EGN 9/30/13 10Q


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
____________________________________________
FORM 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013
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
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of November 1, 2013.
Energen Corporation
 
 $0.01 par value
 
 72,685,415 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 SEPTEMBER 30, 2013

TABLE OF CONTENTS
 
 
 
Page
Item 1.
 
 
 
 
 
 
(b) Consolidated Condensed Statements of Comprehensive Income of Energen Corporation
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
Item 4.
 
Item 1.
 
Legal Proceedings
Item 2.
 
Item 6.
 









2



PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
 
 
 
 
ENERGEN CORPORATION
 
 
 
 
 
(Unaudited)
 
 
 
 
 
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands, except per share data)
2013
2012
 
2013
2012
Operating Revenues
 
 
 
 
 
Oil and gas operations
$
272,038

$
214,620

 
$
875,350

$
799,339

Natural gas distribution
48,368

61,809

 
390,567

327,183

Total operating revenues
320,406

276,429

 
1,265,917

1,126,522

Operating Expenses
 
 
 
 
 
Cost of gas
20,435

20,924

 
163,448

94,179

Operations and maintenance
141,271

123,730

 
413,401

336,568

Depreciation, depletion and amortization
136,123

96,634

 
365,355

276,465

Taxes, other than income taxes
24,858

19,572

 
77,955

64,314

Accretion expense
1,771

1,605

 
5,187

4,691

Total operating expenses
324,458

262,465

 
1,025,346

776,217

Operating Income (Loss)
(4,052
)
13,964

 
240,571

350,305

Other Income (Expense)
 
 
 
 
 
Interest expense
(17,689
)
(17,195
)
 
(51,751
)
(48,447
)
Other income
13,062

1,488

 
15,578

3,678

Other expense
(434
)
(84
)
 
(631
)
(305
)
Total other expense
(5,061
)
(15,791
)
 
(36,804
)
(45,074
)
Income (Loss) From Continuing Operations Before Income Taxes
(9,113
)
(1,827
)
 
203,767

305,231

Income tax expense (benefit)
(3,627
)
(322
)
 
73,897

110,508

Income (Loss) From Continuing Operations
(5,486
)
(1,505
)
 
129,870

194,723

Discontinued Operations, net of taxes
 
 
 
 
 
Income (loss) from discontinued operations
1,866

3,551

 
6,269

(3,984
)
Loss on disposal of discontinued operations
(15,678
)

 
(15,678
)

Income (Loss) From Discontinued Operations
(13,812
)
3,551

 
(9,409
)
(3,984
)
Net Income (Loss)
$
(19,298
)
$
2,046

 
$
120,461

$
190,739

Diluted Earnings Per Average Common Share
 
 
 
 
 
Continuing Operations
$
(0.08
)
$
(0.02
)
 
$
1.80

$
2.69

Discontinued operations
(0.19
)
0.05

 
(0.13
)
(0.05
)
Net Income (Loss)
$
(0.27
)
$
0.03

 
$
1.67

$
2.64

Basic Earnings Per Average Common Share
 
 
 
 
 
Continuing Operations
$
(0.08
)
$
(0.02
)
 
$
1.80

$
2.70

Discontinued operations
(0.19
)
0.05

 
(0.13
)
(0.06
)
Net Income (Loss)
$
(0.27
)
$
0.03

 
$
1.67

$
2.64

Dividends Per Common Share
$
0.145

$
0.140

 
$
0.435

$
0.420

Diluted Average Common Shares Outstanding
72,346

72,316

 
72,272

72,301

Basic Average Common Shares Outstanding
72,346

72,130

 
72,220

72,121


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

3



CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
 
 
 
ENERGEN CORPORATION
 
 
 
 
 
(Unaudited)
 
 
 
 
 
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2013
2012
 
2013
2012
Net Income (Loss)
$
(19,298
)
$
2,046

 
$
120,461

$
190,739

Other comprehensive income (loss):
 
 
 
 
 
Cash flow hedges:
 
 
 
 
 
Current period change in fair value of commodity derivative instruments, net of tax of $42, ($30,622), ($6,669) and $30,621
69

(49,962
)
 
(10,882
)
49,961

Reclassification adjustment for commodity derivative instruments, net of tax of ($3,205), ($4,924), ($11,486) and ($14,303)
(5,229
)
(8,034
)
 
(18,740
)
(23,337
)
Current period change in fair value of interest rate swap, net of tax of ($188), ($375), ($23) and ($1,205)
(350
)
(697
)
 
(42
)
(2,240
)
Reclassification adjustment for interest rate swap, net of tax of $156, $142, $449 and $422
290

263

 
833

783

Total cash flow hedges
(5,220
)
(58,430
)
 
(28,831
)
25,167

Pension and postretirement plans:


 


Amortization of net obligation at transition, net of taxes of $26, $25, $77 and $75
48

47

 
143

140

Amortization of prior service cost, net of taxes of $28, $30, $82 and $89
51

55

 
153

166

Amortization of net loss, including settlement charges, net of taxes of $729, $413, $2,383 and $1,238
1,354

766

 
4,425

2,300

Current period change in fair value of pension and postretirement plans, net of taxes of $2,238, ($4,073), $2,238 and ($4,073)
4,157

(7,564
)
 
4,157

(7,564
)
Total pension and postretirement plans
5,610

(6,696
)
 
8,878

(4,958
)
Comprehensive Income (Loss)
$
(18,908
)
$
(63,080
)
 
$
100,508

$
210,948


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


4



CONSOLIDATED CONDENSED BALANCE SHEETS
 
 
ENERGEN CORPORATION
 
 
(Unaudited)
 
 
 
 
 
(in thousands)
September 30, 2013
December 31, 2012
ASSETS
 
 
Current Assets
 
 
Cash and cash equivalents
$
12,413

$
9,704

Accounts receivable, net of allowance for doubtful accounts of $6,070 at September 30, 2013, and $6,549 at December 31, 2012
200,043

277,900

Inventories
 
 
Storage gas inventory
39,507

32,205

Materials and supplies
19,187

28,291

Liquified natural gas in storage
2,990

3,498

Regulatory asset
11,213

45,515

Income tax receivable
7,653

6,664

Assets held for sale
183,862


Deferred income taxes
42,722

8,520

Prepayments and other
12,996

12,823

Total current assets
532,586

425,120

Property, Plant and Equipment
 
 
Oil and gas properties, successful efforts method
6,655,343

6,439,127

Less accumulated depreciation, depletion and amortization
1,657,682

1,765,241

Oil and gas properties, net
4,997,661

4,673,886

Utility plant
1,471,174

1,416,590

Less accumulated depreciation
594,604

573,947

Utility plant, net
876,570

842,643

Other property, net
29,733

25,107

Total property, plant and equipment, net
5,903,964

5,541,636

Other Assets
 
 
Regulatory asset
89,004

110,566

Other postretirement assets
17,417

1,404

Long-term derivative instruments
12,786

40,577

Deferred charges and other
59,115

56,587

Total other assets
178,322

209,134

TOTAL ASSETS
$
6,614,872

$
6,175,890


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










5



CONSOLIDATED CONDENSED BALANCE SHEETS
 
 
ENERGEN CORPORATION
 
 
(Unaudited)
 
 
 
 
 
(in thousands, except share and per share data)
September 30, 2013
December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
Current Liabilities
 
 
Long-term debt due within one year
$
125,000

$
50,000

Notes payable to banks
901,000

643,000

Accounts payable
256,109

257,579

Accrued taxes
51,878

30,076

Customers’ deposits
20,531

24,705

Amounts due customers
19,974

19,718

Accrued wages and benefits
25,896

24,984

Regulatory liability
40,168

45,116

Royalty payable
49,976

34,426

Liabilities related to assets held for sale
23,945


Other
26,812

30,178

Total current liabilities
1,541,289

1,159,782

Long-term debt
1,028,509

1,103,528

Deferred Credits and Other Liabilities
 
 
Asset retirement obligation
106,604

118,023

Pension and other postretirement liabilities
90,893

110,282

Regulatory liability
81,414

80,404

Long-term derivative instruments
1,961

11,305

Deferred income taxes
979,898

905,601

Other
14,638

10,275

Total deferred credits and other liabilities
1,275,408

1,235,890

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, 75,485,159 shares issued at September 30, 2013, and 75,067,760 shares issued at December 31, 2012
755

751

Premium on capital stock
514,784

492,108

Capital surplus
2,802

2,802

Retained earnings
2,403,062

2,314,055

Accumulated other comprehensive income (loss), net of tax
 
 
Unrealized gain on hedges, net
16,730

46,352

Pension and postretirement plans
(43,629
)
(52,507
)
Interest rate swap
(1,365
)
(2,156
)
Deferred compensation plan
3,319

2,774

Treasury stock, at cost: 2,977,920 shares at September 30, 2013, and 2,998,620 shares at December 31, 2012
(126,792
)
(127,489
)
Total shareholders’ equity
2,769,666

2,676,690

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
6,614,872

$
6,175,890


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

6



CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
 
ENERGEN CORPORATION
 
 
(Unaudited)
 
 
 
 
 
Nine months ended September 30, (in thousands)
2013
2012
Operating Activities
 
 
Net income
$
120,461

$
190,739

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
392,854

300,863

Asset impairment
24,612

21,545

Accretion expense
6,131

5,581

Deferred income taxes
51,682

80,724

Bad debt expense
1,203

370

Exploratory expense
8,759

11,420

Change in derivative fair value
53,581

(34,469
)
Gain on sale of assets
(10,980
)
(420
)
Stock based compensation expense
11,759

6,820

Other, net
25,455

10,779

Net change in:
 
 
Accounts receivable
50,767

57,334

Inventories
1,169

62

Accounts payable
(74,183
)
(12,562
)
Amounts due customers, including gas supply pass-through
36,891

(52,466
)
Income tax receivable
(989
)
1,817

Pension and other postretirement benefit contributions
(11,332
)
(5,056
)
Other current assets and liabilities
40,176

20,038

Net cash provided by operating activities
728,016

603,119

Investing Activities
 
 
Additions to property, plant and equipment
(961,798
)
(898,202
)
Acquisitions, net of cash acquired
(21,400
)
(104,200
)
Proceeds from sale of assets
16,220

2,420

Other, net
(1,210
)
(746
)
Net cash used in investing activities
(968,188
)
(1,000,728
)
Financing Activities
 
 
Payment of dividends on common stock
(31,454
)
(30,292
)
Issuance of common stock
13,680

1,164

Payment of long-term debt
(55
)
(1,143
)
Net change in short-term debt
258,000

465,000

Tax benefit on stock compensation
2,710

514

Other

(38
)
Net cash provided by financing activities
242,881

435,205

Net change in cash and cash equivalents
2,709

37,596

Cash and cash equivalents at beginning of period
9,704

9,541

Cash and Cash Equivalents at End of Period
$
12,413

$
47,137


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

7



CONDENSED STATEMENTS OF INCOME
 
 
 
ALABAMA GAS CORPORATION
 
 
 
(Unaudited)
 
 
 
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2013
2012
 
2013
2012
Operating Revenues
$
48,368

$
61,809

 
$
390,567

$
327,183

Operating Expenses
 
 
 
 
 
Cost of gas
20,435

20,924

 
163,448

94,179

Operations and maintenance
33,650

37,235

 
107,672

107,470

Depreciation and amortization
11,063

10,572

 
32,665

31,551

Income taxes
 
 
 
 
 
Current
(7,703
)
(9,242
)
 
16,440

13,567

Deferred
2,093

3,264

 
6,448

9,431

Taxes, other than income taxes
5,764

5,821

 
27,814

23,718

Total operating expenses
65,302

68,574

 
354,487

279,916

Operating Income (Loss)
(16,934
)
(6,765
)
 
36,080

47,267

Other Income (Expense)
 
 
 
 
 
Allowance for funds used during construction
184

187

 
630

452

Other income
12,092

787

 
13,203

1,925

Other expense
(434
)
(84
)
 
(623
)
(254
)
Total other income
11,842

890

 
13,210

2,123

Interest Expense
 
 
 
 
 
Interest on long-term debt
3,377

3,423

 
10,133

10,270

Other interest expense
492

741

 
1,600

1,915

Total interest expense
3,869

4,164

 
11,733

12,185

Net Income (Loss)
$
(8,961
)
$
(10,039
)
 
$
37,557

$
37,205


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

8



CONDENSED BALANCE SHEETS
 
 
ALABAMA GAS CORPORATION
 
 
(Unaudited)
 
 
 
 
 
(in thousands)
September 30, 2013
December 31, 2012
ASSETS
 
 
Property, Plant and Equipment
 
 
Utility plant
$
1,471,174

$
1,416,590

Less accumulated depreciation
594,604

573,947

Utility plant, net
876,570

842,643

Other property, net
41

42

Current Assets
 
 
Cash and cash equivalents
8,541

5,559

Accounts receivable
 
 
Gas
39,962

94,011

Other
4,655

5,117

Affiliated companies
6,579

5,742

Allowance for doubtful accounts
(5,300
)
(5,700
)
Inventories
 
 
Storage gas inventory
39,507

32,205

Materials and supplies
5,401

5,528

Liquified natural gas in storage
2,990

3,498

Regulatory asset
11,213

45,515

Income tax receivable
1,601

2,762

Deferred income taxes
22,314

18,799

Prepayments and other
6,595

4,451

Total current assets
144,058

217,487

Other Assets
 
 
Regulatory asset
89,004

110,566

Pension and other postretirement assets
13,399

848

Deferred charges and other
10,994

11,290

Total other assets
113,397

122,704

TOTAL ASSETS
$
1,134,066

$
1,182,876


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








9



CONDENSED BALANCE SHEETS
 
 
ALABAMA GAS CORPORATION
 
 
(Unaudited)
 
 
 
 
 
(in thousands, except share data)
September 30, 2013
December 31, 2012
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 September 30, 2013 and December 31, 2012
20

20

Premium on capital stock
31,682

31,682

Capital surplus
2,802

2,802

Retained earnings
330,234

325,999

Total common shareholder’s equity
364,738

360,503

Long-term debt
249,973

250,028

Total capitalization
614,711

610,531

Current Liabilities
 
 
Notes payable to banks
49,000

77,000

Accounts payable
32,997

51,741

Accrued taxes
28,635

24,186

Customers’ deposits
20,531

24,705

Amounts due customers
19,974

19,718

Accrued wages and benefits
8,154

6,703

Regulatory liability
40,168

45,116

Other
9,293

9,018

Total current liabilities
208,752

258,187

Deferred Credits and Other Liabilities
 
 
Deferred income taxes
199,372

189,381

Pension and other postretirement liabilities
28,371

43,611

Regulatory liability
81,414

80,404

Other
1,446

762

Total deferred credits and other liabilities
310,603

314,158

Commitments and Contingencies




TOTAL LIABILITIES AND CAPITALIZATION
$
1,134,066

$
1,182,876


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

10



CONDENSED STATEMENTS OF CASH FLOWS
 
 
ALABAMA GAS CORPORATION
 
 
(Unaudited)
 
 
 
 
 
Nine months ended September 30, (in thousands)
2013
2012
Operating Activities
 
 
Net income
$
37,557

$
37,205

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
32,665

31,551

Deferred income taxes
6,448

9,431

Bad debt expense
1,120

364

Gain on sale of assets
10,889


Other, net
1,524

4,681

Net change in:
 
 
Accounts receivable
19,801

29,539

Inventories
(6,667
)
5,975

Accounts payable
(16,181
)
(17,222
)
Amounts due customers, including gas supply pass-through
36,891

(52,466
)
Income tax receivable
1,161

6,002

Pension and other postretirement benefit contributions
(5,848
)
(2,044
)
Other current assets and liabilities
(112
)
(9,795
)
Net cash provided by operating activities
119,248

43,221

Investing Activities
 
 
Additions to property, plant and equipment
(67,085
)
(49,746
)
Proceeds from sale of assets
13,838


Other, net
(1,642
)
2,490

Net cash used in investing activities
(54,889
)
(47,256
)
Financing Activities
 
 
Dividends
(33,322
)
(28,182
)
Payment of long-term debt
(55
)
(143
)
Net increases in advances from affiliates

24,867

Net change in short-term debt
(28,000
)
10,000

Other

(38
)
Net cash provided by (used in) financing activities
(61,377
)
6,504

Net change in cash and cash equivalents
2,982

2,469

Cash and cash equivalents at beginning of period
5,559

7,817

Cash and Cash Equivalents at End of Period
$
8,541

$
10,286


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

11



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

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended
December 31, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. 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 condensed financial statements 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. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. 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 condensed 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.

On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the nine months ended September 30, 2012 resulted in an increase of $1.9 million and a decrease of $0.8 million to Energen and Alagasco’s operating cash flows, respectively. The Company and Alagasco determined that the amounts were not material to the respective statements of cash flows. This adjustment had no impact on Energen or Alagasco’s statements of income.

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. The Company’s current RSE order had an original term extending through December 31, 2014. At its meeting on November 5, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, which are described as follows. The term of the order is extended through September 30, 2018. Alagasco’s allowed range of return on average common equity will be 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. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from a 2007 base year, adjusted for inflation using the Index Range.  Alagasco expects these modifications to be included in a final written order in the fourth quarter of 2013.

Alagasco’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. 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 nine months ended September 30, 2013, Alagasco had a net $4.3 million pre-tax and a net $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million and a $13.0 million annual increase in revenues became effective December 1, 2012 and 2011, respectively.

RSE currently limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the

12



base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013 and 2012.

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, 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. 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 proscribe 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 anticipates recovering 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. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive

13



income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

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

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

(in thousands)
September 30, 2013
 
Oil and Gas Operations
 
Natural Gas Distribution

Total
Derivative assets or (liabilities) not designated as hedging instruments
 
 
 
 
Accounts receivable
$
53,082

 
$

$
53,082

Long-term asset derivative instruments
18,346

 

18,346

Total derivative assets
71,428

 

71,428

Accounts receivable
(40,789
)
*

(40,789
)
Long-term asset derivative instruments
(5,560
)
*

(5,560
)
Accounts payable
(31,928
)
 

(31,928
)
Long-term liability derivative instruments
(1,379
)
 

(1,379
)
Total derivative liabilities
(79,656
)
 

(79,656
)
Total derivatives not designated
$
(8,228
)
 
$

$
(8,228
)

(in thousands)
December 31, 2012
 
Oil and Gas Operations
 
Natural Gas Distribution

Total
Derivative assets or (liabilities) designated as hedging instruments
 
 
 
 
Accounts receivable
$
87,514

 
$

$
87,514

Long-term asset derivative instruments
37,954

 

37,954

Total derivative assets
125,468

 

125,468

Accounts receivable
(37,326
)
*

(37,326
)
Long-term asset derivative instruments
(6,810
)
*

(6,810
)
Long-term liability derivative instruments
(8,726
)
 

(8,726
)
Total derivative liabilities
(52,862
)
 

(52,862
)
Total derivatives designated
72,606

 

72,606

Derivative assets or (liabilities) not designated as hedging instruments
 
 
 
 
Accounts receivable
14,604

 

14,604

Long-term asset derivative instruments
9,433

 

9,433

Total derivative assets
24,037

 

24,037

Accounts payable

 
(2,593
)
(2,593
)
Long-term liability derivative instruments
(874
)
 

(874
)
Total derivative liabilities
(874
)
 
(2,593
)
(3,467
)
Total derivatives not designated
23,163

 
(2,593
)
20,570

Total derivatives
$
95,769

 
$
(2,593
)
$
93,176

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

14



The Company had a net $10.3 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2013, and December 31, 2012, respectively.

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

(in thousands)
Location on Statement of Income
Three months
ended
September 30, 2013
Three months
ended
September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)
$
69

$
(49,962
)
Gain reclassified from accumulated OCI into income (effective portion)
Operating revenues
$
8,455

$
15,998

Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)
Operating revenues
$
(22
)
$
(3,042
)

(in thousands)
Location on Statement of Income
Nine months
ended
September 30, 2013
Nine months
ended
September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621
$
(10,882
)
$
49,961

Gain reclassified from accumulated OCI into income (effective portion)
Operating revenues
$
29,391

$
39,012

Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)
Operating revenues
$
835

$
(1,372
)

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

(in thousands)
Location on Statement of Income
Three months
ended
September 30, 2013
Three months
ended
September 30, 2012
Loss recognized in income on derivatives
Operating revenues
$
(92,313
)
$
(45,618
)

(in thousands)
Location on Statement of Income
Nine months
ended
September 30, 2013
Nine months
ended
September 30, 2012
Gain (loss) recognized in income on derivatives
Operating revenues
$
(70,735
)
$
33,825


As of September 30, 2013, $13.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of September 30, 2013, the Company had 13.5 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 4.4 million barrels (MMBbl), 9.8 MMBbl and 5.8 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 11.9 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $6.7 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.





15



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

Production Period
Total Hedged Volumes
Average Contract
Price

Description
Natural Gas
 
 
 
2013
3.0
 Bcf
$4.82 Mcf
NYMEX Swaps
 
8.9
 Bcf
$4.51 Mcf
Basin Specific Swaps - San Juan
 
1.6
 Bcf
$3.64 Mcf
Basin Specific Swaps - Permian
2014
10.6
 Bcf
$4.55 Mcf
NYMEX Swaps
 
31.4
 Bcf
$4.60 Mcf
Basin Specific Swaps - San Juan
 
9.7
 Bcf
$3.81 Mcf
Basin Specific Swaps - Permian
2015
6.0
 Bcf
$4.07 Mcf
Basin Specific Swaps - San Juan
Oil
 
 
 
2013
2,434
 MBbl
$91.44 Bbl
NYMEX Swaps
2014
9,796
 MBbl
$92.64 Bbl
NYMEX Swaps
2015
5,760
 MBbl
$88.85 Bbl
NYMEX Swaps
Oil Basis Differential
 
 
 
2013
907
 MBbl
$(2.99) Bbl
WTS/WTI Basis Swaps*
 
1,070
 MBbl
$(1.00) Bbl
WTI/WTI Basis Swaps**
Natural Gas Liquids
 
 
 
2013
12.0
 MMGal
$1.02 Gal
Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
 
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing
 

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

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

 
September 30, 2013
(in thousands)
Level 2*
Level 3*
Total
Current assets
$
(12,712
)
$
25,005

$
12,293

Noncurrent assets
6,828

5,958

12,786

Current liabilities
(40,970
)
9,042

(31,928
)
Noncurrent liabilities
(2,580
)
1,201

(1,379
)
Net derivative asset (liability)
$
(49,434
)
$
41,206

$
(8,228
)

 
December 31, 2012
(in thousands)
Level 2*
Level 3*
Total
Current assets
$
(3,629
)
$
68,421

$
64,792

Noncurrent assets
18,899

21,678

40,577

Current liabilities
(2,593
)

(2,593
)
Noncurrent liabilities
(8,520
)
(1,080
)
(9,600
)
Net derivative asset
$
4,157

$
89,019

$
93,176

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


16



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

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $22 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

 
Three months ended
Three months ended
(in thousands)
September 30, 2013
September 30, 2012
Balance at beginning of period
$
51,131

$
103,456

Realized gains
10,852

18,737

Unrealized losses relating to instruments held at the reporting date*
(10,947
)
(46,983
)
Settlements during period
(9,830
)
(17,929
)
Balance at end of period
$
41,206

$
57,281


 
Nine months ended
Nine months ended
(in thousands)
September 30, 2013
September 30, 2012
Balance at beginning of period
$
89,019

$
65,801

Realized gains
41,952

51,858

Unrealized losses relating to instruments held at the reporting date*
(48,835
)
(9,328
)
Settlements during period
(40,930
)
(51,050
)
Balance at end of period
$
41,206

$
57,281

*Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012, respectively.






















17



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

(in thousands)
Fair Value as of September 30, 2013
Valuation Technique*
Unobservable Input*
Range
Natural Gas Basis - San Juan
 
 
 
 
2013
$
9,499

Discounted Cash Flow
Forward Basis
($0.12 - $0.14) Mcf
2014
$
27,678

Discounted Cash Flow
Forward Basis
($0.13 - $0.15) Mcf
2015
$
1,201

Discounted Cash Flow
Forward Basis
($0.20) Mcf
Natural Gas Basis - Permian
 
 
 
 
2013
$
286

Discounted Cash Flow
Forward Basis
($0.14) Mcf
2014
$
825

Discounted Cash Flow
Forward Basis
($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
 
 
 
 
2013
$
(1,897
)
Discounted Cash Flow
Forward Basis
($1.06) Bbl
Oil Basis - WTI/WTI
 
 
 
 
2013
$
(641
)
Discounted Cash Flow
Forward Basis
($0.41 - $0.50) Bbl
Natural Gas Liquids
 
 
 
 
2013
$
4,255

Discounted Cash Flow
Forward Price
 $0.74 - $0.81 Gal
*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.

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

 
September 30, 2013
 
 
 
 
Gross Amounts Not Offset in the Balance Sheets
 
(in thousands)
Gross Amounts Recognized
Gross Amounts Offset in the Balance Sheets
Net Amount Presented in the Balance Sheets
Financial Instruments
Cash Collateral Received
Net Amount
Derivative assets
$
71,428

$
(46,349
)
$
25,079

$

$

$
25,079

Derivative liabilities
$
79,656

$
(46,349
)
$
33,307

$

$

$
33,307


 
December 31, 2012
 
 
 
 
Gross Amounts Not Offset in the Balance Sheets
 
(in thousands)
Gross Amounts Recognized
Gross Amounts Offset in the Balance Sheets
Net Amount Presented in the Balance Sheets
Financial Instruments
Cash Collateral Received
Net Amount
Derivative assets
$
149,504

$
(44,135
)
$
105,369

$

$

$
105,369

Derivative liabilities
$
56,328

$
(44,135
)
$
12,193

$

$

$
12,193














18



4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

 
Three months ended
Three months ended
(in thousands, except per share amounts)
September 30, 2013
September 30, 2012
 
Net
 
Per Share
Net
 
Per Share
 
Loss
Shares
Amount
Income
Shares
Amount
Basic EPS
$
(19,298
)
72,346

$
(0.27
)
$
2,046

72,130

$
0.03

Effect of dilutive securities
 
 
 
 
 
 
Stock options
 

 
 
183

 
Non-vested restricted stock
 

 
 
3

 
Diluted EPS
$
(19,298
)
72,346

$
(0.27
)
$
2,046

72,316

$
0.03


In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.

 
Nine months ended
Nine months ended
(in thousands, except per share amounts)
September 30, 2013
September 30, 2012
 
Net
 
Per Share
Net
 
Per Share
 
Income
Shares
Amount
Income
Shares
Amount
Basic EPS
$
120,461

72,220

$
1.67

$
190,739

72,121

$
2.64

Effect of dilutive securities
 
 
 
 
 
 
Stock options
 
41

 
 
177

 
Non-vested restricted stock
 
10

 
 
3

 
Performance share awards
 
1

 
 

 
Diluted EPS
$
120,461

72,272

$
1.67

$
190,739

72,301

$
2.64


The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:



Three months ended
September 30,
 
Nine months ended
September 30,
(in thousands)
2013
2012
 
2013
2012
Stock options

850

 
875

850

Performance share awards


 
79





















19



5. SEGMENT INFORMATION
 
The Company principally is engaged in two business segments: the development, acquisition, exploration and production of oil and gas in the continental United States (oil and gas operations) and the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution).

 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2013
2012
 
2013
2012
Operating revenues from continuing operations
 
 
 
 
 
Oil and gas operations
$
272,038

$
214,620

 
$
875,350

$
799,339

Natural gas distribution
48,368

61,809

 
390,567

327,183

Total
$
320,406

$
276,429

 
$
1,265,917

$
1,126,522

Operating income (loss) from continuing operations
 
 
 
 
 
Oil and gas operations
$
18,607

$
26,913

 
$
181,948

$
280,897

Natural gas distribution
(22,544
)
(12,743
)
 
58,968

70,265

Eliminations and corporate expenses
(115
)
(206
)
 
(345
)
(857
)
Total
$
(4,052
)
$
13,964

 
$
240,571

$
350,305

Other income (expense)
 
 
 
 
 
Oil and gas operations
$
(13,209
)
$
(12,703
)
 
$
(38,686
)
$
(35,402
)
Natural gas distribution
7,973

(3,274
)
 
1,477

(10,062
)
Eliminations and other
175

186

 
405

390

Total
$
(5,061
)
$
(15,791
)
 
$
(36,804
)
$
(45,074
)
Income (loss) from continuing operations before income taxes
$
(9,113
)
$
(1,827
)
 
$
203,767

$
305,231


(in thousands)
September 30, 2013
December 31, 2012

Identifiable assets
 
 
Oil and gas operations
$
5,444,672

$
4,975,170

Natural gas distribution
1,127,487

1,177,134

Eliminations and other
42,713

23,586

Total
$
6,614,872

$
6,175,890


6. STOCK COMPENSATION

Stock Incentive Plan
Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is 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. The Company granted 134,076 non-qualified option shares during the first quarter of 2013 with a grant-date fair value of $16.66.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock. In January 2013, 46,121 shares of restricted stock were awarded with a grant date fair value of $48.36. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

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 Company common stock. Performance share awards are valued in a Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 84,311 performance share awards during the first quarter of 2013 with a two year vesting period and a grant-date fair value of $59.19. The Company also

20



granted 80,395 performance share awards during the first quarter of 2013 with a three year award period and a grant-date fair value of $60.81.

Stock Appreciation Rights Plan
The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $39.10 as of September 30, 2013.

Petrotech Incentive Plan
The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the first quarter of 2013, Energen Resources awarded 33,796 Petrotech units with a fair value of $75.67 as of September 30, 2013, none of which included a market condition. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $133.58 as of September 30, 2013. These awards have a three-year vesting period. During the third quarter of 2013, Energen Resources awarded 5,854 Petrotech units with a three-year vesting period and a fair value of $75.67 as of September 30, 2013, and 2,952 Petrotech units with a seventeen-month vesting period and a fair value of $75.88 as of September 30, 2013, none of which included a market condition.

Stock Repurchase Program
During the three months and nine months ended September 30, 2013, the Company had noncash purchases of approximately $0.8 million and $0.9 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

7. EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company’s two defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans were:



Three months ended
September 30,
 
Nine months ended
September 30,
(in thousands)
2013
2012
 
2013
2012
Components of net periodic benefit cost:
 
 
 
 
 
Service cost
$
3,602

$
2,632

 
$
10,806

$
7,895

Interest cost
2,725

2,700

 
8,161

8,101

Expected long-term return on assets
(3,713
)
(3,563
)
 
(11,139
)
(10,689
)
Actuarial loss
3,597

2,099

 
10,962

6,297

Prior service cost amortization
123

129

 
367

388

Settlement charge
17


 
161


Net periodic expense
$
6,351

$
3,997

 
$
19,318

$
11,992


There are no required contributions to the qualified pension plans during 2013. 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. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are expected to be made to the pension plans during 2013. During 2014, the Company 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 nine months ending September 30, 2013, the Company made benefit payments aggregating $0.2 million and $1.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2013. In the first quarter of 2013, the Company 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 expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco.



21




The components of net periodic postretirement benefit expense for the Company’s postretirement benefit plans were:



Three months ended
September 30,
 
Nine months ended
September 30,
(in thousands)
2013
2012
 
2013
2012
Components of net periodic benefit cost:
 
 
 
 
 
Service cost
$
444

$
463

 
$
1,333

$
1,390

Interest cost
869

1,062

 
2,605

3,186

Expected long-term return on assets
(1,242
)
(1,109
)
 
(3,727
)
(3,328
)
Actuarial loss

9

 

27

Transition amortization
324

479

 
973

1,438

Net periodic expense
$
395

$
904

 
$
1,184

$
2,713


For the three months and nine months ended September 30, 2013, the Company made contributions aggregating $0.4 million and $1.2 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.4 million to the postretirement benefit plans through the remainder of 2013.

8. COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources 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 7.5 million barrels of oil equivalent (MMBOE) through September 2017.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources’ total resulting exposure could be as much as $14 million depending on the contractor’s ability to remarket the drilling rig.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $185 million through September 2024. During both the nine months ending September 30, 2013 and 2012, Alagasco recognized approximately $36.8 million 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 146 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 September 30, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.

Income Taxes: The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards.  In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $35 million and would result in an additional deferred tax liability of $13 million.

Legal Matters: 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. 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

22



material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

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 Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’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.

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.
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 United States Environmental Protection Agency (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 EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in 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 EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site.  The letter identifies Alagasco as a potentially responsible party (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 requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

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.

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. The Company 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. The Company 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 September 30, 2013.





23



9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (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 $1,188.2 million and $1,255.8 million and both had a carrying value of $1,154.0 million at September 30, 2013 and December 31, 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $262.8 million and $284.7 million and both had a carrying value of $250.0 million at September 30, 2013 and December 31, 2012, 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.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company’s interest rate swap was a $2.1 million and a $3.3 million liability at September 30, 2013 and December 31, 2012, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.8 million and $10.7 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 credit worthiness 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. Uncollected finance receivables are written off approximately 15 months after the account has been final billed. Alagasco had finance receivables past due 90 days or more of $0.7 million and $0.5 million as of September 30, 2013 and December 31, 2012, respectively.

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, 2012
$
470

Provision
191

Allowance for credit losses as of September 30, 2013
$
661

























24



10. REGULATORY ASSETS AND LIABILITIES    

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

(in thousands)
September 30, 2013
December 31, 2012
 
Current
Noncurrent
Current
Noncurrent
Regulatory assets:
 
 
 
 
Pension assets
$
263

$
69,249

$
170

$
90,708

Accretion and depreciation for asset retirement obligation

17,579


16,536

Risk management activities


2,593


Rate recovery of asset removal costs, net

2,176


3,322

Gas supply adjustment
10,925


42,726


Other
25


26


Total regulatory assets
$
11,213

$
89,004

$
45,515

$
110,566

Regulatory liabilities:
 
 
 
 
RSE adjustment
$
6,573

$

$
1,740

$

Unbilled service margin
6,351


25,078


Postretirement liabilities

13,951


1,237

Refundable negative salvage
16,321

40,946

18,265

53,467

Gain on sale of property
10,890




Asset retirement obligation

25,772


24,930

Other
33

745

33

770

Total regulatory liabilities
$
40,168

$
81,414

$
45,116

$
80,404


11. ASSET RETIREMENT OBLIGATIONS

The Company 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 life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

During the nine months ended September 30, 2013, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
 
Balance as of December 31, 2012
$
118,023

Liabilities incurred
2,466

Liabilities settled
(542
)
Accretion expense (including discontinued operations of $944)
6,131

Reclassification associated with held for sale properties*
(19,474
)
Balance as of September 30, 2013
$
106,604

* Asset retirement obligation associated with Black Warrior Basin and North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

The Company 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 $25.8 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2013 and December 31, 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.2 million and $3.3 million as of September 30, 2013 and December 31, 2012, are

25



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.

12. DISPOSITION OF PROPERTIES

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million on the sale of its Metro Operations Center which is located in Birmingham, Alabama, and has been in service since the 1940’s. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. 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. Based upon the November 5, 2013 review by the APSC, Alagasco will recognize the deferred revenues from the 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.

13. 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, 2012
$
44,196

$
(52,507
)
$
(8,311
)
Other comprehensive income (loss) before reclassifications
(10,924
)
4,157

(6,767
)
Amounts reclassified from accumulated other comprehensive income (loss)
(17,907
)
4,721

(13,186
)
Change in accumulated other comprehensive income (loss)
(28,831
)
8,878

(19,953
)
Balance as of September 30, 2013
$
15,365

$
(43,629
)
$
(28,264
)

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

 
Three months ended
Nine months ended
 
 
September 30, 2013
September 30, 2013
 
(in thousands)
Amounts Reclassified
Line Item Where Presented
Gains and (losses) on cash flow hedges:
 
 
 
Commodity contracts
$
8,433

$
30,226

Operating revenues
Interest rate swap
(446
)
(1,282
)
Interest expense
Total cash flow hedges
7,987

28,944

 
Income tax expense
(3,048
)
(11,037
)
 
Net of tax
4,939

17,907

 
Pension and postretirement plans:
 
 
 
Transition obligation
(74
)
(220
)
Operations and maintenance
Prior service cost
(78
)
(235
)
Operations and maintenance
Actuarial losses*
(2,036
)
(6,387
)
Operations and maintenance
Actuarial losses on settlement charges*
(46
)
(421
)
Regulatory asset
Total pension and postretirement plans
(2,234
)
(7,263
)
 
Income tax expense
783

2,542

 
Net of tax
(1,451
)
(4,721
)
 
Total reclassifications for the period
$
3,488

$
13,186

 
* In the first quarter of 2013, the Company 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 is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

26



14. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

15. DISCONTINUED OPERATIONS

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company will record a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 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.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months and nine months ended September 30, 2013. 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. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.






















27



The following table details held-for-sale properties by major classes of assets and liabilities:

(in thousands)
September 30, 2013
 
Black Warrior Basin
North Louisiana/East Texas

Total
Accounts receivable
$
3,704

$
1,418

$
5,122

Inventories
1,078

63

1,141

Oil and gas properties
304,012

348,380

652,392

Less accumulated depreciation, depletion and amortization
(183,011
)
(293,935
)
(476,946
)
Other property, net
1,970

183

2,153

Total assets held-for-sale
127,753

56,109

183,862

Accounts payable
(1,713
)
(2
)
(1,715
)
Royalty payable
(792
)
(936
)
(1,728
)
Other current liabilities
(358
)
(35
)
(393
)
Other long-term liabilities
(5,377
)
(14,732
)
(20,109
)
Total liabilities held-for-sale
(8,240
)
(15,705
)
(23,945
)
Total held-for-sale properties
$
119,513

$
40,404

$
159,917


During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations in the nine months ended September 30, 2012. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources 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.



28



 
Three months ended
Nine months ended
 
September 30,
September 30,
(in thousands, except per share data)
2013
2012
2013
2012
 
 
 
 
 
Oil and gas revenues
$
18,258

$
18,895

$
55,483

$
57,601

Pretax income (loss) from discontinued operations
$
2,971

$
5,526

$
9,980

$
(6,028
)
Income tax expense (benefit)