ENERGEN CORP - FORM 10-Q - November 6, 2015

Attached files

file	filename
EX-32 - ENERGEN CORPORATION 18 U.S.C. SECTION 1350 CERTIFICATION - ENERGEN CORP	egn93015ex32.htm
EX-31.B - ENERGEN CORPORATION CERTIFICATION OF CFO - ENERGEN CORP	egn93015ex31b.htm
EX-31.A - ENERGEN CORPORATION CERTIFICATION OF CEO - ENERGEN CORP	egn93015ex31a.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ______________ TO _______________

Commission file number 1-7810

Energen Corporation

(Exact name of registrant as specified in its charter)



Alabama		63-0757759
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



605 Richard Arrington Jr. Boulevard North, Birmingham, Alabama 35203-2707		35203-2707
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code

(205) 326-2700

Indicate by a check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES x NO o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding

12 months (or for such shorter period that the registrant was required to submit and post such files). YES x NO o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES o NO x

Number of shares outstanding of each of the registrant’s classes of common stock as of October 30, 2015.



Energen Corporation	$0.01 par value	78,798,129

ENERGEN CORPORATION

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2015

TABLE OF CONTENTS



		Page
PART I: FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets	3
	Consolidated Statements of Income	5
	Consolidated Statements of Comprehensive Income	6
	Consolidated Statements of Cash Flows	7
	Condensed Notes to Unaudited Consolidated Financial Statements	8

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44

Item 4.	Controls and Procedures	46

PART II: OTHER INFORMATION

Item 1.	Legal Proceedings	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47

Item 6.	Exhibits	47

SIGNATURES		48

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



ENERGEN CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(in thousands)	September 30, 2015		December 31, 2014
ASSETS
Current Assets
Cash and cash equivalents	$	701	$	1,852
Accounts receivable, net of allowance for doubtful accounts of $735 and $688 at September 30, 2015 and December 31, 2014, respectively	99,297		157,678
Inventories	18,184		14,251
Assets held for sale	—		395,797
Derivative instruments	153,816		322,337
Prepayments and other	12,667		27,445
Total current assets	284,665		919,360
Property, Plant and Equipment
Oil and natural gas properties, successful efforts method
Proved properties	7,754,455		6,903,514
Unproved properties	172,897		142,340
Less accumulated depreciation, depletion and amortization	2,744,855		1,893,106
Oil and natural gas properties, net	5,182,497		5,152,748
Other property and equipment, net	48,739		46,389
Total property, plant and equipment, net	5,231,236		5,199,137
Noncurrent derivative instruments	2,517		—
Other assets	13,129		19,761
TOTAL ASSETS	$	5,531,547	$	6,138,258

The accompanying notes are an integral part of these unaudited consolidated financial statements.



ENERGEN CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(in thousands, except share and per share data)	September 30, 2015			December 31, 2014
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	79,623		$	101,453
Accrued taxes	27,555			5,530
Accrued wages and benefits	25,103			21,553
Accrued capital costs	101,486			207,461
Revenue and royalty payable	58,480			72,047
Liabilities related to assets held for sale	—			24,230
Pension liabilities	29,789			24,609
Deferred income taxes	9,908			79,164
Derivative instruments	3,079			988
Other	13,513			23,288
Total current liabilities	348,536			560,323
Long-term debt	750,081			1,038,563
Asset retirement obligations	100,781			94,060
Pension and other postretirement liabilities	734			15,935
Deferred income taxes	853,360			1,000,486
Noncurrent derivative instruments	2,924			—
Other long-term liabilities	10,234			14,287
Total liabilities	2,066,650			2,723,654
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized; 81,767,862 shares and 75,875,711 shares issued at September 30, 2015 and December 31, 2014, respectively	818			759
Premium on capital stock	975,616			564,438
Retained earnings	2,638,397			2,997,821
Accumulated other comprehensive income (loss), net of tax
Pension and postretirement plans	(19,969		)	(22,870		)
Deferred compensation plan	1,923			2,862
Treasury stock, at cost; 3,019,498 shares and 2,980,598 shares at September 30, 2015 and December 31, 2014, respectively	(131,888		)	(128,406		)
Total shareholders’ equity	3,464,897			3,414,604
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,531,547		$	6,138,258

The accompanying notes are an integral part of these unaudited consolidated financial statements.



ENERGEN CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except per share data)	2015			2014			2015			2014
Revenues
Oil, natural gas liquids and natural gas sales	$	188,398		$	350,773		$	595,510		$	1,057,447
Gain on derivative instruments, net	107,173			147,735			90,245			9,498
Total revenues	295,571			498,508			685,755			1,066,945
Operating Costs and Expenses
Oil, natural gas liquids and natural gas production	54,598			67,720			175,933			199,861
Production and ad valorem taxes	13,366			25,729			45,783			81,102
Depreciation, depletion and amortization	149,781			139,104			434,005			399,568
Asset impairment	399,394			178,912			466,390			181,500
Exploration	493			8,417			12,274			21,218
General and administrative	23,631			27,784			94,338			93,499
Accretion of discount on asset retirement obligations	1,700			1,924			5,379			5,650
(Gain) loss on sale of assets and other	822			747			(26,046		)	1,809
Total costs and expenses	643,785			450,337			1,208,056			984,207
Operating Income (Loss)	(348,214		)	48,171			(522,301		)	82,738
Other Income (Expense)
Interest expense	(10,084		)	(11,522		)	(33,086		)	(27,374		)
Other income	56			37			143			1,047
Total other expense	(10,028		)	(11,485		)	(32,943		)	(26,327		)
Income (Loss) From Continuing Operations Before Income Taxes	(358,242		)	36,686			(555,244		)	56,411
Income tax expense (benefit)	(130,338		)	16,055			(200,319		)	23,287
Income (Loss) From Continuing Operations	(227,904		)	20,631			(354,925		)	33,124
Discontinued Operations, net of tax
Income (loss) from discontinued operations	—			(3,485		)	—			30,435
Gain on disposal of discontinued operations	—			440,105			—			439,055
Income From Discontinued Operations	—			436,620			—			469,490
Net Income (Loss)	$	(227,904	)	$	457,251		$	(354,925	)	$	502,614

Diluted Earnings Per Average Common Share
Continuing operations	$	(2.89	)	$	0.28		$	(4.72	)	$	0.45
Discontinued operations	—			5.94			—			6.41
Net Income (Loss)	$	(2.89	)	$	6.22		$	(4.72	)	$	6.86
Basic Earnings Per Average Common Share
Continuing operations	$	(2.89	)	$	0.28		$	(4.72	)	$	0.45
Discontinued operations	—			5.98			—			6.45
Net Income (Loss)	$	(2.89	)	$	6.26		$	(4.72	)	$	6.90
Dividends Per Common Share	$	0.02		$	0.15		$	0.06		$	0.45
Diluted Average Common Shares Outstanding	78,742			73,507			75,125			73,238
Basic Average Common Shares Outstanding	78,742			73,093			75,125			72,861

The accompanying notes are an integral part of these unaudited consolidated financial statements.



ENERGEN CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2015			2014			2015			2014
Net Income (Loss)	$	(227,904	)	$	457,251		$	(354,925	)	$	502,614
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of derivative commodity instruments, net of tax of $0, $18, $0 and $25, respectively	—			29			—			40
Reclassification adjustment for derivative commodity instruments, net of tax of $0, ($2,277), $0 and ($5,997), respectively	—			(3,715		)	—			(9,784		)
Current period change in fair value of interest rate swap, net of tax of $0, $0, $0 and ($160), respectively	—			—			—			(298		)
Reclassification adjustment for interest rate swap, net of tax of $0, $86, $0 and $798, respectively	—			161			—			1,482
Total cash flow hedges	—			(3,525		)	—			(8,560		)
Pension and postretirement plans:
Amortization of net benefit obligation at transition, net of tax of $0, ($1), $0 and $6, respectively	—			(1		)	—			11
Amortization of prior service cost, net of tax of $0, $26, $0 and $78, respectively	—			48			—			144
Amortization of net loss, including settlement charges, net of tax of $256, $500, $1,561 and $4,071, respectively	474			930			2,901			7,561
Current period change in fair value of pension and postretirement plans, net of tax of $0, $190, $0 and ($962), respectively	—			352			—			(1,784		)
Total pension and postretirement plans	474			1,329			2,901			5,932
Comprehensive Income (Loss)	$	(227,430	)	$	455,055		$	(352,024	)	$	499,986

The accompanying notes are an integral part of these unaudited consolidated financial statements.



ENERGEN CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine months ended September 30, (in thousands)	2015			2014
Operating Activities
Net income (loss)	$	(354,925	)	$	502,614
Income from discontinued operations	—			(469,490		)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	434,005			399,568
Asset impairment	466,390			181,500
Accretion of discount on asset retirement obligations	5,379			5,650
Deferred income taxes	(217,943		)	287,855
Change in derivative fair value	139,490			(53,928		)
(Gain) loss on sale of assets	(27,558		)	105
Stock-based compensation expense	7,158			10,837
Exploration, including dry holes	6,967			8,382
Discontinued operations	—			112,180
Other, net	7,080			(1,972		)
Net change in:
Accounts receivable	81,285			(28,486		)
Inventories	(3,933		)	(3,243		)
Accounts payable	(30,871		)	27,967
Accrued taxes/income tax receivable	25,339			(264,108		)
Pension and other postretirement benefit contributions	(10,932		)	(2,397		)
Other current assets and liabilities	(4,996		)	(3,746		)
Net cash provided by operating activities	521,935			709,288
Investing Activities
Additions to oil and natural gas properties	(960,966		)	(906,166		)
Acquisitions, net of cash acquired	(62,805		)	(26,371		)
Proceeds from the sale of assets	393,174			1,347,904
Purchase of short-term investments	(919,000		)	(377,000		)
Sale of short-term investments	919,000			359,000
Discontinued operations	—			(51,850		)
Net cash provided by (used in) investing activities	(630,597		)	345,517
Financing Activities
Payment of dividends on common stock	(4,499		)	(32,840		)
Issuance of common stock	399,593			23,053
Reduction of long-term debt	—			(600,000		)
Payment of debt issuance costs	—			(7,912		)
Net change in credit facility	(288,500		)	(410,100		)
Tax benefit on stock compensation	917			3,873
Discontinued operations	—			(35,113		)
Net cash provided by (used in) financing activities	107,511			(1,059,039		)
Net change in cash and cash equivalents	(1,151		)	(4,234		)
Cash and cash equivalents at beginning of period	1,852			5,555
Cash and cash equivalents at end of period	$	701		$	1,321

The accompanying notes are an integral part of these unaudited consolidated financial statements.

ENERGEN CORPORATION

CONDENSED NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

Energen Corporation (Energen or the Company) is an oil and natural gas exploration and production company engaged in the exploration, development and production of oil and natural gas liquids-rich properties and natural gas in the Permian Basin in west Texas and the San Juan Basin in New Mexico. Headquartered in Birmingham, Alabama, our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources). The unaudited consolidated financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2014, 2013 and 2012, included in the 2014 Annual Report of Energen on Form 10-K.

Our accompanying unaudited consolidated financial statements include Energen and its subsidiaries, principally Energen Resources, and have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position, results of operations, and cash flows for the periods and as of the dates shown. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior periods’ financial statements to the current-quarter presentation.

Prior to September 2, 2014, Energen owned Alabama Gas Corporation (Alagasco), which was engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. On September 2, 2014, Energen completed the transaction to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion, resulting in a pre-tax gain of $726.5 million. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness.

2. DERIVATIVE COMMODITY INSTRUMENTS

We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

The following table details gain (loss) on derivative instruments, net, as follows:



	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands)	2015			2014		2015			2014
Open non-cash mark-to-market gains (losses) on derivative instruments	$	(1,164	)	$	147,287	$	(177,682	)	$	53,985
Closed gains (losses) on derivative instruments	108,337			448		267,927			(44,487		)
Gain on derivative instruments, net	$	107,173		$	147,735	$	90,245		$	9,498

The following tables detail the offsetting of derivative assets and liabilities as well as the fair values of derivatives on the balance sheets:



(in thousands)	September 30, 2015
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	176,061	$	(22,245	)	$	153,816	$	—	$	—	$	153,816
Noncurrent derivative instruments	3,487		(970		)	2,517		—		—		2,517
Total derivative assets	179,548		(23,215		)	156,333		—		—		156,333
Liabilities
Derivative instruments	25,324		(22,245		)	3,079		—		—		3,079
Noncurrent derivative instruments	3,894		(970		)	2,924		—		—		2,924
Total derivative liabilities	29,218		(23,215		)	6,003		—		—		6,003
Total derivatives	$	150,330	$	—		$	150,330	$	—	$	—	$	150,330



(in thousands)	December 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
	Gross Amounts Recognized at Fair Value		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Fair Value Presented in the Balance Sheets
Derivatives not designated as hedging instruments
Assets
Derivative instruments	$	339,977	$	(17,640	)	$	322,337	$	—	$	—	$	322,337
Noncurrent derivative instruments	—		—			—		—		—		—
Total derivative assets	339,977		(17,640		)	322,337		—		—		322,337
Liabilities
Derivative instruments	18,628		(17,640		)	988		—		—		988
Noncurrent derivative instruments	—		—			—		—		—		—
Total derivative liabilities	18,628		(17,640		)	988		—		—		988
Total derivatives	$	321,349	$	—		$	321,349	$	—	$	—	$	321,349

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with twelve of our active counterparties and in a net loss position with the remaining two at September 30, 2015. The largest counterparty net gain positions at September 30, 2015, Morgan Stanley Capital Group Inc., J.P. Morgan Ventures Energy Corporation, Merrill Lynch Commodities, Inc., Canadian Imperial Bank of Commerce and BP Corporation North America Inc., constituted approximately $24.1 million, $22.6 million, $20.5 million, $14.0 million and $13.9 million, respectively, of Energen’s total gain on fair value of derivatives.

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



(in thousands)	Location on Statements of Income	Three months ended September 30, 2014		Nine months ended September 30, 2014
Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $18 and $25	—	$	29	40
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Gain (loss) on derivative instruments, net	$	5,992	15,781

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



(in thousands)	Location on Statements of Income	Three months ended September 30, 2015		Three months ended September 30, 2014
Gain recognized in income on derivatives	Gain (loss) on derivative instruments, net	$	107,173	$	141,743



(in thousands)	Location on Statements of Income	Nine months ended September 30, 2015		Nine months ended September 30, 2014
Gain (loss) recognized in income on derivatives	Gain (loss) on derivative instruments, net	$	90,245	(6,283	)

As of September 30, 2015, Energen had entered into the following transactions for the remainder of 2015 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2015	3,513	MBbl	$78.28 Bbl	NYMEX Swaps
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps
Oil Basis Differential
2015	1,890	MBbl	$(4.55) Bbl	WTI/WTI Basis Swaps
2015	540	MBbl	$(4.30) Bbl	WTS/WTI Basis Swaps
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps
Natural Gas
2015	5.5	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan
2015	1.5	Bcf	$4.20 Mcf	Basin Specific Swaps - Permian
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

As of September 30, 2015, the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2016.

3. FAIR VALUE MEASUREMENTS

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). In determining fair value, we use various valuation approaches and classify all assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect our own considerations about the assumptions other market participants would use in pricing the asset or liability based on the best information available in the circumstances. 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 hierarchy is broken down into three levels based on the observability of inputs 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 assumptions that market 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.

No transfers between fair value hierarchy levels occurred during the three months or nine months ended September 30, 2015.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Energen classifies the fair value of multiple derivative instruments executed under master netting arrangements as net derivative assets and liabilities. The following fair value hierarchy tables present information about Energen’s assets and liabilities measured at fair value on a recurring basis:



	September 30, 2015
(in thousands)	Level 2		Level 3			Total
Assets:
Derivative instruments	$	164,475	$	(10,659	)	$	153,816
Noncurrent derivative instruments	3,487		(970		)	2,517
Total assets	167,962		(11,629		)	156,333
Liabilities:
Derivative instruments	—		(3,079		)	(3,079		)
Noncurrent derivative instruments	—		(2,924		)	(2,924		)
Total liabilities	—		(6,003		)	(6,003		)
Net derivative asset (liability)	$	167,962	$	(17,632	)	$	150,330



	December 31, 2014
(in thousands)	Level 2		Level 3			Total
Assets:
Derivative instruments	$	294,865	$	27,472		$	322,337
Total assets	294,865		27,472			322,337
Liabilities:
Derivative instruments	2,048		(3,036		)	(988		)
Total liabilities	2,048		(3,036		)	(988		)
Net derivative asset	$	296,913	$	24,436		$	321,349

Derivative Instruments: The fair value of Energen’s derivative commodity instruments is determined using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. Our 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 we are

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 oil and natural gas prices. 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. We consider the frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While Energen does not have access to the specific assumptions used in its counterparties’ valuation models, Energen maintains communications with its counterparties and discusses pricing practices. Further, we corroborate the fair value of our transactions by comparison of market-based price sources.

Energen utilizes a discounted cash flow model in valuing its interest rate derivatives, which are comprised of interest rate swap agreements. The fair value attributable to Energen's interest rate derivative contracts is based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (LIBOR) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

At September 30, 2015, Energen had interest rate swap agreements with a notional value of $83.3 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swaps was a $0.4 million and a $0.8 million liability at September 30, 2015 and December 31, 2014, respectively, and is classified as Level 2 fair value liabilities. The fair value of our interest rate swaps are recognized on a gross basis in accounts payable and other long-term liabilities on the balance sheets.

Level 3 Fair Value Instruments: Energen 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 Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $2 million change in the fair value of open Level 3 derivative contracts and to the results of operations.

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



	Three months ended
	September 30,
(in thousands)	2015			2014
Balance at beginning of period	$	(14,063	)	$	5,207
Realized gains (losses)	(2,820		)	10,769
Unrealized gains (losses) relating to instruments held at the reporting date*	(3,569		)	9,348
Settlements during period	2,820			(10,438		)
Balance at end of period	$	(17,632	)	$	14,886



	Nine months ended
	September 30,
(in thousands)	2015			2014
Balance at beginning of period	$	24,436		$	18,289
Realized gains	10,994			8,581
Unrealized losses relating to instruments held at the reporting date*	(42,068		)	(3,734		)
Settlements during period	(10,994		)	(8,250		)
Balance at end of period	$	(17,632	)	$	14,886

*Includes $5.4 million and $20.2 million in mark-to-market losses for the three months and nine months ended September 30, 2015, respectively. Includes $12.2 million and $9.6 million in mark-to-market gains for the three months and nine months ended September 30, 2014, respectively.

The table below sets forth quantitative information about Energen’s Level 3 fair value measurements of derivative commodity instruments as follows:



(in thousands, except price data)	Fair Value as of September 30, 2015			Valuation Technique*	Unobservable Input*	Range
Oil Basis - WTI/WTI
2015	$	(9,731	)	Discounted Cash Flow	Forward Basis	$0.09 - $0.23 Bbl
2016	$	(13,298	)	Discounted Cash Flow	Forward Basis	($0.05 - $0.16) Bbl
Oil Basis - WTS/WTI
2015	$	(2,762	)	Discounted Cash Flow	Forward Basis	$0.32 - $0.37 Bbl
2016	$	(3,427	)	Discounted Cash Flow	Forward Basis	($0.17) - $0.19 Bbl
Natural Gas Basis - San Juan
2015	$	9,018		Discounted Cash Flow	Forward Basis	($0.09 - $0.10) Mcf
Natural Gas Basis - Permian
2015	$	2,568		Discounted Cash Flow	Forward Basis	($0.10) Mcf

*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.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Energen’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values.

Asset retirement obligations: Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. See Note 11, Asset Retirement Obligations, for further discussion related to these ARO’s. These assumptions are classified as Level 3 fair value.

Asset Impairments: We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues. Such potential events may include, but are not limited to, commodity price declines, unanticipated increased operating costs, and lower than expected field production performance. If a material event occurs, Energen makes an estimate of undiscounted future cash flows to determine whether the asset is impaired. If the asset is impaired, we will record an impairment loss for the difference between the net book value of the properties and the fair value of the properties. The fair value of the properties typically is estimated using discounted cash flows. Cash flow and fair value estimates require Energen to make projections and assumptions for pricing, demand, competition, operating costs, legal and regulatory issues, discount rates and other factors for many years into the future.

These assumptions are classified as Level 3 fair value. See Note 13, Asset Impairment, for impairments recognized by Energen during the three months and nine months ended September 30, 2015 and 2014.

Financial Instruments not Carried at Fair Value

The stated value of cash and cash equivalents, short-term investments, accounts receivable (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. Short-term investments purchased and sold during the year-to-date 2015 of $919 million are not considered readily convertible into cash and accordingly are not classified in cash and cash equivalents. In addition, the Company also invested in certain short-term investments that qualify and were classified as cash and cash equivalents. The fair value of Energen’s long-term debt, including the current portion, was approximately $702.9 million and $993.7 million and had a carrying value of $750.5 million and $1,039.0 million at September 30, 2015 and December 31, 2014, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

4. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:



(in thousands)	September 30, 2015		December 31, 2014
Credit facility	$	196,500	$	485,000
7.40% Medium-term Notes, Series A, due July 24, 2017	2,000		2,000
7.36% Medium-term Notes, Series A, due July 24, 2017	15,000		15,000
7.23% Medium-term Notes, Series A, due July 28, 2017	2,000		2,000
7.32% Medium-term Notes, Series A, due July 28, 2022	20,000		20,000
7.60% Medium-term Notes, Series A, due July 26, 2027	5,000		5,000
7.35% Medium-term Notes, Series A, due July 28, 2027	10,000		10,000
7.125% Medium-term Notes, Series B, due February 15, 2028	100,000		100,000
4.625% Notes, due September 1, 2021	400,000		400,000
	750,500		1,039,000
Less unamortized debt discount	419		437
Total Energen	$	750,081	$	1,038,563

The aggregate maturities of Energen’s long-term debt outstanding at September 30, 2015 are as follows:



(in thousands)
Remaining 2015	2016	2017	2018	2019	2020 and thereafter
$—	$—	$19,000	$—	$196,500	$535,000

The debt agreements of Energen contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have events of default based on credit ratings, the interest rates applicable to the syndicated credit facility discussed below may adjust based on credit rating changes during certain periods.

Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen or Energen Resources will constitute an event of default by Energen. The Indenture does not include a restriction on the payment of dividends.

Credit Facility: On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. Subject to release of collateral in certain periods upon the achievement of certain investment grade ratings from designated ratings agencies, the credit facility is collateralized by certain assets of Energen, including a pledge of equity interests in subsidiaries of Energen other than Energen Resources, and by mortgages on substantially all of Energen Resources’ oil and natural gas properties. The current credit facility qualifies for classification as long-term debt on the consolidated balance sheets. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount

is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2016.

Under the credit facility, a cross default provision provides that any debt default of more than $75 million by Energen or Energen Resources will constitute an event of default by Energen.

Upon an uncured event of default under the credit facility, all amounts owing under the credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen was in compliance with the terms of its credit facility as of September 30, 2015.

The following is a summary of information relating to Energen’s credit facilities:



(in thousands)	September 30, 2015		December 31, 2014
Credit facility outstanding	$	196,500	$	485,000
Available for borrowings	1,403,500		1,515,000
Total borrowing commitments*	$	1,600,000	$	2,000,000

*Effective October 20, 2015, borrowing commitments were lowered to $1.4 billion.



(in thousands)	September 30, 2015			December 31, 2014
Maximum amount outstanding at any month-end	$	685,000		$	750,000
Average daily amount outstanding	$	405,531		$	482,166
Weighted average interest rates based on:
Average daily amount outstanding	1.61		%	1.46		%
Amount outstanding at period-end	1.46		%	1.67		%

Energen’s interest expense was $10.1 million and $33.1 million for the three months and nine months ended September 30, 2015, respectively. Interest expense for Energen was $11.5 million and $27.4 million for the three months and nine months ended September 30, 2014, respectively. Energen had no capitalized interest for the three months ended September 30, 2015 and 2014. Energen’s total interest expense for the nine months ended September 30, 2015 included capitalized interest expense of $32,000. Energen had capitalized interest of $37,000 for the nine months ended September 30, 2014. At September 30, 2015, Energen paid commitment fees on the unused portion of the available credit facilities at a current annual rate of 30 basis points.

5. RECONCILIATION OF EARNINGS PER SHARE (EPS)



	Three months ended							Three months ended
(in thousands, except per share amounts)	September 30, 2015							September 30, 2014
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(227,904	)	78,742	$	(2.89	)	$	457,251	73,093	$	6.26
Effect of dilutive securities
Stock options				—						231
Non-vested restricted stock				—						68
Performance share awards				—						115
Diluted EPS	$	(227,904	)	78,742	$	(2.89	)	$	457,251	73,507	$	6.22



	Nine months ended							Nine months ended
(in thousands, except per share amounts)	September 30, 2015							September 30, 2014
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(354,925	)	75,125	$	(4.72	)	$	502,614	72,861	$	6.90
Effect of dilutive securities
Stock options				—						219
Non-vested restricted stock				—						67
Performance share awards				—						91
Diluted EPS	$	(354,925	)	75,125	$	(4.72	)	$	502,614	73,238	$	6.86

In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 354,479 and 374,294 of excluded shares for the three months and nine months ended September 30, 2015, respectively.

Energen had the following shares that were excluded from the computation of diluted EPS, as inclusion would be anti-dilutive:



	Three months ended September 30,		Nine months ended September 30,
(in thousands)	2015	2014	2015	2014
Stock options	114	6	114	6
Performance share awards	120	2	120	4

6. EQUITY OFFERING

During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from this offering were used to repay borrowings under our credit facility and for general corporate purposes.

7. STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options and non-qualified stock options to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock and restricted stock units. In February 2015, Energen awarded 99,814 restricted stock units with a grant-date fair value of $65.15. These awards have a three year vesting period and were valued based on the quoted market price of Energen’s common stock at the date of grant.

Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Energen common stock. Performance share awards are valued using the Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. Energen granted 120,372 performance share awards during the first quarter of 2015 with a three year vesting period and a grant-date fair value of $83.94.

Stock Appreciation Rights Plan

The Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Energen common stock. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement and have a three year vesting period.

Petrotech Incentive Plan

The Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are remeasured each reporting period until settlement. During the first quarter of 2015, Energen awarded 59,288 Petrotech units with a fair value of $49.68 as of September 30, 2015, none of which included a market condition. Energen awarded 64,305 Petrotech units which included a market condition and had a fair value of $81.96 as of September 30, 2015. These awards have a three year vesting period. Also awarded were 1,472 Petrotech units with a sixteen month vesting period and a fair value of $49.82 as of September 30, 2015, and 265 Petrotech units with a twenty-four month vesting period and a fair value of $49.76 as of September 30, 2015, none of which included a market condition. During the third quarter of 2015, Energen awarded 4,926 Petrotech units with a fair value of $49.68 as of September 30, 2015, 176 Petrotech units with a sixteen month vesting period and a fair value of $49.82 as of September 30, 2015, and 32 Petrotech units with a twenty-four month vesting period and a fair value of $49.76 as of September 30, 2015, none of which included a market condition.

Stock Repurchase Program

During the three months and nine months ended September 30, 2015, Energen had non-cash purchases of approximately $23,000 and $4.4 million, respectively, of Energen common stock in conjunction with tax withholdings on our non-qualified deferred compensation plan and other stock compensation. Energen had non-cash purchases of Energen common stock of $0.6 million and $2.0 million during the three months and nine months ended September 30, 2014, respectively. Energen utilized internally generated cash flows in payment of the related tax withholdings.

8. EMPLOYEE BENEFIT PLANS

In October 2014, Energen’s Board of Directors elected to freeze and terminate its qualified defined benefit pension plan. A plan amendment adopted in October 2014 closed the plan to new entrants, effective November 1, 2014, and froze benefit accruals after December 31, 2014. Energen terminated the plan on January 31, 2015 and anticipates distributing benefits in late 2015 or in 2016.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans are subject to certain payment restrictions under the Internal Revenue Code and Treasury regulations and payments to plan participants were made in the first quarter of 2015 with the remainder to be made in the first quarter of 2016. In connection with the termination of these plans, the Company has also classified approximately $3.3 million as of September 30, 2015 of its investment in a Rabbi Trust from other long term assets to prepayments and other assets in the accompanying balance sheets to reflect its intent to utilize these assets to partially fund the estimated payments in the first quarter of 2016.

In October 2014, Energen’s Board of Directors amended and restated the Employee Savings Plan to make certain benefit design changes effective January 1, 2015. The benefit design changes include an increase in the percentage of Energen match and other contributions.

Effective April 30, 2014, Energen separated its defined benefit non-contributory pension plan and its postretirement healthcare and life insurance benefit plan into an Energen and an Alagasco plan reflecting the separation of assets and obligations in accordance with ERISA provisions. Energen remeasured the plans using current assumptions.

The components of net periodic benefit cost from continuing operations for Energen’s defined benefit non-contributory pension plan and certain nonqualified supplemental pension plans were as follows:



	Three months ended September 30,					Nine months ended September 30,
(in thousands)	2015		2014			2015		2014
Components of net periodic benefit cost:
Service cost	$	—	$	1,902		$	—	$	5,157
Interest cost	204		1,157			612		3,974
Expected long-term return on assets	—		(1,157		)	—		(4,067		)
Actuarial loss	184		1,296			553		4,115
Prior service cost amortization	—		63			—		177
Settlement charge	546		370			3,909		4,043
Net periodic expense	$	934	$	3,631		$	5,074	$	13,399

During 2015, Energen anticipates an additional contribution of $14.3 million in order to complete the distribution of plan assets related to the plan terminations. The Company made benefit payments, which were funded by the Rabbi Trust, of approximately $10.9 million during the nine months ended September 30, 2015 with respect to the termination of the non-qualified supplemental retirement plans and expects to make additional benefit payments of $30,000 through the remainder of 2015. In the three months and nine months ended September 30, 2015, Energen incurred settlement charges of $0.5 million and $1.4 million, respectively, for the payment of lump sums from the qualified defined benefit pension plans. Also in the first quarter of 2015, Energen incurred a settlement charge of $2.5 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the second quarter and third quarter of 2014, Energen incurred settlement charges of $0.4 million and $0.3 million, respectively, for the payment of lump sums from the qualified defined benefit pension plan. In the first quarter of 2014, Energen incurred settlement charges of $6.9 million for the payment of lump sums from the qualified defined benefit pension plans of which $3.7 million is included in discontinued operations. Also in the first quarter and third quarter of 2014, Energen incurred settlement charges of $0.4 million and $26,000, respectively, for the payment of lump sums from the non-qualified supplemental retirement plans.

The components of net periodic postretirement benefit expense from continuing operations for Energen’s postretirement benefit plan were as follows:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2015			2014			2015			2014
Components of net periodic benefit cost:
Service cost	$	98		$	87		$	294		$	206
Interest cost	117			137			350			587
Expected long-term return on assets	(114		)	(246		)	(343		)	(1,016		)
Actuarial gain	—			(151		)	—			(572		)
Transition amortization	—			9			—			39
Net periodic (income) expense	$	101		$	(164	)	$	301		$	(756	)

There are no required contributions to the postretirement benefit plan during 2015.

9. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 5.9 million barrels of oil equivalent (MMBOE) through October 2020.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and we have accrued a provision for our estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. We recognize a liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen and Energen Resources. Historically, the cost of environmental compliance has not materially affected our financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, Energen Resources has substantially completed the cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The cleanup, remediation and related costs approximated $2.9 million.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party under The Comprehensive Environmental Response, Compensation, and Liability Act for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due

to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

New Mexico Audits: In 2011, Energen Resources received an Order to Perform Restructured Accounting and Pay Additional Royalties (the Order), following an audit performed by the Taxation and Revenue Department (the Department) of the State of New Mexico on behalf of the Office of Natural Resources Revenue (ONRR), of federal oil and gas leases in New Mexico. The audit covered periods from January 2004 through December 2008 and included a review of the computation and payment of royalties due on minerals removed from specified U.S. federal leases. The Order addressed ONRR’s efforts to change accounting and reporting practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Energen Resources appealed the Order in 2011 and in July 2012, on a motion from ONRR, the Order was remanded. In August 2014, ONRR issued its Revised Order that is now under appeal. In the Revised Order, ONRR has ordered that Energen pay additional royalties on production from certain federal leases in the amount of $129,700. Energen estimates that application of the Revised Order to all of the Company’s federal leases would result in ONRR claims up to approximately $24 million, plus interest and penalties from 2004 forward. ONRR began implementing its unbundling initiative in 2010, but seeks to implement its revisions retroactively, despite the fact that they conflict with previous audits, allowances and industry practice. Energen continues to vigorously contest the Revised Order and the findings. Management is unable, at this time, to determine a range of reasonably possible losses, and no amount has been accrued as of September 30, 2015.

10. EXPLORATORY COSTS

Energen capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, Energen continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) Energen is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in proved properties in the balance sheets. If the exploratory well is determined to be a dry hole, the costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2015			2014			2015			2014
Capitalized exploratory well costs at beginning of period	$	99,926		$	166,458		$	119,439		$	57,600
Additions pending determination of proved reserves	113,734			258,724			533,255			623,913
Reclassifications due to determination of proved reserves	(82,325		)	(258,123		)	(521,359		)	(513,263		)
Exploratory well costs charged to expense	—			(1,217		)	—			(2,408		)
Capitalized exploratory well costs at end of period	$	131,335		$	165,842		$	131,335		$	165,842

The following table sets forth capitalized exploratory well costs:



(in thousands)	September 30, 2015		December 31, 2014
Exploratory wells in progress (drilling rig not released)	$	14,161	$	18,781
Capitalized exploratory well costs capitalized for a period of one year or less	117,174		100,658
Total capitalized exploratory well costs	$	131,335	$	119,439

No wells were capitalized for a period greater than one year as of September 30, 2015 or December 31, 2014. At September 30, 2015, Energen had 55 gross exploratory wells either drilling or waiting on results from completion and testing. Of these wells, 47 are located in the Permian Basin and the remaining 8 are located in the San Juan Basin.

11. ASSET RETIREMENT OBLIGATIONS

Energen’s asset retirement obligations (ARO) primarily relate to the future plugging, abandonment and reclamation of wells and facilities. We recognize a liability for the fair value of the ARO in the periods incurred. The ARO fair value liability is determined by calculating the present value of the estimated future cash outflows we expect to incur to plug, abandon and reclaim our producing properties at the end of their productive lives, and is recognized on a discounted basis incorporating an estimate of performance risk specific to Energen. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful lives of the related assets. Upon settlement of the liability, Energen may recognize a gain or loss for differences between estimated and actual settlement costs.

The following table reflects the components of the change in Energen’s ARO balance:



(in thousands)
Balance as of December 31, 2014	$	94,060
Liabilities incurred	1,002
Liabilities settled	(712		)
Accretion expense	5,379
Reclassification associated with held for sale properties*	1,052
Balance as of September 30, 2015	$	100,781

*Adjustment to the reclassification of the asset retirement obligation associated with certain San Juan Basin properties included as liabilities related to assets held for sale at December 31, 2014

12. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.



(in thousands)	Pension and Postretirement Plans
Balance as of December 31, 2014	$	(22,870	)
Amounts reclassified from accumulated other comprehensive income (loss)	2,901
Balance as of September 30, 2015	$	(19,969	)

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).



	Three months ended
	September 30,
	2015			2014
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains (losses) on cash flow hedges:
Commodity contracts	$	—		$	5,992		Gain (loss) on derivative instruments, net
Interest rate swap	—			(247		)	Interest expense
Total cash flow hedges	—			5,745
Income tax expense	—			(2,191		)
Net of tax	—			3,554
Pension and postretirement plans:
Transition obligation	—			2			General and administrative
Prior service cost	—			(74		)	General and administrative
Actuarial losses	(730		)	(1,430		)	General and administrative
Total pension and postretirement plans	(730		)	(1,502		)
Income tax expense	256			525
Net of tax	(474		)	(977		)
Total reclassifications for the period	$	(474	)	$	2,577



	Nine months ended
	September 30,
	2015			2014
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains (losses) on cash flow hedges:
Commodity contracts	$	—		$	15,781		Gain (loss) on derivative instruments, net
Interest rate swap	—			(2,280		)	Interest expense
Total cash flow hedges	—			13,501
Income tax expense	—			(5,199		)
Net of tax	—			8,302
Pension and postretirement plans:
Transition obligation	—			(17		)	General and administrative
Prior service cost	—			(222		)	General and administrative
Actuarial losses	(4,462		)	(11,632		)	General and administrative
Total pension and postretirement plans	(4,462		)	(11,871		)
Income tax expense	1,561			4,155
Net of tax	(2,901		)	(7,716		)
Total reclassifications for the period	$	(2,901	)	$	586

13. ASSET IMPAIRMENT

Impairments recognized by Energen are presented below:



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2015		2014		2015		2014
Continuing operations:
Permian Basin oil properties
Central Basin Platform	$	371,593	$	—	$	423,067	$	—
Delaware Basin	18,653		—		22,983		—
Midland Basin	—		25,776		—		25,776
San Juan Basin properties	—		142,172		—		142,172
Permian Basin unproved leasehold properties	9,148		5,231		20,092		7,818
San Juan Basin unproved leasehold properties	—		5,733		248		5,734
Total asset impairments from continuing operations	399,394		178,912		466,390		181,500
Discontinued operations:
North Louisiana/East Texas oil and natural gas properties	—		—		—		1,667
Total asset impairments from discontinued operations	—		—		—		1,667
Total asset impairments	$	399,394	$	178,912	$	466,390	$	183,167

During the three months ended September 30, 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $390.2 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Our commodity price assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price caps, declined by approximately 19 percent for oil and 12 percent for natural gas in comparable periods during the quarter. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million pre-tax, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. For the year-to-date September 30, 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $446.1 million pre-tax. Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement.

Energen recognized unproved leasehold writedowns primarily on Permian properties in the Delaware Basin of $9.1 million pre-tax during the third quarter of 2015 and $20.3 million in the year-to-date. These non-cash writedowns are reflected in asset impairment on the consolidated income statement.

During the third quarter of 2014, Energen recognized a non-cash impairment writedown on certain properties in the Permian Basin of $31 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in anticipation of being designated as held for sale.

During the third quarter of 2014, a non-cash impairment writedown of $147.9 million pre-tax was recognized by Energen on certain gas properties in the San Juan Basin to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows in anticipation of being designated as held for sale. At December 31, 2014, proved reserves associated with Energen’s San Juan Basin properties totaled 69,038 MBOE.

In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown was reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The

impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

14. ACQUISITION AND DISPOSITION OF PROPERTIES

On March 31, 2015, Energen completed the sale of the majority of its natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) to Southland Royalty Company, LLC for an aggregate purchase price of $395 million. The sales proceeds were reduced by purchase price adjustments of approximately $16 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $378 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.1 million on the sale. The purchase price is subject to further purchase price adjustments following closing. Energen used proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE.

Summarized below are the consolidated results of operations for the three months and nine months ended September 30, 2015 and 2014, on an unaudited pro forma basis which gives effect to the sale as if it had occurred at the beginning of the earliest period presented. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above nor are they indicative of results of the future operations of the enterprises.



	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)	2015			2014		2015			2014
Total revenues	$	295,573		$	449,778	$	653,151		$	914,510
Gain (loss) from continuing operations	$	(227,863	)	$	14,188	$	(377,066	)	$	2,268
Net income (loss)	$	(227,863	)	$	450,808	$	(377,066	)	$	471,758
Diluted earnings per average common share from continuing operations	$	(2.89	)	$	0.19	$	(5.02	)	$	0.03
Diluted earnings per average common share	$	(2.89	)	$	6.13	$	(5.02	)	$	6.44
Basic earnings per average common share from continuing operations	$	(2.89	)	$	0.19	$	(5.02	)	$	0.03
Basic earnings per average common share	$	(2.89	)	$	6.17	$	(5.02	)	$	6.47

Energen completed an estimated total of $61.1 million in various purchases of unproved leasehold largely in the Permian Basin during the nine months ended September 30, 2015. During 2014, Energen completed a total of approximately $68.5 million in various purchases of unproved leasehold properties, including the October 2014 purchase of approximately 15,000 net acres of unproved leasehold in the Mancos formation oil play in the San Juan Basin for $22.8 million.

15. DISCONTINUED OPERATIONS AND HELD FOR SALE PROPERTIES

As discussed in Note 14, Acquisition and Disposition of Properties, the following table details held for sale properties by major classes of assets and liabilities:



(in thousands)	December 31, 2014
		San Juan Basin*
Oil and natural gas properties		$	1,166,124
Less accumulated depreciation, depletion and amortization		(770,327		)
Total assets held for sale		395,797
Other long-term liabilities		(24,230		)
Total liabilities held for sale		(24,230		)
Total net assets held for sale		$	371,567

*The San Juan Basin natural gas assets that were held for sale as of December 31, 2014, did not qualify for discontinued operations as we have ongoing operations in the San Juan Basin.

On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion, resulting in a pre-tax gain of $726.5 million. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Energen’s results of operations and cash flows for the three months and nine months ended September 30, 2014 presented in our unaudited consolidated financial statements and these notes reflect Alagasco as discontinued operations.

We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that ended at close of transaction, the related income tax impact of these items and the earnings of Alagasco. In addition, we reclassified from discontinued operations certain general and administrative costs, other income and the related tax impact from these items. The table below provides a detail of these items included in income (loss) from discontinued operations as follows:



(in thousands)	Three months ended September 30, 2014			Nine months ended September 30, 2014
Alagasco net income (loss)	$	(1,767	)	$	40,646
Depreciation, depletion and amortization	(103		)	(408		)
General and administrative	1,710			3,337
Interest expense	(4,329		)	(17,306		)
Other income	—			(347		)
Income tax expense	1,029			5,567
Alagasco income (loss) from discontinued operations	(3,460		)	31,489
Energen income (loss) from discontinued operations	(25		)	(1,054		)
Income (loss) from discontinued operations	$	(3,485	)	$	30,435



(in thousands, except per share data)	Three months ended September 30, 2014			Nine months ended September 30, 2014
Natural gas distribution revenues	$	39,874		$	397,648
Oil and natural gas revenues	6			5,217
Total revenues	$	39,880		$	402,865
Pretax income (loss) from discontinued operations	$	(5,938	)	$	48,581
Income tax expense (benefit)	(2,453		)	18,146
Income (Loss) From Discontinued Operations	$	(3,485	)	$	30,435
Gain on disposal of discontinued operations	$	726,410		$	724,743
Income tax expense	286,305			285,688
Gain on Disposal of Discontinued Operations	$	440,105		$	439,055
Total Income From Discontinued Operations	$	436,620		$	469,490
Diluted Earnings Per Average Common Share
Income (loss) from discontinued operations	$	(0.05	)	$	0.42
Gain on disposal of discontinued operations	5.99			5.99
Total Income From Discontinued Operations	$	5.94		$	6.41
Basic Earnings Per Average Common Share
Income (loss) from discontinued operations	$	(0.05	)	$	0.42
Gain on disposal of discontinued operations	6.03			6.03
Total Income From Discontinued Operations	$	5.98		$	6.45

quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

16. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendment is effective for fiscal years beginning on or after December 15, 2015, and interim periods within those fiscal years. Energen does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. In August 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This update clarifies the guidance regarding line-of-credit arrangements with regards to the recently issued ASU 2015-03. ASU 2015-15 allows entities to defer and present debt issue costs as an asset and subsequently amortize the deferred debt issue costs ratably over the term of the line-of-credit arrangement.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This update is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. Companies may apply this update retrospectively or using a modified retrospective approach to adjust retained earnings. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers, which deferred the effective date of ASU No. 2014-09 to annual periods beginning after December 15, 2017, including interim reporting periods within that reporting period. We are currently evaluating the impact of this guidance on our financial statements.

In April 2014, the FASB issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held for sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment was effective for annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The adoption of this ASU did not have a material impact on the consolidated financial statements of Energen.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW OF BUSINESS

Energen is focused on increasing its oil and natural gas liquids production and proved reserves largely through development well drilling, exploration, and acquisitions of proved and unproved properties in and around our existing assets. All oil, natural gas liquids and natural gas production is sold to third parties. Energen operates properties for its own interest and that of its joint interest owners. This role includes overall project management and day-to-day decision-making relative to project operations.

At December 31, 2014, Energen had approximately 372.7 million barrels of oil equivalent (MMBOE) total proved reserves which included 108.2 MMBOE of proved undeveloped reserves. We had approximately 46.4 MMBOE or 43 percent of our proved undeveloped reserves on leased acreage which is not held by production. The continuous development provisions of these leases extend the primary terms upon the satisfaction of certain conditions. These provisions require at least one well be drilled on such leases prior to the expiration of the primary term and that subsequent wells be drilled within a time period that is specific to each lease but ranges from 60 days to 180 days. Once a lease is developed, it remains in effect as long as production is maintained from the lease. Our drilling plans provided for the development of these proved undeveloped reserves prior to the expiration of the initial primary term or under the extended primary term as provided for under the continuous development provisions of our lease agreements.

FINANCIAL AND OPERATING PERFORMANCE

Overview of Third Quarter and Year-to-Date 2015 Results and Activities

During the three months and nine months ended September 30, 2015 as compared to the same periods in the prior year, we:


•	expanded development and exploratory activities in the Permian Basin increasing production by 922 thousand barrels of oil equivalent (MBOE) or 22.6 percent in the third quarter and 2,508 MBOE or 19.8 percent in the year-to-date;


•	experienced a significant decline in commodity prices;


•	issued 5,700,000 additional shares of common stock through a public equity offering receiving net proceeds of approximately $398.6 million and


•	completed the sale of the majority of our natural gas assets in the San Juan Basin in New Mexico and Colorado for an aggregate purchase price of approximately $395 million on March 31, 2015.

Quarter ended September 30, 2015 vs. quarter ended September 30, 2014

Energen had a net loss of $227.9 million ($2.89 per diluted share) for the three months ended September 30, 2015 as compared with net income of $457.3 million ($6.22 per diluted share) for the same period in the prior year. In the third quarter of 2015, our loss from continuing operations totaled $227.9 million ($2.89 per diluted share) as compared with income from continuing operations of $20.6 million ($0.28 per diluted share) in the same period a year ago. Energen had no discontinued operations in the current quarter. Income from discontinued operations was $436.6 million ($5.94 per diluted share) from the prior-year third quarter largely due to the sale of Alagasco. This change in income (loss) from continuing operations was primarily the result of:


•	lower realized oil, natural gas liquids and natural gas commodity prices (approximately $116.3 million after-tax);


•	year-over-year after-tax $94.9 million loss on open derivatives (resulting from an after-tax $0.8 million non-cash loss on open derivatives for the third quarter of 2015 and an after-tax $94.1 million non-cash gain on open derivatives for the third quarter of 2014);


•	non-cash impairments on certain oil properties primarily in the Central Basin Platform of the Permian Basin (approximately $249.6 million after-tax);


•	decreased natural gas and natural gas liquids production volumes (approximately $20.4 million after-tax);


•	increased depreciation, depletion and amortization (DD&A) expense (approximately $6.8 million after-tax) and


•	additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $5.8 million after-tax)

partially offset by:


•	a non-cash impairment in 2014 on certain gas properties in the San Juan Basin (approximately $94.3 million after-tax);


•	a non-cash impairment in 2014 on certain oil properties in the Permian Basin (approximately $19.8 million after-tax);


•	gain on closed derivatives (approximately $69 million after-tax);


•	increased oil production volumes (approximately $32.8 million after-tax);


•	decreased oil, natural gas liquids and natural gas production expense (approximately $8.4 million after-tax);


•	lower production and ad valorem taxes (approximately $7.9 million after-tax);


•	lower exploration expense (approximately $5.1 million after-tax) and


•	decreased general and administrative (G&A) expense (approximately $2.7 million after-tax).

Nine months ended September 30, 2015 vs. nine months ended September 30, 2014

For the 2015 year-to-date, Energen had a net loss of $354.9 million ($4.72 per diluted share) as compared with net income of $502.6 million ($6.86 per diluted share) for the same period in the prior year. For the nine months ended September 30, 2015, our loss from continuing operations totaled $354.9 million ($4.72 per diluted share) as compared with income from continuing operations of $33.1 million ($0.45 per diluted share) in the same period a year ago. Energen had no discontinued operations in the current year-to-date. Income from discontinued operations was $469.5 million ($6.41 per diluted share) from the prior year-to-date largely due to the sale of Alagasco. This change in income (loss) from continuing operations was primarily the result of:


•	lower realized oil, natural gas liquids and natural gas commodity prices (approximately $355.5 million after-tax);


•	year-over-year after-tax $148.7 million loss on open derivatives (resulting from an after-tax $114.3 million non-cash loss on open derivatives for the first nine months of 2015 and an after-tax $34.5 million non-cash gain on open derivatives for the first nine months of 2014);


•	non-cash impairments on certain oil properties in the Central Basin Platform of the Permian Basin (approximately $285.3 million after-tax);


•	decreased natural gas and natural gas liquids production volumes (approximately $46.4 million after-tax);


•	higher DD&A expense (approximately $22 million after-tax);


•	additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $13 million after-tax) and


•	higher interest expense (approximately $3.7 million after-tax)

partially offset by:


•	gain on closed derivatives (approximately $200 million after-tax);


•	higher oil production volumes (approximately $106.3 million after-tax);


•	a non-cash impairment in 2014 on certain gas properties in the San Juan Basin (approximately $94.3 million after-tax);


•	a non-cash impairment in 2014 on certain oil properties in the Permian Basin (approximately $21.4 million after-tax);


•	gain on sale of the majority of our natural gas assets in the San Juan Basin (approximately $17.3 million after tax);


•	lower production and ad valorem taxes (approximately $22.6 million after-tax);


•	decreased oil, natural gas liquids and natural gas production expense (approximately $15.3 million after-tax) and


•	lower exploration expense (approximately $5.7 million after-tax).

2015 Outlook

2015 Capital Estimate: Energen plans to continue investing significant capital in oil and natural gas production operations. In the 2015 year-to-date, Energen has incurred approximately $891 million on its oil and natural gas capital program and expects the total for 2015 to approximate $1.1 billion, primarily all of which is for existing properties and exploration. Capital expenditures by area and targeted formation during 2015 are planned as follows:



(in thousands)	2015
Permian
Midland Basin
Wolfcamp	$	526,000
Spraberry	173,000
Wolfberry	16,000
Salt water disposal/Facilities	84,000
Non-operated/Other	11,000
Delaware Basin
Bone Spring	17,000
Wolfcamp	69,000
Wolfbone	15,000
Salt water disposal/Facilities	26,000
Non-operated/Other	8,000
Other Permian	6,000
San Juan Basin/Other	60,000
Net Carry-in/Carry Out/Miscellaneous	(9,000		)
Acquisitions/Lease Extensions/Unproved Leasehold	66,000
Total	$	1,068,000

Energen also may allocate additional capital for other oil and natural gas activities such as property acquisitions and additional development of existing properties. Energen may evaluate acquisition opportunities which arise in the marketplace. Energen’s ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included in the aforementioned estimate of oil and natural gas investments and could result in capital expenditures different from those outlined above.

To finance capital spending, Energen expects to use internally generated cash flow supplemented by our existing credit facility. We also used the $378 million ($395 million aggregate purchase price before purchase price adjustments) of pre-tax proceeds from the sale of certain San Juan Basin properties. Energen also may issue long-term debt and additional equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Access to capital is an integral part of Energen’s business plan. While we expect to have ongoing access to our credit facility and long-term capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades.

Results of Operations

The following table summarizes information regarding our production and operating data from continuing operations.



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except sales price and per unit data)	2015			2014			2015			2014
Operating and production data from continuing operations
Oil, natural gas liquids and natural gas sales
Oil	$	160,531		$	260,447		$	491,158		$	776,952
Natural gas liquids	11,001			31,259			36,616			90,625
Natural gas	16,866			59,067			67,736			189,870
Total	$	188,398		$	350,773		$	595,510		$	1,057,447
Open non-cash mark-to-market gains (losses) on derivative instruments
Oil	$	5,760		$	128,346		$	(149,743	)	$	40,710
Natural gas liquids	—			1,276			—			1,603
Natural gas	(6,924		)	17,665			(27,939		)	11,672
Total	$	(1,164	)	$	147,287		$	(177,682	)	$	53,985
Closed gains (losses) on derivative instruments
Oil	$	98,072		$	(6,012	)	$	230,885		$	(46,568	)
Natural gas liquids	—			873			—			1,228
Natural gas	10,265			5,587			37,042			853
Total	$	108,337		$	448		$	267,927		$	(44,487	)
Total revenues	$	295,571		$	498,508		$	685,755		$	1,066,945
Production volumes
Oil (MBbl)	3,610			3,017			10,439			8,601
Natural gas liquids (MMgal)	44.4			46.5			125.5			129.2
Natural gas (MMcf)	7,362			15,156			27,774			43,956
Total production volumes (MBOE)	5,893			6,651			18,055			19,003
Average daily production volumes
Oil (MBbl/d)	39.2			32.8			38.2			31.5
Natural gas liquids (MMgal/d)	0.5			0.5			0.5			0.5
Natural gas (MMcf/d)	80.0			164.7			101.7			161.0
Total average daily production volumes (MBOE/d)	64.1			72.3			66.1			69.6
Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)	$	71.64		$	84.33		$	69.17		$	84.92
Natural gas liquids (per gallon)	$	0.25		$	0.69		$	0.29		$	0.71
Natural gas (per Mcf)	$	3.69		$	4.27		$	3.77		$	4.34
Average realized prices excluding effects of all derivatives instruments
Oil (per barrel)	$	44.47		$	86.33		$	47.05		$	90.33
Natural gas liquids (per gallon)	$	0.25		$	0.67		$	0.29		$	0.70
Natural gas (per Mcf)	$	2.29		$	3.90		$	2.44		$	4.32
Costs per BOE
Oil, natural gas liquids and natural gas production expenses	$	9.26		$	10.18		$	9.74		$	10.52
Production and ad valorem taxes	$	2.27		$	3.87		$	2.54		$	4.27
Depreciation, depletion and amortization	$	25.42		$	20.91		$	24.04		$	21.03
Exploration expense	$	0.08		$	1.27		$	0.68		$	1.12
General and administrative	$	4.01		$	4.18		$	5.23		$	4.92
Net capital expenditures	$	230,900		$	356,725		$	891,491		$	950,993

Revenues: Our revenues fluctuate primarily as a result of realized commodity prices, production volumes and the value of our derivative contracts.

Our revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas. In the third quarter of 2015, commodity sales decreased $162.4 million or 46.3 percent from the same period of 2014. In the nine months ended September 30, 2015, commodity sales decreased $461.9 million or 43.7 percent from the same period of 2014. Particular factors impacting commodity sales include the following:


•	Oil volumes in the third quarter increased 19.7 percent to 3,610 thousand barrels (MBbl) as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the Wolfberry in the Midland Basin, 3rd Bone Spring in the Delaware Basin and the Central Basin Platform. For the year-to-date, oil volumes rose 21.4 percent to 10,439 MBbl.


•	Average realized oil prices fell 48.5 percent to $44.47 per barrel during the three months ended September 30, 2015. Average realized oil prices decreased 47.9 percent to $47.05 per barrel during the nine months ended September 30, 2015.


•	Natural gas liquids production for the current quarter decreased 4.5 percent to 44.4 million gallons (MMgal). For the year-to-date, natural gas liquids production declined 2.9 percent to 125.5 MMgal due to the sale of the majority of our natural gas assets in the San Juan Basin.


•	Average realized natural gas liquids prices decreased 62.7 percent to an average price of $0.25 per gallon during the third quarter of 2015. Average realized natural gas liquids prices decreased 58.6 percent to an average price of $0.29 per gallon during the nine months ended September 30, 2015.


•	Natural gas production decreased 51.4 percent to 7.4 billion cubic feet (Bcf) in the third quarter due to the sale of natural gas assets in the San Juan Basin and normal declines in the San Juan Basin partially offset by accelerated completions and new well performance in the Permian Basin. For the nine months ended September 30, 2015, natural gas production declined 36.8 percent to 27.8 Bcf.


•	Average realized natural gas prices declined 41.3 percent to $2.29 per thousand cubic feet (Mcf) during the three months ended September 30, 2015. For the current year-to-date, average realized natural gas prices fell 43.5 percent to $2.44 per Mcf.

Realized prices exclude the effects of derivative instruments.

Gains on derivative instruments were $107.2 million in the third quarter of 2015 compared to gains of $147.7 million in the same period of 2014. Gains on derivative instruments were $90.2 million in the nine months ended September 30, 2015 compared to gains of $9.5 million in the same period of 2014. Our earnings are significantly affected by the changes of our derivative instruments. Increases or decreases in the expected commodity price outlook generally result in the opposite effect on the fair value of our derivatives. However, these gains and losses are generally expected to be offset by the unhedged price on the related commodities.

Oil, natural gas liquids and natural gas production expense: The following table provides the components of our oil, natural gas liquids and natural gas production expenses:



	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands, except per unit data)	2015		2014		2015		2014
Lease operating expenses	$	33,782	$	35,089	$	108,184	$	100,738
Workover and repair costs	17,571		21,951		51,910		66,736
Marketing and transportation	3,245		10,680		15,839		32,387
Total oil, natural gas liquids and natural gas production expense	$	54,598	$	67,720	$	175,933	$	199,861
Oil, natural gas liquids and natural gas production expense per BOE	$	9.26	$	10.18	$	9.74	$	10.52

Energen had oil, natural gas liquids and natural gas production expense of $54.6 million and $175.9 million during the three months and nine months ended September 30, 2015, respectively, as compared to $67.7 million and $199.9 million during the same periods in 2014. Lease operating expense may be positively or negatively impacted by property acquisitions and dispositions and also generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities. Overall lease operating expense was positively impacted in the current quarter and year-to-date by the sale of the San Juan Basin.

•

Lease operating expense decreased $1.3 million for the quarter largely due to lower other operations and maintenance expense (approximately $2.3 million), decreased electrical costs (approximately $1.4 million) and decreased water disposal costs (approximately $0.8 million) partially offset by higher equipment rental costs (approximately $1.8 million), higher non-operated costs (approximately $0.8 million) and increased gathering costs (approximately $0.7 million). On a per unit basis, the average lease operating expense for the current quarter was $5.72 per barrel of oil equivalent (BOE) as compared to $5.27 per BOE in the same period a year ago.

•

In the year-to-date, lease operating expense increased $7.4 million primarily due to additional equipment rental costs (approximately $4.5 million), higher water disposal costs (approximately $3.6 million), increased non-operated costs (approximately $2.2 million), increased gathering costs (approximately $2 million), higher labor costs (approximately $1.7 million) and higher environmental compliance costs (approximately $1.3 million) partially offset by lower other operations and maintenance expense (approximately $5.4 million) and decreased electrical costs (approximately $3.1 million). For the nine months ended September 30, 2015, the average lease operating expense was $5.98 per BOE as compared to $5.31 per BOE in the previous period.

Workover and repair costs decreased approximately $4.4 million in the three months ended September 30, 2015 and $14.8 million in the year-to-date primarily due to lower incidence of offset well stimulation interference.

In the three months ended September 30, 2015, marketing and transportation costs decreased $7.4 million and $16.5 million year-to-date primarily due to lower natural gas volumes as a result of the sale of certain San Juan Basin natural gas assets.

Production and ad valorem taxes: Production and ad valorem taxes were $13.4 million ($2.27 per BOE) and $45.8 million ($2.54 per BOE), respectively, during the three months and nine months ended September 30, 2015 as compared to $25.7 million ($3.87 per BOE) and $81.1 million ($4.27 per BOE) during the same periods in 2014. In the current quarter, production-related taxes were $10 million lower as decreased commodity market prices contributed approximately $7.7 million and lower net production volumes contributed approximately $2.3 million. In the year-to-date, production-related taxes were $28.5 million lower as decreased commodity market prices contributed approximately $25.5 million and lower net production volumes contributed approximately $3 million. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes. Decreased ad valorem taxes of $2.4 million in the quarter and $6.8 million year-to-date were largely driven by the factor adjusted price impact on our Texas oil and natural gas properties.

Depreciation, depletion and amortization: Energen’s DD&A expense for the quarter rose $10.7 million and $34.4 million year-to-date. The average depletion rate for the current quarter was $25.42 per BOE as compared to $20.91 per BOE in the same period a year ago. For the nine months ended September 30, 2015, the average depletion rate was $24.04 per BOE as compared to $21.03 per BOE in the previous period. The increase in the current quarter and year-to-date per unit depletion rate which contributed approximately $26.2 million and $53 million to the increase in DD&A expense was largely due to higher rates resulting from an increase in development costs. Lower net production volumes reduced DD&A expense approximately $15.7 million and $19.8 million for the quarter and year-to-date, respectively.

Asset impairment: During the three months ended September 30, 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $390.2 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Our commodity price assumptions, which are based on the commodity price curve for five years and then escalated at 3 percent through our assumed price caps, declined by approximately 19 percent for oil and 12 percent for natural gas in comparable periods during the quarter. During the second quarter of 2015, Energen recognized non-cash impairment writedowns on certain properties in the Central Basin Platform of $51.5 million pre-tax, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Estimated future cash flows were revised due to the receipt of an unsolicited offer for these properties. For the year-to-date September 30, 2015, Energen recognized non-cash impairment writedowns on certain properties in the Permian Basin of $446.1 million pre-tax. Non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement.

Energen recognized unproved leasehold writedowns primarily on Permian properties in the Delaware Basin of $9.1 million pre-tax and $20.3 million pre-tax during the third quarter of 2015 and year-to-date, respectively. These non-cash writedowns are reflected in asset impairment on the consolidated income statement.

Exploration: The following table provides a detail of our exploration expense:



	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per unit data)	2015			2014		2015		2014
Geological and geophysical	$	31		$	889	$	4,972	$	2,545
Dry hole costs	469			7,505		6,967		8,791
Delay rentals and other	(7		)	23		335		9,882
Total exploration expense	$	493		$	8,417	$	12,274	$	21,218
Total exploration expense per BOE	$	0.08		$	1.27	$	0.68	$	1.12

Exploration expense decreased $7.9 million in the third quarter of 2015 primarily due to lower dry hole costs and seismic costs. For the nine months ended September 30, 2015, exploration expense decreased $8.9 million largely as a result of lower delay rentals and dry hole costs partially offset by increased seismic costs. Delay rentals are lower in the current year due to the sale of certain San Juan Basin properties.

General and administrative: The following table provides details of our G&A expense:



	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands, except per unit data)	2015		2014		2015		2014
General and administrative	$	3,766	$	6,251	$	22,437	$	23,626
Benefit and performance-based compensation costs	6,369		9,124		32,275		33,197
Labor costs	13,496		12,409		39,626		36,676
Total general and administrative expense	$	23,631	$	27,784	$	94,338	$	93,499
Total general and administrative expense per BOE	$	4.01	$	4.18	$	5.23	$	4.92

Total G&A expense decreased $4.2 million for the three months ended September 30, 2015 largely due to decreased costs from Energen’s benefit and performance-based compensation plans, lower professional services, other G&A expense declines due to operating in a lower commodity price environment and decreased legal expenses partially offset by increased labor costs. G&A expense rose $0.8 million for the year-to-date primarily due to higher legal expenses and increased labor costs partially offset by decreased costs from Energen’s benefit and performance-based compensation plans and other G&A expense declines due to operating in a lower commodity price environment. Included in costs from the benefit and performance-based compensation plans were pension costs of $0.9 million and $5.1 million for the three months and nine months ended September 30, 2015, respectively, as compared to $3.5 million and $13.4 million during the same periods in 2014.

(Gain) loss on sale of assets and other: On March 31, 2015, Energen completed the sale of the majority of our natural gas assets in the San Juan Basin in New Mexico and Colorado (effective as of January 1, 2015) to Southland Royalty Company, LLC for an aggregate purchase price of $395 million. The sales proceeds were reduced by purchase price adjustments of approximately $16 million related to the operations of the San Juan Basin properties subsequent to December 31, 2014 and one-time adjustments related primarily to liabilities assumed by the buyer, which resulted in pre-tax proceeds to Energen of approximately $378 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.1 million on the sale. The purchase price is subject to further purchase price adjustments following closing. Energen used proceeds from the sale to reduce long-term indebtedness. At December 31, 2014, proved reserves associated with these San Juan Basin properties totaled 69,038 MBOE.

Interest expense: Interest expense decreased $1.4 million in the third quarter of 2015 and increased $5.7 million for the nine months ended September 30, 2015. Lower interest in the quarter was primarily due to a prior year write-off of debt issuance costs associated with the $600 million Senior Term Loans. Year-to-date interest expense increased largely due to the classification of interest expense

associated with debt required to be extinguished as discontinued operations in the prior year partially offset by the prior year write-off of debt issuance costs associated with the $600 million Senior Term Loans.

Income tax expense (benefit): Income tax expense decreased $146.4 million for the three months ended September 30, 2015 and $223.6 million for the nine months ended September 30, 2015, as compared to the same periods in the prior year, largely due to lower pre-tax income. Energen’s effective tax rate fluctuates in periods in which significant commodity price volatility impacts the unrealized derivative gains and losses reflected in income from continuing operations. On June 15, 2015, a Texas tax bill was signed into law which reduces the Texas Franchise Tax (Margin Tax) rate from 1 percent to 0.75 percent for taxpayers not engaged in retail or wholesale trade. The tax rate reduction is applicable for tax reports originally due on or after January 1, 2016. Energen recognized a $3.1 million income tax benefit during the second quarter of 2015, the period the law was enacted, to reflect the impact of this change.

Discontinued operations, net of tax: On September 2, 2014, Energen completed the transaction to sell Alagasco to Laclede for $1.6 billion, less the assumption of $267 million in debt. The net pre-tax proceeds to Energen totaled approximately $1.32 billion. This sale had an effective date of August 31, 2014. Energen used cash proceeds from the sale to reduce long-term and short-term indebtedness. During the second quarter of 2014, Energen classified Alagasco as held for sale and reflected the associated operating results in discontinued operations. Our results of operations and cash flows for the three months ended March 31, 2014 and our financial position as of December 31, 2014 presented in our unaudited consolidated financial statements reflect Alagasco as discontinued operations.

In March 2014, Energen completed the sale of its North Louisiana/East Texas primarily natural gas properties for $30.3 million. The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen classified these primarily natural gas properties as held for sale and reflected the associated operating results in discontinued operations. Energen recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91,000 MBbl of oil.

See Note 15, Discontinued Operations and Held for Sale Properties, in the Condensed Notes to Unaudited Consolidated Financial Statements for additional information regarding discontinued operations.

FINANCIAL POSITION AND LIQUIDITY

Cash Flow

The key drivers impacting our cash flow from operations are our oil, natural gas liquids and natural gas production volumes and overall commodity market prices, net of the effects of settlements on our derivative commodity instruments. We rely on our cash flows from operations supplemented by borrowings under our syndicated credit facility to fund our capital spending plans and working capital requirements. We also used the pre-tax proceeds from the sale of certain San Juan Basin properties.

Net cash provided by operating activities: Net cash provided by operating activities for the nine months ended September 30, 2015 was $521.9 million as compared to $709.3 million for the same period of 2014. The year-to-date 2014 included discontinued operations primarily associated with cash flows from Alagasco of $112.2 million. Energen’s working capital was influenced by commodity prices, the timing of payments and recoveries and included pension and postretirement benefit contributions of $10.9 million in the current period.

Net cash provided by (used in) investing activities: Net cash used in investing activities for the nine months ended September 30, 2015 was $630.6 million as compared to net cash provided by investing activities of $345.5 million for the same period of 2014. Energen incurred on a cash basis $1,024 million in capital expenditures including $855 million largely related to the development of oil and natural gas properties, $106 million for payment of accrued capital costs and $63 million primarily related to unproved leasehold acquisitions. Included in the proceeds from the sale of assets are cash proceeds of $384 million from the sale of certain San Juan Basin assets and $8.6 million from the sale of Alagasco.

Net cash provided by (used in) financing activities: Net cash provided by financing activities for the nine months ended September 30, 2015 was $107.5 million as compared to net cash used in financing activities of $1,059.0 million for the same period of 2014. Net cash provided by financing activities in the year-to-date 2015 was primarily due to the issuance of 5,700,000 shares of common stock largely offset by the repayment of credit facility borrowings. Net cash used in financing activities in the year-to-date 2014 was

primarily due to the repayment of the Senior Term Loans, a decrease in credit facility borrowings and discontinued operations primarily related to the sale of Alagasco. For each of the periods, net cash provided by (used in) financing activities also reflected dividends paid to common shareholders and cash received from the issuance of common stock through the Company’s stock-based compensation plan.

Inflation and Changes in Prices

Realized commodity prices and production levels by commodity type are the two primary drivers of our liquidity. Recent price declines in the outlook for oil, natural gas liquids and natural gas indicate a significant risk for lower revenues and related operating cash flows. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile because of supply and demand factors, general economic conditions and seasonal weather patterns. Crude oil prices also are affected by quality differentials, worldwide political developments and actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply and demand factors, including seasonal variations and the availability and price of transportation to consuming areas.

Commodity hedges in place for 2015 and 2016 will help mitigate some of the commodity price volatility and recent declines. We currently have approximately 3,513 MBbl of oil and 7 Bcf of natural gas hedged for the remainder of 2015. In addition we have approximately 1,086 MBbl of oil hedged for 2016. See Item 3, Quantitative and Qualitative Disclosures about Market Risk, for a full detail of our hedged volumes.

Derivative Commodity Instruments

We periodically enter into derivative commodity instruments to hedge our exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

Due to the volatility of commodity prices, the estimated fair value of our derivative instruments is subject to fluctuation from period to period, which could result in significant differences between the current estimated fair value and the ultimate settlement price. Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with twelve of our active counterparties and in a net loss position with the remaining two at September 30, 2015. Energen has policies in place to limit hedging to not more than 80 percent of our estimated annual production; however, Energen’s credit facility contains a covenant which operates to limit hedging at a lower threshold in certain circumstances.

See Note 3, Fair Value Measurements, in the Condensed Notes to Unaudited Consolidated Financial Statements for information regarding our policies on fair value measurement.

Credit Facility and Working Capital

Access to capital is an integral part of Energen’s business plan. While we expect to have ongoing access to our credit facility and long-term capital markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. On September 2, 2014, Energen entered into a five-year syndicated secured credit facility with domestic and foreign lenders. On October 20, 2015, the borrowing base and aggregate commitments were reduced to $1.4 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.4 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the credit facility require Energen to maintain a ratio of total debt to consolidated income before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and other non-cash income and expenses (EBITDAX) less than or equal to 4.0 to 1.0; to maintain a ratio of consolidated current assets (adjusted to include amounts available for borrowings and exclude non-cash derivative instruments) to consolidated current liabilities (adjusted to exclude maturities under the credit facility and non-cash derivative instruments) greater than or equal to 1.0 to 1.0; and, during certain periods, to maintain a ratio of the net present value of proved reserves of our oil and natural gas properties to consolidated total debt greater than or equal to 1.50 to 1.0. We are also bound by covenants which limit our ability to incur additional indebtedness, make certain distributions or alter our corporate structure. Energen may not pay dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility. Our credit facility also limits our ability to enter into commodity hedges based on projected production volumes. In addition, the terms of our credit facility limit the amount we can borrow to a borrowing base amount which is determined by our lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria including commodity price outlook. The borrowing base amount is subject to redetermination semi-annually and for event-driven unscheduled redeterminations. Our next scheduled redetermination is April 1, 2016.

At September 30, 2015, Energen reported negative working capital of $63.9 million arising from current liabilities of $348.5 million exceeding current assets of $284.7 million. Working capital at Energen is influenced by the fair value of derivative financial instruments

associated with future production. Energen has $153.8 million in current assets and $3.1 million in current liabilities, respectively, associated with its derivative instruments at September 30, 2015. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

Equity Offering and Shares Issued

During the second quarter of 2015, Energen issued 5,700,000 additional shares of common stock through a public equity offering. We received net proceeds of approximately $398.6 million, after deducting offering expenses. Net proceeds from this offering were initially used to repay borrowings under our credit facility and for general corporate purposes.

The following table provides a detail of shares issued by Energen:



(in thousands)	September 30, 2015	December 31, 2014
Shares outstanding	78,798	72,973
Treasury stock*	2,970	2,903
Shares issued	81,768	75,876

*Excludes 50,062 shares and 78,254 shares held in the 1997 Deferred Compensation Plan at September 30, 2015 and December 31, 2014, respectively.

Dividends

We expect to pay annual cash dividends of $0.08 per share on Energen common stock in 2015. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors. Energen’s credit facility prohibits payment of dividends during an event of default, if the payment would result in an event of default or if availability is less than 10 percent of the loan limit under the credit facility.

Employee Benefit Plans

In October 2014, Energen’s Board of Directors amended and restated the Employee Saving Plan to make certain benefit design changes effective January 1, 2015. The benefit design changes are expected to include an increase in the percentage of Company match and other contributions.

Stock Repurchase Authorization

From time to time, the Company may repurchase shares of its common stock through open market or negotiated purchases. Such repurchases would be pursuant to a 3.6 million share repurchase authorization approved by the Board of Directors on October 22, 2014. The timing and amounts of any repurchases are subject to changes in market conditions and other business considerations. We would expect to finance any share repurchases under our existing credit facility.

Contractual Cash Obligations

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. There have been no material changes to the contractual cash obligations of the Company since December 31, 2014.

Other Commitments

practices, and to unbundle fees charged by third parties that gather, compress and transport natural gas production. ONRR now maintains that all or some of such fees are not deductible.

Critical Accounting Policies and Estimates

We consider accounting policies related to our accounting for oil and natural gas producing activities and related proved reserves, asset impairments, derivatives, employee benefit plans and asset retirement obligations as critical accounting policies. These policies are summarized in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in our Annual Report on Form 10-K for the year ended December 31, 2014. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used.

Asset Impairments: We monitor the business environment and our oil and natural gas properties for events that could result in a potential impairment. Further, we make assumptions about future expectations in our evaluation of potential impairment. Such assumptions include, but are not necessarily limited to, commodity prices and related basis differentials, transportation costs, inflation assumptions, well and reservoir performance, severance and ad valorem taxes, other operating and future development costs, and general business plans.

Our commodity price assumption is a significant and volatile uncertainty in our estimate, and we are unable to reliably forecast future commodity prices. Our assumption is therefore based on the commodity price curve for the next five years and then escalated at 3 percent through our assumed price caps. Our other assumptions generally have less volatility than the price assumption with variances tending to be field specific and more localized in effect. However, these assumptions can also be impacted by a higher or lower inflationary environment, limitations on takeaway capacity, well and reservoir performance over time, changes to governmental taxation, or changes to cost assumptions, operational and development plans, or the general economic or business environment.

Certain impairments were recognized during the quarter as discussed under Asset Impairments in our Results of Operations. A further decline in our price assumptions by 10 percent (assuming all other assumptions are held constant) would result in approximately $32 million of incremental expense for properties impaired at September 30, 2015. No additional properties were impaired due to the assumed price declines. Other assumptions such as operating costs, transportation costs, well and reservoir performance, severance and ad valorem taxes, operating and development plans may also change given an assumed 10 percent commodity price decline. However, we are unable to estimate their correlation to the price change and these other assumptions may worsen or partially mitigate some of the estimated impairment.

Recent Accounting Standards Updates

See Note 16, Recently Issued Accounting Standards, in the Condensed Notes to Unaudited Consolidated Financial Statements for information regarding recently issued accounting standards.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS AND RISK FACTORS

All statements, other than statements of historical fact, appearing in this report constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and are included in Energen’s disclosure and analysis as permitted by the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among other things, statements about our expectations, beliefs, intentions or business strategies for the future, statements concerning our outlook with regard to timing and amount of future production of oil, natural gas liquids and natural gas, price realizations, nature and timing of capital expenditures for exploration and development, plans for funding operations and drilling program capital expenditures, timing and success of specific projects, operating costs and other expenses, proved oil and natural gas reserves, liquidity and capital resources, outcomes and effects of litigation, claims and disputes and derivative activities. In particular, forward-looking statements may include words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “forecast”, “foresee”, “intend”, “may”, “plan”, “potential”, “predict”, “project”, “seek”, “will” or other words

or expressions concerning matters that are not historical facts. These statements involve certain risks and uncertainties that may cause actual results to differ materially from expectations as of the date of this filing.

The future success and continued viability of our business, like any venture, is subject to many recognized and unrecognized risks and uncertainties. Such risks and uncertainties could cause actual results to differ materially from those contained in forward-looking statements made in this report and presented elsewhere by management. The following list identifies and briefly summarizes certain risk factors. The list should not be viewed as complete or comprehensive, as the risks below are not the only risks facing Energen. Energen could also be affected by additional risks and uncertainties we currently deem to be immaterial or risks that are currently not known or have yet to be identified by us. If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected; and such events could impair our ability to implement business plans or complete development activities as scheduled. In such a case, the trading price of our shares could decline; and shareholders could lose part or all of their investment.

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. We base our forward-looking statements on information currently available to us, and we undertake no obligation to correct or update these statements whether as a result of new information, future events or otherwise.

Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect our financial results and operations.

Our business is significantly impacted by commodity prices, and historical markets for oil, natural gas liquids and natural gas have been volatile. Energen’s revenues, operating results, profitability and cash flows depend primarily upon the prices realized for our oil, natural gas liquids and natural gas production.

We have more oil proved reserves than natural gas proved reserves, so oil prices are more likely to have an impact on our business than natural gas prices. Approximately 59.4 percent of our September 30, 2015 proved reserves are oil. Commodity prices for oil, natural gas liquids and natural gas are reflections of supply and demand and are subject to many factors that are beyond our control, including:


•	the domestic and foreign supply of oil, natural gas liquids and natural gas, including the ability of the members of the Organization of the Petroleum Exporting Countries and other exporting countries to agree on and maintain oil price and production controls;


•	the level of consumer demand for oil, natural gas liquids and natural gas;


•	global oil and natural gas inventory levels;


•	the availability, proximity and capacity of transportation facilities and processing facilities;


•	worldwide economic conditions;


•	commodity price disparities between delivery points and applicable index prices;


•	the supply, demand and pricing of alternative sources of energy or fuels and the effects of energy conservation efforts or technological advances in energy consumption;


•	weather conditions;


•	changes in political conditions in major oil and natural gas producing regions and


•	domestic, local and foreign governmental regulations and taxes.

Substantial reductions in oil, natural gas liquids and natural gas prices would reduce our revenue and cash flows and potentially reduce the amount of oil and natural gas that we can economically produce resulting in a reduction in the proved oil and natural gas reserves we could recognize. Thus, significant and sustained commodity price reductions could materially and adversely affect our financial condition and results of operations which could impact our ability to maintain or increase our current levels of borrowing, our ability to repay current or future indebtedness, our ability to refinance our current indebtedness or obtain additional capital on attractive terms.

Our oil and natural gas proved reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by our inability to invest in production on planned timelines.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures. Reserve estimation is a subjective process involving the estimation of volumes to be recovered from underground accumulations of oil and natural gas that are unable to be measured in an exact manner. The reserve estimation process is dependent upon and subject to multiple variables and assumptions, including:


•	oil, natural gas liquids and natural gas prices;


•	timing of development expenditures;


•	the quality, quantity and interpretation of available geological, geophysical and engineering data;


•	the geologic characteristics of the reservoirs;


•	future operating costs, property, severance, excise and other taxes and costs and


•	the effects of compliance with regulatory and contractual requirements.

Additionally, in the event we are unable to fully invest or must alter the timing of our planned investment expenditures, our future revenues, production and proved reserves could be negatively affected.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could impact our expenses or our production volumes.

Drilling involves many risks, including the risk that no commercially productive oil or natural gas reservoirs will be located or economically developed. Our future drilling activities may not be successful and, if unsuccessful, such failure could have a material adverse effect on our future results of operations and financial condition. Anticipated drilling plans and capital expenditures may also be delayed, curtailed or canceled which could result in actual drilling and capital expenditures being substantially different than currently planned, due to:


•	delays resulting from compliance with regulatory or contractual requirements, which may include limitations on hydraulic

fracturing or the emission of greenhouse gases;


•	unexpected or unusual pressure or irregularities in geological formations;


•	unexpected drilling conditions;


•	declines in oil, natural gas liquids or natural gas prices;


•	adverse weather conditions, such as tornadoes, snow and ice storms;


•	delays in, limited availability of, or cost to obtain personnel and equipment necessary to complete our drilling,

completion and operating activities;


•	equipment or facility failures and accidents or malfunctions resulting in blowouts, fires, explosions, uncontrollable flows of oil, natural gas or well fluids, surface cratering and other events;


•	title related issues;


•	fracture stimulation failures;


•	restricted access to land for drilling;


•	reductions in availability of financing at acceptable rates;


•	strategic changes implemented by management and


•	limitations in the market for oil, natural gas and natural gas liquids.

While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involve greater risks of dry holes or failure to find and exploit commercially productive quantities of oil and natural gas. We expect to continue to experience exploration and abandonment expense in 2015 and future years.

Our concentration of producing properties in the Permian Basin of west Texas and the San Juan Basin of New Mexico makes us vulnerable to risks associated with operating in limited geographic areas.

At September 30, 2015, approximately 93 percent and 7 percent of our total estimated proved reserves were attributable to properties located in the Permian Basin of west Texas and San Juan Basin of New Mexico, respectively. As a result of this geographic concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by:


•	governmental regulation;


•	state politics;


•	processing or transportation capacity constraints;


•	market limitations;


•	water shortages, including restrictions on water usage or other drought related conditions or


•	interruption of the processing or transportation of oil, natural gas liquids or natural gas.

Our industry is highly competitive which makes it challenging for us to acquire properties to replace our proved oil and natural gas reserves, market oil and natural gas and locate and secure qualified personnel.

We operate in a highly competitive environment for acquiring properties to replace our proved oil and natural gas reserves, marketing oil and natural gas and locating and securing qualified personnel. Many of our current and potential competitors possess greater financial, technical and personnel resources than we do. Those competitors may be willing to pay more for exploratory prospects and productive oil and natural gas properties, as well as for trained personnel. Our ability to acquire properties and to find and develop proved reserves in the future will depend on our ability to evaluate and select suitable properties and to execute transactions in an intensely competitive environment. Our failure to acquire properties, market oil and natural gas and secure trained personnel could have a material adverse effect on our production, revenues and results of operations.

Our business is capital intensive, and we may not be able to obtain the needed capital, financing, or to refinance our current indebtedness on satisfactory terms or at all.

Our exploration, development and acquisition activities are capital intensive and constitute the primary use of our capital resources. We make and expect to continue to make significant capital expenditures for the exploration, development and acquisition of oil, natural gas liquids and natural gas reserves. We have historically funded our capital expenditures through cash flows from operations, our credit facility and other borrowings.

If our borrowing capacity decreases, for any reason, we may have limited ability to obtain the capital necessary to support our future operations. If we are unable to obtain necessary financing with appropriate terms, we could experience a decline in our operations. Specifically, a failure to secure additional financing, or necessary refinancing, could result in a reduction of our operations relating to the development of future prospects, which in turn could lead to a decline in our proved oil and natural gas reserves and could adversely affect our future production, revenues and results of operations. The borrowing base of our credit facility is subject to periodic redetermination and is based in part on oil and natural gas prices. A lowering of our borrowing base because of lower oil and natural gas prices or for other reasons could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral.

The nature of our operations involves many operational risks including the risk of personal injury, property damage and environmental damage, and our insurance policies do not cover all such risks.

Inherent in our oil and natural gas production activities are a variety of hazards and operational risks, including, but not limited to:


•	pipeline and storage leaks, ruptures and spills;


•	equipment malfunctions and mechanical failures;


•	fires and explosions;


•	well blowouts, explosions and cratering;


•	uncontrollable flows of oil, natural gas or well fluids;


•	vandalism;


•	pollution;


•	releases of toxic gases;


•	adverse weather conditions or natural disasters and


•	soil, surface and water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to or destruction of property, environmental pollution or other damage, impairment or suspension of our operations, repair and remediation costs, regulatory investigations and penalties or lawsuits and other substantial financial losses. Furthermore, our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including those noted above. Additionally, the location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks and losses; and the insurance coverages are subject to retention levels and coverage limits. We may elect not to obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Furthermore, we could be subject to the credit risk of our insurers if we make a claim under our insurance policies. There is no guarantee that we will be able to obtain or maintain our insurance in the future at rates we deem economical and that the

insurance we may desire will be offered by insurers. Losses and liabilities arising from uninsured or under-insured events or insurer insolvency, in the event of a claim, could materially and adversely affect our business, financial condition or results of operations.

We are subject to extensive regulation, including numerous federal, state and local laws and regulations as well as legislation and regulations restricting the emissions of “greenhouse gases” that may require significant expenditures or impose significant restrictions on our operations.

We are subject to extensive federal, state and local regulation which significantly influences our operations. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject us to significant tax or increased expenditures and can impose significant restrictions and limitations on our operations. Noncompliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities. Furthermore, we may incur significant costs to remain in compliance with or to return to compliance with applicable regulations if they are revised or reinterpreted or if governmental policies or laws change related to our operations.

The subject of climate change is receiving increasing attention from many parties including legislators and governmental agencies. Debate over whether the climate is changing, possible causes and other possible impacts has been ongoing for several years.

If additional legislation or regulatory programs to reduce emissions of greenhouse gases are adopted, it could require us to incur increased operating costs, such as those for purchasing and operating emissions control systems, acquiring emissions allowances or complying with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming and using oil and natural gas, and thereby negatively impact the demand for the oil, natural gas liquids and natural gas we produce. Consequently, legislation and regulatory programs related to greenhouse gases could adversely affect our production, revenues and results of operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.

Energen regularly utilizes hydraulic fracturing in its drilling and completion activities, and hydraulic fracturing is a common practice that is used in the oil and gas industry to stimulate production of hydrocarbons from tight (low permeability) formations. After a well has been drilled, hydraulic fracturing is used during the completion process to form small fractures in the target formation through which the oil, natural gas liquids or natural gas can flow. The fractures are created when a water-based fluid is pumped at a calculated rate and pressure into the crude oil- or natural gas-bearing rock. The fracture fluid is a mixture composed primarily of water and sand or inert ceramic, sand-like grains; it also contains a small percentage of special purpose chemical additives (which are highly diluted-typically less than one percent by volume) that can vary by project. The millimeter-thick cracks or fractures in the target formation are propped open by the sand, thereby allowing the crude oil or natural gas to flow from tight reservoirs into the well bore.

The hydraulic fracturing process is typically regulated by state oil and gas commissions. However, under the Safe Drinking Water Act’s Underground Injection Control Program, the EPA has assumed regulatory authority of hydraulic fracturing involving diesel additives and issued revised permitting guidance in February 2014 requiring facilities to obtain permits to use diesel additives in hydraulic fracturing activities. Legislation intended to provide for federal regulation of hydraulic fracturing and require disclosure of the chemicals used has been introduced and considered by the U.S. Congress. In addition, Texas and New Mexico, two states in which we operate, have adopted, and other states are considering adopting, regulations that could impose new or stricter permitting, disclosure and well construction requirements on companies that perform hydraulic fracturing. Consideration and efforts to regulate hydraulic fracturing by local, state and federal authorities are increasing; and local land use restrictions, such as county and city ordinances, may restrict or prohibit any type of drilling or hydraulic fracturing. If additional federal, state or local restrictions are adopted in the areas we operate or plan to operate, we may incur significant costs to comply with the requirements, experience delays or have to curtail our exploration, development, or production activities. Additionally, such restrictions could reduce the amount of oil and gas that we are able to recover from our proved reserves.

Our operations are dependent on the availability, use and disposal of water; and restrictions on our ability to acquire or dispose of water could cause us to incur substantial costs in the acquisition, usage and disposal of water.

Water is a key component of both the drilling and hydraulic fracturing processes. Historically, we have been able to obtain water from various local sources for use in our operations. Texas is experiencing severe drought conditions that have persisted for the last several years. Several local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply during the drought conditions. If we are unable to obtain water to use in our operations from local sources, we may have to incur substantial costs to produce oil and natural gas and it may make it uneconomical

to produce in that area. Our drilling procedures produce water of which we must dispose. We could be unable to dispose of our wastewater or face increased costs and procedures for disposal as a result of changes in federal or local legislation governing the disposal of drilling wastewater.

We periodically evaluate our proved and unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges in our statements of income in future periods. If commodity prices for oil, natural gas liquids or natural gas decline or our drilling efforts are unsuccessful, we may be required to writedown the carrying values of certain oil and natural gas properties.

We periodically review the carrying value of our proved and unproved oil and natural gas properties for possible impairment on a field-by-field basis. We monitor our oil and natural gas properties as well as the market and business environments in which we operate and make assessments about events that could result in potential impairment issues, which include, but are not limited to, downward commodity price trends, unanticipated increased operating costs and lower than expected production performance. If a material event occurs, we perform an evaluation to determine whether the asset is impaired. If the quantity of potential reserves determined by such evaluations is insufficient to fully recover the cost invested in the respective project, we will record an impairment loss in our statements of income.

We are exposed to counterparty credit risk as a result of our concentrated customer base.

Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil, natural gas liquids and natural gas to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect our overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. We consider the credit quality of our customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent company guarantee.

We are subject to financing and interest rate exposure risks. Volatility in global financial markets, negative operating results, certain strategic business decisions, or other matters resulting in a downgrade in, or a negative outlook with respect to, our credit ratings could negatively impact our cost of and our ability to access capital for future development and working capital needs.

We rely on access to credit markets, and turmoil or volatility in the global financial markets could lead to a contraction in credit availability and negatively impact our ability to finance our operations. Global financial market turmoil, as has been experienced in last decade, could materially affect our operations, liquidity and financial condition through the adverse impacts such turmoil can have on the debt and equity capital markets. Market volatility and credit market disruption may severely limit credit availability, and issuer credit ratings can change rapidly. A significant reduction in cash flows from operations or the availability of credit could limit our ability to pursue acquisition opportunities or reduce cash flow used for drilling which could materially and adversely affect our ability to achieve our planned growth and operating results.

The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders and Energen. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition transactions involving Energen may negatively impact market and rating agency considerations regarding the credit of Energen, and management periodically considers these types of transactions.

Our derivative risk management activities may limit our potential gains and involve other risks that could result in financial losses.

Although we make use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, natural gas liquids and natural gas prices could materially affect our financial position, results of operations and cash flows. Furthermore, such risk mitigation activities may cause our financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not been implemented. The changes in the fair market value of our derivative contracts as reported in our consolidated statements of income may result in significant non-cash gains or losses.

The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality and that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave us financially exposed to our counterparties and result in material adverse financial consequences

to Energen. The adverse effect could be increased if the adverse event was widespread enough to move market prices against our position.

Derivatives reform legislation which has been adopted by the U.S. Congress, or additions to or changes in the legislation, could negatively impact our ability to use derivative instruments as part of our risk management activities.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the SEC to promulgate implementing rules and regulations. These rules and regulations will cover, among other transactions, transactions linked to crude oil and natural gas prices. We believe Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require Energen, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we believe we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as dealers, may change the cost and availability of our future derivative arrangements. The changes in the regulation of swaps may result in certain market participants deciding to curtail or stop engaging in derivative activities. If we reduce our use of derivatives as a result of the Dodd Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations.

Our operations depend on the use of third-party facilities, and an interruption of our ability to utilize these facilities may adversely affect our financial condition and results of operations.

Energen delivers to third-party facilities. These facilities include third-party oil and natural gas gathering, transportation, processing and storage facilities. Energen relies on such facilities for access to market for our oil, natural gas liquids and natural gas production. Such facilities are typically limited in number and geographically concentrated. A lack of available capacity on these facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties for Energen. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act, maintenance or otherwise could have an adverse effect on our revenues and results of operations.

The success of our future operations is dependent on our future drilling activities and our ability to economically develop our oil, natural gas liquids and natural gas reserves; and our expectations regarding future drilling and development activities are subject to uncertainties that could significantly alter the occurrence or timing of such activities, as they are expected to be realized over multiple years.

We have identified drilling locations and prospects for future drilling, including development and exploratory drilling activities. Our ability to successfully and economically drill and develop these locations depends on a number of factors, including:


•	prices of oil, natural gas liquids and natural gas;


•	current laws or regulations or changes in the laws or regulations in the identified and prospective locations;


•	the availability and cost of capital;


•	seasonal and other weather conditions;


•	regulatory approvals;


•	negotiation of agreements with third parties;


•	access to and availability of required equipment, supplies and personnel and


•	drilling results.

Because of the factors noted above, we cannot provide any guarantee regarding the timing or success of future drilling activities; and our actual drilling activities may materially differ from our current expectations.

Energen has limited control over activities on properties which we do not operate, which could materially reduce our production and revenues.

Energen operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. For properties we do not operate, we have limited ability to control the operation or future development of the properties or the amount of capital expenditures that we are required to fund with respect to them. An operator’s failure to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in our best interest could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others is dependent on a number of factors, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to control the operation and future development of these properties could negatively affect the realization of our expected returns on capital in drilling or acquisition activities and could lead to unexpected costs in the future.

Our business could be negatively impacted by security threats, including cybersecurity threats and related disruptions.

We face a variety of security threats, including cybersecurity threats to access sensitive information or render data or systems unusable, threats to the security of our facilities and infrastructure or those of third parties, including processing plants and pipelines, and threats from terrorist acts. Current procedures and controls may not be sufficient to prevent security breaches from occurring, and we could have to implement additional procedures and controls to mitigate the effects of potential breaches and monitor for potential security threats resulting in increased capital and operating costs. In the event of a security breach, losses of sensitive information, critical infrastructure or capabilities essential to our operations could occur and could have a material adverse effect on our reputation, operations, financial position and results of operations. Cybersecurity attacks are becoming more sophisticated and prevalent and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, other electronic security breaches that could cause disruptions in critical systems, unauthorized release of confidential information and data corruption. Furthermore, some experts claim that cybersecurity attacks have become a weapon of war and espionage. As we rely on our information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of our business and day-to-day operations, such attacks could lead to a material disruption in our business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, financial losses, loss of business, potential liability and damage our reputation.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in our Annual Report on Form 10-K for the year ended December 31, 2014, and the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2014.

We are exposed to various market risks including commodity price risk, counterparty credit risk and interest rate risk. We seek to manage these risks through our risk management program which often includes the use of derivative instruments. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Commodity price risk: Energen’s major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil, natural gas liquids and natural gas production have been volatile due to seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of the Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas. See Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, for information regarding the changes in average realized commodity prices.

As of September 30, 2015, Energen had entered into the following transactions for the remainder of 2015 and subsequent years:



Production Period	Total Hedged Volumes		Average Contract Price	Description	Fair Value (in thousands)
Oil
2015	3,513	MBbl	$78.28 Bbl	NYMEX Swaps	$	114,076
2016	1,086	MBbl	$63.80 Bbl	NYMEX Swaps	15,693
Oil Basis Differential
2015	1,890	MBbl	$(4.55) Bbl	WTI/WTI Basis Swaps	(9,731		)
2015	540	MBbl	$(4.30) Bbl	WTS/WTI Basis Swaps	(2,762		)
2016	7,524	MBbl	$(1.92) Bbl	WTI/WTI Basis Swaps	(13,297		)
2016	2,117	MBbl	$(1.63) Bbl	WTS/WTI Basis Swaps	(3,427		)
Natural Gas
2015	5.5	Bcf	$4.14 Mcf	Basin Specific Swaps - San Juan	9,018
2015	1.5	Bcf	$4.20 Mcf	Basin Specific Swaps - Permian	2,568
September 2015 contracts (closed but not cash settled)					38,192
Total					$	150,330
WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

Realized prices are anticipated to be lower than New York Mercantile Exchange prices primarily due to basis differences and other factors. See Note 3, Fair Value Measurements, in the Condensed Notes to Unaudited Consolidated Financial Statements for a summary of changes in the fair value of Energen’s Level 3 derivative commodity instruments.

Additionally, we have entered into certain sales volume and supply target arrangements with certain customers. A failure to meet sales volume targets at Energen due to miscalculations, weather events, natural disasters, accidents, mechanical failures, criminal acts or otherwise could leave us exposed to our counterparties in commodity hedging contracts and result in material adverse financial losses.

Counterparty credit risk: Our principal exposure to credit risk is through the sale of our oil, natural gas liquids and natural gas production, which we market to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect our overall exposure to credit risk. We consider the credit quality of our purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

We are also at risk for economic loss based upon the credit worthiness of our derivative instrument counterparties. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by Energen. All hedge transactions are subject to Energen’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. Energen formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge.

Interest rate risk: Our interest rate exposure as of September 30, 2015 primarily relates to our syndicated credit facility with variable interest rates. At September 30, 2015, we had interest rate swap agreements with a notional value of $83.3 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 1.0425 percent. The fair value of our interest rate swaps was a $0.4 million liability at September 30, 2015. The weighted average interest rate for amounts outstanding at September 30, 2015 was 1.46 percent. All long-term debt obligations, other than our credit facility, were at fixed rates at September 30, 2015.

ITEM 4. CONTROLS AND PROCEDURES

(a)

Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.


(b)	Our chief executive officer and chief financial officer have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Various pending or threatened legal proceedings are in progress currently. See Note 9, Commitments and Contingencies, in the Condensed Notes to Unaudited Consolidated Financial Statements for further discussion with respect to legal proceedings.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS



Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans**
July 1, 2015 - July 31, 2015	—		$	—	—	3,373,161
August 1, 2015 - August 31, 2015	—		—		—	3,373,161
September 1, 2015 - September 30, 2015	448	*	50.32		—	3,373,161
Total	448		$	50.32	—	3,373,161

*Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.

**By resolution adopted October 22, 2014, the Board of Directors authorized Energen to repurchase up to 3.6 million shares of Energen common stock. The resolution does not have an expiration date and does not limit Energen’s authorization to acquire shares in connection with tax withholdings and payment of exercise price on stock compensation plans.

ITEM 6. EXHIBITS



*10	-	Third Amendment to the Credit Agreement, dated as of October 20, 2015, by and among Energen Corporation, as borrower, Wells Fargo Bank, National Association, as administrative agent, Energen Resources Corporation, as guarantor, and the institutions named therein as lenders which was filed as Exhibit 10.1 to Energen’s Current Report on Form 8-K, dated October 20, 2015.
31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
101	-	The financial statements and notes thereto from Energen Corporation’s Quarterly Report on Form 10-Q for the quarter
		ended September 30, 2015 are formatted in XBRL

*Incorporated by reference

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.



		ENERGEN CORPORATION

November 6, 2015	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation


November 6, 2015	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation


November 6, 2015	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation

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