6. Derivative Financial Instruments

Commodity Derivatives

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital expenditures, the Partnership executes a strategy governed by the risk management policy approved by the General Partner’s board of directors. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership manages a portion of its NGL price risk using crude oil contracts, referred to as “proxy contracts,” as the NGL financial markets are not as liquid and historically there has been a strong relationship between changes in NGL and crude oil prices. During 2012 and continuing into 2013, the price of NGLs as compared to crude oil weakened significantly and as a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership may settle its derivative positions prior to the contractual settlement date in order to take advantage of favorable terms at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. Currently, approximately 73% of our derivative positions used to manage our future commodity price exposure are direct product positions.

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2014. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the Credit Facility (“participating bank group members”). Currently, all of the Partnership’s financial derivative positions are with participating bank group members. Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain bank group members allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (master netting arrangements) in the event of default or other terminating events, including bankruptcy.

The Partnership records derivative contracts at fair value in the Condensed Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation. The Partnership’s accounting may cause volatility in the Condensed Consolidated Statements of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value of derivatives.

As of June 30, 2013, the Partnership had the following outstanding commodity contracts that were entered into to manage cash flow risk associated with future sales of NGLs or future purchases of natural gas:

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	1,885,366
Natural Gas (MMBtu)	Long	5,173,965
NGLs (gal)	Short	133,196,994

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (loss) gain related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022 with the producer’s option to extend the agreement for successive five year terms through December 31, 2032. As of June 30, 2013, the estimated fair value of this contract was a liability of $61.6 million and the recorded value was a liability of $8.1 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2013 (in thousands):

Fair value of commodity contract	$	61,587
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2013	$	8,080

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Southwest segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recorded in Derivative gain related to facility expenses. As of June 30, 2013, the estimated fair value of this contract was an asset of $5.7 million.

Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
Commodity contracts(1)
Fair value of derivative instruments — current	$	24,746	$	19,504	$	(17,871	)	$	(27,229	)
Fair value of derivative instruments - long-term	12,418		10,878		(2,010		)	(32,190		)
Total	$	37,164	$	30,382	$	(19,881	)	$	(59,419	)

(1) Includes Embedded Derivatives in Commodity Contracts as discussed above.

Although certain derivative positions are subject to master netting agreements, the Partnership has elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Condensed Consolidated Balance Sheets. The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands):

	Assets							Liabilities
As of June 30, 2013	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	21,546	$	(8,219	)	$	13,327	$	(9,791	)	$	8,219	$	(1,572	)
Embedded derivatives in commodity contracts	3,200		—			3,200		(8,080		)	—		(8,080		)
Total current derivative instruments	24,746		(8,219		)	16,527		(17,871		)	8,219		(9,652		)

Non-current

Commodity contracts	9,941		(1,875		)	8,066		(2,010		)	1,875		(135		)
Embedded derivatives in commodity contracts	2,477		—			2,477		—			—		—
Total non-current derivative instruments	12,418		(1,875		)	10,543		(2,010		)	1,875		(135		)

Total derivative instruments	$	37,164	$	(10,094	)	$	27,070	$	(19,881	)	$	10,094	$	(9,787	)

	Assets							Liabilities
As of December 31, 2012	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	16,438	$	(9,541	)	$	6,897	$	(16,679	)	$	9,541	$	(7,138	)
Embedded derivatives in commodity contracts	3,066		—			3,066		(10,550		)	—		(10,550		)
Total current derivative instruments	19,504		(9,541		)	9,963		(27,229		)	9,541		(17,688		)

Non-current

Commodity contracts	7,798		(2,637		)	5,161		(2,637		)	2,637		—
Embedded derivatives in commodity contracts	3,080		—			3,080		(29,553		)	—		(29,553		)
Total non-current derivative instruments	10,878		(2,637		)	8,241		(32,190		)	2,637		(29,553		)

Total derivative instruments	$	30,382	$	(12,178	)	$	18,204	$	(59,419	)	$	12,178	$	(47,241	)

In the tables above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented above.

The impact of the Partnership’s derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):

Derivative contracts not designated as hedging instruments and the location of	Three months ended June 30,						Six months ended June 30,
gain or (loss) recognized in income	2013			2012			2013			2012
Revenue: Derivative gain (loss)
Realized gain (loss)	$	3,089		$	2,841		$	6,987		$	(7,637	)
Unrealized gain	16,610			133,226			12,527			94,989
Total revenue: derivative gain	19,699			136,067			19,514			87,352

Derivative gain (loss) related to purchased product costs
Realized loss	(1,045		)	(7,793		)	(3,125		)	(14,867		)
Unrealized gain	21,477			59,372			34,261			47,646
Total derivative gain related to purchase product costs	20,432			51,579			31,136			32,779

Derivative (loss) gain related to facility expenses
Unrealized (loss) gain	(800		)	1,146			(468		)	2,892
Total gain	$	39,331		$	188,792		$	50,182		$	123,023