Document


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, 2016
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 29, 2016.
Class
  
Shares Outstanding
No Par Value
  
103,847,858




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,
2016
 
September 30,
2015
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
9,972,415

 
$
9,240,100

Less accumulated depreciation and amortization
1,918,868

 
1,809,520

Net property, plant and equipment
8,053,547

 
7,430,580

Current assets
 
 
 
Cash and cash equivalents
66,206

 
28,653

Accounts receivable, net
277,362

 
295,160

Gas stored underground
244,841

 
236,603

Other current assets
60,504

 
65,890

Total current assets
648,913

 
626,306

Goodwill
742,702

 
742,702

Deferred charges and other assets
282,206

 
293,357

 
$
9,727,368

 
$
9,092,945

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, 2016 — 103,827,358 shares; September 30, 2015 — 101,478,818 shares
$
519

 
$
507

Additional paid-in capital
2,371,381

 
2,230,591

Accumulated other comprehensive loss
(178,233
)
 
(109,330
)
Retained earnings
1,273,057

 
1,073,029

Shareholders’ equity
3,466,724

 
3,194,797

Long-term debt
2,205,645

 
2,455,388

Total capitalization
5,672,369

 
5,650,185

Current liabilities
 
 
 
Accounts payable and accrued liabilities
198,882

 
238,942

Other current liabilities
410,452

 
457,954

Short-term debt
670,466

 
457,927

Current maturities of long-term debt
250,000

 

Total current liabilities
1,529,800

 
1,154,823

Deferred income taxes
1,585,500

 
1,411,315

Regulatory cost of removal obligation
427,332

 
427,553

Pension and postretirement liabilities
283,579

 
287,373

Deferred credits and other liabilities
228,788

 
161,696

 
$
9,727,368

 
$
9,092,945

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 June 30
 
2016
 
2015
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
414,226

 
$
416,794

Regulated pipeline segment
109,249

 
97,008

Nonregulated segment
214,555

 
278,769

Intersegment eliminations
(105,114
)
 
(106,170
)
 
632,916

 
686,401

Purchased gas cost
 
 
 
Regulated distribution segment
138,845

 
149,775

Regulated pipeline segment

 

Nonregulated segment
191,741

 
260,990

Intersegment eliminations
(104,981
)
 
(106,037
)
 
225,605

 
304,728

Gross profit
407,311

 
381,673

Operating expenses
 
 
 
Operation and maintenance
137,444

 
132,447

Depreciation and amortization
73,459

 
68,444

Taxes, other than income
59,244

 
63,175

Total operating expenses
270,147

 
264,066

Operating income
137,164

 
117,607

Miscellaneous income
833

 
634

Interest charges
27,698

 
27,955

Income before income taxes
110,299

 
90,286

Income tax expense
39,106

 
34,005

Net income
$
71,193

 
$
56,281

Basic and diluted net income per share
$
0.69

 
$
0.55

Cash dividends per share
$
0.42

 
$
0.39

Basic and diluted weighted average shares outstanding
103,750

 
102,000

See accompanying notes to condensed consolidated financial statements.







 










4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 
Nine Months Ended 
 June 30
 
2016
 
2015
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
1,902,513

 
$
2,394,179

Regulated pipeline segment
299,629

 
272,305

Nonregulated segment
774,474

 
1,179,379

Intersegment eliminations
(305,186
)
 
(360,629
)
 
2,671,430

 
3,485,234

Purchased gas cost
 
 
 
Regulated distribution segment
884,529

 
1,397,113

Regulated pipeline segment

 

Nonregulated segment
722,803

 
1,122,655

Intersegment eliminations
(304,787
)
 
(360,230
)
 
1,302,545

 
2,159,538

Gross profit
1,368,885

 
1,325,696

Operating expenses
 
 
 
Operation and maintenance
395,958

 
384,489

Depreciation and amortization
216,670

 
204,059

Taxes, other than income
172,872

 
181,606

Total operating expenses
785,500

 
770,154

Operating income
583,385

 
555,542

Miscellaneous expense
(1,061
)
 
(2,634
)
Interest charges
85,741

 
85,166

Income before income taxes
496,583

 
467,742

Income tax expense
180,719

 
176,182

Net income
$
315,864

 
$
291,560

Basic and diluted net income per share
$
3.06

 
$
2.86

Cash dividends per share
$
1.26

 
$
1.17

Basic and diluted weighted average shares outstanding
103,137

 
101,776

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
 
2016
 
2015
 
2016
 
2015
 
(Unaudited)
(In thousands)
Net income
$
71,193

 
$
56,281

 
$
315,864

 
$
291,560

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $110, $(41), $(837) and $(170)
151

 
(191
)
 
(1,496
)
 
(296
)
Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(22,561), $31,314, $(50,631) and $(17,232)
(39,250
)
 
54,475

 
(88,085
)
 
(29,981
)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $11,575, $7,393, $13,220 and $(12,698)
18,105

 
11,563

 
20,678

 
(19,571
)
Total other comprehensive income (loss)
(20,994
)
 
65,847

 
(68,903
)
 
(49,848
)
Total comprehensive income
$
50,199

 
$
122,128

 
$
246,961

 
$
241,712


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
315,864

 
$
291,560

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
216,670

 
204,059

Charged to other accounts
983

 
853

Deferred income taxes
171,042

 
164,627

Other
19,767

 
18,146

Net assets / liabilities from risk management activities
(8,357
)
 
(13,136
)
Net change in operating assets and liabilities
(91,371
)
 
51,473

Net cash provided by operating activities
624,598

 
717,582

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(796,008
)
 
(667,483
)
Other, net
1,627

 
(1,119
)
Net cash used in investing activities
(794,381
)
 
(668,602
)
Cash Flows From Financing Activities
 
 
 
Net increase in short-term debt
212,539

 
48,830

Net proceeds from equity offering
98,660

 

Issuance of common stock through stock purchase and employee retirement plans
26,500

 
20,813

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
(130,363
)
 
(116,645
)
Repurchase of equity awards

 
(7,985
)
Net cash provided by (used in) financing activities
207,336

 
(48,085
)
Net increase in cash and cash equivalents
37,553

 
895

Cash and cash equivalents at beginning of period
28,653

 
42,258

Cash and cash equivalents at end of period
$
66,206

 
$
43,153


See accompanying notes to condensed consolidated financial statements.

7



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2016
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, 2016, 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, 2015. 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, 2015. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2016 are not indicative of our results of operations for the full 2016 fiscal year, which ends September 30, 2016.
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, 2015.
Certain prior-year amounts have been reclassified to conform with the current year presentation.
During the second quarter of fiscal 2016, 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. 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. As of June 30, 2016, we were actively evaluating all of our sources of revenue to determine the potential effect on our financial position, results of operations and cash flows and the transition approach we will utilize. We are also actively monitoring the deliberations of the FASB's Transition Resource Group as decisions made by this group will impact the final conclusions of this evaluation.
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

8



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.
In November 2015, the FASB issued guidance that requires all deferred income tax liabilities and assets to be presented as noncurrent in a classified balance sheet. Currently, entities are required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. As permitted under the new guidance, we elected early adoption as of March 31, 2016. The adoption of this guidance had no impact on our results of operations or cash flows. Because we adopted this new guidance prospectively, prior periods have not been adjusted.
In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning October 1, 2018; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance.
In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adoption is permitted. The new leasing standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. We are currently evaluating the effect on our financial position, results of operations and cash flows.
In March 2016, the FASB issued guidance to simplify the accounting and reporting of share-based payment arrangements. Key modifications required under the new guidance include:
Recognition of all excess tax benefits and tax deficiencies associated with stock-based compensation as income tax expense or benefit in the income statement in the period the awards vest. The guidance also requires these income tax inflows and outflows to be classified as an operating activity.
Simplification of the accounting for forfeitures.
Clarification that cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity.

As permitted under the new guidance, we elected early adoption as of March 31, 2016. In accordance with the transition requirements, we recorded a $3.3 million income tax benefit during the first six months of fiscal 2016. Additionally, we recorded a $14.5 million cumulative-effect increase to retained earnings with an offsetting increase to the Company’s net operating loss (NOL) deferred tax asset to recognize the effect of excess tax benefits earned prior to September 30, 2015. For the nine months ended June 30, 2016, we have recognized a total income tax benefit of $4.9 million. Since we have adopted this new guidance prospectively, prior periods have not been adjusted.
In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are currently evaluating the potential impact of this new guidance.
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.

9




 
Significant regulatory assets and liabilities as of June 30, 2016 and September 30, 2015 included the following:
 
June 30,
2016
 
September 30,
2015
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
110,425

 
$
121,183

Infrastructure mechanisms(2)
31,090

 
32,813

Deferred gas costs
3,390

 
9,715

Recoverable loss on reacquired debt
14,401

 
16,319

APT annual adjustment mechanism
2,976

 
1,002

Rate case costs
1,640

 
1,533

Other
20,906

 
9,774

 
$
184,828

 
$
192,339

Regulatory liabilities:
 
 
 
Regulatory cost of removal obligations
$
486,290

 
$
483,676

Deferred gas costs
34,362

 
28,100

Asset retirement obligations
9,063

 
9,063

Other
5,483

 
3,693

 
$
535,198

 
$
524,532

 
(1) 
Includes $12.9 million and $16.6 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, which primarily consist of interest, depreciation and other taxes, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

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, 2015. We evaluate performance based on net income or loss of the respective operating units.

10




Income statements for the three and nine months ended June 30, 2016 and 2015 by segment are presented in the following tables:
 
Three Months Ended June 30, 2016
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
411,982

 
$
28,518

 
$
192,416

 
$

 
$
632,916

Intersegment revenues
2,244

 
80,731

 
22,139

 
(105,114
)
 

 
414,226

 
109,249

 
214,555

 
(105,114
)
 
632,916

Purchased gas cost
138,845

 

 
191,741

 
(104,981
)
 
225,605

Gross profit
275,381

 
109,249

 
22,814

 
(133
)
 
407,311

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
100,859

 
29,083

 
7,635

 
(133
)
 
137,444

Depreciation and amortization
58,916

 
13,409

 
1,134

 

 
73,459

Taxes, other than income
52,377

 
6,220

 
647

 

 
59,244

Total operating expenses
212,152

 
48,712

 
9,416

 
(133
)
 
270,147

Operating income
63,229

 
60,537

 
13,398

 

 
137,164

Miscellaneous income (expense)
1,111

 
(359
)
 
574

 
(493
)
 
833

Interest charges
18,968

 
9,002

 
221

 
(493
)
 
27,698

Income before income taxes
45,372

 
51,176

 
13,751

 

 
110,299

Income tax expense
15,516

 
18,046

 
5,544

 

 
39,106

Net income
$
29,856

 
$
33,130

 
$
8,207

 
$

 
$
71,193

Capital expenditures
$
191,202

 
$
66,639

 
$
(66
)
 
$

 
$
257,775

 
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



11



 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended June 30, 2016
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,896,636

 
$
75,344

 
$
699,450

 
$

 
$
2,671,430

Intersegment revenues
5,877

 
224,285

 
75,024

 
(305,186
)
 

 
1,902,513

 
299,629

 
774,474

 
(305,186
)
 
2,671,430

Purchased gas cost
884,529

 

 
722,803

 
(304,787
)
 
1,302,545

Gross profit
1,017,984

 
299,629

 
51,671

 
(399
)
 
1,368,885

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
291,388

 
83,302

 
21,667

 
(399
)
 
395,958

Depreciation and amortization
173,913

 
39,358

 
3,399

 

 
216,670

Taxes, other than income
152,324

 
18,529

 
2,019

 

 
172,872

Total operating expenses
617,625

 
141,189

 
27,085

 
(399
)
 
785,500

Operating income
400,359

 
158,440

 
24,586

 

 
583,385

Miscellaneous income (expense)
209

 
(1,164
)
 
1,245

 
(1,351
)
 
(1,061
)
Interest charges
58,390

 
27,294

 
1,408

 
(1,351
)
 
85,741

Income before income taxes
342,178

 
129,982

 
24,423

 

 
496,583

Income tax expense
124,755

 
46,081

 
9,883

 

 
180,719

Net income
$
217,423

 
$
83,901

 
$
14,540

 
$

 
$
315,864

Capital expenditures
$
533,826

 
$
262,058

 
$
124

 
$

 
$
796,008

 
 
 
 
 
 
 
 
 
 
 
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

 

12



Balance sheet information at June 30, 2016 and September 30, 2015 by segment is presented in the following tables:

 
June 30, 2016
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
6,067,548

 
$
1,935,087

 
$
50,912

 
$

 
$
8,053,547

Investment in subsidiaries
1,007,787

 

 

 
(1,007,787
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
61,441

 

 
4,765

 

 
66,206

Assets from risk management activities
3,651

 

 
4,047

 

 
7,698

Other current assets
370,444

 
22,269

 
391,265

 
(208,969
)
 
575,009

Intercompany receivables
981,651

 

 

 
(981,651
)
 

Total current assets
1,417,187

 
22,269

 
400,077

 
(1,190,620
)
 
648,913

Goodwill
575,449

 
132,542

 
34,711

 

 
742,702

Noncurrent assets from risk management activities
750

 

 
908

 

 
1,658

Deferred charges and other assets
258,370

 
21,976

 
202

 

 
280,548

 
$
9,327,091

 
$
2,111,874

 
$
486,810

 
$
(2,198,407
)
 
$
9,727,368

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,466,724

 
$
661,175

 
$
346,612

 
$
(1,007,787
)
 
$
3,466,724

Long-term debt
2,205,645

 

 

 

 
2,205,645

Total capitalization
5,672,369

 
661,175

 
346,612

 
(1,007,787
)
 
5,672,369

Current liabilities
 
 
 
 
 
 
 
 
 
Current maturities of long-term debt
250,000

 

 

 

 
250,000

Short-term debt
870,466

 

 

 
(200,000
)
 
670,466

Liabilities from risk management activities
56,883

 

 

 

 
56,883

Other current liabilities
453,831

 
16,590

 
90,999

 
(8,969
)
 
552,451

Intercompany payables

 
953,683

 
27,968

 
(981,651
)
 

Total current liabilities
1,631,180

 
970,273

 
118,967

 
(1,190,620
)
 
1,529,800

Deferred income taxes
1,093,755

 
480,336

 
11,409

 

 
1,585,500

Noncurrent liabilities from risk management activities
176,491

 

 

 

 
176,491

Regulatory cost of removal obligation
427,332

 

 

 

 
427,332

Pension and postretirement liabilities
283,579

 

 

 

 
283,579

Deferred credits and other liabilities
42,385

 
90

 
9,822

 

 
52,297

 
$
9,327,091

 
$
2,111,874

 
$
486,810

 
$
(2,198,407
)
 
$
9,727,368


13





 
September 30, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,670,306

 
$
1,706,449

 
$
53,825

 
$

 
$
7,430,580

Investment in subsidiaries
1,038,670

 

 
(2,096
)
 
(1,036,574
)
 

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
23,863

 

 
4,790

 

 
28,653

Assets from risk management activities
378

 

 
8,854

 

 
9,232

Other current assets
421,591

 
24,628

 
480,503

 
(338,301
)
 
588,421

Intercompany receivables
887,713

 

 

 
(887,713
)
 

Total current assets
1,333,545

 
24,628

 
494,147

 
(1,226,014
)
 
626,306

Goodwill
575,449

 
132,542

 
34,711

 

 
742,702

Noncurrent assets from risk management activities
368

 

 

 

 
368

Deferred charges and other assets
270,372

 
17,288

 
5,329

 

 
292,989

 
$
8,888,710

 
$
1,880,907

 
$
585,916

 
$
(2,262,588
)
 
$
9,092,945

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,194,797

 
$
577,275

 
$
461,395

 
$
(1,038,670
)
 
$
3,194,797

Long-term debt
2,455,388

 

 

 

 
2,455,388

Total capitalization
5,650,185

 
577,275

 
461,395

 
(1,038,670
)
 
5,650,185

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
782,927

 

 

 
(325,000
)
 
457,927

Liabilities from risk management activities
9,568

 

 

 

 
9,568

Other current liabilities
569,273

 
29,780

 
99,480

 
(11,205
)
 
687,328

Intercompany payables

 
867,409

 
20,304

 
(887,713
)
 

Total current liabilities
1,361,768

 
897,189

 
119,784

 
(1,223,918
)
 
1,154,823

Deferred income taxes
1,008,091

 
406,254

 
(3,030
)
 

 
1,411,315

Noncurrent liabilities from risk management activities
110,539

 

 

 

 
110,539

Regulatory cost of removal obligation
427,553

 

 

 

 
427,553

Pension and postretirement liabilities
287,373

 

 

 

 
287,373

Deferred credits and other liabilities
43,201

 
189

 
7,767

 

 
51,157

 
$
8,888,710

 
$
1,880,907

 
$
585,916

 
$
(2,262,588
)
 
$
9,092,945


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, 2016 and 2015 are calculated as follows:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share
 
 
 
 
 
 
 
Net income
$
71,193

 
$
56,281

 
$
315,864

 
$
291,560

Less: Income allocated to participating securities
108

 
111

 
496

 
596

Income available to common shareholders
$
71,085

 
$
56,170

 
$
315,368

 
$
290,964

Basic and diluted weighted average shares outstanding
103,750

 
102,000

 
103,137

 
101,776

Net income per share - Basic and Diluted
$
0.69

 
$
0.55

 
$
3.06

 
$
2.86


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, 2015. Except as noted below, there were no material changes in the terms of our debt instruments during the nine months ended June 30, 2016.
Long-term debt
Long-term debt at June 30, 2016 and September 30, 2015 consisted of the following:
 
 
June 30, 2016
 
September 30, 2015
 
(In thousands)
Unsecured 6.35% Senior Notes, due June 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

 
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
4,355

 
4,612

Current maturities
250,000

 

 
$
2,205,645

 
$
2,455,388

 
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.

15



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, 2016 and September 30, 2015 a total of $670.5 million and $457.9 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, which was renewed on April 1, 2016, and a $10 million unsecured revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.1 million at June 30, 2016.
In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016.
Nonregulated Operations
Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million bilateral credit facility that was renewed and extended in March 2016 and one committed $15 million bilateral credit facility that was renewed and extended in December 2015. The uncommitted $25 million bilateral credit facility currently expires in December 2016 and the $15 million bilateral credit facility expires in September 2016. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $33.0 million at June 30, 2016.
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, 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, 2016, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 49 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, 2016. 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.


16



6.    Shareholders' Equity

Shelf Registration
On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. At June 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.

At-the-Market Equity Sales Program

On March 28, 2016, we entered into an at-the-market (ATM) equity distribution agreement (the Agreement) with Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC in their capacity as agents and/or as principals (Agents). Under the terms of the Agreement, we may issue and sell, through any of the Agents, shares of our common stock, up to an aggregate offering price of $200 million, through the period ended March 28, 2019. We may also sell shares from time to time to an Agent for its own account at a price to be agreed upon at the time of sale. We will pay each Agent a commission of 1.0% of the gross offering proceeds of the shares sold through it as a sales agent. We have no obligation to offer or sell any shares under the Agreement, and may at any time suspend offers and sales under the Agreement. The shares will be issued pursuant to our shelf registration statement filed with the SEC on March 28, 2016. During the third fiscal quarter of 2016, we sold 1,360,756 shares of common stock under the ATM program for $100.0 million and received net proceeds of $98.7 million.

1998 Long-Term Incentive Plan 
In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock. 
As of September 30, 2015, we were authorized to grant awards for up to a maximum of 8.7 million shares of common stock under this plan subject to certain adjustment provisions. In February 2016, our shareholders voted to increase the number of authorized LTIP shares by 2.5 million shares and to extend the term of the plan for an additional five years, through September 2021. On March 29, 2016, we filed with the SEC a registration statement on Form S-8 to register an additional 2.5 million shares; we also listed such shares with the New York Stock Exchange.
2011 Share Repurchase Program
We did not repurchase any shares during the nine months ended June 30, 2016 and 2015 under our 2011 share repurchase program, which is scheduled to end on September 30, 2016.
Accumulated Other Comprehensive Income (Loss)
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 (loss).

17



 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2015
$
4,949

 
$
(88,842
)
 
$
(25,437
)
 
$
(109,330
)
Other comprehensive loss before reclassifications
(1,417
)
 
(88,345
)
 
(8,612
)
 
(98,374
)
Amounts reclassified from accumulated other comprehensive income
(79
)
 
260

 
29,290

 
29,471

Net current-period other comprehensive income (loss)
(1,496
)
 
(88,085
)
 
20,678

 
(68,903
)
June 30, 2016
$
3,453

 
$
(176,927
)
 
$
(4,759
)
 
$
(178,233
)
 
 
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
)

The following tables detail reclassifications out of AOCI for the three and nine months ended June 30, 2016 and 2015. Amounts in parentheses below indicate decreases to net income in the statement of income.
 
Three Months Ended June 30, 2016
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Cash flow hedges
 
 
 
Interest rate agreements
$
(137
)
 
Interest charges
Commodity contracts
(12,347
)
 
Purchased gas cost
 
(12,484
)
 
Total before tax
 
4,865

 
Tax benefit
Total reclassifications
$
(7,619
)
 
Net of tax

18



 
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
 
 
 
 
 
Nine Months Ended June 30, 2016
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
$
124

 
Operation and maintenance expense
 
124

 
Total before tax
 
(45
)
 
Tax expense
 
$
79

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(410
)
 
Interest charges
Commodity contracts
(48,015
)
 
Purchased gas cost
 
(48,425
)
 
Total before tax
 
18,875

 
Tax benefit
 
$
(29,550
)
 
Net of tax
Total reclassifications
$
(29,471
)
 
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

19




7.     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, 2016 and 2015 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.
 
Three Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,698

 
$
5,051

 
$
2,705

 
$
3,895

Interest cost
7,095

 
6,698

 
3,106

 
3,596

Expected return on assets
(6,881
)
 
(6,435
)
 
(1,566
)
 
(1,608
)
Amortization of transition obligation

 

 
21

 
69

Amortization of prior service credit
(57
)
 
(48
)
 
(411
)
 
(411
)
Amortization of actuarial (gain) loss
3,319

 
3,916

 
(541
)
 

Net periodic pension cost
$
8,174

 
$
9,182

 
$
3,314

 
$
5,541

 
 
 
 
 
 
 
 
 
Nine Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
14,093

 
$
15,153

 
$
8,117

 
$
11,687

Interest cost
21,284

 
20,095

 
9,318

 
10,789

Expected return on assets
(20,642
)
 
(19,308
)
 
(4,698
)
 
(4,824
)
Amortization of transition obligation

 

 
62

 
205

Amortization of prior service credit
(170
)
 
(144
)
 
(1,233
)
 
(1,233
)
Amortization of actuarial (gain) loss
9,959

 
11,749

 
(1,625
)
 

Net periodic pension cost
$
24,524

 
$
27,545

 
$
9,941

 
$
16,624


The assumptions used to develop our net periodic pension cost for the three and nine months ended June 30, 2016 and 2015 are as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
2016
 
2015
 
2016
 
2015
Discount rate
 
4.55%
 
4.43%
 
4.55%
 
4.43%
Rate of compensation increase
 
3.50%
 
3.50%
 
N/A
 
N/A
Expected return on plan assets
 
7.00%
 
7.25%
 
4.45%
 
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 plan as of January 1, 2016. Based on that determination, we are not required to make a minimum contribution to our defined benefit plan; however, we made a voluntary contribution of $15.0 million during the third quarter of fiscal 2016.
We contributed $12.8 million to our other post-retirement benefit plans during the nine months ended June 30, 2016. We expect to contribute between $15 million and $25 million to these plans during fiscal 2016.


20



8.    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, 2015, there were no material changes in the status of such litigation and environmental-related matters or claims during the nine months ended June 30, 2016.
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. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. There were no material changes to the purchase commitments for the nine months ended June 30, 2016.
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. Except for purchases made in the normal course of business under these contracts, there were no material changes to the purchase commitments for the nine months ended June 30, 2016.
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, 2015. There were no material changes to the estimated storage and transportation fees for the nine months ended June 30, 2016.
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, 2016, rate cases were in progress in our Kentucky and Virginia service areas, two formula rate mechanisms were in progress in our Louisiana service area and an infrastructure mechanism was in progress in our Mississippi service area. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
9.    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, 2015. During the nine months ended June 30, 2016 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

21



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 2015-2016 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or 23.0 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 54 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, 2016, 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, 2016, we had $18.4 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.
 
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, 2016, 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, 2016, 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
 

 
(35,118
)
 
 
Cash Flow
 

 
45,325

 
 
Not designated
 
10,002

 
51,128

 
 
 
 
10,002

 
61,335


22



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, 2016 and September 30, 2015. 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, 2016
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$

 
$

 
$
10,149

 
$
(35,680
)
Interest rate contracts
Other current assets /
Other current liabilities
 

 
(65,533
)
 

 

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

 

 
3,911

 
(3,831
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 
(184,131
)
 

 

Total
 
 

 
(249,664
)
 
14,060

 
(39,511
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
3,651

 
(40
)
 
27,247

 
(20,407
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
750

 

 
10,812

 
(9,983
)
Total
 
 
4,401

 
(40
)
 
38,059

 
(30,390
)
Gross Financial Instruments
 
 
4,401

 
(249,704
)
 
52,119

 
(69,901
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 

 

 
(51,210
)
 
51,210

Net Financial Instruments
 
 
4,401

 
(249,704
)
 
909

 
(18,691
)
Cash collateral
 
 

 
16,330

 
4,046

 
18,691

Net Assets/Liabilities from Risk Management Activities
 
 
$
4,401

 
$
(233,374
)
 
$
4,955

 
$

 
 

23



 
 
 
Regulated Distribution
 
Nonregulated
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2015
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$

 
$

 
$
11,680

 
$
(36,067
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 

 
126

 
(9,918
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 
(110,539
)
 

 

Total
 
 

 
(110,539
)
 
11,806

 
(45,985
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
378

 
(9,568
)
 
65,239

 
(65,780
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
368

 

 
14,318

 
(14,218
)
Total
 
 
746

 
(9,568
)
 
79,557

 
(79,998
)
Gross Financial Instruments
 
 
746

 
(120,107
)
 
91,363

 
(125,983
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 

 

 
(91,363
)
 
91,363

Net Financial Instruments
 
 
746

 
(120,107
)
 

 
(34,620
)
Cash collateral
 
 

 

 
8,854

 
34,620

Net Assets/Liabilities from Risk Management Activities
 
 
$
746

 
$
(120,107
)
 
$
8,854

 
$

 
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, 2016 and 2015 we recognized gains arising from fair value and cash flow hedge ineffectiveness of $13.6 million and $3.6 million. For the nine months ended June 30, 2016 and 2015 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $18.1 million and $(0.9) million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and nine months ended June 30, 2016 and 2015 is presented below.
 
Three Months Ended 
 June 30
 
2016
 
2015
 
(In thousands)
Commodity contracts
$
(22,146
)
 
$
(1,715
)
Fair value adjustment for natural gas inventory designated as the hedged item
35,630

 
5,350

Total decrease in purchased gas cost
$
13,484

 
$
3,635

The decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(684
)
 
$
599

Timing ineffectiveness
14,168

 
3,036

 
$
13,484

 
$
3,635


24



 
 
 
 
 
 
 
 
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
(In thousands)
Commodity contracts
$
(11,808
)
 
$
5,754

Fair value adjustment for natural gas inventory designated as the hedged item
29,852

 
(6,291
)
Total (increase) decrease in purchased gas cost
$
18,044

 
$
(537
)
The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
(1,490
)
 
$
908

Timing ineffectiveness
19,534

 
(1,445
)
 
$
18,044

 
$
(537
)
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.

Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three and nine months ended June 30, 2016 and 2015 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, 2016
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(12,347
)
 
$
(12,347
)
Gain arising from ineffective portion of commodity contracts

 
66

 
66

Total impact on purchased gas cost

 
(12,281
)
 
(12,281
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(137
)
 

 
(137
)
Total Impact from Cash Flow Hedges
$
(137
)
 
$
(12,281
)
 
$
(12,418
)
 
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
)

25



 
Nine Months Ended June 30, 2016
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$

 
$
(48,015
)
 
$
(48,015
)
Gain arising from ineffective portion of commodity contracts

 
84

 
84

Total impact on purchased gas cost

 
(47,931
)
 
(47,931
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(410
)
 

 
(410
)
Total Impact from Cash Flow Hedges
$
(410
)
 
$
(47,931
)
 
$
(48,341
)
 
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
)
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, 2016 and 2015. 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
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$
(39,337
)
 
$
54,388

 
$
(88,345
)
 
$
(30,436
)
Forward commodity contracts
10,573

 
1,505

 
(8,612
)
 
(37,397
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
87

 
87

 
260

 
455

Forward commodity contracts
7,532

 
10,058

 
29,290

 
17,826

Total other comprehensive income (loss) from hedging, net of tax(1)
$
(21,145
)
 
$
66,038

 
$
(67,407
)
 
$
(49,552
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.

26




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 losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of June 30, 2016. 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
$
(372
)
 
$
(4,992
)
 
$
(5,364
)
Thereafter
(18,018
)
 
233

 
(17,785
)
Total(1) 
$
(18,390
)
 
$
(4,759
)
 
$
(23,149
)
 
(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, 2016 and 2015 was a decrease in purchased gas cost of $1.9 million and $3.7 million. For the nine months ended June 30, 2016 and 2015 purchased gas cost (increased) decreased by $(2.8) million and $13.2 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.
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, 2015. During the nine months ended June 30, 2016, 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, 2015.
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, 2016 and September 30, 2015. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

27



 
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, 2016
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
4,401

 
$

 
$

 
$
4,401

Nonregulated segment

 
52,119

 

 
(47,164
)
 
4,955

Total financial instruments

 
56,520

 

 
(47,164
)
 
9,356

Hedged portion of gas stored underground
97,860

 

 

 

 
97,860

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
1,358

 

 

 
1,358

Registered investment companies
39,068

 

 

 

 
39,068

Bonds

 
31,319

 

 

 
31,319

Total available-for-sale securities
39,068

 
32,677

 

 

 
71,745

Total assets
$
136,928

 
$
89,197

 
$

 
$
(47,164
)
 
$
178,961

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
249,704

 
$

 
$
(16,330
)
 
$
233,374

Nonregulated segment

 
69,901

 

 
(69,901
)
 

Total liabilities
$

 
$
319,605

 
$

 
$
(86,231
)
 
$
233,374

 
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, 2015
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
746

 
$

 
$

 
$
746

Nonregulated segment

 
91,363

 

 
(82,509
)
 
8,854

Total financial instruments

 
92,109

 

 
(82,509
)
 
9,600

Hedged portion of gas stored underground
43,901

 

 

 

 
43,901

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds

 
1,072

 

 

 
1,072

Registered investment companies
40,619

 

 

 

 
40,619

Bonds

 
32,509

 

 

 
32,509

Total available-for-sale securities
40,619

 
33,581

 

 

 
74,200

Total assets
$
84,520

 
$
125,690

 
$

 
$
(82,509
)
 
$
127,701

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$

 
$
120,107

 
$

 
$

 
$
120,107

Nonregulated segment

 
125,983

 

 
(125,983
)
 

Total liabilities
$

 
$
246,090

 
$

 
$
(125,983
)
 
$
120,107

 
(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.

28



(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, 2016, we had $16.3 million of cash held in margin accounts to collateralize certain regulated distribution financial instruments, which were used to offset current and noncurrent risk management liabilities. As of June 30, 2016, we also had $22.7 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $18.7 million was used to offset current and noncurrent risk management liabilities under master netting arrangements with the remaining $4.0 million 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, 2015, we had $43.5 million of cash held in margin accounts to collateralize certain nonregulated financial instruments. Of this amount, $34.6 million was used to offset current and noncurrent risk management liabilities under master netting arrangements with the remaining $8.9 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, 2016
 
 
 
 
 
 
 
Domestic equity mutual funds
$
28,377

 
$
5,549

 
$
(962
)
 
$
32,964

Foreign equity mutual funds
5,357

 
747

 

 
6,104

Bonds
31,147

 
175

 
(3
)
 
31,319

Money market funds
1,358

 

 

 
1,358

 
$
66,239

 
$
6,471

 
$
(965
)
 
$
71,745

As of September 30, 2015
 
 
 
 
 
 
 
Domestic equity mutual funds
$
27,643

 
$
7,332

 
$
(456
)
 
$
34,519

Foreign equity mutual funds
5,261

 
905

 
(66
)
 
6,100

Bonds
32,423

 
106

 
(20
)
 
32,509

Money market funds
1,072

 

 

 
1,072

 
$
66,399

 
$
8,343

 
$
(542
)
 
$
74,200

At June 30, 2016 and September 30, 2015, our available-for-sale securities included $40.4 million and $41.7 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At June 30, 2016, we maintained investments in bonds that have contractual maturity dates ranging from July 2016 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, 2016 and September 30, 2015:
 
June 30, 2016
 
September 30, 2015
 
(In thousands)
Carrying Amount
$
2,460,000

 
$
2,460,000

Fair Value
$
2,858,540

 
$
2,669,323



29



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, 2015. During the nine months ended June 30, 2016, 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, 2016 and the related condensed consolidated statements of income and comprehensive income for the three and nine-month periods ended June 30, 2016 and 2015 and the condensed consolidated statements of cash flows for the nine-month periods ended June 30, 2016 and 2015. 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, 2015, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and we expressed an unqualified audit opinion on those consolidated financial statements in our report dated November 6, 2015. In our opinion, the accompanying condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2015, is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived.
/s/    ERNST & YOUNG LLP
Dallas, Texas
August 3, 2016

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, 2015.
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 and capital 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 commodity price volatility, counterparty creditworthiness or performance and interest rate risk; 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 regulated distribution business; increased costs of providing health care benefits along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain appropriate personnel; 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 climate changes or related additional legislation or regulation in the future; the inherent hazards and risks involved in operating our distribution and pipeline and storage businesses; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; 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 natural gas distribution and transmission 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, 2016 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 transmission 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, 2015 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, 2016.
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.
During the first nine months of fiscal 2016, we earned $315.9 million, or $3.06 per diluted share, an eight percent increase period over period. Regulated operations generated 88 and 95 percent of our consolidated net income for the three and nine months ended June 30, 2016. 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
 
2016
 
2015
 
Change
 
(In thousands, except per share data)
Regulated operations
$
62,986

 
$
51,032

 
$
11,954

Nonregulated operations
8,207

 
5,249

 
2,958

Net income
$
71,193

 
$
56,281

 
$
14,912

 
 
 
 
 
 
Diluted EPS from regulated operations
$
0.61

 
$
0.50

 
$
0.11

Diluted EPS from nonregulated operations
0.08

 
0.05

 
0.03

Consolidated diluted EPS
$
0.69

 
$
0.55

 
$
0.14



33



 
Nine Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, except per share data)
Regulated operations
$
301,324

 
$
273,989

 
$
27,335

Nonregulated operations
14,540

 
17,571

 
(3,031
)
Net income
$
315,864

 
$
291,560

 
$
24,304

 
 
 
 
 
 
Diluted EPS from regulated operations
$
2.92

 
$
2.69

 
$
0.23

Diluted EPS from nonregulated operations
0.14

 
0.17

 
(0.03
)
Consolidated diluted EPS
$
3.06

 
$
2.86

 
$
0.20


Positive rate outcomes achieved in our regulated businesses offset the effect of weather that was 25 percent warmer than the prior-year period. As of June 30, 2016, we had completed 16 regulatory proceedings resulting in an increase in annual operating income of $104.4 million and had five ratemaking efforts in progress seeking $24.5 million of additional annual operating income. Our nonregulated results in the current-year period reflect larger losses on the settlement of financial positions during a period of falling gas prices.
Capital expenditures for the first nine months of fiscal 2016 were $796.0 million. Approximately 83 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 $1 billion and $1.1 billion for fiscal 2016. We funded our capital expenditure program primarily through operating cash flows of $624.6 million, net short-term borrowings and the issuance of common stock. On March 28, 2016, we entered into an at-the-market (ATM) equity distribution agreement under which we may issue and sell, shares of our common stock, up to an aggregate offering price of $200 million. During the third fiscal quarter of 2016, we issued 1.4 million shares of common stock and received $98.7 million in net proceeds under the ATM program.
On May 13, 2016, Standard & Poor’s Corporation upgraded our senior unsecured debt rating to A from A- and upgraded our short-term debt rating to A-1 from A-2, with a ratings outlook of stable, citing strong financial performance largely due to our ability to timely recover capital investments.
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 7.7 percent for fiscal 2016.
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

34



our Texas and Mississippi service areas includes 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.

Three Months Ended June 30, 2016 compared with Three Months Ended June 30, 2015
Financial and operational highlights for our regulated distribution segment for the three months ended June 30, 2016 and 2015 are presented below.
 
Three Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
275,381

 
$
267,019

 
$
8,362

Operating expenses
212,152

 
210,219

 
1,933

Operating income
63,229

 
56,800

 
6,429

Miscellaneous income
1,111

 
1,045

 
66

Interest charges
18,968

 
19,961

 
(993
)
Income before income taxes
45,372

 
37,884

 
7,488

Income tax expense
15,516

 
15,420

 
96

Net income
$
29,856

 
$
22,464

 
$
7,392

Consolidated regulated distribution sales volumes — MMcf
34,983

 
36,126

 
(1,143
)
Consolidated regulated distribution transportation volumes — MMcf
30,416

 
30,134

 
282

Total consolidated regulated distribution throughput — MMcf
65,399

 
66,260

 
(861
)
Consolidated regulated distribution average cost of gas per Mcf sold
$
3.97

 
$
4.15

 
$
(0.18
)
Income for our regulated distribution segment increased 33 percent, primarily due to an $8.4 million increase in gross profit, partially offset with a $1.9 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:
a $6.5 million net increase in rate adjustments, primarily in our Mississippi, Louisiana, West Texas and Kentucky/Mid-States Divisions.
Customer growth, primarily in our Mid-Tex, Louisiana and Tennessee service areas, which contributed an incremental $1.5 million.
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 higher levels of system maintenance and higher depreciation expense associated with increased capital investments.
Net income for the three months ended June 30, 2016 includes a $1.6 million income tax benefit for equity awards that vested during the current-year quarter as a result of adopting the new stock-based accounting guidance.






35



The following table shows our operating income by regulated distribution division, in order of total rate base, for the three months ended June 30, 2016 and 2015. 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
 
2016
 
2015
 
Change
 
(In thousands)
Mid-Tex
$
33,818

 
$
33,473

 
$
345

Kentucky/Mid-States
6,955

 
10,104

 
(3,149
)
Louisiana
9,288

 
6,561

 
2,727

West Texas
5,709

 
5,018

 
691

Mississippi
3,959

 
1,546

 
2,413

Colorado-Kansas
3,152

 
1,872

 
1,280

Other
348

 
(1,774
)
 
2,122

Total
$
63,229

 
$
56,800

 
$
6,429


Nine Months Ended June 30, 2016 compared with Nine Months Ended June 30, 2015
Financial and operational highlights for our regulated distribution segment for the nine months ended June 30, 2016 and 2015 are presented below.
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Gross profit
$
1,017,984

 
$
997,066

 
$
20,918

Operating expenses
617,625

 
617,451

 
174

Operating income
400,359

 
379,615

 
20,744

Miscellaneous income (expense)
209

 
(1,221
)
 
1,430

Interest charges
58,390

 
60,914

 
(2,524
)
Income before income taxes
342,178

 
317,480

 
24,698

Income tax expense
124,755

 
121,776

 
2,979

Net income
$
217,423

 
$
195,704

 
$
21,719

Consolidated regulated distribution sales volumes — MMcf
215,632

 
265,503

 
(49,871
)
Consolidated regulated distribution transportation volumes — MMcf
103,304

 
107,205

 
(3,901
)
Total consolidated regulated distribution throughput — MMcf
318,936

 
372,708

 
(53,772
)
Consolidated regulated distribution average cost of gas per Mcf sold
$
4.10

 
$
5.26

 
$
(1.16
)
Income for our regulated distribution segment increased 11 percent, primarily due to a $20.9 million increase in gross profit. The year-over-year increase in gross profit primarily reflects:
a $37.2 million net increase in rate adjustments. Our Mid-Tex Division accounted for $16.3 million of this increase. We also experienced increases in our Mississippi and West Texas Divisions.
The impact of weather that was 25 percent warmer than the prior-year period, before adjusting for weather normalization mechanisms. Therefore, although sales volumes declined 19 percent, gross margin experienced just a $3.6 million decline from lower consumption. Warmer weather also contributed to a $2.5 million decrease in service and other revenues.
Customer growth, primarily in our Mid-Tex, Louisiana and Tennessee service areas, which contributed an incremental $4.9 million.
a $14.5 million decrease in revenue-related taxes primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $15.4 million decrease in the related tax expense.
Net income for the nine months ended June 30, 2016 includes a $4.9 million income tax benefit for equity awards that vested during the current-year period as a result of adopting the new stock-based accounting guidance.

36



The following table shows our operating income by regulated distribution division, in order of total rate base, for the nine months ended June 30, 2016 and 2015. 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
 
2016
 
2015
 
Change
 
(In thousands)
Mid-Tex
$
182,594

 
$
166,586

 
$
16,008

Kentucky/Mid-States
56,334

 
59,256

 
(2,922
)
Louisiana
48,082

 
47,380

 
702

West Texas
38,937

 
33,820

 
5,117

Mississippi
40,491

 
37,356

 
3,135

Colorado-Kansas
31,308

 
29,129

 
2,179

Other
2,613

 
6,088

 
(3,475
)
Total
$
400,359

 
$
379,615

 
$
20,744

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 2016, we completed 15 regulatory proceedings, resulting in a $63.7 million increase in annual operating income as summarized below:
Rate Action
 
Annual Increase to
Operating Income
 
 
(In thousands)
Annual formula rate mechanisms
 
$
59,414

Rate case filings
 
4,456

Other rate activity
 
(183
)
 
 
$
63,687

Additionally, the following ratemaking efforts seeking $24.5 million in annual operating income were in progress as of June 30, 2016:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income
Requested
 
 
 
 
 
 
(In thousands)
Kentucky/Mid-States
 
Rate Case (1)
 
Kentucky
 
$
5,531

Kentucky/Mid-States
 
Expedited Rate Filing(2)
 
Virginia
 
537

Louisiana
 
Formula Rate Mechanism(2)
 
Trans LA
 
6,216

Louisiana
 
Formula Rate Mechanism(2)
 
LGS
 
8,686

Mississippi
 
Infrastructure Mechanism
 
Mississippi
 
3,519

 
 
 
 
 
 
$
24,489


(1) 
The parties filed a unanimous settlement that, if accepted by the Kentucky Pubic Service Commission, will result in an increase to operating revenue of $2.7 million on August 15, 2016.
(2)
The proposed increase for Virginia and Louisiana customers was implemented on April 1, 2016 (Trans LA & Virginia) and July 1, 2016 (LGS), subject to refund.
Annual Formula Rate Mechanisms
As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual 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. We currently have formula rate mechanisms in our Louisiana, Mississippi and Tennessee operations and in substantially all of our Texas divisions. Additionally, we have specific

37



infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state.
 
 
Annual Formula Rate Mechanisms
State
 
Infrastructure Programs
 
Formula Rate Mechanisms
 
 
 
 
 
Colorado
 
System Safety and Integrity Rider (SSIR)
 
Kansas
 
Gas System Reliability Surcharge (GSRS)
 
Kentucky
 
Pipeline Replacement Program (PRP)
 
Louisiana
 
(1)
 
Rate Stabilization Clause (RSC)
Mississippi
 
System Integrity Rider (SIR)
 
Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee
 
 
Annual Rate Mechanism (ARM)
Texas
 
Gas Reliability Infrastructure Program (GRIP), (1)
 
Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia
 
Steps to Advance Virginia Energy (SAVE)
 

(1)  
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

The following annual formula rate mechanisms were approved during the nine months ended June 30, 2016.
Division
 
Jurisdiction
 
Test Year
Ended
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2016 Filings:
 
 
 
 
 
 
 
 
Kentucky/Mid-States
 
Tennessee
 
05/31/2017
 
$
4,888

 
06/01/2016
Mid-Tex
 
Mid-Tex Cities RRM
 
12/31/2015
 
25,816

 
06/01/2016
Mid-Tex
 
Mid-Tex DARR
 
09/30/2015
 
5,429

 
06/01/2016
Mid-Tex
 
Mid-Tex Environs
 
12/31/2015
 
1,325

 
05/03/2016
West Texas
 
West Texas Environs
 
12/31/2015
 
646

 
05/03/2016
West Texas
 
West Texas ALDC
 
12/31/2015
 
3,484

 
04/26/2016
Colorado-Kansas
 
Colorado
 
12/31/2016
 
764

 
01/01/2016
Mississippi
 
Mississippi-SRF (1)
 
10/31/2016
 
9,192

 
01/01/2016
Mississippi
 
Mississippi-SGR (2)
 
10/31/2016
 
250

 
12/01/2015
Kentucky/Mid-States
 
Kentucky-PRP
 
09/30/2016
 
3,786

 
10/01/2015
Kentucky/Mid-States
 
Virginia-SAVE
 
09/30/2016
 
118

 
10/01/2015
West Texas
 
West Texas Cities
 
09/30/2015
 
3,716

 
10/01/2015
Total 2016 Filings
 
 
 
 
 
$
59,414

 
 

(1) 
The commission issued a final order approving a $9.2 million increase in annual operating income on December 21, 2015 with an effective date of January 1, 2016.
(2) 
The Mississippi Supplemental Growth Rider permits the Company to pursue up to $5.0 million of eligible industrial growth projects beyond the Division’s normal main extension policies. This is the third year of the SGR program.

38



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 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, 2016.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Division
 
State
 
Increase in Annual
Operating Income
 
Effective
Date
 
 
(In thousands)
2016 Rate Case Filings:
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
$
2,372

 
03/17/2016
Colorado-Kansas
 
Colorado
 
2,084

 
01/01/2016
Total 2016 Rate Case Filings
 
 
 
$
4,456

 
 
Other Ratemaking Activity
The following table summarizes other ratemaking activity during the nine months ended June 30, 2016.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Division
 
Jurisdiction
 
Rate Activity
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2016 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad-Valorem (1)
 
$
(183
)
 
02/01/2016
Total 2016 Other Rate Activity
 
 
 
 
 
$
(183
)
 
 

(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 and stores natural gas for our Mid-Tex Division and third party local distribution companies and manages five underground storage facilities in Texas. We also provide interruptible transportation, storage and ancillary services to electric generation and industrial customers as well as producers, marketers and other shippers.
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 and storage 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 the volumes of gas transported for shippers through our pipeline system and the rates for such transportation.
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 transporter 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. Additionally, the Atmos Pipeline–Texas Division annually uses GRIP to recover capital costs incurred in the prior calendar year.


39



Three Months Ended June 30, 2016 compared with Three Months Ended June 30, 2015
Financial and operational highlights for our regulated pipeline segment for the three months ended June 30, 2016 and 2015 are presented below.
 
Three Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
83,503

 
$
71,989

 
$
11,514

Third-party transportation
22,715

 
22,724

 
(9
)
Storage and park and lend services
931

 
664

 
267

Other
2,100

 
1,631

 
469

Gross profit
109,249

 
97,008

 
12,241

Operating expenses
48,712

 
44,581

 
4,131

Operating income
60,537

 
52,427

 
8,110

Miscellaneous expense
(359
)
 
(211
)
 
(148
)
Interest charges
9,002

 
8,299

 
703

Income before income taxes
51,176

 
43,917

 
7,259

Income tax expense
18,046

 
15,349

 
2,697

Net income
$
33,130

 
$
28,568

 
$
4,562

Gross pipeline transportation volumes — MMcf
156,489

 
165,898

 
(9,409
)
Consolidated pipeline transportation volumes — MMcf
128,801

 
134,823

 
(6,022
)
Net income for our regulated pipeline segment increased 16 percent, primarily due to a $12.2 million increase in gross profit, offset by a $4.1 million increase in operating expenses. The increase in gross profit primarily reflects an $11.3 million increase in rates from the GRIP filings approved in fiscal 2015 and 2016.
Operating expenses increased $4.1 million, primarily due to increased levels of pipeline maintenance activities and higher depreciation expense associated with increased capital investments.
On May 3, 2016, a GRIP filing was approved by the Railroad Commission of Texas for $40.7 million of additional annual operating income, effective with bills rendered on and after May 3, 2016.


40



Nine Months Ended June 30, 2016 compared with Nine Months Ended June 30, 2015
Financial and operational highlights for our regulated pipeline segment for the nine months ended June 30, 2016 and 2015 are presented below.
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex transportation
$
224,662

 
$
192,734

 
$
31,928

Third-party transportation
63,597

 
71,203

 
(7,606
)
Storage and park and lend services
2,495

 
2,737

 
(242
)
Other
8,875

 
5,631

 
3,244

Gross profit
299,629

 
272,305

 
27,324

Operating expenses
141,189

 
125,270

 
15,919

Operating income
158,440

 
147,035

 
11,405

Miscellaneous expense
(1,164
)
 
(842
)
 
(322
)
Interest charges
27,294

 
25,014

 
2,280

Income before income taxes
129,982

 
121,179

 
8,803

Income tax expense
46,081

 
42,894

 
3,187

Net income
$
83,901

 
$
78,285

 
$
5,616

Gross pipeline transportation volumes — MMcf
520,233

 
567,906

 
(47,673
)
Consolidated pipeline transportation volumes — MMcf
373,000

 
381,828

 
(8,828
)

Net income for our regulated pipeline segment increased seven percent, primarily due to a $27.3 million increase in gross profit, partially offset by a $15.9 million increase in operating expenses. The increase in gross profit primarily reflects a $28.4 million increase in rates from the GRIP filings approved in fiscal 2015 and 2016 and a $3.6 million increase from the sale of excess retention gas. These increases were partially offset by a $4.0 million decrease in through-system volumes and lower storage and blending fees due to warmer weather in the current-year period compared to the prior-year period.
Operating expenses increased $15.9 million, primarily due to increased levels of pipeline maintenance activities to improve the safety and reliability of our system and increased property taxes and depreciation expense associated with increased capital investments.
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.
The level of borrowings under our credit facilities, which affects the level of interest expense recognized by this
segment.

41



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, 2016 compared with Three Months Ended June 30, 2015
Financial and operating highlights for our nonregulated segment for the three months ended June 30, 2016 and 2015 are presented below.
 
Three Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
8,899

 
$
10,648

 
$
(1,749
)
Storage and transportation services
3,616

 
3,607

 
9

Other
6,047

 
1,508

 
4,539

Total realized margins
18,562

 
15,763

 
2,799

Unrealized margins
4,252

 
2,016

 
2,236

Gross profit
22,814

 
17,779

 
5,035

Operating expenses
9,416

 
9,399

 
17

Operating income
13,398

 
8,380

 
5,018

Miscellaneous income
574

 
345

 
229

Interest charges
221

 
240

 
(19
)
Income before income taxes
13,751

 
8,485

 
5,266

Income tax expense
5,544

 
3,236

 
2,308

Net income
$
8,207

 
$
5,249

 
$
2,958

Gross nonregulated delivered gas sales volumes — MMcf
88,472

 
89,052

 
(580
)
Consolidated nonregulated delivered gas sales volumes — MMcf
76,798

 
75,929

 
869

Net physical position (Bcf)
30.6

 
22.1

 
8.5

 
The $5.0 million quarter-over-quarter increase in gross profit reflects a $2.8 million increase in realized margins, combined with a $2.2 million increase in unrealized margins. The following were the key drivers for the $2.8 million increase in realized margins:
Other realized margins increased $4.5 million. The increase primarily reflects larger settlement gains on short financial positions established during the first and second quarter of fiscal 2016.
Margins from gas delivery and related services margins decreased $1.7 million, primarily due to a decrease in per-unit margins from 12 cents to 10 cents per Mcf, primarily due to increased demand from low-margin power generation and marketing customers due to warmer weather.

Unrealized margins increased $2.2 million, primarily due to the period-over-period favorable movement of the physical mark on the fair value of natural gas inventory hedged positions.



42



Nine Months Ended June 30, 2016 compared with Nine Months Ended June 30, 2015
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands, unless otherwise noted)
Realized margins
 
 
 
 
 
Gas delivery and related services
$
37,454

 
$
39,280

 
$
(1,826
)
Storage and transportation services
10,143

 
10,273

 
(130
)
Other
(8,718
)
 
(1,322
)
 
(7,396
)
Total realized margins
38,879

 
48,231

 
(9,352
)
Unrealized margins
12,792

 
8,493

 
4,299

Gross profit
51,671

 
56,724

 
(5,053
)
Operating expenses
27,085

 
27,832

 
(747
)
Operating income
24,586

 
28,892

 
(4,306
)
Miscellaneous income
1,245

 
897

 
348

Interest charges
1,408

 
706

 
702

Income before income taxes
24,423

 
29,083

 
(4,660
)
Income tax expense
9,883

 
11,512

 
(1,629
)
Net income
$
14,540

 
$
17,571

 
$
(3,031
)
Gross nonregulated delivered gas sales volumes — MMcf
292,619

 
319,423

 
(26,804
)
Consolidated nonregulated delivered gas sales volumes — MMcf
257,733

 
272,260

 
(14,527
)
Net physical position (Bcf)
30.6

 
22.1

 
8.5


The $5.1 million year-over-year decrease in gross profit reflects a $9.4 million decrease in realized margins, partially offset by a $4.3 million increase in unrealized margins. The following were the key drivers for the $9.4 million decrease in realized margins:
Margins from gas delivery and related services decreased $1.8 million year-over-year. Consolidated sales volumes decreased five percent due to warmer weather. However, lower net transportation costs and other variable costs driven by fewer deliveries resulted in an increase in per-unit margins from 12 cents to 13 cents per Mcf, which partially offset the effect of reduced sales volumes.
Other realized margins decreased $7.4 million. The decrease primarily reflects higher realized losses incurred during the first six months of fiscal 2016 on the settlement of long financial positions during a period of falling prices. Additionally, storage fees rose primarily due to increased park and loan activity. The aforementioned settlement gains realized during the third quarter partially offset these period over period decreases.

Unrealized margins increased $4.3 million, primarily due to the period-over-period favorable movement of the physical mark on the fair value of natural gas inventory hedged positions.

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-capitalization ratio in a target range of 45 to 55 percent. We also evaluate the levels of committed borrowing capacity that we require. We currently have over $1 billion of capacity under 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 filed a registration statement with the SEC on March 28, 2016 to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which replaced our registration statement that expired on March 28, 2016. On March 28, 2016, we entered into an at-the-market (ATM) equity distribution agreement under which we may issue and sell, shares of our common stock, up to an aggregate offering price of

43



$200 million. The shares will be issued under our shelf registration statement. Proceeds from the ATM program will be used primarily to repay short-term debt outstanding under our $1.25 billion commercial paper program, to fund capital spending primarily to enhance the safety and reliability of our system and for general corporate purposes. During the third fiscal quarter of 2016, we issued 1.4 million shares of common stock and received $98.7 million in net proceeds under the ATM program. At June 30, 2016, $2.4 billion of securities remain available for issuance under the shelf registration statement.
The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2016September 30, 2015 and June 30, 2015:
 
 
June 30, 2016
 
September 30, 2015
 
June 30, 2015
 
(In thousands, except percentages)
Short-term debt
$
670,466

 
10.2
%
 
$
457,927

 
7.5
%
 
$
251,977

 
4.2
%
Long-term debt(1)
2,455,645

 
37.2
%
 
2,455,388

 
40.2
%
 
2,455,303

 
41.3
%
Shareholders’ equity
3,466,724

 
52.6
%
 
3,194,797

 
52.3
%
 
3,238,255

 
54.5
%
Total
$
6,592,835

 
100.0
%
 
$
6,108,112

 
100.0
%
 
$
5,945,535

 
100.0
%

(1) In June 2017, $250 million of long-term debt will mature. We plan to issue new senior notes to replace this maturing debt. We have executed forward starting interest rate swaps to effectively fix the Treasury yield component associated with this anticipated issuance at 3.37%.
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, 2016 and 2015 are presented below.
 
Nine Months Ended June 30
 
2016
 
2015
 
Change
 
(In thousands)
Total cash provided by (used in)
 
 
 
 
 
Operating activities
$
624,598

 
$
717,582

 
$
(92,984
)
Investing activities
(794,381
)
 
(668,602
)
 
(125,779
)
Financing activities
207,336

 
(48,085
)
 
255,421

Change in cash and cash equivalents
37,553

 
895

 
36,658

Cash and cash equivalents at beginning of period
28,653

 
42,258

 
(13,605
)
Cash and cash equivalents at end of period
$
66,206

 
$
43,153

 
$
23,053

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, 2016, we generated cash flow of $624.6 million from operating activities compared with $717.6 million for the nine months ended June 30, 2015. The $93.0 million decrease in operating cash flows primarily reflects the timing of deferred gas cost recoveries.
Cash flows from investing activities
In executing our regulatory strategy, we target our capital spending on regulatory mechanisms that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Substantially all of our regulated jurisdictions 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 our ongoing construction program, which enables us to enhance the safety and reliability of the systems used to provide regulated distribution services to our

44



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. Over the last three fiscal years, approximately 80 percent of our capital spending has been committed to improving the safety and reliability of our system. We anticipate our annual capital spending will be in the range of $1 billion to $1.4 billion through fiscal 2020.
For the nine months ended June 30, 2016, capital expenditures were $796.0 million, compared with $667.5 million in the prior-year period. The $128.5 million increase primarily reflects an 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 combined with a planned increase in spending in our regulated distribution operations.
Cash flows from financing activities
    
For the nine months ended June 30, 2016, our financing activities generated $207.3 million of cash compared with $48.1 million of cash used in the prior-year period. The $255.4 million increase of cash generated is primarily due to higher net short-term debt borrowings due to increased capital expenditures and period-over-period changes in working capital funding needs compared to the prior year, as well as proceeds received from the issuance of common stock under our ATM program in the third fiscal quarter of 2016.
The following table summarizes our share issuances for the nine months ended June 30, 2016 and 2015.
 
Nine Months Ended 
 June 30
 
2016
 
2015
Shares issued:
 
 
 
Direct Stock Purchase Plan
107,736

 
137,049

1998 Long-Term Incentive Plan
597,470

 
664,074

Retirement Savings Plan and Trust
282,578

 
296,067

At-the-Market (ATM) Equity Sales Program
1,360,756

 

Total shares issued
2,348,540

 
1,097,190


The year-over-year increase in the number of shares issued primarily reflects shares issued under the ATM Program. For the nine months ended June 30, 2016, we did not cancel and retire any shares attributable to federal income tax withholdings on equity awards. For the nine months ended June 30, 2015, we canceled and retired 148,464 such shares.

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, 2016, the amount available to us under our credit facilities, net of commercial paper and outstanding letters of credit, was $0.6 billion.
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.

45



Our debt is rated by three rating agencies: Standard & Poor’s Corporation (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch). On May 13, 2016, S&P upgraded our senior unsecured debt rating to A from A- and upgraded our short-term debt rating to A-1 from A-2, with a ratings outlook of stable, citing strong financial performance largely due to our ability to timely recover capital investments. As of June 30, 2016, all three rating agencies maintained a stable 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
Short-term debt
A-1
  
P-1
  
F-2
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, 2016. 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 8 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, 2016.

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.
The following table shows the components of the change in fair value of our regulated distribution segment’s financial instruments for the three and nine months ended June 30, 2016 and 2015:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Fair value of contracts at beginning of period
$
(187,864
)
 
$
(137,710
)
 
$
(119,361
)
 
$
14,284

Contracts realized/settled
(107
)
 
(48
)
 
(20,865
)
 
(33,859
)
Fair value of new contracts
2,377

 
1,514

 
2,434

 
1,365

Other changes in value
(59,709
)
 
85,993

 
(107,511
)
 
(32,041
)
Fair value of contracts at end of period
(245,303
)
 
(50,251
)
 
(245,303
)
 
(50,251
)
Netting of cash collateral
16,330

 

 
16,330

 

Cash collateral and fair value of contracts at period end
$
(228,973
)
 
$
(50,251
)
 
$
(228,973
)
 
$
(50,251
)

46



The fair value of our regulated distribution segment’s financial instruments at June 30, 2016 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2016
 
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
$
(61,922
)
 
$
(183,381
)
 
$

 
$

 
$
(245,303
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(61,922
)
 
$
(183,381
)
 
$

 
$

 
$
(245,303
)

The following table shows the components of the change in fair value of our nonregulated segment’s financial instruments for the three and nine months ended June 30, 2016 and 2015:
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Fair value of contracts at beginning of period
$
(16,085
)
 
$
(36,140
)
 
$
(34,620
)
 
$
(3,033
)
Contracts realized/settled
1,303

 
11,502

 
22,050

 
23,013

Fair value of new contracts

 

 

 

Other changes in value
(3,000
)
 
4,121

 
(5,212
)
 
(40,497
)
Fair value of contracts at end of period
(17,782
)
 
(20,517
)
 
(17,782
)
 
(20,517
)
Netting of cash collateral
22,737

 
31,323

 
22,737

 
31,323

Cash collateral and fair value of contracts at period end
$
4,955

 
$
10,806

 
$
4,955

 
$
10,806


The fair value of our nonregulated segment’s financial instruments at June 30, 2016 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2016
 
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
$
(18,691
)
 
$
621

 
$
288

 
$

 
$
(17,782
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(18,691
)
 
$
621

 
$
288

 
$

 
$
(17,782
)
Pension and Postretirement Benefits Obligations
For the nine months ended June 30, 2016 and 2015, our total net periodic pension and other benefits costs were $34.5 million and $44.2 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 2016 net periodic pension cost is approximately 20 percent lower than in fiscal 2015. The decrease is attributable to the net impact of changes in the various assumptions used to establish those costs as of September 30, 2015, our most recent measurement date. The most significant changes include:
An increase in the discount rate from 4.43 percent to 4.55 percent
A decrease in the expected return on plan assets from 7.25 percent to 7.00 percent
Utilization of updated mortality tables issued in October 2015 by the Society of Actuaries
The amount with which we fund our defined benefit plan is determined in accordance with the Pension Protection Act of 2006 (PPA) and are influenced by the funded position of the plan when the funding requirements are determined on January 1 of each year. Based upon the determination as of January 1, 2015, we are not required to make a minimum contribution to our

47



defined benefit plan during fiscal 2016. However, we made a voluntary contribution of $15.0 million during the third quarter of fiscal 2016.
For the nine months ended June 30, 2016 we contributed $12.8 million to our postretirement medical plans. We anticipate contributing between $15 million and $25 million to our postretirement plans during fiscal 2016.
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.


48




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, 2016 and 2015.
Regulated Distribution Sales and Statistical Data
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
2016
 
2015
METERS IN SERVICE, end of period
 
 
 
 
 
 
 
Residential
2,903,099

 
2,872,584

 
2,903,099

 
2,872,584

Commercial
266,435

 
262,353

 
266,435

 
262,353

Industrial
1,463

 
1,518

 
1,463

 
1,518

Public authority and other
8,377

 
8,419

 
8,377

 
8,419

Total meters
3,179,374

 
3,144,874

 
3,179,374

 
3,144,874

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
51.3

 
42.6

 
51.3

 
42.6

SALES VOLUMES — MMcf(1)
 
 
 
 
 
 
 
Gas sales volumes
 
 
 
 
 
 
 
Residential
16,407

 
16,667

 
125,334

 
159,067

Commercial
14,718

 
15,216

 
73,990

 
87,852

Industrial
2,671

 
2,925

 
10,586

 
11,713

Public authority and other
1,187

 
1,318

 
5,722

 
6,871

Total gas sales volumes
34,983

 
36,126

 
215,632

 
265,503

Transportation volumes
33,367

 
33,743

 
112,477

 
117,019

Total throughput
68,350

 
69,869

 
328,109

 
382,522

OPERATING REVENUES (000’s)(1)
 
 
 
 
 
 
 
Gas sales revenues
 
 
 
 
 
 
 
Residential
$
260,634

 
$
253,033

 
$
1,240,184

 
$
1,538,771

Commercial
113,075

 
114,942

 
507,580

 
666,220

Industrial
9,456

 
13,089

 
41,309

 
62,694

Public authority and other
7,309

 
8,465

 
34,402

 
46,355

Total gas sales revenues
390,474

 
389,529

 
1,823,475

 
2,314,040

Transportation revenues
18,097

 
16,506

 
60,202

 
57,635

Other gas revenues
5,655

 
10,759

 
18,836

 
22,504

Total operating revenues
$
414,226

 
$
416,794

 
$
1,902,513

 
$
2,394,179

Average cost of gas per Mcf sold
$
3.97

 
$
4.15

 
$
4.10

 
$
5.26

See footnote following these tables.


49



Regulated Pipeline and Nonregulated Operations Sales and Statistical Data
 
Three Months Ended 
 June 30
 
Nine Months Ended 
 June 30
 
2016
 
2015
 
2016
 
2015
CUSTOMERS, end of period
 
 
 
 
 
 
 
Industrial
767

 
750

 
767

 
750

Municipal
133

 
129

 
133

 
129

Other
518

 
516

 
518

 
516

Total
1,418

 
1,395

 
1,418

 
1,395

NONREGULATED INVENTORY STORAGE
 
 
 
 
 
 
 
BALANCE — Bcf
40.9

 
28.2

 
40.9

 
28.2

REGULATED PIPELINE VOLUMES — MMcf(1)
156,489

 
165,898

 
520,233

 
567,906

NONREGULATED DELIVERED GAS SALES
 
 
 
 
 
 
 
VOLUMES — MMcf(1)
88,472

 
89,052

 
292,619

 
319,423

OPERATING REVENUES (000’s)(1)
 
 
 
 
 
 
 
Regulated pipeline
$
109,249

 
$
97,008

 
$
299,629

 
$
272,305

Nonregulated
214,555

 
278,769

 
774,474

 
1,179,379

Total operating revenues
$
323,804

 
$
375,777

 
$
1,074,103

 
$
1,451,684

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, 2015. During the nine months ended June 30, 2016, 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, 2016 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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


50



PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
During the nine months ended June 30, 2016, 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, 2015. 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.

51



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 3, 2016

52



EXHIBITS INDEX
Item 6
 
Exhibit
Number
  
Description
Page Number or
Incorporation by
Reference to
10
  
Equity Distribution Agreement, dated as of March 28, 2016, among Atmos Energy Corporation, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Morgan Stanley & Co. LLC.
Exhibit 1.1 to Form 8-K dated March 28, 2016 (File No. 1-10042)
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.

53