10-Q 1 ato2014033110-q.htm 10-Q ATO 2014.03.31 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 March 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 May 1, 2014.
Class
  
Shares Outstanding
No Par Value
  
100,186,395




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
GSRS
Gas System Reliability Surcharge
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
 
 
March 31,
2014
 
September 30,
2013
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
8,014,440

 
$
7,722,019

Less accumulated depreciation and amortization
1,744,457

 
1,691,364

Net property, plant and equipment
6,269,983

 
6,030,655

Current assets
 
 
 
Cash and cash equivalents
136,740

 
66,199

Accounts receivable, net
671,021

 
301,992

Gas stored underground
124,950

 
244,741

Other current assets
126,450

 
64,201

Total current assets
1,059,161

 
677,133

Goodwill
741,363

 
741,363

Deferred charges and other assets
417,109

 
485,117

 
$
8,487,616

 
$
7,934,268

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2014 — 100,177,825 shares; September 30, 2013 — 90,640,211 shares
$
501

 
$
453

Additional paid-in capital
2,163,144

 
1,765,811

Retained earnings
924,282

 
775,267

Accumulated other comprehensive income
36,834

 
38,878

Shareholders’ equity
3,124,761

 
2,580,409

Long-term debt
1,955,829

 
2,455,671

Total capitalization
5,080,590

 
5,036,080

Current liabilities
 
 
 
Accounts payable and accrued liabilities
442,816

 
241,611

Other current liabilities
420,576

 
368,891

Short-term debt

 
367,984

Current maturities of long-term debt
500,000

 

Total current liabilities
1,363,392

 
978,486

Deferred income taxes
1,283,551

 
1,164,053

Regulatory cost of removal obligation
358,262

 
359,299

Pension and postretirement liabilities
360,851

 
358,787

Deferred credits and other liabilities
40,970

 
37,563

 
$
8,487,616

 
$
7,934,268

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 March 31
 
2014
 
2013
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
1,290,960

 
$
905,176

Regulated transmission and storage segment
73,615

 
61,848

Nonregulated segment
757,683

 
428,948

Intersegment eliminations
(157,936
)
 
(86,976
)
 
1,964,322

 
1,308,996

Purchased gas cost
 
 
 
Natural gas distribution segment
905,772

 
558,170

Regulated transmission and storage segment

 

Nonregulated segment
720,094

 
404,641

Intersegment eliminations
(157,821
)
 
(86,566
)
 
1,468,045

 
876,245

Gross profit
496,277

 
432,751

Operating expenses
 
 
 
Operation and maintenance
124,675

 
111,086

Depreciation and amortization
61,307

 
57,180

Taxes, other than income
60,215

 
54,307

Total operating expenses
246,197

 
222,573

Operating income
250,080

 
210,178

Miscellaneous income (expense)
(1,516
)
 
1,712

Interest charges
31,601

 
33,331

Income from continuing operations before income taxes
216,963

 
178,559

Income tax expense
83,596

 
66,219

Income from continuing operations
133,367

 
112,340

Income from discontinued operations, net of tax ($0 and $2,258)

 
4,085

Net income
$
133,367

 
$
116,425

Basic earnings per share
 
 
 
Income per share from continuing operations
$
1.40

 
$
1.24

Income per share from discontinued operations

 
0.04

Net income per share — basic
$
1.40

 
$
1.28

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
1.38

 
$
1.23

Income per share from discontinued operations

 
0.04

Net income per share — diluted
$
1.38

 
$
1.27

Cash dividends per share
$
0.37

 
$
0.35

Weighted average shares outstanding:
 
 
 
Basic
95,264

 
90,530

Diluted
96,191

 
91,492

See accompanying notes to condensed consolidated financial statements.

4



 ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 
 
 
 
 
 
 
 
 
Six Months Ended 
 March 31
 
2014
 
2013
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Natural gas distribution segment
$
2,134,825

 
$
1,571,963

Regulated transmission and storage segment
144,956

 
122,529

Nonregulated segment
1,205,404

 
828,842

Intersegment eliminations
(265,715
)
 
(180,183
)
 
3,219,470

 
2,343,151

Purchased gas cost
 
 
 
Natural gas distribution segment
1,450,466

 
945,326

Regulated transmission and storage segment

 

Nonregulated segment
1,149,249

 
782,076

Intersegment eliminations
(265,479
)
 
(179,364
)
 
2,334,236

 
1,548,038

Gross profit
885,234

 
795,113

Operating expenses
 
 
 
Operation and maintenance
240,432

 
217,613

Depreciation and amortization
121,776

 
116,759

Taxes, other than income
102,226

 
95,641

Total operating expenses
464,434

 
430,013

Operating income
420,800

 
365,100

Miscellaneous income (expense)
(3,648
)
 
2,410

Interest charges
63,716

 
63,853

Income from continuing operations before income taxes
353,436

 
303,657

Income tax expense
133,053

 
113,969

Income from continuing operations
220,383

 
189,688

Income from discontinued operations, net of tax ($0 and $3,986)

 
7,202

Net income
$
220,383

 
$
196,890

Basic earnings per share
 
 
 
Income per share from continuing operations
$
2.36

 
$
2.09

Income per share from discontinued operations

 
0.08

Net income per share — basic
$
2.36

 
$
2.17

Diluted earnings per share
 
 
 
Income per share from continuing operations
$
2.34

 
$
2.07

Income per share from discontinued operations

 
0.08

Net income per share — diluted
$
2.34

 
$
2.15

Cash dividends per share
$
0.74

 
$
0.70

Weighted average shares outstanding:
 
 
 
Basic
93,049

 
90,445

Diluted
93,976

 
91,406

See accompanying notes to condensed consolidated financial statements.


5




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2014
 
2013
 
2014
 
2013
 
(Unaudited)
(In thousands)
Net income
$
133,367

 
$
116,425

 
$
220,383

 
$
196,890

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(133), $(110), $1,302 and $(330)
(252
)
 
(200
)
 
2,142

 
(573
)
Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(15,546), $13,513, $(7,533) and $20,562
(27,047
)
 
23,509

 
(13,105
)
 
35,773

Net unrealized gains on commodity cash flow hedges, net of tax of $703, $5,650, $5,702 and $5,417
1,101

 
8,838

 
8,919

 
8,473

Total other comprehensive income (loss)
(26,198
)
 
32,147

 
(2,044
)
 
43,673

Total comprehensive income
$
107,169

 
$
148,572

 
$
218,339

 
$
240,563


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Six Months Ended 
 March 31
 
2014
 
2013
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
220,383

 
$
196,890

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
121,776

 
118,608

Charged to other accounts
441

 
265

Deferred income taxes
119,710

 
106,891

Other
10,746

 
5,519

Net assets / liabilities from risk management activities
836

 
(14,709
)
Net change in operating assets and liabilities
17,089

 
(37,123
)
Net cash provided by operating activities
490,981

 
376,341

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(359,009
)
 
(389,117
)
Other, net
(4,904
)
 
(3,700
)
Net cash used in investing activities
(363,913
)
 
(392,817
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(369,012
)
 
(342,141
)
Net proceeds from equity offering
390,205

 

Net proceeds from issuance of long-term debt

 
493,793

Settlement of Treasury lock agreements

 
(66,626
)
Repayment of long-term debt

 
(131
)
Cash dividends paid
(71,380
)
 
(64,008
)
Repurchase of equity awards
(6,317
)
 
(3,124
)
Other
(23
)
 
21

Net cash provided by (used in) financing activities
(56,527
)
 
17,784

Net increase in cash and cash equivalents
70,541

 
1,308

Cash and cash equivalents at beginning of period
66,199

 
64,239

Cash and cash equivalents at end of period
$
136,740

 
$
65,547


See accompanying notes to condensed consolidated financial statements.

7



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 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 transmission and storage businesses as well as certain other nonregulated businesses. For the fiscal year ended September 30, 2013, our regulated businesses generated approximately 95 percent of our consolidated net income.
Through our natural gas 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 natural gas distribution divisions, which at March 31, 2014, covered service areas located in eight states. On April 1, 2013, we completed the divestiture of our natural gas distribution operations in Georgia, representing approximately 64,000 customers. 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 natural gas 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, 2013. 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, 2013. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, 2014 are not indicative of our results of operations for the full 2014 fiscal year, which ends September 30, 2014.
Except as noted in Note 7 and Note 8, 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, 2013.
During the second quarter of fiscal 2014, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
Due to the April 1, 2013 sale of our Georgia distribution operations, prior year financial results for this service area are shown in discontinued operations.
Disclosure requirements for offsetting arrangements for financial instruments became effective for us beginning on October 1, 2013. We have presented these disclosures in Note 8. In connection with the adoption of this standard, prior-year risk management assets and liabilities have been reclassified to conform with the current-year presentation. The adoption of this standard and reclassification did not have an impact on our financial position, results of operations or cash flows. There were no other significant changes to our accounting policies nor were there new accounting standards announced during the six months ended March 31, 2014 that will become applicable to the Company in future periods.

8



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. 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 March 31, 2014 and September 30, 2013 included the following:
 
March 31,
2014
 
September 30,
2013
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
176,616

 
$
187,977

Merger and integration costs, net
4,990

 
5,250

Deferred gas costs
10,004

 
15,152

Regulatory cost of removal asset
9,716

 
10,008

Rate case costs
5,037

 
6,329

Texas Rule 8.209(2)
40,760

 
30,364

APT annual adjustment mechanism
4,084

 
5,853

Recoverable loss on reacquired debt
20,156

 
21,435

Other
6,393

 
4,380

 
$
277,756

 
$
286,748

Regulatory liabilities:
 
 
 
Deferred gas costs
$
80,330

 
$
16,481

Deferred franchise fees
11,523

 
1,689

Regulatory cost of removal obligation
425,461

 
427,524

Other
11,683

 
7,887

 
$
528,997

 
$
453,581

 
(1) 
Includes $18.1 million and $17.4 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 natural gas distribution segment, which includes our regulated natural gas distribution and related sales operations,
The regulated transmission and storage 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 natural gas distribution segment operations are geographically dispersed, they are reported as a single segment as each natural gas distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of

9



significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. We evaluate performance based on net income or loss of the respective operating units.
Income statements for the three and six month periods ended March 31, 2014 and 2013 by segment are presented in the following tables:
 
Three Months Ended March 31, 2014
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,289,429

 
$
21,002

 
$
653,891

 
$

 
$
1,964,322

Intersegment revenues
1,531

 
52,613

 
103,792

 
(157,936
)
 

 
1,290,960

 
73,615

 
757,683

 
(157,936
)
 
1,964,322

Purchased gas cost
905,772

 

 
720,094

 
(157,821
)
 
1,468,045

Gross profit
385,188

 
73,615

 
37,589

 
(115
)
 
496,277

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
106,776

 
16,595

 
1,419

 
(115
)
 
124,675

Depreciation and amortization
50,020

 
10,156

 
1,131

 

 
61,307

Taxes, other than income
60,606

 
(1,232
)
 
841

 

 
60,215

Total operating expenses
217,402

 
25,519

 
3,391

 
(115
)
 
246,197

Operating income
167,786

 
48,096

 
34,198

 

 
250,080

Miscellaneous income (expense)
97

 
(1,081
)
 
443

 
(975
)
 
(1,516
)
Interest charges
22,828

 
9,155

 
593

 
(975
)
 
31,601

Income before income taxes
145,055

 
37,860

 
34,048

 

 
216,963

Income tax expense
56,312

 
13,751

 
13,533

 

 
83,596

Net income
$
88,743

 
$
24,109

 
$
20,515

 
$

 
$
133,367

Capital expenditures
$
139,555

 
$
39,000

 
$
(113
)
 
$

 
$
178,442



 

10



 
Three Months Ended March 31, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
904,181

 
$
19,655

 
$
385,160

 
$

 
$
1,308,996

Intersegment revenues
995

 
42,193

 
43,788

 
(86,976
)
 

 
905,176

 
61,848

 
428,948

 
(86,976
)
 
1,308,996

Purchased gas cost
558,170

 

 
404,641

 
(86,566
)
 
876,245

Gross profit
347,006

 
61,848

 
24,307

 
(410
)
 
432,751

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
89,344

 
15,390

 
6,763

 
(411
)
 
111,086

Depreciation and amortization
47,631

 
8,690

 
859

 

 
57,180

Taxes, other than income
49,592

 
4,277

 
438

 

 
54,307

Total operating expenses
186,567

 
28,357

 
8,060

 
(411
)
 
222,573

Operating income
160,439

 
33,491

 
16,247

 
1

 
210,178

Miscellaneous income (expense)
2,591

 
(99
)
 
(91
)
 
(689
)
 
1,712

Interest charges
25,664

 
7,857

 
498

 
(688
)
 
33,331

Income from continuing operations before income taxes
137,366

 
25,535

 
15,658

 

 
178,559

Income tax expense
51,176

 
9,005

 
6,038

 

 
66,219

Income from continuing operations
86,190

 
16,530

 
9,620

 

 
112,340

Income from discontinued operations, net of tax
4,085

 

 

 

 
4,085

Net income
$
90,275

 
$
16,530

 
$
9,620

 
$

 
$
116,425

Capital expenditures
$
131,465

 
$
67,208

 
$
417

 
$

 
$
199,090


 

11



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2014
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,131,861

 
$
42,172

 
$
1,045,437

 
$

 
$
3,219,470

Intersegment revenues
2,964

 
102,784

 
159,967

 
(265,715
)
 

 
2,134,825

 
144,956

 
1,205,404

 
(265,715
)
 
3,219,470

Purchased gas cost
1,450,466

 

 
1,149,249

 
(265,479
)
 
2,334,236

Gross profit
684,359

 
144,956

 
56,155

 
(236
)
 
885,234

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
196,439

 
33,895

 
10,334

 
(236
)
 
240,432

Depreciation and amortization
99,571

 
19,942

 
2,263

 

 
121,776

Taxes, other than income
97,690

 
3,431

 
1,105

 

 
102,226

Total operating expenses
393,700

 
57,268

 
13,702

 
(236
)
 
464,434

Operating income
290,659

 
87,688

 
42,453

 

 
420,800

Miscellaneous income (expense)
(374
)
 
(2,262
)
 
767

 
(1,779
)
 
(3,648
)
Interest charges
46,153

 
18,112

 
1,230

 
(1,779
)
 
63,716

Income from before income taxes
244,132

 
67,314

 
41,990

 

 
353,436

Income tax expense
92,632

 
23,759

 
16,662

 

 
133,053

Net income
$
151,500

 
$
43,555

 
$
25,328

 
$

 
$
220,383

Capital expenditures
$
267,061

 
$
91,921

 
$
27

 
$

 
$
359,009



 

12



 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended March 31, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,569,730

 
$
38,354

 
$
735,067

 
$

 
$
2,343,151

Intersegment revenues
2,233

 
84,175

 
93,775

 
(180,183
)
 

 
1,571,963

 
122,529

 
828,842

 
(180,183
)
 
2,343,151

Purchased gas cost
945,326

 

 
782,076

 
(179,364
)
 
1,548,038

Gross profit
626,637

 
122,529

 
46,766

 
(819
)
 
795,113

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
173,080

 
31,710

 
13,645

 
(822
)
 
217,613

Depreciation and amortization
97,691

 
17,080

 
1,988

 

 
116,759

Taxes, other than income
86,343

 
8,226

 
1,072

 

 
95,641

Total operating expenses
357,114

 
57,016

 
16,705

 
(822
)
 
430,013

Operating income
269,523

 
65,513

 
30,061

 
3

 
365,100

Miscellaneous income (expense)
2,460

 
(226
)
 
1,576

 
(1,400
)
 
2,410

Interest charges
49,227

 
14,728

 
1,295

 
(1,397
)
 
63,853

Income from continuing operations before income taxes
222,756

 
50,559

 
30,342

 

 
303,657

Income tax expense
83,473

 
17,924

 
12,572

 

 
113,969

Income from continuing operations
139,283

 
32,635

 
17,770

 

 
189,688

Income from discontinued operations, net of tax
7,202

 

 

 

 
7,202

Net income
$
146,485

 
$
32,635

 
$
17,770

 
$

 
$
196,890

Capital expenditures
$
277,336

 
$
111,039

 
$
742

 
$

 
$
389,117

 

13



Balance sheet information at March 31, 2014 and September 30, 2013 by segment is presented in the following tables.

 
March 31, 2014
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,889,160

 
$
1,322,441

 
$
58,382

 
$

 
$
6,269,983

Investment in subsidiaries
908,939

 

 
(2,096
)
 
(906,843
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
73,165

 

 
63,575

 

 
136,740

Assets from risk management activities
58,746

 

 
7,940

 

 
66,686

Other current assets
609,806

 
14,363

 
610,515

 
(378,949
)
 
855,735

Intercompany receivables
786,428

 

 

 
(786,428
)
 

Total current assets
1,528,145

 
14,363

 
682,030

 
(1,165,377
)
 
1,059,161

Goodwill
574,190

 
132,462

 
34,711

 

 
741,363

Noncurrent assets from risk management activities
30,665

 

 
8,910

 

 
39,575

Deferred charges and other assets
350,362

 
19,585

 
7,587

 

 
377,534

 
$
8,281,461

 
$
1,488,851

 
$
789,524

 
$
(2,072,220
)
 
$
8,487,616

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,124,761

 
$
439,977

 
$
468,962

 
$
(908,939
)
 
$
3,124,761

Long-term debt
1,955,829

 

 

 

 
1,955,829

Total capitalization
5,080,590

 
439,977

 
468,962

 
(908,939
)
 
5,080,590

Current liabilities
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt
500,000

 

 

 

 
500,000

Short-term debt
343,000

 

 

 
(343,000
)
 

Other current liabilities
658,106

 
13,654

 
225,485

 
(33,853
)
 
863,392

Intercompany payables

 
708,046

 
78,382

 
(786,428
)
 

Total current liabilities
1,501,106

 
721,700

 
303,867

 
(1,163,281
)
 
1,363,392

Deferred income taxes
943,831

 
324,879

 
14,841

 

 
1,283,551

Regulatory cost of removal obligation
358,262

 

 

 

 
358,262

Pension and postretirement liabilities
360,851

 

 

 

 
360,851

Deferred credits and other liabilities
36,821

 
2,295

 
1,854

 

 
40,970

 
$
8,281,461

 
$
1,488,851

 
$
789,524

 
$
(2,072,220
)
 
$
8,487,616


14





 
September 30, 2013
 
Natural
Gas
Distribution
 
Regulated
Transmission
and Storage
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
4,719,873

 
$
1,249,767

 
$
61,015

 
$

 
$
6,030,655

Investment in subsidiaries
831,136

 

 
(2,096
)
 
(829,040
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
4,237

 

 
61,962

 

 
66,199

Assets from risk management activities
1,837

 

 
10,129

 

 
11,966

Other current assets
428,366

 
11,709

 
452,126

 
(293,233
)
 
598,968

Intercompany receivables
783,738

 

 

 
(783,738
)
 

Total current assets
1,218,178

 
11,709

 
524,217

 
(1,076,971
)
 
677,133

Goodwill
574,190

 
132,462

 
34,711

 

 
741,363

Noncurrent assets from risk management activities
109,354

 

 

 

 
109,354

Deferred charges and other assets
347,687

 
19,227

 
8,849

 

 
375,763

 
$
7,800,418

 
$
1,413,165

 
$
626,696

 
$
(1,906,011
)
 
$
7,934,268

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
2,580,409

 
$
396,421

 
$
434,715

 
$
(831,136
)
 
$
2,580,409

Long-term debt
2,455,671

 

 

 

 
2,455,671

Total capitalization
5,036,080

 
396,421

 
434,715

 
(831,136
)
 
5,036,080

Current liabilities
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt

 

 

 

 

Short-term debt
645,984

 

 

 
(278,000
)
 
367,984

Liabilities from risk management activities
1,543

 

 

 

 
1,543

Other current liabilities
491,681

 
20,288

 
110,306

 
(13,316
)
 
608,959

Intercompany payables

 
712,768

 
70,970

 
(783,738
)
 

Total current liabilities
1,139,208

 
733,056

 
181,276

 
(1,075,054
)
 
978,486

Deferred income taxes
871,360

 
283,554

 
8,960

 
179

 
1,164,053

Regulatory cost of removal obligation
359,299

 

 

 

 
359,299

Pension and postretirement liabilities
358,787

 

 

 

 
358,787

Deferred credits and other liabilities
35,684

 
134

 
1,745

 

 
37,563

 
$
7,800,418

 
$
1,413,165

 
$
626,696

 
$
(1,906,011
)
 
$
7,934,268


15




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 and six months ended March 31, 2014 and 2013 are calculated as follows:
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2014
 
2013
 
2014
 
2013
 
(In thousands, except per share amounts)
Basic Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations
$
133,367

 
$
112,340

 
$
220,383

 
$
189,688

Less: Income from continuing operations allocated to participating securities
337

 
304

 
578

 
634

Income from continuing operations available to common shareholders
$
133,030

 
$
112,036

 
$
219,805

 
$
189,054

Basic weighted average shares outstanding
95,264

 
90,530

 
93,049

 
90,445

Income from continuing operations per share — Basic
$
1.40

 
$
1.24

 
$
2.36

 
$
2.09

 
 
 
 
 
 
 
 
Basic Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations
$

 
$
4,085

 
$

 
$
7,202

Less: Income from discontinued operations allocated to participating securities

 
11

 

 
24

Income from discontinued operations available to common shareholders
$

 
$
4,074

 
$

 
$
7,178

Basic weighted average shares outstanding
95,264

 
90,530

 
93,049

 
90,445

Income from discontinued operations per share — Basic
$

 
$
0.04

 
$

 
$
0.08

Net income per share — Basic
$
1.40

 
$
1.28

 
$
2.36

 
$
2.17



16



 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2014
 
2013
 
2014
 
2013
 
(In thousands, except per share amounts)
Diluted Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations available to common shareholders
$
133,030

 
$
112,036

 
$
219,805

 
$
189,054

Effect of dilutive stock options and other shares
2

 
2

 
4

 
5

Income from continuing operations available to common shareholders
$
133,032

 
$
112,038

 
$
219,809

 
$
189,059

Basic weighted average shares outstanding
95,264

 
90,530

 
93,049

 
90,445

Additional dilutive stock options and other shares
927

 
962

 
927

 
961

Diluted weighted average shares outstanding
96,191

 
91,492

 
93,976

 
91,406

Income from continuing operations per share — Diluted
$
1.38

 
$
1.23

 
$
2.34

 
$
2.07

 
 
 
 
 
 
 
 
Diluted Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations available to common shareholders
$

 
$
4,074

 
$

 
$
7,178

Effect of dilutive stock options and other shares

 

 

 

Income from discontinued operations available to common shareholders
$

 
$
4,074

 
$

 
$
7,178

Basic weighted average shares outstanding
95,264

 
90,530

 
93,049

 
90,445

Additional dilutive stock options and other shares
927

 
962

 
927

 
961

Diluted weighted average shares outstanding
96,191

 
91,492

 
93,976

 
91,406

Income from discontinued operations per share — Diluted
$

 
$
0.04

 
$

 
$
0.08

Net income per share — Diluted
$
1.38

 
$
1.27

 
$
2.34

 
$
2.15

There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and six months ended March 31, 2014 and 2013 as their exercise price was less than the average market price of the common stock during those periods.
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 $950 million commercial paper program, to 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 six months ended March 31, 2014 and 2013 under our 2011 share repurchase program.

17




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, 2013. Except as noted below, there were no material changes in the terms of our debt instruments during the six months ended March 31, 2014.
Long-term debt
Long-term debt at March 31, 2014 and September 30, 2013 consisted of the following:
 
 
March 31, 2014
 
September 30, 2013
 
(In thousands)
Unsecured 4.95% Senior Notes, due October 2014
$
500,000

 
$
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

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
4,171

 
4,329

Current maturities
500,000

 

 
$
1,955,829

 
$
2,455,671

 
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 $950 million commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1 billion of working capital funding. At March 31, 2014, there were no short-term debt borrowings outstanding. At September 30, 2013, there was a total of $368.0 million 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 $985 million of working capital funding, including a five-year $950 million unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.2 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 March 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 (ii) the rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2014.


18



Nonregulated Operations
Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, had two $25 million 364-day bilateral credit facilities that expired in December 2013. In December 2013, the $25 million 364-day uncommitted bilateral facility was extended to December 2014. In January 2014, this facility was amended to temporarily increase the amount available to $50 million to address the increase in volumes and prices driven by colder than normal weather this winter-heating season.  The maximum available under the facility will return to $25 million on June 30, 2014. The $25 million committed bilateral facility was replaced with a $15 million committed 364-day bilateral credit facility in December 2013. 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 $33.7 million at March 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, 2014.
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. On February 18, 2014, we completed the public offering of 9,200,000 shares of our common stock, which generated net proceeds of $390.2 million. As of March 31, 2014, $1.35 billion of securities remained 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 March 31, 2014, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 46 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 March 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 and six months ended March 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 the retirement, on October 2, 2013, we made a $16.8 million benefit payment from the SEBP.

19



 
Three Months Ended March 31
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,738

 
$
5,203

 
$
4,196

 
$
4,700

Interest cost
6,824

 
6,023

 
3,988

 
3,241

Expected return on assets
(5,900
)
 
(5,738
)
 
(1,292
)
 
(997
)
Amortization of transition obligation

 

 
68

 
270

Amortization of prior service credit
(34
)
 
(36
)
 
(362
)
 
(363
)
Amortization of actuarial loss
3,930

 
5,562

 
158

 
1,049

Net periodic pension cost
$
9,558

 
$
11,014

 
$
6,756

 
$
7,900

 
 
 
 
 
 
 
 
 
Six Months Ended March 31
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
9,476

 
$
10,405

 
$
8,392

 
$
9,400

Interest cost
13,648

 
12,048

 
7,976

 
6,482

Expected return on assets
(11,801
)
 
(11,477
)
 
(2,584
)
 
(1,994
)
Amortization of transition obligation

 

 
136

 
540

Amortization of prior service credit
(68
)
 
(71
)
 
(725
)
 
(725
)
Amortization of actuarial loss
7,862

 
11,123

 
316

 
2,098

Settlement loss
4,539

 

 

 

Net periodic pension cost
$
23,656

 
$
22,028

 
$
13,511

 
$
15,801


The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2014 and 2013 are as follows:
 
Pension Benefits
 
Other Benefits
 
2014
 
2013
 
2014
 
2013
Discount rate
4.95
%
 
4.04
%
 
4.95
%
 
4.04
%
Rate of compensation increase
3.50
%
 
3.50
%
 
N/A

 
N/A

Expected return on plan assets
7.25
%
 
7.75
%
 
4.60
%
 
4.70
%
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, 2014. During the first six months of fiscal 2014, we contributed $9.1 million to our defined benefit plans and we anticipate contributing approximately $10 million to $35 million during fiscal 2014.
We contributed $11.6 million to our other post-retirement benefit plans during the six months ended March 31, 2014. We expect to contribute a total of approximately $20 million to $25 million to these plans during fiscal 2014.


20



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, 2013, except as noted below, there were no material changes in the status of such litigation and environmental-related matters or claims during the six months ended March 31, 2014.
Kentucky Litigation
Since April 2009, Atmos Energy and two subsidiaries of AEH, Atmos Energy Marketing, LLC (AEM) and Atmos Gathering Company, LLC (AGC) (collectively, the Atmos Entities), have been involved in a lawsuit filed in the Circuit Court of Edmonson County, Kentucky related to our Park City Gathering Project. The dispute which gave rise to the litigation involves the amount of royalties due from a third party producer to landowners (who own the mineral rights) for natural gas produced from the landowners’ properties. The third party producer was operating pursuant to leases between the landowners and certain investors/working interest owners. The third party producer filed a petition in bankruptcy, which was subsequently dismissed due to the lack of meaningful assets to reorganize or liquidate.
Although certain Atmos Energy companies entered into contracts with the third party producer to gather, treat and ultimately sell natural gas produced from the landowners’ properties, no Atmos Energy company had a contractual relationship with the landowners or the investors/working interest owners. After the lawsuit was filed, the landowners were successful in terminating for non-payment of royalties the leases related to the production of natural gas from their properties. Subsequent to termination, the investors/working interest owners under such leases filed additional claims against us for the termination of the leases.
During the trial, the landowners and the investors/working interest owners requested an award of compensatory damages plus punitive damages against us. On December 17, 2010, the jury returned a verdict in favor of the landowners and investor/working interest owners and awarded compensatory damages of $3.8 million and punitive damages of $27.5 million payable by Atmos Energy and the two AEH subsidiaries.
A hearing was held on February 28, 2011 to hear a number of motions, including a motion to dismiss the jury verdict and a motion for a new trial. The motions to dismiss the jury verdict and for a new trial were denied. However, the total punitive damages award was reduced from $27.5 million to $24.7 million. On October 17, 2011, we filed our brief of appellants with the Kentucky Court of Appeals, appealing the verdict of the trial court. The appellees in this case subsequently filed their appellees’ brief with the Court of Appeals on January 16, 2012, with our reply brief being filed with the Court of Appeals on March 19, 2012. Oral arguments were held in the case on August 27, 2012.
In an opinion handed down on January 25, 2013, the Court of Appeals overturned the $28.5 million jury verdict returned against the Atmos Entities. In a unanimous decision by a three-judge panel, the Court of Appeals reversed the claims asserted by the landowners and investors/working interest owners. The Court of Appeals concluded that all of such claims that the Atmos Entities appealed should have been dismissed by the trial court as a matter of law. The Court of Appeals let stand the jury verdict on one claim that Atmos Energy and our subsidiaries chose not to appeal, which was a trespass claim. The jury had awarded a total of $10,000 in compensatory damages to one landowner on that claim. The Court of Appeals vacated all of the other damages awarded by the jury and remanded the case to the trial court for a new trial, solely on the issue of whether punitive damages should be awarded to that landowner and, if so, in what amount.
The investors/working interest owners, on February 25, 2013, and the landowners, on March 19, 2013, each filed with the Supreme Court of Kentucky, separate motions for discretionary review of the opinion of the Court of Appeals. We filed responses to the motions. The Kentucky Supreme Court denied the motions for discretionary review on  February 12, 2014.  The decision of the Court of Appeals became final on February 21, 2014.  Atmos has filed a motion with the trial court for entry of judgment dismissing all claims against it, except for the trespass claim.  Atmos' motion seeks a ruling by the trial court that the remaining landowner is not entitled to any punitive damages on that claim.  That motion is currently scheduled to be heard on May 19, 2014.
We had previously accrued what we believed to be an adequate amount for the anticipated resolution of this matter. This accrual was reversed during the second fiscal quarter as the appellate process in this case has been completed.
In addition, in a related matter, on July 12, 2011, the Atmos Entities filed a lawsuit in the United States District Court, Western District of Kentucky, Atmos Energy Corporation et al.vs. Resource Energy Technologies, LLC and Robert Thorpe and John F. Charles, against the third party producer and its affiliates to recover all costs, including attorneys’ fees, incurred by the Atmos Entities, which are associated with the defense and appeal of the case discussed above as well as for all damages awarded to the plaintiffs in such case against the Atmos Entities. The total amount of damages being claimed in the lawsuit is “open-ended” since the appellate process and related costs are ongoing. This lawsuit is based upon the indemnification

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provisions agreed to by the third party producer in favor of Atmos Gathering that are contained in an agreement entered into between Atmos Gathering and the third party producer in May 2009. The defendants filed a motion to dismiss the case on August 25, 2011, with Atmos Energy filing a brief in response to such motion on September 19, 2011. On March 27, 2012 the court denied the motion to dismiss. Discovery has been completed, and dispositive motions are due on June 30, 2014.  This case is scheduled for trial beginning October 6, 2014.
Tennessee Business License Tax
Atmos Energy, through its affiliate, AEM, has been involved in a dispute with the Tennessee Department of Revenue (TDOR) regarding sales business tax audits over a period of several years. The cumulative assessment approximated $12 million as of March 31, 2014, which AEM has challenged. We had previously accrued in prior years what we believed to be an adequate amount for the anticipated resolution of this matter. With respect to certain issues, AEM and the TDOR filed competing Partial Motions for Summary Judgment with the Chancery Court. On August 2, 2013, the Chancery Court granted the TDOR's Partial Motion for Summary Judgment and denied AEM's Partial Motion for Summary Judgment. A filing deadline was set for filing any cross motions for partial summary judgment as to the remaining issues. On May 2, 2014, the Company and the TDOR executed an agreed order of dismissal with prejudice whereby AEM agreed to pay $6.2 million to resolve all business tax-related liabilities outstanding through September 2014. The order of dismissal will become effective upon approval of the Chancery Court.
We are a party to other 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.
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 March 31, 2014, AEH was committed to purchase 100.5 Bcf within one year, 15.9 Bcf within one to three years and 0.8 Bcf after three years under indexed contracts. AEH is committed to purchase 9.5 Bcf within one year and 0.8 Bcf within one to three years under fixed price contracts with prices ranging from $3.75 to $6.36 per Mcf. Purchases under these contracts totaled $621.1 million and $327.8 million for the three months ended March 31, 2014 and 2013 and $971.3 million and $617.3 million for the six months ended March 31, 2014 and 2013.
Our natural gas distribution divisions 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 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, 2013. There were no material changes to the estimated storage and transportation fees for the six months ended March 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 March 31, 2014, rate cases were in progress in our Kansas, Kentucky, Virginia and West Texas service areas, annual rate filing mechanisms were in progress in Louisiana and Mid-Tex and infrastructure program filings were in progress in Mid-Tex and Atmos Pipeline–Texas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
8.    Financial Instruments
We use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments have been tailored to our regulated and nonregulated businesses. The accounting for these financial instruments is fully described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2013. During the six months ended March 31, 2014 there were no changes in our objectives, strategies and accounting for these financial instruments. Currently, we utilize financial instruments in our natural gas

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distribution and nonregulated segments. We currently do not manage commodity price risk with financial instruments in our regulated transmission and storage segment.
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.
Regulated Commodity Risk Management Activities
Although our purchased gas cost adjustment mechanisms essentially insulate our natural gas distribution segment from commodity price risk, 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.
Our natural gas distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2013-2014 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 32 percent, or 24.6 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.
The costs associated with the gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with applicable authoritative accounting guidance. Accordingly, there is no earnings impact on our natural gas distribution segment as a result of the use of financial instruments.
Nonregulated Commodity Risk Management Activities
Our nonregulated operations aggregate and purchase gas supply, arrange transportation and/or storage logistics and ultimately deliver gas to our customers at competitive prices. To provide these services, we utilize proprietary and customer-owned transportation and storage assets to provide the various services our customers request. In an effort to offset the demand fees paid to contract for storage capacity and to maximize the value of this capacity, AEH sells financial instruments to earn a gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
As a result of these activities, our nonregulated segment is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Future contracts provide the right, but not the obligation, to buy or sell the commodity at a fixed price. Option contracts provide the right, but not the requirement, to buy or sell the commodity at a fixed price. Swap contracts require receipt of payment for the commodity based on the difference between a fixed price and the market price on the settlement date.
We use financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, to mitigate the commodity price risk in our nonregulated operations associated with deliveries under fixed-priced forward contracts to deliver gas to customers. These financial instruments have maturity dates ranging from one to 49 months. We use financial instruments, designated as fair value hedges, to hedge our natural gas inventory used in asset optimization activities in our nonregulated segment.
Our nonregulated operations also 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.
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 March 31, 2014, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $500 million and $250 million unsecured senior notes in fiscal 2015 and fiscal 2017,

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at 3.129% and 3.37%