Derivative And Financial Instruments

9 Months Ended

Sep. 30, 2016

Derivative And Financial Instruments

Derivative And Financial Instruments

5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized.  These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations.  It is never our intention to enter into derivative contracts for speculative trading purposes. Historically, the Partnership has not paid or received premiums for put options. In September 2016, we restructured a portion of our commodity derivative portfolio by effectively liquidating certain “in-the-money” crude oil and natural gas derivative positions scheduled to settle in the fourth quarter of 2016 and using the proceeds from said liquidations, which totaled $3.2 million, to enhance the price on certain natural gas derivatives scheduled to settle in 2017.

Under ASC Topic 815, Derivatives and Hedging, all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We will net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil and liquids sales in the condensed consolidated statements of operations.

As of September 30, 2016, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

Fixed Price Basis Swaps–West Texas Intermediate (WTI)

	For the Quarter Ended September 30, 2016 (volume in Bbls)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2016							—		—	49,802	$	48.25	49,802	$	48.25
2017	57,953	$	68.06	54,554	$	68.06	51,570	$	68.06	48,926	$	68.06	213,003	$	68.06
2018	56,798	$	65.40	54,197	$	65.40	51,851	$	65.40	49,709	$	65.40	212,555	$	65.40
2019	52,760	$	65.65	50,784	$	65.65	48,960	$	65.65	47,264	$	65.65	199,768	$	65.65
													675,128

Fixed Price Swaps—NYMEX (Henry Hub)

	For the Quarter Ended September 30, 2016 (volume in Mcfs)
	March 31,			June 30,			September 30,			December 31,			Total
		Average			Average			Average			Average			Average
	Volume	Price		Volume	Price		Volume	Price		Volume	Price		Volume	Price
2016							—			505,199	$	3.77	505,199	$	3.77
2017	271,507	$	5.72	255,669	$	5.72	241,748	$	5.72	229,122	$	5.72	998,046	$	5.72
2018	79,042	$	3.58	75,404	$	3.58	72,115	$	3.58	69,122	$	3.58	295,683	$	3.58
2019	73,432	$	3.62	70,648	$	3.62	68,088	$	3.62	65,720	$	3.62	277,888	$	3.62
													2,076,816

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the nine months ended September 30, 2016 and the year ended December 31, 2015 (in thousands):

	September 30,		December 31,
	2016		2015
Beginning fair value of commodity derivatives	$	31,018	$	22,829
Net gains (losses) on crude oil derivatives		(4,601)		22,410
Net gains on natural gas derivatives		1,937		6,148
Net settlements on derivative contracts:
Crude oil		(13,673)		(13,191)
Natural gas		(6,514)		(7,178)
Net premiums on derivative contracts		3,197		—
Ending fair value of commodity derivatives	$	11,364	$	31,018

The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):

		Amount of Gain (Loss) in Income
	Location of Gain	Three Months Ended  September 30,				Nine Months Ended  September 30,
Derivative Type	in Income	2016		2015		2016		2015
Commodity – Mark-to-Market	Oil sales	$	(1,033)	$	14,970	$	(4,600)	$	12,058
Commodity – Mark-to-Market	Natural gas sales		2,104		2,352		1,936		4,200
		$	1,071	$	17,322	$	(2,664)	$	16,258

Derivative instruments expose us to counterparty credit risk.  Our commodity derivative instruments are currently contracted with three counterparties.  We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty.  If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of September 30, 2016 and December 31, 2015, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Hedges Novated in the Eagle Ford Acquisition

As a part of the Eagle Ford  Acquisition, we received by novation from the seller certain hedges covering approximately 90%,  85%,  85% and 80% of estimated 2016, 2017, 2018 and 2019 oil and natural gas production from the acquired assets, respectively.  The counterparty for the hedges is a lender in the Partnership’s Credit Agreement. The Partnership is responsible for all future periodic settlements of these transactions.  As of September 30, 2016, the fair value of the hedges assumed resulted in an $8.5million asset in our condensed consolidated balance sheet. 

Embedded Derivative

The Partnership consummated a contract for the sale of preferred units in October 2015 which contained provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivative is valued through the use of a Monte Carlo model which utilizes observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. The Partnership has marked this derivative to market as of September 30, 2016, and incurred an approximate $43.2 million gain as a result.

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the quarters ended September 30, 2016 and the year ended December 31, 2015 (in thousands):

	September 30,		December 31,
	2016		2015
Beginning fair value of embedded derivative	$	(193,077)	$	—
Initial fair value of embedded derivative - bifurcated from mezzanine equity		—		(183,095)
Gain (loss) on embedded derivative		43,204		(9,982)
Ending fair value of embedded derivative	$	(149,873)	$	(193,077)