Description
Plains All Amer. Director GARY R PETERSEN bought 5000 shares on 5-17-2012 at $ 79.47
BUSINESS OVERVIEW
Business Strategy
Our principal business strategy is to provide competitive and efficient midstream transportation, terminalling, storage, processing, fractionation and supply and logistics services to our producer, refiner and other customers. Toward this end, we endeavor to address regional supply and demand imbalances for crude oil, refined products, NGL and natural gas in the United States and Canada by combining the strategic location and capabilities of our transportation, terminalling, storage, processing and fractionation assets with our extensive supply, logistics and distribution expertise.
We believe successful execution of this strategy will enable us to generate sustainable earnings and cash flow. We intend to manage and grow our business by:
• optimizing our existing assets and realizing cost efficiencies through operational improvements;
• using our transportation, terminalling, storage, processing and fractionation assets in conjunction with our supply and logistics activities to capitalize on inefficient energy markets and to address physical market imbalances, mitigate inherent risks and increase margin;
• developing and implementing internal growth projects that (i) address evolving crude oil, refined products, natural gas and NGL needs in the midstream transportation and infrastructure sector and (ii) are well positioned to benefit from long-term industry trends and opportunities;
• selectively pursuing strategic and accretive acquisitions that complement our existing asset base and distribution capabilities; and
• capitalizing on the anticipated long-term growth in demand for natural gas storage services in North America by owning and operating high-quality natural gas storage facilities and providing our current and future customers reliable, competitive and flexible natural gas storage and related services through our ownership interest in PNG.
Financial Strategy
Targeted Credit Profile
We believe that a major factor in our continued success is our ability to maintain a competitive cost of capital and access to the capital markets. In that regard, we intend to maintain a credit profile that we believe is consistent with our investment grade credit rating. We have targeted a general credit profile with the following attributes:
• an average long-term debt-to-total capitalization ratio of approximately 45% to 50%;
• a long-term debt-to-adjusted EBITDA multiple averaging between 3.5x and 4.0x (Adjusted EBITDA is earnings before interest, taxes, depreciation and amortization, equity compensation plan charges, gains and losses from derivative activities and other selected items that impact comparability. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Non-GAAP Financial Measures” for a discussion of our selected items that impact comparability and our non-GAAP measures.);
• an average total debt-to-total capitalization ratio of approximately 60%; and
• an average adjusted EBITDA-to-interest coverage multiple of approximately 3.3x or better.
The first two of these four metrics include long-term debt as a critical measure. In certain market conditions, we also incur short-term debt in connection with our supply and logistics activities that involve the simultaneous purchase and forward sale of crude oil, NGL and natural gas. The crude oil, NGL and natural gas purchased in these transactions are hedged. We do not consider the working capital borrowings associated with these activities to be part of our long-term capital structure. These borrowings are self-liquidating as they are repaid with sales proceeds. We also incur short-term debt to fund New York Mercantile Exchange (“NYMEX”) and IntercontinentalExchange (“ICE”) margin requirements.
In order for us to maintain our targeted credit profile and achieve growth through internal growth projects and acquisitions, we intend to fund 55% of the capital requirements associated with these activities with equity and cash flow in excess of distributions. From time to time, we may be outside the parameters of our targeted credit profile as, in certain cases, these capital expenditures and acquisitions may be financed initially using debt or there may be delays in realizing anticipated synergies from acquisitions or contributions from capital expansion projects to adjusted EBITDA.
Competitive Strengths
We believe that the following competitive strengths position us to successfully execute our principal business strategy:
• Many of our transportation segment and facilities segment assets are strategically located and operationally flexible. The majority of our primary transportation segment assets are in crude oil service, are located in well-established oil producing regions and transportation corridors and are connected, directly or indirectly, with our facilities segment assets located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets where we have strong business relationships.
• We possess specialized crude oil market knowledge. We believe our business relationships with participants in various phases of the crude oil distribution chain, from crude oil producers to refiners, as well as our own industry expertise, provide us with an extensive understanding of the North American physical crude oil markets.
• Our supply and logistics activities typically generate a base level of margin with the opportunity to realize incremental margins. We believe the variety of activities executed within our supply and logistics segment in combination with our risk management strategies provides us with a balance that generally affords us the flexibility to maintain a base level of margin in a variety of market conditions (subject to the effects of seasonality). In certain circumstances, we are able to realize incremental margins during volatile market conditions.
• We have the evaluation, integration and engineering skill sets and the financial flexibility to continue to pursue acquisition and expansion opportunities. Over the past fourteen years, we have completed and integrated over 70 acquisitions with an aggregate purchase price of approximately $8.2 billion. We have also implemented internal expansion capital projects totaling approximately $3.0 billion. In addition, we believe we have resources to finance future strategic expansion and acquisition opportunities. As of December 31, 2011, we had over $3.6 billion available under our committed credit facilities, subject to continued covenant compliance.
• We have an experienced management team whose interests are aligned with those of our unitholders. Our executive management team has an average of 27 years industry experience, and an average of 16 years with us or our predecessors and affiliates. In addition, through their ownership of common units, indirect interests in our general partner, grants of phantom units and the Class B units in Plains AAP, L.P., our management team has a vested interest in our continued success.
Acquisitions
The acquisition of assets and businesses that are strategic and complementary to our existing operations constitutes an integral component of our business strategy and growth objective. Such assets and businesses include crude oil related assets, refined products assets, NGL assets and natural gas storage assets, as well as other energy transportation related assets that have characteristics and opportunities similar to these business lines and enable us to leverage our asset base, knowledge base and skill sets.
Ongoing Acquisition Activities
Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase of assets and operations that are strategic and complementary to our existing operations. In addition, we have in the past evaluated and pursued, and intend in the future to evaluate and pursue, other energy-related assets that have characteristics and opportunities similar to our existing business lines and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, could have a material effect on our financial condition and results of operations.
We typically do not announce a transaction until after we have executed a definitive acquisition agreement. However, in certain cases in order to protect our business interests or for other reasons, we may defer public announcement of an acquisition until closing or a later date. Past experience has demonstrated that discussions and negotiations regarding a potential acquisition can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive acquisition agreement will be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition efforts will be successful. Although we expect the acquisitions we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. See Item 1A. “Risk Factors—Risks Related to Our Business—If we do not make acquisitions or if we make acquisitions that fail to perform as anticipated, our future growth may be limited” and “—Our acquisition strategy involves risks that may adversely affect our business.”
Pending BP NGL Acquisition. On December 1, 2011, we entered into a definitive agreement to acquire all outstanding shares of BP Canada Energy Company, a wholly owned subsidiary of BP Corporation North America Inc. (“BP North America”). Total consideration for the acquisition, which will be based on an October 1, 2011 effective date, is approximately $1.67 billion, subject to working capital and other adjustments. A cash deposit of $50 million was paid upon signing, and the balance, plus 2% interest from October 1, 2011, is payable in cash upon closing. Subject to Canadian and U.S. regulatory approvals and other customary closing conditions, the acquisition is expected to close in the second quarter of 2012.
Upon completion of this acquisition, we will become the indirect owner of all of BP North America’s Canadian-based NGL business and certain of BP North America’s NGL assets located in the upper-Midwest United States (collectively the “BP NGL Assets”). The BP NGL Assets to be acquired include varying ownership interests and contractual rights relating to approximately 2,600 miles of NGL pipelines; approximately 20 million barrels of NGL storage capacity; seven fractionation plants with an aggregate net capacity of approximately 232,000 barrels per day; four straddle plants and two field gas processing plants with an aggregate net capacity of approximately six Bcf per day; and long-term and seasonal NGL inventories of approximately 10 million barrels as of October 1, 2011. Certain of these pipelines and storage assets are currently inactive. The acquired business also includes various third-party supply contracts at other field gas processing plants and a supply contract relating to a third-party owned straddle plant with throughput capacity of 2.5 Bcf per day, shipping arrangements on third-party NGL pipelines and long-term leases on 720 rail cars used to move product among various locations. Collectively, these assets and activities provide access to approximately 140,000 to 150,000 barrels per day of NGL supply that are transported through an integrated network to fractionation facilities and markets in Western and Eastern Canada and in the U.S. Subject to closing the transaction, we have also entered into an Integrated Supply and Trading Agreement, pursuant to which an affiliate of BP North America will, for a period of two years following the closing of the acquisition, continue to provide sourcing services for gas supply to feed certain of the straddle plants to be acquired as a result of the acquisition.
Crude Oil Market Overview
The definition of a commodity is a “mass-produced unspecialized product” and implies the attribute of fungibility. Crude oil is typically referred to as a commodity; however, it is neither unspecialized nor fungible. The crude slate available to U.S. and world-wide refineries consists of a substantial number of different grades and varieties of crude oil. Each crude grade has distinguishing physical properties. For example, specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content, along with other characteristics, collectively result in varying economic attributes. In many cases, these factors result in the need for such grades to be batched or segregated in the transportation and storage processes, blended to precise specifications or adjusted in value.
The lack of fungibility of the various grades of crude oil creates logistical transportation, terminalling and storage challenges and inefficiencies associated with regional volumetric supply and demand imbalances. These logistical inefficiencies are created as certain qualities of crude oil are indigenous to particular regions or countries. Also, each refinery has a distinct configuration of process units designed to handle particular grades of crude oil. The relative yields and the cost to obtain, transport and process the crude oil drives the refinery’s choice of feedstock. In addition, from time to time, natural disasters and geopolitical factors such as hurricanes, earthquakes, tsunamis, inclement weather, labor strikes, refinery disruptions, embargoes and armed conflicts may impact supply, demand and transportation and storage logistics.
Our assets and our business strategy are designed to serve our producer and refiner customers by addressing regional crude oil supply and demand imbalances that exist in the United States and Canada. The nature and extent of these imbalances change from time to time as a result of a variety of factors, including regional production declines and/or increases; refinery expansions, modifications and shut-downs; available transportation and storage capacity and government mandates and related regulatory factors.
For the 20-year time period beginning in 1985 through 2004, U.S. refinery demand for crude oil increased approximately 29% from approximately 12.0 million barrels per day to approximately 15.5 million barrels per day. U.S. refinery demand for crude oil remained effectively flat from 2005 through 2007 at around 15.5 million barrels per day. Largely as a result of a major economic slowdown and recession, from 2008 to 2011 total U.S. petroleum consumption declined and refinery demand decreased, averaging approximately 14.8 million barrels per day for the 12 months ended October 2011. Of this amount, approximately 5.7 million barrels per day were produced domestically. Accordingly, for the 12 months ended October 2011, approximately 9.1 million barrels per day of the crude oil used by U.S. refineries were imported. This level of crude oil imports represents a meaningful change in a multi-year trend where foreign imports of crude oil tripled over a 23-year period, from approximately 3.2 million barrels per day in 1985 to approximately 10.1 million barrels per day from 2005-2007. Reduced domestic demand for petroleum products from end users and competitive challenges faced by certain U.S. refineries with limited access to domestic feedstocks as well as increased use of ethanol for blending in gasoline have been major factors contributing to the drop in refinery demand for crude oil, partially offset by rising refined products exports. Since 2000, ethanol production has grown from approximately 100,000 barrels per day to approximately 900,000 barrels per day for the 12 months ended October 2011. Growth in ethanol and other renewable fuel production is expected to continue primarily due to government mandates on production. The EIA is currently forecasting a continued gradual decline in foreign crude imports from current levels, which is attributable to increased domestic production and increased supply from other liquid products, including ethanol and biodiesel.
As a result of advances in horizontal drilling and fracturing technology over the last several years and their application to various large scale resource plays, certain historical trends are being influenced. For example, PADD II production increased beginning in 2005 and as of early 2012 is estimated to be over 800,000 barrels per day, nearly double 2004’s level. This increase is being driven mainly by increased production from the Bakken oil formation in North Dakota using advanced horizontal drilling and fracturing technology.
More recently, other parts of the U.S. have experienced increased production volumes from mature producing areas such as the Rockies, the Permian Basin in West Texas, as well as less developed areas such as the Eagle Ford Shale in South Texas. Actual and anticipated production increases in multiple areas combined with actual and expected increased imports from Canada has strained or is expected to strain existing transportation and terminalling infrastructure in multiple areas. These developments are also resulting in changes to historical trends with respect to crude oil movements between regions of the U.S. For example, the quantity of crude oil transported from the Gulf Coast area into PADD II has declined, but the overall change in crude oil flows has resulted in an increased demand for storage and terminalling services at Cushing, Oklahoma and Patoka, Illinois.
The quality of the increasing crude oil volumes, which are generally lighter (higher gravity) and sweeter (lower sulfur content) than previous production, is exacerbating the demands placed on existing infrastructure. Notably, this change in crude oil quality is in stark contrast to the sizeable, multi-year investments made by a number of U.S. refining companies in order to expand their capabilities to process heavier, sourer grades of crude oil, which caused differentials between crude oil grades and qualities to change relative to historical levels and become much more dynamic and volatile. The combination of (i) a significant increase in North American production volumes, (ii) a change in crude oil qualities and related differentials and (iii) a high utilization of existing pipeline and terminal infrastructure have stimulated multiple industry initiatives to build new pipeline and terminal infrastructure, convert certain pipeline assets to alternative service or reverse flows and expand the use of trucks, rail and barges for the movement of crude oil.
Overall, volatility in various aspects of the crude oil market including absolute price, market structure and grade and location differentials has increased over time and we expect this volatility to persist. Some factors that we believe are causing and will continue to cause volatility in the market include:
• the multi-year narrowing of the gap between supply and demand in North America;
• fluctuations in international supply and demand related to the economic environment, geopolitical events and armed conflicts;
• regional supply and demand imbalances and changes in refinery capacity and specific capabilities;
• significant fluctuations in absolute price as well as grade and location differentials;
• political instability in critical producing nations; and
• policy decisions made by various governments around the world attempting to navigate energy challenges.
The complexity and volatility of the crude oil market creates opportunities to solve the logistical inefficiencies inherent in the business.
Refined Products Market Overview
After transport to a refinery, the crude oil is processed into different petroleum products. These “refined products” fall into three major categories: transportation fuels such as motor gasoline and distillate fuel oil (diesel fuel and jet fuel); finished non-fuel products such as solvents, lubricating oils and asphalt; and feedstocks for the petrochemical industry such as naphtha and various refinery gases. Demand is greatest for transportation fuels, particularly motor gasoline.
The characteristics of the gasoline produced depend upon the setup of the refinery at which it is produced. Gasoline characteristics are also impacted by other ingredients that may be blended into it, such as ethanol and octane enhancers. The performance of the gasoline must meet strictly defined industry standards and environmental regulations that vary based on season and location.
After crude oil is refined into gasoline and other petroleum products, the products are distributed to consumers. The majority of products are shipped by pipeline to storage terminals near consuming areas, and then loaded into trucks for delivery to gasoline stations and end users. Products that are used as feedstocks are typically transported by pipeline or barges to chemical plants.
Demand for refined products has generally been affected by price levels, economic growth trends , conservation, fuel efficiency mandates and, to a lesser extent, weather conditions. According to the EIA, petroleum consumption in the United States rose from approximately 15.7 million barrels per day in 1985 to an average of approximately 20.7 million barrels during the four-year period ending with 2007. From 2008 through the 12 months ended October 2011, petroleum consumption averaged approximately 19.1 million barrels per day, an approximate 8% decrease from peak levels, largely d ue to the economic weakness. Given this decreased demand for refined products , the increased use of ethanol and other renewable fuels and the resulting excess refining capacity, a number of U.S. refineries reduced output and, in some cases, indefinitely shut-down. The EIA is currently forecasting growth in overall refined product demand to increase marginally over the next decade.
MANAGEMENT DISCUSSION FROM LATEST 10K
Executive Summary
Company Overview
We engage in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as the processing, transportation, fractionation, storage and marketing of natural gas liquids (“NGL”). The term NGL includes ethane and natural gasoline products as well as propane and butane, products which are also commonly referred to as liquid petroleum gas (“LPG”). The terms NGL and LPG are sometimes used interchangeably within this document depending on the context. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P., we also own and operate natural gas storage facilities. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. See “—Results of Operations—Analysis of Operating Segments” for further discussion.
Overview of Operating Results, Capital Investments and Significant Activities
During 2011, our net income attributable to Plains was $966 million, which was a $461 million year-over-year increase as compared to that recognized during 2010. This increase was primarily driven by strong industry fundamentals and contributions from our acquisitions and internal growth projects. The major items impacting comparability between periods were:
• the favorable results experienced within our supply and logistics segment, which were impacted by (i) the active development of crude oil and liquids-rich resource plays, (ii) favorable crude oil basis differentials and (iii) favorable market structure;
• the favorable results experienced within our transportation segment, which were impacted by (i) increased volumes in key production areas, (ii) increased tariff rates and (iii) favorable foreign currency exchange rates, partially offset by the unfavorable impact of a crude oil release on our Rainbow Pipeline; and
• the favorable results experienced within our facilities segment, which were impacted by expansions to our asset base through acquisitions and our ongoing internal growth projects.
Other key items impacting 2011 were:
• the completion of nine acquisitions for the aggregate consideration, net of cash acquired, of approximately $1.3 billion;
• the issuance of debt and equity for net proceeds of approximately $1.9 billion (this amount includes PNG’s issuance, in conjunction with the Southern Pines Acquisition, of approximately 17.4 million common units to third parties for net proceeds of approximately $370 million);
• the increase in our income tax expense related to our Canadian operations as a result of Canadian tax legislation changes that became effective on January 1, 2011; and
• the redemption of our 7.75% senior notes that were maturing in 2012 for approximately $222 million, as well as the loss of $23 million recognized in Other income/(expense), net within our Consolidated Financial Statements in conjunction with the early redemption of these notes.
Critical Accounting Estimates
The preparation of financial statements in conformity with GAAP and rules and regulations of the United States Securities and Exchange Commission (“SEC”) requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. On a regular basis, we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.
We believe that the assumptions, judgments and estimates involved in the accounting for our (i) purchase and sales accruals, (ii) fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) fair value of derivatives, (iv) accruals and contingent liabilities, including our equity compensation plan accruals, (v) property and equipment and depreciation expense and (vi) allowance for doubtful accounts have the greatest potential impact on our consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting policies. Such critical accounting estimates are discussed further as follows:
Purchase and Sales Accruals. We routinely make accruals based on estimates for certain components of our revenues and cost of sales due to the timing of compiling billing information, receiving third-party information and reconciling our records with those of third parties. Where applicable, these accruals are based on nominated volumes expected to be purchased, transported and subsequently sold. Uncertainties involved in these estimates include levels of production at the wellhead, access to certain qualities of crude oil, pipeline capacities and delivery times, utilization of truck fleets to transport volumes to their destinations, weather, market conditions and other forces beyond our control. These estimates are generally associated with a portion of the last month of each reporting period. For the year ended December 31, 2011, we estimate that approximately 2% of both annual revenues and cost of sales were recorded using purchase and sales estimates. Accordingly, a 10% variance from this estimate would impact annual revenues, cost of sales, operating income and net income attributable to Plains line items by approximately 1% or less on an annual basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.
Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets. In accordance with Financial Accounting Standards Board (“FASB”) guidance regarding business combinations, with each acquisition, we allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. If the initial accounting for the business combination is incomplete when the combination occurs, an estimate will be recorded. Any subsequent adjustments to this estimate, if material, will be recognized retroactive to the date of acquisition. With exception to our equity method investments, we also expense the transaction costs as incurred in connection with each acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment.
Impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of future revenues, future cash flows and market conditions including pricing, demand, competition, operating costs and other factors. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts and industry expertise, involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable. We did not have any material goodwill impairments in 2011, 2010 or 2009. See Note 2 to our Consolidated Financial Statements for a further discussion of goodwill.
Fair Value of Derivatives. Our derivatives are reported at fair value as either assets or liabilities with changes in fair value recognized in either earnings or accumulated other comprehensive income (“AOCI”). The fair value of a derivative at a particular period end does not reflect the end results of a particular transaction, and will most likely not reflect the realized gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. For our derivatives that are not exchange traded, the estimates we use are based on indicative broker quotations or an internal valuation model. Our valuation models utilize market observable inputs such as price, volatility, correlation and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total annual revenues are based on estimates derived from internal valuation models. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Accruals and Contingent Liabilities. We record accruals or liabilities including, but not limited to, environmental remediation and governmental penalties, asset retirement obligations, equity compensation plan accruals (as further discussed below) and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, and the possibility of existing legal claims giving rise to additional claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A variance of 5% in our aggregate estimate for the accruals and contingent liabilities discussed above would have an impact on earnings of up to approximately $17 million. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.
Equity Compensation Plan Accruals. We accrue compensation expense for outstanding equity compensation awards. Under GAAP, we are required to estimate the fair value of our outstanding equity awards and recognize that fair value as compensation expense over the service period. For equity awards that contain a performance condition, the fair value of the equity award is recognized as compensation expense only if the attainment of the performance condition is considered probable. Uncertainties involved in this estimate include the actual unit price at time of vesting, whether or not a performance condition will be attained and the continued employment of personnel with outstanding equity awards.
We recognized total compensation expense of approximately $110 million, $98 million and $68 million in 2011, 2010 and 2009, respectively, related to equity awards granted under our various equity compensation plans. We cannot provide assurance that the actual fair value of our equity compensation awards will not vary significantly from estimated amounts. See Note 10 to our Consolidated Financial Statements.
Property and Equipment and Depreciation Expense. We compute depreciation using the straight-line method based on estimated useful lives. These estimates are based on various factors including condition, manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. During 2010 and 2011, we conducted a review to assess the useful lives of our property and equipment. See Note 2 to our Consolidated Financial Statements.
Recent Accounting Pronouncements
See Note 2 to our Consolidated Financial Statements for information regarding the effect of recent accounting pronouncements on our financial statements.
Results of Operations
Analysis of Operating Segments
We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. Our Chief Operating Decision Maker (our Chief Executive Officer) evaluates such segment performance based on a variety of measures including segment profit, segment volumes, segment profit per barrel and maintenance capital investment. See Note 13 to our Consolidated Financial Statements for a definition of segment profit (including an explanation of why this is a performance measure) and a reconciliation of segment profit to net income attributable to Plains.
Our segment analysis involves an element of judgment relating to the allocations between segments. In connection with its operations, the supply and logistics segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers under month-to-month and multi-year arrangements. Intersegment transportation service rates are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market rates. Facilities segment services are also obtained at rates generally consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates are discounted to our supply and logistics segment to reflect the fact that these services may be canceled on short notice to enable the facilities segment to provide services to third parties. Intersegment activities are eliminated in consolidation and we believe that the estimates with respect to these rates are reasonable. Also, our segment operating and general and administrative expenses reflect direct costs attributable to each segment; however, we also allocate certain operating expense and general and administrative overhead expenses between segments based on management’s assessment of the business activities for the period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period. We believe that the estimates with respect to these allocations are reasonable.
Non-GAAP Financial Measures
To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future. The primary measures used by management are adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”) and implied distributable cash flow (“DCF”).
Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial, operational, compensation and planning decisions and (iii) present measurements that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) the mark-to-market of derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), (iii) items that are not indicative of our core operating results and business outlook and/or (iv) other items that we believe should be excluded in understanding our core operating performance. We have defined all such items hereinafter as “Selected Items Impacting Comparability.” These additional financial measures are reconciled from the most directly comparable measures as reported in accordance with GAAP, and should be viewed in addition to, and not in lieu of, our consolidated financial statements and footnotes.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Executive Summary
Company Overview
We engage in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as the processing, transportation, fractionation, storage and marketing of NGL. Through our general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P., we also own and operate natural gas storage facilities. We were formed in 1998, and our operations are conducted directly and indirectly through our operating subsidiaries and are managed through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics.
Overview of Operating Results, Capital Investments and Significant Activities
During the first three months of 2012, our net income attributable to Plains was $230 million, or $1.02 per diluted limited partner unit, representing increases of 26% and 13%, respectively as compared to net income attributable to Plains of $182 million, or $0.90 per diluted limited partner unit recognized during the first three months of 2011. The major items impacting the favorable performance between periods include increased utilization of certain existing transportation assets, incremental fee-based contributions associated with acquisition and expansion capital invested in our transportation and facilities segments and increased lease-gathering volumes and improved unit margins in our supply and logistics segment. The majority of the incremental volumes and a portion of the enhanced unit margins are attributable to technological advancements and their application in the development and expansion of North American crude oil and liquids-rich resource plays. Favorable basis and quality differentials also contributed substantially to margins in our supply and logistics segment, but were largely offset by a $61 million loss related to the mark-to-market impact for derivative instruments (compared to a $20 million gain for the first quarter of 2011). All segments were also negatively impacted by an increase in our equity compensation expense of approximately $19 million.
quity Compensation Expense. Equity compensation expense increased for the three months ended March 31, 2012 compared to the three months ended March 31, 2011, primarily due to (i) an increase in unit price of $5 for the first quarter of 2012 compared to a less than $1 increase for the first quarter of 2011 and (ii) additional awards that have been deemed probable of occurring. The increase in unit price impacts the fair value of our liability-classified awards. A majority of our equity compensation awards (including the Class B units) contain performance conditions contingent upon achieving certain distribution levels. For awards with performance conditions (such as distribution targets), expense is accrued over the service period only if the performance condition is considered probable of occurring. When awards with performance conditions that were previously considered improbable become probable, we incur additional expense in the period that our probability assessment changes. This is necessary to bring the accrued liability associated with these awards up to the level it would have been if we had been accruing for these awards since the grant date. At March 31, 2012, we determined that a PAA distribution level of $4.50 was probable of occurring, and we incurred additional expense as a result of such determination. See Note 10 to our Consolidated Financial Statements included in Part IV of our 2011 Annual Report on Form 10-K for further information regarding our equity compensation plans.
Maintenance Capital . Maintenance capital consists of capital investments for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. The increase in maintenance capital in the three months ended March 31, 2012 compared to the three months ended March 31, 2011 is primarily due to increased spending on pipeline integrity projects as well as timing of repairs between years.
Equity Earnings in Unconsolidated Entities . Equity earnings in unconsolidated entities increased for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 primarily related to increased earnings for the 2012 comparative period from our 34% interest in White Cliffs Pipeline LLC. The favorable year-over-year variance was also impacted by a loss incurred for an environmental liability in February 2011 related to an incident involving Settoon Towing LLC, in which we have a 50% interest, for which a similar loss was not experienced in the current period.
Facilities Segment
Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, natural gas and NGL, as well as NGL fractionation and isomerization services. The facilities segment generates revenue through a combination of month-to-month and multi-year leases and processing arrangements.
Other Income and Expenses
Depreciation and Amortization
Depreciation and Amortization. Depreciation and amortization expense was $60 million for the three months ended March 31, 2012 compared to $63 million for the three months ended March 31, 2011 , reflecting a net gain in the 2012 period of approximately $5 million recognized upon disposition of certain assets as compared to a net loss in the 2011 period of approximately $1 million for asset dispositions and impairments for assets taken out of service. Expense was also lower in the 2012 period as a result of the extension of depreciable lives of several of our crude oil and other storage facilities and pipeline systems. These comparative period decreases were partially offset by an increased amount of assets resulting from acquisition activities completed in 2011 as well as various internal growth projects in both years.
Other Income/(Expense), Net
Other income/(expense), net was a net gain of approximately $2 million for the three months ended March 31, 2012, compared to a net loss of approximately $22 million for the three months ended March 31, 2011. This variance is primarily due to the loss related to the early redemption of our $200 million, 7.75% senior notes in February 2011.
Income Tax Expense
Current income tax expense increased for the three months ended March 31, 2012 compared to the three months ended March 31, 2011 primarily due to an increase in the level of taxable earnings in our entities subject to Canadian federal and provincial taxes and other adjustments. In addition, payments of interest and dividends from our Canadian entities to other affiliates are subject to Canadian withholding tax which is also treated as income tax expense.
Equity and Debt Financing Activities
Our financing activities primarily relate to funding acquisitions and internal capital projects, and short-term working capital and hedged inventory borrowings related to our contango market activities and NGL business, as well as refinancing of our debt maturities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings and repayments under our credit facilities.
Registration Statements
We periodically access the capital markets for both equity and debt financing. We have filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $2.0 billion of debt or equity securities (“Traditional Shelf”). At March 31, 2012, we had $2.0 billion of unsold securities available under the Traditional Shelf. We also have access to a universal shelf registration statement (“WKSI Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The March 2012 offerings of our $750 million, 3.65% senior notes due 2022 and our $500 million, 5.15% senior notes due 2042 as well as the March 2012 equity offering, as discussed further below, were all conducted under the WKSI Shelf.
PNG has filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows PNG to issue up to an aggregate of $1.0 billion of debt or equity securities. PNG has not issued any securities under its shelf registration statement.
Equity and Debt Offerings
PAA Equity Offering. In March 2012, we completed the sale and issuance of 5,750,000 common units at $80.03 per unit for net proceeds of approximately $455 million. The net proceeds include our general partner’s proportionate capital contribution and are reflected net of costs associated with the offering. We used the net proceeds to fund a portion of the BP NGL Acquisition, to temporarily reduce outstanding borrowings under our credit facilities and for general partnership purposes. Amounts repaid under our credit facilities may be reborrowed to fund our ongoing capital program, potential future acquisitions or for general partnership purposes.
Senior Notes. We had several issues of senior debt outstanding at March 31, 2012 totaling approximately $6.0 billion, excluding discounts. These issues of senior debt range in size from $150 million to $750 million and mature at various dates between 2012 and 2042. See Note 7 to our condensed consolidated financial statements.
In March 2012, we completed the sale and issuance of $750 million, 3.65% senior notes due 2022 and $500 million, 5.15% senior notes due 2042. The senior notes were sold at 99.823% and 99.755% of face value, respectively. Interest payments are due on June 1 and December 1 each year beginning on December 1, 2012. We used the net proceeds from these offerings to fund a portion of the consideration for the BP NGL Acquisition and for general partnership purposes.
Credit Agreements
General. During the three months ended March 31, 2012, we had net borrowings on our credit agreements, which include our revolving credit facilities, our GO Zone term loans and our hedged inventory facility, in the aggregate of approximately $104 million.
During the three months ended March 31, 2011, we had net repayments on our revolving credit facilities and our hedged inventory facility in the aggregate of approximately $906 million. The net repayments were primarily attributed to funds received from our January 2011 debt offering and March 2011 equity offering as well as from sales of NGL inventory that was liquidated during the quarter.
PAA senior unsecured 364-day revolving credit agreement. In March 2012, we elected to terminate an unactivated 364-day credit facility agreement that had a borrowing capacity of $1.2 billion.
Acquisitions and Capital Expenditures and Distributions Paid to Our Unitholders, General Partner and Noncontrolling Interests
In addition to operating needs discussed above, we also use cash for our acquisition activities, internal growth projects and distributions paid to our unitholders, general partner and noncontrolling interests. We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations and the financing activities discussed above. See “Internal Growth Projects” above and “Acquisitions and Internal Growth Projects” under Item 7 of our 2011 Annual Report on Form 10-K for further discussion of such capital expenditures.
Acquisitions. The price of acquisitions includes cash paid, assumed liabilities and net working capital items. Because of the non-cash items included in the total price of the acquisitions and the timing of certain cash payments, the net cash paid may differ significantly from the total price of the acquisitions completed during the year.
In December 2011, we entered into a definitive agreement to acquire all of the outstanding shares of BP Canada Energy Company for a total consideration of approximately $1.67 billion, which closed on April 1, 2012 (see Note 4 to our condensed consolidated financial statements). As of March 31, 2012, we had approximately $1.63 billion in r estricted cash held by an escrow agent in contemplation of closing this acquisition and p rior to December 31, 2011, we paid a cash deposit of $50 million upon signing. See Note 4 for further discussion of this acquisition.
Distributions to our unitholders and general partner. We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. On May 15, 2012, we will pay a quarterly distribution of $1.045 per limited partner unit. This distribution represents a year-over-year distribution increase of approximately 7.7%. See Note 9 to our condensed consolidated financial statements for details of distributions paid. Also, see Item 5. “Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy” included in our 2011 Annual Report on Form 10-K for additional discussion on distributions.
In order to enhance our distribution coverage ratio and liquidity in connection with a significant acquisition, our general partner has, from time to time, agreed to reduce the amounts due to it as incentive distributions. As such, beginning with the first distribution declared and paid after closing the BP NGL Acquisition, which occurred on April 1, 2012, our general partner agreed to reduce the amount of its incentive distributions by $15 million per year for two years and $10 million per year thereafter. The first incentive distribution reduction related to this acquisition of approximately $4 million will be applied to the May 2012 distribution. See Note 4 to our condensed consolidated financial statements for further discussion of the BP NGL Acquisition.
Distributions to noncontrolling interests. We paid approximately $12 million and $5 million for distributions to our noncontrolling interests during the three months ended March 31, 2012 and 2011, respectively. These amounts represent distributions paid on interests in PNG and SLC that are not owned by us.
We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. We are, however, subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.
CONF CALL
Roy I. Lamoreaux
Good morning. My name is Roy Lamoreaux, Director of Investor Relations. We welcome you to Plains All American Pipeline and PAA Natural Gas Storage's First Quarter 2012 Results Conference Call. The slide presentation for today's call is available under the Conference Call tab in the Investor Relations section of our website at www.paalp.com and www.pnglp.com.
I would mention that throughout the call, we will refer to the companies by their New York Stock Exchange ticker symbols of PAA and PNG, respectively. As a reminder, Plains All American owns the 2% general partner interest and all of the incident distribution rights and approximately 62% in the limited partner interest in PNG, which accordingly, is consolidated into PAA's results.
In addition to reviewing recent results, we'll provide forward-looking comments on the partnership's outlook for the future. In order to avail ourselves to the Safe Harbor precepts that encourage companies to provide this type of information, we direct you to the risks and warnings set forth in the partnership's most recent and future filings with the Securities and Exchange Commission.
Today's presentation will also include references to certain non-GAAP financial measures such as EBIT and EBITDA. The non-GAAP reconciliation sections of our websites reconcile certain non-GAAP financial measures to the most directly comparable GAAP financial measures and provide a table of selected items that impact comparability of the partnership's reported financial information. References to adjusted financial metrics exclude the effect of these selected items. Also for PAA, all references to net income are references to net income attributable to Plains.
Today's call will be chaired by Greg L. Armstrong, Chairman and CEO of PAA and PNG. Also participating in the call are: Harry Pefanis, President and COO of PAA; Dean Liollio, President of PNG; and Al Swanson, Executive Vice President and CFO of PAA and PNG.
In addition to these gentlemen and myself, we have several other members of our management team present and available for the question-and-answer session.
With that, I will turn the call over to Greg.
Greg L. Armstrong
Thanks, Roy. Good morning, and welcome to everyone. PAA delivered very strong first quarter results underpinned by solid fundamental performance and further enhanced by favorable market conditions. Yesterday, after market close, Plains All American announced first quarter adjusted EBITDA of $472 million. These results exceeded the midpoint of our guidance range by $72 million or 18%, and were $52 million above the high end of our guidance range.
In comparison to last year's first quarter, adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the first quarter of 2012 increased 36%, 58% and 53%, respectively. These results and additional information are summarized on Slide 3.
PAA's first quarter results were driven by solid performance in all 3 segments with Supply and Logistics segment being the largest contributor to the overperformance. As shown on Slide 4, our first quarter results marked the 41st consecutive quarter that PAA has delivered results in line with or above guidance. In April, PAA declared a 7.7% year-over-year increase in our annualized run rate distribution to $4.18 per common unit.
As shown on Slide 5, PAA has increased its distribution in each of the last 11 quarters and 30 out of the last 32 quarters. As reflected on Slide 6, during the remainder of today's call, we will discuss our segment performance relative to guidance, our expansion capital program, our acquisition and integration activities and our financial position. We will also address the drivers and major assumptions supporting our financial and operating guidance for the second quarter of 2012. We will address similar information for PNG.
At the end of the call, I will provide a recap, as well as some comments regarding our outlook for the future. And with that, I'll turn the call over to Harry.
Harry N. Pefanis
Thanks, Greg. During my section of the call, I'll review our first quarter operating results compared to the midpoint of our guidance issued on February 8, discuss the operational assumptions used to generate our second quarter guidance and discuss our 2012 capital program and acquisition activities.
As shown on Slide 7, adjusted segment profit for the Transportation segment was $173 million, which was $25 million above the midpoint of the guidance. Volumes for this segment of 3,170,000 barrels per day were above guidance by approximately 60,000 barrels per day, which combined with our higher pipeline loss allowance volumes accounted for approximately $18 million of the overperformance.
Operating expenses were approximately $8 million lower than our guidance, primarily due to combination of: One, $4 million reversal of accrued expenses associated with the Rainbow pipeline released in 2011; and secondly, a shift in the timing of certain maintenance and integrity expenses. On a per unit basis, adjusted segment profit was $0.60 per barrel.
Adjusted segment profit for the Facilities segment was $100 million or $5 million above the midpoint of our guidance. Volumes of 91 million barrels were in line with the guidance, generating adjusted segment profit per barrel of $0.37, which was slightly above the midpoint of guidance.
Primary contributors to our financial performance were higher throughput fees and other ancillary fees at several of our crude oil and LPG terminals, as well as favorable performance from our gas processing assets.
Adjusted segment profit for the Supply and Logistics segment was $197 million or $41 million above the midpoint of our guidance. Our volumes of 932,000 barrels per day were in line with the guidance. Adjusted segment profit per barrel was $2.33 or $0.49 per barrel above the midpoint of our guidance.
Our financial overperformance for the quarter was due to a combination of favorable crude oil basis differentials and stronger-than-forecasted propane and isobutane margins.
Let me now move to Slide 7 and review the operational assumptions used to generate our second quarter 2012 guidance, which was furnished in our Form 8-K last night. The guidance includes the benefit of the BP NGL acquisition, which was effective April 1, 2012.
For the Transportation segment, we expect volumes to average approximately 3.5 million barrels per day, that's about 10% higher than first quarter volumes. Approximately 215,000 barrels per day of the increase is related to the BP acquisition. The balance of the increase primarily relates to increased volume on several pipelines including our Mid-Continent, Capline and Mesa Pipeline Systems.
We expect adjusted segment profit per barrel of $0.55, which is about $0.05 per barrel lower than the first quarter segment profit. That's primarily due to the timing of maintenance and integrity spending, and then the first quarter had the benefit of the reversal of a portion of the Rainbow Pipeline expense accrual.
Facilities segment guidance assumes an average capacity of 111 million barrels of oil equivalent, but the increase is primarily due to storage capacity added from BP and Yorktown acquisitions and an NGL fractionation capacity added from the BP acquisition.
Adjusted segment profit is expected to be $0.34 per barrel in the second quarter. Supply and Logistics segment guidance volumes are projected to average 940,000 barrels per day for the second quarter of 2012. And while basically flat with the first quarter volumes, the forecast includes an increase on our lease gathering volumes of approximately 37,000 barrels per day, which is offset by the seasonal volume decline associated with our NGL activities.
The projected midpoint adjusted segment profit is $1.98 per barrel, which is very strong compared to historical levels but is lower than the first quarter results and that's primarily due to the seasonality of our NGL activities.
Now let's move on to our capital program. As reflected on Slide 9, we have increased our projected expansion capital expenditures for 2012 by $150 million, with the targeted amount of [indiscernible] dollars range of $950 million to $1.1 billion. The range reflects the fact that there are issues that could impact the timing of capital expenditures and is primarily associated with our pipeline projects, and particularly with respect to securing the rights away, sourcing materials such as pumps and certain sizes of pipe, sourcing power and of course, mother nature.
Our growth projects are coming in within acceptable tolerance of our forecasted costs and timing. Slide 10 reflects the expected in-service timing of certain of our larger capital projects. I want to spend a few minutes and provide a brief update on the status of some of our larger capital projects.
Our Eagle Ford pipeline project is progressing on schedule. We expect to have the segment from Gardendale to Three Rivers in service in the third quarter this year and the segment Corpus Christi in service by the end of the year.
Power is an issue in this area and we probably won't be at 100% of capacity until late 2013. However, we should have capacity to move somewhere between 150,000 and 200,000 barrels a day when we have this place in service.
We have a significant amount of activity in the Permian Basin. Our Bone Spring area pipelines will be in service by the end of May, and in the Sprayberry we have expansion projects totaling $100 million that are expected to be completed in the second half of the year. These projects will increase our capacity by approximately 125,000 barrels a day, increase our operating flexibility and provide the ability to deliver 225,000 barrels a day into the long-haul pipeline systems at [indiscernible].
With respect to takeaway capacity in the Permian Basin, we've also completed our Mesa expansion and are now delivering an additional 30,000 to 40,000 barrels a day. As to the West Texas Gulf pipeline system, it will be capable of an additional 60,000 barrels a day in West Texas Gulf once their expansion is complete.
And lastly, we have largely completed the expansion of our basin pipeline system having achieved approximately 90% of the volume uplift expected. But the timing of this expansion, has been challenged due to the sheer volume of crude oil nominations we've had on the system. We expect to complete the final minor modifications as we are able to.
Maintenance capital expenditures for the first quarter were $35 million. We expect maintenance capital expenditures for 2012 to range between $140 million and $150 million and that incorporates the expenditures expected as a result of our recent acquisition.
Now moving on to acquisitions. On April 1, we closed the BP -- the acquisition of BP Canadian NGL business. And as mentioned before, this transaction is not a typical bolt-on acquisition, it will represent a more challenging integration process. We were able to use the 4-month period upon signing and closing to fine-tune our integration plan, to secure most of the equipment required for the integration and complete the process to lift most of BP's systems and ship them to a platform that communicates with our systems.
We believe we have made some meaningful progress in our integration effort and believe that we can substantially complete the integration process by the end of the year.
I want to note that we'll continue to pursue both asset and IP optimization opportunities within the next couple of years.
Slide 11 reflects the primary integration milestones and the status of our integration efforts. And while our Canadian team remains focused on integration of the Canadian NGL acquisition, in the U.S., we are continuing to pursue strategic and accretive acquisition opportunities.
And with that, I'll turn the call over to Dean to discuss PNG's operating and financial results.
Dean Liollio
Thanks, Harry. In my part of the call, I will review PNG's first quarter operating and financial results and our financial position as of March 31, 2012, provide an update on PNG's operations and capital program and review our second quarter and full year 2012 guidance.
Let me begin by discussing the results we released yesterday afternoon. As shown on Slide 12, PNG delivered first quarter 2012 results in line with the guidance we provided in February. Adjusted EBITDA for the first quarter of 2012 totaled $227.8 million, resulting in adjusted net income of $17.1 million and adjusted net income per diluted unit of $0.23.
In comparison to last year's first quarter results, adjusted EBITDA, adjusted net income and adjusted net income per diluted unit for the first quarter of 2012 increased 43%, 40% and 15%, respectively. Financially, PNG continues to be well-positioned. Included on Slide 13 is a condensed capitalization table for PNG at March 31, 2012, highlighting PNG's long-term debt to capitalization ratio of 27.4%, and a long-term debt-to-adjusted-EBITDA ratio of 3.9x and $131 million of committed liquidity.
Operationally, we are on track to complete our 2012 capital program on time and on budget. Our 2012 expansion capital plan calls for expenditures to range between $55 million and $60 million. We expect to place a total of approximately 16 Bcf of working storage capacity in service in 2012, increasing our average working capacity for 2012 to 84 Bcf, representing an 18% increase over our 71 Bcf average working capacity in 2011.
This increase in capacity will consist of a 5th cavern at Pine Prairie that is scheduled to be placed into service in the second quarter, and 4th cavern at Southern Pine which is scheduled to go into service in the third quarter, along with capacity created by incremental leaching activities at both Pine Prairie and Southern Pine and the full period benefit of capacity brought into service last year.
Overall market conditions for natural gas storage remain fairly challenging with some of the winter spreads remaining in a very narrow band at or near the lower portion of the multiyear range.
The recent weakening of natural gas prices in early 2012 has increased the level of volatility somewhat relative to 2011 and has created some short-term opportunity. Although encouraging, this development has not made a unnoticeable difference in operating results nor has it changed our overall outlook for 2012. As a result, we continue to position PNG to manage through a continuation of the conditions we have experienced over the last 18 months.
With that outlook in mind, our annual guidance for 2012 is essentially unchanged with our adjusted EBITDA forecast for 2012 continuing to range between $115 million and $125 million with the midpoint of $120 million. This guidance is shown at the bottom of Slide 14 and represents a 12% increase over our 2011 comparable results.
At second quarter, as shown at the top of Slide 14, we expect adjusted EBITDA to range from $26 million to $30 million with the midpoint of $28 million. As depicted by the chart in the upper right of Slide 14, we expect relatively steady adjusted EBITDA for the first 3 quarters of the year with a seasonal increase in the fourth quarter.
With respect to distributions, in early April, we announced a quarterly distribution of $1.43 per unit on an annualized basis. This distribution, which is payable next week, is equal to the distribution that was paid in February 2012 and equates to a 3.6% increase over the distribution that was paid in May of 2011.
As expected, due to the seasonality of our business, our distribution coverage for the first quarter were slightly less than 1:1, but was 105% on the fourth quarter trailing basis, which metric averages out the seasonal aspects.
As represented on Slide 15, achieving the midpoint of our guidance for 2012 also provides 105% coverage of our existing distribution level. As we have highlighted previously, a critical element of our fundamental business strategy is to commit a high percentage of our storage capacity to firm storage contracts. As a result, PNG's distribution is underpinned by a diverse portfolio of third-party firm storage contracts with initial terms ranging from 1 to 10 years in length.
For 2012, approximately 90% of our 2012 net revenue guidance is attributable to these third-party contracts, which have an aggregate remaining weighted average tender of 3.4 years.
And as illustrated on Slide 16, for calendar year 2012, approximately 95% of our average capacity is contracted with third parties. These contracts roll off, and we have incremental storage capacity, this percentage changes. The comparable percentages for 2013 and 2014 were approximately 70% and 50%, respectively. In each case, without taking into account new contracts that we intend to enter into the future but including incremental storage capacity we expect to place into service.
In conclusion, we believe PNG is strategically located in operationally flexible assets, supportive parent, attractive contract portfolio, solid capital structure and low-cost expansion projects position PNG relatively well relative to its peers.
Additionally, we believe these attributes will provide growth opportunity in the form of continued organic and acquisition-related activities.
With that, I'll turn it over to Al.
Al Swanson
Thanks, Dean. The first items I want to review are PAA's recent financing activity and our capitalization of liquidity following the closing of the BP NGL acquisition. We have been very active since holding our earnings conference call in February 9, as we have raised an aggregate of $1.7 billion of long-term capital.
In early March, we completed a public offering of 5.75 million common units, which raised $455 million. As we have indicated in recent conference calls, we intend to file a continuous equity offering program that will allow us to raise equity capital on an ongoing basis while minimizing disruption to the market and lowering our cost. We believe this program will enhance our ability to timely finance the equity needs associated with our ongoing expansion capital programs.
In mid-March, we accessed the debt capital markets raising an aggregate of $1.25 billion through the sale of $750 million of 10-year senior notes, and $500 million of 30-year senior notes. The 10-year notes and 30-year notes were priced to yield 3.67% and 5.17%, respectively. Following the closing of these transactions, we terminated the $1.2 billion, 364-day liquidity facility that we put in place in December 2011.
In order to close the BP NGL acquisition on April 1, which was a Sunday, we pre-funded $1.63 billion into an escrow account on March 30, 2012. Accordingly, although the acquisition did not technically close until the first day of the second quarter, as illustrated on Slide 17, PAA's capitalization as of March 31, 2012, is substantially representative of the capitalization immediately after the closing of the transaction.
Since we had already secured the long-term financing for the transaction, the only material element of our capitalization that changed between March 31 and closing is that the $1.682 billion of restricted cash and deposits was transferred to the BP and PAA received $120 million of cash as a part of the acquired entity. This is reflected in the table as an increase in our pro forma liquidity.
As illustrated on this slide, even after consummating the BP NGL acquisition and canceling the $1.2 billion, 364-day liquidity facility, PAA ended the first quarter of 2012 with strong capitalization, credit metrics that are favorable to our targets and approximately $2.5 billion of committed liquidity, including the cash acquired in the transaction.
At March 31, 2012, PAA's long-term debt-to-capitalization ratio was 47%. Total debt-to-capitalization ratio was 50%. Long-term debt-to-adjusted-EBITDA ratio was 3.2x. And our adjusted EBITDA-at-interest-covera ge ratio was 7.3x. I would note that our total debt ratio includes $757 million of short-term debt that primarily supports our hedged inventory. This debt is essentially self-liquidating from the cash proceeds where we sell the inventory. For reference, our short-term hedged inventory at March 31, 2012, consisted of approximately 15 million barrels equivalent with an aggregate value of approximately $1.1 billion. These amounts do not include approximately 14 million barrels of equivalent of line fill and base gas in PAA and third-party pipelines and terminals that are classified as a long-term asset on our balance sheet, with a book value of approximately $700 million and a market value of over $1 billion.
Adjusted for the BP transaction, the volumes and book value of our line fill and long-term inventory increased by approximately 5 million barrels and $250 million, respectively.
The second item I want to discuss is PAA's guidance for the second quarter and full year of 2012, the highlights of which are summarized on Slide 18. For a more detailed information, please refer to our guidance 8-K that we furnished last night. We are forecasting adjusted EBITDA for the second quarter of 2012 to range from $440 million to $480 million, with adjusted net income ranging from $263 million to $312 million, or $1.17 to $1.46 per diluted unit.
Including the benefits of the first quarter 2012 overperformance, we are forecasting adjusted EBITDA for the year of -- full year of 2012 to range from $1.74 billion to $1.86 billion, with adjusted net income ranging from $1.045 billion to $1.197 billion, or $4.65 to $5.57 per diluted unit. Although we typically see these stronger results in our Supply and Logistics segment in the first and fourth quarters, with slightly lower results in the second and third quarters, we expect the favorable market conditions that we are currently experiencing to more than offset the impact of seasonality during the second quarter.
As represented on Slide 19, giving effect to our recent financing activities and based on the midpoint of our 2012 guidance for distributable cash flow or DCF, and LP distributions, our distribution coverage is forecast to be 130% and we would retain approximately $290 million of access DCF or excess capital.
Before I turn the call over to Greg, I wanted to make a few comments related to our credit rating. Our financial growth strategy includes an objective to achieve and maintain mid to high BBB credit ratings. In this regard, we are very pleased to receive an upgrade from Moody's on March 8, from the BAA3 to BAA2 with a stable outlook.
Our credit ratings with Standard & Poor's is BBB- with a positive outlook. We remain committed to our target of achieving mid to high BBB credit rating and intend to continue to prudently manage our capital structure to achieve this important objective.
With that, I will turn the call over to Greg.
Greg L. Armstrong
Thanks, Al. PAA delivered very strong performance for the first quarter of 2012, and we believe we are well-positioned to continue to perform well throughout the balance of the year and to accomplish our 2012 goals, including delivering year-over-year distribution growth of roughly 8% to 9%. Our guidance for 2012 reflects a continuation of strong industry fundamentals but does not assume that market conditions will be as favorable in the second half of 2012 as they were in 2011, or have been in the first half of 2012.
Accordingly, as a result of PAA's proven business model and strategic flexible asset base, there's an upward bias to our annual guidance should the favorable market conditions that we are currently experiencing continue throughout the second half of the year.
Looking beyond 2012, we believe PAA is well positioned to continue to deliver attractive results as we realize the contributions from the $1.9 billion of capital we've invested in 2011, the $2.7 billion that we have already invested or expect to invest in 2012, as well as future years capital programs and acquisitions.
As always, we will remain focused on prudently financing our growth while maintaining a solid capital structure and a high level of liquidity. Prior to opening the call up for questions, I wanted to mention that we will be holding our joint PAA and PNG 2012 Analyst Meeting on May 30 in Houston, followed by tour of PAA's Midland Assets -- Area Assets. If you've not received an invitation but would like to attend, please contact our Investor Relations team at (713) 646-4489.
Once again, thank you for participating in today's call and for your investment in PAA and PNG. We look forward to updating you on our activities during our second quarter results call in August, and hopefully, see many of you at our Analyst Meeting on May 30.
Operator, we're now ready to open the call up for questions.
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Fund Letters
