Edgar Filing: BUCKEYE PARTNERS, L.P.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Form 10-Q for quarterly period ended March 31, 2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2012

¨	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission file number 1-9356

Buckeye Partners, L.P.

(Exact name of registrant as specified in its charter)


Delaware		23-2432497
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification number)

One Greenway Plaza Suite 600 Houston, TX		77046
(Address of principal executive offices)		(Zip Code)

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 May 2, 2012: 90,323,403 and 7,445,999, respectively.

TABLE OF CONTENTS


	Page
PART I. FINANCIAL INFORMATION
Item 1. *Financial Statements*
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011 (Unaudited)		2
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011 (Unaudited)		3
Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011 (Unaudited)		4
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011 (Unaudited)		5
Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2012 and 2011 (Unaudited)		6
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Organization and Basis of Presentation		7
2. Acquisitions		8
3. Commitments and Contingencies		9
4. Inventories		10
5. Prepaid and Other Current Assets		10
6. Equity Investments		11
7. Derivative Instruments and Hedging Activities		11
8. Fair Value Measurements		17
9. Pensions and Other Postretirement Benefits		18
10. Unit-Based Compensation Plans		18
11. Partners’ Capital and Distributions		19
12. Earnings Per Unit		21
13. Business Segments		21
14. Supplemental Cash Flow Information		24

Item 2. *Management’s Discussion and Analysis of Financial Condition and Results of Operations*		25

Item 3. *Quantitative and Qualitative Disclosures About Market Risk*		33

Item 4. *Controls and Procedures*		36

PART II. OTHER INFORMATION

Item 1. *Legal Proceedings*		36

Item 1A. *Risk Factors*		36

Item 6. *Exhibits*		37

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit amounts)

(Unaudited)


	Three Months Ended March 31,
	2012			2011
Revenue:
Product sales	$	1,027,888		$	1,037,556
Transportation and other services		231,551			214,980

Total revenue		1,259,439			1,252,536

Costs and expenses:
Cost of product sales and natural gas storage services		1,031,485			1,037,962
Operating expenses		97,555			80,264
Depreciation and amortization		33,027			26,241
General and administrative		16,975			15,506

Total costs and expenses		1,179,042			1,159,973

Operating income		80,397			92,563

Other income (expense):
Earnings from equity investments		1,949			3,347
Interest and debt expense		(28,810	)		(28,497	)
Other (expense) income		(69	)		400

Total other expense, net		(26,930	)		(24,750	)

Net income		53,467			67,813
Less: Net income attributable to noncontrolling interests		(1,508	)		(1,320	)

Net income attributable to Buckeye Partners, L.P.	$	51,959		$	66,493

Earnings per unit:
Basic	$	0.55		$	0.79

Diluted	$	0.54		$	0.79

Weighted average units outstanding:
Basic		95,229			83,669

Diluted		95,558			83,954

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)


	Three Months Ended
	March 31,
	2012			2011
Net income	$	53,467		$	67,813
Other comprehensive income (loss):
Change in value of derivatives		17,303			4,847
Gain on settlement of treasury lock, net of amortization		(12	)		489
Adjustment to funded status of benefit plans		23			(110	)

Total other comprehensive income		17,314			5,226

Comprehensive income		70,781			73,039
Less: Comprehensive income attributable to noncontrolling interests		(1,508	)		(1,320	)

Comprehensive income attributable to Buckeye Partners, L.P.	$	69,273		$	71,719

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except unit amounts)

(Unaudited)


	March 31,			December 31,
	2012			2011
Assets:
Current assets:
Cash and cash equivalents	$	15,059		$	12,986
Trade receivables, net		191,798			206,601
Construction and pipeline relocation receivables		8,922			8,662
Inventories		187,407			298,304
Derivative assets		5,271			6,756
Prepaid and other current assets		62,668			92,727

Total current assets		471,125			626,036

Property, plant and equipment, net		3,901,921			3,847,573

Equity investments		65,904			65,882
Goodwill		753,100			753,100
Intangible assets, net		226,422			230,568
Other non-current assets		46,640			47,217

Total assets	$	5,465,112		$	5,570,376

Liabilities and partners’ capital:
Current liabilities:
Line of credit	$	151,400		$	251,200
Accounts payable		70,775			102,445
Derivative liabilities		3,326			1,859
Accrued and other current liabilities		168,407			199,475

Total current liabilities		393,908			554,979

Long-term debt		2,249,741			2,393,574
Long-term derivative liabilities		84,850			101,911
Other non-current liabilities		186,525			195,955

Total liabilities		2,915,024			3,246,419

Commitments and contingent liabilities (Note 3)

Partners’ capital:
Buckeye Partners, L.P. capital:
Limited Partners (90,299,908 and 85,968,423 units outstanding as of March 31, 2012 and December 31, 2011, respectively)		2,239,600			2,035,271
Class B Units (7,445,999 and 7,304,880 units outstanding as of March 31, 2012 and December 31, 2011, respectively)		399,652			395,639
Accumulated other comprehensive loss		(110,427	)		(127,741	)

Total Buckeye Partners, L.P. capital		2,528,825			2,303,169
Noncontrolling interests		21,263			20,788

Total partners’ capital		2,550,088			2,323,957

Total liabilities and partners’ capital	$	5,465,112		$	5,570,376

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities:
Net income	$	53,467		$	67,813
Adjustments to reconcile net income to net cash provided by operating activities:
Value of ESOP shares released		—			1,183
Depreciation and amortization		33,027			26,241
Net changes in fair value of derivatives		2,952			(78,611	)
Non-cash deferred lease expense		975			1,030
Amortization of unfavorable storage contracts		(2,748	)		(1,932	)
Earnings from equity investments		(1,949	)		(3,347	)
Distributions from equity investments		1,853			1,793
Amortization of other non-cash items		4,412			3,134
Change in assets and liabilities, net of amounts related to acquisitions:
Trade receivables		14,803			6,864
Construction and pipeline relocation receivables		(260	)		1,377
Inventories		110,897			169,679
Prepaid and other current assets		31,156			7,679
Accounts payable		(31,670	)		(25,349	)
Accrued and other current liabilities		(27,532	)		(24,634	)
Other non-current assets		1,853			5,107
Other non-current liabilities		(9,635	)		(1,645	)

Net cash provided by operating activities		181,601			156,382

Cash flows from investing activities:
Capital expenditures		(74,313	)		(38,033	)
Deposit in anticipation of acquisition		(14,000	)		(22,427	)
Acquisitions, net of cash acquired		—			(895,255	)
Proceeds from disposal of property, plant and equipment		317			42

Net cash used in investing activities		(87,996	)		(955,673	)

Cash flows from financing activities:
Net proceeds from issuance of units		247,461			420,405
Net proceeds from exercise of unit options		(61	)		270
Issuance of long-term debt		—			647,530
Repayment of long term-debt		—			(1,525	)
Borrowings under BPL Credit Facilities		111,000			521,500
Repayments under BPL Credit Facilities		(255,000	)		(284,500	)
Net borrowings (repayments) under BES Credit Facility		(99,800	)		(49,300	)
Debt issuance costs		—			(4,919	)
Repayment of debt assumed in BORCO acquisition		—			(318,167	)
Costs associated with agreement and plan of merger		—			(344	)
Distributions paid to noncontrolling interests		(2,395	)		(1,204	)
Proceeds from settlement of treasury lock		—			497
Distributions paid to unitholders		(92,737	)		(78,148	)

Net cash provided by (used in) financing activities		(91,532	)		852,095

Net increase in cash and cash equivalents		2,073			52,804
Cash and cash equivalents — Beginning of period		12,986			13,626

Cash and cash equivalents — End of period	$	15,059		$	66,430

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In thousands)

(Unaudited)


	Limited Partners			Class B Units		Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total
Partners’ capital—January 1, 2012	$	2,035,271		$	395,639	$	(127,741	)	$	20,788		$	2,323,957
Net income		47,946			4,013		—			1,508			53,467
Distributions paid to unitholders		(94,090	)		—		—			1,353			(92,737	)
Net proceeds from issuance of units		247,461			—		—			—			247,461
Amortization of unit-based compensation awards		2,627			—		—			—			2,627
Net proceeds from exercise of unit options		(61	)		—		—			—			(61	)
Distributions paid to noncontrolling interests		—			—		—			(1,042	)		(1,042	)
Other comprehensive income		—			—		17,314			—			17,314
Noncash accrual for distribution equivalent rights		(241	)		—		—			—			(241	)
Other		687			—		—			(1,344	)		(657	)

Partners’ capital—March 31, 2012	$	2,239,600		$	399,652	$	(110,427	)	$	21,263		$	2,550,088


Partners’ capital—January 1, 2011	$	1,413,664		$	—	$	(21,259	)	$	17,855		$	1,410,260
Net income		56,783			9,710		—			1,320			67,813
Acquisition of 80% interest in BORCO		—			—		—			276,508			276,508
Acquisition of remaining interest in BORCO		—			—		—			(278,211	)		(278,211	)
Costs associated with agreement and plan of merger		(344	)		—		—			—			(344	)
Distributions paid to unitholders		(78,148	)		—		—			—			(78,148	)
Issuance of units to First Reserve for BORCO acquisition		152,772			254,619		—			—			407,391
Issuance of units to Vopak for BORCO acquisition		36,041			60,069		—			—			96,110
Net proceeds from issuance of units		347,334			73,071		—			—			420,405
Amortization of unit-based compensation awards		1,986			—		—			—			1,986
Exercise of LP Unit options		270			—		—			—			270
Services Company’s non-cash ESOP distributions		—			—		—			(1,410	)		(1,410	)
Distributions paid to noncontrolling interests		—			—		—			(1,204	)		(1,204	)
Other comprehensive income		—			—		5,226			—			5,226
Noncash accrual for distribution equivalent rights		(267	)		—		—			—			(267	)
Other		(454	)		—		—			3,106			2,652

Partners’ capital—March 31, 2011	$	1,929,637		$	397,469	$	(16,033	)	$	17,964		$	2,329,037

See Notes to Unaudited Condensed Consolidated Financial Statements.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

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. 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 over 6,000 miles of pipeline and over 100 active products terminals which provide aggregate storage capacity of over 64 million barrels. In addition, we operate and/or maintain approximately 2,800 miles of third-party 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 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. Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”) is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a premier global logistics hub.

Basis of Presentation and Principles of Consolidation

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”). Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. We have eliminated all intercompany transactions in consolidation.

We believe that the disclosures in these condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Developments

Intangibles, Goodwill and Other. In September 2011, the Financial Accounting Standards Board (“FASB”) issued guidance that amended testing goodwill for impairment. Under the revised guidance, entities testing goodwill for impairment have the option of performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step 1 of the goodwill impairment test). If entities determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step impairment test would be required. The amended guidance does not change how goodwill is calculated or assigned to reporting units nor revise the requirement to test goodwill for impairment annually or between annual tests if events or circumstances warrant. However, it does revise the examples of events and circumstances that an entity should consider. The amendments are effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We applied the amended guidance for our annual goodwill impairment test as of January 1, 2012 based on the facts and circumstances within each reporting unit. The adoption of this guidance did not have an impact on our condensed consolidated financial statements.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Presentation of Comprehensive Income. In June 2011, the FASB issued new guidance regarding the presentation of comprehensive income. This guidance requires entities to present reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement in which the components of net income and components of other comprehensive income are presented. It also eliminates the current option under U.S. GAAP to present components of other comprehensive income within the statement of changes in stockholders’ equity. The components of comprehensive income are required to be presented within either (i) a single continuous statement of comprehensive income or (ii) two separate but consecutive statements. This guidance is effective for interim and annual periods beginning after December 15, 2011. Since this issuance only impacts the presentation of such financial information, adoption of this guidance did not have an impact on our condensed consolidated financial statements. On December 23, 2011, the FASB issued guidance to defer the new requirement to present reclassifications of other comprehensive income on the face of the income statement. The FASB is expected to redeliberate the accounting for reclassification adjustments (for both interim and annual periods) later this year.

2. ACQUISITIONS

Pipelines 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 Products North America Inc. and its affiliates for $166.0 million. The purchase price has been allocated to tangible and intangible assets acquired and liabilities assumed, on a preliminary basis, as follows (in thousands):


Inventory	$	1,161
Property, plant and equipment		174,597
Intangible assets		8,940
Environmental and other liabilities		(18,722	)

Allocated purchase price	$	165,976

Pending Acquisition

On February 9, 2012, we signed a definitive agreement with Chevron U.S.A Inc. (“Chevron”) to acquire a marine terminal facility for liquid petroleum products in New York Harbor (the “Perth Amboy Facility”) for $260.0 million in cash. In anticipation of the acquisition, we paid a deposit of $14.0 million to Chevron in February 2012. The facility, which sits on approximately 250 acres on the Arthur Kill in Perth Amboy, New Jersey, has over 4 million barrels of tankage, four docks, and significant undeveloped land available for potential expansion. The Perth Amboy Facility has water, pipeline, rail, and truck access, and is located only six miles from our Linden, New Jersey complex. Chevron agreed to enter into multi-year storage, blending, and throughput commitments with us concurrent with the acquisition. The Perth Amboy Facility will provide a link between our inland pipelines and terminals and our BORCO facility in The Bahamas, improving service offerings for our customers and providing further support to our planned clean products tankage expansion at the BORCO facility. The operations of the Perth Amboy Facility will be reported in our Pipelines & Terminals segment upon closing, which is expected to close late in the second quarter or early in the third quarter of 2012.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

3. COMMITMENTS AND CONTINGENCIES

Claims and Legal 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.

On March 30, 2012, the Federal Energy Regulatory Commission (“FERC”) issued an order (the “Order”) regarding the market-based methodology used by Buckeye Pipe Line Company, L.P., (“BPLC”) to set tariff rates on its pipeline system (the “Buckeye System”). In 1991, BPLC sought and received FERC permission to determine rate changes on the Buckeye System using a unique methodology that constrains rates based on competitive pressures in markets that FERC found to be competitive as well as certain other limits on rate increases. FERC permitted the continuation of this methodology for the Buckeye System in 1994, subject to FERC’s authority to cause BPLC to terminate the program in the future. The Order, among other things, states that FERC will review the continued efficacy of BPLC’s unique program and directs BPLC to show cause why it should not be required to discontinue the program on the Buckeye System and avail itself of the generic ratemaking methodologies used by other oil pipelines. Pending FERC’s review of the program, the Order also disallowed proposed rate increases on the Buckeye System that would have become effective April 1, 2012. BPLC is preparing its response to FERC, which is due on May 15, 2012. The timing or outcome of final resolution of this matter cannot reasonably be determined at this time. The Order does not impact any of the pipeline systems or terminals owned by Buckeye’s other operating subsidiaries.

Environmental Contingencies

We recorded operating expenses, net of recoveries, of $1.2 million and $1.1 million during the three months ended March 31, 2012 and 2011, respectively, related to environmental remediation expenditures unrelated to claims and legal proceedings. As of March 31, 2012 and December 31, 2011, we recorded environmental liabilities of $57.3 million and $58.4 million, respectively. Costs incurred may be in excess of our estimate, which may have a material impact our financial condition, results of operations or cash flows.

Ammonia Contract Contingencies

On November 30, 2005, Buckeye Development & Logistics I LLC (“BDL”) 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.

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,

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 EPME ceases paying for ammonia costs under the contracts at issue, including commencing litigation or pursuing other recourse against EPME and El Paso, with respect to this matter.

4. INVENTORIES

Our inventory amounts were as follows at the dates indicated (in thousands):


	March 31,		December 31,
	2012		2011
Refined petroleum products (1)	$	174,012		$	285,509
Materials and supplies		13,395			12,795

Total inventories	$	187,407		$	298,304

(1)	Ending inventory was 55.0 million and 99.6 million gallons of refined petroleum products at March 31, 2012 and December 31, 2011, respectively.

At March 31, 2012 and December 31, 2011, approximately 86% and 96% of our refined petroleum products inventory volumes were hedged, respectively. Because we generally designate inventory as a hedged item upon purchase, 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 the lower of cost or market using the weighted average cost method.

5. PREPAID AND OTHER CURRENT ASSETS

Prepaid and other current assets consist of the following at the dates indicated (in thousands):


	March 31,		December 31,
	2012		2011
Prepaid insurance	$	8,519	$	12,028
Insurance receivables related to environmental expenditures		12,230		12,724
Ammonia receivable		1,183		1,288
Margin deposits		2,412		9,871
Prepaid services		10,552		8,661
Unbilled revenue		1,275		10,090
Tax receivable		—		1,610
Prepaid taxes		5,875		1,677
Vendor prepaid		9,380		14,903
Other		11,242		19,875

Total prepaid and other current assets	$	62,668	$	92,727

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

6. EQUITY INVESTMENTS

The following table presents earnings from equity investments for the periods indicated (in thousands):


	Three Months Ended
	March 31,
	2012		2011
Muskegon Pipeline LLC	$	263	$	183
Transport4, LLC		—		58
West Shore Pipe Line Company		1,685		1,548
West Texas LPG Pipeline Limited Partnership (1)		—		1,558
South Portland Terminal LLC (2)		1		—

Total earnings from equity investments	$	1,949	$	3,347

(1)	In May 2011, we sold our 20% interest in West Texas LPG Pipeline Limited Partnership (“WT LPG”). Amounts for WT LPG are included through the date of the sale of our interest.

(2)	In July 2011, we acquired a 50% interest.

Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent 100% of investee income statement data in thousands):


	Three Months Ended
	March 31,
	2012			2011 (1)
Revenue	$	16,299		$	33,303
Costs and expenses		(8,264	)		(17,008	)
Non-operating expense		(3,137	)		(3,553	)

Net income	$	4,898		$	12,742

(1)	In May 2011, we sold our 20% interest in WT LPG. Amounts for WT LPG are included through the date of the sale of our interest.

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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 forecasted transactions. Derivatives are financial and physical 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 physical contracts, swaps and other instruments with similar characteristics. We have no trading derivative instruments and do not engage in hedging activity with respect to trading instruments.

We 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.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 by mitigating the adverse effect of a change in the capital markets. 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 change in fair value of the swap instrument is positive and the counterparty may 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 entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying 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 February 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 a 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.

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 March 31, 2012 and 2011, unrealized gains of $17.1 million and $4.5 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. We designated the swap agreements as cash flow hedges at inception and expect the changes in value to be highly correlated with the changes in value of the underlying borrowings.

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. The time value component is excluded from our hedge assessment and reported directly in earnings. 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.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 addition, futures contracts were executed to economically hedge a portion of the Energy Services segment’s refined petroleum products held in inventory. The mark-to-market is recorded on the condensed consolidated balance sheets with gains and losses being recognized in earnings during the period.

The following table summarizes our commodity derivative instruments outstanding at March 31, 2012 (amounts in thousands of gallons):

Volume (1)

Accounting

Derivative Purpose

Current

Long-Term

Treatment

Derivatives NOT designated as hedging instruments:

Physical fixed price derivative contracts for refined products

14,591

—

Mark-to-market

Physical index derivative contracts

29,915

—

Mark-to-market

Futures contracts for refined products

10,609

—

Mark-to-market

Derivatives designated as hedging instruments:

Futures contracts for refined products

44,394

—

Fair value hedge

Physical fixed price derivative contracts

3,150

—

Fair value hedge

(1)	Volume represents absolute value of net notional volume position.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the fair value of each classification of derivative instruments at the dates indicated (in thousands):


	March 31, 2012
	Derivatives			Derivatives						Netting
	NOT Designated			Designated			Derivative			Balance
	as Hedging			as Hedging			Carrying			Sheet
	Instruments			Instruments			Value			Adjustment			Total
Physical fixed price derivative contracts	$	1,466		$	—		$	1,466		$	(61	)	$	1,405
Physical index derivative contracts		615			—			615			(4	)		611
Futures contracts for refined products		3,072			3,305			6,377			(3,122	)		3,255

Total current derivative assets		5,153			3,305			8,458			(3,187	)		5,271

Physical derivative contracts		(819	)		(2,384	)		(3,203	)		61			(3,142	)
Physical index derivative contracts		(188	)		—			(188	)		4			(184	)
Futures contract for refined products		(2,755	)		(367	)		(3,122	)		3,122			—

Total current derivative liabilities		(3,762	)		(2,751	)		(6,513	)		3,187			(3,326	)

Interest rate derivatives		—			(84,850	)		(84,850	)		—			(84,850	)

Total non-current derivative liabilities		—			(84,850	)		(84,850	)		—			(84,850	)

Net derivative assets (liabilities)	$	1,391		$	(84,296	)	$	(82,905	)	$	—		$	(82,905	)


	December 31, 2011
	Derivatives			Derivatives						Netting
	NOT Designated			Designated			Derivative			Balance
	as Hedging			as Hedging			Carrying			Sheet
	Instruments			Instruments			Value			Adjustment			Total
Physical fixed price derivative contracts	$	5,351		$	—		$	5,351		$	(59	)	$	5,292
Physical index derivative contracts		853			—			853			(19	)		834
Futures contracts for refined products		3,594			2,664			6,258			(5,628	)		630

Total current derivative assets		9,798			2,664			12,462			(5,706	)		6,756

Physical derivative contracts		(1,304	)		—			(1,304	)		59			(1,245	)
Physical index derivative contracts		(633	)		—			(633	)		19			(614	)
Futures contract for refined products		(3,154	)		(2,474	)		(5,628	)		5,628			—

Total current derivative liabilities		(5,091	)		(2,474	)		(7,565	)		5,706			(1,859	)

Interest rate derivatives		—			(101,911	)		(101,911	)		—			(101,911	)

Total non-current derivative liabilities		—			(101,911	)		(101,911	)		—			(101,911	)

Net derivative assets (liabilities)	$	4,707		$	(101,721	)	$	(97,014	)	$	—		$	(97,014	)

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Our hedged inventory portfolio extends to the third quarter of 2012. The majority of the unrealized gain of $0.6 million at March 31, 2012 for inventory hedges represented by futures contracts will be realized by the third quarter of 2012 as the inventory is sold. At March 31, 2012, open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for fixed-price sales contracts noted above) varied in duration in the overall portfolio, but did not extend beyond March 2013. In addition, at March 31, 2012, we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts.

The following table sets forth the location of derivative instruments on our condensed consolidated balance sheets at the dates indicated (in thousands):


	March 31,			December 31,
	2012			2011
Derivative assets	$	5,271		$	6,756
Derivative liabilities		(3,326	)		(1,859	)
Long-term derivative liabilities		(84,850	)		(101,911	)

Total	$	(82,905	)	$	(97,014	)

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands):


		Gain (Loss) Recognized
		in Income on Derivatives
		Three Months Ended
		March 31,
	Location	2012			2011
Derivatives NOT designated as hedging instruments:

Physical fixed price derivative contracts	Product sales	$	(893	)	$	(3,791	)
Physical index derivative contracts	Product sales		102			—
Physical fixed price derivative contracts	Cost of product sales and natural gas storage services		(1,387	)		1,035
Physical index derivative contracts	Cost of product sales and natural gas storage services		(43	)		—
Futures contracts for refined products	Cost of product sales and natural gas storage services		3,371			(2,149	)

Derivatives designated as fair value hedging instruments:

Futures contracts for refined products	Cost of product sales and natural gas storage services	$	(29,171	)	$	(56,900	)
Physical inventory—hedged items	Cost of product sales and natural gas storage services		28,458			50,419

Ineffectiveness excluding the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	Cost of product sales and natural gas storage services	$	(732	)	$	4,049
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services		20			(10,529	)

Net loss in income		$	(712	)	$	(6,480	)


The gains and losses reclassified from accumulated other comprehensive income (“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):

		Gain (Loss) Reclassified from AOCI to Income
		Three Months Ended March 31,
	Location	2012			2011
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	—		$	(120	)
Interest rate contracts	Interest and debt expense		(230	)		(233	)


	Change in Value Recognized in OCI on Derivatives
	Three Months Ended March 31,
	2012		2011
Derivatives designated as cash flow hedging instruments:
Futures contracts for natural gas	$	—	$	(29	)
Interest rate contracts		17,061		5,012

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

8. FAIR VALUE MEASUREMENTS

We categorize our financial assets and liabilities using the three-tier hierarchy as follows.

Recurring

The following table sets forth financial assets and liabilities, measured at fair value on a recurring basis, as of the measurement dates, March 31, 2012 and December 31, 2011, and the basis for that measurement, by level within the fair value hierarchy (in thousands):


	March 31, 2012					December 31, 2011
	Level 1		Level 2			Level 1		Level 2
Financial assets:
Physical fixed price derivative contracts	$	—	$	1,405		$	—	$	5,292
Physical index derivative contracts		—		611			—		834
Futures contracts for refined products		3,255		—			630		—

Financial liabilities:
Physical fixed price derivative contracts		—		(3,142	)		—		(1,245	)
Physical index derivative contracts		—		(184	)		—		(614	)
Interest rate derivatives		—		(84,850	)		—		(101,911	)

Fair value	$	3,255	$	(86,160	)	$	630	$	(97,644	)

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 London Interbank Offered Rate yield curve for the same period as the future interest swap settlements.

The values of the Level 2 physical derivative 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 physical derivative 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 physical derivative 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 physical derivative contracts are large organizations with nationally-recognized credit ratings. The Level 2 physical derivative contracts assets of $2.0 million and $6.1 million as of March 31, 2012 and December 31, 2011, respectively, are net of CVA of ($0.1) million for both periods, respectively. As of March 31, 2012, the Energy Services segment did not hold any net liability derivative position containing credit contingent features.

Cash and cash equivalents, prepaid and other current assets and accrued and other current liabilities are reported in the condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our 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 our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. Using level 2 input values, the fair values of our aggregate debt and credit facility were estimated to be $2,548.8 million and $2,811.7 million at March 31, 2012 and December 31, 2011, respectively.

Our policy is to recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the three months ended March 31, 2012 and 2011, respectively.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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. For the three months ended March 31, 2012 and 2011, there were not any fair value adjustments related to such assets or liabilities reflected in our condensed consolidated financial statements.

9. PENSIONS AND OTHER POSTRETIREMENT BENEFITS

Buckeye Pipe Line Services Company (“Services Company”), which employs the majority of our workforce, sponsors a defined benefit plan, Retirement Income Guarantee Plan (“RIGP”) and an unfunded post-retirement benefit plan (the “Retiree Medical Plan”). The components of the net periodic benefit cost for the RIGP and Retiree Medical Plan were as follows for the three months ended March 31, 2012 and 2011 (in thousands):


	RIGP						Retiree Medical Plan
	Three Months Ended March 31,						Three Months Ended March 31,
	2012			2011			2012			2011
Service cost	$	71		$	63		$	76		$	86
Interest cost		207			200			482			457
Expected return on plan assets		(87	)		(106	)		—			—
Amortization of prior service benefit		—			—			(741	)		(741	)
Amortization of unrecognized losses		454			337			311			294

Net periodic benefit costs	$	645		$	494		$	128		$	96

During the three months ended March 31, 2012, we contributed $2.3 million to the RIGP. We expect to contribute an additional $0.7 million for the year ending December 31, 2012.

10. UNIT-BASED COMPENSATION PLANS

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 $2.6 million and $2.1 million for the three months ended March 31, 2012 and 2011, respectively. These compensation plans are discussed below.

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 March 31, 2012, awards representing a total of 557,118 additional LP Units could be issued under the LTIP.

Approximately $0.7 million of 2011 compensation awards were deferred at December 31, 2011, for which 23,426 phantom units (including matching units) were granted during the three months ended March 31, 2012. These grants are included as granted in the LTIP activity table below.

Awards under the LTIP

During the three months ended March 31, 2012, the Compensation Committee granted 224,431 phantom units to employees (including the 23,426 phantom units granted pursuant to the Deferral Plan discussed above), 14,000 phantom units to independent directors of Buckeye GP and 125,789 performance units to employees. The amounts paid with respect to phantom unit distribution equivalents under the LTIP were $0.4 million and $0.3 million for the three months ended March 31, 2012 and 2011, respectively.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts):


	Number of LP Units			Weighted- Average Grant Date Fair Value per LP Unit (1)		Total Value
Unvested at January 1, 2012		585		$	56.75	$	33,217
Granted		364			63.29		23,051
Vested		(66	)		48.83		(3,208	)
Forfeited		(43	)		42.55		(1,845	)

Unvested at March 31, 2012		840		$	60.94	$	51,215

(1)	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures.

At March 31, 2012, approximately $32.6 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of approximately 1.9 years.

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 (in thousands, except per unit amount):


	Number of LP Units			Weighted- Average Strike Price ($/LP Unit)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (1)
Outstanding at January 1, 2012		97		$	46.81
Exercised		(20	)		46.38

Outstanding at March 31, 2012		77			46.92		4.0	$	1,101

Exercisable at March 31, 2012		77		$	46.92		4.0	$	1,101

(1)

Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in March 2012 and the exercise price, multiplied by the number of exercisable, in-the-money options.

The total intrinsic value of options exercised was $0.3 million and $0.1 million during the three months ended March 31, 2012 and 2011, respectively.

11. PARTNERS’ CAPITAL AND DISTRIBUTIONS

In February 2012, we issued 4,262,575 LP Units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Revolving Credit Agreement dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank and have also funded a portion of the Perth Amboy Facility and certain other growth capital expenditures.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Summary of Changes in Outstanding Units

The following is a summary of changes in units outstanding for the periods indicated (in thousands):


	Limited Partners		Class B Units		Total
Units outstanding at January 1, 2012		85,968		7,305		93,273
LP Units issued pursuant to the Option Plan (1)		19		—		19
LP Units issued pursuant to the LTIP (1)		50		—		50
Issuance of units to institutional investors		4,263		—		4,263
Issuance of Class B Units in lieu of quarterly cash distributions		—		141		141

Units outstanding at March 31, 2012		90,300		7,446		97,746

(1)	The number of units issued represents issuance net of tax withholding.

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 $94.1 million and $79.3 million during the three months ended March 31, 2012 and 2011, respectively. We also paid distributions in-kind to our Class B unitholders by issuing 141,119 Class B Units during the three months ended March 31, 2012.

On May 4, 2012, we announced a quarterly distribution of $1.0375 per LP Unit that will be paid on May 31, 2012, to LP unitholders of record on May 14, 2012. Cash distributed to LP unitholders on May 31, 2012 will total approximately $94.2 million. We also expect to issue approximately 160,000 Class B Units in lieu of cash distributions on May 31, 2012, to Class B unitholders of record on May 14, 2012.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

12. EARNINGS PER UNIT

The following table is a reconciliation of the weighted average units used in computing the basic and diluted earnings per unit for the periods indicated (in thousands, except per unit amounts):


	Three Months Ended March 31,
	2012		2011
Net income attributable to Buckeye Partners, L.P.	$	51,959	$	66,493
Basic:
Weighted average units outstanding		95,229		83,669

Earnings per unit—basic	$	0.55	$	0.79

Diluted:
Units used for basic calculation		95,229		83,669
Dilutive effect of LP Unit options and LTIP awards granted		329		285

Units for diluted		95,558		83,954

Earnings per unit—diluted	$	0.54	$	0.79

13. BUSINESS SEGMENTS

We operate and report in five business segments: (i) Pipelines & Terminals; (ii) International Operations; (iii) Natural Gas Storage; (iv) Energy Services; and (v) Development & Logistics.

Pipelines & Terminals

The Pipelines & Terminals segment receives refined petroleum products from refineries, connecting pipelines, and bulk and marine terminals and transports those products to other locations for a fee and provides bulk storage and terminal throughput services in the continental United States. This segment owns and operates over 6,000 miles of pipeline systems in 16 states. The segment has approximately 100 refined petroleum products terminals, which includes five terminals owned by the Energy Services segment but operated by the Pipelines & Terminals segment, in 21 states with aggregate storage capacity of approximately 37.4 million barrels.

International Operations

The International Operations segment provides marine bulk storage and marine terminal throughput services. The segment has two liquid petroleum product terminals, one in Puerto Rico and one on Grand Bahama Island in The Bahamas, with an aggregate storage capacity of approximately 26.1 million barrels.

Natural Gas Storage

The Natural Gas Storage segment provides natural gas storage services at a natural gas storage facility in Northern California. The facility has approximately 30 Bcf of working natural gas storage capacity and is connected to Pacific Gas and Electric’s intrastate natural gas pipelines that services natural gas demand in the San Francisco and Sacramento, California areas. The Natural Gas Storage segment does not trade or market natural gas.

Energy Services

The Energy Services segment is a wholesale distributor of refined petroleum products in the Northeastern and Midwestern United States. This segment recognizes revenue when products are delivered. The segment’s products include gasoline, propane, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel and kerosene.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The segment owns five terminals with aggregate storage capacity of approximately 1.0 million barrels, which are operated by the Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products.

Development & Logistics

The Development & Logistics segment consists primarily of our contract operations of approximately 2,800 miles of third-party pipeline, which are owned principally by major oil and gas, petrochemical and chemical companies and are located primarily in Texas and Louisiana. This segment also performs pipeline construction management services, typically for cost plus a fixed fee, for these same customers. The Development & Logistics segment also includes our ownership and operation of two underground propane storage caverns in Indiana and Illinois, an ammonia pipeline and our majority ownership of the Sabina Pipeline, located in Texas.

Adjusted EBITDA

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. We define EBITDA, a measure not defined under GAAP, as net income attributable to our unitholders before interest and debt expense, income taxes and depreciation and amortization. Adjusted EBITDA eliminates (i) non-cash expenses, including but not limited to depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

Each segment uses the same accounting policies as those used in the preparation of our condensed consolidated financial statements. All inter-segment revenue has been eliminated. All periods are presented on a consistent basis. All of our operations and assets are conducted and located in the continental United States, except for our terminals located in Puerto Rico and The Bahamas.

The following table summarizes our revenue by each segment for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012			2011
Revenue:
Pipelines & Terminals	$	165,928		$	144,206
International Operations (1)		50,235			45,075
Natural Gas Storage		10,211			19,604
Energy Services		1,030,426			1,051,312
Development & Logistics		12,465			9,591
Intersegment		(9,826	)		(17,252	)

Total revenue	$	1,259,439		$	1,252,536

(1)	The International Operations segment’s revenue generated in The Bahamas was $46.1 million and $41.4 million for the three months ended March 31, 2012 and 2011, which represented 91.8% and 91.9%, respectively, of the International Operations segment’s total revenue for the periods.

BUCKEYE PARTNERS, L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2012 and 2011, no customer contributed 10% or more of consolidated revenue.

The following table presents Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income to Adjusted EBITDA for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012			2011
Adjusted EBITDA:
Pipelines & Terminals	$	88,232		$	90,120
International Operations		31,666			25,507
Natural Gas Storage		(1,268	)		2,452
Energy Services		(6,172	)		2,759
Development & Logistics		2,529			1,401

Total Adjusted EBITDA	$	114,987		$	122,239


Reconciliation of Net Income to Adjusted EBITDA:
Net income	$	53,467		$	67,813
Less: Net income attributable to noncontrolling interests		(1,508	)		(1,320	)

Net income attributable to Buckeye Partners, L.P.		51,959			66,493
Add: Interest and debt expense		28,810			28,497
Income tax expense (benefit)		337			(176	)
Depreciation and amortization		33,027			26,241
Non-cash deferred lease expense		975			1,030
Non-cash unit-based compensation expense		2,627			2,086
Less: Amortization of unfavorable storage contracts		(2,748	)		(1,932	)

Adjusted EBITDA	$	114,987		$	122,239

(1)	Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

14. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012			2011
Cash paid for interest (net of capitalized interest)	$	48,045		$	32,708
Cash paid for income taxes		2,302			15
Capitalized interest		2,041			1,543

Non-cash changes in assets and liabilities:
Change in accrued and other current liabilities related to capital expenditures	$	(4,144	)	$	(218	)

Non-cash financing activities:
Issuance of units to First Reserve for BORCO acquisition	$	—		$	407,391
Issuance of units to Vopak for BORCO acquisition		—			96,110
Issuance of Class B Units in lieu of quarterly cash distribution		7,579			6,709

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q (this “Report”) contains various forward-looking statements and information that are based on our beliefs, as well as assumptions made by us and information currently available to us. When used in this Report, words such as “proposed,” “anticipate,” “project,” “potential,” “could,” “should,” “continue,” “estimate,” “expect,” “may,” “believe,” “will,” “plan,” “seek,” “outlook” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we believe that such expectations reflected in such forward-looking statements are reasonable, we cannot give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Part I and Part II of “Item 1A, Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2011 and in this Report, respectively. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this Report.

Overview of Business

Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership 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. As used in this Report, unless otherwise indicated, “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 over 6,000 miles of pipeline and over 100 active products terminals that provide aggregate storage capacity of approximately 64 million barrels. We also operate and/or maintain approximately 2,800 miles of third-party 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 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. Our flagship marine terminal in The Bahamas, Bahamas Oil Refining Company International Limited (“BORCO”), is one of the largest marine crude oil and petroleum products storage facilities in the world, serving the international markets as a premier global logistics hub.

Our primary business objective is to provide stable and sustainable cash distributions to our LP Unitholders, while maintaining a relatively low investment risk profile. The key elements of our strategy are to: (i) maximize utilization of our assets at the lowest cost per unit; (ii) maintain stable long-term customer relationships; (iii) operate in a safe and environmentally responsible manner; (iv) optimize, expand and diversify our portfolio of energy assets; and (v) maintain a solid, conservative financial position and our investment-grade credit rating.

Recent Developments

In February 2012, we signed a definitive agreement with Chevron U.S.A. Inc. (“Chevron”) to acquire a marine terminal facility for liquid petroleum products in New York Harbor (the “Perth Amboy Facility”) for $260.0 million in cash. In anticipation of the acquisition, we paid a deposit of $14.0 million to Chevron in February 2012. The facility, which sits on approximately 250 acres on the Arthur Kill in Perth Amboy, New Jersey, has over 4 million barrels of tankage, four docks, and significant undeveloped land available for potential expansion. The Perth Amboy Facility has water, pipeline, rail, and truck access, and is located only six miles from our Linden, New Jersey complex. Chevron agreed to enter into multi-year storage, blending, and throughput commitments with us concurrent with the acquisition. The Perth Amboy Facility will provide a link between our inland pipelines and terminals and our BORCO facility in The Bahamas, improving service offerings for our customers and providing further support to our planned clean products tankage expansion at the BORCO facility. The operations of the Perth Amboy Facility will be reported in our Pipelines & Terminals segment following closing, which is expected to close late in the second quarter or early in the third quarter of 2012.

Additionally in February 2012, we issued 4,262,575 LP Units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Revolving Credit Agreement dated September 26, 2011 (the “Credit Facility”) with SunTrust Bank and have also funded a portion of the Perth Amboy Facility and certain other growth capital expenditures.

Results of Operations

Non-GAAP Financial Measures

Adjusted EBITDA is the primary measure used by our senior management, including our Chief Executive Officer, to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. Distributable cash flow is another measure used by our senior management to provide a clearer picture of Buckeye’s cash available for distribution to its unitholders. We define EBITDA, a measure not defined under generally accepted accounting principles (“GAAP”), as net income attributable to our unitholders before interest and debt expense, income taxes and depreciation and amortization. Adjusted EBITDA and distributable cash flow eliminate (i) non-cash expenses, including but not limited to, depreciation and amortization expense resulting from the significant capital investments we make in our businesses and from intangible assets recognized in business combinations; (ii) charges for obligations expected to be settled with the issuance of equity instruments; and (iii) items that are not indicative of our core operating performance results and business outlook.

We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA and distributable cash flow data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies.

The following table presents Adjusted EBITDA by segment and on a consolidated basis, distributable cash flow and a reconciliation of net income, which is the most comparable GAAP financial measure, to Adjusted EBITDA and distributable cash flow for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012			2011
Adjusted EBITDA:
Pipelines & Terminals	$	88,232		$	90,120
International Operations		31,666			25,507
Natural Gas Storage		(1,268	)		2,452
Energy Services		(6,172	)		2,759
Development & Logistics		2,529			1,401

Total Adjusted EBITDA	$	114,987		$	122,239


Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow:
Net income	$	53,467		$	67,813
Less: Net income attributable to noncontrolling interests		(1,508	)		(1,320	)

Net income attributable to Buckeye Partners, L.P.		51,959			66,493
Add: Interest and debt expense		28,810			28,497
Income tax expense (benefit)		337			(176	)
Depreciation and amortization		33,027			26,241
Non-cash deferred lease expense		975			1,030
Non-cash unit-based compensation expense		2,627			2,086
Less: Amortization of unfavorable storage contracts (1)		(2,748	)		(1,932	)

Adjusted EBITDA	$	114,987		$	122,239

Less: Interest and debt expense, excluding amortization of deferred financing costs and debt discounts		(27,917	)		(27,393	)
Income tax expense (benefit)		(337	)		176
Maintenance capital expenditures		(13,110	)		(7,473	)

Distributable cash flow	$	73,623		$	87,549

(1)	Represents amortization of negative fair values allocated to certain unfavorable storage contracts acquired in connection with the BORCO acquisition.

The following table presents product volumes transported and average daily throughput for the Pipelines & Terminals segment in barrels per day (“bpd”) and total volumes sold in gallons for the Energy Services segment for the periods indicated:


	Three Months Ended March 31,
	2012		2011
Pipelines & Terminals (average bpd in thousands):
Pipelines:
Gasoline		653.6		602.9
Jet fuel		332.5		326.5
Middle distillates (1)		339.1		351.1
Other products (2)		20.5		22.5

Total pipelines throughput		1,345.7		1,303.0

Terminals:
Products throughput (3)		852.3		535.5

Energy Services (in millions of gallons):
Sales volumes		344.8		381.5

(1)	Includes diesel fuel, heating oil and kerosene.

(2)	Includes liquefied petroleum gas (“LPG”).

(3)	Amounts for 2012 include throughput volumes at terminals acquired from BP Products North America Inc. and its affiliates and ExxonMobil Corporation on June 1, 2011 and July 19, 2011, respectively.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Consolidated

Adjusted EBITDA was $115.0 million for the three months ended March 31, 2012, which is a decrease of $7.2 million, or 5.9%, from $122.2 million for the corresponding period in 2011. The decrease in Adjusted EBITDA was primarily related to losses incurred in the Energy Services segment as a result of declining basis in the Midwest refined petroleum commodity markets that adversely affected the value of our inventory portfolio and a decrease in lease revenue in the Natural Gas Storage segment due to lower storage prices caused by compressed seasonal spreads, partially offset by an increase in earnings at BORCO due to a full quarter of operations as well as lower acquisition and integration costs in the International Operations segment.

Revenue was $1,259.4 million for the three months ended March 31, 2012, which is an increase of $6.9 million, or 0.6%, from $1,252.5 million for the corresponding period in 2011. The increase in revenue was primarily related to pipeline and terminal acquisitions in 2011 and revenue on legacy assets in the Pipelines & Terminals segment, partially offset by a net decrease in revenue in the Energy Services segment.

Operating income was $80.4 million for the three months ended March 31, 2012, which is a decrease of $12.2 million, or 13.1%, from $92.6 million for the corresponding period in 2011. The decrease in operating income was primarily related to a negative contribution associated with the operating activities in the Energy Services segment and an increase in depreciation and amortization due to a full quarter of operations for BORCO in the International Operations segment and the pipeline and terminal acquisitions in 2011 in the Pipelines & Terminals segment, partially offset by a positive contribution relating to the operating activities of the pipeline and terminal acquisitions in the Pipelines & Terminals segment.

Distributable cash flow was $73.6 million for the three months ended March 31, 2012, which is a decrease of $13.9 million, or 15.9%, from $87.5 million as compared to the corresponding period in 2011. The decrease in distributable cash flow was primarily related to a decrease of $7.2 million in Adjusted EBITDA as described above and a $5.6 million increase in maintenance capital expenditures relating to pipeline and tank integrity work performed in the Pipelines & Terminals and International Operations segments.

Adjusted EBITDA by Segment

Pipelines & Terminals. Adjusted EBITDA from the Pipelines & Terminals segment was $88.2 million for the three months ended March 31, 2012, which is a decrease of $1.9 million, or 2.1%, from $90.1 million for the corresponding period in 2011. The negative factors impacting Adjusted EBITDA were $12.4 million of operating expenses related to pipeline and terminal assets acquired during the second half of 2011, a $5.2 million decrease in revenue due to lower pipeline and terminalling volumes on assets existing prior to acquisitions in 2011 (which we refer to as our “legacy” assets), a $4.6 million increase in operating expenses, which included integrity program expenditures, payroll costs and environmental remediation expenses, $3.1 million in unfavorable settlement experience, a $2.9 million increase in acquisition and integration expenses, a $2.3 million increase in other costs and a $1.4 million decrease in earnings from equity investments primarily due to the sale of our interest in West Texas LPG Pipeline Limited Partnership in May 2011.

The positive factors impacting Adjusted EBITDA were $18.3 million in revenue related to pipeline and terminal acquisitions, $9.8 million due to higher pipeline tariff rates and terminalling contract rate escalations on our legacy assets and a $1.9 million increase in other revenue.

Overall pipeline and terminalling volumes increased by 3.3% and 59.2%, respectively, as a result of the pipeline and terminal acquisitions. Legacy pipeline volumes decreased by 4.0% primarily due to lower heating oil deliveries as a result of the unseasonably mild winter, as well as changes in supply patterns related to the recent refinery closures affecting the Pennsylvania market. Legacy terminalling volumes decreased by 5.6% primarily due to lower demand for gasoline and middle distillates caused by high commodity prices, a milder than normal winter and supply interruptions due to refinery closures and maintenance.

International Operations. Adjusted EBITDA from the International Operations segment was $31.7 million for the three months ended March 31, 2012, which is an increase of $6.2 million, or 24.1%, from $25.5 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily related to a $4.7 million net increase in storage fees, which includes a full quarter of operations for BORCO and a decrease in storage capacity leased due to maintenance activities, $1.7 million of noncontrolling interests income related to the remaining 20.0% in BORCO not acquired by us until February 16, 2011 and a $1.1 million decrease in acquisition and integration expenses, partially offset by a $0.9 million increase in operating expenses, which included increases in other taxes, insurance costs and lease expenses and a decrease in professional fees and a $0.4 million decrease in ancillary service revenue.

Natural Gas Storage. Adjusted EBITDA from the Natural Gas Storage segment was a loss of $1.3 million for the three months ended March 31, 2012, which is a decrease of $3.8 million, or 151.7%, from earnings of $2.5 million for the corresponding period in 2011. The decrease in Adjusted EBITDA was primarily the result of a $6.1 million decrease in lease revenue due to lower storage prices caused by compressed seasonal spreads, partially offset by a $2.3 million decrease in operating expenses, which primarily related to a decline in the number of well workovers performed during 2012 as compared to the 2011 period. Lease revenue is affected by the difference in natural gas commodity prices for the periods in which natural gas is injected and withdrawn from the storage facility (i.e., time spread).

Energy Services. Adjusted EBITDA from the Energy Services segment was a loss of $6.2 million for the three months ended March 31, 2012, which is a decrease of $9.0 million, or 323.7%, from earnings of $2.8 million for the corresponding period in 2011. During the period, market dynamics impacting the flow of product along the supply chain, such as warmer weather conditions and decreased consumer demand, created downward pressure on basis. As a result of declining basis in the Midwest refined petroleum commodity markets, the value of our inventory portfolio was adversely affected. The decrease in Adjusted EBITDA was primarily related to a $20.9 million net decrease in revenue, which included a $101.1 million decrease due to 9.6% of lower sales volumes and an $80.2 million increase as a result of approximately $0.23 per gallon increase in refined petroleum product sales price (average sales prices per gallon were $2.99 and $2.76 for the 2012 and 2011 periods, respectively).

This decrease in Adjusted EBITDA was partially offset by a $11.6 million net decrease in cost of product sales, which included a $100.5 million decrease due to 9.6% of lower volumes sold and an $88.9 million increase as a result of approximately $0.25 per gallon increase in refined petroleum product cost price (average cost prices per gallon were $2.99 and $2.74 for the 2012 and 2011 periods, respectively) and a $0.3 million decrease in operating expenses, which primarily related to payroll costs.

Development & Logistics. Adjusted EBITDA from the Development & Logistics segment was $2.5 million for the three months ended March 31, 2012, which is an increase of $1.1 million, or 80.5%, from $1.4 million for the corresponding period in 2011. The increase in Adjusted EBITDA was primarily due to a $1.4 million increase in project management revenue, $1.2 million in revenue related to the LPG storage caverns acquired in November 2011 and a $0.3 million increase in operating services contract revenue as a result of new contracts and higher fees, partially offset by a $1.2 million increase in operating expenses related to project management activities, a $0.3 million increase in operating expenses, which primarily related to payroll costs and $0.3 million in operating expenses of the LPG storage caverns.

Liquidity and Capital Resources

General

The following section describes our liquidity and capital requirements, including sources and uses of liquidity and capital resources. Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to partners. Our principal sources of liquidity are cash from operations, borrowings under our Credit Facility and proceeds from the issuance of our units. We will, from time to time, issue debt securities to permanently finance amounts borrowed under our Credit Facility. Buckeye Energy Services LLC (“BES”) funds its working capital needs principally from its operations and its portion of our Credit Facility. Our financial policy has been to fund maintenance capital expenditures with cash from operations. Expansion and cost reduction capital expenditures, along with acquisitions, have typically been funded from external sources including our Credit Facility as well as debt and equity offerings. Our goal has been to fund at least half of these expenditures with proceeds from equity offerings in order to maintain our investment-grade credit rating.

As a result of our financing activities in 2012 and in light of the fact that none of our long-term debt obligations mature prior to 2013, we believe that our borrowing capacity under our Credit Facility, ongoing cash flows from operations and proceeds from the registered direct offering in February 2012, will be sufficient to fund our operations for the remainder of 2012, including our expansion plans. We will continue to evaluate a variety of financing sources throughout 2012, including the debt and equity markets described above.

Current Liquidity

We had the following liquidity available to meet our working capital needs, capital expenditures, business acquisitions and distributions to partners as of the period indicated (in thousands):


	March 31, 2012
Cash and cash equivalents	$	15,059
Availability under our Credit Facility		135,674

Total available liquidity	$	150,733

At March 31, 2012, we had total fixed-rate and variable-rate debt obligations of $2,075.0 million and $331.4 million, respectively, with an aggregate fair value of $2,548.8 million. At March 31, 2012, we were in compliance with the covenants under our Credit Facility.

Capital Structuring Transactions

As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, we may explore additional sources of external liquidity, including public or private debt or equity issuances. Matters to be considered will include cash interest expense and maturity profile, all to be balanced with maintaining adequate liquidity. We have a universal shelf registration statement that does not place any dollar limits on the amount of debt and equity securities that we may issue thereunder and a traditional shelf registration statement on file with the SEC that currently has a $750.0 million limit on the amount of equity securities that we may issue thereunder. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions.

Equity

In February 2012, we issued 4,262,575 LP units to institutional investors in a registered direct offering for aggregate consideration of approximately $250.0 million at a price of $58.65 per LP Unit, before deducting placement agents’ fees and estimated offering expenses. We have used the majority of the net proceeds from this offering to reduce the indebtedness outstanding under our Credit Facility and have also funded a portion of the Perth Amboy Facility and certain other growth capital expenditures.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012			2011
Cash provided by (used in):
Operating activities	$	181,601		$	156,382
Investing activities		(87,996	)		(955,673	)
Financing activities		(91,532	)		852,095

Operating Activities

Net cash provided by operating activities was $181.6 million for the three months ended March 31, 2012, which is an increase of $25.2 million, from $156.4 million for the corresponding period in 2011. The increase in net cash provided by operating activities primarily related to lower margin deposits and vendor prepayments and a reduction in refined petroleum products inventory in the Energy Services segment, partially offset by an increase in cash paid for interest.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the cost of commodities, the effectiveness of our strategy, legal environmental and regulatory requirements and our ability to capture value associated with commodity price volatility.

Investing Activities

Net cash used in investing activities was $88.0 million for the three months ended March 31, 2012, which is a decrease of $867.7 million, from $955.7 million for the corresponding period in 2011. The decrease in net cash used in investing activities primarily related to $893.7 million of net cash consideration paid for the BORCO acquisition in 2011, partially offset by a $36.3 million increase in capital expenditures. See below for a discussion of capital spending.

Capital expenditures, excluding non-cash changes in accruals for capital expenditures, were as follows for the periods indicated (in thousands):


	Three Months Ended March 31,
	2012		2011
Maintenance capital expenditures	$	13,110	$	7,473
Expansion and cost reduction		61,203		30,560

Total capital expenditures	$	74,313	$	38,033

In the three months ended March 31, 2012, maintenance capital expenditures included terminal pump replacements and truck rack infrastructure upgrades, as well as pipeline and tank integrity work, and expansion and cost reduction projects included significant investments in storage tank expansion at BORCO, biodiesel and butane blending, rail off-loading facilities, and continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects. In the three months ended March 31, 2011, maintenance capital expenditures included pipeline and tank integrity work, and expansion and cost reduction projects included upgrades and expansions of the jetty structure at BORCO, terminal ethanol and butane blending, new pipeline connections, continued progress on a new pipeline and terminal billing system as well as various other operating infrastructure projects.

We estimated our capital expenditures as follows for the period indicated (in thousands):


	2012
	Low		High
Pipelines & Terminals:
Maintenance capital expenditures	$	40,000	$	50,000
Expansion and cost reduction		80,000		100,000

Total capital expenditures	$	120,000	$	150,000

International Operations:
Maintenance capital expenditures	$	10,000	$	20,000
Expansion and cost reduction		120,000		150,000

Total capital expenditures	$	130,000	$	170,000

Overall:
Maintenance capital expenditures	$	50,000	$	70,000
Expansion and cost reduction		200,000		250,000

Total capital expenditures	$	250,000	$	320,000

Estimated maintenance capital expenditures include renewals and replacement of pipeline sections, tank floors and tank roofs and upgrades to station and terminalling equipment, field instrumentation and cathodic protection systems. Estimated major expansion and cost reduction expenditures include storage tank expansion projects at the BORCO facility, completion of additional storage tanks and rail loading facilities in the Midwest, the refurbishment of storage tanks and facilities in the Northeast, continued installation of vapor recovery units throughout our system of terminals, additive system installation throughout our terminal infrastructure and various upgrades and expansions of our ethanol business. Cost reduction expenditures improve operational efficiencies or reduce costs.

Financing Activities

Net cash used in financing activities was $91.5 million for the three months ended March 31, 2012, which is an increase of $943.6 million, from $852.1 million in net cash provided by financing activities for the corresponding period in 2011. During 2012, we received $247.5 million in net proceeds from the issuance of 4.3 million LP Units to institutional investors in a registered direct offering and borrowed $111.0 million under our Credit Facility. During 2011, we received $647.5 million from the issuance of 4.875% Notes in an underwritten public offering and $420.4 million in net proceeds from the issuance of 5.8 million LP Units and 1.3 million Class B Units to institutional investors to fund a portion of the BORCO acquisition and borrowed $521.5 million under the revolving credit agreement dated November 13, 2006, partially offset by the repayment of $318.2 million of debt assumed in the BORCO acquisition.

Off-Balance Sheet Arrangements

There have been no material changes with regard to our off-balance sheet arrangements since those reported in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

See Note 1 in the Notes to Unaudited Condensed Consolidated Financial Statements for a description of certain new accounting pronouncements that will or may affect our consolidated financial statements.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Item 7A in our Annual Report on Form 10-K for the year ended December 31, 2011. There have been no material changes in that information other than as discussed below. Also see Note 7 to in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Market Risk – Non-Trading Instruments

The primary factors affecting our market risk and the fair value of our derivative portfolio at any point in time are the volume of open derivative positions, changing refined petroleum commodity prices, and prevailing interest rates for our interest rate swaps. Since prices for refined petroleum products and interest rates are volatile, there may be material changes in the fair value of our derivatives over time. Our net derivative liability has decreased to approximately $82.9 million at March 31, 2012, compared to $97.0 million at December 31, 2011.

The following is a summary of changes in fair value of our outstanding commodity and interest rate derivative instruments for the periods indicated (in thousands):


	Commodity Instruments			Interest Rate Swaps			Total
Fair value of contracts outstanding at January 1, 2012	$	4,897		$	(101,911	)	$	(97,014	)
Items recognized or settled during the period		26,880			—			26,880
Fair value attributable to new deals		2,493			—			2,493
Change in fair value attributable to price movements		(32,352	)		17,061			(15,291	)
Change in fair value attributable to non-performance risk		27			—			27

Fair value of contracts outstanding at March 31, 2012	$	1,945		$	(84,850	)	$	(82,905	)

Commodity Risk

Natural Gas Storage

The Natural Gas Storage segment enters into interruptible natural gas storage hub service agreements in order to manage the operational integrity of the natural gas storage facility, while also attempting to capture value from seasonal price differences in the natural gas markets. Although the Natural Gas Storage segment does not purchase or sell natural gas, the Natural Gas Storage segment is subject to commodity risk because the value of natural gas storage hub services generally fluctuates based on changes in the relative market prices of natural gas over different delivery periods. The hub service agreements do not qualify as derivatives and therefore are not accounted for at fair value. The fee to be received or paid is based on the time spread at the time of execution. The hub service agreements are accrued as fees are paid or received and recognized ratably in earnings over the entire term of the transactions.

The following is a summary of changes in the net balance sheet of our outstanding hub service agreements (in thousands):


	Hub Service Agreements
Net asset at January 1, 2012	$	11,390
Net expenses recognized (1)		(577	)
Net unearned revenue (2)		(6,549	)

Net asset at March 31, 2012	$	4,264

(1)	Expenses were amortized into earnings based on the net fee paid over the injection and withdrawal period.

(2)	Fees were collected and a net liability was recorded for injection and withdrawal services to be rendered in future periods.

Energy Services

Based on a hypothetical 10% movement in the underlying quoted market prices of the futures contracts, physical fixed price and index derivative contracts, and designated hedged refined petroleum products inventories outstanding at March 31, 2012, the estimated fair value of the portfolio of commodity financial instruments would be as follows (in thousands):


Scenario	Resulting Classification	Commodity Financial Instrument Portfolio Fair Value
Fair value assuming no change in underlying commodity prices (as is)	Asset	$	157,420
Fair value assuming 10% increase in underlying commodity prices	Asset	$	157,234
Fair value assuming 10% decrease in underlying commodity prices	Asset	$	157,606

Interest Rate Risk

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 impact 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.

The following table presents the effect of hypothetical price movements on the estimated fair value of our interest rate swap portfolio and the related change in fair value of the underlying debt at March 31, 2012 (in thousands):


Scenario	Resulting Classification	Financial Instrument Portfolio Fair Value
Fair value assuming no change in underlying interest rates (as is)	Liability	$	(84,850	)
Fair value assuming 10% increase in underlying interest rates	Liability	$	(68,784	)
Fair value assuming 10% decrease in underlying interest rates	Liability	$	(100,565	)

See Note 7 in the Notes to Unaudited Condensed Consolidated Financial Statements for additional discussion related to derivative instruments and hedging activities.

Item 4.

Controls and Procedures

(a)

Evaluation of Disclosure Controls and Procedures.

Our management, with the participation of our Chief Executive Officer (the “CEO”) and Chief Financial Officer (the “CFO”), evaluated the design and effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the CEO and CFO concluded that our disclosure controls and procedures as of the end of the period covered by this report are designed and operating effectively to provide reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to management, including the CEO and CFO, as appropriate to allow timely decisions regarding disclosure. A controls system cannot provide absolute assurance, however, that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

(b)

Change in Internal Control Over Financial Reporting.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the first quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

For information on legal proceedings, see Part I, Item 1, Financial Statements, Note 3, “Commitments and Contingencies” in the Notes to Unaudited Condensed Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item 1A.

Risk Factors

We are updating the following risk factor set forth in Part I, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011:

Our rate structures are subject to regulation and change by the Federal Energy Regulatory Commission (“FERC”); required changes could be adverse.

Buckeye Pipe Line Company, L.P. (“Buckeye Pipe Line”), Wood River Pipe Lines LLC (“Wood River”), Buckeye Pipe Line Transportation LLC (“BPL Transportation”) and NORCO Pipe Line Company, LLC (“NORCO”) are interstate common carriers regulated by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and the Department of Energy Organization Act. The FERC’s primary ratemaking methodology is indexing rates for inflation. In the alternative, a pipeline is allowed to charge market-based rates if the pipeline establishes that it does not possess significant market power in a particular market. A pipeline may also charge rates based on the agreement of all shippers receiving a service, which are referred to as settlement-based rates.

The indexing methodology is used to establish rates on the pipelines owned by Wood River, BPL Transportation and NORCO. In December 2010, FERC amended its regulations to change the index to the Producer Price Index (“PPI”) – finished goods plus 2.65% effective July 1, 2011. If the index were to be negative, we would be required to reduce the rates charged by Wood River, BPL Transportation and NORCO if they exceed the new maximum allowable rate. In addition, changes in the PPI might not fully reflect actual increases in the costs associated with these pipelines, thus potentially hampering our ability to recover our costs relying on the index. Where circumstances justify it, FERC permits pipelines to use one of three alternatives to indexing—pipelines may seek to use market-based, cost-based, or settlement-based rates.

Buckeye Pipe Line presently is authorized to charge rates set by market forces, subject to limitations, rather than by reference to costs historically incurred by the pipeline, in 15 regions and metropolitan areas. In 1991, Buckeye Pipe Line sought and received FERC permission to determine rate changes on Buckeye Pipe Line’s pipeline system (the “Buckeye System”) using a unique

methodology that constrains rates based on competitive pressures in markets that FERC found to be competitive, as well as certain other limits on rate increases in other markets on the Buckeye System (the “Buckeye Methodology”). FERC permitted the continuation of the Buckeye Methodology for the Buckeye System in 1994, subject to FERC’s authority to cause Buckeye Pipe Line to terminate the Buckeye Methodology in the future. The Buckeye Methodology is an exception to the generic oil pipeline regulations the FERC issued under the Energy Policy Act of 1992 (the “FERC Rules”), which rely primarily on the indexing methodology described above.

On March 1, 2012, Buckeye Pipe Line filed to increase its rates under the Buckeye Methodology. On March 30, 2012, in response to a shipper protest, FERC issued an order (the “Order”) rejecting the rate increase and stating that FERC will review the continued efficacy of the Buckeye Methodology. The Order directs Buckeye Pipe Line to show cause why it should not be required to discontinue the Buckeye Methodology and avail itself of the generic ratemaking methodologies used by other oil pipeline companies. Buckeye Pipe Line is preparing its response to FERC, which is due on May 15, 2012. It is possible that, as a result of FERC’s review of the Buckeye Methodology, FERC would require us to discontinue the Buckeye Methodology and employ one of the ratemaking methodologies authorized by the FERC Rules, including indexing or one of the alternatives (market-based, cost-based, or settlement-based rates).

In addition to the risks described above, at any time shippers on any of our FERC-regulated pipelines have the right to challenge the application of the index to a pipeline’s rates or the underlying rates themselves as being unjust and unreasonable, subject to the FERC’s cost-of-service standards. Such shipper challenges may seek adjustments to our rates prospectively and, subject to limitations, for certain past periods.

Although it is too early to predict the outcome of the FERC’s review of the Buckeye Methodology, a FERC order requiring Buckeye Pipe Line to transition to any ratemaking methodology that is less favorable than the Buckeye Methodology on a significant portion of the Buckeye System could have a material adverse effect on our business, financial condition, results of operations and/or cash flows. Similarly, if a significant shipper challenge were to result in an outcome that is unfavorable to us, our business, financial condition, results of operations and/or cash flows could be adversely impacted.

Security holders and potential investors in our securities should also carefully consider the other risk factors set forth in Part 1, “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 and the other information in such report and in this quarterly report. We have identified these risk factors as important factors that could cause our actual results to differ materially from those contained in any written or oral forward-looking statements made by us or on our behalf.

Item 6.

Exhibits

(a) Exhibits


2.1†		Purchase and Sale Agreement by and between Buckeye Tank Terminals LLC and Chevron U.S.A., Inc., dated as of February 9, 2012 (Incorporated by reference to Exhibit 2.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on February 10, 2012).

3.1		Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of February 4, 1998 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 1997).

3.2		Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of April 26, 2002 (Incorporated by reference to Exhibit 3.2 of Buckeye Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2002).

3.3		Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of June 1, 2004, effective as of June 3, 2004 (Incorporated by reference to Exhibit 3.3 of the Buckeye Partners, L.P.’s Registration Statement on Form S-3 filed June 16, 2004).


3.4		Certificate of Amendment to Amended and Restated Certificate of Limited Partnership of Buckeye Partners, L.P., dated as of December 15, 2004 (Incorporated by reference to Exhibit 3.5 of Buckeye Partners, L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004).

3.5		Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of November 19, 2010 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed November 22, 2010).

3.6		Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Buckeye Partners, L.P., dated as of January 18, 2011 (Incorporated by reference to Exhibit 3.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2011).

10.1		Buckeye Partners, L.P. 2009 Long-Term Incentive Plan, as amended and restated effective August 3, 2011 (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on August 9, 2011).

10.2		Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective August 4, 2011 (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on May 4, 2012).

10.3		Buckeye Partners, L.P. Annual Incentive Compensation Plan (as amended and restated effective January 1, 2012) (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on April 3, 2012).

10.4		Form of Severance Agreement (Incorporated by reference to Exhibit 10.1 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2012).

10.5		Form of Phantom Unit Grant Agreement (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on January 20, 2012).

10.6		Non-Executive Chairman Agreement between Forrest E. Wylie and Buckeye GP LLC, dated as of February 8, 2012 (Incorporated by reference to Exhibit 10.2 of Buckeye Partners, L.P.’s Current Report on Form 8-K filed on February 20, 2012).

*31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14 (a) under the Securities Exchange Act of 1934.

*31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

*32.1		Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

*32.2		Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350.


*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema Document.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

*101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

*	Filed herewith.

†	Schedules and similar attachments have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Buckeye agrees to furnish supplementally a copy of the omitted schedules and similar attachments to the SEC upon request.

SIGNATURES

Pursuant to the requirements of Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		By:	BUCKEYE PARTNERS, L.P. (Registrant)

		By:	Buckeye GP LLC, as General Partner

Date: May 8, 2012	By:	/s/ Keith E. St.Clair
		Keith E. St.Clair
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company