ENERGEN CORP - FORM 10-Q - August 11, 2014

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EX-32.B - SECTION 906 ALABAMA GAS CORPORATION - ENERGEN CORPegn63014ex32b.htm
EX-32.A - SECTION 906 ENERGEN CORPORATION - ENERGEN CORPegn63014ex32a.htm
EX-31.C - SECTION 302 ALABAMA GAS CORPORATION - ENERGEN CORPegn63014ex31c.htm
EX-31.B - SECTION 302 ENERGEN CORPORATION - ENERGEN CORPegn63014ex31b.htm
EX-31.D - SECTION 302 ALABAMA GAS CORPORATION - ENERGEN CORPegn63014ex31d.htm
EXCEL - IDEA: XBRL DOCUMENT - ENERGEN CORPFinancial_Report.xls
EX-31.A - SECTION 302 ENERGEN CORPORATION - ENERGEN CORPegn63014ex31a.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, 2014
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
 
Registrant
 
State of
Incorporation
 
IRS Employer
Identification
Number
1-7810
 
Energen Corporation
 
Alabama
 
63-0757759
2-38960
 
Alabama Gas Corporation
 
Alabama
 
63-0022000
605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number (205) 326-2700
http://www.energen.com
Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).
Indicate by a check mark whether the registrants (1) have 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 registrants were 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).
Energen Corporation
 
YES
x
NO
o
Alabama Gas Corporation
 
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.

Energen Corporation - Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o
Alabama Gas Corporation - Large accelerated filer o Accelerated filer o Non-accelerated filer x 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).
Energen Corporation
 
YES
o
NO
x
Alabama Gas Corporation
 
YES
o
NO
x
Number of shares outstanding of each of the registrant’s classes of common stock as of August 1, 2014.
Energen Corporation
 
 $0.01 par value
 
 73,194,619 shares
Alabama Gas Corporation
 
 $0.01 par value
 
 1,972,052 shares
 
 
 
 
 



ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2014

TABLE OF CONTENTS
 
 
 
Page
Item 1.
 
 
 
 
Energen Corporation
 
 
 
 
 
 
 
 
 
 
 
 
 
Alabama Gas Corporation
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
Item 4.
 
Item 1.
 
Item 2.
 
Item 6.
 









2


PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

ENERGEN CORPORATION
 
 
CONSOLIDATED BALANCE SHEETS
 
 
(Unaudited)
 
 
 
 
 
(in thousands)
June 30, 2014
December 31, 2013

ASSETS
 
 
Current Assets
 
 
Cash and cash equivalents
$
1,516

$
2,523

Short-term investments
42,000

—

Accounts receivable, net of allowance for doubtful accounts of $676 and $696 at June 30, 2014 and December 31, 2013, respectively
178,721

136,334

Inventories
12,541

11,130

Assets held for sale with prior period comparable
1,154,046

1,242,872

Deferred income taxes
49,580

21,250

Derivative instruments
524

17,463

Prepayments and other
37,937

9,989

Total current assets
1,476,865

1,441,561

Property, Plant and Equipment
 
 
Oil and natural gas properties, successful efforts method
 
 
Proved properties
7,273,932

6,695,400

Unproved properties
170,736

168,975

Less accumulated depreciation, depletion and amortization
2,030,941

1,776,802

Oil and natural gas properties, net
5,413,727

5,087,573

Other property and equipment, net
37,869

30,515

Total property, plant and equipment, net
5,451,596

5,118,088

Other postretirement assets
4,592

8,894

Noncurrent derivative instruments
623

5,439

Other assets
48,433

48,230

TOTAL ASSETS
$
6,982,109

$
6,622,212


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, 2014
December 31, 2013

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
Current Liabilities
 
 
Long-term debt due within one year
$
570,000

$
60,000

Notes payable to banks
669,000

489,000

Accounts payable
135,416

78,178

Accrued taxes
21,029

8,201

Accrued wages and benefits
26,979

27,036

Accrued capital costs
92,740

93,623

Revenue and royalty payable
66,071

51,519

Liabilities related to assets held for sale with prior period comparable
767,131

831,570

Derivative instruments
96,213

30,302

Other
20,159

21,796

Total current liabilities
2,464,738

1,691,225

Long-term debt
553,552

1,093,541

Asset retirement obligations
113,087

108,533

Pension liabilities
51,475

47,484

Deferred income taxes
848,422

807,614

Noncurrent derivative instruments
21,705

398

Other long-term liabilities
15,113

15,398

Total liabilities
4,068,092

3,764,193

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; 76,080,876 shares and 75,574,156 shares issued at June 30, 2014 and December 31, 2013, respectively
761

756

Premium on capital stock
558,037

523,711

Retained earnings
2,500,116

2,476,616

Accumulated other comprehensive income (loss), net of tax
 
 
Unrealized gain on hedges, net
7,304

13,362

Pension and postretirement plans
(27,642
)
(32,245
)
Interest rate swap
(161
)
(1,184
)
Deferred compensation plan
3,270

3,259

Treasury stock, at cost; 2,978,179 shares and 2,967,999 shares at June 30, 2014 and December 31, 2013, respectively
(127,668
)
(126,256
)
Total shareholders’ equity
2,914,017

2,858,019

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
6,982,109

$
6,622,212


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)
2014
2013
 
2014
2013
Revenues
 
 
 
 
 
Oil, natural gas liquids and natural gas sales
$
355,852

$
312,400

 
$
706,674

$
567,239

Gain (loss) on derivative instruments, net
(84,846
)
55,244

 
(138,237
)
36,288

Loss on sale of assets and other
(909
)
(663
)
 
(1,062
)
(215
)
Total revenues
270,097

366,981

 
567,375

603,312

Operating Costs and Expenses
 
 
 
 
 
Oil, natural gas liquids and natural gas production
64,697

59,607

 
132,141

125,149

Production and ad valorem taxes
28,049

23,503

 
55,373

46,879

Depreciation, depletion and amortization
136,244

112,384

 
260,464

207,336

Exploration
2,575

3,455

 
15,389

4,953

General and administrative
33,542

27,666

 
65,715

55,752

Accretion of discount on asset retirement obligations
1,883

1,729

 
3,726

3,416

Total costs and expenses
266,990

228,344

 
532,808

443,485

Operating Income
3,107

138,637

 
34,567

159,827

Other Income (Expense)
 
 
 
 
 
Interest expense
(7,964
)
(10,182
)
 
(15,852
)
(20,083
)
Other income
687

196

 
1,010

1,370

Total other expense
(7,277
)
(9,986
)
 
(14,842
)
(18,713
)
Income (Loss) From Continuing Operations Before Income Taxes
(4,170
)
128,651

 
19,725

141,114

Income tax expense (benefit)
(1,016
)
46,229

 
7,232

50,273

Income (Loss) From Continuing Operations
(3,154
)
82,422

 
12,493

90,841

Discontinued Operations, net of tax
 
 
 
 
 
Income (loss) from discontinued operations
(4,799
)
645

 
33,920

48,918

Loss on disposal of discontinued operations
—

—

 
(1,050
)
—

Income (Loss) From Discontinued Operations
(4,799
)
645

 
32,870

48,918

Net Income (Loss)
$
(7,953
)
$
83,067

 
$
45,363

$
139,759

Diluted Earnings Per Average Common Share
 
 
 
 
 
Continuing operations
$
(0.04
)
$
1.14

 
$
0.17

$
1.26

Discontinued operations
(0.07
)
0.01

 
0.45

0.67

Net Income (Loss)
$
(0.11
)
$
1.15

 
$
0.62

$
1.93

Basic Earnings Per Average Common Share
 
 
 
 
 
Continuing operations
$
(0.04
)
$
1.14

 
$
0.17

$
1.26

Discontinued operations
(0.07
)
0.01

 
0.45

0.68

Net Income (Loss)
$
(0.11
)
$
1.15

 
$
0.62

$
1.94

Dividends Per Common Share
$
0.150

$
0.145

 
$
0.300

$
0.290

Diluted Average Common Shares Outstanding
72,851

72,419

 
73,031

72,329

Basic Average Common Shares Outstanding
72,851

72,167

 
72,737

72,155


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)
2014
2013
 
2014
2013
Net Income (Loss)
$
(7,953
)
$
83,067

 
$
45,363

$
139,759

Other comprehensive income (loss):
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
Current period change in fair value of derivative commodity instruments, net of tax of $6, $9,713, $7 and ($6,712), respectively
9

15,847

 
11

(10,951
)
Reclassification adjustment for derivative commodity instruments, net of tax of ($2,179), ($1,711), ($3,720) and ($8,281), respectively
(3,556
)
(2,792
)
 
(6,069
)
(13,511
)
Current period change in fair value of interest rate swap, net of tax of ($98), $176, ($160) and $165, respectively
(183
)
327

 
(298
)
307

Reclassification adjustment for interest rate swap, net of tax of $556, $149, $712 and $292, respectively
1,032

277

 
1,321

544

Total cash flow hedges
(2,698
)
13,659

 
(5,035
)
(23,611
)
Pension and postretirement plans:
 
 
 
 
 
Amortization of net benefit obligation at transition, net of tax of $3, $26, $7 and $52, respectively
6

47

 
12

95

Amortization of prior service cost, net of tax of $26, $28, $52 and $55, respectively
48

51

 
96

102

Amortization of net loss, including settlement charges, net of tax of $577, $734, $3,571 and $1,654, respectively
1,072

1,363

 
6,631

3,071

Current period change in fair value of pension and postretirement plans, net of tax of ($1,151) and $0, respectively
(2,136
)
—

 
(2,136
)
—

Total pension and postretirement plans
(1,010
)
1,461

 
4,603

3,268

Comprehensive Income (Loss)
$
(11,661
)
$
98,187

 
$
44,931

$
119,416


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)
2014
2013
Operating Activities
 
 
Net income
$
45,363

$
139,759

Income from discontinued operations
(32,870
)
(48,918
)
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
260,464

207,336

Accretion of discount on asset retirement obligations
3,726

3,416

Deferred income taxes
16,551

57,500

Change in derivative fair value
103,270

(19,143
)
(Gain) loss on sale of assets
131

(105
)
Stock-based compensation expense
9,012

7,766

Exploration, including dry holes
3,874

937

Discontinued operations
122,199

152,700

Other, net
7,675

21,210

Net change in:
 
 
Accounts receivable
(46,884
)
(25,990
)
Inventories
(1,411
)
8,038

Accounts payable
60,617

19,802

Pension and other postretirement benefit contributions
(2,323
)
(5,153
)
Other current assets and liabilities
(6,919
)
20,639

Net cash provided by operating activities
542,475

539,794

Investing Activities
 
 
Additions to oil and natural gas properties
(575,049
)
(621,698
)
Acquisitions, net of cash acquired
(22,114
)
(17,183
)
Proceeds from sale of assets
217

2,382

Purchase of short-term investments
(191,000
)
—

Sale of short-term investments
149,000

—

Discontinued operations
(690
)
(45,178
)
Other, net
69

(260
)
Net cash used in investing activities
(639,567
)
(681,937
)
Financing Activities
 
 
Payment of dividends on common stock
(21,863
)
(20,945
)
Issuance of common stock
23,053

108

Reduction of long-term debt
(30,000
)
—

Net change in short-term debt
180,000

234,000

Tax benefit on stock compensation
3,763

79

Discontinued operations
(50,093
)
(77,010
)
Net cash provided by financing activities
104,860

136,232

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

(5,911
)
Cash and cash equivalents at beginning of period
5,555

9,704

Cash and cash equivalents at end of period
13,323

3,793

Less cash and cash equivalents of discontinued operations at end of period
(11,807
)
(565
)
Cash and cash equivalents of continuing operations at end of period
$
1,516

$
3,228


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

7


CONDENSED NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
 
 
 
 
 

1. ORGANIZATION AND BASIS OF PRESENTATION

Energen Corporation (Energen or the Company) is an oil and gas exploration and production company primarily engaged in the exploration, development and production of oil and gas properties in the Permian Basin in west Texas and in the San Juan Basin in New Mexico and Colorado in the continental United States. Our operations are conducted substantially through our subsidiary Energen Resources Corporation (Energen Resources). Energen is currently complemented by its legacy natural gas distribution business, Alabama Gas Corporation (Alagasco), which is engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama. 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, 2013, 2012 and 2011, included in the 2013 Annual Report of Energen and Alagasco on Form 10-K.

Our accompanying unaudited consolidated financial statements include Energen and its subsidiaries 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. In addition, and in connection with the pending sale of Alagasco, we have chosen to reformat our financial statements to reflect a presentation more closely aligned with our peers in the oil and gas industry. As part of the financial statement reformatting, certain reclassifications were made to conform prior periods’ financial statements to the current-quarter presentation. These reclassifications primarily included further detail under operating costs and expenses. We further reclassified all commodity hedges from oil and natural gas operating revenues to gain (loss) on derivative instruments, net, as follows:

 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands)
2014
2013
2014
2013
Open non-cash mark-to-market gains (losses) on derivative instruments
$
(59,621
)
$
56,149

$
(93,302
)
$
15,101

Closed gains (losses) on derivative instruments
$
(25,225
)
$
(905
)
$
(44,935
)
$
21,187

Gain (loss) on derivative instruments, net
$
(84,846
)
$
55,244

$
(138,237
)
$
36,288


In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use 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 with prior period comparable and reflected the associated operating results in discontinued operations. See Note 13, Discontinued Operations, for further information regarding the pending sale of Alagasco.

















8


We classified as discontinued operations interest on debt required to be extinguished, certain depreciation costs that end at close, 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 at June 30, 2014:



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2014
2013
2014
2013
Alagasco net income (loss)
$
(615
)
$
(704
)
$
42,413

$
46,518

Depreciation, depletion and amortization
(153
)
(147
)
(305
)
(294
)
General and administrative
687

1,724

1,627

3,578

Interest expense
(7,190
)
(3,288
)
(12,977
)
(6,109
)
Other income
(228
)
(64
)
(347
)
(473
)
Income tax expense (benefit)
2,603

671

4,538

1,247

Alagasco income (loss) from discontinued operations
(4,896
)
(1,808
)
34,949

44,467

Energen income (loss) from discontinued operations
97

2,453

(1,029
)
4,451

Income (loss) from discontinued operations
$
(4,799
)
$
645

$
33,920

$
48,918


2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2014, Alagasco had net pre-tax reductions in revenues of $4.0 million and $20.3 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. During the three months and six months ended June 30, 2013, Alagasco had net pre-tax reductions in revenues of $3.8 million and $6.3 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, an $8.5 million decrease, $10.3 million increase and $7.8 million increase in revenues became effective January 1, 2014, December 1, 2013 and 2012, respectively. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The APSC approved the sale of Alagasco to Laclede, and the order for approval to transfer one hundred percent ownership of common stock of Alagasco from Energen to Laclede was signed on July 24, 2014. This sale is expected to close during 2014.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

3. 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.

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.

9


Additionally, Energen is at risk of economic loss based upon the creditworthiness of our counterparties. We were in a net gain position with two of our active counterparties and in a net loss position with the remaining twelve at June 30, 2014. The counterparty net gain positions at June 30, 2014 constituted approximately $1.0 million.
Energen’s current policy is to not enter into agreements that require the posting of collateral. The majority of our counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, Energen used cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income as a component of shareholders’ equity and subsequently reclassified as gain (loss) on derivative instruments, net when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized immediately in gain (loss) on derivative instruments, net. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net.

Effective March 31, 2013 and June 30, 2013, Energen dedesignated from cash flow hedge accounting 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various New York Mercantile Exchange (NYMEX) oil contracts associated with the Permian Basin due to lack of correlation. Gains and losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Subsequent gains or losses will be accounted for as mark-to-market transactions and recognized immediately through gain (loss) on derivative instruments, net.

Effective June 30, 2013, Energen elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through gain (loss) on derivative instruments, net. As a result of Energen’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in the period of change in gain (loss) on derivative instruments, net.

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, 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
$
14,540

$
(14,016
)
$
524

$
—

$
—

$
524

Noncurrent derivative instruments
2,076

(1,453
)
623

—

—

623

Total derivative assets
16,616

(15,469
)
1,147

—

—

1,147

Liabilities
 
 
 
 
 
 
Derivative instruments
110,229

(14,016
)
96,213

—

—

96,213

Noncurrent derivative instruments
23,158

(1,453
)
21,705

—

—

21,705

Total derivative liabilities
133,387

(15,469
)
117,918

—

—

117,918

Total derivatives
$
(116,771
)
$
—

$
(116,771
)
$
—

$
—

$
(116,771
)


10


(in thousands)
December 31, 2013
 
 
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
$
36,223

$
(18,760
)
$
17,463

$
—

$
—

$
17,463

Noncurrent derivative instruments
7,992

(2,553
)
5,439

—

—

5,439

Total derivative assets
44,215

(21,313
)
22,902

—

—

22,902

Liabilities
 
 
 
 
 
 
Derivative instruments
49,062

(18,760
)
30,302

—

—

30,302

Noncurrent derivative instruments
2,553

(2,553
)
—

—

—

—

Total derivative liabilities
51,615

(21,313
)
30,302

—

—

30,302

Total derivatives
$
(7,400
)
$
—

$
(7,400
)
$
—

$
—

$
(7,400
)

Energen had a net $4.5 million and a net $8.2 million deferred tax liability included in current deferred income taxes on the balance sheets related to derivative items included in accumulated other comprehensive income as of June 30, 2014, and December 31, 2013, respectively.

The following table details 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
Three months
ended
June 30, 2013
Net gain recognized in other comprehensive income on derivatives (effective portion), net of tax of $6 and $9,713
—
$
9

$
15,847

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

$
3,112

Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)
Gain (loss) on derivative instruments, net
$
—

$
1,392


(in thousands)
Location on Statements of Income
Six months
ended
June 30, 2014
Six months
ended
June 30, 2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $7 and ($6,712)
—
$
11

$
(10,951
)
Gain reclassified from accumulated other comprehensive income into income (effective portion)
Gain (loss) on derivative instruments, net
$
9,789

$
20,935

Gain recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)
Gain (loss) on derivative instruments, net
$
—

$
858





11


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

(in thousands)
Location on Statements of Income
Three months
ended
June 30, 2014
Three months
ended
June 30, 2013
Gain (loss) recognized in income on derivatives
Gain (loss) on derivative instruments, net
$
(90,581
)
$
53,078


(in thousands)
Location on Statements of Income
Six months
ended
June 30, 2014
Six months
ended
June 30, 2013
Gain (loss) recognized in income on derivatives
Gain (loss) on derivative instruments, net
$
(148,026
)
$
21,577


As of June 30, 2014, $7.3 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as revenues during the next twelve-month period. During 2013, we had a discontinuance of hedge accounting when Energen determined it was probable certain forecasted volumes would not occur due to certain properties being sold. This discontinuance of hedge accounting resulted in $3.0 million of after-tax losses being recognized into gain (loss) on derivative instruments, net during the six months ended June 30, 2014.

As of June 30, 2014, Energen had entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period
Total Hedged Volumes
Average Contract
Price

Description
Oil
 
 
 
2014
4,958
 MBbl
$92.65 Bbl
NYMEX Swaps
2015
8,280
 MBbl
$89.30 Bbl
NYMEX Swaps
Oil Basis Differential
 
 
 
2014
600
 MBbl
$(3.30) Bbl
WTS/WTI Basis Swaps*
2014
1,200
 MBbl
$(3.08) Bbl
WTI/WTI Basis Swaps**
Natural Gas Liquids
 
 
 
2014
35.8
 MMgal
$0.93 Gal
Liquids Swaps
Natural Gas
 
 
 
2014
5.2
 Bcf
$4.56 Mcf
NYMEX Swaps
2014
15.4
 Bcf
$4.61 Mcf
Basin Specific Swaps - San Juan
2014
5.0
 Bcf
$3.81 Mcf
Basin Specific Swaps - Permian
2015
23.0
 Bcf
$4.13 Mcf
Basin Specific Swaps - San Juan
2015
6.0
 Bcf
$4.20 Mcf
Basin Specific Swaps - Permian
Natural Gas Basis Differential




2014
3.1
 Bcf
$(0.09) Mcf
San Juan Basis Swaps
2014
1.2
 Bcf
$(0.17) Mcf
Permian Basis Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
 
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
 
As of June 30, 2014, the maximum term over which Energen has hedged exposures to the variability of cash flows is through December 31, 2015.




12


4. 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 assumptions 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, 2014 or 2013.

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, 2014
(in thousands)
Level 2
Level 3
Total
Assets:
 
 
 
Derivative instruments
$
(2,992
)
$
3,516

$
524

Noncurrent derivative instruments
—

623

623

Total assets
(2,992
)
4,139

1,147

Liabilities:
 
 
 
Derivative instruments
(95,999
)
(214
)
(96,213
)
Noncurrent derivative instruments
(22,987
)
1,282

(21,705
)
Total liabilities
(118,986
)
1,068

(117,918
)
Net derivative asset (liability)
$
(121,978
)
$
5,207

$
(116,771
)

 
December 31, 2013
(in thousands)
Level 2
Level 3
Total
Assets:
 
 
 
Derivative instruments
$
(1,658
)
$
19,121

$
17,463

Noncurrent derivative instruments
4,383

1,056

5,439

Total assets
2,725

20,177

22,902

Liabilities:
 
 
 
Derivative instruments
(28,414
)
(1,888
)
(30,302
)
Total liabilities
(28,414
)
(1,888
)
(30,302
)
Net derivative asset (liability)
$
(25,689
)
$
18,289

$
(7,400
)

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

13


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, 2014, Energen had interest rate swap agreements with a notional of $190 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent. The fair value of our interest rate swaps was a $1.4 million and a $1.8 million liability at June 30, 2014 and December 31, 2013, respectively, and are classified as a Level 2 fair value liability. The fair value of our interest rate swaps are recognized on a gross basis in accounts payable on the balance sheets.

Level 3 Fair Value Instruments: Energen prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its Level 3 instruments. We estimate that a 10 percent increase or decrease in commodity prices would result in an approximate $23 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $23 million associated with open Level 3 derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by physical sales at the spot market price.

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
Three months ended
(in thousands)
June 30, 2014
June 30, 2013
Balance at beginning of period
$
1,378

$
26,459

Realized gains
785

6,183

Unrealized gains relating to instruments held at the reporting date*
3,800

23,404

Settlements during period
(756
)
(4,915
)
Balance at end of period
$
5,207

$
51,131


 
Six months ended
Six months ended
(in thousands)
June 30, 2014
June 30, 2013
Balance at beginning of period
$
18,289

$
89,019

Realized gains (losses)
(2,158
)
32,368

Unrealized losses relating to instruments held at the reporting date*
(13,111
)
(39,156
)
Settlements during period
2,187

(31,100
)
Balance at end of period
$
5,207

$
51,131

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









14


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

(in thousands, except price data)
Fair Value as of June 30, 2014
Valuation Technique*
Unobservable Input*
Range
Oil Basis - WTS/WTI
 
 
 
 
2014
$
1,119

Discounted Cash Flow
Forward Basis
($5.01) Bbl
Oil Basis - WTI/WTI
 
 
 
 
2014
$
3,072

Discounted Cash Flow
Forward Basis
($5.42 - $5.57) Bbl
Natural Gas Liquids
 
 
 
 
2014
$
91

Discounted Cash Flow
Forward Price
 $0.74 - $0.97 Gal
Natural Gas Basis - San Juan
 
 
 
 
2014
$
2,817

Discounted Cash Flow
Forward Basis
($0.03 - $0.07) Mcf
2015
$
579

Discounted Cash Flow
Forward Basis
($0.11 - $0.12) Mcf
Natural Gas Basis - Permian
 
 
 
 
2014
$
(3,073
)
Discounted Cash Flow
Forward Basis
($0.06 - $0.07) Mcf
2015
$
602

Discounted Cash Flow
Forward Basis
($0.13) 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.

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. The fair value of Energen’s long-term debt, including the current portion, was approximately $1,148.7 million and $1,161.9 million and had a carrying value of $1,124.0 million and $1,154.0 million at June 30, 2014 and December 31, 2013, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $266.6 million and $258.8 million and had a carrying value of $249.8 million and $249.9 million at June 30, 2014 and December 31, 2013, 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.

5. RECONCILIATION OF EARNINGS PER SHARE (EPS)

 
Three months ended
Three months ended
(in thousands, except per share amounts)
June 30, 2014
June 30, 2013
 
Net
 
Per Share
Net
 
Per Share
 
Income
Shares
Amount
Income
Shares
Amount
Basic EPS
$
(7,953
)
72,851

$
(0.11
)
$
83,067

72,167

$
1.15

Effect of dilutive securities
 
 
 
 
 
 
Stock options
 
—

 
 
225

 
Non-vested restricted stock
 
—

 
 
16

 
Performance share awards
 
—

 
 
11

 
Diluted EPS
$
(7,953
)
72,851

$
(0.11
)
$
83,067

72,419

$
1.15


In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. Energen had 337,614 of excluded shares for the three months ended June 30, 2014.


15


 
Six months ended
Six months ended
(in thousands, except per share amounts)
June 30, 2014
June 30, 2013
 
Net
 
Per Share
Net
 
Per Share
 
Income
Shares
Amount
Income
Shares
Amount
Basic EPS
$
45,363

72,737

$
0.62

$
139,759

72,155

$
1.94

Effect of dilutive securities
 
 
 
 
 
 
Stock options
 
165

 
 
164

 
Non-vested restricted stock
 
48

 
 
10

 
Performance share awards
 
81

 
 
—

 
Diluted EPS
$
45,363

73,031

$
0.62

$
139,759

72,329

$
1.93


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)
2014
2013
 
2014
2013
Stock options
114

316

 
114

687

Performance share awards
4

—

 
68

161


6. STOCK COMPENSATION

Stock Incentive Plan
Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options and non-qualified stock options to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Energen common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. Energen granted 107,868 non-qualified option shares during the first quarter of 2014 with a grant-date fair value of $27.57. During the second quarter of 2014, Energen granted 2,439 non-qualified option shares with a grant-date fair value of $32.22.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock units. In January 2014, Energen awarded 41,664 restricted stock units with a grant-date fair value of $70.68. Energen granted 928 restricted stock units during the second quarter of 2014 with a grant-date fair value of $79.15. These awards have a three year vesting period. Energen also granted 6,312 restricted stock units during the second quarter of 2014 with a grant-date fair value of $78.99 and a two year graded vesting period. These awards 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, with each unit equal to the market value of one share of common stock, 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 287 performance share awards during the first quarter of 2014 with a two year vesting period and a grant-date fair value of $118.99. Energen also granted 63,842 performance share awards during the first quarter of 2014 with a three year vesting period and a grant-date fair value of $93.13. During the second quarter of 2014, Energen granted 650 performance share awards with a two year vesting period and a grant-date fair value of $137.11. Energen also granted 1,467 performance share awards during the second quarter of 2014 with a three year vesting period and a grant-date fair value of $109.02.

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. Energen granted 62,749 awards during the first quarter of 2014. These awards had a fair value of $42.54 as of June 30, 2014.




16


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 2014, Energen awarded 28,840 Petrotech units with a fair value of $88.55 as of June 30, 2014, none of which included a market condition. Also awarded were 36,920 Petrotech units which included a market condition and had a fair value of $122.39 as of June 30, 2014. These awards have a three year vesting period.

Stock Repurchase Program
During the three months and six months ended June 30, 2014, we had non-cash purchases of approximately $43,000 and $0.3 million, respectively, of Energen common stock in conjunction with tax withholdings on our non-qualified deferred compensation plan and other stock compensation. Energen utilized internally generated cash flows in payment of the related tax withholdings.

7. EMPLOYEE BENEFIT PLANS

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

The components of net periodic benefit cost 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)
2014
2013
2014
2013
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
1,621

$
1,327

$
3,256

$
2,654

Interest cost
1,404

1,088

2,817

2,176

Expected long-term return on assets
(1,449
)
(1,323
)
(2,909
)
(2,645
)
Actuarial loss
1,407

1,823

2,819

3,657

Prior service cost amortization
57

62

114

123

Settlement charge
115

—

3,673

144

Net periodic expense
$
3,155

$
2,977

$
9,770

$
6,109


Included in discontinued operations for the three months and six months ended June 30, 2014 was $2.6 million and $5.3 million, respectively, of net periodic benefit cost for Alagasco’s two defined benefit non-contributory pension plans and allocated costs from the Energen nonqualified supplemental pension plans. Included in discontinued operations for the three months and six months ended June 30, 2013 was $3.5 million and $7.0 million, respectively, of net periodic benefit cost for Alagasco’s two defined benefit non-contributory pension plans and allocated costs from the Energen nonqualified supplemental pension plans.

Energen anticipates required contributions of approximately $1.6 million during 2014 to the qualified pension plans. Energen expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. Energen made a discretionary contribution of $1.6 million to the qualified pension plans in January 2014. During 2014, Energen may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months and six months ended June 30, 2014, Energen made benefit payments aggregating $33,000 and $0.9 million, respectively, to retirees from the non-qualified supplemental retirement plans and expects to make additional benefit payments of approximately $5.2 million through the remainder of 2014. In the second quarter of 2014, Energen incurred settlement charges of $0.7 million for the payment of lump sums from the qualified defined benefit pension plans, of which $0.4 million was expensed and $0.3 million was recognized as a pension asset in regulatory assets at Alagasco. 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. In the first quarter of 2013, Energen incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension asset in regulatory assets at Alagasco.


17



Also effective April 30, 2014, Energen Corporation separated its postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco employees in accordance with ERISA provisions. Energen and Alagasco remeasured these plans using current assumptions.

The components of net periodic postretirement benefit expense for Energen’s postretirement benefit plans were as follows:



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2014
2013
2014
2013
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
59

$
112

$
119

$
223

Interest cost
224

176

450

351

Expected long-term return on assets
(383
)
(214
)
(770
)
(426
)
Actuarial loss
(209
)
—

(421
)
—

Transition amortization
15

63

30

126

Net periodic (income) expense
$
(294
)
$
137

$
(592
)
$
274


Included in discontinued operations for the three months and six months ended June 30, 2014 was $0.8 million and $1.6 million, respectively, of net periodic postretirement benefit income for Alagasco’s postretirement benefit plans. Included in discontinued operations for the three months and six months ended June 30, 2013 was $0.2 million and $0.5 million, respectively, of net periodic postretirement benefit expense for Alagasco’s postretirement benefit plans. There are no required contributions to the postretirement benefit plans during 2014.

8. 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 6 million barrels of oil equivalent (MMBOE) through September 2017.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $140 million through September 2024. During the six months ended June 30, 2014 and 2013, Alagasco recognized approximately $23.5 million and $26.0 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 115 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At June 30, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through December 2014 with an aggregate purchase price of $0.3 million and a market value of $0.3 million.

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


18


On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

Energen Resources previously disclosed an adverse judgment relating to the ownership of the Company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases. The Summary Judgment Order has been appealed by the other party.

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen, Energen Resources and Alagasco. 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 $3.4 million of which $1.9 million has been incurred and $0.5 million has been reserved. Also included is a preliminary estimate of $1 million of exposure for further remediation which may be required by the Railroad Commission and is pending further review by the Company.
During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) 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.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, Alagasco and the current site owner.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and is considering whether to enter into such a tolling arrangement. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of June 30, 2014.

New Mexico Audits: During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted 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 ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.


19


As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. Energen preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. Energen is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of June 30, 2014.

9. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)
June 30, 2014
December 31, 2013
Energen:
 
 
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

Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.775% at June 30, 2014), due September 30, 2014 to December 17, 2017
570,000

600,000

 
1,124,000

1,154,000

Less amounts due within one year
570,000

60,000

Less unamortized debt discount
448

459

Total Energen
$
553,552

$
1,093,541

Alagasco:
 
 
5.368% Notes, due December 1, 2015
$
80,000

$
80,000

5.20% Notes, due January 15, 2020
40,000

40,000

3.86% Notes, due December 21, 2021
50,000

50,000

5.70% Notes, due January 15, 2035
34,830

34,923

5.90% Notes, due January 15, 2037
45,000

45,000

 
249,830

249,923

Less amounts due within one year
50,000

—

Total Alagasco (included in liabilities related to assets held for sale)
$
199,830

$
249,923


The aggregate maturities of Energen’s long-term debt outstanding at June 30, 2014 are as follows:

(in thousands)
Remaining 2014
2015
2016
2017
2018
2019 and thereafter
$570,000
—
—
$19,000
—
$535,000

In December 2013, Energen issued $600 million in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31, 2014 through December 17, 2017. In conjunction with the pending sale of Alagasco, the Senior Term Loans will be repaid during

20


2014. In addition, Alagasco’s 3.86 percent Notes, due December 21, 2021 may be required to be repaid upon the sale of Alagasco as specified under certain covenants.

The long-term debt and short-term debt agreements of Energen and Alagasco 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 covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of Energen’s and Alagasco’s debt is unsecured.

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, Energen Resources or Alagasco will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.

Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.

Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Energen Resources or Alagasco will constitute an event of default by Energen. Under the Alagasco credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.

Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted 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 and Alagasco were in compliance with the terms of their respective credit facilities as of June 30, 2014.

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

(in thousands)
June 30, 2014
December 31, 2013
Energen notes payable to banks
$
669,000

$
489,000

Available for borrowings
581,000

761,000

Total Energen
$
1,250,000

$
1,250,000

Energen maximum amount outstanding at any month-end
$
669,000

$
901,000

Energen average daily amount outstanding
$
576,486

$
804,895

Energen weighted average interest rates based on:
 
 
Average daily amount outstanding
1.42
%
1.38
%
Amount outstanding at period-end
1.40
%
1.32
%

Energen’s interest expense was $8.0 million and $15.9 million for the three months and six months ended June 30, 2014, respectively. Interest expense for Energen was $10.2 million and $20.1 million for the three months and six months ended June 30, 2013, respectively. For the three months and six months ended June 30, 2014, Energen’s total interest expense included capitalized interest of $37,000. Energen’s total interest expense for the three months and six months ended June 30, 2013 included capitalized interest expense of $34,000 and $0.2 million. At June 30, 2014, Energen paid commitment fees on the unused portion of available credit facilities of 25 basis points per annum. See Note 1, Organization and Basis of Presentation, for further information regarding interest on debt required to be extinguished, associated with the pending sale of Alagasco, which was classified to discontinued operations.

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

21


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 unproved properties in the balance sheets. If the exploratory well is determined to be impaired, the impaired costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

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

 
Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2014
2013
2014
2013
Capitalized exploratory well costs at beginning of period
$
109,968

$
106,175

$
57,600

$
79,791

Additions pending determination of proved reserves
200,347

123,719

365,189

219,580

Reclassifications due to determination of proved reserves
(142,666
)
(157,722
)
(255,140
)
(227,199
)
Exploratory well costs charged to expense
(1,191
)
—

(1,191
)
—

Capitalized exploratory well costs at end of period
$
166,458

$
72,172

$
166,458

$
72,172





The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:

 
Six months ended
Six months ended
(in thousands)
June 30, 2014
June 30, 2013
Exploratory wells in progress
$
35,753

$
25,728

Capitalized exploratory well costs capitalized for a period of one year or less
129,477

45,245

Capitalized exploratory well costs for a period greater than one year
1,228

1,199

Total capitalized exploratory well costs
$
166,458

$
72,172


At June 30, 2014, Energen had 56 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are located primarily in the Permian Basin. Energen has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

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 for the six months ended June 30, 2014:


22


(in thousands)
 
Balance as of December 31, 2013
$
108,533

Liabilities incurred
1,504

Liabilities settled
(676
)
Accretion expense
3,726

Balance as of June 30, 2014
$
113,087



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)
Cash Flow Hedges
Pension and Postretirement Plans
Total
Balance as of December 31, 2013
$
12,178

$
(32,245
)
$
(20,067
)
Other comprehensive income (loss) before reclassifications
(287
)
(2,136
)
(2,423
)
Amounts reclassified from accumulated other comprehensive income (loss)
(4,748
)
6,739

1,991

Change in accumulated other comprehensive income (loss)
(5,035
)
4,603

(432
)
Balance as of June 30, 2014
$
7,143

$
(27,642
)
$
(20,499
)

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
 
Three months ended
Three months ended
 
 
June 30, 2014
June 30, 2013
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains (losses) on cash flow hedges:
 
 
 
Commodity contracts
$
5,735

$
4,503

Gain (loss) on derivative instruments, net
Interest rate swap
(1,588
)
(426
)
Interest expense
Total cash flow hedges
4,147

4,077

 
Income tax expense
(1,623
)
(1,562
)
 
Net of tax
2,524

2,515

 
Pension and postretirement plans:
 
 
 
Transition obligation
(9
)
(74
)
General and administrative
Prior service cost
(74
)
(78
)
General and administrative
Actuarial losses
(1,289
)
(2,097
)
General and administrative
Actuarial losses on settlement charges
(360
)
—

General and administrative
Total pension and postretirement plans
(1,732
)
(2,249
)
 
Income tax expense
606

788

 
Net of tax
(1,126
)
(1,461
)
 
Total reclassifications for the period
$
1,398

$
1,054

 


23


 
Six months ended
Six months ended
 
 
June 30, 2014
June 30, 2013
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains (losses) on cash flow hedges:
 
 
 
Commodity contracts
$
9,789

$
21,792

Gain (loss) on derivative instruments, net
Interest rate swap
(2,033
)
(836
)
Interest expense
Total cash flow hedges
7,756

20,956

 
Income tax expense
(3,008
)
(7,989
)
 
Net of tax
4,748

12,967

 
Pension and postretirement plans:
 
 
 
Transition obligation
(19
)
(147
)
General and administrative
Prior service cost
(148
)
(157
)
General and administrative
Actuarial losses*
(2,580
)
(4,350
)
General and administrative
Actuarial losses on settlement charges
(7,622
)
—

General and administrative
Actuarial losses on settlement charges*
—

(375
)
Assets held for sale as of June 30, 2014 with prior period comparable
Total pension and postretirement plans
(10,369
)
(5,029
)
 
Income tax expense
3,630

1,761

 
Net of tax
(6,739
)
(3,268
)
 
Total reclassifications for the period
$
(1,991
)
$
9,699

 
* In the first quarter of 2013, Energen incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was recognized in actuarial losses above and $0.4 million was recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

13. DISCONTINUED OPERATIONS

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to Laclede for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use 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 with prior period comparable and reflected the associated operating results in discontinued operations. Our results of operations for the three months and six months ended June 30, 2014 and 2013 and our financial position as of June 30, 2014 and December 31, 2013 presented in our unaudited consolidated financial statements and these notes reflect Alagasco as discontinued operations.

In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). 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 natural gas and oil 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 six months ended June 30, 2014. Energen also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified

24


as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

The following tables detail held for sale properties by major classes of assets and liabilities:

(in thousands)
 
June 30, 2014

Alabama Gas Corporation
Black Warrior Basin
North Louisiana/East Texas

Total
Cash
$
11,807

$
—

$
—

$
11,807

Accounts receivable*
50,285

—

—

50,285

Inventories
39,950

—

—

39,950

Utility plant
1,517,534

—

—

1,517,534

Less accumulated depreciation
(624,704
)
—

—

(624,704
)
Other property, net
40

—

—

40

Other current assets*
16,462

—

—

16,462

Other long-term assets
142,672

—

—

142,672

Total assets held for sale
1,154,046

—

—

1,154,046

Accounts payable
(38,646
)
(2,172
)
(1,856
)
(42,674
)
Royalty payable
—

—

(1,284
)
(1,284
)
Accrued taxes*
(29,337
)
—

—

(29,337
)
Long-term debt due within one year
(50,000
)
—

—

(50,000
)
Other current liabilities
(108,633
)
—

(2
)
(108,635
)
Other long-term liabilities
(335,369
)
—

(2
)
(335,371
)
Long-term debt
(199,830
)
—

—

(199,830
)
Total liabilities held for sale
(761,815
)
(2,172
)
(3,144
)
(767,131
)
Total net assets held for sale
$
392,231

$
(2,172
)
$
(3,144
)
$
386,915


25


(in thousands)
 
December 31, 2013
 
Alabama Gas Corporation
Black Warrior Basin
North Louisiana/East Texas

Total
Cash
$
3,032

$
—

$
—

$
3,032

Accounts receivable*
103,748

2,829

1,272

107,849

Inventories
41,200

—

68

41,268

Oil and gas properties
—

—

348,379

348,379

Less accumulated depreciation, depletion and amortization
—


(301,609
)
(301,609
)
Utility plant
1,491,433

—

—

1,491,433

Less accumulated depreciation
(605,924
)
—

—

(605,924
)
Other property, net
41

—

165

206

Other current assets*
29,458

—

—

29,458

Other long-term assets
128,780

—

—

128,780

Total assets held for sale
1,191,768

2,829

48,275

1,242,872

Accounts payable
(48,653
)
(1,732
)
(11
)
(50,396
)
Royalty payable
—

(550
)
(869
)
(1,419
)
Accrued taxes
(28,027
)
—

—

(28,027
)
Notes payable to banks
(50,000
)
—

—

(50,000
)
Other current liabilities*
(105,013
)
(379
)
(21
)
(105,413
)
Other long-term liabilities
(331,409
)
—

(14,983
)
(346,392
)
Long-term debt
(249,923
)
—

—

(249,923
)
Total liabilities held for sale
(813,025
)
(2,661
)
(15,884
)
(831,570
)
Total net assets held for sale
$
378,743

$
168

$
32,391

$
411,302

*At June 30, 2014, Alagasco’s accounts receivable, other current assets and accrued taxes included consolidating adjustments of $13.2 million to adjust for affiliated companies receivables and a $7.9 million reclassification from accrued taxes to other current assets. At December 31, 2013, Alagasco’s accounts receivable included a consolidating adjustment of $4.7 million to adjust for affiliated companies receivables. Certain other current assets and other current liabilities at Alagasco of $1.6 million and $0.5 million, respectively, were reclassified to continuing operations at Energen.

We recognized interest on debt required to be extinguished in connection with the pending sale of Alagasco as discontinued operations. During 2014, we will enter into a new credit facility. We expect this credit facility to be secured by assets of Energen and its subsidiaries. The interest associated with the five-year syndicated unsecured credit facilities was also classified as discontinued operations. See Note 1, Organization and Basis of Presentation, for further information regarding adjustments associated with the pending sale of Alagasco.

Gains and losses on the sale of certain oil and gas properties as well as any impairments of properties held for sale are reported as discontinued operations, with income or loss from operations of the associated assets reported as income or loss from discontinued operations. The results of operations for certain held for sale assets were reclassified and reported as discontinued operations for all prior periods presented. Energen may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held for sale are reported at the lower of the carrying amount or fair value.


26


 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands, except per share data)
2014
2013
2014
2013
Natural gas distribution revenues
$
93,873

$
104,514

$
357,774

$
342,199

Oil and natural gas revenues
390

18,562

5,211

37,225

Total revenues
$
94,263

$
123,076

$
362,985

$
379,424

Pretax income (loss) from discontinued operations
$
(7,797
)
$
967

$
54,519

$
78,775

Income tax expense (benefit)
(2,998
)
322

20,599

29,857

Income (Loss) From Discontinued Operations
$
(4,799
)
$
645

$
33,920

$
48,918

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
)
$
645

$
32,870

$
48,918

Diluted Earnings Per Average Common Share
 
 
 
 
Income (Loss) from Discontinued Operations
$
(0.07
)
$
0.01

$
0.46

$
0.67

Loss on Disposal of Discontinued Operations
—

—

(0.01
)
—

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

$
0.45

$
0.67

Basic Earnings Per Average Common Share
 
 
 
 
Income (Loss) from Discontinued Operations
$
(0.07
)
$
0.01

$
0.46

$
0.68

Loss on Disposal of Discontinued Operations
—

—

(0.01
)
—

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

$
0.45

$
0.68


14. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (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 is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. Energen is currently evaluating the impact of this ASU.

27


ALABAMA GAS CORPORATION
 
 
 
STATEMENTS OF INCOME
 
 
 
(Unaudited)
 
 
 
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands)
2014
2013
 
2014
2013
Operating Revenues
$
93,873

$
104,514

 
$
357,774

$
342,199

Operating Expenses
 
 
 
 
 
Cost of gas
38,468

47,571

 
166,582

143,013

Operations and maintenance
34,771

36,005

 
70,995

74,022

Depreciation and amortization
11,445

10,873

 
22,770

21,602

Income taxes
 
 
 
 
 
Current
(687
)
(1,778
)
 
24,530

24,143

Deferred
227

1,335

 
1,494

4,355

Taxes, other than income taxes
7,243

7,846

 
23,130

22,050

Total operating expenses
91,467

101,852

 
309,501

289,185

Operating Income
2,406

2,662

 
48,273

53,014

Other Income (Expense)
 
 
 
 
 
Allowance for funds used during construction
62

227

 
135

446

Other income
1,090

361

 
2,598

1,111

Other expense
(428
)
(121
)
 
(883
)
(190
)
Total other income
724

467

 
1,850

1,367

Interest Expense
 
 
 
 
 
Interest on long-term debt
3,375

3,377

 
6,752

6,755

Other interest expense
370

456

 
958

1,108

Total interest expense
3,745

3,833

 
7,710

7,863

Net Income (Loss)
$
(615
)
$
(704
)
 
$
42,413

$
46,518


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

28


ALABAMA GAS CORPORATION
 
 
BALANCE SHEETS
 
 
(Unaudited)
 
 
 
 
 
(in thousands)
June 30, 2014
December 31, 2013
ASSETS
 
 
Property, Plant and Equipment
 
 
Utility plant
$
1,517,534

$
1,491,433

Less accumulated depreciation
624,704

605,924

Utility plant, net
892,830

885,509

Other property, net
40

41

Current Assets
 
 
Cash
11,807

3,032

Accounts receivable
 
 
Gas
49,938

103,301

Other
5,347

5,447

Affiliated companies
13,172

4,662

Allowance for doubtful accounts
(5,000
)
(5,000
)
Inventories
 
 
Storage gas inventory
31,975

32,095

Materials and supplies
5,098

5,471

Liquified natural gas in storage
2,877

3,634

Regulatory assets
2,316

2,756

Income tax receivable
—

3,644

Deferred income taxes
21,095

20,049

Prepayments and other
987

4,654

Total current assets
139,612

183,745

Other Assets
 
 
Regulatory assets
91,857

84,890

Other postretirement assets
28,985

26,457

Deferred charges and other
21,830

17,433

Total other assets
142,672

128,780

TOTAL ASSETS
$
1,175,154

$
1,198,075


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








29


ALABAMA GAS CORPORATION
 
 
BALANCE SHEETS
 
 
(Unaudited)
 
 
 
 
 
(in thousands, except share data)
June 30, 2014
December 31, 2013
LIABILITIES AND CAPITALIZATION
 
 
Capitalization
 
 
Preferred stock, cumulative, $0.01 par value, 120,000 shares authorized
$
—

$
—

Common shareholder’s equity
 
 
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at June 30, 2014 and December 31, 2013
20

20

Premium on capital stock
31,682

31,682

Capital surplus
2,802

2,802

Retained earnings
370,899

350,076

Total common shareholder’s equity
405,403

384,580

Long-term debt
199,830

249,923

Total capitalization
605,233

634,503

Current Liabilities
 
 
Long-term debt due within one year
50,000

—

Notes payable to banks
—

50,000

Accounts payable
38,646

48,653

Accrued taxes
37,273

28,027

Customer deposits
20,102

21,692

Amounts due customers
9,556

16,990

Accrued wages and benefits
4,519

7,682

Regulatory liabilities
64,401

49,006

Other
10,055

10,113

Total current liabilities
234,552

232,163

Deferred Credits and Other Liabilities
 
 
Deferred income taxes
208,171

205,631

Pension liabilities
28,479

20,191

Regulatory liabilities
82,580

94,125

Other
16,139

11,462

Total deferred credits and other liabilities
335,369

331,409

Commitments and Contingencies




TOTAL LIABILITIES AND CAPITALIZATION
$
1,175,154

$
1,198,075


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

30


ALABAMA GAS CORPORATION
 
 
STATEMENTS OF CASH FLOWS
 
 
(Unaudited)
 
 
 
 
 
Six months ended June 30, (in thousands)
2014
2013
Operating Activities
 
 
Net income
$
42,413

$
46,518

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
22,770

21,602

Deferred income taxes
1,494

4,355

Bad debt expense
910

450

Gain on sale of assets
(703
)
—

Other, net
(141
)
7,083

Net change in:
 
 
Accounts receivable
15,172

8,179

Inventories
1,250

11,512

Accounts payable
(7,185
)
(6,828
)
Amounts due customers, including gas supply pass-through
33,839

26,797

Income tax receivable
3,644

2,762

Pension and other postretirement benefit contributions
(1,590
)
(5,600
)
Other current assets and liabilities
8,101

16,863

Net cash provided by operating activities
119,974

133,693

Investing Activities
 
 
Additions to property, plant and equipment
(31,703
)
(44,679
)
Net increases (decreases) in advances from affiliates
(8,510
)
2,378

Proceeds from sale of assets
797

—

Other, net
(100
)
(500
)
Net cash used in investing activities
(39,516
)
(42,801
)
Financing Activities
 
 
Payment of dividends on common stock
(21,590
)
(18,876
)
Reduction of long-term debt
(93
)
(10
)
Net change in short-term debt
(50,000
)
(77,000
)
Net cash used in financing activities
(71,683
)
(95,886
)
Net change in cash and cash equivalents
8,775

(4,994
)
Cash and cash equivalents at beginning of period
3,032

5,559

Cash and cash equivalents at end of period
$
11,807

$
565


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

31


CONDENSED NOTES TO UNAUDITED FINANCIAL STATEMENTS
ALABAMA GAS CORPORATION
 
 
 
 
 

1. BASIS OF PRESENTATION

Alabama Gas Corporation (Alagasco) is a wholly owned subsidiary of Energen Corporation. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2013, 2012 and 2011, included in the 2013 Annual Report of Energen Corporation (Energen) and Alabama Gas Corporation on Form 10-K 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. Alagasco’s natural gas distribution business is seasonal in character and influenced by weather conditions, and therefore, the results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2014, Alagasco had net pre-tax reductions in revenues of $4.0 million and $20.3 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. During the three months and six months ended June 30, 2013, Alagasco had net pre-tax reductions in revenues of $3.8 million and $6.3 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, an $8.5 million decrease, $10.3 million increase and $7.8 million increase in revenues became effective January 1, 2014, December 1, 2013 and 2012, respectively. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The APSC approved the sale of Alagasco to Laclede, and the order for approval to transfer one hundred percent ownership of common stock of Alagasco from Energen to Laclede was signed on July 24, 2014. This sale is expected to close during 2014.

The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75 percent (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. During the second quarter of 2014, Alagasco recorded an increase to revenue of approximately $1.0 million pre-tax to reflect an estimated O&M expense benefit resulting from being below the Index Range. This estimate was based on actual O&M expense through June 2014, and budgeted O&M expense through September 2014.


32


Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, which is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year. Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which prescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco expects to be able to recover underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

3. EMPLOYEE BENEFIT PLANS

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

The components of net periodic benefit cost for Alagasco’s two defined benefit non-contributory pension plans and allocated costs from the Energen nonqualified supplemental pension plans were as follows:



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2014
2013
2014
2013
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
1,696

$
2,176

$
3,393

$
4,352

Interest cost
1,439

1,612

2,878

3,225

Expected long-term return on assets
(1,679
)
(2,315
)
(3,359
)
(4,632
)
Actuarial loss
1,110

1,937

2,220

3,878

Prior service cost amortization
71

72

143

144

Net periodic expense
$
2,637

$
3,482

$
5,275

$
6,967


Alagasco anticipates required contributions of approximately $2.9 million during 2014 to the qualified pension plans. Alagasco expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. Alagasco made a discretionary contribution of $1.4 million to the qualified pension plans in January 2014. During 2014, Alagasco may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. In the first quarter of 2014, Alagasco incurred a settlement charge of $10.2 million for the payment of lump sums from the qualified defined benefit pension plans which was recognized as a pension asset in regulatory assets at Alagasco.

Also effective April 30, 2014, Energen Corporation separated its postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco employees in accordance with ERISA provisions. Energen and Alagasco remeasured these plans using current assumptions.






33


The components of net periodic postretirement benefit (income) expense for Alagasco’s postretirement benefit plans were as follows:



Three months ended
June 30,
Six months ended
June 30,
(in thousands)
2014
2013
2014
2013
Components of net periodic benefit cost:
 
 
 
 
Service cost
$
132

$
314

$
265

$
629

Interest cost
614

664

1,227

1,328

Expected long-term return on assets
(1,172
)
(994
)
(2,343
)
(1,989
)
Actuarial loss
(388
)
—

(777
)
—

Transition amortization
17

251

34

502

Net periodic (income) expense
$
(797
)
$
235

$
(1,594
)
$
470


There are no required contributions to the postretirement benefit plans during 2014.

4. COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $140 million through September 2024. During both the six months ending June 30, 2014 and 2013, Alagasco recognized approximately $23.5 million and $26.0 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 115 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At June 30, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through December 2014 with an aggregate purchase price of $0.3 million with a market value of $0.3 million.

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

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, Alagasco and the current site owner.


34


In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35th Avenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and is considering whether to enter into such a tolling arrangement. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of June 30, 2014.

5. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

(in thousands)
June 30, 2014
December 31, 2013
5.368% Notes, due December 1, 2015
$
80,000

$
80,000

5.20% Notes, due January 15, 2020
40,000

40,000

3.86% Notes, due December 21, 2021
50,000

50,000

5.70% Notes, due January 15, 2035
34,830

34,923

5.90% Notes, due January 15, 2037
45,000

45,000

 
249,830

249,923

Less amounts due within one year
50,000

—

Total
$
199,830

$
249,923


The aggregate maturities of Alagasco’s long-term debt outstanding at June 30, 2014 are as follows:

(in thousands)
 
Remaining 2014
2015
2016
2017
2018
2019 and thereafter
$50,000
$80,000
—
—
—
$119,830

Alagasco’s 3.86 percent Notes due December 21, 2021 may be required to be repaid upon the sale of Alagasco as specified under certain covenants.

The long-term debt and short-term debt agreements of Alagasco 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 covenants or events of default based on credit ratings, the interest rates applicable to the Alagasco syndicated credit facility discussed below may adjust based on credit rating changes. All of Alagasco’s debt is unsecured.

Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. The Indenture does not include a restriction on the payment of dividends.

Alagasco Credit Facility: On October 30, 2012, Alagasco entered into a $100 million five-year syndicated unsecured credit facility (syndicated credit facility) with domestic and foreign lenders. Borrowings under the credit facility are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under the credit facility are classified as short term obligations in the accompanying financial statements. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under the short-term credit facility.


35


The financial covenants of the Alagasco credit facility limit Alagasco to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default. Also under the credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.

Upon an uncured event of default under the credit facility, all amounts owing under the defaulted 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. Alagasco was in compliance with the terms of its credit facility as of June 30, 2014.

The following is a summary of information relating to the credit facility:

(in thousands)
June 30, 2014
December 31, 2013
Notes payable to banks
$
—

$
50,000

Available for borrowings
100,000

50,000

Total
$
100,000

$
100,000

Alagasco maximum amount outstanding at any month-end
$
55,000

$
75,000

Alagasco average daily amount outstanding
$
17,956

$
35,027

Alagasco weighted average interest rates based on:
 
 
Average daily amount outstanding
1.28
%
1.12
%
Amount outstanding at period-end
—
%
1.26
%

Total interest expense for Alagasco was $3.7 million and $7.7 million for the three months and six months ended June 30, 2014, respectively. Alagasco’s total interest expense was $3.8 million and $7.9 million for the three months and six months ended June 30, 2013, respectively. At June 30, 2014, Alagasco paid commitment fees on the unused portion of available credit facilities of 15 basis points per annum.

6. FINANCIAL INSTRUMENTS

The stated value of cash, accounts receivable (net of allowance) and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $266.6 million and $258.8 million and had a carrying value of $249.8 million and $249.9 million at June 30, 2014 and December 31, 2013, 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.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At June 30, 2014 and December 31, 2013, Alagasco’s finance receivable totaled $10.6 million and $10.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to a third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.3 million and $0.4 million as of June 30, 2014 and December 31, 2013, respectively.










36


The following table sets forth a summary of changes in the allowance for credit losses as follows:

(in thousands)
 
Allowance for credit losses as of December 31, 2013
$
423

Provision
(118
)
Allowance for credit losses as of June 30, 2014
$
305


7. REGULATORY ASSETS AND LIABILITIES    

The following table details regulatory assets and liabilities on the balance sheets:

(in thousands)
June 30, 2014
December 31, 2013
 
Current
Noncurrent
Current
Noncurrent
Regulatory assets:
 
 
 
 
Pension assets
$
1,284

$
65,627

$
325

$
58,243

Accretion and depreciation of asset retirement obligations
—

18,825

—

18,046

Rate recovery of asset removal costs, net
—

3,405

—

4,601

Enhanced stability reserve
—

4,000

—

4,000

Gas supply adjustment
—

—

2,406

—

RSE adjustment
1,032

—

25

—

Total regulatory assets
$
2,316

$
91,857

$
2,756

$
84,890

Regulatory liabilities:
 
 
 
 
RSE adjustment
$
18,578

$
—

$
4,690

$
—

Unbilled service margin
6,445

—

28,504

—

Postretirement liabilities
—

26,948

—

26,197

Gas supply adjustment
25,985

—

—

—

Refundable negative salvage
13,360

26,760

15,779

39,663

Asset retirement obligation
—

28,152

—

27,528

Other
33

720

33

737

Total regulatory liabilities
$
64,401

$
82,580

$
49,006

$
94,125


8. ASSET RETIREMENT OBLIGATIONS

Alagasco recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. 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. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to Alagasco.

Alagasco recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $28.2 million and $27.5 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of June 30, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $3.4 million and $4.6 million as of June 30, 2014 and December 31, 2013, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.






37


9. DISPOSITION OF PROPERTIES

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. Alagasco received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

In the second quarter of 2014, Alagasco sold property in Tuscaloosa resulting in a gain of approximately $0.7 million pre-tax, which was recorded in other income.

10. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (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 is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. Alagasco is currently evaluating the impact of this ASU.

38


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 gas exploration and production company primarily engaged in the exploration, development and production of oil and gas properties in the Permian Basin in west Texas and in the San Juan Basin in New Mexico and Colorado in the continental United States. Our operations are conducted substantially through our subsidiary Energen Resources Corporation (Energen Resources). Energen is currently complemented by its legacy natural gas distribution business, Alabama Gas Corporation (Alagasco), which is engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama.

Our strategy is to grow our oil and gas operations largely through the acquisition, exploration and development of proved and unproved reserves with exploration primarily focused in and around the basins in which we operate. Energen focuses on increasing production and reserves through development well drilling, exploration, behind-pipe recompletions, pay-adds, workovers, secondary recovery and operational enhancements. We prefer to operate our properties in order to better control the nature and pace of drilling and development activities. All oil, natural gas liquids and natural gas production is sold to third parties. Energen also provides operating services in the Permian and San Juan basins for its joint interests. These services include 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 2014 Results and Activities
During the second quarter of 2014 as compared to the same period in the prior year, we:
•
increased revenues from the sale of oil, natural gas liquids and natural gas by 13.9 percent;
•
increased production volumes from continuing operations by 8.2 percent;
•
expanded our activities in the Permian Basin by increasing production by 755 MBOE and
•
classified Alagasco as held for sale and reflected the associated operating results in discontinued operations.

During the six months ended June 30, 2014 as compared to the same period in the prior year, we:
•
increased revenues from the sale of oil, natural gas liquids and natural gas by 24.6 percent;
•
increased production volumes from continuing operations by 10.9 percent and
•
expanded our activities in the Permian Basin by increasing production 1,688 MBOE.

Quarter ended June 30, 2014 vs quarter ended June 30, 2013
Energen had a net loss of $8.0 million ($0.11 per diluted share) for the three months ended June 30, 2014 as compared with net income of $83.1 million ($1.15 per diluted share) for the same period in the prior year. In the second quarter of 2014, our loss from continuing operations totaled $3.2 million ($0.04 per diluted share) as compared with income from continuing operations of $82.4 million ($1.14 per diluted share) in the same period a year ago. Loss from discontinued operations for the current quarter was $4.8 million ($0.07 per diluted share) as compared with income of $0.6 million ($0.01 per diluted share) from the prior-year second quarter. This decrease in income from continuing operations was primarily the result of:

•
year-over-year after-tax $73.6 million loss on open derivatives not designated as hedges (resulting from an after-tax $38.1 million non-cash loss on open derivatives for the first quarter of 2014 and an after-tax $35.5 million non-cash gain on open derivatives for the first quarter of 2013);
•
higher depreciation, depletion and amortization (DD&A) expense (approximately $15.3 million after-tax);
•
higher oil, natural gas liquids and natural gas production expense (approximately $3.3 million after-tax);
•
higher production and ad valorem taxes (approximately $2.9 million after-tax) and
•
increased general and administrative expense (approximately $3.8 million after-tax)
partially offset by:
•
higher oil and natural gas liquids production volumes (approximately $18.1 million after-tax) and
•
higher commodity prices (approximately $9.9 million after-tax).



39


Six months ended June 30, 2014 vs six months ended June 30, 2013
For the 2014 year-to-date, Energen’s net income totaled $45.4 million ($0.62 per diluted share) as compared to net income of $139.8 million ($1.93 per diluted share) for the same period in the prior year. For the six months ended June 30, 2014, our income from continuing operations totaled $12.5 million ($0.17 per diluted share) and compared with income from continuing operations of $90.8 million ($1.26 per diluted share) in the same period a year ago. Discontinued operations generated income for the current year-to-date period of $32.9 million ($0.45 per diluted share) as compared with income of $48.9 million ($0.67 per diluted share) from the same period a year ago. This decrease in income from continuing operations was primarily the result of:

•
year-over-year after-tax $69.2 million loss on open derivatives not designated as hedges (resulting from an after-tax $59.7 million non-cash loss on open derivatives for the first six months of 2014 and an after-tax $9.5 million non-cash gain on open derivatives for the first six months of 2013);
•
higher depreciation, depletion and amortization expense (approximately $34 million after-tax);
•
increased exploration expense (approximately $6.7 million after-tax);
•
increased oil, natural gas liquids and natural gas production expense (approximately $4.5 million after-tax);
•
increased production and ad valorem taxes (approximately $5.4 million after-tax) and
•
higher general and administrative expense (approximately $6.4 million after-tax)

partially offset by:

•
higher production volumes (approximately $46.7 million after-tax) and
•
increased oil, natural gas liquids and natural gas commodity prices (approximately $42.4 million after-tax).

2014 Outlook
2014 Sale of Alagasco: In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

2014 Debt Issuance/Pay Down: In conjunction with the pending sale of Alagasco, Energen and Alagasco’s five-year syndicated credit facilities (syndicated credit facilities) and the Senior Term Loans are required to be repaid at close. We will enter into a new credit facility concurrent with repayment of this debt. We expect this credit facility to be secured by assets of Energen and its subsidiaries. In addition, Alagasco’s 3.86 percent Notes due December 21, 2021 may be required to be repaid by Alagasco after the sale as specified under certain covenants. We classified this debt as a current liability pending determination by the debt holders. We recognized interest on debt required to be extinguished in connection with the pending sale of Alagasco as discontinued operations.

























40


2014 Capital Budget
Energen plans to continue investing significant capital in its oil, natural gas liquids and natural gas production operations. For 2014, Energen expects its oil and gas capital spending to total approximately $1.4 billion, primarily all of which is for existing properties.

Capital expenditures by area and targeted formation during 2014 are planned as follows:

(in thousands)
2014
Permian
 
Midland Basin
 
Wolfcamp/Cline
$
665,000

Wolfberry/Other
125,000

Facilities/Other
80,000

Delaware Basin
 
3rd Bone Spring/Other
185,000

Wolfcamp
180,000

Facilities/Other
50,000

Other Permian
43,000

San Juan Basin/Other
49,000

Acquisitions/Unproved leasehold year-to-date
23,000

Total
$
1,400,000


Energen also may allocate additional capital for other oil and 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 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 its credit facilities. Energen also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has no plans for the issuance of equity.



























41


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)
2014
2013
2014
2013
Operating and production data from continuing operations








Oil, natural gas liquids and natural gas sales








Oil
$
262,746

$
234,870

$
516,505

$
425,629

Natural gas liquids
31,163

20,871

59,366

39,526

Natural gas
61,943

56,659

130,803

102,084

Total
$
355,852

$
312,400

$
706,674

$
567,239

Loss on sale of assets and other
$
(909
)
$
(663
)
$
(1,062
)
$
(215
)
Open non-cash mark-to-market gains (losses) on derivative instruments


Oil
$
(66,172
)
$
36,680

$
(87,636
)
$
28

Natural gas liquids
40

168

327

147

Natural gas
6,511

19,301

(5,993
)
14,926

Total
$
(59,621
)
$
56,149

$
(93,302
)
$
15,101

Closed gains (losses) on derivative instruments


Oil
$
(25,754
)
$
(9,076
)
$
(40,556
)
$
(1,632
)
Natural gas liquids
159

3,109

355

5,591

Natural gas
370

5,062

(4,734
)
17,228

Total
$
(25,225
)
$
(905
)
$
(44,935
)
$
21,187

Total Revenues
$
270,097

$
366,981

$
567,375

$
603,312

Production volumes
 
 
 
 
Oil (MBbl)
2,833

2,592

5,584

4,906

Natural gas liquids (MMgal)
44.7

34.2

82.7

61.8

Natural gas (MMcf)
14,676

14,742

28,800

28,560

Total production volumes (MBOE)
6,344

5,864

12,352

11,137

Average daily production volumes
 
 
 
 
Oil (MBbl/d)
31.1

28.5

30.9

27.1

Natural gas liquids (MMgal/d)
0.5

0.4

0.5

0.3

Natural gas (MMcf/d)
161.3

162.0

159.1

157.8

Total production volumes (MBOE/d)
69.7

64.4

68.2

61.5

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)
$
83.65

$
87.11

$
85.23

$
86.42

Natural gas liquids (per gallon)
$
0.70

$
0.70

$
0.72

$
0.73

Natural gas (per Mcf)
$
4.25

$
4.19

$
4.38

$
4.18

Average realized prices excluding derivatives instruments
Oil (per barrel)
$
92.74

$
90.61

$
92.50

$
86.76

Natural gas liquids (per gallon)
$
0.70

$
0.61

$
0.72

$
0.64

Natural gas (per Mcf)
$
4.22

$
3.84

$
4.54

$
3.57

Other costs per BOE
 
 
 
 
Oil, natural gas liquids and natural gas production expenses
$
10.20

$
10.16

$
10.70

$
11.24

Production and ad valorem taxes
$
4.42

$
4.01

$
4.48

$
4.21

Depreciation, depletion and amortization
$
21.31

$
19.00

$
20.93

$
18.45

Exploration expense
$
0.41

$
0.59

$
1.25

$
0.44

General and administrative
$
5.29

$
4.72

$
5.32

$
5.01


42


Revenues: Our revenues fluctuate primarily as a result of realized commodity prices, production volumes, the value of our derivative contracts and any recognized gains or losses on the sales of assets.
Our revenues are predominantly derived from the sale of oil, natural gas liquids and natural gas. In the second quarter of 2014, commodity sales increased $43.5 million or 13.9 percent from the same period of 2013. In the six months ended June 30, 2014, oil, natural gas liquids and natural gas sales increased $139.4 million or 24.6 percent from the same period of 2013. Particular factors impacting commodity sales include the following:
•
Oil volumes in the second quarter increased 9.3 percent to 2,833 thousand barrels (MBbl) as new drilling in the horizontal Wolfcamp in the Midland and Delaware basins more than offset declines in the mature Central Basin Platform. For the year-to-date, oil volumes rose 13.8 percent to 5,584 MBbl.
•
Average realized oil prices rose 2.4 percent to $92.74 per barrel during the three months ended June 30, 2014. Average realized oil prices increased 6.6 percent to $92.50 per barrel during the six months ended June 30, 2014 and included the impact of wider oil basis differentials.
•
Natural gas liquids production for the current quarter rose 30.7 percent to 44.7 million gallons (MMgal) largely due to less ethane rejection and new horizontal Wolfcamp drilling. For the year-to-date, natural gas liquids production rose 33.8 percent to 82.7 MMgal.
•
Average realized natural gas liquids prices increased 14.8 percent to an average price of $0.70 per gallon during the second quarter. Average realized natural gas prices rose 12.5 percent to an average price of $0.72 per gallon during the six months ended June 30, 2014.
•
Natural gas production decreased slightly to 14.7 billion cubic feet (Bcf) in the second quarter as production in the Permian Basin was offset by declining San Juan Basin production. For the six months ended June 30, 2014, natural gas production increased 1 percent to 28.8 Bcf.
•
Average realized natural gas prices rose 9.9 percent to $4.22 per thousand cubic feet (Mcf) during the three months ended June 30, 2014. For the current year-to-date, average realized natural gas prices increased 27.2 percent to $4.54 per Mcf.

Realized prices exclude the effects of derivative instruments. The aforementioned increases in oil, natural gas liquids and natural gas sales were primarily due to increased realized commodity prices and higher production volumes as a result of increased field development in certain Permian Basin liquids-rich properties partially offset by normal production declines.

Losses on derivative instruments were $84.8 million in the second quarter of 2014 compared to gains of $55.2 million in the same period of 2013. Losses on derivative instruments were $138.2 million in the six months ended June 30, 2014 compared to gains of $36.3 million in the same period of 2013. 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 expected to be offset by the expected 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)
2014
2013
2014
2013
Lease operating expenses
$
31,763

$
29,895

$
66,784

$
65,259

Workover and repair costs
22,001

18,726

43,650

38,708

Marketing and transportation
10,933

10,986

21,707

21,182

Total oil, natural gas liquids and natural gas production expense
$
64,697

$
59,607

$
132,141

$
125,149

Oil, natural gas liquids and natural gas production expense per BOE
$
10.20

$
10.16

$
10.70

$
11.24


Energen had oil, natural gas liquids and natural gas production expense of $64.7 million and $132.1 million during the three months and six months ended June 30, 2014, respectively, as compared to $59.6 million and $125.1 million during the same periods in 2013. Lease operating expense generally reflects year-over-year increases in the number of active wells resulting from Energen’s ongoing development and exploratory activities. Lease operating expense increased $1.9 million for the quarter largely due to higher non-operated costs (approximately $0.9 million), increased labor costs (approximately $0.9 million), higher electrical costs (approximately $0.7 million), higher producing overhead costs (approximately $0.7 million), increased chemical and treatment costs (approximately $0.6 million) and additional other operations and maintenance (O&M) expense (approximately $0.5 million) partially offset by

43


decreased environmental compliance costs (approximately $1.9 million) and lower water disposal costs (approximately $1.2 million). In the year-to-date, lease operating expense increased $1.5 million primarily due to increased labor costs (approximately $1.6 million), additional other O&M expense (approximately $1.6 million), higher electrical costs (approximately $1.2 million), increased non-operated costs (approximately $1.1 million), increased chemical and treatment costs (approximately $0.8 million) and higher producing overhead costs (approximately $0.7 million) partially offset by lower water disposal costs (approximately $2 million), decreased equipment rental expense (approximately $1.8 million) and decreased environmental compliance costs (approximately $1.8 million). On a per unit basis, the average lease operating expense for the current quarter was $5.01 per barrel of oil equivalent (BOE) as compared to $5.10 per BOE in the same period a year ago. For the six months ended June 30, 2014, the average lease operating expense was $5.41 per BOE as compared to $5.86 per BOE in the previous period.

In the three and six months ended June 30, 2014, workover and repair costs increased approximately $3.3 million and $4.9 million, respectively. These expenses were primarily related to workovers in the west Texas Permian Basin associated with the cleanout of producing wells following the drilling and completion of offset wells and with the protective preparation of wells for offset operations. Also, the increased number of producing wells resulting from our ongoing drilling program creates a higher level of base load expense.

Marketing and transportation costs decreased $0.1 million in the three months ended June 30, 2014 and rose $0.5 million in the year-to-date.

Production and ad valorem taxes: Production and ad valorem taxes were $28.0 million ($4.42 per BOE) and $55.4 million ($4.48 per BOE), respectively, during the three and six months ended June 30, 2014 as compared to $23.5 million ($4.01 per BOE) and $46.9 million ($4.21 per BOE), respectively, during the same periods in 2013. In the quarter, oil and higher natural gas commodity market prices contributed approximately $1.5 million to the increase in production-related taxes and higher oil and natural gas liquids commodity production volumes contributed approximately $1.4 million to the increase. In the year-to-date, higher net commodity market prices contributed approximately $5.5 million to the increase in production-related taxes and higher commodity production volumes contributed approximately $3.3 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining production taxes.

Depreciation, depletion and amortization: Energen’s DD&A expense for the quarter rose $23.9 million and $53.1 million year-to-date. The average depletion rate for the current quarter was $21.31 per BOE as compared to $19.00 per BOE in the same period a year ago. For the six months ended June 30, 2014, the average depletion rate was $20.93 per BOE as compared to $18.45 per BOE in the previous period. The increase in the current quarter and year-to-date per unit depletion rate, which contributed approximately $14.6 million and $30.6 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and greater oil volumes as a percent of total production. Higher oil and natural gas liquids production volumes contributed approximately $9.1 million and $22.4 million to the increase in DD&A expense for the quarter and year-to-date, respectively.

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)
2014
2013
2014
2013
Geological and geophysical
$
(450
)
$
590

$
1,656

$
1,379

Leasehold abandonments
1,342

355

2,588

400

Dry hole costs
1,255

42

1,286

537

Delay rentals and other
428

2,468

9,859

2,637

Total exploration expense
$
2,575

$
3,455

$
15,389

$
4,953

Total exploration expense per BOE
$
0.41

$
0.59

$
1.25

$
0.44


Exploration expense decreased $0.9 million in the second quarter of 2014 primarily due to lower delay rental payments and seismic costs partially offset by higher leasehold abandonments and dry hole costs. For the six months ended June 30, 2014 exploration expense rose $10.4 million largely as a result of higher delay rental payments and seismic costs combined with increased leasehold abandonments and dry hole costs.




44


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

 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands, except per unit data)
2014
2013
2014
2013
General and administrative
$
5,776

$
4,854

$
11,079

$
10,832

Benefit and performance-based compensation costs
12,488

11,113

27,933

22,276

Labor costs
13,159

11,438

24,268

20,831

Legal expenses
2,119

261

2,435

1,813

Total general and administrative expense
$
33,542

$
27,666

$
65,715

$
55,752

Total general and administrative expense per BOE
$
5.29

$
4.72

$
5.32

$
5.01


G&A expense increased $5.9 million for the three months ended June 30, 2014 largely due to higher labor costs, increased costs from Energen’s benefit and performance-based compensation plans and increased legal expenses. G&A expense rose $10 million for the year-to-date primarily due to increased costs from Energen’s benefit and performance-based compensation plans and higher labor costs.

Interest expense: Interest expense decreased $2.2 million in the second quarter of 2014 and $4.2 million for the six months ended June 30, 2014 largely due to the October 2013 repayment of $50 million of 5 percent Notes and the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011. The interest expense associated with the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due September 30, 2014 through December 17, 2017 and the syndicated credit facilities are reflected in discontinued operations. In conjunction with the pending sale of Alagasco, the Senior Term Loans and the syndicated credit facilities will be repaid during 2014.

Income tax expense (benefit): Income tax expense decreased $47.2 million in the current quarter and $43 million year-to-date, respectively, largely due to lower pre-tax income.

Discontinued operations, net of tax: In April 2014, Energen signed a stock purchase agreement to sell Alagasco to Laclede for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use 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 for the three months and six months ended June 30, 2014 and 2013 and our financial position as of June 30, 2014 and December 31, 2013 presented in our unaudited consolidated financial statements and the notes reflect Alagasco as discontinued operations.

In March 2014, Energen completed the sale of its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). 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 natural gas and oil 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 six months ended June 30, 2014. Energen also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. 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.

In October 2013, Energen completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). Energen recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which was reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. The sale had an effective date of July 1, 2013, and the proceeds from the sale were used to repay short-term obligations. The property was classified as held for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

See Note 13, Discontinued Operations, in Energen Corporation’s Condensed Notes to Unaudited Consolidated Financial Statements for additional information regarding discontinued operations.


45


Natural Gas Distribution
Alagasco reported a net loss of $0.6 million in the second quarter of 2014 compared to net loss of $0.7 million in the same period last year. Natural gas distribution revenues decreased $10.6 million for the quarter largely due to a decrease in the pass-through of gas costs. During the second quarter of 2014, Alagasco had a net $4.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the second quarter of 2013, Alagasco had a net $3.8 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the second quarter, weather was 19.7 percent warmer than the same quarter in the prior year. Residential sales volumes fell 13.6 percent while commercial and industrial customer sales volumes decreased 1.9 percent. Transportation volumes rose 8.4 percent in period comparisons. Alagasco’s net income of $42.4 million in the current year-to-date compared to net income of $46.5 million in the same period in the previous year. Revenues for the year-to-date rose $15.6 million primarily due to additional customer usage partially offset by a decrease in the pass-through of gas costs along with adjustments from the utility’s rate setting mechanisms. During the year-to-date 2014, Alagasco had a net $20.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. In the 2013 year-to-date, Alagasco had a net reduction in revenues of $6.3 million pre-tax to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current year-to-date, that was 17.5 percent colder compared with the same period in the prior year contributed to a 15.6 percent increase in residential sales volumes and a 17.4 percent rise in commercial and industrial customer sales volumes. Transportation volumes increased 3.8 percent in period comparisons. Lower gas costs partially offset by increased gas purchase volumes resulted in a 19.1 percent decrease in cost of gas for the quarter. For the year-to-date a significant increase in gas purchase volumes slightly offset by lower gas costs resulted in a 16.5 percent increase in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas cost fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense declined 3.4 percent in the current quarter primarily due to decreased consulting and technology costs (approximately $0.6 million). In the six months ended June 30, 2014, O&M expense decreased 4.1 percent largely due to lower labor-related costs (approximately $2.1 million), decreased consulting and technology expense (approximately $0.6 million) and decreased advertising costs (approximately $0.5 million) partially offset by higher bad debt expense (approximately $0.5 million).

A 5.3 percent increase in depreciation expense in the current quarter and a 5.4 percent increase in the year-to-date was primarily due to the extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

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 plan on repaying our $570 million Senior Term Loans with the proceeds from the sale of Alagasco. The remaining proceeds will be used to repay our credit facilities.

Net cash provided by operating activities: Net cash provided by operating activities for the six months ended June 30, 2014 was $542.5 million as compared to $539.8 million for the same period of 2013 and included discontinued operations primarily associated with cash flows from Alagasco of $122.2 million and $152.7 million, respectively. Energen’s working capital was influenced by commodity prices and the timing of payments and recoveries. Working capital needs at Alagasco were affected by the timing of payments and recoveries, including gas supply pass-through adjustments and refundable negative salvage costs, lower gas costs and changes to storage gas inventory compared to the prior period.

Net cash used in investing activities: Net cash used in investing activities for the six months ended June 30, 3014 was $639.6 million as compared to $681.9 million for the same period of 2013. Energen incurred on a cash basis $597 million in capital expenditures including $575 million largely related to the development of oil and gas properties and $22 million primarily related to unproved leasehold acquisitions. Included in discontinued operations, Energen had cash proceeds of $30.3 million from the sale of the North Louisiana/East Texas properties largely offset by Alagasco capital expenditures on a cash basis of $31.7 million year-to-date which primarily represented expansion and replacement of its distribution system and replacement of its support facilities

46


and information systems. We also had a net purchase of short-term investments of $42 million associated with the timing of payments on our credit facilities.

Net cash provided by financing activities: Net cash provided by financing activities for the six months ended June 30, 3014 was $104.9 million as compared to $136.2 million for the same period of 2013. Net cash provided by financing activities in the year-to-date 2014 was primarily due to an increase in short-term borrowings and the issuance of common stock through the Company’s stock-based compensation plan partially offset by discontinued operations primarily related to the sale of Alagasco, the reduction of long-term debt for current maturities and the payment of dividends to common shareholders. Net cash provided by financing activities in the year-to-date 2013 was largely due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders.

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 two of our active counterparties and in a net loss position with the remaining twelve at June 30, 2014.

See Note 4, Fair Value Measurements, in Energen Corporation’s Condensed Notes to Unaudited Consolidated Financial Statements for information regarding our policies on fair value measurement.

Natural Gas Distribution
In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control, the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $15.3 million, $16.3 million, $14.2 million, $22.2 million and $2.7 million for the periods January through June 2014, the years ended December 31, 2013, 2012, 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $13.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $26.8 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through 2019 through lower tariff rates. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve and other APSC approved charges. The refunds as of June 30, 2014 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

Alagasco maintains an investment in storage gas that is expected to average approximately $32 million in 2014 but will vary depending upon the price of natural gas. During 2014, Alagasco plans to invest approximately $69 million in capital expenditures for the normal needs of its distribution, support systems and technology-related projects and the construction of a service center to replace the Metro

47


Operations Center sold during 2013. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities.

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million related to the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. Alagasco received approximately $13.8 million pre-tax in cash from the sale of this property. During the third quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, Alagasco recognized the deferred revenues from this sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

Inflation and Changes in Prices
Our revenues, the value of our assets and our ability to obtain additional capital on attractive terms have been and will continue to be affected by changes in oil, natural gas liquids and natural gas prices and the costs to produce our reserves. Oil, natural gas liquids and natural gas prices are subject to significant variations that are beyond our ability to predict or to control. Although some of our costs are impacted by general inflation, the majority of our costs are a function of supply and demand specific to the oil and gas industry. The overall increase in oil and natural gas prices over the past several years has resulted in increased competition and activity in the industry which has caused some costs, including those to obtain certain resources to operate our business, to increase.

Credit Facilities 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 the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and possible credit rating downgrades. On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities with domestic and foreign lenders. Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both Energen and Alagasco. During 2014, we will terminate our existing five-year syndicated unsecured credit facilities and enter into a new credit facility. We expect this credit facility to be secured by assets of Energen and its subsidiaries.

At June 30, 2014, Energen reported negative working capital of $987.9 million arising from current liabilities of $2,464.7 million exceeding current assets of $1,476.9 million. The negative working capital is largely due to the required repayment of the syndicated credit facilities and the Senior Term Loans. These repayments will be funded from the proceeds of the pending sale of Alagasco.

Working capital of Energen is also influenced by the fair value of Energen’s derivative financial instruments associated with future production. Energen has $0.5 million in current assets and $96.2 million in current liabilities, respectively, associated with its derivative instruments at June 30, 2014. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco’s business and reflects an expected pass-through to rate payers of $13.4 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by their syndicated credit facilities to fund working capital needs. Negative working capital is expected to be positively impacted from the sale of Alagasco as previously discussed.

Credit Ratings
On April 8, 2014, following the announced sale of Alagasco, Moody’s Investors Service lowered Energen’s senior unsecured credit rating from Baa3 to Ba1 with a negative outlook. Alagasco’s senior unsecured credit rating, which is investment grade with a negative outlook, has been placed under review. On December 16, 2013, Standard & Poor’s (S&P) lowered its credit ratings for Energen and Alagasco from investment grade with a stable outlook to investment grade with a negative outlook. On April 9, 2014, S&P placed Energen and Alagasco on CreditWatch with negative implications for Energen and positive implications for Alagasco. S&P expects to resolve the CreditWatch around the time of the close of the sale of Alagasco.

Dividends
Energen’s dividend policy is under review in connection with the pending sale of Alagasco. Dividends for the first quarter and second quarter of 2014 were $0.15 per share on the Company’s common stock and a $0.15 per share dividend has been declared for the third quarter of 2014. Subsequent to the sale of Alagasco, the Company expects to substantially reduce the amount of its dividend payments with a focus on further development and exploration of its oil and natural gas properties. 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.



48


Contractual Cash Obligations
In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes Energen’s significant contractual cash obligations, other than hedging contracts, as of June 30, 2014:

 
Payments Due Before December 31,

(in thousands)

Total
Remaining 2014

2015-2016

2017-2018
2019 and Thereafter
Long-term debt (1)
$
1,124,000

$
570,000

$
—

$
19,000

$
535,000

Interest payments on debt
262,406

16,769

59,201

57,218

129,218

Operating leases
16,601

1,577

6,703

5,563

2,758

Asset retirement obligations (2)
722,322

11,360

6,162

5,933

698,867

Nonqualified supplemental retirement plans
35,491

8,937

310

8,938

17,306

Total contractual cash obligations
$
2,160,820

$
608,643

$
72,376

$
96,652

$
1,383,149


The following table summarizes Alagasco’s significant contractual cash obligations as of June 30, 2014:

 
Payments Due Before December 31,

(in thousands)

Total
Remaining 2014

2015-2016

2017-2018
2019 and Thereafter
Long-term debt
$
249,830

$
50,000

$
80,000

$
—

$
119,830

Interest payments on debt
118,561

5,829

17,374

13,441

81,917

Purchase obligations (3)
139,834

23,237

87,524

26,606

2,467

Operating leases (4)
27,411

2,170

8,216

6,388

10,637

Total contractual cash obligations
$
535,636

$
81,236

$
193,114

$
46,435

$
214,851


(1) Long-term debt obligations include approximately $0.4 million of unamortized debt discounts as of June 30, 2014.

(2) Represents the estimated future asset retirement obligation on an undiscounted basis. 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. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.

(3) Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $140 million through September 2024. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 115 Bcf through August 2020.

(4) Effective July 1, 2013, Alagasco subleased Energen’s headquarters to Energen. Included in operating leases for Alagasco are payments that will be due for Energen’s headquarters. Upon the close of the sale of Alagasco, Energen will pay Alagasco for 100 percent of this expense.

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 6 MMBOE through September 2017.

Energen and Alagasco anticipate required contributions of approximately $1.6 million and $2.9 million, respectively, during 2014 to the qualified pension plans. Energen and Alagasco expect sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. Energen and Alagasco made discretionary contributions of $1.6 million and $1.4 million, respectively, to the qualified pension plans in January 2014. During 2014, Energen and Alagasco may make discretionary contributions to the qualified pension plans depending on the

49


amount and timing of employee retirements and market conditions. The contractual obligations reported above exclude any payments Energen or Alagasco expects to make to postretirement benefit program assets.

The contractual obligations reported above exclude Energen’s liability of $17.2 million related to Energen’s provision for uncertain tax positions. Energen cannot make a reasonably reliable estimate of the amount and period of related future payments for such liability.

Other Commitments
During the third quarter of 2010, Energen Resources received preliminary findings from the Taxation and Revenue Department (the Department) of the State of New Mexico relating to its audit, conducted 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 ONRR has proposed certain changes in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases.

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004 forward. Energen preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. Energen is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of June 30, 2014.

Recent Accounting Standards Updates
See Note 14, Recently Issued Accounting Standards, in Energen Corporation’s Condensed Notes to Unaudited Consolidated Financial Statements for information regarding recently issued accounting standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS
 
 
 
 
 

The disclosure and analysis in this report contains forward-looking statements that express management’s expectations of future plans, objectives and performance of the Company and its subsidiaries. Such statements constitute forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended, and are noted in the Company’s disclosure as permitted by the Private Securities Litigation Reform Act of 1995. Forward-looking statements often address the Company’s future business and financial performance and financial condition, and often contain words such as “expect”, “anticipate”, “intend”, “plan”, “believe”, “seek”, “see”, “project”, “will”, “estimate”, “may”, and other words of similar meaning.

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, natural gas liquids and natural gas, fluctuations in the weather, drilling risks, costs associated with compliance with environmental and regulatory obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, acts of nature, sabotage, terrorism (including cyber-attacks) and other similar acts that disrupt operations or cause damage greater than covered by insurance, future business decisions, the proposed sale of Alagasco to The Laclede Group, Inc., utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

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. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.


50


Commodity prices for crude oil and natural gas are volatile, and a substantial reduction in commodity prices could adversely affect Energen’s results and the carrying value of its oil and natural gas properties: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for oil, natural gas liquids and natural gas have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, natural gas liquids and natural gas production. Additionally, downward commodity price trends may impact expected cash flows from future production and potentially reduce the carrying value of Company-owned oil and natural gas properties. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Market conditions or a downgrade in the credit ratings of Energen or its subsidiaries could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders, the Company and its subsidiaries. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition (including by sale, spin-off or distribution) transactions involving Energen, Energen Resources or Alagasco may negatively impact market and rating agency considerations regarding the credit of the Company or its subsidiaries, and the management of the Company periodically considers these types of transactions. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs, limit availability of funds to the Company and adversely affect the price of outstanding debt securities.

Energen Resources’ hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk: Although Energen Resources makes use of 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 the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the 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 Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and Energen. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

Energen is exposed to counterparty credit risk as a result of its 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 the Company’s 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. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee.

Energen’s operations depend upon the use of third-party facilities and an interruption of its ability to utilize these facilities may adversely affect its financial condition and results of operations: Energen Resources delivers to and Alagasco is served by third-party facilities. These facilities include third-party oil and natural gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Energen, Energen Resources and Alagasco.

Energen’s oil and natural gas reserves are estimates, and actual future production may vary significantly and may also be negatively impacted by its 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. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by

51


lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

Energen’s operations involve operational risk including risk of personal injury, property damage and environmental damage and its insurance policies do not cover all such risks: Inherent in the oil and natural gas production activities of Energen Resources and the natural gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:

•
Pipeline and storage leaks, ruptures and spills;
•
Equipment malfunctions and mechanical failures;
•
Fires and explosions;
•
Well blowouts, explosions and cratering; and
•
Soil, surface 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 property, environmental pollution, impairment of operations and substantial financial losses. 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, the Company maintains insurance against some, but not all, of these risks and losses and the insurance coverages are subject to retention levels and coverage limits. The occurrence of any of these events could adversely affect Energen, Energen Resources’ and Alagasco’s financial positions, results of operations and cash flows.

Alagasco operates in a limited service territory and is therefore subject to concentrated regional risks which may negatively affect Alagasco’s financial condition and results of operations: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

Energen is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. 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 the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’s operations.

Energen’s business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions: Energen relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company’s information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company’s operations, financial position and results of operations.

Successful completion of the Energen’s pending sale of Alagasco is subject to various risks and conditions: In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness. The sale of Alagasco involves various inherent risks including satisfaction by the parties of contractual conditions to closing.

52


SELECTED BUSINESS SEGMENT DATA
 
 
ENERGEN CORPORATION
 
 
(Unaudited)
 
 
 
Three months ended
Six months ended
 
June 30,
June 30,
(in thousands, except sales price and per unit data)
2014
2013
2014
2013
Oil and Gas Operations
 
 
 
 
Oil, natural gas liquids and natural gas sales from continuing operations
 
 
 
Oil
$
262,746

$
234,870

$
516,505

$
425,629

Natural gas liquids
31,163

20,871

59,366

39,526

Natural gas
61,943

56,659

130,803

102,084

Total
$
355,852

$
312,400

$
706,674

$
567,239

Loss on sale of assets and other
$
(909
)
$
(663
)
$
(1,062
)
$
(215
)
Open non-cash mark-to-market gains (losses) on derivative instruments
 
Oil
$
(66,172
)
$
36,680

$
(87,636
)
$
28

Natural gas liquids
40

168

327

147

Natural gas
6,511

19,301

(5,993
)
14,926

Total
$
(59,621
)
$
56,149

$
(93,302
)
$
15,101

Closed gains (losses) on derivative instruments
 
Oil
$
(25,754
)
$
(9,076
)
$
(40,556
)
$
(1,632
)
Natural gas liquids
159

3,109

355

5,591

Natural gas
370

5,062

(4,734
)
17,228

Total
$
(25,225
)
$
(905
)
$
(44,935
)
$
21,187

Total Revenues
$
270,097

$
366,981

$
567,375

$
603,312

Production volumes from continuing operations
 
 
 
 
Oil (MBbl)
2,833

2,592

5,584

4,906

Natural gas liquids (MMgal)
44.7

34.2

82.7

61.8

Natural gas (MMcf)
14,676

14,742

28,800

28,560

Production volumes from continuing operations (MBOE)
6,344

5,864

12,352

11,137

Total production volumes (MBOE)
6,354

6,480

12,516

12,401

Average realized prices excluding effects of open non-cash mark-to-market derivative instruments
Oil (per barrel)
$
83.65

$
87.11

$
85.23

$
86.42

Natural gas liquids (per gallon)
$
0.70

$
0.70

$
0.72

$
0.73

Natural gas (per Mcf)
$
4.25

$
4.19

$
4.38

$
4.18

Average realized prices excluding derivative instruments
Oil (per barrel)
$
92.74

$
90.61

$
92.50

$
86.76

Natural gas liquids (per gallon)
$
0.70

$
0.61

$
0.72

$
0.64

Natural gas (per Mcf)
$
4.22

$
3.84

$
4.54

$
3.57

Other costs per BOE from continuing operations
 
 
 
 
Oil, natural gas liquids and natural gas production expenses
$
10.20

$
10.16

$
10.70

$
11.24

Production and ad valorem taxes
$
4.42

$
4.01

$
4.48

$
4.21

Depreciation, depletion and amortization
$
21.31

$
19.00

$
20.93

$
18.45

Exploration expense
$
0.41

$
0.59

$
1.25

$
0.44

General and administrative
$
5.29

$
4.72

$
5.32

$
5.01

Capital expenditures
$
322,572

$
349,879

$
594,268

$
634,932

 
 
 
 
 
 
 
 
 
 

53


Natural Gas Distribution (included in discontinued operations)
 
 
 
 
Operating revenues
 
 
 
 
Residential
$
56,094

$
65,551

$
247,706

$
228,291

Commercial and industrial
25,711

27,627

94,702

85,225

Transportation
13,818

13,824

31,852

32,064

Other
(1,750
)
(2,488
)
(16,486
)
(3,381
)
Total
$
93,873

$
104,514

$
357,774

$
342,199

Gas delivery volumes (MMcf)
 
 
 
 
Residential
3,121

3,613

16,174

13,995

Commercial and industrial
1,917

1,955

7,232

6,162

Transportation
11,605

10,706

24,387

23,496

Total
16,643

16,274

47,793

43,653

Other data
 
 
 
 
Depreciation and amortization
$
11,445

$
10,873

$
22,770

$
21,602

Capital expenditures
$
15,450

$
27,113

$
29,044

$
46,810

Operating income
$
1,946

$
2,219

$
74,297

$
81,512



54


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, 2013, 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, 2013.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. 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, 2014, Energen had entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period
Total Hedged Volumes
Average Contract
Price

Description
Fair Value (in thousands)
Oil
 
 
 
 
2014
4,958
 MBbl
$92.65 Bbl
NYMEX Swaps
$
(51,720
)
2015
8,280
 MBbl
$89.30 Bbl
NYMEX Swaps
(60,522
)
Oil Basis Differential
 
 
 
 
2014
600
 MBbl
$(3.30) Bbl
WTS/WTI Basis Swaps*
1,119

2014
1,200
 MBbl
$(3.08) Bbl
WTI/WTI Basis Swaps**
3,072

Natural Gas Liquids
 
 
 
 
2014
35.8
 MMgal
$0.93 Gal
Liquids Swaps
39

Natural Gas
 
 
 
 
2014
5.2
 Bcf
$4.56 Mcf
NYMEX Swaps
541

2014
15.4
 Bcf
$4.61 Mcf
Basin Specific Swaps - San Juan
3,021

2014
5.0
 Bcf
$3.81 Mcf
Basin Specific Swaps - Permian
(2,936
)
2015
23.0
 Bcf
$4.13 Mcf
Basin Specific Swaps - San Juan
579

2015
6.0
 Bcf
$4.20 Mcf
Basin Specific Swaps - Permian
602

Natural Gas Basis Differential
 
 
 
 
2014
3.1
 Bcf
$(0.09) Mcf
San Juan Basis Swaps
(181
)
2014
1.2
 Bcf
$(0.17) Mcf
Permian Basis Swaps
(137
)
June 2014 contracts (closed but not cash settled)
(10,248
)
Total
$
(116,771
)
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
 
**WTI - West Texas Intermediate/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.

55


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

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

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

Interest rate risk: Our interest rate exposure, as of June 30, 2014, primarily relates to our syndicated credit facilities with variable interest rates. At June 30, 2014, we had interest rate swap agreements with a notional of $190 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent. The fair value of our interest rate swaps was a $1.4 million liability at June 30, 2014. The weighted average interest rate for amounts outstanding at June 30, 2014 was 1.40 percent. Our interest rate exposure on long-term debt is approximately 51 percent at June 30, 2014.


56


ITEM 4. CONTROLS AND PROCEDURES
 
 
 
 
 

Energen Corporation
(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)
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.

Alabama Gas Corporation
(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)
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.



57


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 8, Commitments and Contingencies, in Energen Corporation’s Condensed Notes to Unaudited Consolidated Financial Statements and Note 4, Commitments and Contingencies, in Alabama Gas Corporation’s Condensed Notes to Unaudited 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, 2014 through April 30, 2014
—

 
$
—

—

8,992,700

May 1, 2014 through May 31, 2014
9,851

*
83.59

—

8,992,700

June 1, 2014 through June 30, 2014
3,150

*
87.73

—

8,992,700

Total
13,001

 
$
84.59

—

8,992,700

*Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.
**By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized Energen to repurchase up to 12,564,400 shares of Energen common stock. The resolutions do not have an expiration date.

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)
31(c)
-
Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)
-
Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)
-
Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)
-
Section 906 Alabama Gas 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, 2014 are formatted in XBRL



58


SIGNATURES

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

 
 
 
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
 
 
 
 
August 11, 2014
 
By
/s/ J. T. McManus, II       
 
 
 
J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
 
 
 
 
 
 
 
 
August 11, 2014
 
By
/s/ Charles W. Porter, Jr.             
 
 
 
Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
 
 
 
 
 
 
 
 
August 11, 2014
 
By
/s/ Russell E. Lynch, Jr.                    
 
 
 
Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation
 
 
 
 
 
 
 
 
August 11, 2014
 
By
/s/ Leonarda M. DiChiara
 
 
 
Leonarda M. DiChiara Vice President and Controller of Alabama Gas Corporation













 




59

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