ATO 2015.06.30 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 June 30, 2015
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 July 31, 2015.
Class
  
Shares Outstanding
No Par Value
  
101,369,699




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
 
 
June 30,
2015
 
September 30,
2014
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
9,017,043

 
$
8,447,700

Less accumulated depreciation and amortization
1,804,955

 
1,721,794

Net property, plant and equipment
7,212,088

 
6,725,906

Current assets
 
 
 
Cash and cash equivalents
43,153

 
42,258

Accounts receivable, net
301,743

 
343,400

Gas stored underground
213,151

 
278,917

Other current assets
58,602

 
111,265

Total current assets
616,649

 
775,840

Goodwill
742,029

 
742,029

Deferred charges and other assets
313,723

 
350,929

 
$
8,884,489

 
$
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: June 30, 2015 — 101,336,818 shares; September 30, 2014 — 100,388,092 shares
$
507

 
$
502

Additional paid-in capital
2,207,102

 
2,180,151

Retained earnings
1,092,887

 
917,972

Accumulated other comprehensive loss
(62,241
)
 
(12,393
)
Shareholders’ equity
3,238,255

 
3,086,232

Long-term debt
2,455,303

 
2,455,986

Total capitalization
5,693,558

 
5,542,218

Current liabilities
 
 
 
Accounts payable and accrued liabilities
227,256

 
308,086

Other current liabilities
437,344

 
405,869

Short-term debt
251,977

 
196,695

Total current liabilities
916,577

 
910,650

Deferred income taxes
1,429,090

 
1,286,616

Regulatory cost of removal obligation
432,153

 
445,387

Pension and postretirement liabilities
318,140

 
340,963

Deferred credits and other liabilities
94,971

 
68,870

 
$
8,884,489

 
$
8,594,704

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 June 30
 
2015
 
2014
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
416,794

 
$
517,707

Regulated pipeline segment
97,008

 
87,189

Nonregulated segment
278,769

 
465,485

Intersegment eliminations
(106,170
)
 
(127,211
)
 
686,401

 
943,170

Purchased gas cost
 
 
 
Regulated distribution segment
149,775

 
260,042

Regulated pipeline segment

 

Nonregulated segment
260,990

 
450,672

Intersegment eliminations
(106,037
)
 
(127,077
)
 
304,728

 
583,637

Gross profit
381,673

 
359,533

Operating expenses
 
 
 
Operation and maintenance
132,447

 
125,559

Depreciation and amortization
68,444

 
63,955

Taxes, other than income
63,175

 
63,414

Total operating expenses
264,066

 
252,928

Operating income
117,607

 
106,605

Miscellaneous income (expense)
634

 
(374
)
Interest charges
27,955

 
31,840

Income before income taxes
90,286

 
74,391

Income tax expense
34,005

 
28,670

Net income
$
56,281

 
$
45,721

Basic net income per share
$
0.55

 
$
0.45

Diluted net income per share
$
0.55

 
$
0.45

Cash dividends per share
$
0.39

 
$
0.37

Weighted average shares outstanding:
 
 
 
Basic
102,000

 
101,162

Diluted
102,000

 
101,163

See accompanying notes to condensed consolidated financial statements.













4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
 
 
 
 
 
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
2,394,179

 
$
2,652,532

Regulated pipeline segment
272,305

 
232,145

Nonregulated segment
1,179,379

 
1,660,131

Intersegment eliminations
(360,629
)
 
(392,926
)
 
3,485,234

 
4,151,882

Purchased gas cost
 
 
 
Regulated distribution segment
1,397,113

 
1,710,508

Regulated pipeline segment

 

Nonregulated segment
1,122,655

 
1,589,163

Intersegment eliminations
(360,230
)
 
(392,556
)
 
2,159,538

 
2,907,115

Gross profit
1,325,696

 
1,244,767

Operating expenses
 
 
 
Operation and maintenance
384,489

 
365,991

Depreciation and amortization
204,059

 
185,731

Taxes, other than income
181,606

 
165,640

Total operating expenses
770,154

 
717,362

Operating income
555,542

 
527,405

Miscellaneous expense
(2,634
)
 
(4,022
)
Interest charges
85,166

 
95,556

Income before income taxes
467,742

 
427,827

Income tax expense
176,182

 
161,723

Net income
291,560

 
266,104

Basic net income per share
$
2.86

 
$
2.76

Diluted net income per share
$
2.86

 
$
2.76

Cash dividends per share
$
1.17

 
$
1.11

Weighted average shares outstanding:
 
 
 
Basic
101,776

 
96,392

Diluted
101,776

 
96,394

See accompanying notes to condensed consolidated financial statements.


5




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(Unaudited)
(In thousands)
Net income
$
56,281

 
$
45,721

 
$
291,560

 
$
266,104

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(41), $216, $(170) and $1,518
(191
)
 
377

 
(296
)
 
2,519

Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $31,314, $(13,472), $(17,232) and $(21,005)
54,475

 
(23,440
)
 
(29,981
)
 
(36,545
)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $7,393, $(1,580), $(12,698) and $4,122
11,563

 
(2,471
)
 
(19,571
)
 
6,448

Total other comprehensive income (loss)
65,847

 
(25,534
)
 
(49,848
)
 
(27,578
)
Total comprehensive income
$
122,128

 
$
20,187

 
$
241,712

 
$
238,526


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
291,560

 
$
266,104

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
204,059

 
185,731

Charged to other accounts
853

 
669

Deferred income taxes
164,627

 
150,457

Other
18,146

 
21,587

Net assets / liabilities from risk management activities
(13,136
)
 
3,158

Net change in operating assets and liabilities
51,473

 
2,504

Net cash provided by operating activities
717,582

 
630,210

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(667,483
)
 
(552,600
)
Other, net
(1,119
)
 
(620
)
Net cash used in investing activities
(668,602
)
 
(553,220
)
Cash Flows From Financing Activities
 
 
 
Net increase (decrease) in short-term debt
48,830

 
(366,602
)
Net proceeds from equity offering

 
390,205

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
(116,645
)
 
(108,806
)
Repurchase of equity awards
(7,985
)
 
(8,717
)
Issuance of common stock
20,813

 
2,152

Net cash used in financing activities
(48,085
)
 
(91,768
)
Net increase (decrease) in cash and cash equivalents
895

 
(14,778
)
Cash and cash equivalents at beginning of period
42,258

 
66,199

Cash and cash equivalents at end of period
$
43,153

 
$
51,421


See accompanying notes to condensed consolidated financial statements.

7



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2015
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 June 30, 2015, 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 nine-month period ended June 30, 2015 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.
During the second quarter of fiscal 2015, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
In May 2014, the Financial Accounting Standards Board (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. On July 9, 2015, the FASB voted to approve a deferral of the effective date of the new standard by one year. With the one year extension, the new standard is currently scheduled to become effective for us beginning on October 1, 2018 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.
In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new standard will be effective for us beginning on October 1, 2016, and will be applied retrospectively. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.

8



In April 2015, the FASB issued guidance to simplify the accounting for fees paid in connection with arrangements with cloud-based software providers. Under the new guidance, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. The new guidance is effective for us beginning October 1, 2016 and may be applied either prospectively or retrospectively with early adoption permitted. We anticipate the adoption of this standard will not have a material impact on our financial position, results of operations and cash flows.
There were no other significant changes to our accounting policies during the nine months ended June 30, 2015 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. 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 June 30, 2015 and September 30, 2014 included the following:
 
June 30,
2015
 
September 30,
2014
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
149,202

 
$
162,777

Merger and integration costs, net
4,327

 
4,730

Deferred gas costs
1,494

 
20,069

Rate case costs
1,354

 
3,757

Infrastructure Mechanisms(2)
24,228

 
26,948

APT annual adjustment mechanism

 
8,479

Recoverable loss on reacquired debt
16,959

 
18,877

Other
4,944

 
4,672

 
$
202,508

 
$
250,309

Regulatory liabilities:
 
 
 
Deferred gas costs
$
81,134

 
$
35,063

Deferred franchise fees
747

 
5,268

Regulatory cost of removal obligation
486,672

 
490,448

Other
12,810

 
14,980

 
$
581,363

 
$
545,759

 
(1) 
Includes $15.8 million and $18.8 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2) 
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest expense, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable 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.




9



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.
Income statements for the three and nine month periods ended June 30, 2015 and 2014 by segment are presented in the following tables:
 
Three Months Ended June 30, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
415,160

 
$
25,859

 
$
245,382

 
$

 
$
686,401

Intersegment revenues
1,634

 
71,149

 
33,387

 
(106,170
)
 

 
416,794

 
97,008

 
278,769

 
(106,170
)
 
686,401

Purchased gas cost
149,775

 

 
260,990

 
(106,037
)
 
304,728

Gross profit
267,019

 
97,008

 
17,779

 
(133
)
 
381,673

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
98,552

 
26,572

 
7,456

 
(133
)
 
132,447

Depreciation and amortization
55,491

 
11,816

 
1,137

 

 
68,444

Taxes, other than income
56,176

 
6,193

 
806

 

 
63,175

Total operating expenses
210,219

 
44,581

 
9,399

 
(133
)
 
264,066

Operating income
56,800

 
52,427

 
8,380

 

 
117,607

Miscellaneous income (expense)
1,045

 
(211
)
 
345

 
(545
)
 
634

Interest charges
19,961

 
8,299

 
240

 
(545
)
 
27,955

Income before income taxes
37,884

 
43,917

 
8,485

 

 
90,286

Income tax expense
15,420

 
15,349

 
3,236

 

 
34,005

Net income
$
22,464

 
$
28,568

 
$
5,249

 
$

 
$
56,281

Capital expenditures
$
170,134

 
$
55,914

 
$
(209
)
 
$

 
$
225,839


10



 
Three Months Ended June 30, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
516,644

 
$
24,990

 
$
401,536

 
$

 
$
943,170

Intersegment revenues
1,063

 
62,199

 
63,949

 
(127,211
)
 

 
517,707

 
87,189

 
465,485

 
(127,211
)
 
943,170

Purchased gas cost
260,042

 

 
450,672

 
(127,077
)
 
583,637

Gross profit
257,665

 
87,189

 
14,813

 
(134
)
 
359,533

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
92,994

 
23,570

 
9,129

 
(134
)
 
125,559

Depreciation and amortization
52,542

 
10,281

 
1,132

 

 
63,955

Taxes, other than income
57,596

 
5,054

 
764

 

 
63,414

Total operating expenses
203,132

 
38,905

 
11,025

 
(134
)
 
252,928

Operating income
54,533

 
48,284

 
3,788

 

 
106,605

Miscellaneous income (expense)
678

 
(489
)
 
1,018

 
(1,581
)
 
(374
)
Interest charges
23,649

 
9,162

 
610

 
(1,581
)
 
31,840

Income before income taxes
31,562

 
38,633

 
4,196

 

 
74,391

Income tax expense
13,033

 
13,695

 
1,942

 

 
28,670

Net income
$
18,529

 
$
24,938

 
$
2,254

 
$

 
$
45,721

Capital expenditures
$
146,860

 
$
45,658

 
$
1,073

 
$

 
$
193,591

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended June 30, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,389,037

 
$
70,887

 
$
1,025,310

 
$

 
$
3,485,234

Intersegment revenues
5,142

 
201,418

 
154,069

 
(360,629
)
 

 
2,394,179

 
272,305

 
1,179,379

 
(360,629
)
 
3,485,234

Purchased gas cost
1,397,113

 

 
1,122,655

 
(360,230
)
 
2,159,538

Gross profit
997,066

 
272,305

 
56,724

 
(399
)
 
1,325,696

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
288,962

 
74,029

 
21,897

 
(399
)
 
384,489

Depreciation and amortization
165,730

 
34,945

 
3,384

 

 
204,059

Taxes, other than income
162,759

 
16,296

 
2,551

 

 
181,606

Total operating expenses
617,451

 
125,270

 
27,832

 
(399
)
 
770,154

Operating income
379,615

 
147,035

 
28,892

 

 
555,542

Miscellaneous income (expense)
(1,221
)
 
(842
)
 
897

 
(1,468
)
 
(2,634
)
Interest charges
60,914

 
25,014

 
706

 
(1,468
)
 
85,166

Income before income taxes
317,480

 
121,179

 
29,083

 

 
467,742

Income tax expense
121,776

 
42,894

 
11,512

 

 
176,182

Net income
$
195,704

 
$
78,285

 
$
17,571

 
$

 
$
291,560

Capital expenditures
$
482,371

 
$
185,028

 
$
84

 
$

 
$
667,483


11



 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended June 30, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,648,505

 
$
67,162

 
$
1,436,215

 
$

 
$
4,151,882

Intersegment revenues
4,027

 
164,983

 
223,916

 
(392,926
)
 

 
2,652,532

 
232,145

 
1,660,131

 
(392,926
)
 
4,151,882

Purchased gas cost
1,710,508

 

 
1,589,163

 
(392,556
)
 
2,907,115

Gross profit
942,024

 
232,145

 
70,968

 
(370
)
 
1,244,767

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
289,433

 
57,465

 
19,463

 
(370
)
 
365,991

Depreciation and amortization
152,113

 
30,223

 
3,395

 

 
185,731

Taxes, other than income
155,286

 
8,485

 
1,869

 

 
165,640

Total operating expenses
596,832

 
96,173

 
24,727

 
(370
)
 
717,362

Operating income
345,192

 
135,972

 
46,241

 

 
527,405

Miscellaneous income (expense)
304

 
(2,751
)
 
1,785

 
(3,360
)
 
(4,022
)
Interest charges
69,802

 
27,274

 
1,840

 
(3,360
)
 
95,556

Income before income taxes
275,694

 
105,947

 
46,186

 

 
427,827

Income tax expense
105,665

 
37,454

 
18,604

 

 
161,723

Net income
$
170,029

 
$
68,493

 
$
27,582

 
$

 
$
266,104

Capital expenditures
$
413,921

 
$
137,579

 
$
1,100

 
$

 
$
552,600

 

12



Balance sheet information at June 30, 2015 and September 30, 2014 by segment is presented in the following tables:

 
June 30, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,543,386

 
$
1,613,182

 
$
55,520

 
$

 
$
7,212,088

Investment in subsidiaries
1,028,457

 

 
(2,096
)
 
(1,026,361
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
35,288

 

 
7,865

 

 
43,153

Assets from risk management activities
780

 

 
10,806

 

 
11,586

Other current assets
375,213

 
20,100

 
497,871

 
(331,274
)
 
561,910

Intercompany receivables
820,587

 

 

 
(820,587
)
 

Total current assets
1,231,868

 
20,100

 
516,542

 
(1,151,861
)
 
616,649

Goodwill
574,816

 
132,502

 
34,711

 

 
742,029

Noncurrent assets from risk management activities
1,109

 

 

 

 
1,109

Deferred charges and other assets
291,740

 
15,305

 
5,569

 

 
312,614

 
$
8,671,376

 
$
1,781,089

 
$
610,246

 
$
(2,178,222
)
 
$
8,884,489

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,238,255

 
$
560,898

 
$
467,559

 
$
(1,028,457
)
 
$
3,238,255

Long-term debt
2,455,303

 

 

 

 
2,455,303

Total capitalization
5,693,558

 
560,898

 
467,559

 
(1,028,457
)
 
5,693,558

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
570,977

 

 

 
(319,000
)
 
251,977

Liabilities from risk management activities
4,916

 

 

 

 
4,916

Other current liabilities
551,102

 
17,850

 
100,910

 
(10,178
)
 
659,684

Intercompany payables

 
786,493

 
34,094

 
(820,587
)
 

Total current liabilities
1,126,995

 
804,343

 
135,004

 
(1,149,765
)
 
916,577

Deferred income taxes
1,014,432

 
415,687

 
(1,029
)
 

 
1,429,090

Noncurrent liabilities from risk management activities
47,224

 

 

 

 
47,224

Regulatory cost of removal obligation
432,153

 

 

 

 
432,153

Pension and postretirement liabilities
318,140

 

 

 

 
318,140

Deferred credits and other liabilities
38,874

 
161

 
8,712

 

 
47,747

 
$
8,671,376

 
$
1,781,089

 
$
610,246

 
$
(2,178,222
)
 
$
8,884,489


13





 
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


14




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 nine months ended June 30, 2015 and 2014 are calculated as follows:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(In thousands, except per share amounts)
Basic Earnings Per Share
 
 
 
 
 
 
 
Net income
$
56,281

 
$
45,721

 
$
291,560

 
$
266,104

Less: Income allocated to participating securities
111

 
106

 
596

 
667

Income available to common shareholders
$
56,170

 
$
45,615

 
$
290,964

 
$
265,437

Basic weighted average shares outstanding
102,000

 
101,162

 
101,776

 
96,392

Net income per share - Basic
$
0.55

 
$
0.45

 
$
2.86

 
$
2.76

Diluted Earnings Per Share
 
 
 
 
 
 
 
Net income available to common shareholders
$
56,170

 
$
45,615

 
290,964

 
265,437

Effect of dilutive stock options and other shares

 

 

 

Net income available to common shareholders
$
56,170

 
$
45,615

 
290,964

 
265,437

Basic weighted average shares outstanding
102,000

 
101,162

 
101,776

 
96,392

Additional dilutive stock options and other shares

 
1

 

 
2

Diluted weighted average shares outstanding
102,000

 
101,163

 
101,776

 
96,394

Net income per share - Diluted
$
0.55

 
$
0.45

 
$
2.86

 
$
2.76


There were no out-of-the-money stock options excluded from the computation of diluted earnings per share for the three and nine months ended June 30, 2014 as their exercise price was less than the average market price of the common stock during those periods. As of June 30, 2015 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 nine months ended June 30, 2015 and 2014 under our 2011 share repurchase program, which is scheduled to end on September 30, 2016.

15




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 nine months ended June 30, 2015.
Long-term debt
Long-term debt at June 30, 2015 and September 30, 2014 consisted of the following:
 
 
June 30, 2015
 
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
4,697

 
4,014

 
$
2,455,303

 
$
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 June 30, 2015 and September 30, 2014 a total of $252.0 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 $4.2 million at June 30, 2015.
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

16



(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 $36.0 million at June 30, 2015.
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. 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 June 30, 2015, $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 June 30, 2015, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 47 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 June 30, 2015. 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 nine months ended June 30, 2015 and 2014 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.

17



 
Three Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
5,051

 
$
4,738

 
$
3,895

 
$
4,196

Interest cost
6,698

 
6,824

 
3,596

 
3,987

Expected return on assets
(6,435
)
 
(5,901
)
 
(1,608
)
 
(1,291
)
Amortization of transition obligation

 

 
69

 
69

Amortization of prior service credit
(48
)
 
(34
)
 
(411
)
 
(363
)
Amortization of actuarial loss
3,916

 
3,931

 

 
158

Net periodic pension cost
$
9,182

 
$
9,558

 
$
5,541

 
$
6,756

 
 
 
 
 
 
 
 
 
Nine Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
15,153

 
$
14,214

 
$
11,687

 
$
12,588

Interest cost
20,095

 
20,472

 
10,789

 
11,963

Expected return on assets
(19,308
)
 
(17,702
)
 
(4,824
)
 
(3,875
)
Amortization of transition obligation

 

 
205

 
205

Amortization of prior service credit
(144
)
 
(102
)
 
(1,233
)
 
(1,088
)
Amortization of actuarial loss
11,749

 
11,793

 

 
474

Settlement loss

 
4,539

 

 

Net periodic pension cost
$
27,545

 
$
33,214

 
$
16,624

 
$
20,267


The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2015 and 2014 are as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
2015
 
2014
 
2015
 
2014
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. Based on that determination, we are not required to make a minimum contribution to our defined benefit plans during fiscal 2015. However, we made a voluntary contribution of $38.0 million during the third quarter of fiscal 2015.
We contributed $15.0 million to our other post-retirement benefit plans during the nine months ended June 30, 2015. We expect to contribute a total of approximately $20 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.



18



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 nine months ended June 30, 2015.
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.
Purchase Commitments
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 June 30, 2015, we were committed to purchase 36.6 Bcf within one year and 35.2 Bcf within two years under indexed contracts. Purchases under these contracts totaled $21.2 million and $27.8 million for the three months ended June 30, 2015 and 2014 and $93.2 million, and $81.9 million for the nine months ended June 30, 2015 and 2014.
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. At June 30, 2015, AEH was committed to purchase 99.1 Bcf within one year, 22.6 Bcf within one to three years and 0.2 Bcf after three years under indexed contracts. AEH is committed to purchase 4.1 Bcf within one year under fixed price contracts with prices ranging from $2.62 to $3.23 per Mcf. Purchases under these contracts totaled $203.3 million and $383.2 million for the three months ended June 30, 2015 and 2014 and $925.4 million and $1,354.5 million for the nine months ended June 30, 2015 and 2014.
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 nine months ended June 30, 2015.
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 June 30, 2015, a rate case was in progress in our Colorado service area, an annual rate filing mechanism was in progress in Louisiana and an infrastructure program was in progress in Virginia. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.




19



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 nonregulated 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 nine months ended June 30, 2015 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 hedged 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 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 52 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 June 30, 2015, 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 swaps were executed. As of June 30, 2015, we had $18.7 million of 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 extend through fiscal 2045.
 

20



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 June 30, 2015, 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 June 30, 2015, 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
 

 
(25,020
)
 
 
Cash Flow
 

 
55,158

 
 
Not designated
 
14,609

 
65,577

 
 
 
 
14,609

 
95,715

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 June 30, 2015 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)
June 30, 2015
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$

 
$

 
$
8,465

 
$
(31,422
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 

 
476

 
(7,591
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
570

 
(47,224
)
 

 

Total
 
 
570

 
(47,224
)
 
8,941

 
(39,013
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
780

 
(4,916
)
 
86,265

 
(78,374
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
539

 

 
9,000

 
(7,336
)
Total
 
 
1,319

 
(4,916
)
 
95,265

 
(85,710
)
Gross Financial Instruments
 
 
1,889

 
(52,140
)
 
104,206

 
(124,723
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 

 

 
(104,206
)
 
104,206

Net Financial Instruments
 
 
1,889

 
(52,140
)
 

 
(20,517
)
Cash collateral
 
 

 

 
10,806

 
20,517

Net Assets/Liabilities from Risk Management Activities
 
 
$
1,889

 
$
(52,140
)
 
$
10,806

 
$

 
 

21



 
 
 
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 purchased gas cost 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 June 30, 2015 and 2014 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $3.6 million and $(0.1) million. For the nine months ended June 30, 2015 and 2014 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $(0.9) million and $1.3 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 

22



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 and nine months ended June 30, 2015 and 2014 is presented below.
 
Three Months Ended 
 June 30
 
2015
 
2014
 
(In thousands)
Commodity contracts
$
(1,715
)
 
$
1,991

Fair value adjustment for natural gas inventory designated as the hedged item
5,350

 
(2,258
)
Total (increase) decrease in purchased gas cost
$
3,635

 
$
(267
)
The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
599

 
$
817

Timing ineffectiveness
3,036

 
(1,084
)
 
$
3,635

 
$
(267
)
 
 
 
 
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
(In thousands)
Commodity contracts
$
5,754

 
$
(2,983
)
Fair value adjustment for natural gas inventory designated as the hedged item
(6,291
)
 
4,071

Total (increase) decrease in purchased gas cost
$
(537
)
 
$
1,088

The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
908

 
$
(382
)
Timing ineffectiveness
(1,445
)
 
1,470

 
$
(537
)
 
$
1,088

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.


23



Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2015 and 2014 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 June 30, 2015
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(16,488
)
 
$
(16,488
)
Gain arising from ineffective portion of commodity contracts

 
11

 
11

Total impact on purchased gas cost

 
(16,477
)
 
(16,477
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(137
)
 

 
(137
)
Total Impact from Cash Flow Hedges
$
(137
)
 
$
(16,477
)
 
$
(16,614
)
 
Three Months Ended June 30, 2014
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$

 
$
4,209

 
$
4,209

Gain arising from ineffective portion of commodity contracts

 
179

 
179

Total impact on purchased gas cost

 
4,388

 
4,388

Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(1,057
)
 

 
(1,057
)
Total Impact from Cash Flow Hedges
$
(1,057
)
 
$
4,388

 
$
3,331

 
 
 
 
 
 
 
Nine Months Ended June 30, 2015
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(29,222
)
 
$
(29,222
)
Loss arising from ineffective portion of commodity contracts

 
(316
)
 
(316
)
Total impact on purchased gas cost

 
(29,538
)
 
(29,538
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(717
)
 

 
(717
)
Total Impact from Cash Flow Hedges
$
(717
)
 
$
(29,538
)
 
$
(30,255
)
 
 
 
 
 
 
 
Nine Months Ended June 30, 2014
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$

 
$
8,783

 
$
8,783

Gain arising from ineffective portion of commodity contracts

 
203

 
203

Total impact on purchased gas cost

 
8,986

 
8,986

Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(3,172
)
 

 
(3,172
)
Total Impact from Cash Flow Hedges
$
(3,172
)
 
$
8,986

 
$
5,814



24



The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three and nine months ended June 30, 2015 and 2014. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$
54,388

 
$
(24,111
)
 
$
(30,436
)
 
$
(38,559
)
Forward commodity contracts
1,505

 
96

 
(37,397
)
 
11,805

Recognition of (gains) losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
87

 
671

 
455

 
2,014

Forward commodity contracts
10,058

 
(2,567
)
 
17,826

 
(5,357
)
Total other comprehensive income (loss) from hedging, net of tax(1)
$
66,038

 
$
(25,911
)
 
$
(49,552
)
 
$
(30,097
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred gains (losses) associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 2015. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.
 
Interest Rate
Agreements
 
Commodity
Contracts
 
Total
 
(In thousands)
Next twelve months
$
(347
)
 
$
(16,952
)
 
$
(17,299
)
Thereafter
(18,390
)
 
(4,293
)
 
(22,683
)
Total(1) 
$
(18,737
)
 
$
(21,245
)
 
$
(39,982
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
 
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended June 30, 2015 and 2014 was an (increase) decrease in purchased gas cost of $3.7 million and $(0.6) million. For the nine months ended June 30, 2015 and 2014, purchased gas cost (increased) decreased by $13.2 million and $(10.7) million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our regulated distribution segment are not designated as hedges. However, there is no earnings impact on our regulated distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are 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. Accordingly, the impact of these financial instruments is excluded from this presentation.
9.    Accumulated Other Comprehensive Income
We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.

25



 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2014
$
7,662

 
$
(18,381
)
 
$
(1,674
)
 
$
(12,393
)
Other comprehensive income (loss) before reclassifications
30

 
(30,436
)
 
(37,397
)
 
(67,803
)
Amounts reclassified from accumulated other comprehensive income
(326
)
 
455

 
17,826

 
17,955

Net current-period other comprehensive income (loss)
(296
)
 
(29,981
)
 
(19,571
)
 
(49,848
)
June 30, 2015
$
7,366

 
$
(48,362
)
 
$
(21,245
)
 
$
(62,241
)
 
 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2013
$
5,448

 
$
37,906

 
$
(4,476
)
 
$
38,878

Other comprehensive income (loss) before reclassifications
3,212

 
(38,559
)
 
11,805

 
(23,542
)
Amounts reclassified from accumulated other comprehensive income
(693
)
 
2,014

 
(5,357
)
 
(4,036
)
Net current-period other comprehensive income (loss)
2,519

 
(36,545
)
 
6,448

 
(27,578
)
June 30, 2014
$
7,967

 
$
1,361

 
$
1,972

 
$
11,300



The following tables detail reclassifications out of AOCI for the three and nine months ended June 30, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.
 
Three Months Ended June 30, 2015
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
508

 
Operation and maintenance expense
 
508

 
Total before tax
 
(186
)
 
Tax expense
 
$
322

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(137
)
 
Interest charges
Commodity contracts
(16,488
)
 
Purchased gas cost
 
(16,625
)
 
Total before tax
 
6,480

 
Tax benefit
 
$
(10,145
)
 
Net of tax
Total reclassifications
$
(9,823
)
 
Net of tax

26



 
Three Months Ended June 30, 2014
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
733

 
Operation and maintenance expense
 
733

 
Total before tax
 
(267
)
 
Tax expense
 
$
466

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(1,057
)
 
Interest charges
Commodity contracts
4,209

 
Purchased gas cost
 
3,152

 
Total before tax
 
(1,256
)
 
Tax expense
 
$
1,896

 
Net of tax
Total reclassifications
$
2,362

 
Net of tax
 
 
 
 
 
Nine Months Ended June 30, 2015
Accumulated Other Comprehensive Income Components                          
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in  the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
514

 
Operation and maintenance expense
 
514

 
Total before tax
 
(188
)
 
Tax expense
 
$
326

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(717
)
 
Interest charges
Commodity contracts
(29,222
)
 
Purchased gas cost
 
(29,939
)
 
Total before tax
 
11,658

 
Tax benefit
 
$
(18,281
)
 
Net of tax
Total reclassifications
$
(17,955
)
 
Net of tax

27



 
 
 
 
 
Nine Months Ended June 30, 2014
Accumulated Other Comprehensive Income Components                          
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in  the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
1,091

 
Operation and maintenance expense
 
1,091

 
Total before tax
 
(398
)
 
Tax expense
 
$
693

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(3,172
)
 
Interest charges
Commodity contracts
8,783

 
Purchased gas cost
 
5,611

 
Total before tax
 
(2,268
)
 
Tax expense
 
$
3,343

 
Net of tax
Total reclassifications
$
4,036

 
Net of tax

10.    Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the nine months ended June 30, 2015, there were no changes in these methods.
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 6 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2014.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2015 and September 30, 2014. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

28



 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(2)
 
June 30, 2015
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
1,889

 
$

 
$

 
$
1,889

Nonregulated segment

 
104,206

 

 
(93,400
)
 
10,806

Total financial instruments

 
106,095

 

 
(93,400
)
 
12,695

Hedged portion of gas stored underground
65,717

 

 

 

 
65,717

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
1,217

 

 

 
1,217

Registered investment companies
44,854

 

 

 

 
44,854

Bonds

 
33,418

 

 

 
33,418

Total available-for-sale securities
44,854

 
34,635

 

 

 
79,489

Total assets
$
110,571

 
$
140,730

 
$

 
$
(93,400
)
 
$
157,901

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
52,140

 
$

 
$

 
$
52,140

Nonregulated segment

 
124,723

 

 
(124,723
)
 

Total liabilities
$

 
$
176,863

 
$

 
$
(124,723
)
 
$
52,140

 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(3)
 
September 30, 2014
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
36,140

 
$

 
$

 
$
36,140

Nonregulated segment
25

 
68,998

 

 
(46,298
)
 
22,725

Total financial instruments
25

 
105,138

 

 
(46,298
)
 
58,865

Hedged portion of gas stored underground
40,492

 

 

 

 
40,492

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
2,185

 

 

 
2,185

Registered investment companies
44,014

 

 

 

 
44,014

Bonds

 
33,414

 

 

 
33,414

Total available-for-sale securities
44,014

 
35,599

 

 

 
79,613

Total assets
$
84,531

 
$
140,737

 
$

 
$
(46,298
)
 
$
178,970

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
21,856

 
$

 
$

 
$
21,856

Nonregulated segment
12

 
72,044

 

 
(72,056
)
 

Total liabilities
$
12

 
$
93,900

 
$

 
$
(72,056
)
 
$
21,856

 
(1) 
Our Level 2 measurements consist of over-the-counter options and swaps which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds which are valued based on the most recent available quoted market prices and money market funds which are valued at cost.

29



(2) 
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of June 30, 2015, we had $31.3 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $20.5 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $10.8 million is classified as current risk management assets.
(3) 
This column reflects adjustments to our gross financial instrument assets and liabilities to reflect netting permitted under our master netting agreements and the relevant authoritative accounting literature. In addition, as of September 30, 2014, we had $25.8 million of cash held in margin accounts to collateralize certain financial instruments. Of this amount, $3.1 million was used to offset current and noncurrent risk management liabilities under master netting arrangements and the remaining $22.7 million is classified as current risk management assets.
 
Available-for-sale securities are comprised of the following:
 
Amortized
Cost
 
Gross
Unrealized
Gain
 
Gross
Unrealized
Loss
 
Fair
Value
 
(In thousands)
As of June 30, 2015
 
 
 
 
 
 
 
Domestic equity mutual funds
$
28,023

 
$
10,010

 
$
(163
)
 
$
37,870

Foreign equity mutual funds
5,279

 
1,705

 

 
6,984

Bonds
33,364

 
78

 
(24
)
 
33,418

Money market funds
1,217

 

 

 
1,217

 
$
67,883

 
$
11,793

 
$
(187
)
 
$
79,489

As of September 30, 2014
 
 
 
 
 
 
 
Domestic equity mutual funds
$
26,633

 
$
10,136

 
$

 
$
36,769

Foreign equity mutual funds
5,382

 
1,863

 

 
7,245

Bonds
33,266

 
161

 
(13
)
 
33,414

Money market funds
2,185

 

 

 
2,185

 
$
67,466

 
$
12,160

 
$
(13
)
 
$
79,613

At June 30, 2015 and September 30, 2014, our available-for-sale securities included $46.1 million and $46.2 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2015, we maintained investments in bonds that have contractual maturity dates ranging from July 2015 through September 2020.
These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.
Other Fair Value Measures
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of June 30, 2015 and September 30, 2014:
 
June 30, 2015
 
September 30, 2014
 
(In thousands)
Carrying Amount
$
2,460,000

 
$
2,460,000

Fair Value
$
2,659,908

 
$
2,769,541

11.    Concentration of Credit Risk
Information regarding our concentration of credit risk is disclosed in Note 15 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the nine months ended June 30, 2015, there were no material changes in our concentration of credit risk.

30



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of June 30, 2015, the related condensed consolidated statements of income and comprehensive income for the three and nine-month periods ended June 30, 2015 and 2014, and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2015 and 2014. These financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2014, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 6, 2014, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2014, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/    ERNST & YOUNG LLP
Dallas, Texas
August 5, 2015

31



Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2014.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit markets to satisfy our liquidity requirements; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; market risks beyond our control affecting our risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; the concentration of our distribution, pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our gas distribution business; increased costs of providing pension and postretirement health care benefits and increased funding requirements along with increased costs of health care benefits; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of possible future additional regulatory and financial risks associated with global warming and climate change on our business; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; the risks of accidents and additional operating costs associating with distributing, transporting and storing natural gas; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged primarily in the regulated distribution and transportation and storage businesses as well as other nonregulated natural gas businesses. We distribute natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers throughout our six regulated distribution divisions, which at June 30, 2015 covered service areas located in eight states. In addition, we transport natural gas for others through our regulated distribution and pipeline systems.
Through our nonregulated businesses, we provide natural gas management and marketing services to municipalities, other local gas distribution companies and industrial customers primarily in the Midwest and Southeast and natural gas transportation and storage services to certain of our regulated distribution divisions and to third parties.

As discussed in Note 3, 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 includes our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.

32



CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014 and include the following:

Regulation
Unbilled revenue
Pension and other postretirement plans
Contingencies
Financial instruments and hedging activities
Fair value measurements
Impairment assessments

Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the nine months ended June 30, 2015.
RESULTS OF OPERATIONS

Executive Summary
Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. To achieve this objective, we are investing in our infrastructure and seeking to achieve positive rate outcomes that benefit both our customers and the Company.
Consolidated net income for the nine months ended June 30, 2015 increased 10 percent period over period. Positive rate outcomes in our regulated businesses and the favorable effect of colder than normal weather more than offset the effect of weather that was warmer than the prior-year period. As of June 30, 2015, we had completed 16 regulatory proceedings resulting in a $113.1 million increase in annual operating income and had three ratemaking efforts in progress seeking $7.1 million of additional annual operating income.
Colder than normal weather in both fiscal years and residential and commercial consumption after the winter heating season during fiscal 2015 drove higher throughput in our regulated operations. Before adjusting for weather normalization mechanisms, weather was eight percent colder than normal during the nine months ended June 30, 2015. However, weather was nine percent warmer than the prior year nine-month period; therefore, regulated distribution sales volumes decreased eight percent due to decreased customer consumption as a result of warmer weather in the current year. Additionally, a period-over-period reduction in natural gas market volatility reduced realized gross margin in our nonregulated segment by $11.2 million.
Capital expenditures for the first nine months of fiscal 2015 were $667.5 million. Approximately 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between $900 million and $1 billion for fiscal 2015. We funded our capital expenditure program primarily through operating cash flows of $717.6 million and net short-term borrowings.
On July 1, 2015, Fitch Ratings (Fitch) upgraded our senior unsecured debt rating to A from A- with a ratings outlook of stable, citing Fitch's expectation of continued strong financial performance, which has been driven primarily by organic growth in our regulated distribution and regulated pipeline segments.
As a result of the continued contribution and stability of our regulated earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 5.4 percent in the first quarter of fiscal 2015.


33



Consolidated Results
The following table presents our consolidated financial highlights for the three and nine months ended June 30, 2015 and 2014:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(In thousands, except per share data)
Operating revenues
$
686,401

 
$
943,170

 
$
3,485,234

 
$
4,151,882

Gross profit
381,673

 
359,533

 
1,325,696

 
1,244,767

Operating expenses
264,066

 
252,928

 
770,154

 
717,362

Operating income
117,607

 
106,605

 
555,542

 
527,405

Miscellaneous income (expense)
634

 
(374
)
 
(2,634
)
 
(4,022
)
Interest charges
27,955

 
31,840

 
85,166

 
95,556

Income before income taxes
90,286

 
74,391

 
467,742

 
427,827

Income tax expense
34,005

 
28,670

 
176,182

 
161,723

Net income
$
56,281

 
$
45,721

 
$
291,560

 
$
266,104

Diluted net income per share
$
0.55

 
$
0.45

 
$
2.86

 
$
2.76

Our consolidated net income during the three and nine month periods ended June 30, 2015 and 2014 was earned in each of our business segments as follows:
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands)
Regulated distribution segment
$
22,464

 
$
18,529

 
$
3,935

Regulated pipeline segment
28,568

 
24,938

 
3,630

Nonregulated segment
5,249

 
2,254

 
2,995

Net income
$
56,281

 
$
45,721

 
$
10,560

 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands)
Regulated distribution segment
$
195,704

 
$
170,029

 
$
25,675

Regulated pipeline segment
78,285

 
68,493

 
9,792

Nonregulated segment
17,571

 
27,582

 
(10,011
)
Net income
$
291,560

 
$
266,104

 
$
25,456


Regulated operations represented 91 percent and 94 percent of our consolidated net income for the three and nine months ended June 30, 2015. The following tables reflect the segregation of our consolidated net income and diluted earnings per share between our regulated and nonregulated operations:
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, except per share data)
Regulated operations
$
51,032

 
$
43,467

 
$
7,565

Nonregulated operations
5,249

 
2,254

 
2,995

Net income
$
56,281

 
$
45,721

 
$
10,560

 
 
 
 
 
 
Diluted EPS from regulated operations
$
0.50

 
$
0.43

 
$
0.07

Diluted EPS from nonregulated operations
0.05

 
0.02

 
0.03

Consolidated diluted EPS
$
0.55

 
$
0.45

 
$
0.10


34



 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, except per share data)
Regulated operations
$
273,989

 
238,522

 
$
35,467

Nonregulated operations
17,571

 
27,582

 
(10,011
)
Net income
$
291,560

 
$
266,104

 
$
25,456

 
 
 
 
 
 
Diluted EPS from regulated operations
$
2.69

 
$
2.47

 
$
0.22

Diluted EPS from nonregulated operations
0.17

 
0.29

 
(0.12
)
Consolidated diluted EPS
$
2.86

 
$
2.76

 
$
0.10

Regulated Distribution Segment
The primary factors that impact the results of our regulated distribution operations are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
Seasonal weather patterns can also affect our regulated distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 97 percent of our residential and commercial meters in the following states for the following time periods:
 
 
Kansas, West Texas
October — May
Tennessee
October — April
Kentucky, Mississippi, Mid-Tex
November — April
Louisiana
December — March
Virginia
January — December
Our regulated distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe gross profit is a better indicator of our financial performance than revenues. However, gross profit in our Texas and Mississippi service areas does include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which may adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 75 percent of our residential and commercial margins.


35



Three Months Ended June 30, 2015 compared with Three Months Ended June 30, 2014
Financial and operational highlights for our regulated distribution segment for the three months ended June 30, 2015 and 2014 are presented below.
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
267,019

 
$
257,665

 
$
9,354

Operating expenses
210,219

 
203,132

 
7,087

Operating income
56,800

 
54,533

 
2,267

Miscellaneous income
1,045

 
678

 
367

Interest charges
19,961

 
23,649

 
(3,688
)
Income before income taxes
37,884

 
31,562

 
6,322

Income tax expense
15,420

 
13,033

 
2,387

Net income
$
22,464

 
$
18,529

 
$
3,935

Consolidated regulated distribution sales volumes — MMcf
36,126

 
39,341

 
(3,215
)
Consolidated regulated distribution transportation volumes — MMcf
30,134

 
32,997

 
(2,863
)
Total consolidated regulated distribution throughput — MMcf
66,260

 
72,338

 
(6,078
)
Consolidated regulated distribution average transportation revenue per Mcf
$
0.49

 
$
0.46

 
$
0.03

Consolidated regulated distribution average cost of gas per Mcf sold
$
4.15

 
$
6.61

 
$
(2.46
)
    
Income for our regulated distribution segment increased 21 percent, primarily due to a $9.4 million increase in gross profit, partially offset by a $7.1 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:
a $16.2 million net increase in rate adjustments, primarily in our Mid-Tex, Kentucky/Mid-States and West Texas Divisions.
a $1.3 million decrease in consumption associated with an eight percent decrease in sales volumes.  Current quarter weather was 31 percent warmer than the prior-year quarter, before adjusting for weather normalization mechanisms. 
A $4.4 million decrease in revenue-related taxes, offset by a corresponding $4.3 million decrease in the related tax expense.
The increase in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to increased operation and maintenance expenses due to increased employee-related expenses and depreciation expense associated with increased capital investments.
The following table shows our operating income by regulated distribution division, in order of total rate base, for the three months ended June 30, 2015 and 2014. The presentation of our regulated distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands)
Mid-Tex
$
33,473

 
$
26,100

 
$
7,373

Kentucky/Mid-States
10,104

 
5,724

 
4,380

Louisiana
6,561

 
7,713

 
(1,152
)
West Texas
5,018

 
3,785

 
1,233

Mississippi
1,546

 
(1,520
)
 
3,066

Colorado-Kansas
1,872

 
1,369

 
503

Other
(1,774
)
 
11,362

 
(13,136
)
Total
$
56,800

 
$
54,533

 
$
2,267




36




Nine Months Ended June 30, 2015 compared with Nine Months Ended June 30, 2014
Financial and operational highlights for our regulated distribution segment for the nine months ended June 30, 2015 and 2014 are presented below.

 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
997,066

 
$
942,024

 
$
55,042

Operating expenses
617,451

 
596,832

 
20,619

Operating income
379,615

 
345,192

 
34,423

Miscellaneous income (expense)
(1,221
)
 
304

 
(1,525
)
Interest charges
60,914

 
69,802

 
(8,888
)
Income before income taxes
317,480

 
275,694

 
41,786

Income tax expense
121,776

 
105,665

 
16,111

Net income
$
195,704

 
$
170,029

 
$
25,675

Consolidated regulated distribution sales volumes — MMcf
265,503

 
288,702

 
(23,199
)
Consolidated regulated distribution transportation volumes — MMcf
107,205

 
105,608

 
1,597

Total consolidated regulated distribution throughput — MMcf
372,708

 
394,310

 
(21,602
)
Consolidated regulated distribution average transportation revenue per Mcf
$
0.49

 
$
0.47

 
$
0.02

Consolidated regulated distribution average cost of gas per Mcf sold
$
5.26

 
$
5.92

 
$
(0.66
)

Income for our regulated distribution segment increased 15 percent, primarily due to a $55.0 million increase in gross profit, partially offset by a $20.6 million increase in operating expenses. The period-over-period increase in gross profit primarily reflects:
a $61.5 million net increase in rate adjustments, primarily in our Mid-Tex, West Texas, Kentucky/Mid-States and Colorado-Kansas Divisions.
a $3.6 million increase in transportation revenue.  Transportation volumes increased two percent due to increased economic activity experienced in our Kentucky/Mid-States Division and increased consumption in our West Texas Division due to colder than normal weather.
a $9.2 million decrease in consumption associated with an eight percent decrease in sales volumes. Current period weather was nine percent warmer compared to the prior-year period, before adjusting for weather normalization mechanisms.
a $2.0 million decrease in revenue-related taxes primarily in our Mid-Tex Division.
The increase in operating expenses, which include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, was primarily due to increased depreciation expense associated with increased capital investments and increased taxes, other than income, primarily due to increases in ad valorem and franchise taxes.

37



The following table shows our operating income by regulated distribution division, in order of total rate base, for the nine months ended June 30, 2015 and 2014. The presentation of our regulated distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands)
Mid-Tex
$
166,586

 
$
151,009

 
$
15,577

Kentucky/Mid-States
59,256

 
53,243

 
6,013

Louisiana
47,380

 
51,131

 
(3,751
)
West Texas
33,820

 
27,591

 
6,229

Mississippi
37,356

 
31,457

 
5,899

Colorado-Kansas
29,129

 
26,785

 
2,344

Other
6,088

 
3,976

 
2,112

Total
$
379,615

 
$
345,192

 
$
34,423

Recent Ratemaking Developments
The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first nine months of fiscal 2015, we completed 15 regulatory proceedings, resulting in a $75.9 million increase in annual operating income as summarized below:
Rate Action
 
Annual Increase  to
Operating Income
 
 
(In thousands)
Infrastructure programs
 
$
11,264

Annual rate filing mechanisms
 
63,873

Rate case filings
 
711

Other rate activity
 
78

 
 
$
75,926

Additionally, the following ratemaking efforts seeking $7.1 million in annual operating income were in progress as of June 30, 2015:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income
Requested
 
 
 
 
 
 
(In thousands)
Louisiana
 
Rate Stabilization Clause(1)
 
LGS
 
$
1,674

Colorado-Kansas
 
Rate Case
 
Colorado
 
5,276

Kentucky/Mid-States
 
SAVE
 
Virginia
 
163

 
 
 
 
 
 
$
7,113


(1)
On July 1, 2015, an operating income increase of $1.3 million was implemented.

38



Infrastructure Programs
Infrastructure programs such as the Gas Reliability Infrastructure Program (GRIP) allow natural gas distribution companies the opportunity to include in their rate base annually approved capital costs incurred in the prior calendar year. As of June 30, 2015, we had infrastructure programs approved in Kansas, Kentucky, Louisiana, Texas and Virginia. The following table summarizes our infrastructure program filings with effective dates occurring during the nine months ended June 30, 2015.
Division
 
Period End
 
Incremental
Net Utility
Plant
Investment
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
 
(In thousands)
 
 
2015 Infrastructure Programs:
 
 
 
 
 
 
 
 
West Texas - Environs
 
12/31/2014
 
$
48,616

 
$
697

 
06/12/2015
Mid-Tex - Environs
 
12/31/2014
 
225,611

 
1,158

 
06/01/2015
West Texas - Cities
 
12/31/2014
 
59,452

 
4,593

 
05/01/2015
Colorado-Kansas - Kansas
 
09/30/2014
 
2,708

 
301

 
02/01/2015
Kentucky/Mid-States - Kentucky
 
09/30/2015
 
35,382

 
4,382

 
10/10/2014
Kentucky/Mid-States - Virginia
 
09/30/2015
 
1,553

 
133

 
10/01/2014
Total 2015 Infrastructure Programs
 
 
 
$
373,322

 
$
11,264

 
 
Annual Rate Filing Mechanisms
As an instrument to reduce regulatory lag, annual rate filing mechanisms allow us to refresh our rates on a periodic basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. As of June 30, 2015, we had formula rate filings or mechanisms in our Louisiana, Mississippi and Tennessee service areas and in a portion of our Texas divisions. These mechanisms are referred to as the Dallas annual rate review (DARR) and rate review mechanism (RRM) in our Mid-Tex Division, the RRM in our West Texas Division, stable rate/supplemental growth filings in the Mississippi Division, the rate stabilization clause in the Louisiana Division and Annual Rate Mechanism (ARM) in Tennessee. The following formula rate filings or mechanisms were completed during the nine months ended June 30, 2015.
Division
 
Jurisdiction
 
Test Year
Ended
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2015 Filings:
 
 
 
 
 
 
 
 
Mid-Tex
 
Cities
 
12/31/2014
 
$
16,801

 
06/01/2015
Mid-Tex
 
Dallas
 
09/30/2014
 
4,420

 
06/01/2015
Louisiana
 
Trans La
 
09/30/2014
 
(286
)
 
04/01/2015
West Texas
 
West Texas Cities
 
09/30/2014
 
4,300

 
03/15/2015
Mississippi
 
Mississippi-SRF
 
10/31/2015
 
4,441

 
02/01/2015
Mississippi
 
Mississippi-SGR (1)
 
10/31/2015
 
782

 
11/01/2014
Mid-Tex
 
Cities(2)
 
12/31/2013
 
33,415

 
06/01/2014
Total 2015 Filings
 
 
 
 
 
$
63,873

 
 

(1)
The Mississippi Supplemental Growth Rider (SGR) permits the Company to incur up to $5.0 million in eligible industrial growth projects each year beyond the division’s normal main extension policies. This is the second year of the SGR program.
(2) 
Mid-Tex Cities RRM rates were put into effect on June 1, 2014, subject to refund. The Company appealed the Mid-Tex Cities decision to deny the 2013 RRM increase to the Texas Railroad Commission on May 30, 2014. Following a proposal for decision from the Texas Railroad Commission, the Company and the Mid-Tex Cities reached a settlement that left the previously implemented rates in place. The rates became permanent on June 1, 2015.

39



Rate Case Filings
A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return to our shareholders and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. The following table summarizes the rate cases that were completed during the nine months ended June 30, 2015.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Division
 
State
 
Increase in Annual
Operating Income
 
Effective
Date
 
 
(In thousands)
2015 Rate Case Filings:
 
 
 
 
 
 
Kentucky/Mid-States
 
Tennessee
 
$
711

 
06/01/2015
Total 2015 Rate Case Filings
 
 
 
$
711

 
 
Other Ratemaking Activity
The following table summarizes other ratemaking activity during the nine months ended June 30, 2015.
 
 
 
 
 
 
 
 
 
Division
 
Jurisdiction
 
Rate Activity
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2015 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
78

 
02/01/2015
Total 2015 Other Rate Activity
 
 
 
 
 
$
78

 
 

(1)
The Ad Valorem filing relates to a collection of property taxes in excess of the amount included in our Kansas service area's base rates.

Regulated Pipeline Segment
Our regulated pipeline segment consists of the pipeline and storage operations of the Atmos Pipeline–Texas Division. The Atmos Pipeline–Texas Division transports natural gas to our Mid-Tex Division and third parties and manages five underground storage reservoirs in Texas. We also provide ancillary services to third parties customary in the pipeline industry including parking arrangements, lending arrangements and sales of excess gas.
Our regulated pipeline segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Mid-Tex service area. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve could influence customers to transport gas through our pipeline to capture arbitrage gains.
The results of Atmos Pipeline — Texas Division are also significantly impacted by the natural gas requirements of the Mid-Tex Division because it is the primary supplier of natural gas for our Mid-Tex Division.
Finally, as a regulated pipeline, the operations of the Atmos Pipeline — Texas Division may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.


40



Three Months Ended June 30, 2015 compared with Three Months Ended June 30, 2014
Financial and operational highlights for our regulated pipeline segment for the three months ended June 30, 2015 and 2014 are presented below.
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
71,989

 
$
63,313

 
$
8,676

Third-party transportation
22,724

 
20,413

 
2,311

Storage and park and lend services
664

 
1,086

 
(422
)
Other
1,631

 
2,377

 
(746
)
Gross profit
97,008

 
87,189

 
9,819

Operating expenses
44,581

 
38,905

 
5,676

Operating income
52,427

 
48,284

 
4,143

Miscellaneous expense
(211
)
 
(489
)
 
278

Interest charges
8,299

 
9,162

 
(863
)
Income before income taxes
43,917

 
38,633

 
5,284

Income tax expense
15,349

 
13,695

 
1,654

Net income
$
28,568

 
$
24,938

 
$
3,630

Gross pipeline transportation volumes — MMcf
165,898

 
160,038

 
5,860

Consolidated pipeline transportation volumes — MMcf
134,823

 
127,979

 
6,844


Net income for our regulated pipeline segment increased 15 percent, primarily due to a $9.8 million increase in gross profit, partially offset by a $5.7 million increase in operating expenses. The increase in gross profit primarily reflects a $9.5 million increase in rates from the approved 2014 and 2015 GRIP filings. Additionally, gross profit reflects increased pipeline demand fees and through-system transportation volumes and rates that were offset by lower storage and blending fees.

Operating expenses increased $5.7 million, primarily due to increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system and increased depreciation expense associated with increased capital investments.

On April 8, 2015, a GRIP filing was approved by the RRC for $37.2 million of additional annual operating income, effective with bills rendered on and after April 8, 2015.


41



Nine Months Ended June 30, 2015 compared with Nine Months Ended June 30, 2014
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
192,734

 
$
163,818

 
$
28,916

Third-party transportation
71,203

 
56,457

 
14,746

Storage and park and lend services
2,737

 
4,336

 
(1,599
)
Other
5,631

 
7,534

 
(1,903
)
Gross profit
272,305

 
232,145

 
40,160

Operating expenses
125,270

 
96,173

 
29,097

Operating income
147,035

 
135,972

 
11,063

Miscellaneous expense
(842
)
 
(2,751
)
 
1,909

Interest charges
25,014

 
27,274

 
(2,260
)
Income before income taxes
121,179

 
105,947

 
15,232

Income tax expense
42,894

 
37,454

 
5,440

Net income
$
78,285

 
$
68,493

 
$
9,792

Gross pipeline transportation volumes — MMcf
567,906

 
559,824

 
8,082

Consolidated pipeline transportation volumes — MMcf
381,828

 
362,583

 
19,245


Net income for our regulated pipeline segment increased 14 percent, primarily due to a $40.2 million increase in gross profit, partially offset by a $29.1 million increase in operating expenses. The increase in gross profit primarily reflects a $37.2 million increase in rates from the approved 2014 and 2015 GRIP filings. Additionally, gross profit reflects increased pipeline demand fees and through-system transportation volumes and rates that were offset by lower park and lend, storage and blending fees and the absence of a $1.8 million increase recorded in the prior-year associated with the renewal of an annual adjustment mechanism.

Operating expenses increased $29.1 million, primarily due to increased levels of pipeline and right-of-way maintenance activities to improve the safety and reliability of our system and increased depreciation expense associated with increased capital investments, along with the absence of a $6.7 million refund received in the prior year as a result of the completion of a state use tax audit.
Nonregulated Segment
Our nonregulated operations are conducted through Atmos Energy Holdings, Inc. (AEH), a wholly-owned subsidiary of Atmos Energy Corporation and, historically, have represented approximately five percent of our consolidated net income.
AEH's primary business is to buy, sell and deliver natural gas at competitive prices to approximately 1,000 customers located primarily in the Midwest and Southeast areas of the United States. AEH accomplishes this objective by aggregating and purchasing gas supply, arranging transportation and storage logistics and effectively managing commodity price risk.
AEH also earns storage and transportation demand fees primarily from our regulated distribution operations in Louisiana and Kentucky. These demand fees are subject to regulatory oversight and are renewed periodically.
Our nonregulated activities are significantly influenced by competitive factors in the industry and general economic conditions. Therefore, the margins earned from these activities are dependent upon our ability to attract and retain customers and to minimize the cost of buying, selling and delivering natural gas to offer more competitive pricing to those customers.

Natural gas prices can influence:
The demand for natural gas. Higher prices may cause customers to conserve or use alternative energy sources.
Conversely, lower prices could cause customers such as electric power generators to switch from alternative energy
sources to natural gas.
The collection of accounts receivable from customers, which could affect the level of bad debt expense recognized by this segment and
The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this
segment.

42



Natural gas price volatility can also influence our nonregulated business in the following ways:
Price volatility influences basis differentials, which provide opportunities to profit from identifying the lowest cost
alternative among the natural gas supplies, transportation and markets to which we have access.
Increased or decreased volatility impacts the amounts of unrealized margins recorded in our gross profit and could
impact the amount of cash required to collateralize our risk management liabilities.

Our nonregulated segment manages its exposure to natural gas commodity price risk through a combination of physical storage and financial instruments. Therefore, results for this segment include unrealized gains or losses on its net physical gas position and the related financial instruments used to manage commodity price risk. These margins fluctuate based upon changes in the spreads between the physical and forward natural gas prices. The magnitude of the unrealized gains and losses is also contingent upon the levels of our net physical position at the end of the reporting period.

Three Months Ended June 30, 2015 compared with Three Months Ended June 30, 2014
Financial and operating highlights for our nonregulated segment for the three months ended June 30, 2015 and 2014 are presented below.
 
Three Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
10,648

 
$
7,871

 
$
2,777

Storage and transportation services
3,607

 
3,603

 
4

Other
1,508

 
4,004

 
(2,496
)
Total realized margins
15,763

 
15,478

 
285

Unrealized margins
2,016

 
(665
)
 
2,681

Gross profit
17,779

 
14,813

 
2,966

Operating expenses
9,399

 
11,025

 
(1,626
)
Operating income
8,380

 
3,788

 
4,592

Miscellaneous income
345

 
1,018

 
(673
)
Interest charges
240

 
610

 
(370
)
Income before income taxes
8,485

 
4,196

 
4,289

Income tax expense
3,236

 
1,942

 
1,294

Net income
$
5,249

 
$
2,254

 
$
2,995

Gross nonregulated delivered gas sales volumes — MMcf
89,052

 
96,119

 
(7,067
)
Consolidated nonregulated delivered gas sales volumes — MMcf
75,929

 
82,074

 
(6,145
)
Net physical position (Bcf)
22.1

 
6.6

 
15.5

 
The $3.0 million quarter-over-quarter increase in gross profit reflects a $0.3 million increase in realized margins, combined with a $2.7 million increase in unrealized margins. The $0.3 million increase in realized margins primarily reflects:
A $2.8 million increase in gas delivery and related services margins, primarily due to an increase in per-unit margins from 8 cents to 12 cents per Mcf, partially offset by a seven percent decrease in consolidated sales volumes. AEH elected not to renew excess transportation capacity in certain markets in late fiscal 2014 and early 2015. As a result, AEH has experienced fewer deliveries to low-margin marketing and power generation customers, which is the primary driver for the decrease in consolidated sales volumes and higher per-unit margins.
A $2.5 million decrease in other realized margins, primarily due to increased storage fees and the timing of financial settlements in the current-year quarter.

Unrealized margins increased $2.7 million, primarily due to the quarter-over-quarter timing of realized margins on the settlement of hedged natural gas inventory positions.
Operating expenses decreased $1.6 million, primarily due to lower employee-related expenses.



43



Nine Months Ended June 30, 2015 compared with Nine Months Ended June 30, 2014
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
39,280

 
$
32,783

 
$
6,497

Storage and transportation services
10,273

 
10,815

 
(542
)
Other
(1,322
)
 
15,831

 
(17,153
)
Total realized margins
48,231

 
59,429

 
(11,198
)
Unrealized margins
8,493

 
11,539

 
(3,046
)
Gross profit
56,724

 
70,968

 
(14,244
)
Operating expenses
27,832

 
24,727

 
3,105

Operating income
28,892

 
46,241

 
(17,349
)
Miscellaneous income
897

 
1,785

 
(888
)
Interest charges
706

 
1,840

 
(1,134
)
Income before income taxes
29,083

 
46,186

 
(17,103
)
Income tax expense
11,512

 
18,604

 
(7,092
)
Net income
$
17,571

 
$
27,582

 
$
(10,011
)
Gross nonregulated delivered gas sales volumes — MMcf
319,423

 
343,451

 
(24,028
)
Consolidated nonregulated delivered gas sales volumes — MMcf
272,260

 
294,678

 
(22,418
)
Net physical position (Bcf)
22.1

 
6.6

 
15.5


The $14.2 million period-over-period decrease in gross profit reflects an $11.2 million decrease in realized margins, combined with a $3.0 million decrease in unrealized margins. The $11.2 million decrease in realized margins primarily reflects:
A $17.2 million decrease in other realized margins, primarily due to lower natural gas price volatility. In the prior-year period, strong market demand caused by significantly colder-than-normal weather resulted in increased market volatility. These market conditions created the opportunity to accelerate physical withdrawals that had been planned for later in the fiscal year into the second quarter to capture incremental gross profit margin. Market conditions in the current-year period were less volatile than the prior-year period, which provided fewer opportunities to capture incremental gross profit.
A $6.5 million increase in gas delivery and related services margins, due to the absence in the current-year period of losses incurred in the prior-year period to meet peaking requirements for certain customers, which caused per-unit margins to rise from 10 cents per Mcf in the prior-year period to 12 cents per Mcf in the current-year period and fewer deliveries to low-margin marketing and power generation customers as described above. The reduction in these deliveries combined with warmer weather during the current-year period compared to the prior-year period contributed to an eight percent decline in sales volumes.

Unrealized margins decreased $3.0 million, primarily due to the period-over-period timing of realized margins on the settlement of hedged natural gas inventory positions.
Operating expenses increased $3.1 million, primarily due to higher legal expenses as a result of the prior-year dismissal of the Kentucky litigation and the resolution of the Tennessee Business License Tax matter, which are discussed in Note 10 to the Form 10-K for the fiscal year ended September 30, 2014, partially offset by lower employee-related costs.
Liquidity and Capital Resources
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a variety of sources including internally generated funds and borrowings under our commercial paper program and bank credit facilities. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. Finally, from time to time, we raise funds from the public debt and equity capital markets to fund our liquidity needs.
We regularly evaluate our funding strategy and capital structure to ensure that we (i) have sufficient liquidity for our short-term and long-term needs in a cost-effective manner and (ii) maintain a balanced capital structure with a debt-to-

44



capitalization ratio in a target range of 50 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of capacity from our short-term facilities.
We plan to continue to fund our growth through the use of operating cash flows, debt and equity securities while maintaining a balanced capital structure. To support our capital market activities, we have a shelf registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. As of June 30, 2015, approximately $845 million of securities remained available for issuance under the shelf registration statement until March 28, 2016.
The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2015September 30, 2014 and June 30, 2014:
 
 
June 30, 2015
 
September 30, 2014
 
June 30, 2014
 
(In thousands, except percentages)
Short-term debt
$
251,977

 
4.2
%
 
$
196,695

 
3.4
%
 
$

 
%
Long-term debt
2,455,303

 
41.3
%
 
2,455,986

 
42.8
%
 
2,455,907

 
44.1
%
Shareholders’ equity
3,238,255

 
54.5
%
 
3,086,232

 
53.8
%
 
3,116,685

 
55.9
%
Total
$
5,945,535

 
100.0
%
 
$
5,738,913

 
100.0
%
 
$
5,572,592

 
100.0
%
Cash Flows
Our internally generated funds may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, prices for our products and services, demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks and other factors.

Cash flows from operating, investing and financing activities for the nine months ended June 30, 2015 and 2014 are presented below.
 
Nine Months Ended June 30
 
2015
 
2014
 
Change
 
(In thousands)
Total cash provided by (used in)
 
 
 
 
 
Operating activities
$
717,582

 
$
630,210

 
$
87,372

Investing activities
(668,602
)
 
(553,220
)
 
(115,382
)
Financing activities
(48,085
)
 
(91,768
)
 
43,683

Change in cash and cash equivalents
895

 
(14,778
)
 
15,673

Cash and cash equivalents at beginning of period
42,258

 
66,199

 
(23,941
)
Cash and cash equivalents at end of period
$
43,153

 
$
51,421

 
$
(8,268
)
Cash flows from operating activities
Period-over-period changes in our operating cash flows are primarily attributable to changes in net income and working capital changes, particularly within our regulated distribution segment resulting from changes in the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.
For the nine months ended June 30, 2015, we generated cash flow of $717.6 million from operating activities compared with $630.2 million for the nine months ended June 30, 2014. The $87.4 million increase in operating cash flows primarily reflects successful rate case outcomes in the prior year, the timing of gas cost recoveries under our purchased gas cost mechanisms and lower gas prices during the current-year storage injection season.
Cash flows from investing activities
In executing our regulatory strategy, we focus our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Currently, substantially all of our regulated distribution divisions and our Atmos Pipeline–Texas Division have rate tariffs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.
In recent years, a substantial portion of our cash resources has been used to fund growth projects in our regulated operations, our ongoing construction program and improvements to information technology systems. Over the last two fiscal years, approximately 80 percent of our capital spending has been committed to improving the safety and reliability of our

45



systems. Our ongoing construction program enables us to enhance the safety and reliability of the systems used to provide regulated distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network.
We anticipate our annual capital spending will be in the range of $900 million to $1.1 billion through fiscal 2018 as we continue to invest in the safety and reliability of our distribution and transportation systems. Where possible, we will also continue to focus our capital spending in jurisdictions that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system.
For the nine months ended June 30, 2015, capital expenditures were $667.5 million, compared with $552.6 million in the prior-year period. The $114.9 million increase primarily reflects:
A $68.5 million increase in capital spending in our regulated distribution segment, which primarily reflects the timing of the spending combined with a planned increase in safety and reliability investment in fiscal 2015.
A $47.4 million increase in capital spending in our regulated pipeline segment, primarily related to the enhancement and fortification of two storage fields to ensure the reliability of gas service to our Mid-Tex Division.
Cash flows from financing activities
    
For the nine months ended June 30, 2015, our financing activities used $48.1 million of cash compared with $91.8 million used in the prior-year period. The $43.7 million decrease of cash used is primarily due to timing between short-term debt borrowings and repayments during the current year, proceeds from the issuance of $500 million unsecured 4.125% senior notes in October 2014 and the settlement of the associated forward starting interest rate swaps, partially offset by the repayment of $500 million 4.95% senior unsecured notes at maturity on October 15, 2014, compared with short-term debt borrowings and repayments in the prior year and proceeds generated from the equity offering completed in February 2014.
The following table summarizes our share issuances for the nine months ended June 30, 2015 and 2014.
 
Nine Months Ended 
 June 30
 
2015
 
2014
Shares issued:
 
 
 
Direct Stock Purchase Plan
137,049

 
41,907

1998 Long-Term Incentive Plan
664,074

 
653,130

Retirement Savings Plan and Trust
296,067

 

Outside Directors Stock-for-Fee Plan

 
1,354

February 2014 Offering

 
9,200,000

Total shares issued
1,097,190

 
9,896,391


The year-over-year decrease in the number of shares issued reflects the equity offering completed in February 2014, partially offset by the fact that we have begun issuing shares for use by the Direct Stock Purchase Plan and the Retirement Savings Plan and Trust rather than using shares purchased in the open market. For the nine months ended June 30, 2015 and 2014, we canceled and retired 148,464 and 190,134 shares attributable to federal income tax withholdings on equity awards.

Credit Facilities

Our short-term borrowing requirements are affected primarily by the seasonal nature of the natural gas business and the level of our capital expenditures. Changes in the price of natural gas, the amount of natural gas we need to supply to meet our customers’ needs and our capital spending activities could significantly affect our borrowing requirements. However, our short-term borrowings typically reach their highest levels in the winter months.
We 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 that provide approximately $1.3 billion of working capital funding. As of June 30, 2015, the amount available to us under our credit facilities, net of outstanding letters of credit, was $1.1 billion.



46



Credit Ratings
Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy, the risks associated with our regulated and nonregulated businesses and the regulatory structures that govern our rates in the states where we operate.
Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch). As of June 30, 2015, S&P and Moody's maintained a stable outlook while Fitch maintained a positive outlook. Our current debt ratings are all considered investment grade and are as follows:
 
S&P
 
Moody’s
 
Fitch
Senior unsecured long-term debt
A-
  
A2
  
A-
Commercial paper
A-2
  
P-1
  
F-2
On July 1, 2015, Fitch upgraded our senior unsecured debt rating to A from A- with a ratings outlook of stable, citing Fitch's expectation of continued strong financial performance, which has been driven primarily by organic growth in our regulated distribution and regulated pipeline segments.
A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the three credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.
A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P, Aaa for Moody’s and AAA for Fitch. The lowest investment grade credit rating is BBB- for S&P, Baa3 for Moody’s and BBB- for Fitch. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.
Debt Covenants
We were in compliance with all of our debt covenants as of June 30, 2015. Our debt covenants are described in greater detail in Note 5 to the unaudited condensed consolidated financial statements.
Contractual Obligations and Commercial Commitments
Except as noted in Note 7 to the unaudited condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the nine months ended June 30, 2015.

Risk Management Activities
We conduct risk management activities through our regulated distribution and nonregulated segments. In our regulated distribution segment, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
In our nonregulated segment, we manage our exposure to the risk of natural gas price changes and lock in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. To the extent our inventory cost and actual sales and actual purchases do not correlate with the changes in the market indices we use in our hedges, we could experience ineffectiveness or the hedges may no longer meet the accounting requirements for hedge accounting, resulting in the financial instruments being treated as mark to market instruments through earnings.

47



The following table shows the components of the change in fair value of our regulated distribution segment’s financial instruments for the nine months ended June 30, 2015 and 2014:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Fair value of contracts at beginning of period
$
(137,710
)
 
$
89,411

 
$
14,284

 
$
109,648

Contracts realized/settled
(48
)
 
23

 
(33,859
)
 
5,220

Fair value of new contracts
1,514

 
(902
)
 
1,365

 
(36
)
Other changes in value
85,993

 
(39,019
)
 
(32,041
)
 
(65,319
)
Fair value of contracts at end of period
$
(50,251
)
 
$
49,513

 
$
(50,251
)
 
$
49,513


The fair value of our regulated distribution segment’s financial instruments at June 30, 2015 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2015
 
Maturity in Years
 
 
Source of Fair Value
Less
Than 1
 
1-3
 
4-5
 
Greater
Than 5
 
Total
Fair
Value
 
(In thousands)
Prices actively quoted
$
(4,136
)
 
$
(46,115
)
 
$

 
$

 
$
(50,251
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(4,136
)
 
$
(46,115
)
 
$

 
$

 
$
(50,251
)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the nine months ended June 30, 2015 and 2014:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Fair value of contracts at beginning of period
$
(36,140
)
 
$
5,796

 
$
(3,033
)
 
$
(14,700
)
Contracts realized/settled
11,502

 
(3,220
)
 
23,013

 
11,358

Fair value of new contracts

 

 

 

Other changes in value
4,121

 
762

 
(40,497
)
 
6,680

Fair value of contracts at end of period
(20,517
)
 
3,338

 
(20,517
)
 
3,338

Netting of cash collateral
31,323

 
9,689

 
31,323

 
9,689

Cash collateral and fair value of contracts at period end
$
10,806

 
$
13,027

 
$
10,806

 
$
13,027


The fair value of our nonregulated segment’s financial instruments at June 30, 2015 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2015
 
Maturity in Years
 
 
Source of Fair Value
Less
Than 1
 
1-3
 
4-5
 
Greater
Than 5
 
Total
Fair
Value
 
(In thousands)
Prices actively quoted
$
(15,066
)
 
$
(5,298
)
 
$
(153
)
 
$

 
$
(20,517
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(15,066
)
 
$
(5,298
)
 
$
(153
)
 
$

 
$
(20,517
)


48



Pension and Postretirement Benefits Obligations
For the nine months ended June 30, 2015 and 2014, our total net periodic pension and other benefits costs were $44.2 million and $53.5 million. A substantial portion of those costs relating to our regulated distribution operations are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
Our fiscal 2015 costs were determined using a September 30, 2014 measurement date. As of September 30, 2014, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30, 2013, the measurement date for our fiscal 2014 net periodic cost. Therefore, we decreased the discount rate used to measure our fiscal 2015 net periodic cost from 4.95 percent to 4.43 percent. We maintained our expected return on plan assets at 7.25 percent in the determination of our fiscal 2015 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of changes of these and other assumptions and the absence of a $4.5 million non-recurring settlement loss recorded during the first quarter of fiscal 2014, we expect our fiscal 2015 net periodic pension cost to decrease by approximately 10 percent.
The amounts with which we fund our defined benefit plans are determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plans when the funding requirements are determined on January 1 of each year. Based upon that determination, we are not required to make a minimum contribution to our defined benefit plans during fiscal 2015. However, we made a voluntary contribution of $38.0 million during the third quarter of fiscal 2015.
For the nine months ended June 30, 2015 we contributed $15.0 million to our postretirement medical plans. We anticipate contributing a total of approximately $20 million to our postretirement plans during fiscal 2015.
The projected pension liability, future funding requirements and the amount of pension expense or income recognized for the plans are subject to change, depending upon the actuarial value of plan assets in the plans and the determination of future benefit obligations as of each subsequent actuarial calculation date. These amounts will be determined by actual investment returns, changes in interest rates, values of assets in the plans and changes in the demographic composition of the participants in the plans.
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.



49




OPERATING STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for our regulated distribution, regulated pipeline and nonregulated segments for the three and nine month periods ended June 30, 2015 and 2014.
Regulated Distribution Sales and Statistical Data
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
METERS IN SERVICE, end of period
 
 
 
 
 
 
 
Residential
2,872,584

 
2,751,812

 
2,872,584

 
2,751,812

Commercial
262,353

 
245,833

 
262,353

 
245,833

Industrial
1,518

 
1,466

 
1,518

 
1,466

Public authority and other
8,419

 
8,400

 
8,419

 
8,400

Total meters
3,144,874

 
3,007,511

 
3,144,874

 
3,007,511

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
42.6

 
39.0

 
42.6

 
39.0

SALES VOLUMES — MMcf(1)
 
 
 
 
 
 
 
Gas sales volumes
 
 
 
 
 
 
 
Residential
16,667

 
19,555

 
159,067

 
175,884

Commercial
15,216

 
15,305

 
87,852

 
92,240

Industrial
2,925

 
3,074

 
11,713

 
12,898

Public authority and other
1,318

 
1,407

 
6,871

 
7,680

Total gas sales volumes
36,126

 
39,341

 
265,503

 
288,702

Transportation volumes
33,743

 
36,321

 
117,019

 
116,064

Total throughput
69,869

 
75,662

 
382,522

 
404,766

OPERATING REVENUES (000’s)(1)
 
 
 
 
 
 
 
Gas sales revenues
 
 
 
 
 
 
 
Residential
$
253,033

 
$
309,798

 
$
1,538,771

 
$
1,698,600

Commercial
114,942

 
154,375

 
666,220

 
748,705

Industrial
13,089

 
19,458

 
62,694

 
74,003

Public authority and other
8,465

 
10,817

 
46,355

 
54,960

Total gas sales revenues
389,529

 
494,448

 
2,314,040

 
2,576,268

Transportation revenues
16,506

 
16,216

 
57,635

 
53,972

Other gas revenues
10,759

 
7,043

 
22,504

 
22,292

Total operating revenues
$
416,794

 
$
517,707

 
$
2,394,179

 
$
2,652,532

Average transportation revenue per Mcf
$
0.49

 
$
0.45

 
$
0.49

 
$
0.47

Average cost of gas per Mcf sold
$
4.15

 
$
6.61

 
$
5.26

 
$
5.92

See footnote following these tables.


50



Regulated Pipeline and Nonregulated Operations Sales and Statistical Data
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2015
 
2014
 
2015
 
2014
CUSTOMERS, end of period
 
 
 
 
 
 
 
Industrial
750

 
736

 
750

 
736

Municipal
129

 
128

 
129

 
128

Other
516

 
524

 
516

 
524

Total
1,395

 
1,388

 
1,395

 
1,388

NONREGULATED INVENTORY STORAGE
 
 
 
 
 
 
 
BALANCE — Bcf
28.2

 
10.9

 
28.2

 
10.9

REGULATED PIPELINE VOLUMES — MMcf(1)
165,898

 
160,038

 
567,906

 
559,824

NONREGULATED DELIVERED GAS SALES
 
 
 
 
 
 
 
VOLUMES — MMcf(1)
89,052

 
96,119

 
319,423

 
343,451

OPERATING REVENUES (000’s)(1)
 
 
 
 
 
 
 
Regulated pipeline
$
97,008

 
$
87,189

 
$
272,305

 
$
232,145

Nonregulated
278,769

 
465,485

 
1,179,379

 
1,660,131

Total operating revenues
$
375,777

 
$
552,674

 
$
1,451,684

 
$
1,892,276

Note to preceding tables:
 
(1) 
Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.
RECENT ACCOUNTING DEVELOPMENTS
Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the unaudited condensed consolidated financial statements.
 
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Information regarding our quantitative and qualitative disclosures about market risk are disclosed in Item 7A in our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. During the nine months ended June 30, 2015, there were no material changes in our quantitative and qualitative disclosures about market risk.

Item 4.
Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2015 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
    
We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of the fiscal year ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


51



PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
During the nine months ended June 30, 2015, there were no material changes in the status of the litigation and other matters that were disclosed in Note 10 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2014. We continue to believe that the final outcome of such litigation and other matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
 
Item 6.
Exhibits
A list of exhibits required by Item 601 of Regulation S-K and filed as part of this report is set forth in the Exhibits Index, which immediately precedes such exhibits.

52



SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
ATMOS ENERGY CORPORATION
               (Registrant)
 
 
 
By: /s/    BRET J. ECKERT
 
 
 
Bret J. Eckert
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: August 5, 2015

53



EXHIBITS INDEX
Item 6
 
Exhibit
Number
  
Description
Page Number or
Incorporation by
Reference to
12
  
Computation of ratio of earnings to fixed charges
 
15
  
Letter regarding unaudited interim financial information
 
31
  
Rule 13a-14(a)/15d-14(a) Certifications
 
32
  
Section 1350 Certifications*
 
101.INS
  
XBRL Instance Document
 
101.SCH
  
XBRL Taxonomy Extension Schema
 
101.CAL
  
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
  
XBRL Taxonomy Extension Definition Linkbase
 
101.LAB
  
XBRL Taxonomy Extension Labels Linkbase
 
101.PRE
  
XBRL Taxonomy Extension Presentation Linkbase
 
 
*
These certifications, which were made pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Quarterly Report on Form 10-Q, will not be deemed to be filed with the Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference.

54