
By using derivative financial instruments to hedge exposures related to changes in commodity prices, interest rates and currency exchange rates, we expose ourselves to market risk and credit risk. Market risk is the risk of loss arising from the adverse effect on the value of a financial instrument that results from changes in commodity prices, interest rates or currency exchange rates. The market risk associated with price volatility is managed by established parameters that limit the types and degree of market risk that may be undertaken.
Credit risk is the risk of loss arising from the failure of the derivative agreement counterparty to perform under the terms of the derivative agreement. When the fair value of a derivative agreement is positive, the counterparty is liable to us, which creates credit risk for us. When the fair value of a derivative agreement is negative, we are liable to the counterparty and, therefore, it creates credit risk for the counterparty. The counterparties we transact with are large, well known companies in the industry or large creditworthy financial institutions. As such, we believe our exposure to counterparty credit risk is low. Nonetheless, there can be no assurance as to the performance of a counterparty.
Fair Value of Financial Instruments
The carrying amount and fair values of financial instruments are as follows:
The carrying amount of derivative financial instruments represents fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. The Partnership's fair values of crude oil hedging futures are based on Reuters quoted market prices on the NYMEX. Interest rate swaps and foreign exchange contracts fair values are based on the prevailing market price at which the positions could be liquidated.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
The information required here is included in this report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures
None.
ITEM 9A.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to the Partnership, including its consolidated subsidiaries, is made known to the officers who certify the Partnership's financial reports and to other members of senior management and the Board of Directors. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Based on their evaluation as of December 31, 2005, the principal executive officer and principal financial officer of the Partnership have concluded that the Partnership's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")) are effective to ensure that the information required to be disclosed by the Partnership in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
Internal Control Over Financial Reporting Statement
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined under Rule 13a-15(f) of the Exchange Act. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2005. Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included below.
Changes in Internal Controls
There has not been any change in our internal control over financial reporting that occurred during the year ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Pacific Energy Management LLC and Unitholders of
Pacific Energy Partners, L.P.:
We have audited management's assessment, included in the accompanying Internal Control Over Financial Reporting Statement, that Pacific Energy Partners, L.P. (the "Partnership") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 an opinion on management's assessment and an opinion on the effectiveness of the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that Pacific Energy Partners, L.P. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pacific Energy Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, partners' capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 10, 2006, expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Los Angeles, California
March 10, 2006
ITEM 9B.
ITEM 9B. Other Information
None.
Part III
ITEM 10.
ITEM 10. Directors and Executive Officers of the Registrant
We are managed by our general partner, Pacific Energy GP, LP, a Delaware limited partnership, which is managed by PEM, which is 100% owned by LBP. PEM has a board of directors (the "Board of Directors" or "Board") that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of Pacific Energy GP, LP and the Partnership.
The following table shows information for the directors and executive officers of PEM as of February 28, 2006.
Christopher R. Manning was elected Chairman of the Board of Directors in March 2005. Mr. Manning is a principal of LBMB and a Managing Director of Lehman Brothers. Mr. Manning joined the Natural Resources Group of Lehman Brothers in 1997 and joined LBMB in 2000. Prior to joining Lehman Brothers, Mr. Manning was Chief Financial Officer of The Wing Group, a developer of international power projects. Mr. Manning is a member of the Nominating and Governance and Compensation Committees of the Partnership. Mr. Manning is currently a director of Antero Resources Corporation and RSI Holding Corporation and holds an observer seat on the board of directors of Enduring Resources LLC.
Forrest E. Wylie was elected Vice Chairman of the Board of Directors in March 2005. Mr. Wylie was President and Chief Financial Officer of NuCoastal Corporation since May 2002. Prior to NuCoastal, Mr. Wylie served as Senior Vice President, Natural Gas Trading, for both The Coastal Corporation, and Engage Energy, a joint venture of the Coastal Corporation and West Coast Energy, and its successor, El Paso Merchant Energy from September 1997 to May 2000. Mr. Wylie also held senior positions at Transocean Sedco Forex from June 1993 to September 1997.
Joshua L. Collins was elected to the Board of Directors in March 2005. Mr. Collins is a principal of LBMB and a Managing Director of Lehman Brothers. Mr. Collins Joined LBMB in 1996.
Mr. Collins is currently a director of Blount International Inc., EverGreen Copyright Acquisitions, LLC, Enduring Resources LLC and Phoenix Brands LLC.
Timothy H. Day was elected to the Board of Directors in April 2005. Mr. Day was elected to the board of directors pursuant to the Second Amended and Restated Limited Liability Company Agreement of LB Pacific GP, LLC, and the Second Amended and Restated Limited Partnership Agreement of LB Pacific, both of which were entered into pursuant to the Purchase Agreement by and among First Reserve Pacific Holdings AIV, L.P., Lehman Sidecar I, LLC and LB I Group Inc. dated March 21, 2005. These agreements provide that so long as First Reserve Pacific Holdings AIV, L.P. holds a certain number of shares in LB Pacific GP, LLC or a certain number of units in LB Pacific, then First Reserve Pacific Holdings AIV, L.P. has the right to cause LB Pacific GP, LLC to cause LB Pacific to elect a designee to serve on the board of directors of PEM. Mr. Day is a director and vice president of First Reserve Corporation and serves on the board of directors of Chart Industries, Inc. Mr. Day joined First Reserve Corporation in 2002. Prior to joining First Reserve Corporation, Mr. Day held various positions with SCF Partners, a Houston, Texas based investment firm, from 1995 to 2000. Previously, Mr. Day served in the energy investment banking divisions of Credit Suisse First Boston and Salomon Brothers Inc.
David L. Lemmon was elected to the Board of Directors in April 2002. Mr. Lemmon served as President and Chief Executive Officer of Colonial Pipeline Company from November 1997 to January 2006 and as a director from 1990 to November 1997. He served as President of Amoco Pipeline Company from 1990 to 1997, as Manager for Corporate Planning for Amoco Corporation from 1989 to 1990 and Vice President and General Manager-Operations for Amoco Pipeline Company from 1987 to 1989. Mr. Lemmon joined Amoco in 1965. Mr. Lemmon serves as chairman of the Audit Committee and is a member of the Compensation, Conflicts and Nominating and Governance Committees.
John C. Linehan was elected to the Board of Directors in April 2004. Mr. Linehan served as the Chairman and Chief Executive Officer of Texaco Refining and Marketing (East) Inc. from September 2001 to March 2002. Prior thereto, from 1985 to 1999, Mr. Linehan held various positions at the Kerr-McGee Corporation, including Vice President, Controller, Executive Vice President and Chief Financial Officer. Mr. Linehan serves as Chairman of the Conflicts Committee and is a member of the Audit and Compensation Committees.
Douglas L. Polson was elected to the Board of Directors in December 2001, serving as Chairman from December 2001 until March 2005. He was Chairman of the Board of Directors of Pacific Energy Group LLC from August 2001 to March 2005 and Chairman of the Members Committee of Pacific Pipeline System LLC from July 1999 to April 2002. Mr. Polson served as Vice President and a director of The Anschutz Corporation and Anschutz Company for more than five years until October 2002. Mr. Polson served on the boards of directors of Southern Pacific Rail Corporation from 1988 to 1996 and Qwest Communications International, Inc. from February 1997 to 2000.
Jim E. Shamas was elected to the Board of Directors in December 2001. He served as a director of Pacific Energy Group LLC from August 2001 to March 2002 and as a representative on the Pacific Pipeline System LLC Members Committee from May 1999 to April 2002. From September 1994 until his retirement in December 1998, Mr. Shamas was President of Rooney Engineering, Inc. and Interwest Group, Inc. Mr. Shamas has served as a director of Rooney Engineering, Inc. since September 1994. Prior to that, he served as President and Chief Executive Officer of Texaco Trading and Transportation Inc. from August 1984 to August 1994. From May 1982 until August 1984, Mr. Shamas served as President and Chief Executive Officer of Getty Trading and Transportation and Vice President of Getty Oil Company. Mr. Shamas serves as Chairman of the Compensation Committee and is a member of the Audit, Conflicts and Nominating and Governance Committees.
William L. Thacker was elected to the Board of Directors in April 2004. From March 1997 until October 2002, Mr. Thacker held various positions at Texas Eastern Products Pipeline Co., LLC, which was, at the time, the general partner of TEPPCO Partners, L.P., including serving as Chairman, President and Chief Executive Officer. Mr. Thacker serves as Chairman of the Nominating and Governance Committee and is a member of the Audit and Compensation Committees. Mr. Thacker serves on the Board of Directors of Copano Energy L.L.C. and Mirant Corp.
Irvin Toole, Jr. was elected President, Chief Executive Officer and director in December 2001. He has been President, Chief Executive Officer and director of Pacific Energy Group LLC since August 2001 and has been President and Chief Executive Officer of Pacific Pipeline System LLC since July 1999 and served as a representative to its Members Committee from July 1999 to April 2002. Mr. Toole served as President and Chief Executive Officer of the predecessor of Pacific Pipeline System LLC in June 1998 after having served as Chairman, President and Chief Executive Officer of Santa Fe Pacific Pipelines, Inc., the general partner of Santa Fe Pacific Pipeline Partners, L.P., from September 1991 to April 1998.
David E. Wright was elected Executive Vice President, Corporate Development in February 2005. He has been Executive Vice President, Corporate Development and Marketing since December 2001 and served as a director of Pacific Energy GP, Inc. from December 2001 to June 2002. He has been Executive Vice President, Corporate Development and Marketing and director of Pacific Energy Group LLC since August 2001 and Executive Vice President, Corporate Development and Marketing of Pacific Pipeline System LLC since June 2001. Mr. Wright joined Pacific Energy Group LLC in June 2001 after having served as Vice President, Distribution West of Tosco Refining Company from March 1997 to June 2001. From October 1995 to March 1997, Mr. Wright served as Vice President, Pipelines for GATX Terminals Corporation.
Gerald A. Tywoniuk was elected Senior Vice President, Chief Financial Officer in December 2002. Previously, he was Senior Vice President, Chief Financial Officer and a member of the Board of Directors of the general partner of MarkWest Energy Partners, L.P. from its initial public offering in May 2002 to November 2002. He also served as Senior Vice President and Chief Financial Officer with MarkWest Hydrocarbon, Inc. from December 2001, and as a director from March 2002 to November 2002. Prior to that, Mr. Tywoniuk was MarkWest Hydrocarbon's Vice President of Finance and Chief Financial Officer since April 1997.
Lynn T. Wood was elected Vice President, General Counsel and Secretary in March 2002. He has been Vice President of Pacific Energy Group LLC since August 2001, Vice President of Pacific Pipeline System LLC and its predecessor since October 1998 and Secretary since October 1996. Mr. Wood was the Secretary and Assistant General Counsel of Anschutz Company and The Anschutz Corporation from October 1996 to October 2002, during which time he had the responsibility for providing ongoing legal services to Pacific Pipeline System LLC and, after their formation, Pacific Energy Group LLC and the Partnership.
Arthur G. Diefenbach was elected Senior Vice President, West Coast Business Unit in February 2005. He has been Vice President, Operations & Technical Services of Pacific Energy Group LLC since August 2001 and Vice President, Operations & Technical Services of Pacific Pipeline Systems LLC since July 1999. Mr. Diefenbach joined Pacific Energy Group LLC in July 1999 after having served as Manager, Western Region of ARCO Pipeline Company from August 1998 to July 1999 and as Superintendent, Operations of ARCO Pipeline Company from January 1990 to August 1998.
Gary L. Zollinger was elected Senior Vice President, Rocky Mountain Business Unit in February 2005. He has been Vice President, Marketing and Business Development-Rocky Mountains since March 2002. Mr. Zollinger joined Pacific Energy Group LLC in January 2002 after having served as President of Crossing Associates LLC from 2001 to January 2002. From 1998 to 2001, he served as Vice President of North American Consulting Group LLC. Crossing Associates LLC and North
American Consulting Group LLC are privately held consulting firms specializing in the midstream energy business. From 1997 to 1998, Mr. Zollinger did private consulting work in the mid-stream energy business.
Lyle B. Boarts was elected Vice President, Human Resources in January 2004. Previously, he was Vice President, Human Resources, GTran Inc. from March 2000 to August 2004 and was Vice President, Human Resources with Ortel Corporation from March 1998 to August 1999. Mr. Boarts also served as Vice President, Human Resources with Santa Fe Pacific Pipelines, Inc., general partner of Santa Fe Pacific Pipeline Partners, L.P., from June 1986 to March 1998.
Marilyn A. Lobel was appointed as Vice President, Corporate Controller and Chief Accounting Officer in February 2006. Previously, Ms. Lobel served as Vice President, Corporate Controller at Biolase Technology, Inc. from June 2004 through December 2005. From January 2004 through June 2004, she served as finance consultant to various publicly traded firms. From May 2002 through December 2003, she served as Director of Finance at Xoma Ltd. Prior to joining Xoma Ltd., she served as Vice President of Finance and Interim Chief Financial Officer from August 2001 through May 2002 and Vice President of Finance and Corporate Controller from January 1999 through July 2001 for Tut Systems, Inc.
The following table shows other officers of PEM as of February 28, 2006:
Stephen F. Blackwood was elected Vice President and Treasurer in September 2005. Mr. Blackwood previously served as Director of Global Treasury at Amgen Inc. and held various management positions in the Treasury group at Amgen since 1998. Prior to Amgen, Mr. Blackwood served as Vice President-Treasury at Deposit Guaranty Corp and held various positions in the treasury group since 1992.
Dominic D. Ferrari was elected Vice President, Corporate Development in August 2004. Mr. Ferrari has been with Pacific Energy since 2001, serving most recently as Senior Director, Corporate Development. Prior to joining Pacific Energy, Mr. Ferrari was with Unocal Pipeline Company from 1975 to 2001. While at Unocal, he held various positions including Vice President and Manager of Joint Ventures, Project Manager-SPR Project, and Coordinator-Joint Ventures.
John Kers was elected Vice President, Operations and Technical Services-Canada in August 2004. He previously served as Director and Vice President, Operations Engineering and Construction for Plains Marketing Canada, L.P. from 2001 to 2004. Prior to joining Plains, Mr. Kers served in progressive managerial assignments at Murphy Oil Company, Ltd from 1980 to 2001, including Manager of Engineering.
Jesse G. Metcalf was elected Vice President, Operations and Technical Services-Rocky Mountains in March 2002. From 2000 to March 2002, Mr. Metcalf served as Vice President, Anschutz Ranch East Pipeline, Anschutz Marketing and Transportation and Anschutz Wahsatch Gathering System. Prior to that, he served as Manager, Operations for Anschutz Ranch East Pipeline, Anschutz Marketing and
Transportation and Anschutz Wahsatch Gathering System from 1987 to 2000. From 1982 to 1987, Mr. Metcalf served as Field Supervisor, Exploration and Production for The Anschutz Corporation.
Khalid A. Muslih was elected Vice President-Corporate Development in March 2005. Mr. Muslih previously served as Commercial Officer, Mergers & Acquisitions of NuCoastal Corporation since July 2002. Prior to NuCoastal Corporation, Mr. Muslih served as Director, Merchant & International Regulatory Affairs with El Paso Corporation from January 2001 to June 2002 and as Director, Legislative and Regulatory Affairs for The Coastal Corporation from January 1999 to December 2000. From July 1994 to December 1998, Mr. Muslih held various positions with Coastal States Refining and Marketing, Inc. and at Coastal States Management Corporation from June 1993 to June 1994.
Edward L. Scheibelhut was elected Vice President of Marketing and Business Development-Canada in May 2004. Mr. Scheibelhut previously served as Manager, Strategic Implementation of BP Canada Energy Company from October 2002 to May 2004 and Manager of Marketing and Trading from January 2000 to October 2002. Mr. Scheibelhut served as Manager, Business Development and Planning of BP Canada Energy Company from December 1998 to January 2000.
John Tsouvalas was elected Vice President, Marketing and Business Development-West Coast in October 2003. He previously served as Director, Marketing and Business Development for Pacific Energy Group LLC's West Coast Operations from August 2001 to October 2003 and Director of Marketing and Business Development of Pacific Pipeline System LLC from July 1999 to August 2001. Mr. Tsouvalas joined Pacific Energy Group LLC in July 1999 after having served as West Coast Crude Asset Manager for ARCO Pipe Line Company from January 1996 to July 1999 and as Marketing and Scheduling Manager of ARCO Pipe Line Company West Coast from January 1990 to January 1996.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires directors, officers and persons who beneficially own more than 10% of a class of our equity securities that is registered under Section 12 of the Exchange Act to file with the SEC and the New York Stock Exchange initial reports of ownership and reports of changes in ownership of such securities. These persons are also required to furnish us copies of all of the Section 16(a) reports they filed. Based solely upon a review of the copies of reports on Forms 3, 4 and 5 furnished to us, or written representations that no reports on Form 5 were required, we believe the directors and officers of our General Partner, our General Partner in its capacity as a beneficial owner and any other persons who beneficially own more than 10% of our common units complied with all filing requirements with respect to transactions in our equity securities in 2005, except that Mr. Polson inadvertently omitted from reports filed by him on Form 4 during 2005 four sales transactions pursuant to a 10b5-1 plan, involving 100, 200, 500 and 500 of our common units, which were omitted as a result of administrative error by Mr. Polson's brokerage firm.
Director Independence
The New York Stock Exchange ("NYSE") listing standards requiring a majority of directors to be independent do not apply to publicly traded limited partnerships like the Partnership. Four directors are "independent" as that term is defined in the applicable NYSE rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, the Board has adopted certain categorical standards. PEM's independent directors as determined in accordance with those standards are: David L. Lemmon, Jim E. Shamas, John C. Linehan and William L. Thacker. The categorical standard adopted by the Board are as follows:
•A director will not be considered independent if the director is, or has been within the last three years, an employee of the Partnership or the General Partner or any of its subsidiaries, PEM, or LB Pacific or its general partner (collectively, the "Partnership Group"), or if an immediate family member of a director is, or has been within the last three years, an executive officer of
any member of the Partnership Group; provided however, that employment as an interim Chairman or Chief Executive Officer or other executive officer will not disqualify a director from being considered independent following that employment;
•A director who has received, or has an immediate family member who has received, during any twelve-month period within the last three years, more than $100,000 in direct compensation from the Partnership Group, other than director and committee fees and pension or other forms of deferred compensation for prior services (provided such compensation is not contingent in any way on continued service), will not be considered independent; provided, however, that the following need not be considered in determining independence under this test: (i) compensation received by a director for former service as an interim Chairman or Chief Executive Officer or other executive officer and (ii) compensation received by an immediate family member for service as an employee (other than an executive officer) of any member of the Partnership Group;
•A director will not be considered independent if (i) the director or an immediate family member is a current partner of a firm that is the Partnership's internal or external auditor; (ii) the director is a current employee of such a firm, (iii) the director has an immediate family member who is a current employee of such a firm and who participates in the firm's audit, assurance or tax compliance (but not tax planning) practice; or (iv) the director or an immediate family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on the Partnership's audit within that time;
•A director or immediate family member who is, or has been within the last three years, employed as an executive officer of another company where any of the present executive officers of any member of the Partnership Group at the same time serves or served on that company's compensation committee will not be considered independent; and
•A director who is a current employee, or whose immediate family member who is a current executive officer, of a company that has made payments to, or received payments from, one or more members of the Partnership Group for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company's consolidated gross revenues, will not be considered independent; provided, however, that charitable organizations will not be considered to be a company for purposes of this test.
For purposes of the above-described categorical standards, the term "immediate family member" includes a person's spouse, parents, children, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, brothers- and sisters-in-law and anyone (other than domestic employees) who shares such person's home; provided, that any such persons who no longer have any such relationship as a result of legal separation or divorce, or death or incapacitation, shall not be considered immediate family members.
Committees and Meetings
The Board of Directors has the responsibility for establishing broad policies and for our overall direction and management. The Board of Directors held four regular meetings and six special meetings during 2005. The Board has established standing committees to consider designated matters. The standing committees of the Board are Audit, Compensation, Conflicts, and Nominating and Governance.
Audit Committee
The members of the Audit Committee are: David L. Lemmon, Chairman, Jim E. Shamas, John C. Linehan and William L. Thacker. The members of the Audit Committee are not officers or employees
of our General Partner. Among other things, the Audit Committee is responsible for reviewing our external financial reporting, including reports filed with the SEC, engaging and reviewing our independent auditors, and reviewing procedures for internal auditing and the adequacy of our internal accounting controls. The Committee held six meetings during 2005.
The Board of Directors has determined that all of the members of the Audit Committee are "audit committee financial experts," as that term is defined under the Securities Act and the Exchange Act, and that each is "independent," as that term is used in the Exchange Act.
Compensation Committee
The members of the Compensation Committee are: Jim E. Shamas, Chairman, David L. Lemmon, John C. Linehan, Christopher R. Manning and William L. Thacker. The Compensation Committee is responsible for overseeing compensation related decisions for the directors, officers and employees of our General Partner. The committee held five meetings during 2005.
Conflicts Committee
The members of the Conflicts Committee are: John C. Linehan, Chairman, David L. Lemmon and Jim E. Shamas. The Conflicts Committee is responsible for reviewing specific matters, including those that the Board of Directors believes may involve conflicts of interest between our General Partner or its affiliates and the Partnership. The General Partner is authorized, but not required, to seek a determination from the Conflicts Committee as to whether a potential transaction involving a conflict of interest is fair and reasonable to us. The members of the Conflicts Committee are not officers or employees of our General Partner or its affiliates. The Committee held four meetings during 2005.
Nominating and Governance Committee
The members of the Nominating and Governance Committee are: William L. Thacker, Chairman, Douglas L. Polson, David L. Lemmon, Christopher R. Manning and Jim E. Shamas. The Nominating and Governance Committee is responsible for assisting the Board of Directors in identifying individuals qualified to become Board members, recommending nominees to Board committees, formulating and recommending guidelines for corporate governance, and leading the Board in its annual review of the Board's performance. The Committee held four meetings in 2005.
Executive Sessions
The Board of Directors holds executive sessions for the non-management directors on a regular basis without management present. Since the non-management directors include directors who are not independent directors, the independent directors also meet in separate executive session without the other directors or management at least once each year to discuss such matters as the independent directors consider appropriate. A majority of the independent directors select a presiding director for these executive sessions. In addition, any director may call for an executive session of non-management or independent directors at any Board of Directors meeting.
Communications from Unitholders, Employees and Others
Unitholders, employees and other interested persons who wish to communicate with the Board of Directors, non-management directors as a group, a committee of the Board of Directors or a specific director may do so by letters so addressed to the care of PEM's corporate secretary. Letters addressed to the Board of Directors in general will be reviewed by PEM's corporate secretary and relayed to the Chairman of the Board of Directors or the chair of an appropriate committee. Letters addressed to the non-management directors in general will be relayed unopened to the chair of the Audit Committee. Letters addressed to a committee of the Board of Directors or a specific director will be relayed
unopened to the chair of the committee or the specific director to whom they are addressed. All letters regarding accounting, accounting policies, internal accounting controls and procedures, auditing matters, financial reporting processes, or disclosure controls and procedures are to be forwarded by the recipient director to the chair of the Audit Committee.
Code of Ethics
Our General Partner has adopted a code of ethics that applies to all employees, including its principal executive officers, principal financial officer, principal accounting officer and its Board of Directors. A copy of the code of ethics is available on our Internet website at www.PacificEnergy.com, and is available in print to any holder of our units who requests it from our Investor Relations Department. Our General Partner intends to satisfy the disclosure requirement under Item 10 of the current report on Form 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics by posting such information on our website at the Internet website address set forth above.
Corporate Governance Matters
The NYSE requires the chief executive officer of each listed company to certify annually that he is not aware of any violation by the company of the NYSE corporate governance listing standards as of the date of the certification, qualifying the certification to the extent necessary. The Chief Executive Officer of the General Partner provided such certification to the NYSE in 2005 without qualification. In addition, the certifications of the General Partner's Chief Executive Officer and Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act have been included as exhibits to the Partnership's Annual Report on Form 10-K.
Reimbursement of Expenses of the General Partner
Our General Partner does not receive any management fee or other compensation for its management of the Partnership. However, our General Partner and its affiliates are reimbursed for all expenses incurred by them on our behalf. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us and all other expenses necessary or appropriate to the conduct of our business. The partnership agreement provides that our General Partner may determine the expenses that are allocable to us in any reasonable manner determined by our General Partner in its sole discretion.
ITEM 11.
ITEM 11. Executive Compensation
The following table sets forth certain information with respect to compensation of our General Partner's chief executive officer and certain other executive officers.
SUMMARY COMPENSATION TABLE
(1)Mr. Wylie became an employee of our General Partner on March 4, 2005. Mr. Wylie's current annual salary is $250,000.
(2)Mr. Polson resigned as Chairman of the Board of Directors in March 2005 but remains a director. His director fees earned subsequent to such date are excluded from this table. |
(3)Represents consulting fees of $75,000 for Mr. Polson. Includes, for Mr. Tywoniuk and Mr. Wood, reimbursement of relocation expenses, including reimbursement of associated income taxes of $33,027 and $64,612, respectively. |
(4)Calculated as follows: common units issued upon vesting (pursuant to our long-term incentive plan), multiplied by the closing market price on the day prior to issuance. |
(5)Includes for Mr. Polson $900,000 paid pursuant to his employment agreement (see "Employment Agreements-Douglas L. Polson" below) and a Special Agreement. LBP reimbursed us as described in "Employment Agreements-Douglas L. Polson" below. All other amounts reflect employer contribution to our General Partner's 401(k) plan. Option Exercises
During 2005, Mr. Polson exercised 50,000 common unit options, which had vested in 2003 and 2004, for an aggregate dollar value of $667,500 (closing market price on the day prior to exercise less
exercise price). No other individuals named in the Summary Compensation Table above hold common unit options.
Long-Term Incentive Plan Awards
2005 Grants
No common unit options were granted in 2005, and none are currently outstanding. No restricted units were granted in 2005 to the individuals named in the Summary Compensation Table above.
2006 Grants
In January 2006, our General Partner awarded restricted units to key employees that vest over a three year period, beginning on March 1, 2006, and that are also subject to meeting annual financial performance objectives. The financial measure used is the Partnership's distributable cash flow per unit, as determined by the Committee, for the calendar year preceding each of the three annual vesting dates. The number of units to be delivered in any year, if any, will be a portion of the number vested on March 1 of that year based on accomplishment of performance targets for the previous calendar year.
Depending on our actual results of distributable cash flow per unit for each of the 2005 through 2007 fiscal years, compared to pre-established targets, each participant will receive an amount of units between the threshold and maximum number. If the threshold distributable cash flow target is not met for a particular year, no units will vest. The Compensation Committee has the power to adjust the number of units vested.
Compensation of Directors
Beginning May 2003, our General Partner increased the annual rate of compensation for outside directors to $40,000, which covers attendance at meetings of the Board of Directors as well as committee meetings. The previous annual compensation was $30,000. Effective February 2006, each non-employee director who serves as audit committee chairman will receive an additional stipend of $7,500 per annum, and each other standing committee chairman will receive an additional stipend of $2,500 per annum. Our General Partner paid no director's fee to directors who were also officers or employees of The Anschutz Corporation, Lehman Brothers Holdings Inc., our General Partner or their affiliates. In 2003, three outside directors also each received a grant of 3,000 restricted units under our long-term incentive plan, which were to vest over three years. In 2004, two new outside directors each received a grant of 2,000 restricted units under our long-term incentive plan, which were to vest over two years. There were no new grants in 2005. In connection with the closing of the LB Acquisition on March 3, 2005, all of the restricted units outstanding under our long-term incentive plan vested. In January 2006, each outside director received a grant of 3,000 restricted units, which are scheduled to vest over the next three years. In addition, each director is reimbursed for his out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees. We and certain of our affiliates have agreed to fully indemnify each director for his actions associated with being a director to the fullest extent permitted under Delaware law.
Employment Agreements
Irvin Toole, Jr.
Mr. Toole entered into an employment agreement with our General Partner on January 1, 2002. The employment agreement provides for an annual base salary and an annual bonus in accordance with our General Partner's annual incentive plan. Mr. Toole is also eligible to participate in all other bonus and benefit programs for which employees and/or senior executives are generally eligible. In addition, he is reimbursed for reasonable expenses incurred in his capacity as President and Chief Executive Officer and for the cost of owning and operating a vehicle.
Under his employment agreement, our General Partner may terminate Mr. Toole's employment for cause or without cause. If Mr. Toole's employment is terminated without cause, he will, among other things, be entitled to a one-time severance payment as well as continuation of certain benefits for up to two years. If Mr. Toole is terminated without cause following a change of control or as a result of corporate downsizing, or if he resigns for "good reason," as defined in the agreement, following a change of control, he will then be entitled to substantially the same severance benefits as if he had been terminated without cause, except that the amount of the one-time severance payment will increase.
Mr. Toole's employment agreement also contains indemnification, non-solicitation and non-disclosure provisions.
David E. Wright
Mr. Wright entered into an employment agreement with our General Partner on January 1, 2002. The employment agreement provides for an annual base salary and an annual bonus in accordance with our General Partner's annual incentive plan. Mr. Wright is also eligible to participate in all other bonus and benefit programs for which employees and/or senior executives are generally eligible. In addition, he is reimbursed for reasonable expenses incurred in his capacity as Executive Vice President, Corporate Development and Marketing and for the cost of owning and operating a vehicle.
Under his employment agreement, our General Partner may terminate Mr. Wright's employment for cause or without cause. If Mr. Wright's employment is terminated without cause, he will, among other things, be entitled to a one-time severance payment. If Mr. Wright is terminated without cause following a change of control or as a result of corporate downsizing, or if he resigns for "good reason," as defined in the agreement, following a change of control, he will then be entitled to substantially the same severance benefits as if he had been terminated without cause, except that the amount of the one-time severance payment will increase, certain of his benefits will continue for up to two years and he will be entitled to receive six months of executive outplacement services.
Mr. Wright's employment agreement also contains indemnification, non-solicitation and non-disclosure provisions.
Gerald A. Tywoniuk
Mr. Tywoniuk entered into an employment agreement with our General Partner effective on November 1, 2002. The employment agreement provides for an annual base salary and an annual bonus in accordance with our General Partner's annual incentive plan. Mr. Tywoniuk is also eligible to participate in all other bonus and benefit programs for which employees and/or senior executives are generally eligible. In addition, he is reimbursed for reasonable expenses incurred in his capacity as Chief Financial Officer and for the cost of owning and operating a vehicle. Upon commencement of his employment, Mr. Tywoniuk received a one-time payment.
Under his employment agreement, our General Partner may terminate Mr. Tywoniuk's employment for cause or without cause. If Mr. Tywoniuk's employment is terminated without cause, he will, among other things, be entitled to a one-time severance payment. If Mr. Tywoniuk is terminated without cause following a change of control or as a result of corporate downsizing, or if he resigns for "good reason," as defined in the agreement, following a change of control, he will then be entitled to substantially the same severance benefits as if he had been terminated without cause, except that the amount of the one-time severance payment will increase, certain of his benefits will continue for up to one year and he will be entitled to receive three months of executive outplacement services.
Mr. Tywoniuk's employment agreement also contains indemnification, non-solicitation and non-disclosure provisions.
Lynn T. Wood
Mr. Wood entered into an employment agreement with our General Partner effective on September 5, 2002. The employment agreement provides for an annual base salary and an annual bonus in accordance with our General Partner's annual incentive plan. Mr. Wood is also eligible to participate in all other bonus and benefit programs for which employees and/or senior executives are generally eligible. In addition, he is reimbursed for reasonable expenses incurred in his capacity as Vice President, General Counsel and Secretary and for the cost of owning and operating a vehicle.
Under his employment agreement, our General Partner may terminate Mr. Wood's employment for cause or without cause. If Mr. Wood's employment is terminated without cause, he will, among other things, be entitled to a one-time severance payment. If Mr. Wood is terminated without cause following a change of control or as a result of corporate downsizing, or if he resigns for "good reason," as defined in the agreement, following a change of control, he will then be entitled to substantially the same severance benefits as if he had been terminated without cause, except that the amount of the one-time severance payment will increase, certain of his benefits will continue for up to one year and he will be entitled to receive three months of executive outplacement services.
Mr. Wood's employment agreement also contains indemnification, non-solicitation and non-disclosure provisions.
Douglas L. Polson
Mr. Polson entered into an employment agreement with our General Partner effective on October 1, 2002. The employment agreement provided for an annual base salary and an annual bonus in accordance with our General Partner's annual incentive plan. Mr. Polson was also eligible to participate in all other bonus and benefit programs for which employees and/or senior executives are generally eligible. In addition, he was reimbursed for reasonable expenses incurred in his capacity as Chairman of the Board of Directors.
On March 3, 2005, Mr. Polson entered into a Special Agreement and a Consulting Agreement with PEM, and, in consideration thereof, Mr. Polson executed a general release. Pursuant to the Special Agreement, PEM assumed the rights and obligations of our General Partner under Mr. Polson's
employment agreement, and, pursuant to the general release, Mr. Polson released PEM and its affiliates, including the Partnership, from claims which Mr. Polson has or may have against them, including under Mr. Polson's employment agreement. In accordance with the Special Agreement, Mr. Polson resigned as Chairman of the Board of Directors of our General Partner effective March 3, 2005. Pursuant to the Special Agreement, Mr. Polson was paid $900,000 in satisfaction of obligations under the Employment Agreement. Pursuant to the Ancillary Agreement, LBP reimbursed us for this amount. Mr. Polson now serves as a non-executive member of the Board of Directors of PEM. Pursuant to the Consulting Agreement, Mr. Polson agreed to perform advisory services to PEM as mutually agreed between Mr. Polson and the Chief Executive Officer of PEM from time to time. In consideration for Mr. Polson's services under the Consulting Agreement, which had a one-year term that expired on March 3, 2006, Mr. Polson received a monthly consulting fee of $12,500 and reimbursement of all reasonable business expenses incurred or paid by Mr. Polson in the course of performing his duties thereunder.
Long-Term Incentive Plan
General
Our General Partner has adopted a long-term incentive plan for employees and directors of the General Partner and employees of its affiliates who perform services for us.
The plan consists of two components: restricted units and unit options. The aggregate number of units permitted to be granted under the long-term incentive plan is 1,750,000. The long-term incentive plan is administered by the Compensation Committee of the Board of Directors. Grant levels, the type of award and the frequency of grants for designated employees will be recommended by the chief executive officer of our General Partner, subject to the review and approval of the Compensation Committee. The Compensation Committee will determine the grant level, the type of award and the frequency of grants for directors. The Board of Directors may terminate or amend the plan at any time with respect to units for which a grant has not yet been made. However, no change may be made that would materially impair the rights of a participant with respect to an outstanding grant without the consent of the participant.
Upon vesting of restricted units or the exercise of unit options, the Partnership has the option of issuing common units acquired by our General Partner in the open market, common units already owned by our General Partner, common units acquired by our General Partner directly from us or any other person, new common units issued by us, or any combination of the foregoing. Our General Partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units upon vesting of the restricted units, or the exercise of a unit option, the total number of common units outstanding will increase.
Restricted Units
A restricted unit is a "phantom" unit. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. In the future, the Compensation Committee may determine to make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine under the plan. The Compensation Committee will determine the period over which restricted units granted to employees and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. If a grantee's employment or membership on the Board of Directors terminates for any reason other than death, disability or upon the occurrence of certain other specified events that cause immediate full or pro-rated vesting, such as the retirement of the grantee when the grantee is eligible for retirement, the grantee's unvested restricted units will be automatically forfeited unless, and to the extent, the Compensation Committee provides otherwise. In addition, the restricted units will vest upon a change
of control of Pacific Energy Partners or our General Partner. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights, i.e. the right to receive cash equal to cash distributions made on a common unit, with respect to restricted units; however, none have been granted to date.
We intend the issuance of the restricted units under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants will not pay any consideration for the common units they receive, and we will receive no remuneration for such units.
The Compensation Committee may determine to grant unit options under the plan to employees and directors containing such terms as the committee shall determine. Unit options will have an exercise price that may not be less than the fair market value of the units on the date of grant. In general, unit options granted will become exercisable over a period determined by the Compensation Committee. In addition, the unit options will become exercisable upon a change in control of Pacific Energy Partners or our General Partner. The unit option plan has been designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders. No unit options were granted in 2005, 2004 and 2003.
(1)In connection with the closing of the LB Acquisition on March 3, 2005, all 144,750 restricted units outstanding under our long-term incentive plan vested.
(2)Includes units relinquished in satisfaction of withholding taxes.
Annual Incentive Plan
Our General Partner has an annual incentive compensation plan that is designed to enhance the performance of eligible employees of our General Partner by rewarding them with cash awards for certain individual achievements and the Partnership achieving certain annual financial and operational performance objectives. The Compensation Committee may in its discretion determine individual participants and payments, if any, for each fiscal year. The Board of Directors may amend or change the annual incentive plan at any time. We reimburse our General Partner for payments and costs incurred under the plan.
LB Pacific, LP Option Plan
LBP, the owner of our General Partner, has adopted an option plan for officers, directors, employees, advisors, and consultants of Pacific Energy Management LLC, LBP, and their affiliates. Under the plan, participants may be granted options to acquire partnership interests in LBP. We are not obligated to pay any amounts to LBP for the benefits granted or paid to our executives and key
employees under the Plan, although generally accepted accounting principles require that we record an expense in the Partnership's financial statements with a corresponding increase in the general partner's capital account.
The option plan is administered by the board of directors of LB Pacific GP, LLC. The terms, conditions, performance goals, restrictions, limitations, forfeiture, vesting or exercise schedule, and other provisions of grants under the plan, as well as eligibility to participate are determined by the board of directors of LB Pacific GP, LLC. The board of directors of LB Pacific GP, LLC may determine to grant options under the plan to participants containing such terms as the board of LB Pacific GP, LLC shall determine. Options will have an exercise price that may not be less than the fair market value of the units on the date of grant. In general, options granted will become exercisable over a period determined by the board of directors of LB Pacific GP, LLC. In addition, the board of directors of LB Pacific GP, LLC may determine whether any unit options may become exercisable upon a change in control of LB Pacific GP, LLC, LB Pacific, LP, or our General Partner.
The board of directors of LB Pacific GP, LLC may terminate or amend the unit option plan at any time with respect to units for which a grant has not yet been made. However, no change may be made that would materially impair the rights of a participant with respect to an outstanding grant without the consent of the participant.
Information concerning the plan and grants is shared by LB Pacific, LP with our Compensation Committee and Board of Directors, and considered in determining the appropriate level of long term compensation paid for by the Partnership.
No option grants were made pursuant to the plan during 2005. In January 2006, the following grants were made to the individuals in the Summary Compensation Table above:
(1)Assuming all options are exercised.
(2)The expiration date also represents the earliest exercise date, except in limited circumstances such as a change in control.
(3)The present value of the grant at January 9, 2006, the date of grant, using the Black-Scholes option pricing model. The following assumptions were used: volatility 21.86%; risk-free rate of return 4.37%; dividend yield of 0% and exercise in ten years.
(4)Excludes an additional 3.3% grant (potential ownership in LB Pacific LP assuming all options are exercised) for Mr. Wylie's role in sourcing, evaluating, financing and closing the acquisition by LB Pacific, LP of the limited and general partner interests in Pacific Energy Partners, L.P. from The Anschutz Corporation. Grants under the LBP plan were also made to other key employees of the General Partner and Partnership.
As noted above, we are not obligated to pay any amounts to LB Pacific, LP for the benefits granted or paid to our executives under the plan, although generally accepted accounting principles require that we record an expense over the vesting period with a corresponding increase in the general partners' capital account.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of equity securities of Pacific Energy Partners as of January 31, 2006, held by beneficial owners of more than 5% of the units, by directors of our General Partner, by each named executive officer, by our General Partner and by all directors and executive officers of our General Partner as a group.
(1)The address of each of Lehman Brothers Holdings, Inc. and LB Pacific, LP is 399 Park Avenue, New York, NY 10022.
(2)The address of First Reserve GP X, Inc. is One Lafayette Place, Greenwich, CT 06830.
(3)In each instance a "*" indicates that the individual owns less than 1.0% of the common and total units outstanding.
(4)The subordinated units are convertible on a one-to-one basis into common units upon the satisfaction of certain financial tests set forth in our limited partnership agreement.
(5)The common and subordinated units shown as beneficially owned by Lehman Brothers Holdings, Inc., Christopher R. Manning and Joshua L. Collins are directly owned by LB Pacific, LP. Lehman Brothers Holdings, Inc. controls LBMB and LBMB Associates III, LLC, which own a 70% limited partner interest in LB Pacific, LP and a 70% membership interest in LB Pacific GP, LLC and shares control of LB Pacific, LP and LB Pacific GP, LLC with First Reserve GP X, Inc.,
and thus may be deemed to have beneficial ownership of the common and subordinated units owned by LB Pacific, LP. Messrs. Manning and Collins are members of the board of directors of the general partner of LB Pacific, LP and principals of Lehman Brothers Merchant Banking Partners III L.P. and may be deemed to share beneficial ownership of the common and subordinated units shown as beneficially owned by LB Pacific, LP. Messrs. Manning and Collins disclaim beneficial ownership of all such units.
(6)See Footnote (5) with respect to common and subordinated units which may be attributable to Lehman Brothers Holdings, Inc. and Messrs. Manning and Collins that have been included in the total. Messrs. Manning and Collins disclaim beneficial ownership of all such units.
(7)The common and subordinated units shown as beneficially owned by First Reserve GP X Inc. and Timothy H. Day are directly owned by LB Pacific, LP. First Reserve GP X Inc., which controls First Reserve Pacific Holdings AIV, L.P., which owns a 30% limited partner interest in LB Pacific, LP and a 30% membership interest in LB Pacific GP, LLC and shares control of LB Pacific, LP and LB Pacific GP, LLC with Lehman Brothers Holding, Inc., and thus may be deemed to have beneficial ownership of the common and subordinated units owned by LB Pacific, LP. Mr. Day is a member of the board of directors of the general partner of LB Pacific, LP and is a director of First Reserve Corporation and may be deemed to share beneficial ownership of the common and subordinated units shown as beneficially owned by LB Pacific, LP and First Reserve Pacific Holdings AIV, L.P. Mr. Day disclaims beneficial ownership of such units.
(8)See Footnote (7) with respect to common and subordinated units which may be attributable to First Reserve GP X Inc. and Mr. Day that have been included in the total. Mr. Day disclaims beneficial ownership of all such units.
(9)The address of Tortoise Capital Advisors LLC and Tortoise Energy Capital Corporation is 10801 Mastin Blvd., Suite 222, Overland Park, Kansas 66210.
(10)Includes 1,617,500 common units owned of record by Tortoise Energy Capital Corporation over which Tortoise Capital Advisors has beneficial ownership pursuant to an investment advisory agreement between Tortoise Capital Advisors LLC and Tortoise Energy Capital Corporation.
(11)The address of Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne is 1800 Avenue of the Stars, Second Floor, Los Angeles, CA 90067. Mr. Kayne is chief executive officer and co-founder of Kayne Anderson Capital Advisors, L.P.
(12)Includes 1,000 units with respect to which such the listed beneficial owner has the right to acquire beneficial ownership through vesting of units under the Long-Term Incentive Plan within 60 days of January 31, 2006.
(13)Includes units with respect to which the listed beneficial owner has the right to acquire beneficial ownership through vesting of units under the Long-Term Incentive Plan within 60 days of January 31, 2006, as set forth in the table below. Pursuant to the terms of the Long-Term Incentive Plan, participants can elect to receive fewer units, in exchange for withholding of sufficient units to pay withholding taxes on the vested units. In connection with the vesting, which
occurred on March 1, 2006, certain of the participants elected to receive fewer units, as reflected in the column titled "Net Common Units Acquired."
(14)See Footnotes (5) and (7) with respect to common and subordinated units which may be attributable to Messrs. Manning, Collins and Day that have been included in the total. Messrs. Manning, Collins and Day disclaim beneficial ownership of all such units. The following table sets forth the beneficial ownership of equity securities of LB Pacific, LP as of January 31, 2006, held by directors of our General Partner, by each named executive officer, and by all directors and executive officers of our General Partner as a group.
(1)Not exercisable within 60 days of January 31, 2006. Figures represent maximum percentage ownership if all performance targets are achieved. Changes in Control
LBP financed a portion of the purchase price it paid in the LB Acquisition with the proceeds from a $175.0 million secured credit and guarantee agreement (the "Credit Agreement"), entered into at the closing of the LB Acquisition by and among LBP, as borrower, the several lenders parties thereto, Citicorp North America, Inc., as administrative agent and collateral agent and Lehman Commercial Paper Inc., as syndication agent, and Citigroup Global Markets Inc. as sole lead arranger and sole bookrunner. We are not a party to the Credit Agreement. The Credit Agreement is secured by a pledge of substantially all of the assets of LBP, including the interest of LBP in PEM and our general partner. If LBP defaults on its obligations under the Credit Agreement the lenders could exercise their rights under this pledge, which could result in a change of control of us.
Equity Compensation Plan Information
The following table sets forth certain information at December 31, 2005 with respect to the number of units issuable under our equity compensation plans:
For a description of the material features of our long-term incentive plan and annual incentive plan, please see "Item 11 - Long-Term Incentive Plan" and "Item 11 - Annual Incentive Plan" above.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions
Distributions and Payments to the General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with the ongoing operation and any liquidation of the Partnership. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Operational Stage
(Subsequent to July 26, 2002)
Liquidation Stage
Ancillary Agreement
On October 29, 2004, we entered into an Ancillary Agreement with PPS Holding Company (a subsidiary of Anschutz), LBP, Anschutz and our General Partner. Pursuant to this agreement, the following terms, among others, were agreed to:
•Anschutz agreed to enter into a transition services agreement with us;
•Anschutz, PPS Holding and their affiliates agreed not to compete with us under certain circumstances; and
•LBP agreed not to compete with us under certain circumstances.
In addition, LBP agreed to reimburse us or our affiliates for certain severance costs resulting from the LB Acquisition and LBP, Anschutz and one of Anschutz's affiliates agreed to reimburse certain specified types of costs of the Partnership relating to the LB Acquisition, including legal fees and accounting fees, up to an aggregate of $650,000, and certain other specified types of costs, without a limitation on the amount of reimbursement.
On or around March 8, 2005, pursuant to the terms of the Ancillary Agreement, LBP reimbursed PEM for more than $900,000, which PEM paid to Douglas L. Polson under the Special Agreement between PEM and Mr. Polson. For more information on the Special Agreements and other transactions with Mr. Polson, see "Cost Reimbursements" below.
Lehman Brothers, Inc.
Christopher R. Manning and Joshua L. Collins, directors of our General Partner, are each affiliates of Lehman Brothers, Inc. Lehman Brothers, Inc. and its affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services
for us, for which they received or will receive customary fees and expenses. We may engage Lehman Brothers, Inc. and its affiliates from time to time, to perform advisory services for us in connection with acquisitions and financings.
In connection with the purchase and associated financing of the Valero Acquisition, including a private equity offering, public equity offering, debt offering and new credit facility, Lehman Brothers, Inc. and its affiliates provided advisory and underwriting services to us. Additionally, an affiliate of Lehman Brothers, Inc. was a participant in the syndicate that provided our new senior secured credit facility. These agreements with Lehman Brothers, Inc. were reviewed and approved by the Conflicts Committee of the Board of Directors and the fees charged were customary for the types of services provided. For the period from March 3, 2005 through December 31, 2005, we incurred $9.9 million in fees to Lehman Brothers, Inc. and its affiliates, a portion of which was paid to non-affiliated financial institutions in the syndication of the new credit facility and in the public offering of equity.
Cost Reimbursements
General Partner: Our General Partner employs all U.S.-based employees. All employee expenses incurred by the General Partner on our behalf are charged back to us.
Special Agreement: On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board of Directors of Pacific Energy GP, Inc., entered into a Special Agreement and a Consulting Agreement with PEM. In accordance with the Special Agreement, Mr. Polson resigned as Chairman of the Board of Directors of our General Partner effective March 3, 2005. Mr. Polson was paid approximately $0.9 million, representing accrued salary through March 3, 2005, accrued but unused vacation and payment in satisfaction of other obligations under his employment agreement. Pursuant to the Ancillary Agreement, LBP reimbursed us for more than $0.9 million of the total. Mr. Polson now serves as a non-executive member of the Board of Directors of PEM. Pursuant to the Consulting Agreement, Mr. Polson agreed to perform advisory services to PEM from time to time as mutually agreed between Mr. Polson and the Chief Executive Officer of PEM. In consideration for Mr. Polson's services under the Consulting Agreement, which expired on March 3, 2006, Mr. Polson received a monthly consulting fee of $12,500 and reimbursement of all reasonable business expenses incurred or paid by Mr. Polson in the course of performing his duties thereunder.
LBP and Anschutz: LBP and Anschutz reimbursed us in 2005 for certain costs relating to the LB Acquisition. These included $1.2 million for the Consent Solicitation and $0.3 million for legal and other expenses.
Other Related Party Transactions
Related party balances at December 31, 2005 and 2004 are reflected on the consolidated balance sheets included in the section entitled "Item 8 - Financial Statements and Supplementary Data" as follows:
Prior to March 3, 2005, in the ordinary course of our operations, we engaged in various transactions with Anschutz and its affiliates. These transactions, which are more thoroughly described below, are summarized in the following table for the year ended December 31, 2005, 2004 and 2003:
Revenue from Related Parties
A subsidiary of Anschutz was a shipper on Line 2000 and was charged the published tariff rates applicable to "participating shippers" until March 31, 2003, when an agreement between the Anschutz subsidiary and a third party, the performance of which required the Anschutz subsidiary to ship on Line 2000, was assigned to us for consideration equal to the value of transferred inventory. The agreement ended April 1, 2003. In addition, a subsidiary of Anschutz is a shipper on pipelines owned by RMPS and is charged published tariff rates.
RMPS serves as the contract operator for certain gas producing properties owned by a subsidiary of Anschutz in Wyoming and Utah, in exchange for which RMPS is reimbursed its direct costs of operation and is paid an annual fee of $0.3 million as compensation for the time spent by RMPS management and for other overhead services related to their activities. In addition, during 2003 and the first half of 2004, RMPS's trucking operation hauled water for a Anschutz subsidiary at rates equivalent to those charged to third parties.
RMPS also receives a management fee from Frontier in connection with time spent by RMPS management and for other services related to Frontier's pipeline's activities. RMPS received $0.8 million, $0.9 million and $0.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Expenses Paid to Related Parties
Pursuant to an easement agreement between PPS and Union Pacific Corporation ("UPC"), UPC provides us with access to its right-of-way for a portion of Line 2000 in return for an annual rental. Philip F. Anschutz, a director of our General Partner until March 3, 2005, and sole stockholder of Anschutz Company, the indirect parent of our General Partner until that date, is a director of UPC.
From mid-2002 through December 31, 2005, we utilized a financial accounting system owned and provided by Anschutz under a shared services arrangement. In addition, from time to time until mid-2003 we utilized the services of Anschutz's risk management personnel for acquiring our insurance, and until 2004 our surety bonds were issued under Anschutz's bonding line. From January 2003 through December 31, 2005, Anschutz charged us a fee of $0.1 million per year for these services, plus any out-of-pocket costs. The fixed annual fee included all license, maintenance and employee costs associated with our use of the financial accounting system.
In January 2003, we began leasing approximately office space from an affiliate of Anschutz, for a term of five years at an initial annual cost of $0.1 million. This lease terminated in February 2006.
ITEM 14.
ITEM 14. Principal Accountant Fees and Services
The following table presents fees for professional audit services rendered by our independent registered public accounting firm, KPMG LLP, for the audit of our annual financial statements for the years ended December 31, 2005 and 2004 and fees billed for other services rendered by KPMG LLP during those periods.
The Audit Committee reviewed and approved, in advance, all services provided by KPMG LLP.
Part IV
ITEM 15.
ITEM 15. Exhibits and Financial Statement Schedules
(a)(1) and (2) Financial Statements and Financial Statement Schedules
Please see "Index to Consolidated Financial Statements" on page.
(a)(3) Exhibits
The following documents are filed as exhibits to this annual filing:
Exhibit
Number
Description
3.1
First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P., dated July 26, 2002 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-Q filed on September 5, 2002, Exhibit 3.2)
3.2
Second Amended and Restated Limited Liability Company Agreement of Pacific Energy Group LLC, dated July 26, 2002 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-Q filed on September 5, 2002, Exhibit 3.7)
3.3
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P., dated August 1, 2003 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form S-3 filed on August 1, 2003, Exhibit 3.3)
3.4
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P., dated January 27, 2004 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 15, 2004)
3.5
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Pacific Energy Partners, L.P., dated March 26, 2004 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-Q filed on May 5, 2004)
4.1
Indenture dated June 16, 2004, by and 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 71/8% senior notes due 2014 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-Q filed on August 9, 2004, Exhibit 4.2)
4.2
First Supplemental Indenture dated March 3, 2005 by and 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 71/8% senior notes due 2014 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 8-K filed on March 9, 2005, Exhibit 4.1)
4.3
Indenture dated September 23, 2005, by and among Pacific Energy Partners, L.P., Pacific Energy Finance Corporation, Pacific Atlantic Terminals LLC, Pacific Energy Group LLC, PEG Canada GP LLC, PEG Canada, L.P., Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Marketing and Transportation LLC, and Wells Fargo Bank, National Association (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 8-K dated September 23, 2005, Exhibit 4.1)
4.4
Registration Rights Agreement, dated September 23, 2005, among the Issuers and the Initial Purchasers (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 8-K dated September 28, 2005, Exhibit 4.3)
10.1
Credit Agreement, dated as of September 30, 2005, among Pacific Energy Partners, L.P., Rangeland Pipeline Company, Bank of America, NA and other lenders party thereto (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 8-K filed on October 6, 2005, Exhibit 10.1)
10.2^
Employment Agreement between Pacific Energy GP, Inc. and Irvin Toole, Jr. (Incorporated by reference to Pacific Energy Partners, L.P.'s Form S-1 filed on July 19, 2002, Exhibit 10.4)
10.3^
Employment Agreement between Pacific Energy GP, Inc. and David E. Wright (Incorporated by reference to Pacific Energy Partners, L.P.'s Amendment No. 3 to Form S-1 filed on July 2, 2002, Exhibit 10.5)
10.4^
Employment Agreement between Pacific Energy GP, Inc. and Gary L. Zollinger (Incorporated by reference to Pacific Energy Partners, L.P.'s Amendment No. 3 to Form S-1 filed on July 2, 2002, Exhibit 10.6)
10.5
Omnibus Agreement (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-Q filed on September 5, 2002, Exhibit 10.10)
10.6
First Amendment to Omnibus Agreement (Incorporated by reference to Exhibit 10.1 to Form 8-K filed on March 9, 2005)
10.7^
Form of Pacific Energy GP, Inc. Long-Term Incentive Plan (Incorporated by reference to Pacific Energy Partners, L.P.'s Amendment No. 4 to Form S-1 filed on July 19, 2002, Exhibit 10.8(b))
10.8^
Employment Agreement between Pacific Energy GP, Inc. and Douglas L. Polson (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 27, 2003, Exhibit 10.12)
10.9^
Special Agreement between Pacific Energy Management LLC and Douglas L. Polson dated March 3, 2005 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 15, 2005, Exhibit 10.14)
10.10^
Consulting Agreement between Pacific Energy Management LLC and Douglas Polson dated March 3, 2005 (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 15, 2005, Exhibit 10.15)
10.11^
Employment Agreement between Pacific Energy GP, Inc. and Gerald A. Tywoniuk (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 27, 2003, Exhibit 10.13)
10.12^
Employment Agreement between Pacific Energy GP, Inc. and Lynn T. Wood (Incorporated by reference to Pacific Energy Partners, L.P.'s Form 10-K filed on March 27, 2003, Exhibit 10.14)
10.13^
Form of Pacific Energy GP, Inc. Annual Incentive Plan (Incorporated by reference to Pacific Energy Partners, L.P.'s Amendment No. 4 to Form S-1 filed on July 19, 2002, Exhibit 10.8(b))
10.14
Ancillary Agreement by and among PPS Holding Company, The Anschutz Corporation, LB Pacific, LP, Pacific Energy Partners, L.P. and Pacific Energy GP, Inc. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed November 3, 2004)
10.15
Director Compensation Summary Sheet (Incorporated by reference to Exhibit 10.1 to Form 8-K filed February 7, 2006)
12.1*
Statement of Computation of Ratio of Earnings to Fixed Charges
21.1*
List of Subsidiaries of Pacific Energy Partners, L.P.
23.1*
Consent of Independent Registered Public Accounting Firm
31.1*
Certification of Principal Executive Officer of Pacific Energy Management LLC, the general partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of
31.2*
Certification of Principal Financial Officer of Pacific Energy Management LLC, the general partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., as required by Rule 13a-14(a) of the Securities Exchange Act of
32.1
Certification of Chief Executive Officer of Pacific Energy Management LLC, the general partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350
32.2
Certification of Chief Financial Officer of Pacific Energy Management LLC, the general partner of Pacific Energy GP, LP, General Partner of Pacific Energy Partners, L.P., pursuant to 18 U.S.C. §1350
*Filed herewith.
Not considered to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.
^Management contract or compensatory plan, contract or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PACIFIC ENERGY PARTNERS, L.P.
By:
PACIFIC ENERGY GP, LP, its General Partner
By:
PACIFIC ENERGY MANAGEMENT LLC, its General Partner
By:
/s/ IRVIN TOOLE, JR. Irvin Toole, Jr.
President, Chief Executive Officer
and Director
(Principal Executive Officer)
March 10, 2006
By:
/s/ GERALD A. TYWONIUK Gerald A. Tywoniuk
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
March 10, 2006
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 Partnership in the capacities and on the dates indicated.
Date
Signature
Title
March 10, 2006
/s/ JOSHUA L. COLLINS Joshua L. Collins
Director
March 10, 2006
/s/ TIMOTHY H. DAY Timothy H. Day
Director
March 10, 2006
/s/ DAVID L. LEMMON David L. Lemmon
Director
March 10, 2006
/s/ JOHN C. LINEHAN John C. Linehan
Director
March 10, 2006
/s/ CHRISTOPHER R. MANNING Christopher R. Manning
Director
March 10, 2006
/s/ DOUGLAS L. POLSON Douglas L. Polson
Director
March 10, 2006
/s/ JIM E. SHAMAS Jim E. Shamas
Director
March 10, 2006
/s/ WILLIAM L. THACKER William L. Thacker
Director
March 10, 2006
/s/ FORREST E. WYLIE Forrest E. Wylie
Director
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors of Pacific Energy Management LLC and
Unitholders of Pacific Energy Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Pacific Energy Partners, L.P. and subsidiaries, as of December 31, 2005 and 2004, and the related consolidated statements of income, partners' capital, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of Pacific Energy Partners, L.P.'s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pacific Energy Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Pacific Energy Partners, L.P. and subsidiaries' internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2006 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.
/s/ KPMG LLP
Los Angeles, California
March 10, 2006
PACIFIC ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2005 and 2004
See accompanying notes to consolidated financial statements.
PACIFIC ENERGY PARTNERS, L. P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 2005, 2004 and 2003
See accompanying notes to consolidated financial statements.
PACIFIC ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
Years ended December 31, 2005, 2004 and 2003
(in thousands)
See accompanying notes to consolidated financial statements.
PACIFIC ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Years ended December 31, 2005, 2004 and 2003
See accompanying notes to consolidated financial statements.
PACIFIC ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 2005, 2004 and 2003
See accompanying notes to consolidated financial statements.
PACIFIC ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Pacific Energy Partners, L.P., a Delaware limited partnership, was formed in February 2002 and completed its initial public offering of common units representing limited partner units on July 26, 2002. Pacific Energy Partners, L.P. and its subsidiaries (collectively the "Partnership") are engaged principally in the business of gathering, transporting, storing and distributing crude oil, refined products and other related products. The Partnership generates revenue primarily by transporting such commodities on its pipelines, by leasing storage capacity in its storage tanks, and by providing other terminaling services. The Partnership also buys and sells crude oil, activities that are generally complementary to its other crude oil operations. The Partnership conducts its business through two business units, the West Coast Business Unit, which includes activities in California and the Philadelphia, Pennsylvania area, and the Rocky Mountain Business Unit, which includes activities in five Rocky Mountain states and Alberta, Canada.
The Partnership is managed by its general partner, Pacific Energy GP, LP, a Delaware limited partnership (the "General Partner"), which, prior to its conversion to a limited partnership on March 3, 2005, was Pacific Energy GP, Inc., a corporation owned 100% by a subsidiary of The Anschutz Corporation ("Anschutz"). On March 3, 2005, Anschutz sold all of its interest in Pacific Energy GP, Inc. to LB Pacific, LP ("LBP"), which was formed by the Lehman Brothers Merchant Banking Group ("LBMB") in connection with the purchase (see "Note 8-Related Party Transactions"). Pacific Energy GP, LP is managed by its general partner, Pacific Energy Management LLC ("PEM"), a Delaware limited liability company, thus the officers and Board of Directors of PEM manage the business affairs of the Partnership and its General Partner. The Partnership's General Partner does not receive any management fee or other compensation in connection with its management of the Partnership's business, but is entitled to reimbursement for all direct and indirect expenses incurred on the Partnership's behalf.
The Partnership holds a 100% ownership interest in Pacific Energy Group LLC ("PEG"), whose 100% owned subsidiaries consist of:
(i)Pacific Pipeline System LLC ("PPS"), owner of Line 2000 and the Line 63 system;
(ii)Pacific Terminals LLC ("PT"), owner of the Pacific Terminals storage and distribution system;
(iii)Pacific Atlantic Terminals LLC ("PAT"), which was formed for the purpose of acquiring the California and East Coast terminal assets the Partnership purchased on September 30, 2005 as part of the acquisition of assets from Valero, L.P. (see "Note 3-Acquisitions");
(iv)Pacific Marketing and Transportation LLC ("PMT"), owner of the PMT gathering system and marketer of crude oil;
(v)Rocky Mountain Pipeline System LLC ("RMPS"), owner of the Western Corridor and Salt Lake City Core systems, and which acquired the West Pipeline system (which is now known as the Rocky Mountain Products Pipeline) on September 30, 2005 as part of the acquisition of assets from Valero, L.P.; and
(vi)Ranch Pipeline LLC ("RPL"), owner of a 22.22% partnership interest in Frontier Pipeline Company ("Frontier"), a Wyoming general partnership.
The Partnership holds 100% interest in PEG Canada GP LLC ("PEG Canada GP"), the general partner of PEG Canada, L.P. ("PEG Canada"), the holding company of the Partnership's Canadian
subsidiaries. The Partnership owns 100% of the limited and general partner interests in PEG Canada, whose 100% owned subsidiaries consist of:
(i)Rangeland Pipeline Company ("RPC"), which owns 100% of Aurora Pipeline Company Ltd. ("Aurora") and a partnership interest in Rangeland Pipeline Partnership ("Rangeland Partnership");
(ii)Rangeland Northern Pipeline Company ("RNPC"), which owns the remaining partnership interest in Rangeland Partnership; and
(iii)Rangeland Marketing Company ("RMC").
Rangeland Partnership owns all of the assets that make up the Rangeland pipeline system except the Aurora pipeline, which is owned by Aurora.
The Partnership also owns 100% of Pacific Energy Finance Corporation, which was organized for the purpose of co-issuing the Partnership's senior notes.
Business Segment Reporting
The business segments of the Partnership consist of two geographic regions, the West Coast and the Rocky Mountains. The West Coast Business Unit includes PPS, PT, PAT and PMT. The Rocky Mountain Business Unit includes RMPS, RPL and PEG Canada and its Canadian subsidiaries RPC, Aurora, RNPC, RMC and Rangeland Partnership. Information relating to these two segments is summarized in "Note 20-Segment Information".
Basis of Presentation
The accompanying financial statements and related notes present the Partnership's (including all of its wholly-owned subsidiaries) consolidated financial position as of December 31, 2005 and 2004, and the consolidated results of the Partnership's operations, cash flows, changes in partners' capital and comprehensive income for the years ended December 31, 2005, 2004 and 2003. All significant intercompany balances and transactions have been eliminated during the consolidation process. Certain reclassifications were made to prior periods to conform to the current period presentation. Investments in affiliates, over which the Partnership has significant influence, are accounted for by the equity method.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Management Estimates
Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires that management make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the balance sheet date as well as the reported amounts of revenue and expenses during the reporting period. The actual results could differ significantly from those estimates.
The Partnership's most significant estimates involve the valuation of individual assets acquired in purchase transactions, the useful lives of property and equipment, the expected costs of environmental remediation, accounting for the potential impact of regulatory proceedings or other actions with shippers on the Partnership's pipelines, and the valuation of inventory.
Revenue Recognition
Revenue from pipeline transportation services is recognized upon delivery of the product to the customer. Other revenue associated with the operation of the Partnership's pipelines is recognized as the services are performed.
Storage and distribution revenue is recognized monthly based on the lease of storage tanks, the use of distribution system assets, and the delivery of related incidental services.
The Rangeland system is a proprietary system. Therefore, customers who wish to transport commodities on the Rangeland system must either: (i) sell commodities at the inlet to the pipeline without repurchasing commodities; or (ii) sell commodities at an inlet point and repurchase such product at agreed-upon delivery points for the price paid at the inlet to the pipeline plus an established location differential on a pre-arranged basis. Revenue from buy/sell transactions is recognized on a net basis. Revenue is recognized when the commodity is delivered to the customer.
PMT's crude oil sales are recognized as the crude oil is delivered to customers, and are reflected separately, net of crude oil purchases, on the accompanying consolidated statements of income.
Regulation
The California Public Utilities Commission ("CPUC") regulates PPS's common carrier crude oil pipeline operations. All shipments on the regulated pipelines are governed by tariffs authorized and approved by the CPUC. Tariffs on the Line 2000 pipeline are market-based, established based on market considerations, subject to contractual terms. Tariffs on the Line 63 pipeline are cost-of-service based, designed to allow PPS to recover its various costs to operate and maintain the pipeline as well as a charge for depreciation of the capital investment in the pipeline and an authorized rate of return.
The CPUC also regulates PT's storage and distribution operations. The CPUC has authorized PT to establish the terms, conditions and charges for its storage and distribution services through negotiated contracts with its customers.
The West and East Coast products terminals are not regulated utilities, nor is the PMT gathering system, which is a proprietary intrastate operation.
The Western Corridor and Salt Lake City Core systems are common carrier pipelines that transport oil under cost-based tariffs under the jurisdiction of the Federal Energy Regulatory Commission ("FERC") and the Wyoming Public Service Commission ("WPSC"). The Rocky Mountain Products Pipeline that was acquired as part of the Valero Acquisition is a common carrier system that transports products under market-based FERC tariffs, except for one FERC regulated cost-based segment, and under cost-based tariffs under the jurisdiction of the states of Wyoming and Colorado.
The Rangeland system operates as a proprietary system, and accordingly the Partnership takes title to the crude oil that is gathered and transported. The Rangeland system is subject to the jurisdiction of the Alberta Energy and Utilities Board ("EUB"). The Aurora pipeline is subject to the jurisdiction of the Canadian National Energy Board ("NEB"). The EUB and NEB will generally not review rates set by a crude oil pipeline operator unless it receives a complaint.
Concentration of Customers and Credit Risk
A substantial portion of the West Coast transportation and storage business in 2005, 2004 and 2003 was with four customers who individually accounted for more that 10% of West Coast transportation and storage revenue. Collectively, these four customers accounted for approximately 60%, 73% and 76% of total West Coast transportation and storage revenue in 2005, 2004 and 2003, respectively. Two of these customers, Chevron and Shell Trading Company, who collectively accounted for approximately 32%, 46% and 47% of 2005, 2004 and 2003 transportation and storage revenue, respectively, have
executed ten-year ship or pay transportation agreements expiring in 2009 whereby they have committed to ship minimum volumes that represent approximately 61% of their actual 2005 volumes transported on the Partnership's West Coast pipelines.
A substantial portion of the Partnership's Rocky Mountain pipeline transportation and storage business in 2005, 2004 and 2003 was with two customers who individually accounted for more that 10% of Rocky Mountain transportation revenue. Collectively, these two customers accounted for approximately 36%, 40% and 50% of total Rocky Mountain transportation revenue in 2005, 2004 and 2003, respectively. In addition, for the Partnership's Canadian buy/sell transportation revenue, in 2005 three customers accounted for 50% of the Partnership's Canadian net sales revenue and in 2004 two customers accounted for approximately 60% of the Partnership's Canadian net sales revenue. In 2005, three suppliers accounted for 58% of the Partnership's Canadian net purchase contracts and in 2004 one supplier accounted for 66% of the Partnership's Canadian net purchase contracts. Each of these customers and suppliers individually accounted for more that 10% of the Partnership's Canadian buy/sell transportation revenue and net purchase contracts.
Although the above concentration could affect the Partnership's overall exposure to credit risk, management believes that the risk is minimal given that a majority of its business is conducted with large, high credit quality companies within the industry. The Partnership performs periodic credit evaluations of its customers' financial condition and generally does not require collateral for its accounts receivables. In some cases, the Partnership requires payment in advance or security in the form of a letter of credit or bank guarantee.
Cash Equivalents
For purposes of the consolidated statements of cash flows, the Partnership considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable
Crude oil sales receivable relate to the Partnership's gathering and marketing activities. The Partnership's gathering and marketing activities can generally be described as high volume and low margin activities. Transportation and storage accounts receivable are from shippers who transport crude on our pipelines and customers who lease our storage capacity. The Partnership makes a determination of the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances required. Such financial assurances are commonly provided in the form of standby letters of credit. The Partnership also monitors changes in the creditworthiness of its customers as a result of developments related to each customer, the industry as a whole and the general economy.
The Partnership routinely reviews its accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. The Partnership has an insignificant amount for allowances for doubtful accounts as of December 31, 2005, 2004 and 2003.
Crude Oil and Refined Products Inventories
Crude oil and refined products inventories are valued at the lower of cost or market with cost determined using an average cost method. The inventory balance is subject to downward adjustment if prices decline below the carrying value of the inventory.
Property and Equipment
The components of property and equipment are capitalized at cost and depreciated using the straight-line method over the estimated useful lives of the assets as follows:
In accordance with our capitalization policy, costs associated with acquisitions and improvements, including related interest costs, which expand our existing capacity are capitalized. For the years ended December 31, 2005 and 2004, and 2003, capitalized interest was $1.1 million, $0.4 million, and $0.1 million, respectively. In addition, costs incurred to extend the useful lives of assets are capitalized. 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.
Impairment of Long-Lived Assets
Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. This review consists of a comparison of the carrying value of the asset with the asset's expected future undiscounted cash flows. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions are permanent and may not be restored in the future. The Partnership recorded impairment expense of $0.5 million and $0.8 million associated with idle Pacific Terminals property in 2005 and 2004, respectively.
Asset Retirement Obligations
The Partnership has determined that it is obligated by contractual or regulatory requirements to remove facilities or perform remediation upon retirement of certain of its assets. However, the Partnership is not able to reasonably determine the fair value of the asset retirement obligations for its pipelines and storage tanks, since the range of future dismantlement and removal dates are indeterminate.
In order to determine a removal date for the Partnership's gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. The Partnership is not a producer of the oil field reserves, and therefore does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Partnership gathers crude oil. In the absence of such information, the Partnership is not able to make a reasonable estimate of when the dismantlement and removal of its gathering assets will be required. With regard to the Partnership's trunk and interstate pipelines and their related surface assets, it is not possible to predict when demand for transportation of the related products will cease. The Partnership's right-of-way agreements allow it to maintain the right-of-way rather than remove the pipe. In addition, the Partnership believes its trunk pipelines can be put into alternative uses.
The Partnership will record such asset retirement obligations in the period in which sufficient information becomes available for it to reasonably estimate the settlement date and amount of its retirement obligations.
Investment in Frontier
The Partnership's 22% investment in Frontier is accounted for using the equity method of accounting. Under the equity method, an investment is initially recorded at cost and subsequently adjusted to recognize the investor's share of distributions and net income or losses of the investee as they occur. Recognition of any such losses is generally limited to the extent of the investor's investment in, advances to, and commitments and guarantees for the investee.
Deferred Financing Costs
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the effective interest method. Costs incurred in connection with the issuance and amendments to our credit facilities are capitalized and amortized using the straight line methods over the term of the related facility. Unamortized debt issue costs may be written-off in conjunction with the refinancing or termination of the applicable debt arrangement prior to its scheduled maturity. We capitalized $7.9 million and $5.9 million of such costs in 2005 and 2004, respectively. In addition, during 2004 we wrote off $2.3 million of unamortized costs relating to the early termination of debt.
Environmental Liabilities
The Partnership accrues environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable in the future and can be reasonably estimated. To the extent environmental liabilities are assumed in acquisitions, the Partnership records an estimate of such costs at the date of acquisition. These accruals are undiscounted and are based on information currently available, existing technology, the estimated timing of remedial actions and related inflation assumptions and enacted laws and regulations. The Partnership monitors the balance of accrued undiscounted environmental liabilities on a regular basis and may make adjustments to the initial estimates recorded, from time to time, to reflect changing circumstances.
Income Taxes
The Partnership and its 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 its unitholders. The Partnership's Canadian subsidiaries are taxable entities in Canada and are subject to Canadian federal and provincial income taxes and other Canadian income taxes. In addition, monies repatriated by the Partnership from Canada into the U.S. may subject the Partnership to withholding taxes.
Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the Partnership's First Amended and Restated Agreement of Limited Partnership, as amended. Individual unitholders have different investment bases depending upon the timing and price of their acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in the consolidated financial statements. Accordingly, the aggregate difference in the basis of the Partnership's net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in the Partnership is not available to the Partnership.
In addition to federal and state income taxes, unitholders may be subject to other taxes, such as local, estate, inheritance or intangible taxes which may be imposed by the various jurisdictions in which the Partnership does business or owns property. Individual unitholders generally have no responsibility to file Canadian tax returns.
Income taxes for the Partnership's Canadian subsidiaries are accounted for under the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in operations in the period that includes the enactment date. The Partnership intends to repatriate its Canadian subsidiaries' earnings in the future and accordingly has recorded a provision for Canadian withholding taxes.
Derivative Instruments
The Partnership uses certain derivative instruments to hedge its exposure to commodity price, interest rate and foreign exchange rate risks. The Partnership records all derivative instruments on the balance sheet as either assets or liabilities measured at their fair value under the provisions of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities", as amended. SFAS 133 requires that changes in the fair value of derivative instruments 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" 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 16-Derivative Financial Instruments" for further discussion).
The Partnership formally documents at inception the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument used, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed and the method of measuring such ineffectiveness. On a continuing basis, the Partnership assesses whether the derivative instruments that are used as hedges are highly effective in offsetting changes in fair values or cash flows that are being hedged. If it is determined that a derivative instrument ceases to be a highly effective hedge, then the Partnership will discontinue hedge accounting prospectively.
Foreign Currency Translation
The financial statements of operating subsidiaries in Canada are prepared using the Canadian dollar as the functional currency. Balance sheet amounts are translated at the end of period exchange rate. Income statement and cash flow amounts are translated at the average exchange rate for the period. Adjustments from translating these financial statements into U.S. dollars are recognized in the equity section of the balance sheet under the caption, "accumulated other comprehensive income."
Net Income per Unit
Basic net income per limited partner unit is determined by dividing net income, after deducting the amount allocated to the general partner interest, by the weighted average number of outstanding limited partner units.
Diluted net income per limited partner unit is calculated in the same manner as basic net income per limited partner unit above, except that the weighted average number of outstanding limited partner units is increased to include the dilutive effect of outstanding options and restricted units by application
of the treasury stock method. Following is a reconciliation of the basic weighted average limited partner units to diluted weighted average limited partner units.
Allocation of Net Income
Net income is allocated to the Partnership's general partner and limited partners based on their respective interests in the Partnership. The Partnership's general partner has also been directly charged with specific costs that it assumed in connection with its acquisition by LBP and for which neither the Partnership nor the limited partners are responsible (see "Note 17-Allocation of Net Income").
Restricted Units and Unit Options
As permitted under Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation," the Partnership elected to measure costs for restricted units and unit options using the intrinsic value method, as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Compensation expense related to the restricted units is recognized by the Partnership over the vesting periods of the units. Accordingly, the compensation expense related to the restricted units that is allocable to the current reporting period has been recognized in the accompanying consolidated statements of income, and non-cash employee compensation related to the long-term incentive plan is included in "undistributed employee long-term incentive compensation" in the accompanying consolidated balance sheets. No compensation expense related to the unit options has been recognized in the accompanying consolidated financial statements. Had the Partnership determined compensation cost based on the fair value at the grant date for its unit options under SFAS 123, "Accounting for Stock-Based Compensation," net income would have been reduced less than $0.1 million in each of 2005, 2004 and 2003 and the effect on earnings per limited partner unit would have been less than $0.01 per limited partner unit in each of 2005, 2004 and 2003.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 123 (revised December 2004), Share-Based Payment (SFAS 123R). This Statement is a revision of SFAS No. 123. SFAS 123R establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123R is effective for the Partnership as of the beginning of the first interim period or annual reporting period that begins after June 15, 2005. There were no stock options or restricted stock units outstanding as of December 31, 2005 (see "Note 18-Long-Term Incentive Plan"). The Partnership will adopt SFAS 123R on January 1, 2006 for future grants.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, Exchanges of Nonmonetary Assets ("SFAS 153"). SFAS 153 addresses the measurement of exchanges of certain nonmonetary assets (except for certain exchanges of products or property held for sale in the ordinary course of business). It amends APB Opinion No. 29, Accounting for Nonmonetary Exchanges, and requires that nonmonetary exchanges be accounted for at the fair value of the assets exchanged, with gains or losses being recognized, if the fair value is determinable within reasonable limits and the
transaction has commercial substance, as defined in SFAS 153. The Partnership adopted SFAS 153 on July 1, 2005, and the adoption did not have a material impact on the consolidated financial statements.
On March 30, 2005 the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations("FIN 47"), to clarify the term conditional asset retirement obligation as that term is used in FASB Statement No. 143, Accounting for Asset Retirement Obligations. The Interpretation also clarifies when an entity has sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 was effective for us as of December 31, 2005. The adoption of FIN 47 did not have a material impact on the Partnership's financial statements.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections ("SFAS 154"). SFAS 154 replaces APB No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Changes in Interim Financial Statements. The Statement changes the accounting for, and reporting of, a change in accounting principle. SFAS 154 requires retrospective application to prior period's financial statements of voluntary changes in accounting principle and changes required by new accounting standards when the standard does not include specific transition provisions, unless it is impracticable to do so. SFAS 154 is effective for accounting changes and corrections of errors in fiscal years beginning after December 15, 2005. If required, the Partnership will apply the provisions of SFAS 154 in future periods.
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 issues addressed by the EITF are (i) the circumstances under which two or more exchange transactions involving inventory with the same counterparty should be viewed as a single exchange transaction for the purposes of evaluating the effect of APB No. 29; and (ii) whether there are circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF 04-13 is effective for new arrangements entered into in the reporting periods beginning after March 15, 2006, and to all inventory transactions that are completed after December 15, 2006, for arrangements entered into prior to March 15, 2006. The Partnership is in the process of determining the impact of EITF 04-13 on its financial statements, but does not expect it to have a material impact on its financial statements.
3. ACQUISITIONS
Acquisition Of Assets From Valero, L.P.
On September 30, 2005, the Partnership completed the purchase of certain terminal and pipeline assets from various subsidiaries of Valero, L.P. (the "Sellers") for an aggregate purchase price of $455.0 million, plus $11.5 million for the assumption of certain legal, environmental and operating liabilities and $3.7 million for closing costs (the "Valero Acquisition"). Valero, L.P. was required to divest these assets pursuant to an order from the Federal Trade Commission in connection with its acquisition of the Kaneb group of companies. The purchased assets consist of (i) the Martinez and Richmond terminals in the San Francisco, California area, (ii) the North Philadelphia, South Philadelphia and Paulsboro, New Jersey, terminals in the Philadelphia, Pennsylvania area, and (iii) a 550-mile refined products pipeline with four terminals in the U.S. Rocky Mountains (the "Valero Assets"). The Valero Acquisition was funded through a combination of the proceeds from a private placement of 4.3 million common units, a public equity offering of 5.2 million common units, a private placement of $175 million of senior unsecured notes, and borrowings under the Partnership's new revolving credit facility (See "Note 9-Long-term Debt" and "Note 15-Partner's Capital" for further discussion on these financing arrangements).
The Martinez and Richmond terminals currently have 4.1 million barrels of combined storage capacity. The terminals handle refined products, blend stocks and crude oil, and are connected to a network of owned and third-party pipelines that carry crude oil and light products to and from area
refineries. These terminals also receive and deliver crude oil and light products by marine vessel or barge. The Richmond terminal has a rail spur for delivery and receipt of light products and a truck rack for product delivery.
The North Philadelphia, South Philadelphia and Paulsboro terminals handle refined products and have a combined storage capacity of 3.1 million barrels. The terminals receive product via connections to third party pipelines and have truck racks for deliveries. The North Philadelphia and Paulsboro terminals can also deliver and receive products by marine vessel or barge.
The 550-mile Rocky Mountain Products Pipeline, formerly known as the West Pipeline System, consists of 550 miles of pipeline extending from Casper, Wyoming, east to Rapid City, South Dakota, and south to Colorado Springs, Colorado. There are products terminals at Rapid City, South Dakota, Cheyenne, Wyoming, and Denver and Colorado Springs, Colorado, with a combined storage capacity of 1.7 million barrels. The pipeline system has various segments with different receipt and delivery points.
The majority of the Rocky Mountain Products Pipeline was constructed in 1948, with extensions to Rapid City and Colorado Springs added in the 1960's. The South Philadelphia Terminal was constructed in 1938, the Richmond and Paulsboro terminals were constructed in 1953, and the Martinez and North Philadelphia terminals were constructed in 1973. Many improvements and facility additions have been made since the original startup of the operations. Additional tankage has been constructed and pipeline system and terminal improvements have been made over the years since their initial startup.
The Partnership has integrated the operations, maintenance, marketing and business development of the Rocky Mountain Products Pipeline with its existing pipeline activities in the Rocky Mountain Business Unit. It has similarly integrated the San Francisco area and Philadelphia area terminals with its existing pipeline and terminal activities in its West Coast Business Unit.
The Partnership did not acquire accounting software or hardware with the acquired assets. The Partnership has acquired and is implementing software associated with the complex task of volumetric and revenue accounting for the acquired assets, and uses its existing financial accounting software for other accounting functions. In addition, the Partnership did not acquire the pipeline control center or the software and other operating systems required for the Rocky Mountain Products Pipeline, and has installed new operating systems that are now being operated out of its Long Beach pipeline control center. The Seller agreed to provide all of these accounting, control center and operating services to the Partnership on a transition basis.
The acquired assets comprise only a portion of the total pipeline and terminal assets owned and operated by the Sellers in North America. The Sellers have other substantial pipeline and terminal assets that the Partnership did not acquire that are, or have been, operated and managed by the Seller's existing management team and operating and marketing staff. The acquired assets were not historically operated by the Sellers as a separate division or subsidiary. The Sellers, and prior to its merger with Valero, L.P., Kaneb Pipeline Partners, L.P. ("Kaneb"), operated these assets as part of its more extensive transportation and terminalling and refined products operations. As a result, neither the Sellers nor Kaneb maintained complete and separate financial statements for these assets as an independent business unit. The Partnership is making significant changes to the assets, and intends additional changes in the future, resulting in significant differences in operations and revenue generation. Additionally, differences in the Partnership's operating and marketing approach may result in it obtaining different productivity levels, results of operations and revenues than those historically achieved by the Sellers and Kaneb.
At the closing of the acquisition, the Partnership hired 76 of the Seller's employees directly involved in the operation of the acquired assets, including certain field level managerial and supervisory employees, operators, technicians, and engineers/project coordinators. The Partnership has hired
additional accounting, environmental, engineering, pipeline controllers and technical staff to support the acquired assets.
The acquisition was accounted for as an acquisition of assets, and not as an acquisition of a continuing business operation.
The consolidated statements of income include the results of the acquired assets from their acquisition date. Based upon independent appraisals of the fair values of the acquired assets, the following is a summary of the consideration paid and purchase price allocation (in thousands):
The Partnership is depreciating the purchased assets over their estimated useful lives of three to forty years based on the type of assets, which lives are similar to the Partnership's existing assets. Intangible assets are amortized over their estimated useful lives, which range from 15 to 40 years.
Purchase Of Crude Oil and Contracts
On July 1, 2005, Pacific Marketing and Transportation LLC, a wholly owned subsidiary of the Partnership, purchased certain crude oil contracts and crude oil inventories for approximately $3.8 million plus contingent payments over the next three and one-half years based on specified performance criteria. The Partnership will capitalize any such contingent payments as intangible assets and amortize them over three years.
Canadian Acquisitions
On May 11, 2004, the Partnership completed the acquisition of all of the outstanding shares of Rangeland Pipeline Company ("RPC"), Rangeland Marketing Company ("RMC") and Aurora Pipeline Company Ltd. ("Aurora"), the corporations that owned various components of the Rangeland system and the related marketing business from BP Canada Energy Company ("BP"). The Rangeland system is located in the province of Alberta, Canada. The purchase price for the shares of these companies was Cdn$130.1 million plus approximately Cdn$32.2 million for assumed liabilities, linefill, working capital and transaction costs. The aggregate purchase price was approximately U.S. $118.1 million and was funded through a combination of proceeds from the Partnership's March 30, 2004 equity offering and borrowings of Cdn$45 million. The acquisition was accounted for as an acquisition of assets.
On June 30, 2004, the Partnership completed the acquisition of the MAPL pipeline from Imperial Oil. The MAPL pipeline is located in Alberta, Canada, and connects with the Rangeland pipeline system. The purchase price for MAPL was Cdn$31.5 million, of which Cdn$5.0 million is payable June 30, 2007. In addition to the MAPL pipeline, the Partnership acquired linefill for Cdn$5.0 million. The aggregate purchase price, including assumed liabilities, linefill and transaction costs was approximately U.S. $27.0 million, most of which was funded from the Partnership's credit facility.
Following the acquisition, the MAPL pipeline assets were integrated into and are now operated as part of the Rangeland system.
Based upon independent appraisals of the fair values of the Rangeland and MAPL assets, the following is a summary of the consideration paid and purchase price allocation (U.S.$ in thousands):
Pacific Terminals Storage and Distribution System
On July 31, 2003, PT completed the acquisition of the storage and pipeline distribution system assets of Edison Pipeline and Terminal Company, a division of Southern California Edison Company. The PT storage and distribution system is used by the Partnership to serve the crude oil and other dark products storage and distribution needs of the refining, pipeline, and marine terminal industries in the Los Angeles Basin. The purchase was funded through $90.0 million of proceeds from the issuance of additional common units on August 25, 2003, and borrowings under the Partnership's revolving credit facility, and was treated as an asset purchase. Based upon independent appraisals of the fair values of the acquired assets, the following is a summary of the consideration paid and purchase price allocation (in thousands):
4. LINE 63 OIL RELEASE RESERVE
On March 23, 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63 when it was severed as a result of a landslide induced by heavy rainfall in the Pyramid Lake area of Los Angeles County. Over the period March 2005 through anticipated completion in June 2007, the Partnership expects to incur an estimated total of $25.6 million for oil containment and clean-up of the impacted areas, future monitoring costs, potential third-party claims and penalties, and other costs, excluding pipeline repair costs. As of December 31, 2005, the Partnership had incurred approximately $19.0 million of the total expected remediation costs related to the oil release for work performed through that date. The Partnership estimates that $4.4 million of the remaining remediation costs will be incurred in 2006 and $2.2 million (included in "Other liabilities" in the accompanying balance sheet) will be incurred in 2007. Additionally, in 2005 the Partnership expensed $0.7 million for the repair of Line 63 and incurred $2.2 million of Line 63 capital improvements.
The Partnership has a pollution liability insurance policy with a $2.0 million per-occurrence deductible that covers containment and clean-up costs, third-party claims and penalties. The insurance carrier has, subject to the terms of the insurance policy, acknowledged coverage of the incident and is processing and paying invoices related to the clean-up. The Partnership believes that, subject to the $2.0 million deductible, it will be entitled to recover substantially all of its clean-up costs and any third-party claims associated with the release. The Partnership's insurance coverage will not cover the cost to repair the pipeline. As of December 31, 2005, the Partnership has recovered $12.3 million from insurance and recorded receivables of $11.3 million for future insurance recoveries it deems probable, of which $2.2 million is considered long-term and is included in "Other assets, net" in the accompanying consolidated balance sheet.
The Partnership recorded $2.0 million in net costs in "Line 63 oil release costs" in the accompanying condensed consolidated financial statements for the year ended December 31, 2005. The $2.0 million net oil release costs consist of the $25.6 million of accrued costs relating to the release, net of insurance recovery of $12.3 million and accrued insurance receipts of $11.3 million.
Effective August 1, 2005, with the California Public Utilities Commission (the "CPUC") approval, the Partnership began collecting a temporary surcharge of $0.10 per barrel on its Line 63 long-haul tariff rates to recover its uninsured costs relating to this release together with other costs incurred or to be incurred as a result of problems caused by rain-related earth movement and stream erosion. The Partnership was required under the terms of the CPUC decision that approved the collection of the surcharge, to substantiate in subsequent advice letter filings with the CPUC that the actual costs incurred by the Partnership were necessary and reasonable and otherwise recoverable. The Partnership filed its advice letter on January 27, 2006, which was approved by the CPUC on February 22, 2006.
The foregoing estimates are based on facts known at the time of estimation and the Partnership's assessment of the ultimate outcome. Among the many uncertainties that impact the estimates are the necessary regulatory approvals for, and potential modification of, remediation plans, the ongoing assessment of the impact of soil and water contamination, changes in costs associated with environmental remediation services and equipment, and the possibility of third-party legal claims giving rise to additional expenses. Therefore, no assurance can be made that costs incurred in excess of this provision, if any, would not have a material adverse effect on the Partnership's financial condition, results of operations, or cash flows, though the Partnership believes that most, if not all, of any such excess cost, to the extent attributable to clean-up and third-party claims, would be recoverable through insurance. As new information becomes available in future periods, the Partnership may change its provision and recovery estimates.
5. PROPERTY AND EQUIPMENT
Property and equipment consists of the following amounts:
Depreciation expense for each of the three years in the period ended December 31, 2005, was $27.4 million, $23.4 million and $18.2 million, respectively.
6. INTANGIBLE ASSETS
SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. The Partnership assesses the useful lives of all intangible assets each reporting period to determine if adjustments are required. All of the Partnership's intangibles have finite lives and are amortized on a straight line basis over the expected lives of the intangibles. The weighted average expected life of intangibles at December 31, 2005 and 2004 was approximately 31.0 years and 38.5 years, respectively. Amortization expense on amortizable intangible assets was $2.0 million, $0.8 million and $0.6 million for the years ended December 31, 2005, 2004 and 2003, respectively. Intangible assets included in the accompanying balance sheet consist of the following:
The following table sets forth future estimated amortization expense on amortizable intangible assets as follows (in thousands):
7. INVESTMENT IN FRONTIER
RPL owns a 22.22% partnership interest in Frontier which is accounted for by the equity method of accounting. The summarized balance sheets and income statements are presented below (unaudited):
Balance Sheets
Statements of Income
The unamortized portion of the excess cost over the Partnership's share of net assets of Frontier was $6.2 million and $6.3 million at December 31, 2005 and 2004, respectively. This excess cost over the Partnership's share of net assets represents the difference between the historical cost and the fair
value of property and equipment at acquisition dates. The Partnership is amortizing this excess cost over the life of the related property and equipment.
8. RELATED PARTY TRANSACTIONS
Sale of The Anschutz Corporation's Interest in the Partnership
On March 3, 2005, Anschutz sold all of its interest in Pacific Energy GP, Inc. to LBP, which was formed by LBMB in connection with the purchase. The acquisition by LBP (the "LB Acquisition") included the 100% ownership interest in Pacific Energy GP, Inc., which owned (i) the 2% general partner interest in the Partnership and the incentive distribution rights, and (ii) 10,465,000 subordinated units of the Partnership which represented a then 34.6% limited partner interest in the Partnership. Immediately prior to the closing of the LB Acquisition, Pacific Energy GP, Inc. was converted to Pacific Energy GP, LLC, a Delaware limited liability company; and immediately after the closing of the LB Acquisition, Pacific Energy GP, LLC was converted to Pacific Energy GP, LP (the "General Partner"). Immediately following the consummation of the LB Acquisition, the General Partner distributed the 10,465,000 subordinated units of the Partnership to LBP.
In connection with the conversion of the Partnership's General Partner to a limited partnership, the General Partner ceased to have a board of directors, and is now managed by its general partner, Pacific Energy Management LLC, a Delaware limited liability company ("PEM" or the "Managing General Partner"), which is 100% owned by LBP. PEM has a board of directors (the "Board of Directors" or "Board") that manages the business and affairs of PEM and, thus, indirectly manages the business and affairs of the General Partner and the Partnership. All of the officers and employees of Pacific Energy GP, Inc. were transferred to fill the same positions with PEM, and the PEM Board established the same committees as had been maintained by Pacific Energy GP, Inc. prior to the LB Acquisition. PEM also adopted Pacific Energy GP, Inc.'s governance guidelines and its compensation structure and employee benefits plans and policies.
Additionally, on March 21, 2005, an affiliate of First Reserve Corporation ("First Reserve") acquired from LBMB a 30% partnership interest in LBP. LBMB and its affiliates continue to own a 70% partnership interest in LBP.
Lehman Brothers, Inc.
In connection with the purchase and associated financing of the Valero Acquisition including a private equity offering, public equity offering, senior notes offering and new credit facility, Lehman Brothers, Inc. and its affiliates provided advisory and underwriting services to the Partnership. Additionally, an affiliate of Lehman Brothers, Inc. was a participant in the syndicate that provided the Partnership's new senior secured credit facility. These agreements with Lehman Brothers, Inc. were reviewed and approved by the Conflicts Committee of the Board of Directors and the fees charged were customary for the types of services provided. For the period from March 3, 2005 through December 31, 2005, the Partnership incurred $9.9 million in fees with Lehman Brothers, Inc. and its affiliates, a portion of which was paid to non-affiliated financial institutions in the syndication of the New Credit Facility and in the public offering of equity.
Cost Reimbursements
Managing General Partner: The Partnership's Managing General Partner employs all U.S.-based employees. All employee expenses incurred by the Managing General Partner on behalf of the Partnership are charged back to the Partnership.
Special Agreement: On March 3, 2005, Douglas L. Polson, previously the Chairman of the Board of Directors of Pacific Energy GP, Inc., entered into a Special Agreement and a Consulting Agreement
with PEM. In accordance with the Special Agreement, Mr. Polson resigned as Chairman of the Board of Directors of Pacific Energy GP, Inc. effective March 3, 2005. Mr. Polson was paid approximately $0.9 million, representing accrued salary through March 3, 2005, accrued but unused vacation and payment in satisfaction of other obligations under his employment agreement. The latter portion of this payment was recorded as an expense in "Transaction costs" in the accompanying condensed consolidated income statements (see "Note 17-Allocation of Net Income"). LBP reimbursed this amount, which was recorded as a partner's capital contribution. Pursuant to the Consulting Agreement, Mr. Polson has agreed to perform advisory services to PEM from time to time as shall be mutually agreed between Mr. Polson and the Chief Executive Officer of PEM. In consideration for Mr. Polson's services under the Consulting Agreement, which has a one-year term, Mr. Polson receives a monthly consulting fee of $12,500 and reimbursement of all reasonable business expenses incurred or paid by Mr. Polson in the course of performing his duties thereunder.
LBP and Anschutz: LBP and Anschutz reimbursed the Partnership for certain other costs relating to the LB Acquisition. These included $1.2 million for the Consent Solicitation (as defined and further described in "Note 9-Long-Term Debt", below) and $0.3 million for legal and other expenses (also see "Note 17-Allocation of Net Income").
Other Related Party Transactions
Related party balances at December 31, 2005 and 2004 were as follows:
Prior to March 3, 2005, in the ordinary course of its operations, the Partnership engaged in various transactions with Anschutz and its affiliates. These transactions, which are more thoroughly described below, are summarized in the following table for the years ended December 31, 2005, 2004 and 2003:
Revenue from Related Parties
A subsidiary of Anschutz was a shipper on Line 2000 and was charged the published tariff rates applicable to "participating shippers" until March 31, 2003, when an agreement between the Anschutz subsidiary and a third party, the performance of which required the Anschutz subsidiary to ship on
Line 2000, was assigned to the Partnership for consideration equal to the value of transferred inventory. The agreement ended April 1, 2003. In addition, a subsidiary of Anschutz is a shipper on pipelines owned by RMPS and is charged published tariff rates.
RMPS serves as the contract operator for certain gas producing properties owned by a subsidiary of Anschutz in Wyoming and Utah, in exchange for which RMPS is reimbursed its direct costs of operation and is paid an annual fee of $0.3 million as compensation for the time spent by RMPS management and for other overhead services related to their activities. In addition, during 2003 and the first half of 2004, RMPS's trucking operation hauled water for a Anschutz subsidiary at rates equivalent to those charged to third parties.
RMPS also receives a management fee from Frontier in connection with time spent by RMPS management and for other services related to Frontier's pipeline's activities. RMPS received $0.8 million, $0.9 million and $0.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Expenses Paid to Related Parties
Pursuant to an easement agreement between PPS and Union Pacific Corporation ("UPC"), UPC provides the Partnership with access to its right-of-way for a portion of Line 2000 in return for an annual rental. Philip F. Anschutz, a director of the Partnership's General Partner until March 3, 2005, and sole stockholder of Anschutz Company, the indirect parent until March 3, 2005, of the Partnership's General Partner, is a director of UPC.
From mid-2002 through December 31, 2005, the Partnership utilized a financial accounting system owned and provided by Anschutz under a shared services arrangement. In addition, the Partnership from time to time until mid-2003 utilized the services of Anschutz's risk management personnel for acquiring the Partnership's insurance, and the Partnership's surety bonds were, until 2004, issued under Anschutz's bonding line. From January 2003 through December 31, 2005, Anschutz charged the Partnership a fee of $0.1 million per year for these services and together with any out-of-pocket costs. The fixed annual fee included all license, maintenance and employee costs associated with our use of the financial accounting system.
In January 2003, the Partnership began leasing office space from an affiliate of Anschutz, for a term of five years at an initial annual cost of $0.1 million. The lease was terminated in February 2006.
9. LONG-TERM DEBT
The Partnership's long-term debt obligations are shown below:
Principal payments due on long-term debt during each of the five years subsequent to December 31, 2005 are as follows (in thousands):
$400 million Senior Secured Credit Facility
On September 30, 2005, the Partnership entered into a new five-year $400 million senior secured revolving credit facility (the "New Credit Facility") that replaced the Partnership's previous U.S. and Canadian revolving credit facilities. The New Credit Facility is available for general Partnership purposes in the U.S. and Canada, including working capital, letters of credit and distributions to unitholders (subject to certain limitations). The New Credit Facility matures on September 30, 2010, but the Partnership may prepay all loans under the New Credit Facility without premium or penalty. Obligations under the New Credit Facility are guaranteed by all of the subsidiaries of the Partnership except those for which regulatory approval is required and are secured by substantially all of the assets of the Partnership, excluding property held by the non-guaranteeing subsidiaries. The New Credit Facility is recourse to the Partnership and the guarantors, but non-recourse to the General Partner.
Subject to certain limited exceptions, indebtedness under the New Credit Facility bears interest (at the Partnership's option) at either (i) the base rate, which is equal to the higher of the prime rate as
announced by Bank of America, N.A. or the Federal Funds rate plus 0.50% (or in the case of borrowings under the Canadian sub-facility described below, Canadian US dollar base rate or Canadian prime rate) each plus an applicable margin ranging from 0% to 0.75% or (ii) the Eurodollar rate plus an applicable margin ranging from 0.75% to 2.00%. The applicable margins fluctuate based on the Partnership's credit rating at any given time. In addition, the Partnership incurs a commitment fee which ranges from 0.1875% to 0.5000% per annum on the unused portion of the New Credit Facility.
Included in the New Credit Facility is a Canadian sub-facility for Rangeland Pipeline Company ("RPC"), one of the Partnership's Canadian subsidiaries. The Canadian sub-facility currently has a limit of U.S.$100 million, but can be adjusted from time to time by the Partnership. The Canadian sub-facility includes an option for RPC to receive loans in either U.S. dollars or Canadian dollars.
The New Credit Facility contains certain financial covenants and covenants limiting the ability of the Partnership to, among other things, incur or guarantee indebtedness, change ownership or structure, including mergers, consolidations, liquidations and dissolutions, sell or transfer assets and properties, and enter into a new line of business. At December 31, 2005, the Partnership was in compliance with all such covenants.
The Partnership provides certain suppliers with irrevocable standby letters of credit to secure its obligation for the purchase of crude oil. These letters of credit are issued under the Partnership's credit facility, and the liabilities with respect to these purchase obligations are recorded in "Accrued crude oil purchases" on the Partnership's balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to sixty-day periods and are terminated upon completion of each transaction. In addition, the Partnership provided a letter of credit to the seller of the MAPL pipeline to secure a note payable. At December 31, 2005 and 2004, The Partnership had outstanding letters of credit totaling approximately $14.8 million and $4.2 million, respectively.
As of December 31, 2005, in addition to $14.8 million of letters of credit, $140.8 million was outstanding under the New Credit Facility, including $55.8 million under the Canadian sub-facility, and there was $125.5 million of undrawn available credit.
The New Credit Facility was entered into with a syndicate of financial institutions, including an affiliate of Lehman Brothers, Inc., which is an affiliate of LBP (see "Note 8-Related Party Transactions").
71/8% Senior Notes Due June 2014
On June 16, 2004, the Partnership and its 100% owned subsidiary, Pacific Energy Finance Corporation, completed the sale of $250 million of 71/8% senior unsecured notes due June 15, 2014. The notes were sold in a private offering to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933 (the "Securities Act") and to non-U.S. persons under Regulation S of the Securities Act. In October 2004, the notes were exchanged for new notes with materially identical terms that have been registered under the Securities Act but are not listed on any securities exchange. The notes were issued at a discount of $4.4 million, resulting in an effective interest rate of 7.375%. Interest payments are due on June 15 and December 15 of each year. At any time prior to June 15, 2007, the Partnership has the option to redeem up to 35% of the aggregate principal amount of notes at a redemption price of 107.125% of the principal amount with the net cash proceeds of one or more
equity offerings. The Partnership has the option to redeem the notes, in whole or in part, at anytime on or after June 15, 2009 at the following redemption prices:
The notes are jointly and severally guaranteed by certain of the Partnership's subsidiaries, namely Pacific Energy Group LLC, Pacific Marketing and Transportation LLC, Pacific Atlantic Terminals LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, PEG Canada GP LLC and PEG Canada, L.P.
The indenture governing the notes contains certain covenants that, among other things, limit the Partnership's ability and the ability of its restricted subsidiaries to incur or guarantee indebtedness or issue certain types of preferred equity securities; sell assets; pay distributions on, redeem or repurchase Partnership units; or consolidate, merge or transfer all or substantially all of its assets. At December 31, 2005, the Partnership was in compliance with all such covenants.
Under the indenture governing the Partnership's 71/8% senior notes due 2014, the Partnership would have been required to make a "Change of Control Offer" to the holders of such notes if the LB Acquisition caused a rating decline by a credit rating agency. In order to avoid triggering the "Change of Control Offer" provision, the Partnership solicited the consent (the "Consent Solicitation") of the holders of the 71/8% notes to amend certain provisions of the Indenture, including an amendment to the definition of "Change of Control." The Consent Solicitation was completed on February 10, 2005 with a majority of the holders of the senior notes consenting to the adoption of the proposed amendments, and as such, the proposed amendments were approved. Thereafter, a supplemental indenture that incorporated the proposed amendments was executed by the parties to the indenture. Fees of $0.6 million paid to holders of the notes were capitalized and included in "Other assets, net" in the accompanying condensed consolidated balance sheet at December 31, 2005 and are being amortized over the remaining life of the 71/8% notes. Other solicitation-related fees and expenses of approximately $0.6 million are included in "Transaction costs" in the accompanying condensed consolidated statements of income. LBP and Anschutz reimbursed the Partnership for the entire cost of the Consent Solicitation, which reimbursement is recorded as a general partner's capital contribution (see "Note 8-Related Party Transactions").
61/4% Senior Notes Due 2015
On September 23, 2005, the Partnership and its 100% owned subsidiary, Pacific Energy Finance Corporation, completed the sale of $175 million of 61/4% senior unsecured notes due September 15, 2015. The notes were sold in a private offering to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933 and to non-U.S. persons under Regulation S of the Securities Act of 1933. In January 2006, the notes were exchanged for new notes with materially identical terms that have been registered under the Securities Act but are not listed on any securities exchange. The notes were sold for 99.544% of face value resulting in an effective interest rate of 6.3125% to maturity. Interest payments are due on March 15 and September 15 of each year, beginning on March 15, 2006.
The notes are jointly and severally guaranteed by the same Partnership subsidiaries that guarantee the 71/8% senior notes, due June 2014. At any time prior to September 15, 2008, the Partnership has the option to redeem up to 35% of the aggregate principal amount of notes at a redemption price of 106.25% of the principal amount with the net cash proceeds of one or more equity offerings. At any
time prior to September 15, 2010, the Partnership may redeem some or all of the notes at a price equal to 100% of the principal amount, plus a make-whole premium and accrued and unpaid interest, if any, to the date of redemption. The Partnership will also have the option to redeem the notes, in whole or in part, at any time on or after September 15, 2010 at the following redemption prices:
The indenture governing the notes contains certain covenants that, among other things, limit the Partnership's ability and the ability of its restricted subsidiaries to incur or guarantee indebtedness or issue certain types of preferred equity securities; sell assets; pay distributions on, redeem or repurchase Partnership units; or consolidate, merge or transfer all or substantially all of its assets. At December 31, 2005, the Partnership was in compliance with all such covenants.
Net proceeds from the issuance of the notes were $170.9 million after deducting the $0.8 million discount and offering expenses of $3.3 million. The net proceeds were used to partially fund the Valero Acquisition.
Future Payment for MAPL Assets
In connection with the purchase of the MAPL pipeline, the Partnership is obligated to pay the seller Cdn$5.0 million (U.S.$4.3 million) on June 30, 2007. The future payment was discounted at 5%. The carrying value of the obligation was Cdn$4.4 million (U.S.$4.0 million) at December 31, 2005.
10. WRITE OFF OF DEFERRED FINANCING COSTS AND INTEREST RATE SWAP TERMINATION EXPENSE
On June 16, 2004, in connection with the repayment of a term loan, the Partnership had a $2.3 million non-cash write-off of deferred financing costs and incurred a $0.6 million cash expense to terminate related interest rate swaps.
11. INCOME TAXES
In May 2004, the Partnership acquired the Rangeland Pipeline system (see "Note 3-Acquisitions"). The Partnership's 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 it unitholders. However, the Partnership's Canadian subsidiaries are taxable entities in Canada and are subject to Canadian federal and provincial income taxes. In addition, intercompany interest payments and repatriation of funds through dividends are subject to withholding tax.
Components of the income tax expense for the years ended December 31, 2005 and 2004 are as follows:
The difference between the statutory federal income tax rate and the Partnership's effective income tax rate is summarized as follows:
Deferred tax assets and liabilities result from the following:
The Partnership has $2.9 million of net operating loss carryforwards, of which $2.3 million will expire in the year 2014 and $0.6 million will expire in the year 2015. The Partnership believes it is more likely than not that the net operating loss carryforwards will be utilized prior to their expiration; therefore no valuation allowance is considered necessary.
12. ENVIRONMENTAL LIABILITIES
The Partnership is subject to numerous federal (U.S. and Canadian), state, provincial and local laws which regulate the discharge of materials into the environment or that otherwise relate to the protection of the environment. The following table presents the activity of the Partnership's environmental liabilities.
The actual future costs for environmental remediation activities will depend on, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the technology available and required to meet the various existing legal requirements, the nature and extent of future environmental laws, inflation rates and the determination of the Partnership's liability at multi-party sites, if any, in light of uncertainties with respect to joint and several liability, and the number, participation levels and financial viability of other potentially responsible parties.
13. CONTINGENCIES
In August, 2005, Rangeland Pipeline Company ("RPC"), a wholly-owned subsidiary of the Partnership, learned that a Statement of Claim was filed by Desiree Meier and Robert Meier in the Alberta Court of Queen's Bench, Judicial District of Red Deer, naming RPC as defendant, and alleging personal injury and property damage caused by an alleged release of petroleum substances onto plaintiff's land by a prior owner and operator of the pipeline that is currently owned and operated by the Partnership. The claim seeks Cdn$1 million (approximately U.S.$0.9 million at December 31, 2005) in general damages, Cdn$2 million (approximately U.S.$1.7 million at December 31, 2005) in special damages, and, in addition, unspecified amounts for punitive, exemplary and aggravated damages, costs and interest. The Statement of Claim has not been served on RPC, so RPC has not been required to file an answer. RPC believes the claim is without merit, and intends to vigorously defend against it. RPC also believes that certain of the claims, if successfully proven by the plaintiffs, would be liabilities retained by the pipeline's prior owner under the terms of the agreement whereby the Partnership acquired the pipeline in question.
In connection with the Valero Acquisition, the Partnership assumed responsibility for the defense of a lawsuit filed in 2003 against Support Terminals Services, Inc., ("ST Services") by ExxonMobil Corporation ("ExxonMobil") in New Jersey state court. The Partnership has also assumed any liability that might be imposed on ST Services as a result of the suit. In the suit, ExxonMobil seeks reimbursement of approximately $400,000 for remediation costs it has incurred, from GATX Corporation, Kinder Morgan Liquid Terminals, the successor in interest to GATX Terminals Corporation, and ST Services. ExxonMobil also seeks a ruling imposing liability for any future remediation and related liabilities on the same defendants. These costs are associated with the Paulsboro, New Jersey terminal that was acquired by the Partnership on September 30, 2005. ExxonMobil claims that the costs and future remediation requirements are related to releases at the site subsequent to its sale of the terminal to GATX in 1990 and that, therefore, any remaining remediation requirements are the responsibility of GATX Corporation, Kinder Morgan and ST Services. The Partnership believes the claims against ST Services are without merit, and intend to vigorously defend against them.
The Partnership is involved in various other regulatory disputes, litigation and claims arising out of its operations in the normal course of business (see also "Note 4-Line 63 Oil Release Reserve"). The Partnership is not currently a party to any legal or regulatory proceedings the resolution of which could be expected to have a material adverse effect on its business, financial condition, liquidity or results of operations.
14. COMMITMENTS
Leases
The Partnership is obligated under several noncancelable operating leases, primarily for the rental of office space, trucks and equipment, which expire through the year 2011. These leases generally require the Partnership to pay all operating costs such as maintenance. Rental expense for all operating leases during the years ended December 31, 2005, 2004 and 2003 amounted to $1.9 million,
$1.5 million and $1.2 million, respectively. Future minimum rental payments under noncancelable operating leases at December 31, 2005 are as follows (in thousands):
Right-of-Way Obligations
The Partnership has secured various rights-of-way for the pipeline systems under right-of-way agreements that provide for annual payments to third parties. Right-of-way payments, which are included in operating expenses, totaled $3.3 million, $3.4 million and $2.9 million in 2005, 2004 and 2003, respectively.
The Partnership operates under various right-of-way and franchise agreements, certain of which expire at various times through at least 2035. Due to the nature of the Partnership's operations, the Partnership expects to continue making payments and renewing the right-of-way agreements. As of December 31, 2005, future minimum payments under the Partnership's right-of-way agreements of $4.0 million in 2006, between $4.5 million and $5.1 million annually in 2007 through 2010 and approximately $67.3 million thereafter reflect the Partnership's commitment for the next 15 years, assuming the current right-of-way agreements will be renewed during that period. The annual amounts payable under various right-of-way agreements are subject to adjustments as described above as well as for the effects of inflation, which is estimated at 5% per year.
15. PARTNERS' CAPITAL
Common Units Outstanding
There were 31,448,931 common units outstanding at December 31, 2005, with the public unitholders owning 28,832,681 units and LB Pacific, LP owning 2,616,250 units.
Subordinated Units and Conversion
All of the 7,848,750 subordinated units outstanding at December 31, 2005 were owned by LB Pacific, LP. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available sufficient cash to pay the minimum quarterly distribution on the common units. The subordination period will generally expire on the first day of any quarter beginning after June 30, 2007 once certain financial tests are achieved. Prior to the end of the subordination period, 50% of the subordinated units (25% in respect of each quarter ending on or after June 30, 2005 and 2006) may convert into common units on a one-for-one basis. On August 12, 2005, pursuant to the terms of the Partnership's partnership agreement, 25% or 2,616,250 subordinated units were converted to common units on a one-for-one basis.
General Partner Interest
The Partnership's General Partner holds a 2% interest in the Partnership and is required to make additional capital contributions to the Partnership upon the issuance of any additional units, if necessary, to maintain its capital account balance equal to 2% of the total capital accounts of all partners.
Distributions
Within 45 days after the end of each quarter, the Partnership will distribute all of its available cash, if any, to unitholders of record on the applicable date and to its General Partner. Available cash is generally defined as all of the Partnership's cash and cash equivalents on hand at the end of each quarter less reserves established by the General Partner for future requirements. Cash distributions in each of the three years ended December 31, 2005 were as follows:
In January 2006, the Partnership declared a cash distribution of $0.555 per limited partner unit for the fourth quarter of 2005, which was paid in February 2006 to unitholders of record as of January 31, 2006.
The General Partner is entitled to incentive distributions in quarters when the limited partner distribution exceeds $0.5125 per unit. The February 2006 distribution was the first quarterly distribution to exceed $0.5125 per limited partner unit and, accordingly, the General Partner received an incentive distribution of approximately $255,000 in addition to its 2% interest distribution.
Public Equity Offerings
During the three years ended December 31, 2005, the Partnership completed the following public equity offerings of its common units:
Net proceeds from the September 2005 offering were used to partially fund the Valero Acquisition. Net proceeds from the March/April 2004 offering were used to partially fund the Rangeland acquisition and to repay borrowings under the U.S. revolving credit facility. Proceeds from the 2003 offering were used to repay indebtedness outstanding under PEG's revolving credit facility, which had been incurred in connection with the acquisition of PT storage and distribution system assets and to redeem 1,727,100 common units owned by the General Partner.
Private Equity Placement
On September 30, 2005, the Partnership sold 4,300,000 common units pursuant to a Common Unit Purchase Agreement with certain institutional investors at a price of $30.75 per unit. The Partnership
received net proceeds of $131.8 million from the sale of the common units including the General Partner's contribution of $2.7 million, which were used to partially fund the Valero Acquisition.
Shelf Registration Statements
On December 23, 2005, the Partnership and certain subsidiaries filed a universal shelf registration statement on Form S-3 with the SEC to register the issuance and sale, from time to time and in such amounts as is determined by the market conditions and needs of the Partnership, of up to $1.0 billion of common units of the Partnership and debt securities of both the Partnership and certain subsidiaries. The SEC declared the registration statement effective on January 12, 2006. In addition, we have $110 million available and remaining under our August 2003 universal shelf registration statement.
16. DERIVATIVE FINANCIAL INSTRUMENTS
The Partnership uses derivative financial instruments primarily to reduce its exposure to adverse fluctuations in commodity prices, interest rates and foreign exchange rates. The Partnership formally designates and documents such financial instrument as a hedge of a specific underlying exposure, as well as the risk management objectives and strategies for undertaking the hedge transactions. The Partnership formally assesses, both at the inception and at least quarterly thereafter, whether the financial instruments that are used in hedging transactions are effective at offsetting changes in either the fair value or cash flows of the related underlying exposure. All of the Partnership's derivatives are commonly used over-the-counter instruments with liquid markets or are traded on the New York Mercantile Exchange. The Partnership does not enter into derivative financial instruments for trading or speculative purposes.
Commodity Price Risk Hedging
The Partnership uses derivative instruments (principally futures and options) to hedge its exposure to market price volatility related to its inventory or future sales of crude oil. Derivatives used to hedge market price volatility related to inventory are generally designated as fair value hedges, and derivatives related to future sale of crude oil are generally classified as cash flow hedges. Derivative instruments are included in other assets in the accompanying consolidated balance sheets.
Changes in the fair value of the Partnership's derivative instruments related to crude oil inventory are recognized in net income. For the years ended December 31, 2005, 2004 and 2003, "crude oil sales, net of purchases" were net of $0.8 million, $2.7 million and $0.3 million in losses, respectively, reflecting changes in the fair value of derivative instruments held as hedges related to crude oil marketing activities. Losses on derivatives were generally offset by gains in physical crude oil inventory positions. Changes in the fair value of the Partnership's derivative instruments related to the future sale of crude oil, which are generally for one year or less, are deferred and reflected in "accumulated other comprehensive income," a component of partners' capital, until the related revenue is reflected in the consolidated statements of income. As of December 31, 2005, a $0.1 million loss relating to the change in the fair value of highly effective derivative instruments was included in "accumulated other comprehensive income" and is expected to be reclassified to earnings in 2006. Since these amounts are 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. There were immaterial amounts of ineffectiveness associated with crude oil hedging in 2005, 2004 and 2003, respectively.
Interest Rate Risk Hedging
In connection with the issuance of its 71/8% senior notes due 2014, the Partnership entered into interest rate swap agreements with an aggregate notional principal amount of $80.0 million to receive interest at a fixed rate of 71/8% and to pay interest at an average variable rate of six month LIBOR
plus 1.6681% (set in advance or in arrears depending on the swap transaction). The interest rate swaps mature in June 2014 and are callable at the same dates and terms as the 71/8% senior notes. The Partnership designated these swaps as a hedge of the change in the Senior Notes fair value attributable to changes in the six month LIBOR interest rate. Changes in fair values of the interest rate swaps are recorded into earnings each period. Similarly, changes in the 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. At December 31, 2005, the Partnership recorded an increase of $0.6 million in the fair value of interest rate swaps. During the year ended December 31, 2005, the Partnership recognized reductions in interest expense of $1.3 million related to the difference between the fixed rate and the floating rate of interest on the interest rate swaps. As of December 31, 2005 and 2004, the Partnership had immaterial amounts of hedge ineffectiveness relating to these interest rate swaps.
In the third quarter of 2002, the Partnership entered into interest rate swap agreements that were to mature in 2007 and 2009 with a notional amount of $170.0 million. The Partnership designated these swaps as a hedge of its exposure to variability in future cash flows attributable to the LIBOR interest payments due on $170.0 million outstanding under a term loan facility. The average swap rate on this $170.0 million of debt was approximately 4.25%, resulting in an all-in interest rate on the $170.0 million of debt of approximately 6.50%. In June 2004, in conjunction with the issuance of the 71/8% Senior Notes and the repayment of the term loan, the Partnership bought back the swaps for a loss of $0.6 million.
Currency Exchange Rate Risk Hedging
The purpose of the Partnership's foreign currency hedging activities is to reduce the risk that the Partnership's cash inflows resulting from interest payments from its Canadian subsidiaries on intercompany debt will be adversely affected by changes in the U.S./Canadian exchange rate.
The Partnership entered into forward exchange contracts to hedge receipt of forecasted interest payments denominated in Canadian dollars. The effective portion of the change in fair value of these contracts, which have been designated as a cash flow hedge, is reported in "Accumulated other comprehensive income" and will be reclassified into earnings in "Other income" in the period the hedged transaction affects earnings. The ineffective portion, if any, of the change in fair value of this instrument will be immediately recognized in earnings. These foreign exchange contracts are as follows:
As of December 31, 2005, a $0.2 million loss relating to foreign exchange contracts was deferred and included in "accumulated other comprehensive income" and is expected to be reclassified into earnings in 2006. For the year ended December 31, 2005, no gains or losses were recognized in the income statement for these foreign exchange contracts.
Credit Risks
By using derivative financial instruments to hedge exposures related to changes in commodity prices, interest rates and currency exchange rates, the Partnership exposes itself to market risk and credit risk. Market risk is the risk of loss arising from the adverse effect on the value of a financial instrument that results from changes in commodity prices, interest rates or currency exchange rates. The market risk associated with price volatility is managed by established parameters that limit the types and degree of market risk that may be undertaken.
Credit risk is the risk of loss arising from the failure of the derivative agreement counterparty to perform under the terms of the derivative agreement. When the fair value of a derivative agreement is positive, the counterparty is liable to the Partnership, which creates credit risk for the Partnership. When the fair value of a derivative agreement is negative, the Partnership is liable to the counterparty and, therefore, it creates credit risk for the counterparty. The counterparties the Partnership transacts with are large, well known companies in the industry or large creditworthy financial institutions. As such, the Partnership believes its exposure to counterparty credit risk is low. Nonetheless, there can be no assurance as to the performance of a counterparty.
Fair Value of Financial Instruments
The carrying amount and fair values of financial instruments are as follows:
As of December 31, 2005 and 2004, the carrying amounts of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts of the revolving credit facilities approximate fair value primarily because the interest rates fluctuate with prevailing market rates. The interest rates on the 71/8% senior notes due 2014 and the 61/4% senior notes due 2015 are fixed and the fair value is determined from a broker's price quote at December 31, 2005.
The carrying amount of derivative financial instruments represents fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. The Partnership's fair values of crude oil hedging futures are based on Reuters quoted market prices on the NYMEX. Interest rate swaps and foreign exchange contracts fair values are based on the prevailing market price at which the positions could be liquidated.
17. ALLOCATION OF NET INCOME
The allocation of net income between the Partnership's General Partner and limited partners is as follows.
LBP and Anschutz reimbursed the Partnership for certain costs incurred in connection with the LB Acquisition. The Partnership was reimbursed $1.2 million for costs incurred in connection with the Consent Solicitation, $0.3 million of legal and other costs and $0.9 million relating to severance costs (see "Note 8-Related Party Transactions"), for a total of $2.4 million. Of the $1.2 million incurred for the consent solicitation, $0.6 million was capitalized as deferred financing costs (and did not affect the income allocation) and $0.6 million was expensed.
18. LONG-TERM INCENTIVE PLAN
In 2002, the General Partner adopted the Long-Term Incentive Plan (the "Plan") for employees and affiliates who perform services for the Partnership. The Plan consists of two components, a restricted unit plan and a unit option plan. The Plan was amended in 2006. The Plan currently permits the granting of an aggregate of 1,750,000 restricted units and unit options and is administered by the Compensation Committee of the Managing General Partner, subject to approval by the Managing General Partner's Board of Directors. The Managing General Partner's Board of Directors in its discretion may terminate the Plan at any time with respect to any restricted units for which a grant has not yet been made. The Managing General Partner's Board of Directors also reserves the right to alter or amend the Plan from time to time, including 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 which would materially impair the rights of the participant without the consent of such participant. As the restricted units vest, the Managing General Partner has the option to acquire common units in the open market for delivery to the recipient or distribute newly issued common units from the Partnership. In all cases, the Managing General Partner is reimbursed by the Partnership for such expenditures.
Restricted unit activity during the years ended December 31, 2005, 2004 and 2003 was as follows:
(1)Includes units relinquished in satisfaction of withholding taxes. The Partnership recognized $0.2 million, $2.1 million and $3.2 million of compensation expense associated with these grants in 2005, 2004 and 2003.
On March 3, 2005, in connection with the LB Acquisition and the change in control of the Partnership's General Partner, all restricted units outstanding under the Partnership's Long-Term Incentive Plan immediately vested pursuant to the terms of the grants. The Partnership issued 99,583 common units and recognized a compensation expense of $3.1 million, which is included in "Accelerated long-term incentive plan compensation expense" in the accompanying condensed consolidated statements of income.
In addition, Canadian employees of the Partnership participate in a separate Phantom Unit Plan, which upon vesting provides for payment in cash for the equivalent of the Partnership's unit on the vesting date. In 2004, the General partner granted 15,000 phantom units to certain key employees which were to vest over five years from the date of grant. These phantom units also became immediately vested with the change in control of the Partnership's General Partner.
In December 2002, the General Partner granted 50,000 common unit options with a 10-year term. The unit options were granted with an exercise price of $19.50 per unit, which was equal to the fair market value at the date of grant and vested in 2003 and 2004. On July 8, 2005, these options were exercised, 8,149 common units were withheld to cover withholding taxes and the Partnership issued 41,851 new common units.
The Partnership applied APB Opinion No. 25, "Accounting for Stock Issued to Employees," and, accordingly, no compensation expense was recognized for its unit options in the financial statements.
In January 2006, the General Partner awarded restricted units to key employees that vest over a three-year period, beginning on March 1, 2006, and that are also subject to meeting annual financial performance objectives. The financial measure used is the Partnership's distributable cash flow per unit, as determined by the Compensation Committee, for the calendar year preceding each of the three annual vesting dates. The number of units to be delivered in any year, if any, will be a portion of the number vested on March 1 of that year based on accomplishment of performance targets for the previous calendar year. The Partnership will apply the accounting treatment under FAS 123R to these restricted units awards beginning on January 1, 2006.
19. EMPLOYEE BENEFIT PLANS
The General Partner sponsors a defined contribution 401(k) plan for its U.S. based employees whereby eligible employees may contribute up to 18% of their annual compensation to the plan, subject to certain defined limits. The General Partner matches employee contributions up to 6% to 12%, depending on years of service, of the employee's annual compensation. Total employer contributions to the plan were $1.0 million, $0.9 million and $1.0 million, for 2005, 2004 and 2003 respectively.
The Partnership's Canadian subsidiaries sponsor an employee savings plan (the "Savings Plan") and a defined contribution plan. Under the Savings Plan eligible employees may contribute a percentage of their salary to the Savings Plan. The Partnership's Canadian subsidiaries provide matching contributions between 1% and 6% depending on years of service. The defined contribution plan requires the Canadian subsidiaries to make a contribution to a tax-deferred account established in an employee's name. Employee contributions to the defined contribution plan are not required nor permitted. The Canadian subsidiaries make contributions of between 2% and 6% of an employee's annual compensation depending on years of service. Contributions are limited by the Canada Customs and Revenue Agency to Cdn$18,000 in 2006 for any employee. Total employer contributions to the plan for 2005 and 2004 were Cdn$0.4 million and Cdn$0.2 million.
20. SEGMENT INFORMATION
The Partnership's business and operations are organized into two business segments: the West Coast Business Unit and the Rocky Mountain Business Unit. The West Coast Business Unit includes: (i) Pacific Pipeline System LLC, owner of Line 2000 and Line 63, (ii) Pacific Marketing and Transportation LLC, owner of the PMT gathering system, (iii) Pacific Terminals LLC, owner of the Pacific Terminals storage and distribution system, which was acquired on July 31, 2003, and (iv) Pacific Atlantic Terminals LLC, which was formed for the purpose of holding the California and East Coast terminal assets the Partnership acquired in the Valero Acquisition on September 30, 2005. The Rocky Mountain Business Unit includes: (i) Rocky Mountain Pipeline System LLC, owner of the Partnership's interest in various pipelines that make up the Western Corridor and Salt Lake City Core systems and the Rocky Mountain Products Pipeline, which was acquired in the Valero Acquisition on September 30, 2005, (ii) Ranch Pipeline LLC, the owner of a 22.22% partnership interest in Frontier Pipeline Company, and (iii) PEG Canada, L.P. and its Canadian subsidiaries, which own and operate the Rangeland system (which was acquired on May 11, 2004). General and administrative costs, which consist of executive management, accounting and finance, human resources, information technology, investor relations, legal, and business development, are not allocated to the individual business units. Information regarding these two business units is summarized below:
(1)Includes the revenue of Pacific Terminals storage and distribution system, which Pacific Terminals acquired on July 31, 2003.
(2)Includes the revenue of the Rangeland system, which was acquired on May 11, 2004 and June 30, 2004.
(3)The above amounts are net of purchases of $623,115, $402,283 and $358,454 for 2005, 2004 and 2003, respectively.
(4)See "Note 4-Line 63 Oil Release Reserve" for further information.
(5)The following is a reconciliation of operating income as stated above to the statements of income:
(6)Identifiable segment assets do not include assets related to the Partnership's corporate activity. As of December 31, 2005, 2004 and 2003, corporate related assets were $49,107, $31,875 and $19,174, respectively.
(7)Capital expenditures do not include the Pier 400 project and other parent-level related capital expenditures. Pier 400 project and other parent-level related capital expenditures were $8,695, $5,351, and $5,451 as of December 31, 2005, 2004, and 2003, respectively.
Geographic Data
Set forth below are revenues and identifiable assets attributable to the United States and Canada for the years ended December 31, 2005 and 2004:
21. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
Certain of the Partnership's 100% owned subsidiaries have issued full, unconditional, and joint and several guarantees of the 71/8% senior notes due 2014 and the 61/4% senior notes due 2015 (the "Senior Notes"). Given that certain, but not all subsidiaries of the Partnership are guarantors of its Senior Notes, the Partnership is required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, the Partnership is referred to as "Parent", while the "Guarantor Subsidiaries" are Rocky Mountain Pipeline System LLC, Pacific Marketing and Transportation LLC, Pacific Atlantic Terminals LLC, Ranch Pipeline LLC, PEG Canada GP LLC, PEG Canada, L.P. and Pacific Energy Group LLC, and "Non-Guarantor Subsidiaries" are Pacific Pipeline System LLC, Pacific Terminals LLC, Rangeland Pipeline Company, Rangeland Marketing Company, Rangeland Northern Pipeline Company, Rangeland Pipeline Partnership and Aurora Pipeline Company, Ltd.
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:
(1)General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.
(1)General and administrative expense is not currently allocated between Guarantor and Non-Guarantor Subsidiaries for financial reporting purposes.
22. QUARTERLY FINANCIAL DATA (unaudited)