Annual Reports

 
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  • 10-Q (Aug 2, 2017)
  • 10-Q (May 4, 2017)
  • 10-Q (Feb 7, 2017)
  • 10-Q (Aug 3, 2016)
  • 10-Q (May 4, 2016)
  • 10-Q (Feb 2, 2016)

 
8-K

 
Other

Atmos Energy 10-Q 2015

Documents found in this filing:

  1. 10-Q
  2. Ex-12
  3. Ex-15
  4. Ex-31
  5. Ex-32
  6. Ex-32
ATO 2014.12.31 10-Q


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2014
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
Texas and Virginia
 
75-1743247
(State or other jurisdiction of
incorporation or organization)
 
(IRS employer
identification no.)
 
 
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 
75240
(Zip code)
(Address of principal executive offices)
 
 
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
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. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of January 30, 2015.
Class
  
Shares Outstanding
No Par Value
  
100,862,051




GLOSSARY OF KEY TERMS
 
 
 
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated other comprehensive income
Bcf
Billion cubic feet
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings, Ltd.
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
Mcf
Thousand cubic feet
MMcf
Million cubic feet
Moody’s
Moody’s Investors Services, Inc.
NYMEX
New York Mercantile Exchange, Inc.
PPA
Pension Protection Act of 2006
PRP
Pipeline Replacement Program
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
S&P
Standard & Poor’s Corporation
SEC
United States Securities and Exchange Commission
WNA
Weather Normalization Adjustment

2



PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
December 31,
2014
 
September 30,
2014
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
8,661,288

 
$
8,447,700

Less accumulated depreciation and amortization
1,748,747

 
1,721,794

Net property, plant and equipment
6,912,541

 
6,725,906

Current assets
 
 
 
Cash and cash equivalents
123,832

 
42,258

Accounts receivable, net
607,421

 
343,400

Gas stored underground
277,916

 
278,917

Other current assets
109,595

 
111,265

Total current assets
1,118,764

 
775,840

Goodwill
742,029

 
742,029

Deferred charges and other assets
341,759

 
350,929

 
$
9,115,093

 
$
8,594,704

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2014 — 100,854,217 shares; September 30, 2014 — 100,388,092 shares
$
504

 
$
502

Additional paid-in capital
2,181,645

 
2,180,151

Retained earnings
975,975

 
917,972

Accumulated other comprehensive loss
(94,199
)
 
(12,393
)
Shareholders’ equity
3,063,925

 
3,086,232

Long-term debt
2,455,131

 
2,455,986

Total capitalization
5,519,056

 
5,542,218

Current liabilities
 
 
 
Accounts payable and accrued liabilities
397,595

 
308,086

Other current liabilities
472,113

 
405,869

Short-term debt
550,903

 
196,695

Total current liabilities
1,420,611

 
910,650

Deferred income taxes
1,256,443

 
1,286,616

Regulatory cost of removal obligation
443,931

 
445,387

Pension and postretirement liabilities
345,350

 
340,963

Deferred credits and other liabilities
129,702

 
68,870

 
$
9,115,093

 
$
8,594,704

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 December 31
 
2014
 
2013
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
846,772

 
$
843,865

Regulated pipeline segment
83,567

 
71,341

Nonregulated segment
462,288

 
436,431

Intersegment eliminations
(133,862
)
 
(107,779
)
 
1,258,765

 
1,243,858

Purchased gas cost
 
 
 
Regulated distribution segment
522,960

 
544,694

Regulated pipeline segment

 

Nonregulated segment
446,249

 
417,865

Intersegment eliminations
(133,729
)
 
(107,658
)
 
835,480

 
854,901

Gross profit
423,285

 
388,957

Operating expenses
 
 
 
Operation and maintenance
118,582

 
115,757

Depreciation and amortization
67,593

 
60,469

Taxes, other than income
49,385

 
42,011

Total operating expenses
235,560

 
218,237

Operating income
187,725

 
170,720

Miscellaneous expense
(1,707
)
 
(2,132
)
Interest charges
29,764

 
32,115

Income before income taxes
156,254

 
136,473

Income tax expense
58,659

 
49,457

Net income
$
97,595

 
$
87,016

Basic net income per share
$
0.96

 
$
0.95

Diluted net income per share
$
0.96

 
$
0.95

Cash dividends per share
$
0.39

 
$
0.37

Weighted average shares outstanding:
 
 
 
Basic
101,581

 
91,841

Diluted
101,581

 
91,843

See accompanying notes to condensed consolidated financial statements.
 
 
 
 
 
 
 
 


4




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 December 31
 
2014
 
2013
 
(Unaudited)
(In thousands)
Net income
$
97,595

 
$
87,016

Other comprehensive income (loss), net of tax
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(613) and $1,435
(1,067
)
 
2,394

Cash flow hedges:
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(29,768) and $8,013
(51,787
)
 
13,942

Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $(18,696) and $4,999
(28,952
)
 
7,818

Total other comprehensive income (loss)
(81,806
)
 
24,154

Total comprehensive income
$
15,789

 
$
111,170


See accompanying notes to condensed consolidated financial statements.

5



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Three Months Ended 
 December 31
 
2014
 
2013
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
97,595

 
$
87,016

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
67,593

 
60,469

Charged to other accounts
275

 
221

Deferred income taxes
55,418

 
47,127

Other
4,889

 
5,228

Net assets / liabilities from risk management activities
(20,828
)
 
(5,477
)
Net change in operating assets and liabilities
(177,527
)
 
(160,284
)
Net cash provided by operating activities
27,415

 
34,300

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(261,313
)
 
(180,567
)
Other, net
(739
)
 
(5,867
)
Net cash used in investing activities
(262,052
)
 
(186,434
)
Cash Flows From Financing Activities
 
 
 
Net increase in short-term debt
350,574

 
320,783

Net proceeds from issuance of long-term debt
493,538

 

Settlement of interest rate agreements
13,364

 

Repayment of long-term debt
(500,000
)
 

Cash dividends paid
(39,592
)
 
(33,984
)
Repurchase of equity awards
(7,985
)
 
(6,289
)
Issuance of common stock
6,312

 
(12
)
Net cash provided by financing activities
316,211

 
280,498

Net increase in cash and cash equivalents
81,574

 
128,364

Cash and cash equivalents at beginning of period
42,258

 
66,199

Cash and cash equivalents at end of period
$
123,832

 
$
194,563


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2014
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and pipeline businesses as well as other nonregulated natural gas businesses. Historically, our regulated businesses have generated over 90 percent of our consolidated net income.
Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at December 31, 2014, covered service areas located in eight states. In addition, we transport natural gas for others through our distribution system. Our regulated businesses also include our regulated pipeline and storage operations, which include the transportation of natural gas to our North Texas distribution system and the management of our underground storage facilities. Our regulated businesses are subject to federal and state regulation and/or regulation by local authorities in each of the states in which our regulated distribution divisions operate.
Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy, and third parties.

2.    Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2014 are not indicative of our results of operations for the full 2015 fiscal year, which ends September 30, 2015.
No events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

Significant accounting policies
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014.
Certain prior-year amounts have been reclassified to conform with the current year presentation.
In May 2014, the FASB issued a comprehensive new revenue recognition standard that will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. The new standard is currently scheduled to become effective for us beginning on October 1, 2017 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.
There were no other significant changes to our accounting policies during the three months ended December 31, 2014 that will become applicable to the Company in future periods.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process.

7



Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
 
Significant regulatory assets and liabilities as of December 31, 2014 and September 30, 2014 included the following:
 
December 31,
2014
 
September 30,
2014
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
158,190

 
$
162,777

Merger and integration costs, net
4,595

 
4,730

Deferred gas costs
38,022

 
20,069

Rate case costs
2,427

 
3,757

Texas Rule 8.209(2)
36,100

 
26,948

APT annual adjustment mechanism
5,623

 
8,479

Recoverable loss on reacquired debt
18,238

 
18,877

Other
4,297

 
4,672

 
$
267,492

 
$
250,309

Regulatory liabilities:
 
 
 
Deferred gas costs
$
61,530

 
$
35,063

Deferred franchise fees
7,367

 
5,268

Regulatory cost of removal obligation
489,210

 
490,448

Other
13,808

 
14,980

 
$
571,915

 
$
545,759

 
(1) 
Includes $17.7 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2) 
Texas Rule 8.209 is a Railroad Commission rule that allows for the deferral of all expenses associated with capital expenditures incurred pursuant to this rule, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates.
Currently authorized rates do not include a return on certain of our merger and integration costs; however, we recover the amortization of these costs. Merger and integration costs, net, are generally amortized on a straight-line basis over estimated useful lives ranging up to 20 years.
3.    Segment Information
We operate the Company through the following three segments:
The regulated distribution segment, which includes our regulated natural gas distribution and related sales operations,
The regulated pipeline segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
 
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our regulated distribution segment operations are geographically dispersed, they are reported as a single segment as each regulated distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. We evaluate performance based on net income or loss of the respective operating units.

8



Income statements for the three month periods ended December 31, 2014 and 2013 by segment are presented in the following tables:
 
Three Months Ended December 31, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
845,404

 
$
20,551

 
$
392,810

 
$

 
$
1,258,765

Intersegment revenues
1,368

 
63,016

 
69,478

 
(133,862
)
 

 
846,772

 
83,567

 
462,288

 
(133,862
)
 
1,258,765

Purchased gas cost
522,960

 

 
446,249

 
(133,729
)
 
835,480

Gross profit
323,812

 
83,567

 
16,039

 
(133
)
 
423,285

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
86,985

 
24,615

 
7,115

 
(133
)
 
118,582

Depreciation and amortization
55,086

 
11,382

 
1,125

 

 
67,593

Taxes, other than income
43,644

 
4,865

 
876

 

 
49,385

Total operating expenses
185,715

 
40,862

 
9,116

 
(133
)
 
235,560

Operating income
138,097

 
42,705

 
6,923

 

 
187,725

Miscellaneous income (expense)
(1,329
)
 
(252
)
 
300

 
(426
)
 
(1,707
)
Interest charges
21,640

 
8,324

 
226

 
(426
)
 
29,764

Income before income taxes
115,128

 
34,129

 
6,997

 

 
156,254

Income tax expense
43,741

 
12,094

 
2,824

 

 
58,659

Net income
$
71,387

 
$
22,035

 
$
4,173

 
$

 
$
97,595

Capital expenditures
$
166,247

 
$
94,754

 
$
312

 
$

 
$
261,313


9



 
Three Months Ended December 31, 2013
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
842,432

 
$
21,170

 
$
380,256

 
$

 
$
1,243,858

Intersegment revenues
1,433

 
50,171

 
56,175

 
(107,779
)
 

 
843,865

 
71,341

 
436,431

 
(107,779
)
 
1,243,858

Purchased gas cost
544,694

 

 
417,865

 
(107,658
)
 
854,901

Gross profit
299,171

 
71,341

 
18,566

 
(121
)
 
388,957

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
89,663

 
17,300

 
8,915

 
(121
)
 
115,757

Depreciation and amortization
49,551

 
9,786

 
1,132

 

 
60,469

Taxes, other than income
37,084

 
4,663

 
264

 

 
42,011

Total operating expenses
176,298

 
31,749

 
10,311

 
(121
)
 
218,237

Operating income
122,873

 
39,592

 
8,255

 

 
170,720

Miscellaneous income (expense)
(471
)
 
(1,181
)
 
324

 
(804
)
 
(2,132
)
Interest charges
23,325

 
8,957

 
637

 
(804
)
 
32,115

Income before income taxes
99,077

 
29,454

 
7,942

 

 
136,473

Income tax expense
36,320

 
10,008

 
3,129

 

 
49,457

Net income
$
62,757

 
$
19,446

 
$
4,813

 
$

 
$
87,016

Capital expenditures
$
127,506

 
$
52,921

 
$
140

 
$

 
$
180,567

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

10



Balance sheet information at December 31, 2014 and September 30, 2014 by segment is presented in the following tables:

 
December 31, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,310,469

 
$
1,544,320

 
$
57,752

 
$

 
$
6,912,541

Investment in subsidiaries
949,428

 

 
(2,096
)
 
(947,332
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
79,345

 

 
44,487

 

 
123,832

Assets from risk management activities
852

 

 
17,402

 

 
18,254

Other current assets
733,736

 
13,881

 
500,168

 
(271,107
)
 
976,678

Intercompany receivables
835,928

 

 

 
(835,928
)
 

Total current assets
1,649,861

 
13,881

 
562,057

 
(1,107,035
)
 
1,118,764

Goodwill
574,816

 
132,502

 
34,711

 

 
742,029

Noncurrent assets from risk management activities
124

 

 

 

 
124

Deferred charges and other assets
316,704

 
19,578

 
5,353

 

 
341,635

 
$
8,801,402

 
$
1,710,281

 
$
657,777

 
$
(2,054,367
)
 
$
9,115,093

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,063,925

 
$
504,648

 
$
444,780

 
$
(949,428
)
 
$
3,063,925

Long-term debt
2,455,131

 

 

 

 
2,455,131

Total capitalization
5,519,056

 
504,648

 
444,780

 
(949,428
)
 
5,519,056

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
791,503

 

 

 
(240,600
)
 
550,903

Liabilities from risk management activities
13,701

 

 

 

 
13,701

Other current liabilities
675,685

 
23,722

 
185,011

 
(28,411
)
 
856,007

Intercompany payables

 
805,723

 
30,205

 
(835,928
)
 

Total current liabilities
1,480,889

 
829,445

 
215,216

 
(1,104,939
)
 
1,420,611

Deferred income taxes
887,452

 
376,018

 
(7,027
)
 

 
1,256,443

Noncurrent liabilities from risk management activities
82,123

 

 

 

 
82,123

Regulatory cost of removal obligation
443,931

 

 

 

 
443,931

Pension and postretirement liabilities
345,350

 

 

 

 
345,350

Deferred credits and other liabilities
42,601

 
170

 
4,808

 

 
47,579

 
$
8,801,402

 
$
1,710,281

 
$
657,777

 
$
(2,054,367
)
 
$
9,115,093


11





 
September 30, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,202,761

 
$
1,464,572

 
$
58,573

 
$

 
$
6,725,906

Investment in subsidiaries
952,171

 

 
(2,096
)
 
(950,075
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
33,303

 

 
8,955

 

 
42,258

Assets from risk management activities
23,102

 

 
22,725

 

 
45,827

Other current assets
490,408

 
14,009

 
526,161

 
(342,823
)
 
687,755

Intercompany receivables
790,442

 

 

 
(790,442
)
 

Total current assets
1,337,255

 
14,009

 
557,841

 
(1,133,265
)
 
775,840

Goodwill
574,816

 
132,502

 
34,711

 

 
742,029

Noncurrent assets from risk management activities
13,038

 

 

 

 
13,038

Deferred charges and other assets
309,965

 
21,826

 
6,100

 

 
337,891

 
$
8,390,006

 
$
1,632,909

 
$
655,129

 
$
(2,083,340
)
 
$
8,594,704

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,086,232

 
$
482,612

 
$
469,559

 
$
(952,171
)
 
$
3,086,232

Long-term debt
2,455,986

 

 

 

 
2,455,986

Total capitalization
5,542,218

 
482,612

 
469,559

 
(952,171
)
 
5,542,218

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
522,695

 

 

 
(326,000
)
 
196,695

Liabilities from risk management activities
1,730

 

 

 

 
1,730

Other current liabilities
559,765

 
24,790

 
142,397

 
(14,727
)
 
712,225

Intercompany payables

 
763,635

 
26,807

 
(790,442
)
 

Total current liabilities
1,084,190

 
788,425

 
169,204

 
(1,131,169
)
 
910,650

Deferred income taxes
913,260

 
361,688

 
11,668

 

 
1,286,616

Noncurrent liabilities from risk management activities
20,126

 

 

 

 
20,126

Regulatory cost of removal obligation
445,387

 

 

 

 
445,387

Pension and postretirement liabilities
340,963

 

 

 

 
340,963

Deferred credits and other liabilities
43,862

 
184

 
4,698

 

 
48,744

 
$
8,390,006

 
$
1,632,909

 
$
655,129

 
$
(2,083,340
)
 
$
8,594,704


12




4.    Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three months ended December 31, 2014 and 2013 are calculated as follows:
 
Three Months Ended 
 December 31
 
2014
 
2013
 
(In thousands, except per share amounts)
Basic Earnings Per Share
 
 
 
Net income
$
97,595

 
$
87,016

Less: Income allocated to participating securities
216

 
232

Income available to common shareholders
$
97,379

 
$
86,784

Basic weighted average shares outstanding
101,581

 
91,841

Net income per share - Basic
$
0.96

 
$
0.95

Diluted Earnings Per Share
 
 
 
Net income available to common shareholders
$
97,379

 
$
86,784

Effect of dilutive stock options and other shares

 

Net income available to common shareholders
$
97,379

 
$
86,784

Basic weighted average shares outstanding
101,581

 
91,841

Additional dilutive stock options and other shares

 
2

Diluted weighted average shares outstanding
101,581

 
91,843

Net income per share - Diluted
$
0.96

 
$
0.95


There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three months ended December 31, 2013 as their exercise price was less than the average market price of the common stock during those periods. As of December 31, 2014 there were no outstanding options.
2014 Equity Offering
On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, including the underwriters’ exercise of their overallotment option of 1,200,000 shares under our existing shelf registration statement. The offering was priced at $44.00 and generated net proceeds of $390.2 million, which were used to repay short-term debt outstanding under our commercial paper program, fund infrastructure spending primarily to enhance the safety and reliability of our system and for general corporate purposes.
2011 Share Repurchase Program
We did not repurchase any shares during the three months ended December 31, 2014 and 2013 under our 2011 share repurchase program.

13




5.    Debt
The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. Except as noted below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2014.
Long-term debt
Long-term debt at December 31, 2014 and September 30, 2014 consisted of the following:
 
 
December 31, 2014
 
September 30, 2014
 
(In thousands)
Unsecured 4.95% Senior Notes, due October 2014
$

 
$
500,000

Unsecured 6.35% Senior Notes, due 2017
250,000

 
250,000

Unsecured 8.50% Senior Notes, due 2019
450,000

 
450,000

Unsecured 5.95% Senior Notes, due 2034
200,000

 
200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

 
400,000

Unsecured 4.15% Senior Notes, due 2043
500,000

 
500,000

Unsecured 4.125% Senior Notes, due 2044
500,000

 

Medium-term note Series A, 1995-1, 6.67%, due 2025
10,000

 
10,000

Unsecured 6.75% Debentures, due 2028
150,000

 
150,000

Total long-term debt
2,460,000

 
2,460,000

Less:
 
 
 
Original issue discount on unsecured senior notes and debentures
4,869

 
4,014

 
$
2,455,131

 
$
2,455,986

 
On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds of approximately $494 million were used to repay our $500 million 4.95% senior unsecured notes at maturity on October 15, 2014.

Short-term debt
Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. Our short-term borrowing requirements are affected primarily by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
We currently finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1.3 billion of working capital funding. At December 31, 2014 and September 30, 2014 a total of $550.9 million and $196.7 million was outstanding under our commercial paper program.
Regulated Operations
We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.3 billion of working capital funding, including a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 billion, a $25 million unsecured facility and a $10 million unsecured revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.1 million at December 31, 2014.
In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or

14



(ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.
Nonregulated Operations
Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million 364-day bilateral credit facility and one committed $15 million 364-day bilateral credit facility that expire in December 2015. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $31.1 million at December 31, 2014.
AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the one-month LIBOR rate plus 3.00 percent or (ii) the rate for AEM's borrowings under its committed credit facility plus 0.75 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2015.
Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013 that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. At December 31, 2014, $845 million of securities remain available for issuance under the shelf registration statement until March 28, 2016.
Debt Covenants
The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2014, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 51 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.
In addition to these financial covenants, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.
Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.
We were in compliance with all of our debt covenants as of December 31, 2014. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

6.     Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2014 and 2013 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense. On October 2, 2013, due to the retirement of one of our executive officers, we recognized a settlement loss of $4.5 million associated with our Supplemental Executive Benefits Plan (SEBP). In association with his retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.

15



 
Three Months Ended December 31
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
5,051

 
$
4,738

 
$
3,896

 
$
4,196

Interest cost
6,699

 
6,824

 
3,596

 
3,988

Expected return on assets
(6,436
)
 
(5,901
)
 
(1,608
)
 
(1,292
)
Amortization of transition obligation

 

 
68

 
68

Amortization of prior service credit
(49
)
 
(34
)
 
(411
)
 
(363
)
Amortization of actuarial loss
3,917

 
3,932

 

 
158

Settlement loss

 
4,539

 

 

Net periodic pension cost
$
9,182

 
$
14,098

 
$
5,541

 
$
6,755

 
 
 
 
 
 
 
 

The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2014 and 2013 are as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
2014
 
2013
 
2014
 
2013
Discount rate
 
4.43
%
 
4.95
%
 
4.43
%
 
4.95
%
Rate of compensation increase
 
3.50
%
 
3.50
%
 
N/A

 
N/A

Expected return on plan assets
 
7.25
%
 
7.25
%
 
4.60
%
 
4.60
%
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2015. Due to current market conditions, the current funded position of the plans and the funding requirements under the PPA, we were not required to make a contribution to our defined benefit plans during the first quarter of fiscal 2015, nor do we anticipate making a contribution during the remainder of the fiscal year.
We contributed $5.6 million to our other post-retirement benefit plans during the three months ended December 31, 2014. We expect to contribute a total of approximately $20 million to $25 million to these plans during all of fiscal 2015.
In October 2014, the Society of Actuaries released its final report on mortality tables and the mortality improvement scale to reflect increasing life expectancies in the United States. We anticipate utilizing the new mortality data in our next actuarial calculation date on September 30, 2015. We are currently evaluating the impact the updated data will have on the valuation of our defined benefit and other post-retirement benefits plans. It is expected the use of this new data will increase the total amount of liabilities reported on our balance sheet in future periods by less than five percent.

7.    Commitments and Contingencies
Litigation and Environmental Matters
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 10 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2014.
We are a party to various litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

16



Purchase Commitments
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At December 31, 2014, AEH was committed to purchase 93.2 Bcf within one year, 11.6 Bcf within one to three years and 0.4 Bcf after three years under indexed contracts. AEH is committed to purchase 5.1 Bcf within one year under fixed price contracts with prices ranging from $1.22 to $4.49 per Mcf. Purchases under these contracts totaled $383.0 million and $350.2 million for the three months ended December 31, 2014 and 2013.
Our regulated distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at prices indexed to natural gas distribution hubs. At December 31, 2014, we were committed to purchase 47.0 Bcf within one year and 57.7 Bcf within one to three years under indexed contracts. Purchases under these contracts totaled $46.5 million, and $30.4 million for the three months ended December 31, 2014 and 2013.
Our nonregulated segment maintains long-term contracts related to storage and transportation. The estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. There were no material changes to the estimated storage and transportation fees for the three months ended December 31, 2014.
Regulatory Matters
Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations.  Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.
As of December 31, 2014, rate cases were in progress in our Mid-Tex and Tennessee service areas, annual rate filing mechanisms were in progress in Louisiana, Texas and Mississippi and an infrastructure program and an other ratemaking filing were in progress in Kansas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
8.    Financial Instruments
We currently use financial instruments in our regulated distribution and nonregulated segments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments, which have been tailored to our regulated distribution and nongregulated segments, and the related accounting for these financial instruments are fully described in Notes 2 and 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the three months ended December 31, 2014 there were no changes in our objectives, strategies and accounting for using financial instruments. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions. The following summarizes those objectives and strategies.

Regulated Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our regulated distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2014-2015 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 37 percent, or 28.2 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Nonregulated Commodity Risk Management Activities
Our nonregulated segment is exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. We manage our exposure to such risks through

17



a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Specifically, these operations use financial instruments in the following ways:
Gas delivery and related services - Certain financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, are used to mitigate the commodity price risk associated with deliveries under fixed-priced forward contracts to either deliver gas to customers or purchase gas from suppliers. These financial instruments have maturity dates ranging from one to 58 months.
Transportation and storage services - Our nonregulated operations use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges for accounting purposes.
Aggregating and purchasing gas supply - Certain financial instruments, designated as fair value hedges, are used to hedge our natural gas inventory used in asset optimization activities.

Interest Rate Risk Management Activities
We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
As of December 31, 2014, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $250 million and $450 million unsecured senior notes in fiscal 2017 and fiscal 2019, at 3.37% and 3.78%, which we designated as cash flow hedges at the time the agreements were executed. As of December 31, 2014, we had $18.9 million net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extends through fiscal 2045.
 
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of December 31, 2014, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2014, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type
 
Hedge Designation
 
Regulated
Distribution
 
Nonregulated
 
 
 
 
Quantity (MMcf)
Commodity contracts
 
Fair Value
 

 
(17,225
)
 
 
Cash Flow
 

 
65,720

 
 
Not designated
 
16,493

 
76,750

 
 
 
 
16,493

 
125,245


18



Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2014 and September 30, 2014. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties.
 
 
 
Regulated Distribution
 
Nonregulated
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
 (In thousands)
December 31, 2014
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$

 
$

 
$
38,443

 
$
(62,886
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 

 
1,123

 
(9,136
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 
(80,721
)
 

 

Total
 
 

 
(80,721
)
 
39,566

 
(72,022
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
852

 
(13,701
)
 
179,884

 
(175,804
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
124

 
(1,402
)
 
9,036

 
(6,759
)
Total
 
 
976

 
(15,103
)
 
188,920

 
(182,563
)
Gross Financial Instruments
 
 
976

 
(95,824
)
 
228,486

 
(254,585
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 

 

 
(228,486
)
 
228,486

Net Financial Instruments
 
 
976

 
(95,824
)
 

 
(26,099
)
Cash collateral
 
 

 

 
17,402

 
26,099

Net Assets/Liabilities from Risk Management Activities
 
 
$
976

 
$
(95,824
)
 
$
17,402

 
$

 
 

19



 
 
 
Regulated Distribution
 
Nonregulated
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2014
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$

 
$

 
$
8,912

 
$
(7,082
)
Interest rate contracts
Other current assets /
Other current liabilities
 
21,869

 

 

 

Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 

 
757

 
(2,459
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
12,608

 
(19,835
)
 

 

Total
 
 
34,477

 
(19,835
)
 
9,669

 
(9,541
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
1,233

 
(1,730
)
 
43,677

 
(47,729
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
430

 
(291
)
 
15,677

 
(14,786
)
Total
 
 
1,663

 
(2,021
)
 
59,354

 
(62,515
)
Gross Financial Instruments
 
 
36,140

 
(21,856
)
 
69,023

 
(72,056
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 

 

 
(69,023
)
 
69,023

Net Financial Instruments
 
 
36,140

 
(21,856
)
 

 
(3,033
)
Cash collateral
 
 

 

 
22,725

 
3,033

Net Assets/Liabilities from Risk Management Activities
 
 
$
36,140

 
$
(21,856
)
 
$
22,725

 
$

 
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of unrealized gross profit and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended December 31, 2014 and 2013 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(2.2) million and $5.1 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2014 and 2013 is presented below.
 
Three Months Ended 
 December 31
 
2014
 
2013
 
(In thousands)
Commodity contracts
$
15,090

 
$
(8,561
)
Fair value adjustment for natural gas inventory designated as the hedged item
(16,782
)
 
13,779

Total (increase) decrease in purchased gas cost
$
(1,692
)
 
$
5,218

The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
986

 
$
(620
)
Timing ineffectiveness
(2,678
)
 
5,838

 
$
(1,692
)
 
$
5,218

 
 
 
 

20



Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.

Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2014 and 2013 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
Three Months Ended December 31, 2014
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$