Derivatives (Linn Energy, LLC [Member])

3 Months Ended

12 Months Ended

Mar. 31, 2013

Dec. 31, 2012

Linn Energy, LLC [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Derivatives

Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of March 31, 2013:

	April 1 - December 31, 2013			2014			2015			2016			2017		2018
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)	65,766			97,401			118,041			121,841			120,122		36,500
Average price ($/MMBtu)	$	5.22		$	5.25		$	5.19		$	4.20		$	4.26	$	5.00
Puts: (1)
Hedged volume (MMMBtu)	64,944			79,628			71,854			76,269			66,886		—
Average price ($/MMBtu)	$	5.37		$	5.00		$	5.00		$	5.00		$	4.88	$	—
Total:
Hedged volume (MMMBtu)	130,710			177,029			189,895			198,110			187,008		36,500
Average price ($/MMBtu)	$	5.29		$	5.14		$	5.12		$	4.51		$	4.48	$	5.00
Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)	8,944			11,903			11,599			11,464			4,755		—
Average price ($/Bbl)	$	94.97		$	92.92		$	96.23		$	90.56		$	89.02	$	—
Puts:
Hedged volume (MBbls)	2,339			3,960			3,426			3,271			384		—
Average price ($/Bbl)	$	97.86		$	91.30		$	90.00		$	90.00		$	90.00	$	—
Total:
Hedged volume (MBbls)	11,283			15,863			15,025			14,735			5,139		—
Average price ($/Bbl)	$	95.57		$	92.52		$	94.81		$	90.44		$	89.10	$	—
Natural gas basis differential positions: (3)
Panhandle basis swaps:
Hedged volume (MMMBtu)	58,508			79,388			87,162			19,764			—		—
Hedged differential ($/MMBtu)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.31	)	$	—	$	—
NWPL Rockies basis swaps:
Hedged volume (MMMBtu)	26,208			36,026			38,362			39,199			—		—
Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	—	$	—
MichCon basis swaps:
Hedged volume (MMMBtu)	7,233			9,490			9,344			—			—		—
Hedged differential ($/MMBtu)	$	0.10		$	0.08		$	0.06		$	—		$	—	$	—
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)	4,318			5,256			4,891			4,575			—		—
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	—	$	—
Permian basis swaps:
Hedged volume (MMMBtu)	3,493			4,891			5,074			—			—		—
Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	—		$	—	$	—
Oil basis differential positions: (3)
Midland - Cushing basis swaps:
Hedged volume (MBbls)	1,513			—			—			—			—		—
Hedged differential ($/Bbl)	$	(0.95	)	$	—		$	—		$	—		$	—	$	—
Oil timing differential positions:
Trade month roll swaps: (4)
Hedged volume (MBbls)	5,232			7,254			7,251			7,446			6,486		—
Hedged differential ($/Bbl)	$	0.22		$	0.22		$	0.24		$	0.25		$	0.25	$	—

(1) Includes certain outstanding natural gas puts of approximately 7,964 MMMBtu for the period April 1, 2013, through December 31, 2013, 10,570 MMMBtu for each of the years ending December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

(2) Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

(3) Settle on the respective pricing index to hedge basis differential associated with natural gas and oil production.

(4) The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the three months ended March 31, 2013, the Company entered into commodity derivative contracts consisting of oil basis swaps for April 2013 through December 2013.

Settled derivatives on natural gas production for the three months ended March 31, 2013, included volumes of 42,778 MMMBtu at an average contract price of $5.29 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2013, included volumes of 3,693 MBbls at an average contract price of $95.57 per Bbl. Settled derivatives on natural gas production for the three months ended March 31, 2012, included volumes of 23,642 MMMBtu at an average contract price of $5.84 per MMBtu. Settled derivatives on oil production for the three months ended March 31, 2012, included volumes of 2,578 MBbls at an average contract price of $97.93 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.

Balance Sheet Presentation

The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

	March 31, 2013		December 31, 2012
	(in thousands)
Assets:
Commodity derivatives	$	1,034,866	$	1,282,390
Liabilities:
Commodity derivatives	$	352,259	$	405,619

By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.0 billion at March 31, 2013. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Total gains and losses on derivatives, including realized and unrealized gains and losses, were a net loss of approximately $108 million and a net gain of approximately $2 million for the three months ended March 31, 2013, and March 31, 2012, respectively, and are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”

Derivatives

Commodity Derivatives

The Company utilizes derivative instruments to minimize the variability in cash flow due to commodity price movements. The Company has historically entered into derivative instruments such as swap contracts, put options and collars to economically hedge its forecasted oil, natural gas and NGL sales. The Company did not designate any of these contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.

The following table summarizes derivative positions for the periods indicated as of December 31, 2012:

	2013			2014			2015			2016			2017		2018
Natural gas positions:
Fixed price swaps:
Hedged volume (MMMBtu)	87,290			97,401			118,041			121,841			120,122		36,500
Average price ($/MMBtu)	$	5.22		$	5.25		$	5.19		$	4.20		$	4.26	$	5.00
Puts: (1)
Hedged volume (MMMBtu)	86,198			79,628			71,854			76,269			66,886		—
Average price ($/MMBtu)	$	5.37		$	5.00		$	5.00		$	5.00		$	4.88	$	—
Total:
Hedged volume (MMMBtu)	173,488			177,029			189,895			198,110			187,008		36,500
Average price ($/MMBtu)	$	5.29		$	5.14		$	5.12		$	4.51		$	4.48	$	5.00
Oil positions:
Fixed price swaps: (2)
Hedged volume (MBbls)	11,871			11,903			11,599			11,464			4,755		—
Average price ($/Bbl)	$	94.97		$	92.92		$	96.23		$	90.56		$	89.02	$	—
Puts:
Hedged volume (MBbls)	3,105			3,960			3,426			3,271			384		—
Average price ($/Bbl)	$	97.86		$	91.30		$	90.00		$	90.00		$	90.00	$	—
Total:
Hedged volume (MBbls)	14,976			15,863			15,025			14,735			5,139		—
Average price ($/Bbl)	$	95.57		$	92.52		$	94.81		$	90.44		$	89.10	$	—
Natural gas basis differential positions:(3)
Panhandle basis swaps:
Hedged volume (MMMBtu)	77,800			79,388			87,162			19,764			—		—
Hedged differential ($/MMBtu)	$	(0.56	)	$	(0.33	)	$	(0.33	)	$	(0.31	)	$	—	$	—
NWPL - Rockies basis swaps:
Hedged volume (MMMBtu)	34,785			36,026			38,362			39,199			—		—
Hedge differential ($/MMBtu)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	(0.20	)	$	—	$	—
MichCon basis swaps:
Hedged volume (MMMBtu)	9,600			9,490			9,344			—			—		—
Hedged differential ($/MMBtu)	$	0.10		$	0.08		$	0.06		$	—		$	—	$	—
Houston Ship Channel basis swaps:
Hedged volume (MMMBtu)	5,731			5,256			4,891			4,575			—		—
Hedged differential ($/MMBtu)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	(0.10	)	$	—	$	—
Permian basis swaps:
Hedged volume (MMMBtu)	4,636			4,891			5,074			—			—		—
Hedged differential ($/MMBtu)	$	(0.20	)	$	(0.21	)	$	(0.21	)	$	—		$	—	$	—
Oil timing differential positions:
Trade month roll swaps: (4)
Hedged volume (MBbls)	6,944			7,254			7,251			7,446			6,486		—
Hedged differential ($/Bbl)	$	0.22		$	0.22		$	0.24		$	0.25		$	0.25	$	—

⁽¹⁾  Includes certain outstanding natural gas puts of approximately 10,570 MMMBtu for each of the years ending December 31, 2013, December 31, 2014, and December 31, 2015, and 10,599 MMMBtu for the year ending December 31, 2016, used to hedge revenues associated with NGL production.

⁽²⁾  Includes certain outstanding fixed price oil swaps of approximately 5,384 MBbls which may be extended annually at a price of $100.00 per Bbl for each of the years ending December 31, 2017, and December 31, 2018, and $90.00 per Bbl for the year ending December 31, 2019, if the counterparties determine that the strike prices are in-the-money on a designated date in each respective preceding year. The extension for each year is exercisable without respect to the other years.

⁽³⁾  Settle on the respective pricing index to hedge basis differential associated with natural gas production.

⁽⁴⁾  The Company hedges the timing risk associated with the sales price of oil in the Mid-Continent, Hugoton Basin and Permian Basin regions. In these regions, the Company generally sells oil for the delivery month at a sales price based on the average NYMEX price of light crude oil during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is prompt (the “trade month roll”).

During the year ended December 31, 2012, the Company entered into commodity derivative contracts consisting of oil swaps for 2012 through 2017, natural gas swaps for 2012 through 2018, and oil and natural gas puts for 2012 through 2017 and paid premiums for put options of approximately $583 million. The Company also entered into natural gas basis swaps for 2012 through 2016 and trade month roll swaps for 2012 through 2017.

Settled derivatives on natural gas production for the year ended December 31, 2012, included volumes of 140,884 MMMBtu at an average contract price of $5.41 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2012, included volumes of 11,289 MBbls at an average contract price of $97.61 per Bbl. Settled derivatives on natural gas production for the year ended December 31, 2011, included volumes of 64,457 MMMBtu at an average contract price of $8.24 per MMBtu. Settled derivatives on oil production for the year ended December 31, 2011, included volumes of 7,917 MBbls at an average contract price of $85.70 per Bbl. The natural gas derivatives are settled based on the closing price of NYMEX natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX light crude oil for each day of the delivery month.

Interest Rate Swaps

The Company may from time to time enter into interest rate swap agreements based on LIBOR to minimize the effect of fluctuations in interest rates. If LIBOR is lower than the fixed rate in the contract, the Company is required to pay the counterparty the difference, and conversely, the counterparty is required to pay the Company if LIBOR is higher than the fixed rate in the contract. The Company does not designate interest rate swap agreements as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings.

In 2010, the Company restructured its interest rate swap portfolio in conjunction with the repayments of all of the outstanding indebtedness under its Credit Facility with net proceeds from the issuances of the 2020 and 2021 Senior Notes (see Note 6). In connection with the repayments of borrowings under its Credit Facility with net proceeds from the issuances of the 2020 and 2021 Senior Notes, the Company canceled (before the contract settlement date) all of its interest rate swap agreements resulting in realized losses of approximately $124 million. At December 31, 2012, and December 31, 2011, the Company had no outstanding interest rate swap agreements.

Balance Sheet Presentation

The Company’s commodity derivatives and, when applicable, its interest rate swap derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following summarizes the fair value of derivatives outstanding on a gross basis:

	December 31,
	2012		2011
	(in thousands)
Assets:
Commodity derivatives	$	1,282,390	$	880,175
Liabilities:
Commodity derivatives	$	405,619	$	320,835

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, when applicable, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in its Credit Facility or were participants or affiliates of participants in its Credit Facility at the time it originally entered into the derivatives. The Credit Facility is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $1.3 billion at December 31, 2012. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives and, when applicable, its interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated.

Gains (Losses) on Derivatives

Total gains and losses on derivatives, including realized and unrealized gains and losses, were approximately $125 million, $450 million and $7 million for the years ended December 31, 2012, December 31, 2011, and December 31, 2010, respectively, and are reported on the consolidated statements of operations in “gains on oil and natural gas derivatives” and “losses on interest rate swaps.”