DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with eleven of its active counterparties at September 30, 2012. The five largest counterparty net gain positions at September 30, 2012, Macquarie Bank Limited, J Aron & Company, BP Corporation North America Inc., Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $16.8 million, $9.7 million, $9.6 million, $8.5 million and $7.7 million, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net loss position with three of its active counterparties at September 30, 2012. The largest counterparty net loss position at September 30, 2012, Morgan Stanley Capital Group, Inc constituted approximately $24.3 million of Energen Resources’ net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

The following tables detail the fair values of commodity contracts by business segment on the balance sheets:



(in thousands)	September 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	76,354			$	—		$	76,354
Long-term asset derivative instruments	51,181				—			51,181
Total derivative assets	127,535				—			127,535
Accounts receivable	(33,476		)	*	—			(33,476		)
Long-term asset derivative instruments	(17,575		)	*	—			(17,575		)
Accounts payable	(12,471		)		—			(12,471		)
Long-term liability derivative instruments	(7,739		)		—			(7,739		)
Total derivative liabilities	(71,261		)		—			(71,261		)
Total derivatives designated	56,274				—			56,274
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(6,603		)	*	—			(6,603		)
Long-term asset derivative instruments	9,531				—			9,531
Total derivative assets	2,928				—			2,928
Accounts payable	(4,476		)		(14,990		)	(19,466		)
Long-term liability derivative instruments	(1,316		)		—			(1,316		)
Total derivative liabilities	(5,792		)		(14,990		)	(20,782		)
Total derivatives not designated	(2,864		)		(14,990		)	(17,854		)
Total derivatives	$	53,410			$	(14,990	)	$	38,420



(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $22.0 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2012, and December 31, 2011, respectively.

Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

The following table details the effect of derivative commodity instruments in cash flow hedging relationships on the financial statements:



(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($30.6) million and $105.7 million	—	$	(49,962	)	$	172,430
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	15,998		$	11,207
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(3,042	)	$	5,631



(in thousands)	Location on Income Statement	Nine months ended September 30, 2012			Nine months ended September 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $30.6 million and $76.6 million	—	$	49,961		$	125,005
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	39,012		$	13,028
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(1,372	)	$	3,240

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:



(in thousands)	Location on Income Statement	Three months ended September 30, 2012			Three months ended September 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	(45,618	)	$	53,227



(in thousands)	Location on Income Statement	Nine months ended September 30, 2012		Nine months ended September 30, 2011
Gain recognized in income on derivative	Operating revenues	$	33,825	$	53,225

As of September 30, 2012, $20.2 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of September 30, 2012, the Company had 2.0 billion, 5.6 billion and 9.7 billion cubic feet (Bcf) of natural gas hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.2 million, 8.7 million and 5.4 million barrels (MMBbl) of oil and oil basis hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 3.8 million and 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2012 and 2013, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $46,000 after-tax gain being recognized into operating revenues during the nine months ended September 30, 2012.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	3.6	Bcf	$4.49 Mcf	NYMEX Swaps
	8.9	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
	2.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.1	Bcf	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	1,850	MBbl	$88.51 Bbl	NYMEX Swaps
2013	8,858	MBbl	$90.95 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
Oil Basis Differential
2012	752	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	3,592	MBbl	$(3.03) Bbl	WTS/WTI Basis Swaps*
	1,740	MBbl	$(1.13) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2012	15.3	MMGal	$0.99 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:



Production Period	Total Hedged Volumes		Description
2012	4.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

As of September 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:


Level 1 -	Unadjusted quoted prices in active markets for identical assets or liabilities;


Level 2 -	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;


Level 3 -	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:



	September 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,048	)	$	37,323		$	36,275
Noncurrent assets	18,133			25,004			43,137
Current liabilities	(30,588		)	(1,349		)	(31,937		)
Noncurrent liabilities	(5,358		)	(3,697		)	(9,055		)
Net derivative asset (liability)	$	(18,861	)	$	57,281		$	38,420



	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

As of September 30, 2012, Alagasco had $15.0 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of September 30, 2012, and December 31, 2011.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $35 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.9 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

The tables below set forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:



	Three months ended			Three months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	103,456		$	13,446
Realized gains	18,737			9,370
Unrealized gains (losses) relating to instruments held at the reporting date*	(46,983		)	23,953
Settlements during period	(17,929		)	(10,565		)
Balance at end of period	$	57,281		$	36,204



	Nine months ended			Nine months ended
(in thousands)	September 30, 2012			September 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	51,858			37,031
Unrealized losses relating to instruments held at the reporting date*	(9,328		)	(5,356		)
Settlements during period	(51,050		)	(38,226		)
Balance at end of period	$	57,281		$	36,204

*Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012. Includes $0.1 million in mark-to-market gains for both the three months and nine months ended September 30, 2011.

The tables below set forth quantitative information about the Company’s Level 3 fair value measurements of derivative commodity instruments as follows:



(in thousands)	Fair Value as of September 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	8,807		Discounted Cash Flow	Forward Basis	($0.10 - $0.12) Mcf
2013	$	27,968		Discounted Cash Flow	Forward Basis	($0.14 - $0.15) Mcf
2014	$	17,273		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(634	)	Discounted Cash Flow	Forward Basis	($0.08) Mcf
2013	$	(1,221	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(2,132	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2012	$	14		Discounted Cash Flow	Forward Basis	($2.74 - $2.81) Bbl
2013	$	(5,085	)	Discounted Cash Flow	Forward Basis	($1.59) Bbl
Oil Basis - WTI/WTI
2013	$	(379	)	Discounted Cash Flow	Forward Basis	($0.75 - $1.15) Bbl
Natural Gas Liquids
2012	$	3,594		Discounted Cash Flow	Forward Price	$0.75 - $0.89 Gal
2013	$	9,076		Discounted Cash Flow	Forward Price	$0.77 - $0.85 Gal

*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.