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EX-32 - ENERGEN CORPORATION 18 U.S.C. SECTION 1350 CERTIFICATION - ENERGEN CORPegn63015ex32.htm
EX-31.A - ENERGEN CORPORATION CERTIFICATION OF CEO - ENERGEN CORPegn63015ex31a.htm
EX-31.B - ENERGEN CORPORATION CERTIFICATION OF CFO - ENERGEN CORPegn63015ex31b.htm
XML - IDEA: XBRL DOCUMENT - ENERGEN CORPR9999.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 JUNE 30, 2015
OR
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 July 31, 2015.
Energen Corporation
 
 $0.01 par value
 
78,798,438

 
 
 
 
 




ENERGEN CORPORATION
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2015

TABLE OF CONTENTS









2



PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

ENERGEN CORPORATION
 
 
CONSOLIDATED BALANCE SHEETS
 
 
(Unaudited)
 
 
 
 
 
(in thousands)
June 30, 2015
December 31, 2014

ASSETS
 
 
Current Assets
 
 
Cash and cash equivalents
$
1,510

$
1,852

Accounts receivable, net of allowance for doubtful accounts of $742 and $688 at June 30, 2015 and December 31, 2014, respectively
128,564

157,678

Inventories
17,988

14,251

Assets held for sale

395,797

Derivative instruments
147,789

322,337

Prepayments and other
22,419

27,445

Total current assets
318,270

919,360

Property, Plant and Equipment
 
 
Oil and natural gas properties, successful efforts method
 
 
Proved properties
7,537,545

6,903,514

Unproved properties
168,289

142,340

Less accumulated depreciation, depletion and amortization
2,212,325

1,893,106

Oil and natural gas properties, net
5,493,509

5,152,748

Other property and equipment, net
46,773

46,389

Total property, plant and equipment, net
5,540,282

5,199,137

Other assets
14,094

19,761

TOTAL ASSETS
$
5,872,646

$
6,138,258


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










3



ENERGEN CORPORATION
 
 
CONSOLIDATED BALANCE SHEETS
 
 
(Unaudited)
 
 
 
 
 
(in thousands, except share and per share data)
June 30, 2015
December 31, 2014

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
Current Liabilities
 
 
Accounts payable
$
94,953

$
101,453

Accrued taxes
14,055

5,530

Accrued wages and benefits
22,217

21,553

Accrued capital costs
110,485

207,461

Revenue and royalty payable
62,179

72,047

Liabilities related to assets held for sale

24,230

Pension liabilities
29,616

24,609

Deferred income taxes
11,970

79,164

Derivative instruments
10,220

988

Other
23,220

23,288

Total current liabilities
378,915

560,323

Long-term debt
686,575

1,038,563

Asset retirement obligations
99,049

94,060

Pension and other postretirement liabilities
634

15,935

Deferred income taxes
1,001,251

1,000,486

Noncurrent derivative instruments
3,902


Other long-term liabilities
12,272

14,287

Total liabilities
2,182,598

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; 81,767,121 shares and 75,875,711 shares issued at June 30, 2015 and December 31, 2014, respectively
818

759

Premium on capital stock
971,737

564,438

Retained earnings
2,867,877

2,997,821

Accumulated other comprehensive income (loss), net of tax
 
 
Pension and postretirement plans
(20,443
)
(22,870
)
Deferred compensation plan
1,921

2,862

Treasury stock, at cost; 3,019,245 shares and 2,980,598 shares at June 30, 2015 and December 31, 2014, respectively
(131,862
)
(128,406
)
Total shareholders’ equity
3,690,048

3,414,604

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
5,872,646

$
6,138,258


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

4



ENERGEN CORPORATION
 
 
 
 
CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
(Unaudited)
 
 
 
 
 
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands, except per share data)
2015
2014
 
2015
2014
Revenues
 
 
 
 
 
Oil, natural gas liquids and natural gas sales
$
219,290

$
355,852

 
$
407,112

$
706,674

Loss on derivative instruments, net
(50,964
)
(84,846
)
 
(16,928
)
(138,237
)
Total revenues
168,326

271,006

 
390,184

568,437

Operating Costs and Expenses
 
 
 
 
 
Oil, natural gas liquids and natural gas production
53,581

64,697

 
121,335

132,141

Production and ad valorem taxes
13,352

28,049

 
32,417

55,373

Depreciation, depletion and amortization
149,843

136,244

 
284,224

260,464

Asset impairment
60,413

1,342

 
66,996

2,588

Exploration
11,018

1,233

 
11,781

12,801

General and administrative
38,652

33,542

 
70,707

65,715

Accretion of discount on asset retirement obligations
1,669

1,883

 
3,679

3,726

(Gain) loss on sale of assets and other
1,476

909

 
(26,868
)
1,062

Total costs and expenses
330,004

267,899

 
564,271

533,870

Operating Income (Loss)
(161,678
)
3,107

 
(174,087
)
34,567

Other Income (Expense)
 
 
 
 
 
Interest expense
(11,244
)
(7,964
)
 
(23,002
)
(15,852
)
Other income
41

687

 
87

1,010

Total other expense
(11,203
)
(7,277
)
 
(22,915
)
(14,842
)
Income (Loss) From Continuing Operations Before Income Taxes
(172,881
)
(4,170
)
 
(197,002
)
19,725

Income tax expense (benefit)
(61,280
)
(1,016
)
 
(69,981
)
7,232

Income (Loss) From Continuing Operations
(111,601
)
(3,154
)
 
(127,021
)
12,493

Discontinued Operations, net of tax
 
 
 
 
 
Income (loss) from discontinued operations

(4,799
)
 

33,920

Loss on disposal of discontinued operations


 

(1,050
)
Income (Loss) From Discontinued Operations

(4,799
)
 

32,870

Net Income (Loss)
$
(111,601
)
$
(7,953
)
 
$
(127,021
)
$
45,363

 
 
 
 
 
 
Diluted Earnings Per Average Common Share
 
 
 
 
 
Continuing operations
$
(1.52
)
$
(0.04
)
 
$
(1.74
)
$
0.17

Discontinued operations

(0.07
)
 

0.45

Net Income (Loss)
$
(1.52
)
$
(0.11
)
 
$
(1.74
)
$
0.62

Basic Earnings Per Average Common Share
 
 
 
 
 
Continuing operations
$
(1.52
)
$
(0.04
)
 
$
(1.74
)
$
0.17

Discontinued operations

(0.07
)
 

0.45

Net Income (Loss)
$
(1.52
)
$
(0.11
)
 
$
(1.74
)
$
0.62

Dividends Per Common Share
$
0.02

$
0.15

 
$
0.04

$
0.30

Diluted Average Common Shares Outstanding
73,452

72,851

 
73,143

73,031

Basic Average Common Shares Outstanding
73,452

72,851

 
73,143

72,737


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

5



ENERGEN CORPORATION
 
 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
(Unaudited)
 
 
 
 
 
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands)
2015
2014
 
2015
2014
Net Income (Loss)
$
(111,601
)
$
(7,953
)
 
$
(127,021
)
$
45,363

Other comprehensive income (loss):
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
Current period change in fair value of derivative commodity instruments, net of tax of $0, $6, $0 and $7, respectively

9

 

11

Reclassification adjustment for derivative commodity instruments, net of tax of $0, ($2,179), $0 and ($3,720), respectively

(3,556
)
 

(6,069
)
Current period change in fair value of interest rate swap, net of tax of $0, ($98), $0 and ($160), respectively

(183
)
 

(298
)
Reclassification adjustment for interest rate swap, net of tax of $0, $556, $0 and $712, respectively

1,032

 

1,321

Total cash flow hedges

(2,698
)
 

(5,035
)
Pension and postretirement plans:
 
 
 
 
 
Amortization of net benefit obligation at transition, net of tax of $0, $3, $0 and $7, respectively

6

 

12

Amortization of prior service cost, net of tax of $0, $26, $0 and $52, respectively

48

 

96

Amortization of net loss, including settlement charges, net of tax of $309, $577, $1,305 and $3,571, respectively
576

1,072

 
2,427

6,631

Current period change in fair value of pension and postretirement plans, net of tax of $0, ($1,151), $0 and ($1,151), respectively

(2,136
)
 

(2,136
)
Total pension and postretirement plans
576

(1,010
)
 
2,427

4,603

Comprehensive Income (Loss)
$
(111,025
)
$
(11,661
)
 
$
(124,594
)
$
44,931


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


6



ENERGEN CORPORATION
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
(Unaudited)
 
 
 
 
 
Six months ended June 30, (in thousands)
2015
2014
Operating Activities
 
 
Net income (loss)
$
(127,021
)
$
45,363

Income from discontinued operations

(32,870
)
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
284,224

260,464

Asset impairment
66,996

2,588

Accretion of discount on asset retirement obligations
3,679

3,726

Deferred income taxes
(67,734
)
16,551

Change in derivative fair value
156,135

103,270

(Gain) loss on sale of assets
(27,503
)
131

Stock-based compensation expense
6,223

9,012

Exploration, including dry holes
6,498

1,286

Discontinued operations

122,199

Other, net
7,474

7,675

Net change in:
 
 
Accounts receivable
52,036

(46,884
)
Inventories
(3,737
)
(1,411
)
Accounts payable
(15,413
)
60,617

Accrued taxes/income tax receivable
790

14,949

Pension and other postretirement benefit contributions
(10,902
)
(2,323
)
Other current assets and liabilities
4,326

(21,868
)
Net cash provided by operating activities
336,071

542,475

Investing Activities
 
 
Additions to oil and natural gas properties
(728,284
)
(575,049
)
Acquisitions, net of cash acquired
(46,203
)
(22,114
)
Proceeds from the sale of assets
393,094

217

Purchase of short-term investments
(919,000
)
(191,000
)
Sale of short-term investments
919,000

149,000

Discontinued operations

(690
)
Other, net

69

Net cash used in investing activities
(381,393
)
(639,567
)
Financing Activities
 
 
Payment of dividends on common stock
(2,923
)
(21,863
)
Issuance of common stock
399,272

23,053

Reduction of long-term debt

(30,000
)
Net change in credit facility
(352,000
)
180,000

Tax benefit on stock compensation
631

3,763

Discontinued operations

(50,093
)
Net cash provided by financing activities
44,980

104,860

Net increase (decrease) in cash and cash equivalents
(342
)
7,768

Cash and cash equivalents at beginning of period
1,852

5,555

Cash and cash equivalents at end of period
1,510

13,323

Less cash and cash equivalents of discontinued operations at end of period

(11,807
)
Cash and cash equivalents of continuing operations at end of period
$
1,510

$
1,516


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

7



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
Six months ended
 
June 30,
June 30,
(in thousands)
2015
2014
2015
2014
Open non-cash mark-to-market losses on derivative instruments
$
(116,867
)
$
(59,621
)
$
(176,518
)
$
(93,302
)
Closed gains (losses) on derivative instruments
65,903

(25,225
)
159,590

(44,935
)
Loss on derivative instruments, net
$
(50,964
)
$
(84,846
)
$
(16,928
)
$
(138,237
)












8



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)
June 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
$
165,556

$
(17,767
)
$
147,789

$

$

$
147,789

Noncurrent derivative instruments
707

(707
)




Total derivative assets
166,263

(18,474
)
147,789



147,789

Liabilities
 
 
 
 
 
 
Derivative instruments
27,987

(17,767
)
10,220



10,220

Noncurrent derivative instruments
4,592

(707
)
3,885



3,885

Total derivative liabilities
32,579

(18,474
)
14,105



14,105

Total derivatives
$
133,684

$

$
133,684

$

$

$
133,684


(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 June 30, 2015. The largest counterparty net gain positions at June 30, 2015, J.P. Morgan Ventures Energy Corporation, Merrill Lynch Commodities, Inc., Canadian Imperial Bank of Commerce, Bank of Montreal and Morgan Stanley Capital Group Inc., constituted approximately $28.3 million, $23.6 million, $17.3 million, $16.4 million and $15.7 million, respectively, of Energen’s total gain on fair value of derivatives.


9



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
June 30, 2014
Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $6
$
9

Gain reclassified from accumulated other comprehensive income into income (effective portion)
Gain (loss) on derivative instruments, net
$
5,735


(in thousands)
Location on Statements of Income
Six months
ended
June 30, 2014
Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $7
$
11

Gain reclassified from accumulated other comprehensive income into income (effective portion)
Gain (loss) on derivative instruments, net
$
9,789


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
June 30, 2015
Three months
ended
June 30, 2014
Loss recognized in income on derivatives
Gain (loss) on derivative instruments, net
$
(50,964
)
$
(90,581
)

(in thousands)
Location on Statements of Income
Six months
ended
June 30, 2015
Six months
ended
June 30, 2014
Loss recognized in income on derivatives
Gain (loss) on derivative instruments, net
$
(16,928
)
(148,026
)




















10



As of June 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
7,040
 MBbl
$78.24 Bbl
NYMEX Swaps
2016
1,086
 MBbl
$63.80 Bbl
NYMEX Swaps
Oil Basis Differential
 
 
 
2015
3,780
 MBbl
$(4.55) Bbl
WTI/WTI Basis Swaps
2015
1,080
 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
10.8
 Bcf
$4.14 Mcf
Basin Specific Swaps - San Juan
2015
3.0
 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 June 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 six months ended June 30, 2015.















11



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:

 
June 30, 2015
(in thousands)
Level 2
Level 3
Total
Assets:
 
 
 
Derivative instruments
$
145,979

$
1,810

$
147,789

Total assets
145,979

1,810

147,789

Liabilities:
 
 
 
Derivative instruments
1,069

(11,289
)
(10,220
)
Noncurrent derivative instruments
699

(4,584
)
(3,885
)
Total liabilities
1,768

(15,873
)
(14,105
)
Net derivative asset
$
147,747

$
(14,063
)
$
133,684


 
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 June 30, 2015, Energen had interest rate swap agreements with a notional value of $100 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 $0.5 million and a $0.8 million liability at June 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 derivative instruments 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

12



decrease in commodity prices would result in an approximate $3 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
 
June 30,
(in thousands)
2015
2014
Balance at beginning of period
$
2,413

$
1,378

Realized gains
661

785

Unrealized gains (losses) relating to instruments held at the reporting date*
(16,476
)
3,800

Settlements during period
(661
)
(756
)
Balance at end of period
$
(14,063
)
$
5,207


 
Six months ended
 
June 30,
(in thousands)
2015
2014
Balance at beginning of period
$
24,436

$
18,289

Realized gains (losses)
13,814

(2,158
)
Unrealized losses relating to instruments held at the reporting date*
(38,499
)
(13,111
)
Settlements during period
(13,814
)
2,187

Balance at end of period
$
(14,063
)
$
5,207

*Includes $15.8 million and $20.9 million in mark-to-market losses for the three months and six months ended June 30, 2015, respectively. Includes $5.2 million in mark-to-market gains and $4.2 million in mark-to-market losses for the three months and six months ended June 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 June 30, 2015
Valuation Technique*
Unobservable Input*
Range
Oil Basis - WTI/WTI
 
 
 
 
2015
$
(16,604
)
Discounted Cash Flow
Forward Basis
($0.05 - $0.35) Bbl
2016
$
(7,866
)
Discounted Cash Flow
Forward Basis
($0.80 - $0.88) Bbl
Oil Basis - WTS/WTI
 
 
 
 
2015
$
(5,427
)
Discounted Cash Flow
Forward Basis
$0.59 - $0.76 Bbl
2016
$
(2,676
)
Discounted Cash Flow
Forward Basis
($0.26-$0.80) Bbl
Natural Gas Basis - San Juan
 
 
 
 
2015
$
14,336

Discounted Cash Flow
Forward Basis
($0.09 - $0.10) Mcf
Natural Gas Basis - Permian
 
 
 
 
2015
$
4,174

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.

13



Asset Impairments: Energen monitors 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 six months ended June 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 $667.9 million and $993.7 million and had a carrying value of $687.0 million and $1,039.0 million at June 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)
June 30, 2015
December 31, 2014
Credit facility
$
133,000

$
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

 
687,000

1,039,000

Less unamortized debt discount
425

437

Total Energen
$
686,575

$
1,038,563


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

(in thousands)
Remaining 2015
2016
2017
2018
2019
2020 and thereafter
$—
$—
$19,000
$—
$133,000
$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.


14



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. Originally, the credit facility had an initial borrowing base of $2.1 billion and aggregate commitments of $1.5 billion. On November 17, 2014, the credit facility was amended to provide for $2.0 billion in aggregate commitments. On April 16, 2015, the borrowing base and aggregate commitments were reduced to $1.6 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.6 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 October 1, 2015.

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 June 30, 2015.

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

(in thousands)
June 30, 2015
December 31, 2014
Credit facility outstanding
$
133,000

$
485,000

Available for borrowings
1,467,000

1,515,000

Total borrowing commitments
$
1,600,000

$
2,000,000


(in thousands)
June 30, 2015
December 31, 2014
Maximum amount outstanding at any month-end
$
685,000

$
750,000

Average daily amount outstanding
$
521,735

$
482,166

Weighted average interest rates based on:
 
 
Average daily amount outstanding
1.64
%
1.46
%
Amount outstanding at period-end
1.44
%
1.67
%

Energen’s interest expense was $11.2 million and $23.0 million for the three months and six months ended June 30, 2015, respectively. Interest expense for Energen was $8.0 million and $15.9 million for the three months and six months ended June 30, 2014, respectively. Energen had no capitalized interest for the three months ended June 30, 2015. Energen’s total interest expense for the six months ended June 30, 2015 included capitalized interest expense of $32,000. Energen had capitalized interest of $37,000 for both the three

15



months and six months ended June 30, 2014. At June 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)
June 30, 2015
June 30, 2014
 
Net
 
Per Share
Net
 
Per Share
 
Loss
Shares
Amount
Loss
Shares
Amount
Basic EPS
$
(111,601
)
73,452

$
(1.52
)
$
(7,953
)
72,851

$
(0.11
)
Effect of dilutive securities
 
 
 
 
 
 
Stock options
 

 
 

 
Non-vested restricted stock
 

 
 

 
Performance share awards
 

 
 

 
Diluted EPS
$
(111,601
)
73,452

$
(1.52
)
$
(7,953
)
72,851

$
(0.11
)

 
Six months ended
Six months ended
(in thousands, except per share amounts)
June 30, 2015
June 30, 2014
 
Net
 
Per Share
Net
 
Per Share
 
Loss
Shares
Amount
Income
Shares
Amount
Basic EPS
$
(127,021
)
73,143

$
(1.74
)
$
45,363

72,737

$
0.62

Effect of dilutive securities
 
 
 
 
 
 
Stock options
 

 
 
165

 
Non-vested restricted stock
 

 
 
48

 
Performance share awards
 

 
 
81

 
Diluted EPS
$
(127,021
)
73,143

$
(1.74
)
$
45,363

73,031

$
0.62


In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 351,130 and 312,964 of excluded shares for the three months and six months ended June 30, 2015, respectively. The Company had 337,614 of excluded shares for the three months ended June 30, 2014.

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



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2015
2014
2015
2014
Stock options
6

114

6

114

Performance share awards
120

4

120

68


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

16



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 $68.10 as of June 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 $103.38 as of June 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 $68.24 as of June 30, 2015, and 265 Petrotech units with a twenty-four month vesting period and a fair value of $68.18 as of June 30, 2015, none of which included a market condition.

Stock Repurchase Program
During the three months and six months ended June 30, 2015, Energen had non-cash purchases of approximately $43,000 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 $1.1 million and $1.4 million during the three months and six months ended June 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. We anticipate distributing benefits under the plan in late 2015 or early 2016 pending receipt of a determination letter from the Internal Revenue Service and completion of certain administrative actions.

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 June 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.


17



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
June 30,
Six months ended
June 30,
(in thousands)
2015
2014
2015
2014
Components of net periodic benefit cost:
 
 
 
 
Service cost
$

$
1,621

$

$
3,256

Interest cost
204

1,404

408

2,817

Expected long-term return on assets

(1,449
)

(2,909
)
Actuarial loss
184

1,407

369

2,819

Prior service cost amortization

57


114

Settlement charge
701

115

3,363

3,673

Net periodic expense
$
1,089

$
3,155

$
4,140

$
9,770


During 2015, Energen anticipates an additional contribution of $13.7 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 six months ended June 30, 2015 with respect to the termination of the non-qualified supplemental retirement plans and expects to make additional benefit payments of $0.1 million through the remainder of 2015. In the first quarter and second quarter of 2015, Energen incurred settlement charges of $0.2 million and $0.7 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 of 2014, Energen incurred settlement charges of $0.4 million for the payment of lump sums from the qualified defined benefit pension plans. 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 of 2014, Energen incurred a settlement charge of $0.4 million 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
June 30,
Six months ended
June 30,
(in thousands)
2015
2014
2015
2014
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
98

$
59

$
196

$
119

Interest cost
117

224

233

450

Expected long-term return on assets
(114
)
(383
)
(229
)
(770
)
Actuarial gain

(209
)

(421
)
Transition amortization

15


30

Net periodic (income) expense
$
101

$
(294
)
$
200

$
(592
)

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 4.0 million barrels of oil equivalent (MMBOE) through August 2017.

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

18



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 is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. We estimate that the cleanup, remediation and related costs will approximate $2.5 million of which $2.2 million has been incurred. In addition, we are in preliminary stages of an evaluation to determine whether inspection or site work related to other reserve pits is appropriate. We have not accrued and are unable to estimate a range of possible losses related to these reserve pits.
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 June 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.










19



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
June 30,
Six months ended
June 30,
(in thousands)
2015
2014
2015
2014
Capitalized exploratory well costs at beginning of period
$
115,209

$
109,968

$
119,439

$
57,600

Additions pending determination of proved reserves
189,460

200,347

419,521

365,189

Reclassifications due to determination of proved reserves
(204,743
)
(142,666
)
(439,034
)
(255,140
)
Exploratory well costs charged to expense

(1,191
)

(1,191
)
Capitalized exploratory well costs at end of period
$
99,926

$
166,458

$
99,926

$
166,458


The following table sets forth capitalized exploratory well costs:

(in thousands)
June 30, 2015
December 31, 2014
Exploratory wells in progress (drilling rig not released)
$
20,424

$
18,781

Capitalized exploratory well costs capitalized for a period of one year or less
79,502

100,658

Total capitalized exploratory well costs
$
99,926

$
119,439


No wells were capitalized for a period greater than one year as of June 30, 2015 or December 31, 2014. At June 30, 2015, Energen had 48 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are located primarily in the Permian 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
770

Liabilities settled
(512
)
Accretion expense
3,679

Reclassification associated with held for sale properties*
1,052

Balance as of June 30, 2015
$
99,049

*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









20



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)
 
2,427

Balance as of June 30, 2015

$
(20,443
)

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

 
Three months ended
 
 
June 30,
 
 
2015
2014
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains (losses) on cash flow hedges:
 
 
 
Commodity contracts
$

$
5,735

Gain (loss) on derivative instruments, net
Interest rate swap

(1,588
)
Interest expense
Total cash flow hedges

4,147

 
Income tax expense

(1,623
)
 
Net of tax

2,524

 
Pension and postretirement plans:
 
 
 
Transition obligation

(9
)
General and administrative
Prior service cost

(74
)
General and administrative
Actuarial losses
(885
)
(1,649
)
General and administrative
Total pension and postretirement plans
(885
)
(1,732
)
 
Income tax expense
309

606

 
Net of tax
(576
)
(1,126
)
 
Total reclassifications for the period
$
(576
)
$
1,398

 


21



 
Six months ended
 
 
June 30,
 
 
2015
2014
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains (losses) on cash flow hedges:
 
 
 
Commodity contracts
$

$
9,789

Gain (loss) on derivative instruments, net
Interest rate swap

(2,033
)
Interest expense
Total cash flow hedges

7,756

 
Income tax expense

(3,008
)
 
Net of tax

4,748

 
Pension and postretirement plans:
 
 
 
Transition obligation

(19
)
General and administrative
Prior service cost

(148
)
General and administrative
Actuarial losses
(3,732
)
(10,202
)
General and administrative
Total pension and postretirement plans
(3,732
)
(10,369
)
 
Income tax expense
1,305

3,630

 
Net of tax
(2,427
)
(6,739
)
 
Total reclassifications for the period
$
(2,427
)
$
(1,991
)
 

13. ASSET IMPAIRMENT

Impairments recognized by Energen are presented below:



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2015
2014
2015
2014
Continuing operations:
 
 
 
 
Permian Basin oil properties
$
51,474

$

$
55,804

$

Permian Basin unproved leasehold properties
8,939

1,339

10,944

2,587

San Juan Basin unproved leasehold properties

3

248

1

Total asset impairments from continuing operations
60,413

1,342

66,996

2,588

Discontinued operations:
 
 
 
 
North Louisiana/East Texas oil and natural gas properties



1,667

Total asset impairments from discontinued operations



1,667

Total asset impairments
$
60,413

$
1,342

$
66,996

$
4,255


During the three months and six months ended June 30, 2015, Energen recognized non-cash impairment writedowns on certain properties primarily in the Central Basin Platform of the Permian Basin of $51.5 million pre-tax and $55.8 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. During the quarter, Energen received an unsolicited offer for certain properties which resulted in an evaluation and subsequent revision of estimated future cash flows. The 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 $8.9 million pre-tax during the second quarter of 2015 and $11.2 million in the year-to-date. These non-cash writedowns are reflected in asset impairment on the consolidated income statement.

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

22



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. 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 $11 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 $384 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.2 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 six months ended June 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 each 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
Six months ended
 
June 30,
June 30,
(in thousands, except per share data)
2015
2014
2015
2014
Total revenues
$
167,734

$
221,642

$
357,578

$
464,732

Loss from continuing operations
$
(110,362
)
$
(13,769
)
$
(149,203
)
$
(11,920
)
Net income (loss)
$
(110,362
)
$
(18,568
)
$
(149,203
)
$
20,950

Diluted earnings per average common share from continuing operations
$
(1.50
)
$
(0.19
)
$
(2.04
)
$
(0.16
)
Diluted earnings per average common share
$
(1.50
)
$
(0.25
)
$
(2.04
)
$
0.29

Basic earnings per average common share from continuing operations
$
(1.50
)
$
(0.19
)
$
(2.04
)
$
(0.16
)
Basic earnings per average common share
$
(1.50
)
$
(0.25
)
$
(2.04
)
$
0.29


Energen completed an estimated total of $46.0 million in various purchases of unproved leasehold during the six months ended June 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.














23



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 six months ended June 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 June 30, 2014
Six months ended June 30, 2014
Alagasco net income (loss)
$
(615
)
$
42,413

Depreciation, depletion and amortization
(153
)
(305
)
General and administrative
687

1,627

Interest expense
(7,190
)
(12,977
)
Other income
(228
)
(347
)
Income tax expense
2,603

4,538

Alagasco income (loss) from discontinued operations
(4,896
)
34,949

Energen income (loss) from discontinued operations
97

(1,029
)
Income (loss) from discontinued operations
$
(4,799
)
$
33,920





24



(in thousands, except per share data)
Three months
ended
June 30, 2014
Six months
ended
June 30, 2014
Natural gas distribution revenues
$
93,873

$
357,774

Oil and natural gas revenues
390

5,211

Total revenues
$
94,263

$
362,985

Pretax income (loss) from discontinued operations
$
(7,797
)
$
54,519

Income tax expense (benefit)
(2,998
)
20,599

Income (Loss) From Discontinued Operations
$
(4,799
)
$
33,920

Loss on disposal of discontinued operations
$

$
(1,667
)
Income tax benefit

(617
)
Loss on Disposal of Discontinued Operations
$

$
(1,050
)
Total Income (Loss) From Discontinued Operations
$
(4,799
)
$
32,870

Diluted Earnings Per Average Common Share
 
 
Income (loss) from discontinued operations
$
(0.07
)
$
0.46

Loss on disposal of discontinued operations

(0.01
)
Total Income (Loss) From Discontinued Operations
$
(0.07
)
$
0.45

Basic Earnings Per Average Common Share
 
 
Income (loss) from discontinued operations
$
(0.07
)
$
0.46

Loss on disposal of discontinued operations

(0.01
)
Total Income (Loss) From Discontinued Operations
$
(0.07
)
$
0.45


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 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.


25


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 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. This amendment is effective for interim and annual periods beginning on or after December 15, 2016. On April 1, 2015, the FASB proposed a deferral of the effective date by one year, which will not be final until the FASB completes its due process requirements. 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 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 in the San Juan Basin in New Mexico. Our operations are conducted through our subsidiary, Energen Resources Corporation (Energen Resources).

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.

FINANCIAL AND OPERATING PERFORMANCE

Overview of Second Quarter and Year-to-Date 2015 Results and Activities
During the second quarter of 2015 as compared to the same period in the prior year, we:
expanded development and exploratory activities in the Permian Basin increasing production by 1,019 MBOE or 24 percent and
issued 5,700,000 additional shares of common stock through a public equity offering receiving proceeds of approximately $398.6 million.

During the six months ended June 30, 2015 as compared to the same period in the prior year, we:
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;
expanded development and exploratory activities in the Permian Basin increasing production by 1,516 MBOE or 18 percent and
experienced a significant decline in commodity prices.

Quarter ended June 30, 2015 vs quarter ended June 30, 2014
Energen had a net loss of $111.6 million ($1.52 per diluted share) for the three months ended June 30, 2015 as compared with a net loss of $8.0 million ($0.11 per diluted share) for the same period in the prior year. In the second quarter of 2015, our loss from continuing operations totaled $111.6 million ($1.52 per diluted share) as compared with a loss from continuing operations of $3.2 million ($0.04 per diluted share) in the same period a year ago. Energen had no discontinued operations in the current quarter. Loss from discontinued operations was $4.8 million ($0.07 per diluted share) from the prior-year second quarter largely due to the sale of Alagasco. This increase in loss from continuing operations was primarily the result of:

lower realized oil, natural gas liquids and natural gas commodity prices (approximately $112.3 million after-tax);
year-over-year after-tax $37 million loss on open derivatives (resulting from an after-tax $75.1 million non-cash loss on open derivatives for the second quarter of 2015 and an after-tax $38.1 million non-cash loss on open derivatives for the second quarter of 2014);
non-cash impairments on certain oil properties in the Permian Basin (approximately $33 million after-tax);
decreased natural gas production volumes (approximately $20.4 million after-tax);
increased depreciation, depletion and amortization (DD&A) expense (approximately $8.7 million after-tax);
higher exploration expense (approximately $6.3 million after-tax);
additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $4.9 million after-tax);
increased general and administrative (G&A) expense (approximately $3.3 million after-tax) and
higher interest expense (approximately $2.1 million after-tax)

partially offset by:

gain on closed derivatives (approximately $58.3 million after-tax);
increased oil and natural gas liquids production volumes (approximately $45.3 million after-tax);

27



lower production and ad valorem taxes (approximately $9.4 million after-tax) and
decreased oil, natural gas liquids and natural gas production expense (approximately $7.1 million after-tax).

Six months ended June 30, 2015 vs six months ended June 30, 2014
For the 2015 year-to-date, Energen had a net loss of $127.0 million ($1.74 per diluted share) as compared with net income of $45.4 million ($0.62 per diluted share) for the same period in the prior year. For the six months ended June 30, 2015, our loss from continuing operations totaled $127.0 million ($1.74 per diluted share) as compared with income from continuing operations of $12.5 million ($0.17 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 $32.9 million ($0.45 per diluted share) from the prior year-to-date largely due to the sale of Alagasco. This decrease in income from continuing operations was primarily the result of:

lower realized oil, natural gas liquids and natural gas commodity prices (approximately $240.3 million after-tax);
year-over-year after-tax $53.8 million loss on open derivatives (resulting from an after-tax $113.5 million non-cash loss on open derivatives for the first six months of 2015 and an after-tax $59.7 million non-cash loss on open derivatives for the first six months of 2014);
non-cash impairments on certain oil properties primarily in the Central Basin Platform of the Permian Basin (approximately $35.8 million after-tax);
decreased natural gas and natural gas liquids production volumes (approximately $25.1 million after-tax);
higher DD&A expense (approximately $15.2 million after-tax);
additional unproved leasehold writedowns primarily on Permian Basin properties in the Delaware Basin (approximately $5.4 million after-tax);
higher interest expense (approximately $4.6 million after-tax) and
increased G&A expense (approximately $3.2 million after-tax).

partially offset by:

gain on closed derivatives (approximately $130.9 million after-tax);
higher oil production volumes (approximately $73.7 million after-tax);
gain on sale of the majority of our natural gas assets in the San Juan Basin (approximately $17.4 million after tax);
lower production and ad valorem taxes (approximately $14.7 million after-tax) and
decreased oil, natural gas liquids and natural gas production expense (approximately $6.9 million after-tax).




























28



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 $661 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
$
545,000

Spraberry
150,000

Wolfberry
20,000

SWD/Facilities
82,000

Non-operated/Other
13,000

Delaware Basin
 
Bone Spring
18,000

Wolfcamp
73,000

Wolfbone
15,000

SWD/Facilities
32,000

Non-operated/Other
5,000

Other Permian
11,000

San Juan Basin/Other
63,000

Net Carry-in/Carry Out/Miscellaneous
18,000

Acquisitions/Lease Extensions/Unproved Leasehold
55,000

Total
$
1,100,000


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 $384 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.
















29



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


Three months ended
Six months ended

June 30,
June 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
$
188,599

$
262,746

$
330,627

$
516,505

Natural gas liquids
14,781

31,163

25,615

59,366

Natural gas
15,910

61,943

50,870

130,803

Total
$
219,290

$
355,852

$
407,112

$
706,674

Open non-cash mark-to-market gains (losses) on derivative instruments


Oil
$
(103,734
)
$
(66,172
)
$
(155,503
)
$
(87,636
)
Natural gas liquids

40


327

Natural gas
(13,133
)
6,511

(21,015
)
(5,993
)
Total
$
(116,867
)
$
(59,621
)
$
(176,518
)
$
(93,302
)
Closed gains (losses) on derivative instruments


Oil
$
55,330

$
(25,754
)
$
132,813

$
(40,556
)
Natural gas liquids

159


355

Natural gas
10,573

370

26,777

(4,734
)
Total
$
65,903

$
(25,225
)
$
159,590

$
(44,935
)
Total revenues
$
168,326

$
271,006

$
390,184

$
568,437

Production volumes
 
 
 
 
Oil (MBbl)
3,594

2,833

6,829

5,584

Natural gas liquids (MMgal)
44.9

44.7

81.1

82.7

Natural gas (MMcf)
7,134

14,676

20,412

28,800

Total production volumes (MBOE)
5,853

6,344

12,162

12,352

Average daily production volumes
 
 
 
 
Oil (MBbl/d)
39.5

31.1

37.7

30.9

Natural gas liquids (MMgal/d)
0.5

0.5

0.5

0.5

Natural gas (MMcf/d)
78.4

161.3

112.8

159.1

Total average daily production volumes (MBOE/d)
64.3

69.7

67.2

68.2

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)
$
67.87

$
83.65

$
67.86

$
85.23

Natural gas liquids (per gallon)
$
0.33

$
0.70

$
0.32

$
0.72

Natural gas (per Mcf)
$
3.71

$
4.25

$
3.80

$
4.38

Average realized prices excluding effects of all derivatives instruments
Oil (per barrel)
$
52.48

$
92.74

$
48.42

$
92.50

Natural gas liquids (per gallon)
$
0.33

$
0.70

$
0.32

$
0.72

Natural gas (per Mcf)
$
2.23

$
4.22

$
2.49

$
4.54

Costs per BOE
 
 
 
 
Oil, natural gas liquids and natural gas production expenses
$
9.15

$
10.20

$
9.98

$
10.70

Production and ad valorem taxes
$
2.28

$
4.42

$
2.67

$
4.48

Depreciation, depletion and amortization
$
25.60

$
21.48

$
23.37

$
21.09

Exploration expense
$
1.88

$
0.19

$
0.97

$
1.04

General and administrative
$
6.60

$
5.29

$
5.81

$
5.32

Net capital expenditures
$
284,764

$
322,572

$
660,591

$
594,268


30



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 second quarter of 2015, commodity sales decreased $136.6 million or 38.4 percent from the same period of 2014. In the six months ended June 30, 2015, commodity sales decreased $299.6 million or 42.4 percent from the same period of 2014. Particular factors impacting commodity sales include the following:
Oil volumes in the second quarter increased 26.9 percent to 3,594 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 22.3 percent to 6,829 MBbl.
Average realized oil prices fell 43.4 percent to $52.48 per barrel during the three months ended June 30, 2015. Average realized oil prices decreased 47.7 percent to $48.42 per barrel during the six months ended June 30, 2015.
Natural gas liquids production for the current quarter rose slightly to 44.9 million gallons (MMgal). For the year-to-date, natural gas liquids production declined 1.9 percent to 81.1 MMgal due to the sale of the majority of our natural gas assets in the San Juan Basin largely offset by increased performance in the Permian Basin.
Average realized natural gas liquids prices decreased 52.9 percent to an average price of $0.33 per gallon during the second quarter of 2015. Average realized natural gas liquids prices decreased 55.6 percent to an average price of $0.32 per gallon during the six months ended June 30, 2015.
Natural gas production decreased 51.4 percent to 7.1 billion cubic feet (Bcf) in the second quarter due to the sale of natural gas assets in the San Juan Basin, normal declines in the San Juan Basin and pipeline curtailments in the Permian Basin partially offset by accelerated completions and new well performance in the Permian Basin. For the six months ended June 30, 2015, natural gas production declined 29.1 percent to 20.4 Bcf.
Average realized natural gas prices declined 47.2 percent to $2.23 per thousand cubic feet (Mcf) during the three months ended June 30, 2015. For the current year-to-date, average realized natural gas prices fell 45.2 percent to $2.49 per Mcf.

Realized prices exclude the effects of derivative instruments.

Losses on derivative instruments were $51.0 million in the second quarter of 2015 compared to losses of $84.8 million in the same period of 2014. Losses on derivative instruments were $16.9 million in the six months ended June 30, 2015 compared to losses of $138.2 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
Six months ended
 
June 30,
June 30,
(in thousands, except per unit data)
2015
2014
2015
2014
Lease operating expenses
$
34,961

$
31,921

$
74,402

$
65,649

Workover and repair costs
15,088

21,843

34,338

44,785

Marketing and transportation
3,532

10,933

12,595

21,707

Total oil, natural gas liquids and natural gas production expense
$
53,581

$
64,697

$
121,335

$
132,141

Oil, natural gas liquids and natural gas production expense per BOE
$
9.15

$
10.20

$
9.98

$
10.70


Energen had oil, natural gas liquids and natural gas production expense of $53.6 million and $121.3 million during the three months and six months ended June 30, 2015, respectively, as compared to $64.7 million and $132.1 million during the same periods in 2014. Lease operating expense generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities and may also be positively or negatively impacted by property acquisitions and dispositions.

Lease operating expense increased $3 million for the quarter largely due to higher equipment rental costs (approximately $2.4 million), increased water disposal costs (approximately $2.1 million), higher environmental compliance costs

31



(approximately $0.8 million) and increased gathering costs (approximately $0.6 million) partially offset by lower other operations and maintenance expense (approximately $1.9 million) and decreased electrical costs (approximately $1.2 million). On a per unit basis, the average lease operating expense for the current quarter was $5.96 per barrel of oil equivalent (BOE) as compared to $5.03 per BOE in the same period a year ago.

In the year-to-date, lease operating expense increased $8.8 million primarily due to higher water disposal costs (approximately $4.5 million), additional equipment rental costs (approximately $2.7 million), higher labor costs (approximately $1.7 million), increased non-operated costs (approximately $1.4 million), increased gathering costs (approximately $1.4 million), higher environmental compliance costs (approximately $0.7 million) and additional producing overhead costs (approximately $0.6 million) partially offset by lower other operations and maintenance expense (approximately $3.1 million) and decreased electrical costs (approximately $1.7 million). For the six months ended June 30, 2015, the average lease operating expense was $6.11 per BOE as compared to $5.31 per BOE in the previous period.

Workover and repair costs decreased approximately $6.8 million in the three months ended June 30, 2015 and $10.4 million in the year-to-date primarily due to lower incidence of offset well stimulation interference and fewer downhole failures.

In the three months ended June 30, 2015, marketing and transportation costs decreased $7.4 million and $9.1 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 ($2.28 per BOE) and $32.4 million ($2.67 per BOE), respectively, during the three months and six months ended June 30, 2015 as compared to $28.0 million ($4.42 per BOE) and $55.4 million ($4.48 per BOE) during the same periods in 2014. In the current quarter, production-related taxes were $9 million lower as decreased commodity market prices contributed approximately $7.5 million and lower net production volumes contributed approximately $1.5 million. In the year-to-date, production-related taxes were $18.5 million lower as decreased commodity market prices contributed approximately $17.9 million and lower net production volumes contributed approximately $0.6 million. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes. Decreased ad valorem taxes in the quarter and 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 $13.6 million and $23.8 million year-to-date. The average depletion rate for the current quarter was $25.60 per BOE as compared to $21.48 per BOE in the same period a year ago. For the six months ended June 30, 2015, the average depletion rate was $23.37 per BOE as compared to $21.09 per BOE in the previous period. The increase in the current quarter and year-to-date per unit depletion rate which contributed approximately $23.7 million and $26.7 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 $10.5 million and $4 million for the quarter and year-to-date, respectively.

Asset impairment: During the second quarter of 2015 and year-to-date, Energen recognized non-cash impairment writedowns on certain properties primarily in the Central Basin Platform of the Permian Basin of $51.5 million pre-tax and $55.8 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. During the quarter, Energen received an unsolicited offer for certain properties which resulted in an evaluation and subsequent revision of estimated future cash flows. The non-cash impairment writedowns are reflected in asset impairment on the consolidated income statement. In addition, certain properties in the Permian Basin, primarily in the Central Basin Platform, are at risk of impairment if oil price declines subsequent to the balance sheet date are sustained. These properties have a net book value of approximately $171 million at June 30, 2015.

Energen recognized unproved leasehold writedowns primarily on Permian properties in the Delaware Basin of $8.9 million pre-tax and $11.2 million pre-tax during the second quarter of 2015 and year-to-date, respectively. These non-cash writedowns are reflected in asset impairment on the consolidated income statement.










32



Exploration: The following table provides details of our exploration expense:

 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands, except per unit data)
2015
2014
2015
2014
Geological and geophysical
$
4,463

$
(450
)
$
4,941

$
1,656

Dry hole costs
6,474

1,255

6,498

1,286

Delay rentals and other
81

428

342

9,859

Total exploration expense
$
11,018

$
1,233

$
11,781

$
12,801

Total exploration expense per BOE
$
1.88

$
0.19

$
0.97

$
1.04


Exploration expense increased $9.8 million in the second quarter of 2015 primarily due to increased dry hole costs and higher seismic costs. For the six months ended June 30, 2015, exploration expense decreased $1 million largely as a result of lower delay rentals partially offset by higher dry hole costs and increased seismic costs.

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

 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands, except per unit data)
2015
2014
2015
2014
General and administrative
$
11,484

$
7,895

$
18,671

$
13,514

Benefit and performance-based compensation costs
13,256

12,488

25,906

27,933

Labor costs
13,912

13,159

26,130

24,268

Total general and administrative expense
$
38,652

$
33,542

$
70,707

$
65,715

Total general and administrative expense per BOE
$
6.60

$
5.29

$
5.81

$
5.32


Total G&A expense increased $5.1 million for the three months ended June 30, 2015 largely due to higher legal expenses, increased costs from Energen’s benefit and performance-based compensation plans and increased labor costs. G&A expense rose $5 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. Included in costs from the benefit and performance-based compensation plans were pension costs of $1.1 million and $4.1 million for the three months and six months ended June 30, 2015, respectively, as compared to $3.2 million and $9.8 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 $11 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 $384 million before consideration of transaction costs of approximately $2.8 million. Energen recognized a pre-tax gain of $27.2 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 increased $3.3 million in the second quarter of 2015 and $7.2 million for the six months ended June 30, 2015. This increase was largely due to the interest expense from the three months and six months ended June 30, 2015 associated with the $600 million Senior Term Loans issued in December 2013 and the October 2012 syndicated credit facilities being reflected in discontinued operations. In conjunction with the sale of Alagasco, the $600 million Senior Term Loans and the syndicated credit facilities were repaid in September 2014.

Income tax expense (benefit): Income tax expense decreased $60.3 million for the three months ended June 30, 2015 and $77.2 million for the six months period ended June 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

33



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 $384 million ($395 million aggregate purchase price before purchase price adjustments) of 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 six months ended June 30, 2015 was $336.1 million as compared to $542.5 million for the same period of 2014. The year-to-date 2014 included discontinued operations primarily associated with cash flows from Alagasco of $122.2 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 used in investing activities: Net cash used in investing activities for the six months ended June 30, 2015 was $381.4 million as compared to $639.6 million for the same period of 2014. Energen incurred on a cash basis $775 million in capital expenditures largely related to the development of oil and natural gas properties and $46 million primarily related to unproved leasehold acquisitions. Included in the proceeds from the sale of assets are cash proceeds of $383.7 million from the sale of certain San Juan Basin assets and $8.6 million from the sale of Alagasco.

Net cash provided by financing activities: Net cash provided by financing activities for the six months ended June 30, 2015 was $45.0 million as compared $104.9 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 decrease in credit facility borrowings. Net cash provided by financing activities in the year-to-date 2014 was largely due to an increase in borrowings from the credit facility partially offset by discontinued operations primarily related to the sale of Alagasco and the reduction of long-term debt for current maturities. For each of the periods, net cash provided by 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

34



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 7,040 MBbl of oil and 13.8 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 June 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 April 16, 2015, the borrowing base and aggregate commitments were reduced to $1.6 billion in association with the semi-annual redetermination required under the agreement. Energen’s obligations under the $1.6 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 October 1, 2015.

At June 30, 2015, Energen reported negative working capital of $60.6 million arising from current liabilities of $378.9 million exceeding current assets of $318.3 million. Working capital at Energen is influenced by the fair value of derivative financial instruments associated with future production. Energen has $147.8 million in current assets and $10.2 million in current liabilities, respectively, associated with its derivative instruments at June 30, 2015. Energen relies upon cash flows from operations supplemented by our credit facility to fund working capital needs.

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 initially used to repay borrowings under our credit facility and for general corporate purposes.

35



(in thousands)
June 30, 2015
December 31, 2014
Shares outstanding
78,798

72,973

Treasury stock*
2,969

2,903

Shares issued
81,767

75,876

*Excludes 50,337 shares and 78,254 shares held in the 1997 Deferred Compensation Plan at June 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 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. We anticipate distributing benefits under the plan in late 2015 or early 2016 pending receipt of a determination letter from the Internal Revenue Service and completion of certain administrative actions.

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 June 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 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
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

36



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 June 30, 2015.

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 60 percent of our June 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;

37



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.


38



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 June 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;

39



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

40



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.


41



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.







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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.


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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.

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.

As of June 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
7,040
 MBbl
$78.24 Bbl
NYMEX Swaps
$
125,561

2016
1,086
 MBbl
$63.80 Bbl
NYMEX Swaps
1,803

Oil Basis Differential
 
 
 
 
2015
3,780
 MBbl
$(4.55) Bbl
WTI/WTI Basis Swaps
(16,604
)
2015
1,080
 MBbl
$(4.30) Bbl
WTS/WTI Basis Swaps
(5,427
)
2016
7,524
 MBbl
$(1.92) Bbl
WTI/WTI Basis Swaps
(7,866
)
2016
2,117
 MBbl
$(1.63) Bbl
WTS/WTI Basis Swaps
(2,676
)
Natural Gas
 
 
 
 
2015
10.8
 Bcf
$4.14 Mcf
Basin Specific Swaps - San Juan
14,336

2015
3.0
 Bcf
$4.20 Mcf
Basin Specific Swaps - Permian
4,174

June 2015 contracts (closed but not cash settled)
20,383

Total
$
133,684

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.

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

44



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 June 30, 2015 primarily relates to our syndicated credit facility with variable interest rates. At June 30, 2015, we had interest rate swap agreements with a notional value of $100 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 $0.5 million liability at June 30, 2015. The weighted average interest rate for amounts outstanding at June 30, 2015 was 1.44 percent. All long-term debt obligations, other than our credit facility, were at fixed rates at June 30, 2015.


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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.




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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**
April 1, 2015 - April 30, 2015

 
$


3,373,161

May 1, 2015 - May 31, 2015
24

*
70.91


3,373,161

June 1, 2015 - June 30, 2015
599

*
69.51


3,373,161

Total
623

 
$
69.56


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

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 June 30, 2015 are formatted in XBRL
 
 
 
*Incorporated by reference



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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
 
 
 
 
August 7, 2015
 
By
/s/ J. T. McManus, II       
 
 
 
J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation
 
 
 
 
 
 
 
 
August 7, 2015
 
By
/s/ Charles W. Porter, Jr.             
 
 
 
Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation
 
 
 
 
 
 
 
 
August 7, 2015
 
By
/s/ Russell E. Lynch, Jr.                    
 
 
 
Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation
 
 
 
 
 
 
 
 













 




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