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Buckeye Partners 10-Q 2011 Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended June 30, 2011 OR
For the transition period from to Commission file number 1-9356
Buckeye Partners, L.P. (Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code: (832) 615-8600
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x Limited partner units and Class B units outstanding as of August 3, 2011: 85,880,404 and 7,042,771, respectively.
Table of ContentsTABLE OF CONTENTS
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Table of Contents
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per unit amounts) (Unaudited)
See Notes to Unaudited Condensed Consolidated Financial Statements.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (In thousands) (Unaudited)
See Notes to Unaudited Condensed Consolidated Financial Statements.
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Table of ContentsCONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except unit amounts) (Unaudited)
See Notes to Unaudited Condensed Consolidated Financial Statements.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) (Unaudited)
See Notes to Unaudited Condensed Consolidated Financial Statements.
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Table of ContentsCONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (In thousands) (Unaudited)
See Notes to Unaudited Condensed Consolidated Financial Statements.
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Table of ContentsNOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION Partnership Organization Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. Buckeye GP is a wholly owned subsidiary of Buckeye GP Holdings L.P. (“BGH”), a Delaware limited partnership that was previously publicly traded on the NYSE prior to BGH’s merger with a wholly owned subsidiary of Buckeye (see below for further information). As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “we,” “us,” “our” and “Buckeye” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. We were formed in 1986 and own and operate one of the largest independent refined petroleum products pipeline systems in the United States in terms of volumes delivered with approximately 6,100 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of over 64 million barrels. In 2011, we acquired (i) the Bahamas Oil Refining Company International Limited (“BORCO”) terminal facility in Freeport, Grand Bahama, The Bahamas, with a total installed capacity of approximately 21.6 million barrels, (ii) 33 refined petroleum products terminals with a total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines (see Note 2) and (iii) interests in two petroleum products terminals in Maine with a total storage capacity of approximately 0.9 million barrels and a 124-mile pipeline that connects the two terminals (see Note 22). In addition, we operate and maintain approximately 3,400 miles of other pipelines under agreements with major oil and gas, petrochemical and chemical companies, and perform certain engineering and construction management services for third parties. We also own and operate a high performance natural gas storage facility in northern California, and are a wholesale distributor of refined petroleum products in the United States in areas also served by our pipelines and terminals. We operate and report in five business segments: Pipelines & Terminals; International Operations; Natural Gas Storage; Energy Services; and Development & Logistics. Effective January 1, 2011, we realigned our five business segments. We combined the Pipeline Operations and Terminalling & Storage segments into one segment, the Pipelines & Terminals segment, and moved our terminal in Yabucoa, Puerto Rico, previously included as part of the Terminalling & Storage segment, to a new International Operations segment with the BORCO facility. See Note 20 for a discussion of our business segments. On November 19, 2010, we consummated a transaction pursuant to a plan and agreement of merger (the “Merger Agreement”) with our general partner, BGH, BGH’s general partner and Grand Ohio, LLC (“Merger Sub”), our subsidiary. Pursuant to the Merger Agreement, Merger Sub was merged into BGH, with BGH as the surviving entity (the “Merger”). In the transaction, the incentive compensation agreement (also referred to as the incentive distribution rights) held by our general partner was cancelled, the general partner units held by our general partner (representing an approximate 0.5% general partner interest in us) were converted to a non-economic general partner interest, all of the economic interest in BGH was acquired by us and BGH unitholders received aggregate consideration of approximately 20.0 million of our LP Units. Buckeye Pipe Line Services Company (“Services Company”) was formed in 1996 in connection with the establishment of the Buckeye Pipe Line Services Company Employee Stock Ownership Plan (the “ESOP”). At June 30, 2011, Services Company owned approximately 1.6% of our LP Units. Services Company employees provide services to our operating subsidiaries. Pursuant to a services agreement entered into in December 2004, our operating subsidiaries reimburse Services Company for the costs of the services provided by Services Company. Services Company has been consolidated into our financial statements. Basis of Presentation and Principles of Consolidation These consolidated financial statements reflect the financial results of BGH for periods prior to the effective date of the Merger. BGH is considered the surviving consolidated entity for accounting purposes, although Buckeye
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is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, changes in BGH’s ownership interest as a result of the Merger did not result in gain or loss recognition. Costs incurred associated with the Merger were charged directly to partners’ capital. Under applicable accounting guidance, the exchange of BGH’s units for our LP Units was accounted for as a BGH equity issuance and BGH was the surviving entity for accounting purposes. Consequently, the name on these financial statements for periods prior to the Merger has been changed from “Buckeye GP Holdings L.P.” to “Buckeye Partners, L.P.” The reconciliation of Buckeye’s net income, as historically reported, to the net income reported in these financial statements for the three and six months ended June 30, 2010 is as follows (in thousands):
Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate in exchange for all outstanding BGH common units and management units. As a result, the number of Buckeye’s LP Units outstanding increased from 51.6 million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the impact of this change was accounted for as a reverse split of BGH’s units of 0.705 to 1.0, together with the addition of Buckeye’s existing LP Units. Therefore, since BGH was the surviving accounting entity, the weighted average number of LP Units outstanding used for basic and diluted earnings per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split. The condensed consolidated financial statements and the accompanying notes are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and the rules of the U.S. Securities and Exchange Commission (“SEC”). The financial statements include our accounts on a consolidated basis. We have eliminated all intercompany transactions in consolidation. The consolidated financial statements include the financial results of our wholly-owned subsidiaries and the financial results of Services Company on a consolidated basis. Recent Accounting Developments Fair Value Measurements. In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance that requires new disclosures related to fair value measurements. The new guidance requires expanded disclosures related to a gross presentation for Level 3 activity. The new accounting guidance was effective for fiscal years beginning after December 15, 2010 and for interim periods within those years. The new guidance became effective for us on January 1, 2011. We have included the enhanced disclosure requirements regarding fair value measurements in Note 14.
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In May 2011, the FASB issued guidance that is intended to result in convergence between GAAP and International Financial Reporting Standards requirements for measurement of and disclosures about fair value. The amendments are not expected to have a significant impact on companies applying GAAP. Key provisions of the new guidance include: a prohibition on grouping financial instruments for purposes of determining fair value, except when an entity manages market and credit risks on the basis of the entity’s net exposure to the group; an extension of the prohibition against the use of a blockage factor to all fair value measurements (that prohibition currently applies only to financial instruments with quoted prices in active markets); and a requirement that for recurring Level 3 fair value measurements, entities disclose quantitative information about unobservable inputs, a description of the valuation process used and qualitative details about the sensitivity of the measurements. In addition, for items not carried at fair value but for which fair value is disclosed, entities will be required to disclose the level within the fair value hierarchy that applies to the fair value measurement disclosed. This new guidance is effective for interim and annual periods beginning after December 15, 2011. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements. Intangibles, Goodwill and Other. In December 2010, the FASB issued guidance that amended the goodwill impairment test for reporting units with zero or negative carrying amounts. The objective of this new guidance is to address questions about entities with reporting units with zero or negative carrying amounts because some entities concluded that the first step of the goodwill impairment test is passed in those circumstances because the fair value of their reporting unit will generally be greater than zero. The new guidance is effective for fiscal years and interim periods, within those years, beginning after December 15, 2010. We do not expect the adoption of this guidance to have an impact on our consolidated financial statements. Business Combinations. In December 2010, the FASB issued guidance that clarifies disclosures related to pro forma information for business combinations that occurred in the current period. The amendments specify that if an entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The new guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. We have included the enhanced disclosure requirements regarding pro forma information for business combinations in Note 2. Presentation of Comprehensive Income. In June 2011, the FASB issued guidance that will require companies to present the components of net income and other comprehensive income either as one continuous statement or as two consecutive statements. The guidance eliminates the option to present components of other comprehensive income as part of the statement of changes in unitholders’ equity. The guidance does not change the items which must be reported in other comprehensive income, how such items are measured or when they must be reclassified to net income. The new guidance is effective for interim and annual periods beginning after December 15, 2011. Because this guidance impacts presentation only, it will have no effect on our financial condition, results of operations or cash flows. 2. ACQUISITIONS AND DISPOSITIONS Acquisitions The acquisitions of terminals from an affiliate of Royal Dutch Shell plc (“Shell”) and from affiliates of FRC Founders Corporation (“First Reserve”) and Vopak Bahamas B.V. (“Vopak”) and the acquisition of pipeline and terminal assets from BP Products North America Inc. and its affiliates (“BP”) have been accounted for as business combinations. The total purchase price for these acquisitions was allocated to the fair value of the assets acquired
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and the liabilities assumed based on an assessment of their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill. The results of their operations have been included in our condensed consolidated financial statements since their respective acquisition dates. Puerto Rico Terminal Acquisition On December 10, 2010, we, through a wholly owned subsidiary, acquired a refined petroleum products terminal in Yabucoa, Puerto Rico from an affiliate of Shell for $32.8 million, net of cash acquired of $3.5 million. The terminal includes 44 storage tanks with approximately 4.6 million barrels of gasoline, jet fuel, diesel, fuel oil and crude oil storage capacity. Shell entered into a commercial contract with us concurrent with the acquisition regarding usage of the acquired facility. We believe the acquisition of these assets furthers our geographic diversification efforts as this was our first acquisition outside the continental United States and enables us to participate in a growth market outside our existing system footprint. The operations of these acquired assets are reported in the International Operations segment. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands):
We completed the acquisition of the refined petroleum products terminal in Yabucoa, Puerto Rico through the acquisition of a Puerto Rican entity, which is undergoing an audit of its Puerto Rico income tax returns for the tax years 2002 through 2005. The Puerto Rico Treasury Department has notified the entity of certain areas for discussion but has not issued a preliminary or final notice of debt regarding such years. Pursuant to the purchase and sale agreement we entered into in connection with this acquisition, an affiliate of Shell has assumed the full responsibility, through an indemnity and hold harmless provision, for the payment of any income tax debt that may be assessed by the Puerto Rico Treasury Department under this audit. In the purchase price allocation above, we recorded a $17.7 million liability related to the uncertain outcome of the income tax audit with an offsetting indemnification asset from Shell for the same amount. BORCO Acquisition On December 18, 2010, we, through a wholly owned subsidiary, entered into a sale and purchase agreement with affiliates of First Reserve, pursuant to which we agreed to acquire First Reserve’s indirect 80% interest in FR Borco Coop Holdings, L.P. (“FRBCH”), the indirect owner of BORCO, for $1.15 billion, financed through a combination of debt and equity, including the issuance of Class B units representing limited partner interests (“Class B Units”) and LP Units to First Reserve. BORCO is the fourth largest oil and petroleum products storage terminal in the world and the largest petroleum products facility in the Caribbean with current storage capacity of approximately 21.6 million barrels. On January 18, 2011, we completed the purchase of First Reserve’s interest in BORCO through the acquisition by us of all of the partnership interests in FR Borco Topco, L.P., which indirectly owned First Reserve’s interest. Vopak, which is based in The Netherlands, owned the remaining 20% interest in FRBCH. On February 16, 2011, Vopak sold its 20% interest in FRBCH to us for approximately $276.5 million of cash and equity, which is a proportionate price and on the same terms and conditions as those in the sale and purchase agreement with First Reserve.
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The following table presents the aggregate consideration paid or issued to complete the BORCO acquisition (in thousands):
On January 13, 2011, we issued $650.0 million aggregate principal amount of 4.875% Notes due 2021 (the “4.875% Notes”) in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price of the BORCO acquisition. On January 18 and 19, 2011, we issued 5,794,725 LP Units and 1,314,870 Class B Units to institutional investors for aggregate consideration of approximately $425.0 million to fund a portion of the BORCO acquisition. On January 18, 2011, we issued 2,483,444 LP Units and 4,382,889 Class B Units to First Reserve as $400.0 million of consideration to fund a portion of the BORCO acquisition. On February 16, 2011, we issued 620,861 LP Units and 1,095,722 Class B Units to Vopak as $100.0 million of consideration to fund a portion of the BORCO acquisition. Equity issuance costs incurred on these transactions were approximately $4.6 million. The remaining purchase price was funded with cash on hand at closing and borrowings under our unsecured revolving credit agreement (“Credit Facility”). On January 18, 2011, in connection with the BORCO acquisition, we repaid all of BORCO’s outstanding indebtedness and settled BORCO’s interest rate derivative instruments, consisting of approximately $318.2 million.
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The results of operations of the BORCO acquisition are included in our consolidated financial statements from the date of acquisition and are included in our International Operations segment. The acquisition cost has been allocated to assets acquired and liabilities assumed based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represents both expected synergies from combining the BORCO acquisition with our existing operations and the economic value attributable to future expansion projects resulting from this acquisition. Fair values have been developed using recognized business valuation techniques and are subject to change pending final valuation analysis. The purchase price has been allocated to tangible and intangible assets acquired, on a preliminary basis, as follows (in thousands):
Pipeline and Terminals Acquisition On June 1, 2011, we acquired 33 refined petroleum products terminals with total storage capacity of over 10 million barrels and approximately 650 miles of refined petroleum products pipelines from BP for $166.0 million. The terminal and pipeline assets are located in the Midwestern, Southeastern and Western United States. BP entered into a commercial contract with us concurrent with the acquisition relating to the continued usage of these terminals. We believe the acquisition of these assets further extends our operations into new, key geographic markets. The operations of these acquired assets are reported in the Pipelines & Terminals segment. We funded this acquisition with borrowings under our Credit Facility. We continue to evaluate and may revise the preliminary purchase price allocation, primarily the value of property, plant and equipment, in future periods as estimated fair values are finalized. The purchase price has been allocated to tangible assets acquired, on a preliminary basis, as follows (in thousands):
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Unaudited Pro forma Financial Results Our condensed consolidated statements of operations do not include earnings from BORCO prior to January 18, 2011, the effective date of the BORCO acquisition. The following table presents selected unaudited pro forma earnings information for the three months ended June 30, 2010 and the six months ended June 30, 2011 and 2010, as if the BORCO acquisition had occurred on January 1, 2010. This pro forma information does not give effect to any of the other acquisitions we have made since January 1, 2010, as pro forma results including those acquisitions would not be materially different from the information presented in our accompanying condensed consolidated statements of operations. The pro forma information presented below was prepared using BORCO’s historical financial data and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information was prepared for comparative purposes only and is not necessarily indicative of what our consolidated financial results would have been had we actually acquired BORCO on January 1, 2010 or the results that may be attained in the future (in thousands):
Dispositions On May 11, 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”) to affiliates of Atlas Pipeline Partners L.P. for $85.0 million. WT LPG owns a 2,295-mile common-carrier pipeline system that transports natural gas liquids from points in New Mexico and Texas to Mont Belvieu, Texas for fractionation. Chevron Pipeline Company, which owns the remaining 80% interest, is the operator of WT LPG. The proceeds from the sale will be used to fund a portion of our internal growth capital projects in 2011. We recognized a gain of $34.1 million on the sale of our interest in WT LPG.
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3. COMMITMENTS AND CONTINGENCIES Claims and Proceedings In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material. In June 2009, the Pipeline Hazardous Materials Safety Administration (“PHMSA”) proposed penalties totaling approximately $0.6 million as a result of alleged violations of various pipeline safety requirements raised as a result of PHMSA’s 2008 integrated inspection of our procedures and records for operations and maintenance, operator qualification, and integrity management as well as field inspections of locations in Pennsylvania, Ohio, Illinois, Michigan and Colorado. We are contesting portions of the proposed penalty. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time. In April 2010, PHMSA proposed penalties totaling approximately $0.5 million in connection with a tank overfill incident that occurred at our facility in East Chicago, Indiana in May 2005 and other related personnel qualification issues raised as a result of PHMSA’s 2008 Integrity Inspection. We are contesting the proposed penalty. The timing or outcome of this appeal cannot reasonably be determined at this time. On July 30, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management LLC (“MainLine Management”), BGH GP Holdings, LLC (“BGH GP”) and each of MainLine Management’s directors in the District Court of Harris County, Texas under the caption Broadbased Equities v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, acting to facilitate the sale of BGH to Buckeye in order to facilitate the gradual sale by BGH GP of its interest in BGH and failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. Among other things, the Petition sought an order certifying a class consisting of all BGH unitholders, a determination that the action was a proper derivative action, damages in an unspecified amount, and an award of attorneys’ fees and costs. On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management, Merger Sub, Buckeye, Buckeye GP and each of MainLine Management’s directors in the District Court of Harris County, Texas under the caption Henry James Steward v. Forrest E. Wylie, et. al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. The Petition also alleged that Buckeye, Buckeye GP and Merger Sub aided and abetted the breaches of fiduciary duty. Among other things, the Petition sought an order certifying a plaintiff class consisting of all of BGH unitholders, an order enjoining the Merger, rescission of the Merger, damages in an unspecified amount, and an award of attorneys’ fees and costs. On August 2, 2010, a putative class action was filed by a unitholder against BGH, MainLine Management, BGH GP, ArcLight Capital Partners (“ArcLight”), Kelso & Company (“Kelso”), Buckeye, Buckeye GP and each of MainLine Management’s directors in the District Court of Harris County, Texas under the caption JR Garrett Trust v. Buckeye GP Holdings L.P. et al. In the Petition, the plaintiff alleged that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders by, among other things, accepting insufficient consideration, failing to condition the Merger on a majority vote of public unitholders of BGH, and failing to disclose all material facts in order that the BGH unitholders could cast an informed vote on the Merger Agreement. The Petition also alleged that Buckeye, Buckeye GP, BGH GP, ArcLight and Kelso aided and abetted the breaches of fiduciary duty. Among other things, the Petition sought an order certifying a class consisting of all of BGH’s unitholders, an order enjoining the Merger, damages in an unspecified amount, and an award of attorneys’ fees and costs.
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On August 24, 2010, the District Court of Harris County, Texas entered an order consolidating the three previously filed putative class actions (Broadbased Equities v. Forrest E. Wylie, et. al., Henry James Steward v. Forrest E. Wylie, et. al., and JR Garrett Trust v. Buckeye GP Holdings L.P., et al.,) under the caption of Broadbased Equities v. Forrest E. Wylie, et al. and appointing interim co-lead class counsel and interim co-liaison counsel. The plaintiffs subsequently filed a consolidated amended class action and derivative complaint on September 1, 2010 (the “Complaint”). The Complaint purported to be a putative class and derivative action alleging that MainLine Management and its directors breached their fiduciary duties to BGH’s public unitholders in connection with the Merger by, among other things, accepting insufficient consideration and failing to disclose all material facts in order that BGH’s unitholders could cast an informed vote on the Merger Agreement, and that we, Buckeye GP, MainLine Management, Merger Sub, BGH GP, ArcLight and Kelso aided and abetted the breaches of fiduciary duty. On October 29, 2010, the parties to the litigation entered into a Memorandum of Understanding (“MOU”) in connection with a proposed settlement of the class action and the Complaint. The MOU provides for dismissal with prejudice of the litigation and a release of the defendants from all present and future claims asserted in the litigation in exchange for, among other things, the agreement of the defendants to amend the Merger Agreement to reduce the termination fees payable by BGH upon termination of the Merger Agreement and to provide BGH’s unitholders with supplemental disclosure to BGH’s and our joint proxy statement/prospectus, dated September 24, 2010. The supplemental disclosure is set forth in a joint proxy statement/prospectus supplement, dated October 29, 2010, which was filed with the SEC on November 1, 2010. In addition, the MOU provides that, in settlement of the plaintiffs’ claims (including any claim against the defendants by the plaintiffs’ counsel for attorneys’ fees or expenses related to the litigation), the defendants (or their insurers) will make a cash payment of $900,000 to plaintiff’s counsel for attorneys’ fees, subject to final court approval of the settlement. On January 25, 2011, pursuant to the MOU, the parties signed a Stipulation of Settlement. The Stipulation of Settlement was filed with the court, and the court preliminarily approved the settlement on March 21, 2011. The court held a hearing on May 23, 2011 to consider the fairness of the settlement and whether to finally approve the settlement. On May 23, 2011, after the hearing, the court issued an order that, among other things, finally approved all terms of the settlement and dismissed the action. We and the other defendants vigorously deny all liability with respect to the facts and claims alleged in the Complaint, and specifically deny that any modifications to the Merger Agreement or any supplemental disclosure was required or advisable under any applicable rule, statute, regulation or law. However, to avoid the substantial burden, expense, risk, inconvenience and distraction of continuing the litigation, and to fully resolve the claims alleged, we and the other defendants agreed to the proposed settlement described above. Environmental Contingencies In accordance with our accounting policy, we recorded operating expenses, net of insurance recoveries, of $2.4 million and $2.5 million during the three months ended June 30, 2011 and 2010, respectively, related to environmental expenditures unrelated to claims and proceedings. For the six months ended June 30, 2011 and 2010, we recorded operating expenses, net of insurance recoveries, of $4.8 million and $5.4 million, respectively, related to environmental expenditures unrelated to claims and proceedings. Ammonia Contract Contingencies On November 30, 2005, Buckeye Development & Logistics I LLC (“BDL”) (formerly Buckeye Gulf Coast Pipe Lines, L.P.) purchased an ammonia pipeline and other assets from El Paso Merchant Energy-Petroleum Company (“EPME”), a subsidiary of El Paso Corporation (“El Paso”). As part of the transaction, BDL assumed the obligations of EPME under several contracts involving monthly purchases and sales of ammonia. EPME and BDL agreed, however, that EPME would retain the economic risks and benefits associated with those contracts until their expiration at the end of 2012. To effectuate this agreement, BDL passes through to EPME both the cost of purchasing ammonia under a supply contract and the proceeds from selling ammonia under three sales contracts. For the vast majority of monthly periods since the closing of the pipeline acquisition, the pricing terms of the ammonia contracts have resulted in ammonia supply costs exceeding ammonia sales proceeds. The amount of the shortfall generally increases as the market price of ammonia increases.
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EPME has informed BDL that, notwithstanding the parties’ agreement, it will not continue to pay BDL for shortfalls created by the pass-through of ammonia costs in excess of ammonia revenues. EPME encouraged BDL to seek payment by invoking a $40.0 million guaranty made by El Paso, which guaranteed EPME’s obligations to BDL. If EPME fails to reimburse BDL for these shortfalls, then such unreimbursed shortfalls could exceed the $40.0 million cap on El Paso’s guaranty. To the extent the unreimbursed shortfalls significantly exceed the $40.0 million cap, the resulting costs incurred by BDL could adversely affect our financial position, results of operations and cash flows. To date, BDL has continued to receive payment for ammonia costs under the contracts at issue. BDL has not called on El Paso’s guaranty and believes only BDL may invoke the guaranty. EPME, however, contends that El Paso’s guaranty is the source of payment for the shortfalls, but has not clarified the extent to which it believes the guaranty has been exhausted. We, in cooperation with EPME, have terminated one of the ammonia sales contracts. Given the uncertainty of future ammonia prices and EPME’s future actions, we continue to believe we may have risk of loss in connection with the two remaining ammonia sales contracts and an ammonia supply contract and, at this time, are unable to estimate the amount of any such losses we might incur in the future. We are assessing our options in the event that we are unable to mitigate our risk with respect to the remaining contracts through termination of such contracts by other means, including commencing litigation or pursuing other recourse against EPME and El Paso, with respect to this matter. Leases –Where We are Lessee We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Lease expense is charged to operating expenses on a straight-line basis over the period of expected benefit. Contingent rental payments are expensed as incurred. Total rental expense for the three months ended June 30, 2011 and 2010 was $8.5 million and $5.5 million, respectively. For the six months ended June 30, 2011 and 2010, total rental expense was $16.1 million and $10.5 million, respectively. The following table presents minimum lease payment obligations under our operating leases with terms in excess of one year for the years ending December 31 (in thousands):
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Leases – Where We are Lessor We have entered into capacity and other leases with remaining terms from 1 to 12 years that are accounted for as operating leases. All of the agreements provide for negotiated extensions. Future minimum lease payments to be received under such operating leasing arrangements as of December 31, 2011 are as follows, with the amount for 2011 consisting of the remainder of 2011 (July 1 through December 31) and all other years consisting of the total amount for the full year (in thousands):
4. INVENTORIES Our inventory amounts were as follows at the dates indicated (in thousands):
At both June 30, 2011 and December 31, 2010, approximately 94% of our refined petroleum products inventory was hedged. Hedged inventory is valued at current market prices with the change in value of the inventory reflected in our condensed consolidated statements of operations. Inventory not accounted for as a fair value hedge is accounted for at weighted average cost.
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5. PREPAID AND OTHER CURRENT ASSETS Prepaid and other current assets consist of the following at the dates indicated (in thousands):
6. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consist of the following at the dates indicated (in thousands):
Depreciation expense was $26.1 million and $13.4 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, depreciation expense was $49.3 million and $26.7 million, respectively.
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7. EQUITY INVESTMENTS We own interests in related businesses that are accounted for using the equity method of accounting. The following table presents our equity investments, all included within the Pipelines & Terminals segment, at the dates indicated (in thousands):
The following table presents earnings from equity investments for the periods indicated (in thousands):
Combined income statement data for the periods indicated for our equity investments are summarized below (in thousands):
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8. GOODWILL AND INTANGIBLE ASSETS Goodwill Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at the dates indicated (in thousands):
Intangible Assets Intangible assets include customer relationships and contracts. These intangible assets have definite lives and are being amortized on a straight-line basis over their estimated useful lives ranging from 5 to 25 years. Our amortizable customer contracts are contracts that were acquired in connection with the acquisition of BDL in March 1999, the acquisition of the Taylor, Michigan terminal in December 2005, the acquisition of certain pipeline and terminal assets in November 2009, the acquisition of the Yabucoa, Puerto Rico terminal in 2010 and the acquisition of BORCO in 2011 (see Note 2 for further discussion). The customer contracts are being amortized over their contractual life, 5 years in the case of the acquisition of certain pipeline and terminal assets in November 2009 and 5 years in the case of the terminal acquisition in 2010.
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The customer relationships resulted from the acquisition of Farm & Home Oil Company LLC (“Farm & Home”) in 2008 and BORCO in 2011. We determined, through an analysis of historical customer attrition rates at Farm & Home, that an appropriate recovery period for customer relationships is approximately 12 years. For BORCO, due to the high customer demand at the facility, the level of customer service being provided, the expansion capabilities of the facility, the potential of customer recontracting rates and the location of the facility in relation to international shipping routes, we anticipate the customer relationships to extend well beyond the existing contract terms with a recovery period of approximately 25 years. Intangible assets consist of the following at the dates indicated (in thousands):
For the three months ended June 30, 2011 and 2010, amortization expense related to intangible assets was $3.5 million and $1.1 million, respectively. For the six months ended June 30, 2011 and 2010, amortization expense related to intangible assets was $6.3 million and $2.2 million, respectively. Amortization expense related to intangible assets is expected to be approximately $6.7 million for the remainder of 2011 (July 1 through December 31), $13.4 million for 2012, $13.4 million for 2013, $13.2 million for 2014 and $12.2 million for 2015. 9. OTHER NON-CURRENT ASSETS Other non-current assets consist of the following at the dates indicated (in thousands):
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10. ACCRUED AND OTHER CURRENT LIABILITIES Accrued and other current liabilities consist of the following at the dates indicated (in thousands):
11. DEBT OBLIGATIONS Long-term debt consists of the following at the dates indicated (in thousands):
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The fair values of our aggregate debt and credit facilities were estimated to be $2,586.2 million and $1,897.5 million at June 30, 2011 and December 31, 2010, respectively. The fair values of the fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly-issued debt with the market prices of other MLPs’ publicly-issued debt with similar credit ratings and terms. The fair values of the variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. Notes Offering On January 13, 2011, we sold the 4.875% Notes in an underwritten public offering. The notes were issued at 99.62% of their principal amount. Total proceeds from this offering, after underwriters’ fees, expenses and debt issuance costs of $4.9 million, were approximately $642.6 million, and were used to fund a portion of the purchase price for our acquisition of BORCO (see Note 2). In connection with this offering, we settled a treasury lock agreement, which resulted in the receipt of a settlement of $0.5 million, which is being amortized as a reduction to interest expense over the ten-year term of the 4.875% Notes (see Note 14). Bridge Loans In December 2010, in connection with the proposed BORCO acquisition, we obtained a commitment from commercial banks for senior unsecured bridge loans in an aggregate amount up to $595 million (or up to $775 million in the event we purchased both First Reserve’s 80% interest and Vopak’s 20% interest in FRBCH) (the “Bridge Loans”). The commitment was to expire upon the earliest to occur of the termination date as defined in the BORCO sale and purchase agreement, the consummation of the BORCO acquisition, the termination of the BORCO sale and purchase agreement or 120 days after December 18, 2010. We paid $2.0 million of fees in December 2010 associated with these Bridge Loans. In January 2011, we terminated the Bridge Loans upon issuance of the 4.875% Notes. Services Company ESOP Notes At December 31, 2010, Services Company had total debt outstanding of $1.5 million consisting of 3.60% Senior Secured Notes due March 28, 2011 payable by the ESOP to a third-party lender, which were repaid on March 28, 2011. Credit Facility We have a borrowing capacity of $580.0 million under the Credit Facility with SunTrust Bank, as administrative agent, which may be expanded up to $780.0 million subject to certain conditions and upon the further approval of the lenders. The Credit Facility’s maturity date is August 24, 2012, which we may extend for up to two additional one-year periods. Borrowings under the Credit Facility bear interest under one of two rate options, selected by us, equal to either (i) the greater of (a) the federal funds rate plus 0.5% and (b) SunTrust Bank’s prime rate plus an applicable margin, or (ii) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. The applicable margin is determined based on the current utilization level of the Credit Facility and ratings assigned by Standard & Poor’s Rating Services and Moody’s Investor Service for our senior unsecured non-credit enhanced long-term debt. At June 30, 2011 and December 31, 2010, $120.0 million and $98.0 million, respectively, were outstanding under the Credit Facility. The weighted average interest rate for borrowings under the Credit Facility was 0.5% at June 30, 2011. The Credit Facility requires us to maintain a specified ratio (the “Funded Debt Ratio”) of no greater than 5.00 to 1.00 subject to a provision that allows for increases to 5.50 to 1.00 in connection with certain acquisitions. The Funded Debt Ratio is calculated by dividing consolidated debt by annualized EBITDA, which is defined in the Credit Facility as earnings before interest, taxes, depreciation, depletion and amortization, in each case excluding the income of certain of our majority-owned subsidiaries and equity investments (but including distributions from those majority-owned subsidiaries and equity investments). At June 30, 2011, our Funded Debt Ratio was approximately 4.2 to 1.00. As permitted by the Credit Facility, the $267.2 million of borrowings by Buckeye Energy Services LLC (“BES”) under its separate credit agreement (discussed below) was excluded from the calculation of the Funded Debt Ratio.
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In addition, the Credit Facility contains other covenants including, but not limited to, covenants limiting our ability to incur additional indebtedness, to create or incur liens on our property, to dispose of property material to our operations, and to consolidate, merge or transfer assets. At June 30, 2011, we were not aware of any instances of noncompliance with the covenants under our Credit Facility. At June 30, 2011 and December 31, 2010, we had committed $1.5 million and $1.4 million, respectively, in support of letters of credit. The obligations for letters of credit are not reflected as debt on our condensed consolidated balance sheets. BES Credit Agreement BES has a credit agreement (the “BES Credit Agreement”) that provides for borrowings of up to $500.0 million with a maturity date of June 25, 2013. The maximum amount available to be borrowed under the BES Credit Agreement is initially limited to $350.0 million. An accordion feature provides BES the ability to increase the commitments under the BES Credit Agreement to $500.0 million, subject to obtaining the requisite commitments and satisfying other customary conditions. In addition to the accordion, subject to BES’s satisfaction of certain financial covenants as set forth in the financial covenants table below, BES may, from time to time, elect to increase or decrease the maximum amount available for borrowing under the BES Credit Agreement in $5.0 million increments, but in no event below $150.0 million or above $500.0 million. Under the BES Credit Agreement, borrowings accrue interest under one of three rate options, at BES’s election, equal to (i) the Administrative Agent’s Cost of Funds (as defined in the BES Credit Agreement) plus 2.25%, (ii) the Eurodollar Rate (as defined in the BES Credit Agreement) plus 2.25% or (iii) the Prime Rate (as defined in the BES Credit Agreement) plus 1.25%. The BES Credit Agreement also permits Daylight Overdraft Loans (as defined in the BES Credit Agreement), Swingline Loans (as defined in the BES Credit Agreement) and letters of credit. Such alternative extensions of credit are subject to certain conditions as specified in the BES Credit Agreement. The BES Credit Agreement is secured by liens on certain assets of BES, including its inventory, cash deposits (other than certain accounts), investments and hedging accounts, receivables and intangibles. The balances outstanding under the BES Credit Agreement were approximately $267.2 million and $284.3 million at June 30, 2011 and December 31, 2010, respectively, both of which were classified as current liabilities in our condensed consolidated balance sheets. The BES Credit Agreement requires BES to meet certain financial covenants, which are defined in the BES Credit Agreement and summarized below (in millions, except for the leverage ratio):
At June 30, 2011, BES’s Consolidated Tangible Net Worth and Consolidated Net Working Capital were $122.2 million and $82.7 million, respectively, and the Consolidated Leverage Ratio was 3.1 to 1.0. The weighted average interest rate for borrowings outstanding under the BES Credit Agreement was 2.5% at June 30, 2011.
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In addition, the BES Credit Agreement contains other covenants, including, but not limited to, covenants limiting BES’s ability to incur additional indebtedness, to create or incur certain liens on its property, to consolidate, merge or transfer its assets, to make dividends or distributions, to dispose of its property, to make investments, to modify its risk management policy, or to engage in business activities materially different from those presently conducted. At June 30, 2011, we were not aware of any instances of noncompliance with the covenants under the BES Credit Agreement. 12. OTHER NON-CURRENT LIABILITIES Other non-current liabilities consist of the following at the dates indicated (in thousands):
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13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The following table presents the components of accumulated other comprehensive income (loss) (“AOCI”) on the condensed consolidated balance sheets at the dates indicated (in thousands):
14. DERIVATIVE INSTRUMENTS, HEDGING ACTIVITIES AND FAIR VALUE MEASUREMENTS We are exposed to certain risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage risks associated with certain identifiable and anticipated transactions. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates or commodity prices. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. We have no trading derivative instruments. Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in a transaction are highly effective in offsetting changes in cash flows or the fair value of hedged items. A discussion of our derivative activities by risk category follows. Interest Rate Derivatives We utilize forward-starting interest rate swaps to manage interest rate risk related to forecasted interest payments on anticipated debt issuances. This strategy is a component in controlling our cost of capital associated with such borrowings. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the value of the swap transaction is positive and the risk exists that the counterparty will fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by only entering into swap transactions with major financial institutions with investment-grade credit ratings. We manage our market risk by associating each swap transaction with an existing debt obligation or a specified expected debt issuance generally associated with the maturity of an existing debt obligation. Our practice with respect to derivative transactions related to interest rate risk has been to have each transaction in connection with non-routine borrowings authorized by the board of directors of Buckeye GP. In January 2009, Buckeye GP’s board of directors adopted an interest rate hedging policy which permits us to enter into certain short-term interest rate swap agreements to manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s board of directors authorized us to enter into certain transactions, such as forward-starting interest rate swaps, to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.
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We expect to issue new fixed-rate debt (i) on or before July 15, 2013 to repay the $300.0 million of 4.625% Notes that are due on July 15, 2013 and (ii) on or before October 15, 2014 to repay the $275.0 million of 5.300% Notes that are due on October 15, 2014, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. We have entered into six forward-starting interest rate swaps with a total aggregate notional amount of $300.0 million related to the anticipated issuance of debt on or before July 15, 2013 and six forward-starting interest rate swaps with a total aggregate notional amount of $275.0 million related to the anticipated issuance of debt on or before October 15, 2014. The purpose of these swaps is to hedge the variability of the forecasted interest payments on these expected debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. During the three months ended June 30, 2011 and 2010, unrealized losses of $13.8 million and unrealized losses of $34.9 million, respectively, were recorded in accumulated other comprehensive income (loss) to reflect the change in the fair values of the forward-starting interest rate swaps. During the six months ended June 30, 2011 and 2010, unrealized losses of $9.3 million and unrealized losses of $36.2 million, respectively, were recorded in accumulated other comprehensive income (loss). We designated the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings. On January 13, 2011, we issued the 4.875% Notes in an underwritten public offering. In December 2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix the 10-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January 2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875% Notes and received approximately $0.5 million, which is being recognized as a reduction to interest expense over the term of the 4.875% Notes. Over the next twelve months, we expect to reclassify $0.9 million of net losses, consisting of loss attributable to forward-starting interest rate swaps terminated in 2008 associated with our 6.050% Notes, partially offset by a gain attributable to the settlement of the treasury lock agreement associated with the 4.875% Notes in January 2011, from accumulated other comprehensive loss to earnings as an increase to interest and debt expense. Commodity Derivatives Our Energy Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical commodity forward fixed-price purchase and sales contracts. The derivative contracts used to hedge refined petroleum product inventories are designated as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair value of New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. The fair values of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts. Our Energy Services segment has not used hedge accounting with respect to its fixed-price contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset the changes in fair value of the fixed-price sales contracts are all marked-to-market on the condensed consolidated balance sheets with gains and losses being recognized in earnings during the period. In order to hedge the cost of natural gas used to operate our turbine engines at our Linden, New Jersey location, our Pipelines & Terminals segment bought natural gas futures contracts in March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract (through August 2011). We designated the futures contracts as cash flow hedges at inception.
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The following table summarizes our commodity derivative instruments outstanding at June 30, 2011 (amounts in thousands of gallons, except as noted):
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The following table sets forth the fair value of each classification of derivative instruments at the dates indicated (in thousands):
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The following table sets forth the location of derivative instruments on our condensed consolidated balance sheets at the dates indicated (in thousands):
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The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands):
Our hedged inventory portfolio extends to the fourth quarter of 2011. The majority of the unrealized gain of $0.1 million at June 30, 2011 for futures contracts designated as inventory hedging instruments and unrealized gains in the fair values of the underlying hedged refined petroleum product inventories will be realized by the fourth quarter of 2011 as the inventory is sold. At June 30, 2011, open refined petroleum product derivative contracts (represented by the fixed-price contracts and futures contracts for fixed-price sales contracts noted above) varied in duration, but did not extend beyond June 2012. In addition, at June 30, 2011, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.
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The gains and losses reclassified from AOCI to income and the change in value recognized in other comprehensive income (“OCI”) on our derivatives were as follows for the periods indicated (in thousands):
Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the income or market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
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Recurring The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, June 30, 2011 and December 31, 2010, and the basis for that measurement, by level within the fair value hierarchy (in thousands):
The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the NYMEX. The values of the Level 2 interest rate derivatives were determined using expected cash flow models, which incorporated market inputs including the implied forward LIBOR yield curve for the same period as the future interest swap settlements.
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The values of the Level 2 fixed-price contracts assets and liabilities were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 fixed-price contracts assets are net of credit value adjustments (“CVA”) determined using an expected cash flow model, which incorporates assumptions about the credit risk of the fixed-price contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Energy Services segment determined CVA is appropriate because few of the Energy Services segment’s customers entering into these fixed-price contracts are large organizations with nationally-recognized credit ratings. The Level 2 fixed-price contracts assets of $0.6 million and $1.5 million as of June 30, 2011 and December 31, 2010, respectively, are net of CVA of ($0.1) million and ($0.2) million, respectively. As of June 30, 2011, the Energy Services segment did not hold any net liability derivative position containing credit contingent features. Non-Recurring Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of possible impairment. There were no fair value adjustments for such assets or liabilities reflected in our condensed consolidated financial statements for the three and six months ended June 30, 2011 and 2010. 15. PENSIONS AND OTHER POSTRETIREMENT BENEFITS Services Company, which employs the majority of our workforce, sponsors a retirement income guarantee plan (“RIGP”), which is a defined benefit plan that generally guarantees employees hired before January 1, 1986 a retirement benefit based on years of service and the employee’s highest compensation for any consecutive 5-year period during the last 10 years of service or other compensation measures as defined under the respective plan provisions. The retirement benefit is subject to reduction at varying percentages for certain offsetting amounts, including benefits payable under a retirement and savings plan discussed further below. Services Company funds the plan through contributions to pension trust assets, generally subject to minimum funding requirements as provided by applicable law. Services Company also sponsors an unfunded post-retirement benefit plan (the “Retiree Medical Plan”), which provides health care and life insurance benefits to certain of its retirees. To be eligible for these benefits, an employee must have been hired prior to January 1, 1991 and meet certain service requirements.
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The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended June 30, 2011 and 2010 (in thousands):
The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the six months ended June 30, 2011 and 2010 (in thousands):
During the six months ended June 30, 2011, we contributed $2.0 million to the RIGP. 16. UNIT-BASED COMPENSATION PLANS BGH GP has an equity compensation plan (“BGH GP Equity Compensation Plan”) for certain members of our senior management. Compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, compensation expense recorded with respect to the BGH GP Equity Compensation Plan was $0 and $0.6 million, respectively. We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2009 Long-Term Incentive Plan (the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). We recognized compensation expense related to the LTIP and the Option Plan of $2.8 million and $1.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, we recognized compensation expense related to the LTIP and the Option Plan of $4.9 million and $2.5 million, respectively. These compensation plans are discussed below.
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BGH GP’s Override Units Effective on June 25, 2007, BGH GP instituted the BGH GP Equity Compensation Plan. The BGH GP Equity Compensation Plan included both time-based and performance-based participation in the equity of BGH GP (but not ours) referred to as override units. These override units consisted of three equal tranches of units consisting of Value A, Value B and Operating Units. We are required to record, as compensation expense and a corresponding contribution to unitholders’ equity, the fair value of the compensation. We are not the sponsor of this plan and have no obligations with respect to it. Compensation expense related this plan was $0 and $0.3 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, compensation expense related to this plan was $0 and $0.6 million, respectively. On December 31, 2010, the override unit plan was modified. All outstanding Value A and Operating Units were exchanged for LP Units owned by BGH GP. The terms of the Value B Units remained unchanged. The Value B Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 3.5 times the original investment and an internal rate of return of at least 10% or on a pro-rata basis on an investment return ranging from 2.0 to 3.5 times the original investment and an internal rate of return of at least 10%. On January 27, 2011, BGH GP established and granted new override units in BGH GP to a member of senior management, which consisted of Value N-1 and Value N-2 Units. The Value N-1 Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.0 times the original investment up to aggregate distributions of $3.0 million. The Value N-2 Units will participate in distributions by BGH GP based on the occurrence of an exit event and an investment return of 2.5 times the original investment or on a pro-rata basis on an investment return ranging from 2.0 to 2.5 times the original investment up to aggregate distributions of $5.0 million. The exit event with respect to the Value B, Value N-1 and Value N-2 Units is generally defined as the sale by ArcLight, Kelso and their affiliates of their interests in BGH GP, the sale of substantially all the assets of BGH GP and its subsidiaries, or any other “extraordinary” transaction that the Board of Directors of BGH GP determines is an exit event. The investment return is calculated generally as the sum of all the distributions that ArcLight and Kelso have received from BGH GP prior to and through the exit event, divided by the total amount of capital contributions to BGH GP that ArcLight and Kelso have made prior to the exit event. The cumulative grant date fair values of the Value B, Value N-1 and Value N-2 Units that remained unvested as of June 30, 2011 are $2.2 million, $0.9 million and $1.1 million, respectively. The vesting of the override units is contingent on a performance condition, namely the completion of the exit event, and a market condition, primarily relating to the receipt of an investment return at a specified multiple and internal rate of return, where applicable. Accordingly, no compensation expense for these override units will be recorded until, and if, an exit event and other requirements occur. At grant date, the override units were valued using the Monte Carlo simulation method that incorporated the market-based vesting condition into the grant date fair value of the unit awards. The following assumptions were used for grants of the Value N-1 and N-2 Units during the period:
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LTIP The LTIP provides for the issuance of up to 1,500,000 LP Units, subject to certain adjustments. After giving effect to the issuance or forfeiture of phantom unit and performance unit awards through June 30, 2011, awards representing a total of 874,528 additional LP Units could be issued under the LTIP. Under the terms of the Buckeye Partners, L.P. Unit Deferral and Incentive Plan (“Deferral Plan”), eligible employees were allowed to defer up to 50% of their 2011 and 2010 compensation award under our Annual Incentive Compensation Plan or other discretionary bonus program in exchange for grants of phantom units equal in value to the amount of their cash award deferral (each such unit, a “Deferral Unit”). Participants also receive one matching phantom unit for each Deferral Unit. Approximately $1.6 million of 2010 compensation awards had been deferred at December 31, 2010, for which 50,660 phantom units (including matching units) were granted during the six months ended June 30, 2011. These grants are included as granted in the LTIP activity table below. Awards under the LTIP During the six months ended June 30, 2011, the Compensation Committee granted 110,165 phantom units to employees (including the 50,660 phantom units granted pursuant to the Deferral Plan discussed above), 14,000 phantom units to independent directors of Buckeye GP, and 120,740 performance units to employees. The amount paid with respect to phantom unit distribution equivalents under the LTIP was $0.5 million and $0.3 million for the six months ended June 30, 2011 and 2010, respectively. The following table sets forth the LTIP activity for the periods indicated (dollars in thousands):
At June 30, 2011, approximately $19.2 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 1.7 years.
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Unit Option and Distribution Equivalent Plan The following is a summary of the changes in the LP Unit options outstanding (all of which are vested or are expected to vest) under the Option Plan for the periods indicated (dollars in thousands):
The total intrinsic value of options exercised was $0.3 million and $1.0 million during the six months ended June 30, 2011 and 2010, respectively. At June 30, 2011, total unrecognized compensation cost related to unvested LP Unit options was minimal. We expect to recognize this remaining cost over a weighted average period of 0.4 years. At June 30, 2011, 333,000 LP Units were available for grant in connection with the Option Plan. However, with the adoption of the LTIP, we do not expect to make any future grants pursuant to the Option Plan. The fair value of options vested was $0.2 million and $0.4 million during the six months ended June 30, 2011 and 2010, respectively.
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Table of ContentsBUCKEYE PARTNERS, L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
17. RELATED PARTY TRANSACTIONS We are managed by Buckeye GP, our general partner. Services Company is considered a related party with respect to us. As discussed in Note 1, our consolidated financial statements include the financial results of Services Company on a consolidated basis, and all intercompany transactions have been eliminated. Services Company, which is beneficially owned by the ESOP, owned 1.4 million of our LP Units (approximately 1.6% of our LP Units outstanding) as of June 30, 2011. Distributions received by Services Company from us on such LP Units are used to fund obligations of the ESOP. Distributions paid to Services Company totaled $2.9 million and $3.0 million for the six months ended June 30, 2011 and 2010, respectively. Total distributions paid to Services Company decrease over time because Services Company sells LP Units to fund benefits payable to ESOP participants who exit the ESOP. Prior to the Merger, Buckeye GP received incentive distributions from us pursuant to our partnership agreement and incentive compensation agreement. Incentive distributions were based on the level of quarterly cash distributions paid per LP Unit and the total number of LP Units outstanding. Incentive distribution payments totaled $24.9 million during the six months ended June 30, 2010. 18. PARTNERS’ CAPITAL AND DISTRIBUTIONS Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. Our partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units. In accordance with our partnership agreement, capital accounts are maintained for our general partner and limited partners. In conjunction with the Merger, our partnership agreement was amended. Class B Units represent a separate class of our limited partnership interests. The Class B Units share equally with the LP Units (i) with respect to the payment of distributions and (ii) in the event of our liquidation. We have the option to pay distributions on the Class B Units with cash or by issuing additional Class B Units, with the number of Class B Units issued based upon the volume-weighted average price of the LP Units for the 10 trading days immediately preceding the date the distributions are declared, less a discount of 15%. The Class B Units have the same voting rights as if they were outstanding LP Units and are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the Class B Units in relation to other classes of partnership interests or as required by law. The Class B Units will convert into LP Units on a one-for-one basis on the earlier of (a) the date on which at least 4 million barrels of incremental storage capacity are placed in service by BORCO or (b) the third anniversary of the closing of the BORCO acquisition. In April 2011, we issued 5,520,000 LP Units, which included 720,000 LP Units issued as part of the overallotment option, in an underwritten public offering at a public offering price of $59.41 per LP Unit. Total proceeds from the offering, including the overallotment option and after the underwriters’ discount of $1.99 per LP Unit and offering expenses, were approximately $316.6 million, and were used to reduce amounts outstanding under our Credit Facility.
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Table of ContentsBUCKEYE PARTNERS, L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Summary of Changes in Outstanding Units The following is a reconciliation of units outstanding for the periods indicated:
Distributions We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Cash distributions on our LP Units totaled $165.8 million and $122.9 million during the six months ended June 30, 2011 and 2010, respectively. We also paid distributions in kind to our Class B unitholders by issuing 249,290 Class B Units during the six months ended June 30, 2011. On August 5, 2011, we announced a quarterly distribution of $1.0125 per LP Unit that will be paid on August 31, 2011, to LP unitholders of record on August 15, 2011. Total cash distributed to LP unitholders on August 31, 2011 will total approximately $87.2 million. We also expect to issue approximately 130,000 Class B Units in lieu of cash distributions on August 31, 2011, to Class B unitholders of record on August 15, 2011. 19. EARNINGS PER UNIT Basic and diluted earnings per unit (including earnings per unit for LP Units and Class B Units) is calculated by dividing net income, after deducting the amount allocated to noncontrolling interests, by the weighted-average number of LP Units and Class B Units outstanding during the period. Pursuant to the Merger Agreement, BGH’s unitholders received a total of approximately 20.0 million of Buckeye’s LP Units in the aggregate in exchange for all outstanding BGH common units and management units. As a result, the number of Buckeye’s LP Units outstanding increased from 51.6 million to 71.4 million on the date of the Merger. However, for historical reporting purposes, the impact of this change was accounted for as a reverse split of BGH’s units of 0.705 to 1.0, together with the addition of Buckeye’s existing LP Units. Therefore, since BGH was the surviving accounting entity, the weighted average number of units outstanding used for basic and diluted earnings per unit calculations are BGH’s historical weighted average common units outstanding adjusted for the reverse unit split and the addition of Buckeye’s existing LP Units. Amounts reflecting historical BGH unit and per unit amounts included in this report have been restated for the reverse unit split.
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Table of ContentsBUCKEYE PARTNERS, L.P. NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table is a reconciliation of the weighted average number of units used in the basic and diluted earnings per unit calculations for the periods indicated (in thousands, except per unit amounts):
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