15. 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.

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 market. 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 instruments 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 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 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 January 2009, Buckeye GP’s Board of Directors adopted an interest rate hedging policy which permits us to enter into certain short-term interest rate swap agreements to manage our interest rate and cash flow risks associated with the Credit Facility. In addition, in July 2009 and May 2010, Buckeye GP’s Board of Directors authorized us to enter into certain transactions, such as forward-starting interest rate swaps, to manage our interest rate and cash flow risks related to certain expected debt issuances associated with the maturity of existing debt obligations.

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. During 2009, we entered into four forward-starting interest rate swaps with a total aggregate notional amount of $200.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $150.0 million related to the anticipated issuance of debt on or before October 15, 2014. During 2010, we entered into two forward-starting interest rate swaps with a total aggregate notional amount of $100.0 million related to the anticipated issuance of debt on or before July 15, 2013 and three forward-starting interest rate swaps with a total aggregate notional amount of $125.0 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 years ended December 31, 2011 and 2010, unrealized losses of $104.8 million and $13.9 million, respectively, were recorded in AOCI 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 values to be highly correlated with the changes in value of the underlying borrowings.

On January 13, 2011, we issued the 4.875% Notes in an underwritten public offering. See Note 12 for further discussion. In December 2010, in connection with the proposed offering, we entered into a treasury lock agreement to fix the ten-year treasury rate at 3.3375% per annum on a notional amount of $650.0 million. In January 2011, we subsequently cash-settled the treasury lock agreement upon the issuance of the 4.875% Notes and received approximately $0.5 million, which will be recognized as a reduction to interest expense over the ten-year term of the 4.875% Notes.

Over the next twelve months, we expect to reclassify $0.9 million of net losses, consisting of loss attributable to forward-starting interest rate swaps terminated in 2008 associated with our 6.050% Notes, partially offset by a gain attributable to the settlement of the treasury lock agreement associated with the 4.875% Notes issued 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 fixed-price purchase and sales contracts. The derivative contracts used to hedge refined petroleum product inventories are primarily designated as fair value hedges. Accordingly, our method of measuring ineffectiveness compares the change in the fair value of New York Mercantile Exchange (“NYMEX”) futures contracts to the change in fair value of our hedged fuel inventory. Hedge accounting is discontinued when the hedged fuel inventory is sold or when the related derivative contracts expire. In addition, we periodically enter into offsetting exchange-traded futures contracts to economically close-out an existing futures contract based on a near-term expectation to sell a portion of our fuel inventory. These offsetting derivative contracts are not designated as hedging instruments and any resulting gains or losses are recognized in earnings during the period. The fair values of futures contracts for inventory designated as hedging instruments in the following tables have been presented net of these offsetting futures contracts.

Our Energy Services segment has not used hedge accounting with respect to its fixed-price contracts. Therefore, our fixed-price contracts and the related futures contracts used to offset the changes in fair value of the fixed-price contracts are all marked-to-market on the 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 consolidated balance sheet with gains and losses being recognized in earnings during the period.

In order to hedge the cost of natural gas used to operate our turbine engines at our Linden, New Jersey location, our Pipelines & Terminals segment bought natural gas futures contracts in March 2009 with terms that coincide with the remaining term of an ongoing natural gas supply contract that expired August 2011. The natural gas futures contracts were designated as cash flow hedges at inception and the change in fair value was recorded in OCI. As the forecasted event occurred and was recognized in earnings, the change in fair value was reclassed from AOCI to earnings. As of December 31, 2011, there were no designated cash flow hedges of our natural gas supply contracts and the amount that had been recorded in AOCI was reclassed to earnings.

The following table summarizes our commodity derivative instruments outstanding at December 31, 2011 (amounts in thousands of gallons, except as noted):

Volume (1)

Derivative Purpose

Current

Long-Term (2)

Accounting
Treatment

Derivatives Not designated as hedging instruments:

Physical fixed price derivative contracts for refined products

27,744

—

Mark-to-market

Physical index derivative contracts

155,054

—

Mark-to-market

Futures contracts for refined products

30,324

—

Mark-to-market

Derivatives designated as hedging instruments:

Futures contracts for refined products

95,277

—

Fair Value Hedge

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

(2)	At December 31, 2011, we did not have any derivatives with a contract month exceeding December 31, 2012.

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


	December 31, 2011
	Derivatives Not Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Net Carrying Value			Netting Balance Sheet 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 contracts 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	)


	December 31, 2010
	Derivatives Not Designated as Hedging Instruments			Derivatives Designated as Hedging Instruments			Derivative Net Carrying Value			Netting Balance Sheet Adjustment			Total
Physical derivative contracts	$	1,552		$	—		$	1,552		$	(30	)	$	1,522
Futures contracts for refined products		36,916			—			36,916			(36,804	)		112

Total current derivative assets		38,468			—			38,468			(36,834	)		1,634

Interest rate contracts		—			5,351			5,351			(1,459	)		3,892

Total long-term derivative assets		—			5,351			5,351			(1,459	)		3,892


Physical derivative contracts		(3,930	)		—			(3,930	)		30			(3,900	)
Futures contracts for refined products		(21,368	)		(28,071	)		(49,439	)		36,804			(12,635	)
Futures contract for natural gas		—			(206	)		(206	)		—			(206	)
Interest rate contracts		—			(2,003	)		(2,003	)		1,459			(544	)

Total current derivative liabilities		(25,298	)		(30,280	)		(55,578	)		38,293			(17,285	)

Net assets/(liabilities)	$	13,170		$	(24,929	)	$	(11,759	)	$	—		$	(11,759	)

Our hedged inventory portfolio extends to the second quarter of 2012. The majority of the unrealized gain of $0.2 million at December 31, 2011 for inventory hedges represented by futures contracts will be realized by the second quarter of 2012 as the related inventory is sold. At December 31, 2011, open refined petroleum product derivative contracts (represented by the fixed-price sales contracts and futures contracts for fixed-price sales contracts noted above) varied in duration in the overall portfolio, but did not extend beyond December 2012. In addition, at December 31, 2011, 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 consolidated balance sheets at the dates indicated (in thousands):


	December 31,
	2011			2010
Derivative assets	$	6,756		$	1,634
Other non-current assets		—			3,892
Derivative liabilities		(1,859	)		(17,285	)
Other non-current liabilities		(101,911	)		—

Total	$	(97,014	)	$	(11,759	)

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 for the Year Ended December 31,
	Location	2011			2010
Derivatives Not designated as hedging instruments:

Physical fixed price derivative contracts	Product sales	$	5,141		$	3,032
Physical index derivative contracts	Product sales		123			—
Physical fixed price derivative contracts	Cost of product sales and natural gas storage services		5,968			—
Physical index derivative contracts	Cost of product sales and natural gas storage services		98			—
Futures contracts for refined products	Cost of product sales and natural gas storage services		7,103			22,073

Derivatives designated as fair value hedging instruments:

Futures contracts for refined products	Cost of product sales and natural gas storage services	$	(47,681	)	$	(61,235	)
Physical Inventory—hedged items	Cost of product sales and natural gas storage services		37,986			55,405

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	$	(500	)	$	9,746
Time value excluded from hedge assessment	Cost of product sales and natural gas storage services		(9,195	)		(15,576	)

Net loss in income		$	(9,695	)	$	(5,830	)

The gains and losses reclassified from AOCI to income and the change in value recognized in other comprehensive income (“OCI”) on our derivatives were as follows for the periods indicated (in thousands):


		Gain (Loss) Reclassified From AOCI to Income for the Year Ended December 31,
	Location	2011			2010
Derivatives designated as cash flow hedging instruments:

Futures contracts for natural gas	Cost of product sales and natural gas storage services	$	(250	)	$	(428	)
Interest rate derivatives	Interest and debt expense		(920	)		(964	)

		Change in Value Recognized in OCI on Derivatives for the Year Ended December 31,
		2011			2010
Derivatives designated as cash flow hedging instruments:

Futures contracts for natural gas		$	(46	)	$	(929	)
Interest rate derivatives			(104,763	)		(13,856	)