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 twelve of its active counterparties at June 30, 2013. The three largest counterparty net gain positions at June 30, 2013, Macquarie Bank Limited, BP Corporation North America Inc. and J Aron & Company, constituted approximately $16.5 million, $11.7 million and $11.5 million, respectively, of Energen Resources’ total net gain on fair value of derivatives. At June 30, 2013, Energen Resources was in a net loss position with Morgan Stanley Capital Group for approximately $11.4 million.

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 June 30, 2013, 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.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin NYMEX oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company's election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions 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)	June 30, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	72,679			$	—	$	72,679
Long-term asset derivative instruments	42,105				—		42,105
Total derivative assets	114,784				—		114,784
Accounts receivable	(26,598		)	*	—		(26,598		)
Long-term asset derivative instruments	(3,099		)	*	—		(3,099		)
Accounts payable	(12,506		)		—		(12,506		)
Total derivative liabilities	(42,203		)		—		(42,203		)
Total derivatives not designated	$	72,581			$	—	$	72,581



(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

* 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 $13.4 million and a net $28.4 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 June 30, 2013, and December 31, 2012, respectively.

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



(in thousands)	Location on Statement of Income	Three months ended June 30, 2013		Three months ended June 30, 2012
Gain recognized in OCI on derivatives (effective portion), net of tax of $9.7 million and $68.7 million	—	$	15,847	$	112,158
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	3,112	$	21,143
Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	1,392	$	4,336



(in thousands)	Location on Statement of Income	Six months ended June 30, 2013			Six months ended June 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6.7) million and $61.2 million	—	$	(10,951	)	$	99,923
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	20,935		$	23,013
Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	858		$	1,669

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:



(in thousands)	Location on Statement of Income	Three months ended June 30, 2013		Three months ended June 30, 2012
Gain recognized in income on derivatives	Operating revenues	$	53,078	$	123,448



(in thousands)	Location on Statement of Income	Six months ended June 30, 2013		Six months ended June 30, 2012
Gain recognized in income on derivatives	Operating revenues	$	21,577	$	79,443

As of June 30, 2013, $14.6 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. As of June 30, 2013, the Company had 27.3 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 8.5 million barrels (MMBbl), 9.8 MMBbl and 0.7 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 23.2 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $5.9 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.

Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	6.2	Bcf	$4.83 Mcf	NYMEX Swaps
	17.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	3.1	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	4,603	MBbl	$91.07 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	1,811	MBbl	$(3.00) Bbl	WTS/WTI Basis Swaps*
	2,053	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	23.4	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

As of June 30, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010.

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



	June 30, 2013
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	8,108		$	37,973	$	46,081
Noncurrent assets	25,977			13,029		39,006
Current liabilities	(12,635		)	129		(12,506		)
Net derivative asset	$	21,450		$	51,131	$	72,581



	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176

As of June 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

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 $26 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $9.8 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)	June 30, 2013			June 30, 2012
Balance at beginning of period	$	26,459		$	104,923
Realized gains	6,183			20,553
Unrealized gains (losses) relating to instruments held at the reporting date*	23,404			(2,725		)
Settlements during period	(4,915		)	(19,295		)
Balance at end of period	$	51,131		$	103,456



	Six months ended			Six months ended
(in thousands)	June 30, 2013			June 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	32,368			34,379
Unrealized gains (losses) relating to instruments held at the reporting date*	(39,156		)	36,397
Settlements during period	(31,100		)	(33,121		)
Balance at end of period	$	51,131		$	103,456

*Includes $8.5 million and $2.7 million in mark-to-market gains for the three months and six months ended June 30, 2013, respectively. Includes $5.4 million and $7.0 million in mark-to-market gains for the three months and six months ended June 30, 2012, respectively.

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 June 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	19,172		Discounted Cash Flow	Forward Basis	($0.18 - $0.23) Mcf
2014	$	27,196		Discounted Cash Flow	Forward Basis	($0.16 - $0.20) Mcf
2015	$	611		Discounted Cash Flow	Forward Basis	($0.18) Mcf
Natural Gas Basis - Permian
2013	$	537		Discounted Cash Flow	Forward Basis	($0.18) Mcf
2014	$	623		Discounted Cash Flow	Forward Basis	($0.16 - $0.17) Mcf
Oil Basis - WTS/WTI
2013	$	(4,990	)	Discounted Cash Flow	Forward Basis	($0.25) Bbl
Oil Basis - WTI/WTI
2013	$	(1,568	)	Discounted Cash Flow	Forward Basis	($0.13 - $0.32) Bbl
Natural Gas Liquids
2013	$	9,550		Discounted Cash Flow	Forward Price	$0.65 - $0.72 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.

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:



	June 30, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	114,784	$	(29,697	)	$	85,087	$	—	$	—	$	85,087
Derivative liabilities	$	42,203	$	(29,697	)	$	12,506	$	—	$	—	$	12,506



	December 31, 2012
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	149,504	$	(44,135	)	$	105,369	$	—	$	—	$	105,369
Derivative liabilities	$	56,328	$	(44,135	)	$	12,193	$	—	$	—	$	12,193