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 March 31, 2018
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
 
Emerging growth company ¨
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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 April 27, 2018.
Class
  
Shares Outstanding
No Par Value
  
111,064,659



GLOSSARY OF KEY TERMS
 
 
 
Adjusted diluted EPS from continuing operations
Non-GAAP measure defined as diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit
Adjusted income from continuing operations
Non-GAAP measure defined as income from continuing operations before the one-time, non-cash income tax benefit
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated other comprehensive income
ARM
Annual Rate Mechanism
Bcf
Billion cubic feet
Contribution Margin
Non-GAAP measure defined as operating revenues less purchased gas cost
DARR
Dallas Annual Rate Review
ERISA
Employee Retirement Income Security Act of 1974
FASB
Financial Accounting Standards Board
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
GSRS
Gas System Reliability Surcharge
Mcf
Thousand cubic feet
MMcf
Million cubic feet
Moody’s
Moody’s Investors Services, Inc.
NTSB
National Transportation Safety Board
PPA
Pension Protection Act of 2006
PRP
Pipeline Replacement Program
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
RSC
Rate Stabilization Clause
S&P
Standard & Poor’s Corporation
SAVE
Steps to Advance Virginia Energy
SEC
United States Securities and Exchange Commission
SGR
Supplemental Growth Filing
SIR
System Integrity Rider
SRF
Stable Rate Filing
SSIR
System Safety and Integrity Rider
TCJA
Tax Cuts and Jobs Act of 2017
WNA
Weather Normalization Adjustment

2


PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS 
 
March 31,
2018
 
September 30,
2017
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
11,903,715

 
$
11,301,304

Less accumulated depreciation and amortization
2,142,386

 
2,042,122

Net property, plant and equipment
9,761,329

 
9,259,182

Current assets
 
 
 
Cash and cash equivalents
71,074

 
26,409

Accounts receivable, net
407,134

 
222,263

Gas stored underground
89,265

 
184,653

Other current assets
55,263

 
106,321

Total current assets
622,736

 
539,646

Goodwill
730,132

 
730,132

Deferred charges and other assets
242,125

 
220,636

 
$
11,356,322

 
$
10,749,596

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: March 31, 2018 — 111,060,328 shares; September 30, 2017 — 106,104,634 shares
$
555

 
$
531

Additional paid-in capital
2,951,545

 
2,536,365

Accumulated other comprehensive loss
(85,011
)
 
(105,254
)
Retained earnings
1,854,257

 
1,467,024

Shareholders’ equity
4,721,346

 
3,898,666

Long-term debt
2,617,892

 
3,067,045

Total capitalization
7,339,238

 
6,965,711

Current liabilities
 
 
 
Accounts payable and accrued liabilities
230,823

 
233,050

Other current liabilities
538,702

 
332,648

Short-term debt
129,602

 
447,745

Current maturities of long-term debt
450,000

 
—

Total current liabilities
1,349,127

 
1,013,443

Deferred income taxes
1,107,036

 
1,878,699

Regulatory excess deferred taxes (See Note 6)
737,798

 
—

Regulatory cost of removal obligation
484,746

 
485,420

Pension and postretirement liabilities
237,448

 
230,588

Deferred credits and other liabilities
100,929

 
175,735

 
$
11,356,322

 
$
10,749,596

See accompanying notes to condensed consolidated financial statements.

3


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 March 31
 
2018
 
2017
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
1,199,291

 
$
962,541

Pipeline and storage segment
120,955

 
111,972

Intersegment eliminations
(100,837
)
 
(86,327
)
Total operating revenues
1,219,409

 
988,186

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
727,053

 
513,096

Pipeline and storage segment
433

 
725

Intersegment eliminations
(100,526
)
 
(86,327
)
Total purchased gas cost
626,960

 
427,494

Operation and maintenance expense
161,073

 
132,239

Depreciation and amortization expense
89,381

 
77,667

Taxes, other than income
73,007

 
65,614

Operating income
268,988

 
285,172

Miscellaneous (expense) income
(253
)
 
833

Interest charges
27,304

 
26,944

Income from continuing operations before income taxes
241,431

 
259,061

Income tax expense
62,439

 
97,049

Income from continuing operations
178,992

 
162,012

Gain on sale of discontinued operations, net of tax ($0 and $10,215)
—

 
2,716

Net income
$
178,992

 
$
164,728

Basic and diluted net income per share
 
 
 
Income per share from continuing operations
$
1.60

 
$
1.52

Income per share from discontinued operations
—

 
0.03

Net income per share - basic and diluted
$
1.60

 
$
1.55

Cash dividends per share
$
0.485

 
$
0.450

Basic and diluted weighted average shares outstanding
111,706

 
105,935

See accompanying notes to condensed consolidated financial statements.

4


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
 
 
 
 
Six Months Ended 
 March 31
 
2018
 
2017
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
2,060,083

 
$
1,717,197

Pipeline and storage segment
247,418

 
221,924

Intersegment eliminations
(198,900
)
 
(170,767
)
Total operating revenues
2,108,601

 
1,768,354

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
1,190,811

 
908,442

Pipeline and storage segment
1,345

 
1,080

Intersegment eliminations
(198,279
)
 
(170,723
)
Total purchased gas cost
993,877

 
738,799

Operation and maintenance expense
290,640

 
257,177

Depreciation and amortization expense
177,755

 
154,625

Taxes, other than income
135,780

 
122,663

Operating income
510,549

 
495,090

Miscellaneous expense
(2,288
)
 
(161
)
Interest charges
58,813

 
57,974

Income from continuing operations before income taxes
449,448

 
436,955

Income tax (benefit) expense
(43,676
)
 
160,905

Income from continuing operations
493,124

 
276,050

Income from discontinued operations, net of tax ($0 and $6,841)
—

 
10,994

Gain on sale of discontinued operations, net of tax ($0 and $10,215)
—

 
2,716

Net Income
$
493,124

 
$
289,760

Basic and diluted net income per share
 
 
 
Income per share from continuing operations
$
4.47

 
$
2.61

Income per share from discontinued operations
—

 
0.13

Net income per share - basic and diluted
$
4.47

 
$
2.74

Cash dividends per share
$
0.97

 
$
0.90

Basic and diluted weighted average shares outstanding
110,135

 
105,610

See accompanying notes to condensed consolidated financial statements.

5



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017
 
2018
 
2017
 
(Unaudited)
(In thousands)
Net income
$
178,992

 
$
164,728

 
$
493,124

 
$
289,760

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $(276), $879, $(338) and $403
(939
)
 
1,530

 
(1,046
)
 
702

Cash flow hedges:
 
 
 
 
 
 
 
Amortization and unrealized gain on interest rate agreements, net of tax of $6,575, $2,432, $6,026 and $54,861
22,244

 
4,230

 
21,289

 
95,444

Net unrealized gains on commodity cash flow hedges, net of tax of $0, $0, $0 and $3,183
—

 
—

 
—

 
4,982

Total other comprehensive income
21,305

 
5,760

 
20,243

 
101,128

Total comprehensive income
$
200,297

 
$
170,488

 
$
513,367

 
$
390,888


See accompanying notes to condensed consolidated financial statements.

6


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Six Months Ended 
 March 31
 
2018
 
2017
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
493,124

 
$
289,760

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
177,755

 
154,810

Deferred income taxes
116,023

 
148,657

One-time income tax benefit
(165,675
)
 
—

Gain on sale of discontinued operations
—

 
(12,931
)
Discontinued cash flow hedging for natural gas marketing commodity contracts
—

 
(10,579
)
Other
12,252

 
10,391

Net assets / liabilities from risk management activities
812

 
26,757

Net change in operating assets and liabilities
117,076

 
(54,862
)
Net cash provided by operating activities
751,367

 
552,003

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(693,978
)
 
(559,385
)
Acquisition
—

 
(85,714
)
Proceeds from the sale of discontinued operations
3,000

 
133,560

Available-for-sale securities activities, net
(1,175
)
 
(8,918
)
Other, net
4,009

 
3,787

Net cash used in investing activities
(688,144
)
 
(516,670
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(318,143
)
 
(159,204
)
Net proceeds from equity offering
395,092

 
49,400

Issuance of common stock through stock purchase and employee retirement plans
11,902

 
16,984

Proceeds from issuance of long-term debt
—

 
125,000

Interest rate agreements cash collateral
—

 
25,670

Cash dividends paid
(105,891
)
 
(95,314
)
Other
(1,518
)
 
—

Net cash used in financing activities
(18,558
)
 
(37,464
)
Net increase (decrease) in cash and cash equivalents
44,665

 
(2,131
)
Cash and cash equivalents at beginning of period
26,409

 
47,534

Cash and cash equivalents at end of period
$
71,074

 
$
45,403


See accompanying notes to condensed consolidated financial statements.

7


ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
March 31, 2018
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) is engaged in the regulated natural gas distribution and pipeline and storage businesses. Our distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our regulated divisions and subsidiaries operate.
Our distribution business delivers natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at March 31, 2018, covered service areas located in eight states.
Our pipeline and storage business, which is also subject to federal and state regulations, includes the transportation of natural gas to our Texas and Louisiana distribution systems and the management of our underground storage facilities used to support our distribution business in various states.

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, 2017. 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, 2017. Because of seasonal and other factors, the results of operations for the six-month period ended March 31, 2018 are not indicative of our results of operations for the full 2018 fiscal year, which ends September 30, 2018.
Except for the filed formula rate mechanisms as discussed in Note 9, 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, 2017.
During the second quarter of fiscal 2018, we completed our annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit. 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, an entity 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 may need to use more judgment and make more estimates than under current guidance. The new guidance will become effective for us 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 March 31, 2018, we had substantially completed the evaluation of our sources of revenue and the impact that the new guidance will have on our financial position, results of operations, cash flows and business processes. Based on this evaluation, we currently do not believe the implementation of the new guidance will have a material effect on our financial position, results of operations, cash flows or business processes. We expect to apply the new guidance using the modified retrospective method on the date of adoption. We are currently still evaluating the impact on our financial statement presentation and related disclosures.
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 on our financial position, results of operations and cash flows.

8


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. Additionally, in January 2018, the FASB issued amendments to the standard that provides a practical expedient for entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations and cash flows.
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 on our financial position, results of operations and cash flows. 
In January 2017, the FASB issued new guidance that simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The new standard will be effective for our fiscal 2021 goodwill impairment test; however, early adoption is permitted for goodwill impairment tests performed on testing dates after January 1, 2017. We early adopted the new standard, effective for our goodwill impairment test performed in our second fiscal quarter of 2018. The new standard did not have a material impact on our results of operations, consolidated balance sheets or cash flows. 
In March 2017, the FASB issued new guidance related to the income statement presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit cost from the other components and present it with other current compensation costs for related employees in the statement of income. The other components of net benefit cost will be presented outside of income from operations on the statement of income. In addition, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). The Federal Energy Regulatory Commission (“FERC”), which regulates interstate transmission pipelines and also establishes, through its Uniform System of Accounts, accounting practices of rate-regulated entities, has issued guidance that states it will permit an election to either continue to capitalize non-service benefit costs or to cease capitalizing such costs for regulatory purposes.  Accounting guidelines by the FERC are typically also upheld by state commissions.  As such, we plan to continue to capitalize all components of net periodic benefit cost for ratemaking purposes and will defer the non-service cost components as a regulatory asset for U.S. GAAP reporting purposes. The new guidance will be effective for us in the fiscal year beginning on October 1, 2018 and for interim periods within that year.  The standard requires retrospective application of the amendment related to the presentation of non-service cost components outside of income from operations in the statement of income and prospective application of the change in eligible costs for capitalization. We do not anticipate the new standard will have a material impact on our financial position, results of operations and cash flows.
In February 2018, the FASB issued new guidance as a result of the Tax Cuts and Jobs Act of 2017 (the "TCJA"), related to the treatment of certain tax effects from accumulated other comprehensive income. The new guidance allows entities to reclassify from accumulated other comprehensive income to retained earnings the stranded tax effects resulting from the adoption of the TCJA. The new guidance will be effective for us in the fiscal year beginning on October 1, 2019 and for interim periods within that year. Early adoption is permitted, including adoption in any interim period for public business entities for reporting periods for which financial statements have not yet been issued and should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. We are currently evaluating the impact of this new guidance on our financial results and disclosures.
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.

9


Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and a portion 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 our regulatory excess deferred taxes and regulatory cost of removal obligation is reported separately.
Significant regulatory assets and liabilities as of March 31, 2018 and September 30, 2017 included the following:
 
March 31,
2018
 
September 30,
2017
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
20,918

 
$
26,826

Infrastructure mechanisms(2)
65,286

 
46,437

Deferred gas costs
—

 
65,714

Recoverable loss on reacquired debt
9,954

 
11,208

Deferred pipeline record collection costs
14,646

 
11,692

APT annual adjustment mechanism
—

 
2,160

Rate case costs
3,016

 
2,629

Other
8,064

 
10,132

 
$
121,884

 
$
176,798

Regulatory liabilities:
 
 
 
Regulatory excess deferred taxes(3)
$
737,798

 
$
—

Regulatory cost of service reserve(4)
29,042

 
—

Regulatory cost of removal obligation
526,483

 
521,330

Deferred gas costs
167,036

 
15,559

Asset retirement obligation
12,827

 
12,827

APT annual adjustment mechanism
5,081

 
—

Other
14,740

 
5,941

 
$
1,493,007

 
$
555,657

 
(1)
Includes $7.8 million and $9.4 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2)
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.
(3)
The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. The excess deferred taxes will be returned to utility customers in accordance with regulatory requirements. See Note 6 for further information.
(4)
Effective January 1, 2018, regulators in each of our service areas required us to establish a regulatory liability for the difference in recoverable federal taxes included in revenues based on the former 35% federal statutory rate and the new 21% federal statutory rate for service provided on or after January 1, 2018. This liability will be returned to utility customers in accordance with regulatory requirements. See Note 6 for further information.

3.    Segment Information

 We manage and review our consolidated operations through the following reportable segments:

•
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.
•
The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.
•
The natural gas marketing segment was comprised of our discontinued natural gas marketing business.

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 distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.

10



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, 2017. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.
Income statements and capital expenditures for the three and six months ended March 31, 2018 and 2017 by segment are presented in the following tables:
 
Three Months Ended March 31, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,198,309

 
$
21,100

 
$
—

 
$
1,219,409

Intersegment revenues
982

 
99,855

 
(100,837
)
 
—

Total operating revenues
1,199,291

 
120,955

 
(100,837
)
 
1,219,409

Purchased gas cost
727,053

 
433

 
(100,526
)
 
626,960

Operation and maintenance expense
131,991

 
29,393

 
(311
)
 
161,073

Depreciation and amortization expense
65,649

 
23,732

 
—

 
89,381

Taxes, other than income
64,692

 
8,315

 
—

 
73,007

Operating income
209,906

 
59,082

 
—

 
268,988

Miscellaneous income (expense)
393

 
(646
)
 
—

 
(253
)
Interest charges
16,898

 
10,406

 
—

 
27,304

Income before income taxes
193,401

 
48,030

 
—

 
241,431

Income tax expense
48,158

 
14,281

 
—

 
62,439

Net income
$
145,243

 
$
33,749

 
$
—

 
$
178,992

Capital expenditures
$
224,235

 
$
86,505

 
$
—

 
$
310,740



11


 
Three Months Ended March 31, 2017
 
Distribution
 
Pipeline and Storage
 
Natural Gas Marketing
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
962,217

 
$
25,969

 
$
—

 
$
—

 
$
988,186

Intersegment revenues
324

 
86,003

 
—

 
(86,327
)
 
—

Total operating revenues
962,541

 
111,972

 
—

 
(86,327
)
 
988,186

Purchased gas cost
513,096

 
725

 
—

 
(86,327
)
 
427,494

Operation and maintenance expense
103,703

 
28,536

 
—

 
—

 
132,239

Depreciation and amortization expense
61,302

 
16,365

 
—

 
—

 
77,667

Taxes, other than income
57,636

 
7,978

 
—

 
—

 
65,614

Operating income
226,804

 
58,368

 
—

 
—

 
285,172

Miscellaneous income (expense)
1,029

 
(196
)
 
—

 
—

 
833

Interest charges
16,925

 
10,019

 
—

 
—

 
26,944

Income from continuing operations before income taxes
210,908

 
48,153

 
—

 
—

 
259,061

Income tax expense
79,763

 
17,286

 
—

 
—

 
97,049

Income from continuing operations
131,145

 
30,867

 
—

 
—

 
162,012

Gain on sale of discontinued operations, net of tax
—

 
—

 
2,716

 
—

 
2,716

Net income
$
131,145

 
$
30,867

 
$
2,716

 
$
—

 
$
164,728

Capital expenditures
$
208,185

 
$
53,238

 
$
—

 
$
—

 
$
261,423


 
Six Months Ended March 31, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,058,762

 
$
49,839

 
$
—

 
$
2,108,601

Intersegment revenues
1,321

 
197,579

 
(198,900
)
 
—

Total operating revenues
2,060,083

 
247,418

 
(198,900
)
 
2,108,601

Purchased gas cost
1,190,811

 
1,345

 
(198,279
)
 
993,877

Operation and maintenance expense
235,728

 
55,533

 
(621
)
 
290,640

Depreciation and amortization expense
131,083

 
46,672

 
—

 
177,755

Taxes, other than income
119,799

 
15,981

 
—

 
135,780

Operating income
382,662

 
127,887

 
—

 
510,549

Miscellaneous expense
(1,007
)
 
(1,281
)
 
—

 
(2,288
)
Interest charges
38,266

 
20,547

 
—

 
58,813

Income before income taxes
343,389

 
106,059

 
—

 
449,448

Income tax (benefit) expense
(50,953
)
 
7,277

 
—

 
(43,676
)
Net income
$
394,342

 
$
98,782

 
$
—

 
$
493,124

Capital expenditures
$
465,484

 
$
228,494

 
$
—

 
$
693,978



12


 
Six Months Ended March 31, 2017
 
Distribution
 
Pipeline and Storage
 
Natural Gas Marketing
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
1,716,483

 
$
51,871

 
$
—

 
$
—

 
$
1,768,354

Intersegment revenues
714

 
170,053

 
—

 
(170,767
)
 
—

Total operating revenues
1,717,197

 
221,924

 
—

 
(170,767
)
 
1,768,354

Purchased gas cost
908,442

 
1,080

 
—

 
(170,723
)
 
738,799

Operation and maintenance expense
196,417

 
60,804

 
—

 
(44
)
 
257,177

Depreciation and amortization expense
122,459

 
32,166

 
—

 
—

 
154,625

Taxes, other than income
108,182

 
14,481

 
—

 
—

 
122,663

Operating income
381,697

 
113,393

 
—

 
—

 
495,090

Miscellaneous income (expense)
396

 
(557
)
 
—

 
—

 
(161
)
Interest charges
38,043

 
19,931

 
—

 
—

 
57,974

Income from continuing operations before income taxes
344,050

 
92,905

 
—

 
—

 
436,955

Income tax expense
127,541

 
33,364

 
—

 
—

 
160,905

Income from continuing operations
216,509

 
59,541

 
—

 
—

 
276,050

Income from discontinued operations, net of tax
—

 
—

 
10,994

 
—

 
10,994

Gain on sale of discontinued operations, net of tax
—

 
—

 
2,716

 
—

 
2,716

Net income
$
216,509

 
$
59,541

 
$
13,710

 
$
—

 
$
289,760

Capital expenditures
$
430,669

 
$
128,716

 
$
—

 
$
—

 
$
559,385

 

Balance sheet information at March 31, 2018 and September 30, 2017 by segment is presented in the following tables:
 
March 31, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
7,202,673

 
$
2,558,656

 
$
—

 
$
9,761,329

Total assets
$
10,723,398

 
$
2,779,330

 
$
(2,146,406
)
 
$
11,356,322

 
September 30, 2017
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
6,849,517

 
$
2,409,665

 
$
—

 
$
9,259,182

Total assets
$
10,050,164

 
$
2,621,601

 
$
(1,922,169
)
 
$
10,749,596



13


4.    Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three and six months ended March 31, 2018 and 2017 are calculated as follows:

 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017
 
2018
 
2017
 
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share from continuing operations
 
 
 
 
 
 
 
Income from continuing operations
$
178,992

 
$
162,012

 
$
493,124

 
$
276,050

Less: Income from continuing operations allocated to participating securities
161

 
193

 
459

 
348

Income from continuing operations available to common shareholders
$
178,831

 
$
161,819

 
$
492,665

 
$
275,702

Basic and diluted weighted average shares outstanding
111,706

 
105,935

 
110,135

 
105,610

Income from continuing operations per share — Basic and Diluted
$
1.60

 
$
1.52

 
$
4.47

 
$
2.61

 
 
 
 
 
 
 
 
Basic and Diluted Earnings Per Share from discontinued operations
 
 
 
 
 
 
 
Income from discontinued operations
$
—

 
$
2,716

 
$
—

 
$
13,710

Less: Income from discontinued operations allocated to participating securities
—

 
2

 
—

 
15

Income from discontinued operations available to common shareholders
$
—

 
$
2,714

 
$
—

 
$
13,695

Basic and diluted weighted average shares outstanding
111,706

 
105,935

 
110,135

 
105,610

Income from discontinued operations per share — Basic and Diluted
$
—

 
$
0.03

 
$
—

 
$
0.13

Net income per share — Basic and Diluted
$
1.60

 
$
1.55

 
$
4.47

 
$
2.74




14


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, 2017. There were no material changes in the terms of our debt instruments during the six months ended March 31, 2018.
Long-term debt at March 31, 2018 and September 30, 2017 consisted of the following:
 
 
March 31, 2018
 
September 30, 2017
 
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019
$
450,000

 
$
450,000

Unsecured 3.00% Senior Notes, due 2027
500,000

 
500,000

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
750,000

 
750,000

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

Floating-rate term loan, due September 2019(1)
125,000

 
125,000

Total long-term debt
3,085,000

 
3,085,000

Less:
 
 
 
Original issue premium / discount on unsecured senior notes and debentures
(4,412
)
 
(4,384
)
Debt issuance cost
21,520

 
22,339

Current maturities
450,000

 
—

 
$
2,617,892

 
$
3,067,045

    
(1)
Up to $200 million can be drawn under this term loan.
    
We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. 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.
Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility. On March 26, 2018, we executed one of our two one-year extension options which extended the maturity date from September 25, 2021 to September 25, 2022. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At March 31, 2018 and September 30, 2017, a total of $129.6 million and $447.7 million was outstanding under our commercial paper program.
Additionally, we have a $25 million 364-day unsecured facility, which was renewed effective April 1, 2018 and expires March 31, 2019, and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At March 31, 2018, there were no borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total amount available to us under our $10 million facility to $4.4 million.
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At March 31, 2018, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 41 percent. In addition, both

15


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.
These credit facilities and our public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. We were in compliance with all of our debt covenants as of March 31, 2018. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
6.    Impact of the Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. The TCJA introduced several significant changes to corporate income tax laws in the United States. The most significant change that affects Atmos Energy is the reduction of the federal statutory income tax rate from 35% to 21%. As a rate-regulated entity, the accelerated capital expensing and the limitation on interest deductibility provisions included in the TCJA are not applicable to us.
Under generally accepted accounting principles, we use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
At September 30, 2017, we measured our net deferred tax liability using the enacted federal statutory tax rate of 35%. The enactment of the TCJA on December 22, 2017 required us to remeasure our deferred tax assets and liabilities, including our U.S. federal income tax net operating loss carryforwards, at the newly enacted federal statutory income tax rate. As the Company’s fiscal year end is September 30, the Internal Revenue Code requires the Company to use a blended statutory federal corporate income tax rate of 24.5% for fiscal 2018.
The decrease in the federal statutory income tax rate reduced our net deferred tax liability by $903.5 million. Of this amount, $737.8 million relates to regulated operations and has been recorded as a regulatory liability, which will be returned to utility customers. The period and timing of these revenue adjustments are subject to Internal Revenue Code provisions and regulatory actions in each of the eight states in which we operate. The remaining $165.7 million has been reflected as a one-time income tax benefit in our condensed consolidated statement of income for the six months ended March 31, 2018, because these taxes were not considered in our cost of service ratemaking. During the three months ended March 31, 2018, we refined the calculations performed to remeasure the Company's net deferred tax liabilities, which resulted in the recognition of a $3.8 million income tax benefit.
At March 31, 2018, we had $274.7 million of remeasured federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset future taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards that do not expire and are expected to be fully refunded to us between 2019 and 2022 as a result of changes introduced by the TCJA. These credit carryforwards are now reflected as taxes receivable within the deferred charges and other assets line item on our condensed consolidated balance sheet. In addition, the Company has $5.2 million in remeasured charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expire between 2018 and 2023.
The Company also has $21.5 million of state net operating loss carryforwards and $1.5 million of state tax credit carryforwards (net of $5.7 million and $0.4 million of remeasured federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire between 2018 and 2032.
Due to the changes introduced by the TCJA, we now believe it is more likely than not that the benefit from certain charitable contribution carryforwards for which a valuation allowance was previously established will be realized. As a result, we reduced our valuation allowance by $4.2 million during the first quarter. This amount is included in the $165.7 million one-time income tax benefit.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allows us to record provisional amounts during a one-year measurement period, similar to the measurement period in accounting for business combinations. The Company has determined a reasonable estimate for the measurement and accounting for certain effects of the TCJA, including the remeasurement of our net deferred tax liabilities and the establishment of a regulatory liability, which have been reflected as provisional amounts in the March 31, 2018 condensed consolidated financial statements and are described in further detail above. The amounts represent our best estimates based upon records, information and current guidance. We are still analyzing certain aspects of the TCJA, refining our calculations and expecting additional guidance relating to the TCJA from the U.S.

16


Department of the Treasury and the Internal Revenue Service.  Any additional guidance issued or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the TCJA.
We are actively working with our regulators in each jurisdiction to address the impact of the TCJA on our cost of service based rates. Accounting orders have been issued for all our service areas that required us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35% statutory income tax rate and the new 21% statutory income tax rate. The establishment of this regulatory liability relating to our cost of service rates resulted in a reduction to our revenues beginning in the second quarter of fiscal 2018. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.
During the fiscal 2018 second quarter, we received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in our Colorado, Kansas, Kentucky and Texas service areas. The return to customers of regulatory liabilities recorded for differences in our cost of service rates due to the change in the federal statutory income tax rate and the excess deferred taxes created upon implementation of the TCJA will be addressed in future regulatory proceedings. We are still working with regulators in Louisiana, Mississippi, Tennessee and Virginia to reflect the effects of the TCJA in our cost of service in rates.

7.    Shareholders' Equity

Shelf Registration, At-the-Market Equity Sales Program and Equity Issuance
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 expires March 28, 2019. At March 31, 2018, approximately $1.2 billion of securities remained available for issuance under the shelf registration statement.
On November 14, 2017, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million, which expires March 28, 2019. During the six months ended March 31, 2018, no shares of common stock were sold under the ATM program.
On November 30, 2017, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common stock. We received aggregate gross proceeds of $400 million and received net proceeds, after expenses, of $395.1 million from the offering.

Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate cash flow hedges and prior to the sale of Atmos Energy Marketing, LLC (AEM) on January 3, 2017, 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):
 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2017
$
7,048

 
$
(112,302
)
 
$
(105,254
)
Other comprehensive income (loss) before reclassifications
(167
)
 
20,454

 
20,287

Amounts reclassified from accumulated other comprehensive income
(879
)
 
835

 
(44
)
Net current-period other comprehensive income (loss)
(1,046
)
 
21,289

 
20,243

March 31, 2018
$
6,002

 
$
(91,013
)
 
$
(85,011
)
 

17


 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2016
$
4,484

 
$
(187,524
)
 
$
(4,982
)
 
$
(188,022
)
Other comprehensive income before reclassifications
634

 
95,271

 
9,847

 
105,752

Amounts reclassified from accumulated other comprehensive income
68

 
173

 
(4,865
)
 
(4,624
)
Net current-period other comprehensive income
702

 
95,444

 
4,982

 
101,128

March 31, 2017
$
5,186

 
$
(92,080
)
 
$
—

 
$
(86,894
)

The following tables detail reclassifications out of AOCI for the three and six months ended March 31, 2018 and 2017. Amounts in parentheses below indicate decreases to net income in the statement of income:
 
Three Months Ended March 31, 2018
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
1,139

 
Operation and maintenance expense
 
1,139

 
Total before tax
 
(260
)
 
Tax expense
 
$
879

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(593
)
 
Interest charges
 
(593
)
 
Total before tax
 
135

 
Tax benefit
 
$
(458
)
 
Net of tax
Total reclassifications
$
421

 
Net of tax
 
Three Months Ended March 31, 2017
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
$
(107
)
 
Operation and maintenance expense
 
(107
)
 
Total before tax
 
39

 
Tax benefit
 
$
(68
)
 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(136
)
 
Interest charges
 
(136
)
 
Total before tax
 
50

 
Tax benefit
 
$
(86
)
 
Net of tax
Total reclassifications
$
(154
)
 
Net of tax

18


 
Six Months Ended March 31, 2018
Accumulated Other Comprehensive Income Components                          
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in  the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
1,139

 
Operation and maintenance expense
 
1,139

 
Total before tax
 
(260
)
 
Tax expense
 
$
879

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(1,187
)
 
Interest charges
 
(1,187
)
 
Total before tax
 
352

 
Tax benefit
 
$
(835
)
 
Net of tax
Total reclassifications
$
44

 
Net of tax
 
Six Months Ended March 31, 2017
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
$
(107
)
 
Operation and maintenance expense
 
(107
)
 
Total before tax
 
39

 
Tax benefit
 
$
(68
)
 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(273
)
 
Interest charges
Commodity contracts
7,967

 
Purchased gas cost(1)
 
7,694

 
Total before tax
 
(3,002
)
 
Tax expense
 
$
4,692

 
Net of tax
Total reclassifications
$
4,624

 
Net of tax
(1)
Amount is presented as part of income from discontinued operations in the condensed consolidated statement of income.
8.     Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three and six months ended March 31, 2018 and 2017 are presented in the following tables. Most of these costs are recoverable through our tariff rates; however, a portion of these costs is capitalized into our rate base. The remaining costs are recorded as a component of operation and maintenance expense. In the second quarter of fiscal 2018, due to the retirement of certain executives, we recognized a settlement loss of $2.4 million associated with our Supplemental Executive Retirement Plan and revalued the net periodic pension cost for the remainder of fiscal 2018. The revaluation of the net periodic pension cost for our Supplemental Executive Retirement Plan resulted in an increase in the discount rate, effective March 1, 2018, to 4.12%, which will increase our net periodic pension cost by approximately $0.1 million for the remainder of the fiscal year.

19


 
Three Months Ended March 31
 
Pension Benefits
 
Other Benefits
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,575

 
$
5,217

 
$
3,019

 
$
3,109

Interest cost
6,433

 
6,297

 
2,727

 
2,670

Expected return on assets
(6,916
)
 
(6,994
)
 
(2,001
)
 
(1,797
)
Amortization of prior service cost (credit)
(58
)
 
(58
)
 
3

 
(411
)
Amortization of actuarial (gain) loss
3,085

 
4,249

 
(1,619
)
 
(707
)
Settlements
2,415

 
—

 
—

 
—

Net periodic pension cost
$
9,534

 
$
8,711

 
$
2,129

 
$
2,864

 
Six Months Ended March 31
 
Pension Benefits
 
Other Benefits
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
9,135

 
$
10,433

 
$
6,039

 
$
6,218

Interest cost
12,863

 
12,594

 
5,454

 
5,340

Expected return on assets
(13,833
)
 
(13,988
)
 
(4,003
)
 
(3,593
)
Amortization of prior service cost (credit)
(116
)
 
(116
)
 
6

 
(822
)
Amortization of actuarial (gain) loss
6,174

 
8,498

 
(3,237
)
 
(1,414
)
Settlements
2,415

 
—

 
—

 
—

Net periodic pension cost
$
16,638

 
$
17,421

 
$
4,259

 
$
5,729


The assumptions used to develop our net periodic pension cost for the three and six months ended March 31, 2018 and 2017 are as follows:
 
 
Supplemental Executive Retirement Plan
 
Pension Benefits
 
Other Benefits
 
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
Discount rate
 
4.12%
 
3.73%
 
3.89%
 
3.73%
 
3.89%
 
3.73%
Rate of compensation increase
 
3.50%
 
3.50%
 
3.50%
 
3.50%
 
N/A
 
N/A
Expected return on plan assets
 
N/A
 
N/A
 
6.75%
 
7.00%
 
4.29%
 
4.45%
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, 2017. Based on that determination, we are not required to make a minimum contribution to our defined benefit plan during fiscal 2018; however, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.
We contributed $7.5 million to our other post-retirement benefit plans during the six months ended March 31, 2018. We expect to contribute a total of between $10 million and $20 million to these plans during fiscal 2018.
9.    Commitments and Contingencies
Litigation and Environmental Matters
In the normal course of business, we are subject to various legal and regulatory proceedings. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts, our historical experience, and our estimates of the ultimate outcome or resolution of the liability in the future. While the outcome of these proceedings is uncertain and a loss in excess of the amount we have accrued is possible though not reasonably estimable, it is the opinion of management that any amounts exceeding the accruals will not have a material adverse impact on our financial position, results of operations, or cash flows.

20


We maintain liability insurance for various risks associated with the operation of our natural gas pipelines and facilities, including for property damage and bodily injury. These liability insurance policies generally require us to be responsible for the first $1.0 million (self-insured retention) of each incident.
The National Transportation Safety Board (NTSB) is investigating an incident that occurred at a Dallas, Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. Together with the Railroad Commission of Texas and the Pipeline and Hazardous Materials Safety Administration, Atmos Energy is a party to the investigation and in that capacity is working closely with the NTSB to help determine the cause of this incident.
On March 29, 2018, a civil action was filed in Dallas, Texas against Atmos Energy in response to the February 23rd incident. The plaintiffs seek over $1.0 million in damages for, among with others, wrongful death and personal injury.
We are a party to various other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
Our distribution divisions maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our 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 hubs. At March 31, 2018, we were committed to purchase 55.0 Bcf within one year and 64.7 Bcf within two to three years under indexed contracts.
Regulatory Matters
Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations.  Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.
As of March 31, 2018, formula rate mechanisms were pending regulatory approval in our Louisiana and Tennessee service areas, infrastructure mechanisms were pending regulatory approval in our Mid-Tex, Mississippi and West Texas service areas as well as the Atmos Pipeline–Texas Division and rate cases were pending regulatory approval in our Colorado and Kentucky service areas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. On April 3, 2018, we filed formula rate mechanisms in our Mid-Tex and West Texas service areas, seeking increases in operating income. Additionally, as discussed in further detail in Note 6, all jurisdictions are addressing impacts of the TCJA.
10.    Financial Instruments
We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the six months ended March 31, 2018, there were no material 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.

Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.

21


We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2017-2018 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 26 percent, or 15.0 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Interest Rate Risk Management Activities
We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
As of March 31, 2018, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.78%, which we designated as a cash flow hedge at the time the swaps were executed. As of March 31, 2018, we had $49.1 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 March 31, 2018, 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 March 31, 2018, we had 6,251 MMcf of net short commodity contracts outstanding. These contracts have not been designated as hedges.
Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments as of March 31, 2018 and September 30, 2017. 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 our counterparties.
 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
March 31, 2018
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate contracts
Other current assets /
Other current liabilities
 
$
—

 
$
(85,948
)
Total
 
 
—

 
(85,948
)
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
602

 
(996
)
Total
 
 
602

 
(996
)
Gross Financial Instruments
 
 
602

 
(86,944
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
Contract netting
 
 
—

 
—

Net Financial Instruments
 
 
602

 
(86,944
)
Cash collateral
 
 
—

 
—

Net Assets/Liabilities from Risk Management Activities
 
 
$
602

 
$
(86,944
)
 

22


 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2017
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
$
—

 
$
(112,076
)
Total
 
 
—

 
(112,076
)
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
2,436

 
(322
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
803

 
—

Total
 
 
3,239

 
(322
)
Gross Financial Instruments
 
 
3,239

 
(112,398
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
Contract netting
 
 
—

 
—

Net Financial Instruments
 
 
3,239

 
(112,398
)
Cash collateral
 
 
—

 
—

Net Assets/Liabilities from Risk Management Activities
 
 
$
3,239

 
$
(112,398
)
 
Impact of Financial Instruments on the Income Statement
Cash Flow Hedges
As discussed above, our distribution segment has interest rate swap agreements, which we designated as a cash flow hedge at the time the swaps were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of income for the three months ended March 31, 2018 and 2017 was $0.6 million and $0.1 million and for the six months ended March 31, 2018 and 2017 was $1.2 million and $0.3 million.
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 six months ended March 31, 2018 and 2017. 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 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017 (1)
 
2018
 
2017 (1)
 
(In thousands)
Increase in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$
21,786

 
$
4,144

 
$
20,454

 
$
95,271

Forward commodity contracts(2)
—

 
—

 
—

 
9,847

Recognition of (gains) losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
458

 
86

 
835

 
173

Forward commodity contracts(2)
—

 
—

 
—

 
(4,865
)
Total other comprehensive income from hedging, net of tax
$
22,244

 
$
4,230

 
$
21,289

 
$
100,426

 
(1)
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction for the three and six-month period ended March 31, 2017.
(2)
Due to the sale of AEM, these amounts are included in income from discontinued operations.

23


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. The following amounts, net of deferred taxes, represent the expected recognition in earnings, as of March 31, 2018, of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments at the date of settlement. 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
 
(In thousands)
Next twelve months
$
(1,833
)
Thereafter
(47,281
)
Total
$
(49,114
)
 
Financial Instruments Not Designated as Hedges
As discussed above, financial instruments used in our distribution segment are not designated as hedges. However, there is no earnings impact on our 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.
11.    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, 2017. During the six months ended March 31, 2018, 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 7 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017.
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 March 31, 2018 and September 30, 2017. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

24


 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral
 
March 31, 2018
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$
—

 
$
602

 
$
—

 
$
—

 
$
602

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Registered investment companies
39,783

 
—

 
—

 
—

 
39,783

Bond mutual funds
16,308

 
—

 
—

 
—

 
16,308

Bonds
—

 
31,137

 
—

 
—

 
31,137

Money market funds
—

 
6,437

 
—

 
—

 
6,437

Total available-for-sale securities
56,091

 
37,574

 
—

 
—

 
93,665

Total assets
$
56,091

 
$
38,176

 
$
—

 
$
—

 
$
94,267

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$
—

 
$
86,944

 
$
—

 
$
—

 
$
86,944



 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral
 
September 30, 2017
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$
—

 
$
3,239

 
$
—

 
$
—

 
$
3,239

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Registered investment companies
41,097

 
—

 
—

 
—

 
41,097

Bond mutual funds
16,371

 
—

 
—

 
—

 
16,371

Bonds
—

 
29,104

 
—

 
—

 
29,104

Money market funds
—

 
1,837

 
—

 
—

 
1,837

Total available-for-sale securities
57,468

 
30,941

 
—

 
—

 
88,409

Total assets
$
57,468

 
$
34,180

 
$
—

 
$
—

 
$
91,648

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$
—

 
$
112,398

 
$
—

 
$
—

 
$
112,398

 
(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.


25



Available-for-sale securities are comprised of the following:
 
Amortized
Cost
 
Gross
Unrealized
Gain
 
Gross
Unrealized
Loss
 
Fair
Value
 
(In thousands)
As of March 31, 2018
 
 
 
 
 
 
 
Domestic equity mutual funds
$
25,515

 
$
8,194

 
$
(95
)
 
$
33,614

Foreign equity mutual funds
4,138

 
2,031

 
—

 
6,169

Bond mutual funds
16,548

 
—

 
(240
)
 
16,308

Bonds
31,295

 
4

 
(162
)
 
31,137

Money market funds
6,437

 
—

 
—

 
6,437

 
$
83,933

 
$
10,229

 
$
(497
)
 
$
93,665

As of September 30, 2017
 
 
 
 
 
 
 
Domestic equity mutual funds
$
25,361

 
$
8,920

 
$
—

 
$
34,281

Foreign equity mutual funds
4,581

 
2,235

 
—

 
6,816

Bond mutual funds
16,391

 
2

 
(22
)
 
16,371

Bonds
29,074

 
46

 
(16
)
 
29,104

Money market funds
1,837

 
—

 
—

 
1,837

 
$
77,244

 
$
11,203

 
$
(38
)
 
$
88,409

At March 31, 2018 and September 30, 2017, our available-for-sale securities included $46.2 million and $42.9 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At March 31, 2018, we maintained investments in bonds that have contractual maturity dates ranging from April 2018 through January 2021.
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 March 31, 2018 and September 30, 2017:
 
March 31, 2018
 
September 30, 2017
 
(In thousands)
Carrying Amount
$
3,085,000

 
$
3,085,000

Fair Value
$
3,291,629

 
$
3,382,272


12.    Concentration of Credit Risk
Information regarding our concentration of credit risk is disclosed in Note 16 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the six months ended March 31, 2018, there were no material changes in our concentration of credit risk.
13. Discontinued Operations
On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all of the equity interests of Atmos Energy Marketing, LLC (AEM). The transaction closed on January 3, 2017, with an effective date of January 1, 2017. CES paid a cash purchase price of $38.3 million plus working capital of $109.0 million for total cash consideration of $147.3 million. Of

26


this amount, $7.0 million was placed into escrow and was to be paid to the Company within 24 months of the closing date, net of any indemnification claims agreed upon between the two companies. In January 2018, $3.0 million of this escrowed amount was released and received by the Company. We recognized a net gain of $0.03 per diluted share on the sale in the second quarter of fiscal 2017 and completed the working capital true–up during the third quarter of fiscal 2017.
The operating results of our natural gas marketing reportable segment have been reported on the condensed consolidated statement of income as income from discontinued operations, net of income tax, for the six months ended March 31, 2017.  Accordingly, expenses related to allocable general corporate overhead and interest expense are not included in these results. 
The tables below set forth selected financial information related to discontinued operations. Operating expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income. At March 31, 2018 and September 30, 2017 we did not have any assets or liabilities held for sale. As AEM was sold effective January 1, 2017, no operating results are reported on the condensed consolidated statement of income as discontinued operations for the three months ended March 31, 2017. During the three months ended March 31, 2017, we recorded a gain on sale from discontinued operations for $2.7 million, net of tax of $10.2 million.
The following table presents statement of income data related to discontinued operations:
 
 
Six Months Ended 
 March 31, 2017
 
(In thousands)
Operating revenues
$
303,474

Purchased gas cost
277,554

Operating expenses
7,874

Operating income
18,046

Other nonoperating expense
(211
)
Income from discontinued operations before income taxes
17,835

Income tax expense
6,841

Income from discontinued operations
10,994

Gain on sale from discontinued operations, net of tax ($10,215)
2,716

Net income from discontinued operations
$
13,710

The following table presents statement of cash flow data related to discontinued operations:
 
Six Months Ended 
 March 31, 2017
 
(In thousands)
Depreciation and amortization expense
$
185

Capital expenditures
$
—

Non-cash loss in commodity contract cash flow hedges
$
(8,165
)

Natural Gas Marketing Commodity Risk Management Activities
Our discontinued natural gas marketing segment was 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. Through December 31, 2016, we managed 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. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.
Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax gain of $10.6 million, which is included in income from discontinued operations on the condensed consolidated statement of income for the six months ended March 31, 2017.
The Company's other risk management activities are discussed in Note 10.
Impact of Financial Instruments on the Income Statement

27


Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas cost, which is included in discontinued operations on the condensed consolidated statements of income, and primarily results from differences in the location and timing of the derivative instrument and the hedged item. For the six months ended March 31, 2017, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.4 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 Fair Value Hedges
The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item on the results of discontinued operations on our condensed consolidated income statement for the six months ended March 31, 2017 is presented below.
 
Six Months Ended 
 March 31, 2017
 
(In thousands)
Commodity contracts
$
(9,567
)
Fair value adjustment for natural gas inventory designated as the hedged item
12,858

Total decrease in purchased gas cost reflected in income from discontinued operations
$
3,291

The decrease in purchased gas cost reflected in income from discontinued operations is comprised of the following:
 
Basis ineffectiveness
$
(597
)
Timing ineffectiveness
3,888

 
$
3,291

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.
Cash Flow Hedges
The impact of our natural gas marketing segment cash flow hedges on our condensed consolidated income statements for the six months ended March 31, 2017 is presented below:
 
Six Months Ended 
 March 31, 2017
 
(In thousands)

Loss reclassified from AOCI for effective portion of natural gas marketing commodity contracts
$
(2,612
)
Gain arising from ineffective portion of natural gas marketing commodity contracts
111

Gain on discontinuance of cash flow hedging of natural gas marketing commodity contracts reclassified from AOCI
10,579

Total impact on purchased gas cost reflected in income from discontinued operations
$
8,078

Financial Instruments Not Designated as Hedges
The impact of the natural gas marketing segment's financial instruments that had not been designated as hedges on our condensed consolidated income statements for the six months ended March 31, 2017 was a decrease in purchased gas cost of $6.8 million, which is included in discontinued operations on the condensed consolidated statements of income.

28


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 as of March 31, 2018 and the related condensed consolidated statements of income and comprehensive income for the three and six month periods ended March 31, 2018 and 2017 and the condensed consolidated statements of cash flows for the six month periods ended March 31, 2018 and 2017. 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 as of September 30, 2017, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 13, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2017, 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
May 2, 2018

29


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, 2017.
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 execute our business strategy; 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; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our 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 operational, technical and managerial 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 change or related additional legislation or regulation in the future; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information; 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 in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at March 31, 2018 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

We manage and review our consolidated operations through the following reportable segments:

•
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.
•
The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.
•
The natural gas marketing segment was comprised of our discontinued natural gas marketing business.

30


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, 2017 and include the following:
•
Regulation
•
Unbilled revenue
•
Pension and other postretirement plans
•
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 six months ended March 31, 2018.

Non-GAAP Financial Measures
Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe contribution margin, a non-GAAP financial measure, defined as operating revenues less purchased gas cost, is a more useful and relevant measure to analyze our financial performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference contribution margin rather than operating revenues and purchased gas cost individually. Further, the term contribution margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.
As described further in Note 6, the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a one-time, non-cash income tax benefit of $165.7 million for the six months ended March 31, 2018. During the three months ended March 31, 2018, we recognized a $3.8 million benefit after we refined the initial measurement calculations performed during the first quarter. Due to the non-recurring nature of this benefit, we believe that income from continuing operations and diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit provide a more relevant measure to analyze our financial performance than income from continuing operations and consolidated diluted earnings per share from continuing operations. Accordingly, the following discussion and analysis of our financial performance will reference adjusted income from continuing operations and diluted earnings per share, which is calculated as follows:
 
Three Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, except per share data)
Income from continuing operations
$
178,992

 
$
162,012

 
$
16,980

TCJA non-cash income tax benefit
3,791

 
—

 
3,791

Adjusted income from continuing operations
$
175,201

 
$
162,012

 
$
13,189

 
 
 
 
 
 
Consolidated diluted EPS from continuing operations
$
1.60

 
$
1.52

 
$
0.08

Diluted EPS from TCJA non-cash income tax benefit
0.03

 
—

 
0.03

Adjusted diluted EPS from continuing operations
$
1.57

 
$
1.52

 
$
0.05



31


 
Six Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, except per share data)
Income from continuing operations
$
493,124

 
$
276,050

 
$
217,074

TCJA non-cash income tax benefit
165,675

 
—

 
165,675

Adjusted income from continuing operations
$
327,449

 
$
276,050

 
$
51,399

 
 
 
 
 
 
Consolidated diluted EPS from continuing operations
$
4.47

 
$
2.61

 
$
1.86

Diluted EPS from TCJA non-cash income tax benefit
1.50

 
—

 
1.50

Adjusted diluted EPS from continuing operations
$
2.97

 
$
2.61

 
$
0.36

RESULTS OF OPERATIONS

Executive Summary
Atmos Energy strives to operate our businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires significant levels of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.
During the six months ended March 31, 2018, we recorded income from continuing operations of $493.1 million, or $4.47 per diluted share, compared to income from continuing operations of $276.1 million, or $2.61 per diluted share for the six months ended March 31, 2017.
After adjusting for the nonrecurring benefit recognized after implementing the TCJA, we recorded adjusted income from continuing operations of $327.4 million, or $2.97 per diluted share for the six months ended March 31, 2018, compared to adjusted income from continuing operations of $276.1 million, or $2.61 per diluted share for the six months ended March 31, 2017. The period-over-period increase of $51.3 million, or 19 percent, largely reflects positive rate outcomes, weather that was 33 percent colder than the prior year, customer growth in our distribution business and the impact of the TCJA on our effective income tax rate, partially offset by reduced revenues as a result of implementing the TCJA. During the six months ended March 31, 2018, we completed ten regulatory proceedings, resulting in an increase in annual operating income of $47.4 million and had ten ratemaking efforts in progress at March 31, 2018 seeking a total increase in annual operating income of $65.3 million. On April 3, 2018, we filed formula rate mechanisms in our Mid-Tex and West Texas service areas, seeking increases in operating income of $28.0 million and $4.0 million.
Capital expenditures for the first six months of fiscal 2018 were $694.0 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to approximate $1.4 billion for fiscal 2018. We funded our capital expenditures program primarily through operating cash flows of $751.4 million. Additionally, we issued $400 million of common stock during the six months ended March 31, 2018. The net proceeds from the issuance were primarily used to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes.
As a result of our sustained financial performance, improved cash flows and capital structure, our Board of Directors increased the quarterly dividend by 7.8 percent for fiscal 2018.
TCJA Impact
The TCJA introduced several significant changes to corporate income tax laws in the United States, which have been reflected in our condensed consolidated financial statements for the period ended March 31, 2018. As a rate regulated entity, the effects of lower tax rates included in our cost of service rates will ultimately flow through to our utility customers in the form of adjusted rates. Therefore, the favorable impact of the reduction in our federal statutory income tax rate on our financial performance will be limited to items that impact our income before income taxes in the current period that have not yet been reflected in our rates (most notably increases to and decreases in commission-approved regulatory assets and liabilities recorded on our condensed consolidated balance sheet) and market-based revenues that are earned from customers who utilize our assets. Note 6 to the condensed consolidated financial statements details the various impacts of the TCJA on our financial position and results from operations. The most significant changes are summarized as follows:

32


•
Because our fiscal year started on October 1, 2017, our federal statutory income tax rate for fiscal 2018 was reduced from 35% to 24.5%. We anticipate our effective income tax rate for fiscal 2018 will range from 26% to 28%, before the effect of the return of the excess deferred tax liability and the one-time, non-cash income tax benefit. Our federal statutory income tax rate will decline to 21% on October 1, 2018.
•
As a result of implementing the TCJA, we remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $903.5 million. Of this amount, $737.8 million was reclassified to a regulatory liability, which will be returned to utility customers. The remaining $165.7 million was recognized as a one-time, non-cash income tax benefit in our condensed consolidated statement of income for the six months ended March 31, 2018. Of this amount, $3.8 million was recorded during the second quarter as we refined the remeasurement calculations performed during the first quarter.
•
Atmos Energy supports our regulators' efforts to ensure our utility customers receive the full benefits of changes in our cost of service rates arising from tax reform. Income taxes, like other costs, are passed through to our customers in our rates; however, changes to customer rates must be approved by our regulators. Beginning in the second quarter of fiscal 2018, we established regulatory liabilities in all our jurisdictions for the difference in taxes included in our cost of service rates that have been calculated based on a 35% statutory income tax rate and a 21% statutory income tax rate. The establishment of these regulatory liabilities for our cost of service rates reduced our revenues. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions. During the second quarter of fiscal 2018, some of our jurisdictions have approved changes to customer rates as discussed in Note 6, which have been reflected in customer bills as of the effective dates stipulated in the regulatory or statutory proceeding. Return to customers of the regulatory liabilities related to the TCJA in these jurisdictions will be addressed in future regulatory proceedings.
•
The enactment of the TCJA is expected to reduce our cash flows from operations primarily due to 1) the collection of taxes at a lower rate and 2) the return of regulatory liabilities established in response to the enactment of the TCJA and regulatory activities to our utility customers. We intend to externally finance this reduction in operating cash flow in a balanced fashion in order to maintain an equity-to-total-capitalization ratio ranging from 50% to 60% to maintain our current credit ratings. We currently anticipate this external financing need will range from $500 million to $600 million through fiscal 2022.
The following discusses the results of operations for each of our operating segments.
Distribution Segment
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment 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 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 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. Contribution margin in 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 contribution margin, over time the impact is offset within operating income.

33


As discussed above, the cost of gas typically does not have a direct impact on our contribution margin. 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 76 percent of our residential and commercial margins.
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended March 31, 2018 compared with Three Months Ended March 31, 2017
Financial and operational highlights for our distribution segment for the three months ended March 31, 2018 and 2017 are presented below.
 
Three Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
1,199,291

 
$
962,541

 
$
236,750

Purchased gas cost
727,053

 
513,096

 
213,957

Contribution margin
472,238

 
449,445

 
22,793

Operating expenses
262,332

 
222,641

 
39,691

Operating income
209,906

 
226,804

 
(16,898
)
Miscellaneous income
393

 
1,029

 
(636
)
Interest charges
16,898

 
16,925

 
(27
)
Income before income taxes
193,401

 
210,908

 
(17,507
)
TCJA non-cash income tax benefit
(3,791
)
 
—

 
(3,791
)
Income tax expense
51,949

 
79,763

 
(27,814
)
Net income
$
145,243

 
$
131,145

 
$
14,098

Consolidated distribution sales volumes — MMcf
134,046

 
97,754

 
36,292

Consolidated distribution transportation volumes — MMcf
45,932

 
39,915

 
6,017

Total consolidated distribution throughput — MMcf
179,978

 
137,669

 
42,309

Consolidated distribution average cost of gas per Mcf sold
$
5.42

 
$
5.25

 
$
0.17

Income before income taxes for our distribution segment decreased 8 percent, primarily due to a $39.7 million increase in operating expenses, partially offset by a $22.8 million increase in contribution margin. The quarter-over-quarter increase in contribution margin primarily reflects:
•
a $27.6 million net increase in rate adjustments, before the effect of the TCJA, primarily in our Mid-Tex and West Texas Divisions.
•
a $9.3 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.
•
an $8.9 million increase in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $5.4 million increase in the related tax expense.
•
a $4.3 million increase in transportation margin primarily in our Kentucky/Mid-States and West Texas Divisions.
•
a $26.2 million decrease in contribution margin due to the inclusion of the lower statutory rate in our revenues due to implementation of the TCJA. Of this amount, $4.8 million has been reflected in customer bills. The remaining $21.4 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory rate and the current 21% federal statutory rate as further described in Note 6.
The increase in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, largely reflects expenses incurred after we decided to undertake a planned outage of our natural gas distribution system in Northwest Dallas. In late February 2018, there were gas-related incidents in Northwest Dallas, one of which resulted in a fatality and injuries to four other residents.  The National Transportation Safety Board (NTSB) is investigating the latter incident. Together with the Railroad Commission of Texas and the Pipeline and Hazardous Materials Safety Administration, we are a party to the investigation and in that capacity we are working closely with the NTSB to help determine the cause of this incident.  On March 1, 2018, we initiated a planned outage of a portion of our natural gas distribution system in Northwest Dallas that affected approximately 2,400 homes.  The outage

34


was initiated after we experienced a sudden and unexplainable increase in leaks in this confined geographic area in less than a week’s time.  Based upon our preliminary assessment, we believe an extraordinary combination of events and circumstances that could not have been predicted, anticipated, readily modeled or foreseen damaged our pipeline system in that area.  These events and circumstances, include, but are not limited to, geology, hydrology, soil conditions and record rainfall.  The system was replaced and placed into service by March 31, 2018.  While the system was replaced, we provided financial assistance to the affected residents and incurred other related costs of approximately $23 million.
The remaining increase in operating expenses is attributable to incremental system integrity activities, increased depreciation and property taxes associated with increased capital investments.
The decrease in income tax expense reflects a reduction in our effective tax rate from 37.8% to 26.9%, as a result of the TCJA.
The following table shows our operating income by distribution division, in order of total rate base, for the three months ended March 31, 2018 and 2017. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Three Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands)
Mid-Tex
$
78,190

 
$
90,809

 
$
(12,619
)
Kentucky/Mid-States
36,529

 
34,010

 
2,519

Louisiana
30,760

 
30,362

 
398

West Texas
21,430

 
21,023

 
407

Mississippi
25,096

 
25,802

 
(706
)
Colorado-Kansas
17,474

 
18,331

 
(857
)
Other
427

 
6,467

 
(6,040
)
Total
$
209,906

 
$
226,804

 
$
(16,898
)

Six Months Ended March 31, 2018 compared with Six Months Ended March 31, 2017

Financial and operational highlights for our distribution segment for the six months ended March 31, 2018 and 2017 are presented below.
 
Six Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
2,060,083

 
$
1,717,197

 
$
342,886

Purchased gas cost
1,190,811

 
908,442

 
282,369

Contribution margin
869,272

 
808,755

 
60,517

Operating expenses
486,610

 
427,058

 
59,552

Operating income
382,662

 
381,697

 
965

Miscellaneous (expense) income
(1,007
)
 
396

 
(1,403
)
Interest charges
38,266

 
38,043

 
223

Income before income taxes
343,389

 
344,050

 
(661
)
One-time, non-cash income tax benefit
(143,942
)
 
—

 
(143,942
)
Income tax expense
92,989

 
127,541

 
(34,552
)
Net income
$
394,342

 
$
216,509

 
$
177,833

Consolidated regulated distribution sales volumes — MMcf
220,353

 
172,184

 
48,169

Consolidated regulated distribution transportation volumes — MMcf
83,982

 
76,090

 
7,892

Total consolidated regulated distribution throughput — MMcf
304,335

 
248,274

 
56,061

Consolidated regulated distribution average cost of gas per Mcf sold
$
5.40

 
$
5.28

 
$
0.12



35


Income before income taxes for our distribution segment was flat compared to the prior year, primarily due to a $59.6 million increase in operating expenses offset with a $60.5 million increase in contribution margin. The year-over-year increase in contribution margin primarily reflects:
•
a $53.1 million net increase in rate adjustments, excluding rate adjustments resulting from the TCJA, primarily in our Mid-Tex, Kentucky/Mid-States and West Texas Divisions.
•
a $15.0 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.
•
an $11.2 million increase in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $7.7 million increase in the related tax expense.
•
a $6.0 million increase in transportation margin primarily in our Kentucky/Mid-States Division.
•
a $26.2 million decrease in contribution margin as a result of lower taxes included in our cost of service rates due to implementation of the TCJA, as discussed above.
The increase in operating expenses reflects expenses incurred with the planned outage we initiated in March 2018, as discussed above, combined with incremental system integrity activities, property taxes and depreciation expense associated with increased capital investments.
The decrease in income tax expense reflects a reduction in our effective tax rate from 37.1% to 27.1%, as a result of the TCJA.
The following table shows our operating income by distribution division, in order of total rate base, for the six months ended March 31, 2018 and 2017. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Six Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands)
Mid-Tex
$
151,115

 
$
163,552

 
$
(12,437
)
Kentucky/Mid-States
64,658

 
56,748

 
7,910

Louisiana
54,028

 
50,225

 
3,803

West Texas
37,191

 
35,951

 
1,240

Mississippi
43,371

 
37,760

 
5,611

Colorado-Kansas
30,405

 
30,036

 
369

Other
1,894

 
7,425

 
(5,531
)
Total
$
382,662

 
$
381,697

 
$
965


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 six months of fiscal 2018, we completed nine regulatory proceedings, resulting in an $18.4 million increase in annual operating income as summarized below.
Rate Action
 
Annual Increase in
Operating Income
 
 
(In thousands)
Annual formula rate mechanisms
 
$
17,897

Rate case filings
 
84

Other rate activity
 
457

 
 
$
18,438


The following ratemaking efforts seeking $23.1 million in increased annual operating income were in progress as of March 31, 2018:

36


Division
 
Rate Action
 
Jurisdiction
 
Operating Income Requested
 
 
 
 
 
 
(In thousands)
Colorado-Kansas
 
Rate Case
 
Colorado(1)
 
$
2,916

Kentucky/Mid-States
 
Rate Case
 
Kentucky(1)
 
4,778

Kentucky/Mid-States
 
Formula Rate Mechanism
 
Tennessee(1)
 
850

Louisiana
 
Formula Rate Mechanism
 
Trans La (1)(3)
 
1,195

Louisiana
 
Formula Rate Mechanism
 
LGS (2)
 
(1,521
)
Mid-Tex
 
Infrastructure Mechanism
 
Environs (2)
 
1,604

Mississippi
 
Infrastructure Mechanism
 
Mississippi (2)
 
8,000

West Texas
 
Infrastructure Mechanism
 
Cities of Amarillo, Channing, Dalhart, and Lubbock (2)
 
4,418

West Texas
 
Infrastructure Mechanism
 
Environs (2)
 
826

 
 
 
 
 
 
$
23,066


(1)
These filings were filed prior to the enactment of the TCJA. The impact of the TCJA along with other items considered in establishing rates will result in a difference between the requested amounts and the final amount approved by the commission.
(2)
The filing amount reflects a 21% federal income tax rate resulting from the TCJA.
(3)
The Louisiana Public Service Commission Staff issued a report, reflecting the impact of TCJA, which recommends a base rate decrease of $1.9 million, effective May 1, 2018.
Annual Formula Rate Mechanisms
As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual 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 the service areas in our Texas divisions. Additionally, we have specific 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 (Texas only), 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 six months ended March 31, 2018:

37


Division
 
Jurisdiction
 
Test Year
Ended
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2018 Filings:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas GSRS
 
09/30/2018
 
$
820

 
02/27/2018
Colorado-Kansas
 
Colorado SSIR
 
12/31/2018
 
2,228

 
12/20/2017
Mississippi
 
Mississippi - SIR
 
10/31/2018
 
7,658

 
12/05/2017
Mississippi
 
Mississippi - SGR (1)
 
10/31/2018
 
1,245

 
12/05/2017
Mississippi
 
Mississippi - SRF (1)
 
10/31/2018
 
—

 
12/05/2017
Kentucky/Mid-States
 
Kentucky - PRP
 
09/30/2018
 
5,638

 
10/27/2017
Kentucky/Mid-States
 
Virginia - SAVE (2)
 
09/30/2017
 
308

 
10/01/2017
Total 2018 Filings
 
 
 
 
 
$
17,897

 
 

(1)
In our next SRF filing, the SGR rate base will be combined with the SRF rate base, per Commission order.
(2)
The Company completed our Steps to Advance Virginia Energy (SAVE) program. On October 1, 2017 a refund factor was removed from the rate resulting in an operating income increase of $0.3 million.
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 six months ended March 31, 2018.
Division
 
State
 
Increase in Annual
Operating Income
 
Effective
Date
 
 
 
 
(In thousands)
 
 
2018 Rate Case Filings:
 
 
 
 
 
 
Mid-Tex
 
City of Dallas (1)
 
$
84

 
02/14/2018
Total 2018 Rate Case Filings
 
 
 
$
84

 
 
(1) The operating income reflects a 21% federal income tax rate resulting from the TCJA.
Other Ratemaking Activity
The following table summarizes other ratemaking activity during the six months ended March 31, 2018.
Division
 
Jurisdiction
 
Rate Activity
 
Additional
Annual
Operating
Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2018 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem(1)
 
$
457

 
02/01/2018
Total 2018 Other Rate Activity
 
 
 
 
 
$
457

 
 

(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.

Pipeline and Storage Segment
Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern, eastern and western Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Midland Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third-party local

38


distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT manages five underground storage facilities in Texas.
Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in the New Orleans, Louisiana area that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.
Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Texas and Louisiana service areas. 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 in Texas could influence the volumes of gas transported for shippers through our Texas pipeline system and the rates for such transportation.
The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
APT annually uses GRIP to recover capital costs incurred in the prior calendar year. Following the conclusion of its rate case in August 2017, APT made a GRIP filing that covered changes in net investment from October 1, 2016 through December 31, 2016 with a requested increase in operating income of $29.0 million. On December 5, 2017, the filing was approved. On February 15, 2018, APT made a GRIP filing that covered changes in net investment from January 1, 2017 through December 31, 2017 with a requested increase in operating income of $42.2 million.
On December 21, 2016, the Louisiana Public Service Commission approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017.

Three Months Ended March 31, 2018 compared with Three Months Ended March 31, 2017
Financial and operational highlights for our pipeline and storage segment for the three months ended March 31, 2018 and 2017 are presented below.
 
Three Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue
$
89,631

 
$
84,292

 
$
5,339

Third-party transportation revenue
28,414

 
22,824

 
5,590

Other revenue
2,910

 
4,856

 
(1,946
)
Total operating revenues
120,955

 
111,972

 
8,983

Total purchased gas cost
433

 
725

 
(292
)
Contribution margin
120,522

 
111,247

 
9,275

Operating expenses
61,440

 
52,879

 
8,561

Operating income
59,082

 
58,368

 
714

Miscellaneous expense
(646
)
 
(196
)
 
(450
)
Interest charges
10,406

 
10,019

 
387

Income before income taxes
48,030

 
48,153

 
(123
)
Income tax expense
14,281

 
17,286

 
(3,005
)
Net income
$
33,749

 
$
30,867

 
$
2,882

Gross pipeline transportation volumes — MMcf
237,167

 
195,233

 
41,934

Consolidated pipeline transportation volumes — MMcf
148,980

 
131,151

 
17,829

Income before income taxes for our pipeline and storage segment was flat year over year, due to a $9.3 million increase in contribution margin, partially offset by an $8.6 million increase in operating expenses. The increase in contribution margin primarily reflects:

39


•
a $16.5 million increase in rates from the approved APT rate case and the GRIP filing approved in December 2017.
•
a net increase of $1.7 million due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.
•
an $8.0 million decrease due to the inclusion of the lower statutory rate in our revenues due to implementation of the TCJA. Of this amount, $0.2 million has been reflected in customer bills. The remaining $7.8 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory rate and the current 21% federal statutory rate as further described in Note 6.
Operating expenses increased $8.6 million, primarily due to higher depreciation expense and higher system maintenance expense.
The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9% to 29.7%, as a result of the TCJA.
Six Months Ended March 31, 2018 and Six Months Ended March 31, 2017
Financial and operational highlights for our pipeline and storage segment for the six months ended March 31, 2018 and 2017 are presented below.
 
Six Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue
$
183,529

 
$
166,760

 
$
16,769

Third-party transportation revenue
57,345

 
45,044

 
12,301

Other revenue
6,544

 
10,120

 
(3,576
)
Total operating revenues
247,418

 
221,924

 
25,494

Total purchased gas cost
1,345

 
1,080

 
265

Contribution margin
246,073

 
220,844

 
25,229

Operating expenses
118,186

 
107,451

 
10,735

Operating income
127,887

 
113,393

 
14,494

Miscellaneous expense
(1,281
)
 
(557
)
 
(724
)
Interest charges
20,547

 
19,931

 
616

Income before income taxes
106,059

 
92,905

 
13,154

One-time, non-cash income tax benefit
(21,733
)
 
—

 
(21,733
)
Income tax expense
29,010

 
33,364

 
(4,354
)
Net income
$
98,782

 
$
59,541

 
$
39,241

Gross pipeline transportation volumes — MMcf
450,304

 
382,013

 
68,291

Consolidated pipeline transportation volumes — MMcf
304,085

 
266,127

 
37,958

Income before income taxes for our pipeline and storage segment increased 14 percent, primarily due to a $25.2 million increase in contribution margin, offset by a $10.7 million increase in operating expenses. The increase in contribution margin primarily reflects:
•
a $30.4 million increase in rates from the approved APT rate case and the GRIP filing approved in December 2017.
•
a net increase of $3.1 million due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.
•
an $8.0 million decrease in rates due to the implementation of the TCJA, as discussed above.
Operating expenses increased $10.7 million, primarily due to higher depreciation expense partially offset by the timing of system maintenance expense.
The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 35.9% to 27.4%, as a result of the TCJA.
Natural Gas Marketing Segment
Through December 31, 2016, we were engaged in an unregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange

40


transportation and storage logistics and ultimately deliver gas to customers at competitive prices. Additionally, AEM utilized proprietary and customer-owned transportation and storage assets to provide various services its customers requested.
As more fully described in Note 13, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy fully exited the nonregulated natural gas marketing business. Accordingly, a gain on sale from discontinued operations for $2.7 million was recorded for the three and six months ended March 31, 2017 and net income of $11.0 million for AEM is reported as discontinued operations for the six months ended March 31, 2017.
 
 
 
 
 
 
 
 
 
 
 
 
Liquidity and Capital Resources
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. External debt financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program and three committed revolving credit facilities with a total availability from third-party lenders of approximately $1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for the remainder of fiscal year 2018 and beyond. Please refer to the TCJA Impact section above regarding anticipated impacts on our liquidity, capital resources and cash flows.
To support our capital market activities, we have a registration statement on file with the SEC that permits us to issue a total of $2.5 billion in common stock and/or debt securities. Under the shelf registration statement, we recently filed a prospectus supplement for an at-the-market (ATM) equity distribution program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million. At March 31, 2018, approximately $1.2 billion of securities remained 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 March 31, 2018, September 30, 2017 and March 31, 2017:
 
 
March 31, 2018
 
September 30, 2017
 
March 31, 2017
 
(In thousands, except percentages)
Short-term debt
$
129,602

 
1.6
%
 
$
447,745

 
6.0
%
 
$
670,607

 
9.5
%
Long-term debt(1)
3,067,892

 
38.8
%
 
3,067,045

 
41.4
%
 
2,564,620

 
36.3
%
Shareholders’ equity
4,721,346

 
59.6
%
 
3,898,666

 
52.6
%
 
3,834,864

 
54.2
%
Total
$
7,918,840

 
100.0
%
 
$
7,413,456

 
100.0
%
 
$
7,070,091

 
100.0
%

(1)
In March 2019, $450 million of long-term debt will mature. We plan to issue new senior notes to replace the maturing debt. We have executed forward starting interest rate swaps to effectively fix the Treasury yield component associated with this anticipated issuance at 3.78%.

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 six months ended March 31, 2018 and 2017 are presented below.

41


 
Six Months Ended March 31
 
2018
 
2017
 
Change
 
(In thousands)
Total cash provided by (used in)
 
 
 
 
 
Operating activities
$
751,367

 
$
552,003

 
$
199,364

Investing activities
(688,144
)
 
(516,670
)
 
(171,474
)
Financing activities
(18,558
)
 
(37,464
)
 
18,906

Change in cash and cash equivalents
44,665

 
(2,131
)
 
46,796

Cash and cash equivalents at beginning of period
26,409

 
47,534

 
(21,125
)
Cash and cash equivalents at end of period
$
71,074

 
$
45,403

 
$
25,671

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 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 six months ended March 31, 2018, we generated cash flow of $751.4 million from operating activities compared with $552.0 million for the six months ended March 31, 2017. The $199.4 million increase in operating cash flows reflects the positive cash effects of successful rate case outcomes achieved in fiscal 2017 and changes in working capital, primarily as a result of the timing of gas cost recoveries under our purchase gas cost mechanisms as a result of a period-over-period increase in sales volumes. This increase in sale volumes also contributed to the period-over-period increase in operating cash flow.
Cash flows from investing activities
In recent years, we have incurred capital expenditures to support our distribution and transmission system modernization and integrity enhancement efforts, expand our natural gas distribution services and 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.
For the six months ended March 31, 2018, cash used for investing activities was $688.1 million compared to $516.7 million in the prior-year period. Capital spending increased by $134.6 million, or 24 percent, as a result of planned increases in our distribution segment to repair and replace vintage pipe, and increases in spending in our pipeline and storage segment to improve the reliability of gas service to our local distribution company customers. The period-over-period increase also reflects the absence in the current year period of $133.6 million in net proceeds received from the sale of AEM and the $85.7 million used to acquire the North Texas Pipeline in December 2016.
Cash flows from financing activities
For the six months ended March 31, 2018, our financing activities used $18.6 million of cash compared with $37.5 million in the prior-year period. The $18.9 million decrease in cash used in financing activities primarily reflects an increase in operating cash flow that exceeded an increase in cash used for investing activities during the six months ended March 31, 2018.
In the six months ended March 31, 2018, we used $395.1 million in net proceeds from equity financing to reduce short-term debt, to support our capital spending and for other general corporate purposes. Cash dividends increased due to a 7.8% increase in our dividend rate and an increase in shares outstanding.
In the six months ended March 31, 2017, we issued $125 million of long-term debt under our three year, $200 million term loan agreement and received $49.4 million from the issuance of common stock under our ATM program. The net proceeds from these debt and equity issuances were used to reduce short-term debt and support our capital expenditures program. Additionally, the return of cash collateral related to our forward-starting interest rate swaps due to an increase in interest rates provided cash from financing activities of $25.7 million.

42


The following table summarizes our share issuances for the six months ended March 31, 2018 and 2017:
 
Six Months Ended 
 March 31
 
2018
 
2017
Shares issued:
 
 
 
Direct Stock Purchase Plan
90,042

 
54,366

1998 Long-Term Incentive Plan
257,400

 
426,835

Retirement Savings Plan and Trust
49,848

 
172,932

At-the-Market (ATM) Equity Distribution Program
—

 
690,812

Equity Issuance
4,558,404

 
—

Total shares issued
4,955,694

 
1,344,945

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 businesses and the regulatory structures that govern our rates in the states where we operate.
Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). As of March 31, 2018, both rating agencies maintained a stable outlook. Our current debt ratings are all considered investment grade and are as follows:
 
S&P
 
Moody’s
Senior unsecured long-term debt
A
  
A2
Short-term debt
A-1
  
P-1
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 and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. 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 March 31, 2018. 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 9 to the unaudited condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the six months ended March 31, 2018.

Risk Management Activities
In our distribution and pipeline and storage segments, 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. Through December 31, 2016, we managed our exposure to the risk of natural gas price changes in our natural gas marketing segment by locking in our contribution margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties.

43


The following table shows the components of the change in fair value of our financial instruments for the three and six months ended March 31, 2018 and 2017:
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Fair value of contracts at beginning of period
$
(116,529
)
 
$
(121,722
)
 
$
(109,159
)
 
$
(279,543
)
Contracts realized/settled
(2,360
)
 
1,793

 
(1,200
)
 
11,756

Fair value of new contracts
(147
)
 
(2,560
)
 
(716
)
 
(1,597
)
Other changes in value
32,694

 
8,485

 
24,733

 
155,380

Fair value of contracts at end of period
(86,342
)
 
(114,004
)
 
(86,342
)
 
(114,004
)
Netting of cash collateral
—

 
—

 
—

 
—

Cash collateral and fair value of contracts at period end
$
(86,342
)
 
$
(114,004
)
 
$
(86,342
)
 
$
(114,004
)

The fair value of our financial instruments at March 31, 2018 is presented below by time period and fair value source:
 
Fair Value of Contracts at March 31, 2018
 
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
$
(86,342
)
 
$
—

 
$
—

 
$
—

 
$
(86,342
)
Prices based on models and other valuation methods
—

 
—

 
—

 
—

 
—

Total Fair Value
$
(86,342
)
 
$
—

 
$
—

 
$
—

 
$
(86,342
)
Pension and Postretirement Benefits Obligations
For the six months ended March 31, 2018 and 2017, our total net periodic pension and other benefits costs were $20.9 million and $23.2 million. A substantial portion of those costs is recoverable through our rates; however, a portion of these costs is capitalized into our rate base. The remaining costs are recorded as a component of operation and maintenance expense.
Our fiscal 2018 costs were determined using a September 30, 2017 measurement date. As of September 30, 2017, interest and corporate bond rates were higher than the rates as of September 30, 2016. Therefore, we increased the discount rate used to measure our fiscal 2018 net periodic cost from 3.73 percent to 3.89 percent. We lowered the expected return on plan assets to 6.75 percent in the determination of our fiscal 2018 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2018 net periodic pension cost to be approximately 25 percent lower than fiscal 2017.
The amount of funding required for our defined benefit plan is determined in accordance with the Pension Protection Act of 2006 (PPA) and is 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, 2017, we were not required to make a minimum contribution to our defined benefit plan during fiscal 2018. However, we will consider whether a voluntary contribution is prudent to maintain certain funding levels.
For the six months ended March 31, 2018 we contributed $7.5 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal 2018.
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.


44



OPERATING STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for our distribution and pipeline and storage segments for the three and six-month periods ended March 31, 2018 and 2017.
Distribution Sales and Statistical Data
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017
 
2018
 
2017
METERS IN SERVICE, end of period
 
 
 
 
 
 
 
Residential
2,964,137

 
2,929,455

 
2,964,137

 
2,929,455

Commercial
270,795

 
269,055

 
270,795

 
269,055

Industrial
1,673

 
1,690

 
1,673

 
1,690

Public authority and other
8,407

 
8,332

 
8,407

 
8,332

Total meters
3,245,012

 
3,208,532

 
3,245,012

 
3,208,532

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
29.7

 
40.0

 
29.7

 
40.0

SALES VOLUMES — MMcf(1)
 
 
 
 
 
 
 
Gas sales volumes
 
 
 
 
 
 
 
Residential
80,525

 
56,931

 
129,473

 
98,431

Commercial
40,956

 
31,739

 
67,905

 
55,475

Industrial
9,708

 
6,708

 
18,166

 
14,140

Public authority and other
2,857

 
2,376

 
4,809

 
4,138

Total gas sales volumes
134,046

 
97,754

 
220,353

 
172,184

Transportation volumes
47,843

 
42,142

 
87,702

 
81,207

Total throughput
181,889

 
139,896

 
308,055

 
253,391

OPERATING REVENUES (000’s)(1)
 
 
 
 
 
 
 
Gas sales revenues
 
 
 
 
 
 
 
Residential
$
805,134

 
$
609,771

 
$
1,361,654

 
$
1,091,444

Commercial
318,312

 
251,174

 
541,892

 
451,662

Industrial
39,604

 
47,986

 
73,017

 
78,017

Public authority and other
19,008

 
17,607

 
32,569

 
29,716

Total gas sales revenues
1,182,058

 
926,538

 
2,009,132

 
1,650,839

Transportation revenues
29,939

 
24,307

 
55,301

 
46,788

Other gas revenues
(12,706
)
 
11,696

 
(4,350
)
 
19,570

Total operating revenues
$
1,199,291

 
$
962,541

 
$
2,060,083

 
$
1,717,197

Average cost of gas per Mcf sold
$
5.42

 
$
5.25

 
$
5.40

 
$
5.28

See footnote following these tables.


45


Pipeline and Storage Operations Sales and Statistical Data
 
Three Months Ended 
 March 31
 
Six Months Ended 
 March 31
 
2018
 
2017
 
2018
 
2017
CUSTOMERS, end of period
 
 
 
 
 
 
 
Industrial
92

 
91

 
92

 
91

Other
231

 
226

 
231

 
226

Total
323

 
317

 
323

 
317

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
0.4

 
0.6

 
0.4

 
0.6

PIPELINE TRANSPORTATION VOLUMES — MMcf(1)
237,167

 
195,233

 
450,304

 
382,013

OPERATING REVENUES (000’s)(1)
$
120,955

 
$
111,972

 
$
247,418

 
$
221,924

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, 2017. During the six months ended March 31, 2018, 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 March 31, 2018 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 second quarter of the fiscal year ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


46


PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
During the six months ended March 31, 2018, except as noted in Note 9 to the unaudited condensed consolidated financial statements, there were no material changes in the status of the litigation and other matters that were disclosed in Note 11 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. 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
The following exhibits are filed as part of this Quarterly Report.
 
Exhibit
Number
  
Description
Page Number or
Incorporation by
Reference to
2.1
 
Exhibit 2.1 to Form 8-K dated October 29, 2016 (File No. 1-10042)
10
 
Exhibit 1.1 to Form 8-K dated November 14, 2017 (File No. 1-10042)
12
  
 
15
  
 
31
  
 
32
  
 
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.

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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/    CHRISTOPHER T. FORSYTHE
 
 
 
Christopher T. Forsythe
Senior Vice President and Chief Financial Officer
(Duly authorized signatory)
Date: May 2, 2018

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