Annual Statements Open main menu

ATMOS ENERGY CORP - Quarter Report: 2019 June (Form 10-Q)



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2019
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.)
 
 
 
 
1800 Three Lincoln Centre
 
 
5430 LBJ Freeway
 
 
Dallas
Texas
 
75240
(Address of principal executive offices)
 
(Zip code)
(972934-9227
(Registrant’s telephone number, including area code)
Title of each class
Trading Symbol
Name of each exchange on which registered
Common stock
No Par Value
ATO
New York Stock Exchange
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 every Interactive Data File required to be submitted 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 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
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 July 31, 2019.
Class
 
Shares Outstanding
Common stock
No Par Value
 
118,200,689




GLOSSARY OF KEY TERMS
 
 
 
Adjusted diluted net income per share
Non-GAAP measure defined as diluted net income per share before the one-time, non-cash income tax benefit
Adjusted net income
Non-GAAP measure defined as net income before the one-time, non-cash income tax benefit
AEC
Atmos Energy Corporation
AOCI
Accumulated other comprehensive income
ARM
Annual Rate Mechanism
ASC
Accounting Standards Codification
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
FERC
Federal Energy Regulatory Commission
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
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 
 
June 30,
2019
 
September 30,
2018
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
13,687,833

 
$
12,567,373

Less accumulated depreciation and amortization
2,347,237

 
2,196,226

Net property, plant and equipment
11,340,596

 
10,371,147

Current assets
 
 
 
Cash and cash equivalents
46,163

 
13,771

Accounts receivable, net
285,433

 
253,295

Gas stored underground
106,014

 
165,732

Other current assets
65,924

 
46,055

Total current assets
503,534

 
478,853

Goodwill
730,419

 
730,419

Deferred charges and other assets
306,549

 
294,018

 
$
12,881,098

 
$
11,874,437

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: June 30, 2019 — 118,196,113 shares; September 30, 2018 — 111,273,683 shares
$
591

 
$
556

Additional paid-in capital
3,599,724

 
2,974,926

Accumulated other comprehensive loss
(115,663
)
 
(83,647
)
Retained earnings
2,157,344

 
1,878,116

Shareholders’ equity
5,641,996

 
4,769,951

Long-term debt
3,529,135

 
2,493,665

Total capitalization
9,171,131

 
7,263,616

Current liabilities
 
 
 
Accounts payable and accrued liabilities
206,500

 
217,283

Other current liabilities
494,932

 
547,068

Short-term debt
74,942

 
575,780

Current maturities of long-term debt
125,000

 
575,000

Total current liabilities
901,374

 
1,915,131

Deferred income taxes
1,280,307

 
1,154,067

Regulatory excess deferred taxes (See Note 13)
709,974

 
739,670

Regulatory cost of removal obligation
464,855

 
466,405

Pension and postretirement liabilities
177,602

 
177,520

Deferred credits and other liabilities
175,855

 
158,028

 
$
12,881,098

 
$
11,874,437

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended June 30
 
2019
 
2018
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
444,944

 
$
535,488

Pipeline and storage segment
149,198

 
127,633

Intersegment eliminations
(108,404
)
 
(100,876
)
Total operating revenues
485,738

 
562,245

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
139,518

 
230,887

Pipeline and storage segment
(96
)
 
561

Intersegment eliminations
(108,096
)
 
(100,562
)
Total purchased gas cost
31,326

 
130,886

 
 
 
 
Operation and maintenance expense
164,545

 
143,748

Depreciation and amortization expense
97,700

 
90,671

Taxes, other than income
69,965

 
72,620

Operating income
122,202

 
124,320

Other non-operating income (expense)
1,645

 
(3,330
)
Interest charges
19,592

 
23,349

Income before income taxes
104,255

 
97,641

Income tax expense
23,789

 
26,448

Net income
$
80,466

 
$
71,193

Basic net income per share
$
0.68

 
$
0.64

Diluted net income per share
$
0.68

 
$
0.64

Cash dividends per share
$
0.525

 
$
0.485

Basic weighted average shares outstanding
118,075

 
111,851

Diluted weighted average shares outstanding
118,430

 
111,851

 
 
 
 
Net income
$
80,466

 
$
71,193

Other comprehensive income, net of tax
 
 
 
Net unrealized holding gains on available-for-sale securities, net of tax of $27 and $92 (See Note 2)
94

 
310

Cash flow hedges:
 
 
 
Amortization and unrealized gain on interest rate agreements, net of tax of $312 and $2,460
1,053

 
8,320

Total other comprehensive income
1,147

 
8,630

Total comprehensive income
$
81,613

 
$
79,823

See accompanying notes to condensed consolidated financial statements.







4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Nine Months Ended June 30
 
2019
 
2018
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
2,341,668

 
$
2,595,571

Pipeline and storage segment
419,318

 
375,051

Intersegment eliminations
(302,821
)
 
(299,776
)
Total operating revenues
2,458,165

 
2,670,846

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
1,147,598

 
1,421,698

Pipeline and storage segment
(544
)
 
1,906

Intersegment eliminations
(301,887
)
 
(298,841
)
Total purchased gas cost
845,167

 
1,124,763

 
 
 
 
Operation and maintenance expense
452,572

 
431,952

Depreciation and amortization expense
290,537

 
268,426

Taxes, other than income
213,546

 
208,400

Operating income
656,343

 
637,305

Other non-operating expense
(1,846
)
 
(8,054
)
Interest charges
74,390

 
82,162

Income before income taxes
580,107

 
547,089

Income tax expense (benefit)
127,107

 
(17,228
)
Net income
$
453,000

 
$
564,317

Basic net income per share
$
3.89

 
$
5.09

Diluted net income per share
$
3.88

 
$
5.09

Cash dividends per share
$
1.575

 
$
1.455

Basic weighted average shares outstanding
116,485

 
110,707

Diluted weighted average shares outstanding
116,673

 
110,707

 
 
 
 
Net income
$
453,000

 
$
564,317

Other comprehensive income (loss), net of tax
 
 
 
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $56 and $(246) (See Note 2)
191

 
(736
)
Cash flow hedges:
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(7,093) and $8,486
(23,997
)
 
29,609

Total other comprehensive income (loss)
(23,806
)
 
28,873

Total comprehensive income
$
429,194

 
$
593,190

See accompanying notes to condensed consolidated financial statements.


5



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Nine Months Ended June 30
 
2019
 
2018
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
453,000

 
$
564,317

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
290,537

 
268,426

Deferred income taxes
120,220

 
139,852

One-time income tax benefit

 
(165,522
)
Other
9,649

 
18,007

Net assets / liabilities from risk management activities
(1,976
)
 
912

Net change in operating assets and liabilities
(62,502
)
 
209,304

Net cash provided by operating activities
808,928

 
1,035,296

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(1,199,199
)
 
(1,088,472
)
Proceeds from the sale of discontinued operations
4,000

 
3,000

Debt and equity securities activities, net
(4,041
)
 
(7,857
)
Other, net
3,839

 
6,105

Net cash used in investing activities
(1,195,401
)
 
(1,087,224
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(500,838
)
 
(202,968
)
Net proceeds from equity offering
593,731

 
395,092

Issuance of common stock through stock purchase and employee retirement plans
14,128

 
15,850

Proceeds from issuance of long-term debt
1,045,221

 

Settlement of interest rate swaps
(90,141
)
 

Repayment of long-term debt
(450,000
)
 

Cash dividends paid
(181,982
)
 
(160,007
)
Debt issuance costs
(11,254
)
 

Other

 
(1,518
)
Net cash provided by financing activities
418,865

 
46,449

Net increase (decrease) in cash and cash equivalents
32,392

 
(5,479
)
Cash and cash equivalents at beginning of period
13,771

 
26,409

Cash and cash equivalents at end of period
$
46,163

 
$
20,930


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2019
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and its subsidiaries are 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 June 30, 2019, 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, aside from accounting policy changes noted below, 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, 2018. 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, 2018. Because of seasonal and other factors, the results of operations for the nine-month period ended June 30, 2019 are not indicative of our results of operations for the full 2019 fiscal year, which ends September 30, 2019.
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, 2018.
During the second quarter of fiscal 2019, we completed our annual goodwill impairment assessment. Based on the assessment performed, we determined that our goodwill was not impaired.
Accounting pronouncements adopted in fiscal 2019
During the first quarter of fiscal 2019, we adopted the following accounting guidance updates, effective October 1, 2018. The adoption of this new guidance, individually and collectively, did not have a material impact on our financial position, results of operations or cash flows.
Revenue recognition - Under the new guidance, we are required to recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. See Note 5 for our discussion of the effects of implementing this standard.

Classification and measurement of financial instruments - The new guidance requires that we recognize changes in the fair value of our equity securities formerly designated as available-for-sale in other non-operating income (expense) in our condensed consolidated statement of comprehensive income on a prospective basis from the date of adoption. However, we continue to classify cash flows from purchases and sales of equity securities within investing activities given the nature of these securities. Additionally, in accordance with the guidance, we reclassified a net $8.2 million unrealized gain related to these equity securities from accumulated other comprehensive income (AOCI) to retained earnings. The accounting for debt securities designated as available-for-sale did not change as a result of this new guidance. Accordingly, changes in the fair value of these securities will continue to be recorded as a component of AOCI.

Presentation of the Components of Net Periodic Benefit Cost - The new guidance requires us to present only the current service cost component of the net benefit cost within operations and maintenance expense in the statement of

7



comprehensive income. The remaining components of net benefit cost are now recorded in other non-operating income (expense) in our condensed consolidated statements of comprehensive income. The change in presentation of these costs was implemented on a retrospective basis as required by the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the prior periods’ condensed statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for these costs in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard.

In addition, under the new guidance, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). We continue to capitalize these costs into property, plant and equipment.
However, the Federal Energy Regulatory Commission (FERC), which establishes the regulatory accounting practices for rate-regulated entities, issued guidance that permits such entities the option to continue to capitalize non-service benefit costs for regulatory purposes.  Since the accounting guidelines by the FERC are typically followed by our state regulatory authorities, for U.S. GAAP reporting purposes, we are prospectively deferring into a regulatory asset the portion of non-service components of net periodic benefit cost that are capitalizable for regulatory purposes.
Accounting for Implementation Costs Incurred in A Hosting Arrangement That Is A Service Contract - The new guidance aligns the requirements for capitalizing implementation costs incurred for these contracts with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). We elected to early adopt the new guidance on a prospective basis. Accordingly, we will capitalize the up-front costs incurred for cloud computing arrangements had they been capitalizable in a similar on-premise software solution.
Accounting pronouncements that will be effective after fiscal 2019
In February 2016, the Financial Accounting Standards Board (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. Subsequently, the FASB issued practical expedients to 1) allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance and 2) allow entities the option to adopt the standard and recognize a cumulative–effect adjustment to the opening balance of retained earnings in the period of adoption rather than applying the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The new standard will be effective for us beginning on October 1, 2019.
The impact of this change on our financial position is not reasonably estimable at this time. We do not anticipate the adoption of this standard will have a material impact to our results of operations or cash flows. We continue to evaluate our adoption of certain practical expedients, however we currently anticipate adopting the following practical expedients:
land easements under the provisions of ASU 2018-01, as described above,
package of three practical expedients described in ASC 842-10-65-1 and
transition method practical expedient provided in ASU 2018-11, as described above.
We are implementing a new lease accounting system, which we will utilize to capture, track and account for lease data. The new system will also aid in automating the compilation of disclosure information.
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 debt 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, 2020; 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. 
In August 2018, the FASB issued new guidance that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance removes the disclosure requirements for the amounts of gain/loss and prior service cost/credit amortization expected in the following year and the disclosure of the effect of a one-percentage-point change in the health care cost trend rate, among other changes. The guidance adds certain disclosures including the weighted average interest crediting rate for cash balance plans and a narrative description for the significant change in gains and losses as well as any other significant change in the plan obligations or assets. The new guidance is effective for us in the fiscal year beginning October 1, 2020 and should be applied on a retrospective basis to all periods

8



presented. Early adoption is permitted. The adoption of this new guidance impacts only our disclosures. We intend to early adopt the guidance as of September 30, 2019.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and our regulatory liabilities are recorded as a component of other current liabilities and 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 are reported separately.
Significant regulatory assets and liabilities as of June 30, 2019 and September 30, 2018 included the following:
 
June 30,
2019
 
September 30,
2018
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs
$
8,007

 
$
6,496

Infrastructure mechanisms(1)
111,211

 
96,739

Deferred gas costs
7,227

 
1,927

Recoverable loss on reacquired debt
7,000

 
8,702

Deferred pipeline record collection costs
25,347

 
20,467

Rate case costs
1,413

 
2,741

Other
4,465

 
6,739

 
$
164,670

 
$
143,811

Regulatory liabilities:
 
 
 
Regulatory excess deferred taxes(2)
$
731,837

 
$
744,895

Regulatory cost of service reserve(3)
6,079

 
22,508

Regulatory cost of removal obligation
526,403

 
522,175

Deferred gas costs
66,171

 
94,705

Asset retirement obligation
12,887

 
12,887

APT annual adjustment mechanism
63,130

 
35,228

Pension and postretirement benefit costs
80,330

 
69,113

Other
3,038

 
9,486

 
$
1,489,875

 
$
1,510,997


 
(1)
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.
(2)
The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. Of this amount, $21.9 million as of June 30, 2019 and $5.2 million as of September 30, 2018 is recorded in other current liabilities. The period and timing of the return of the excess deferred taxes is being determined by regulators in each of our jurisdictions. See Note 13 for further information.
(3)
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. The period and timing of the return of this liability to utility customers is being determined by regulators in each of our jurisdictions. See Note 13 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.

9



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 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, 2018.
Income statements and capital expenditures for the three and nine months ended June 30, 2019 and 2018 by segment are presented in the following tables:
 
Three Months Ended June 30, 2019
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
444,287

 
$
41,451

 
$

 
$
485,738

Intersegment revenues
657

 
107,747

 
(108,404
)
 

Total operating revenues
444,944

 
149,198

 
(108,404
)
 
485,738

Purchased gas cost
139,518

 
(96
)
 
(108,096
)
 
31,326

Operation and maintenance expense
123,998

 
40,855

 
(308
)
 
164,545

Depreciation and amortization expense
70,611

 
27,089

 

 
97,700

Taxes, other than income
62,134

 
7,831

 

 
69,965

Operating income
48,683

 
73,519

 

 
122,202

Other non-operating income (expense)
3,005

 
(1,360
)
 

 
1,645

Interest charges
10,597

 
8,995

 

 
19,592

Income before income taxes
41,091

 
63,164

 

 
104,255

Income tax expense
8,693

 
15,096

 

 
23,789

Net income
$
32,398

 
$
48,068

 
$

 
$
80,466

Capital expenditures
$
316,825

 
$
104,788

 
$

 
$
421,613



 
Three Months Ended June 30, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
534,816

 
$
27,429

 
$

 
$
562,245

Intersegment revenues
672

 
100,204

 
(100,876
)
 

Total operating revenues
535,488

 
127,633

 
(100,876
)
 
562,245

Purchased gas cost
230,887

 
561

 
(100,562
)
 
130,886

Operation and maintenance expense
110,568

 
33,494

 
(314
)
 
143,748

Depreciation and amortization expense
66,504

 
24,167

 

 
90,671

Taxes, other than income
64,420

 
8,200

 

 
72,620

Operating income
63,109

 
61,211

 

 
124,320

Other non-operating expense
(2,518
)
 
(812
)
 

 
(3,330
)
Interest charges
13,315

 
10,034

 

 
23,349

Income before income taxes
47,276

 
50,365

 

 
97,641

Income tax expense
11,932

 
14,516

 

 
26,448

Net income
$
35,344

 
$
35,849

 
$

 
$
71,193

Capital expenditures
$
284,209

 
$
110,285

 
$

 
$
394,494



10



 
Nine Months Ended June 30, 2019
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,339,660

 
$
118,505

 
$

 
$
2,458,165

Intersegment revenues
2,008

 
300,813

 
(302,821
)
 

Total operating revenues
2,341,668

 
419,318

 
(302,821
)
 
2,458,165

Purchased gas cost
1,147,598

 
(544
)
 
(301,887
)
 
845,167

Operation and maintenance expense
347,386

 
106,120

 
(934
)
 
452,572

Depreciation and amortization expense
210,224

 
80,313

 

 
290,537

Taxes, other than income
189,377

 
24,169

 

 
213,546

Operating income
447,083

 
209,260

 

 
656,343

Other non-operating income (expense)
1,791

 
(3,637
)
 

 
(1,846
)
Interest charges
44,703

 
29,687

 

 
74,390

Income before income taxes
404,171

 
175,936

 

 
580,107

Income tax expense
85,195

 
41,912

 

 
127,107

Net income
$
318,976

 
$
134,024

 
$

 
$
453,000

Capital expenditures
$
912,640

 
$
286,559

 
$

 
$
1,199,199


 
Nine Months Ended June 30, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
2,593,578

 
$
77,268

 
$

 
$
2,670,846

Intersegment revenues
1,993

 
297,783

 
(299,776
)
 

Total operating revenues
2,595,571

 
375,051

 
(299,776
)
 
2,670,846

Purchased gas cost
1,421,698

 
1,906

 
(298,841
)
 
1,124,763

Operation and maintenance expense
343,860

 
89,027

 
(935
)
 
431,952

Depreciation and amortization expense
197,587

 
70,839

 

 
268,426

Taxes, other than income
184,219

 
24,181

 

 
208,400

Operating income
448,207

 
189,098

 

 
637,305

Other non-operating expense
(5,961
)
 
(2,093
)
 

 
(8,054
)
Interest charges
51,581

 
30,581

 

 
82,162

Income before income taxes
390,665

 
156,424

 

 
547,089

Income tax (benefit) expense
(39,021
)
 
21,793

 

 
(17,228
)
Net income
$
429,686

 
$
134,631

 
$

 
$
564,317

Capital expenditures
$
749,693

 
$
338,779

 
$

 
$
1,088,472

 

11



Balance sheet information at June 30, 2019 and September 30, 2018 by segment is presented in the following tables:
 
June 30, 2019
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
8,404,238

 
$
2,936,358

 
$

 
$
11,340,596

Total assets
$
12,083,315

 
$
3,174,516

 
$
(2,376,733
)
 
$
12,881,098


 
September 30, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
7,644,693

 
$
2,726,454

 
$

 
$
10,371,147

Total assets
$
11,109,128

 
$
2,963,480

 
$
(2,198,171
)
 
$
11,874,437


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 weighted average shares outstanding is calculated based upon the weighted average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Additionally, the weighted average shares outstanding for diluted EPS includes the incremental effects of the forward sale agreements, discussed in Note 7, when the impact is dilutive. Basic and diluted earnings per share for the three and nine months ended June 30, 2019 and 2018 are calculated as follows:

 
Three Months Ended June 30
 
Nine Months Ended June 30
 
2019
 
2018
 
2019
 
2018
 
(In thousands, except per share amounts)
Basic Earnings Per Share
 
 
 
 
 
 
 
Net income
$
80,466

 
$
71,193

 
$
453,000

 
$
564,317

Less: Income allocated to participating securities
64

 
59

 
386

 
545

Income available to common shareholders
$
80,402

 
$
71,134

 
$
452,614

 
$
563,772

Basic weighted average shares outstanding
118,075

 
111,851

 
116,485

 
110,707

Net income per share — Basic
$
0.68

 
$
0.64

 
$
3.89

 
$
5.09

Diluted Earnings Per Share
 
 
 
 
 
 
 
Income available to common shareholders
$
80,402

 
$
71,134

 
$
452,614

 
$
563,772

Effect of dilutive shares

 

 

 

Income available to common shareholders
$
80,402

 
$
71,134

 
$
452,614

 
$
563,772

Basic weighted average shares outstanding
118,075

 
111,851

 
116,485

 
110,707

Dilutive shares
355

 

 
188

 

Diluted weighted average shares outstanding
118,430

 
111,851

 
116,673

 
110,707

Net income per share - Diluted
$
0.68

 
$
0.64

 
$
3.88

 
$
5.09



5.    Revenue

Effective October 1, 2018, we adopted the new guidance under Accounting Standards Codification (ASC) Topic 606. The implementation of the new guidance did not have a material impact on our financial position, results of operations, cash flow or

12



business processes. However, the guidance introduced new disclosures which are presented below. The following table disaggregates our revenue from contracts with customers by customer type and segment and provides a reconciliation to total revenues for the period presented.

 
Three Months Ended June 30, 2019
 
Nine Months Ended June 30, 2019
 
Distribution
 
Pipeline and Storage
 
Distribution
 
Pipeline and Storage
 
(In thousands)
Gas sales revenues:
 
 
 
 
 
 
 
Residential
$
269,484

 
$

 
$
1,513,239

 
$

Commercial
113,591

 

 
611,474

 

Industrial
25,277

 

 
95,701

 

Public authority and other
6,305

 

 
36,677

 

Total gas sales revenues
414,657

 

 
2,257,091

 

Transportation revenues
22,923

 
166,864

 
76,005

 
456,558

Miscellaneous revenues
6,125

 
2,407

 
20,439

 
6,862

Revenues from contracts with customers
443,705

 
169,271

 
2,353,535

 
463,420

Alternative revenue program revenues
748

 
(20,073
)
 
(13,388
)
 
(44,102
)
Other revenues
491

 

 
1,521

 

Total operating revenues
$
444,944

 
$
149,198

 
$
2,341,668

 
$
419,318



Distribution Revenues
Distribution revenues represent the delivery of natural gas to residential, commercial, industrial and public authority customers at prices based on tariff rates established by regulatory authorities in the states in which we operate. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered and simultaneously consumed by our customer. We have elected to use the invoice practical expedient and recognize revenue for volumes delivered that we have the right to invoice our customers. We read meters and bill our customers on a monthly cycle basis. Accordingly, we estimate volumes from the last meter read to the balance sheet date and accrue revenue for gas delivered but not yet billed.
In our Texas and Mississippi jurisdictions, we pay franchise fees and gross receipt taxes to operate in these service areas. These franchise fees and gross receipts taxes are required to be paid regardless of our ability to collect from our customers. Accordingly, we account for these amounts on a gross basis in revenue and we record the associated tax expense as a component of taxes, other than income.
Pipeline and Storage Revenues
Pipeline and storage revenues primarily represent the transportation and storage of natural gas on our Atmos Pipeline-Texas (APT) system and the transmission of natural gas through our 21-mile pipeline in Louisiana. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies and certain industrial customers under tariff rates approved by the Railroad Commission of Texas (RRC). APT also provides certain transportation and storage services to industrial and electric generation customers, as well as marketers and producers, under negotiated rates. Our pipeline in Louisiana is primarily used to aggregate gas supply for our Louisiana Division under a long-term contract and on a more limited basis to third parties. The demand fee charged to our Louisiana Division is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans with distribution affiliates of the Company at terms that have been approved by the applicable state regulatory commissions. The performance obligations for these transportation customers are satisfied by means of transporting customer-supplied gas to the designated location. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered to the customer. Management determined that these arrangements qualify for the invoice practical expedient for recognizing revenue. For demand fee arrangements, revenue is recognized and our performance obligation is satisfied by standing ready to transport natural gas over the period of each individual month.

13



Alternative Revenue Program Revenues
In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our contribution margin. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark of $69.4 million that was established in its most recent rate case. Differences between actual revenues and revenues calculated under these mechanisms adjust the amount billed to customers. These mechanisms are considered to be alternative revenue programs under accounting standards generally accepted in the United States as they are deemed to be contracts between us and our regulator. Accordingly, revenue under these mechanisms are excluded from revenue from contracts with customers.

6.    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, 2018. Other than as described below, there were no material changes in the terms of our debt instruments during the nine months ended June 30, 2019.
Long-term debt at June 30, 2019 and September 30, 2018 consisted of the following:
 
 
June 30, 2019
 
September 30, 2018
 
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019
$

 
$
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

Unsecured 4.30% Senior Notes, due 2048
600,000

 

Unsecured 4.125% Senior Notes, due 2049
450,000

 

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
3,685,000

 
3,085,000

Less:
 
 
 
Original issue (premium) / discount on unsecured senior notes and debentures
225

 
(4,439
)
Debt issuance cost
30,640

 
20,774

Current maturities
125,000

 
575,000

 
$
3,529,135

 
$
2,493,665


    
(1)
Up to $200 million can be drawn under this term loan.
On March 4, 2019, we completed a public offering of $450 million of 4.125% senior notes due 2049. The effective interest rate of these notes is 4.86%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds, after the underwriting discount and offering expenses, of $443.4 million, together with available cash, was used to repay at maturity our $450 million 8.50% unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps.
On October 4, 2018, we completed a public offering of $600 million of 4.30% senior notes due 2048. We received net proceeds from the offering, after the underwriting discount and offering expenses, of $590.6 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 4.37% after giving effect to the offering costs.
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 driven primarily by construction work in progress and the seasonal nature of the natural gas business. Changes in the price of natural gas and the

14



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 29, 2019, we executed our final one-year extension option which extended the maturity date from September 25, 2022 to September 25, 2023. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a margin 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 June 30, 2019 and September 30, 2018, a total of $74.9 million and $575.8 million was outstanding under our commercial paper program.
Additionally, we have a $25 million 364-day unsecured facility, which was renewed effective April 1, 2019 and expires March 31, 2020, and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At June 30, 2019, 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 June 30, 2019, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 41 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.
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 if not paid at maturity. We were in compliance with all of our debt covenants as of June 30, 2019. 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.


15



7.    Shareholders' Equity

The following tables present a reconciliation of changes in stockholders' equity for the three and nine months ended June 30, 2019 and 2018.
 
Common stock
 
Additional
Paid-in
Capital
 
Accumulated
Other
Comprehensive Income
(Loss)
 
Retained
Earnings
 
Total
 
Number of
Shares
 
Stated
Value
 
 
(In thousands, except share and per share data)
Balance, September 30, 2018
111,273,683

 
$
556

 
$
2,974,926

 
$
(83,647
)
 
$
1,878,116

 
$
4,769,951

Net income

 

 

 

 
157,646

 
157,646

Other comprehensive loss

 

 

 
(22,258
)
 

 
(22,258
)
Cash dividends ($0.525 per share)

 

 

 

 
(58,722
)
 
(58,722
)
Cumulative effect of accounting change (See Note 2)

 

 

 
(8,210
)
 
8,210

 

Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
5,434,812

 
27

 
498,948

 

 

 
498,975

Stock-based compensation plans
184,464

 
1

 
2,602

 

 

 
2,603

Balance, December 31, 2018
116,892,959

 
584

 
3,476,476

 
(114,115
)
 
1,985,250

 
5,348,195

Net income

 

 

 

 
214,888

 
214,888

Other comprehensive loss

 

 

 
(2,695
)
 

 
(2,695
)
Cash dividends ($0.525 per share)

 

 

 

 
(61,606
)
 
(61,606
)
Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
61,006

 
1

 
5,453

 

 

 
5,454

Stock-based compensation plans
28,938

 

 
3,865

 

 

 
3,865

Balance, March 31, 2019
116,982,903

 
585

 
3,485,794

 
(116,810
)
 
2,138,532

 
5,508,101

Net income

 

 

 

 
80,466

 
80,466

Other comprehensive income

 

 

 
1,147

 

 
1,147

Cash dividends ($0.525 per share)

 

 

 

 
(61,654
)
 
(61,654
)
Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
1,127,244

 
5

 
103,425

 

 

 
103,430

Stock-based compensation plans
85,966

 
1

 
10,505

 

 

 
10,506

Balance, June 30, 2019
118,196,113

 
$
591

 
$
3,599,724

 
$
(115,663
)
 
$
2,157,344

 
$
5,641,996



16



 
Common stock
 
Additional
Paid-in
Capital
 
Accumulated
Other
Comprehensive Income
(Loss)
 
Retained
Earnings
 
Total
 
Number of
Shares
 
Stated
Value
 
 
(In thousands, except share and per share data)
Balance, September 30, 2017
106,104,634

 
$
531

 
$
2,536,365

 
$
(105,254
)
 
$
1,467,024

 
$
3,898,666

Net income

 

 

 

 
314,132

 
314,132

Other comprehensive loss

 

 

 
(1,062
)
 

 
(1,062
)
Cash dividends ($0.485 per share)

 

 

 

 
(51,837
)
 
(51,837
)
Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
4,621,518

 
22

 
400,737

 

 

 
400,759

Stock-based compensation plans
235,960

 
2

 
2,960

 

 

 
2,962

Balance, December 31, 2017
110,962,112

 
555

 
2,940,062

 
(106,316
)
 
1,729,319

 
4,563,620

Net income

 

 

 

 
178,992

 
178,992

Other comprehensive income

 

 

 
21,305

 

 
21,305

Cash dividends ($0.485 per share)

 

 

 

 
(54,054
)
 
(54,054
)
Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
76,776

 

 
6,235

 

 

 
6,235

Stock-based compensation plans
21,440

 

 
5,248

 

 

 
5,248

Balance, March 31, 2018
111,060,328

 
555

 
2,951,545

 
(85,011
)
 
1,854,257

 
4,721,346

Net income

 

 

 

 
71,193

 
71,193

Other comprehensive income

 

 

 
8,630

 

 
8,630

Cash dividends ($0.485 per share)

 

 

 

 
(54,116
)
 
(54,116
)
Common stock issued:
 
 
 
 
 
 
 
 
 
 
 
Public and other stock offerings
45,307

 
1

 
3,947

 

 

 
3,948

Stock-based compensation plans
89,813

 

 
8,551

 

 

 
8,551

Balance, June 30, 2018
111,195,448

 
$
556

 
$
2,964,043

 
$
(76,381
)
 
$
1,871,334

 
$
4,759,552


Shelf Registration, At-the-Market Equity Sales Program and Equity Issuances
On November 13, 2018, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $3.0 billion in common stock and/or debt securities, which expires November 13, 2021. This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At June 30, 2019, approximately $1.3 billion of securities remained available for issuance under the shelf registration statement.
On November 19, 2018, 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 (including shares of common stock that may be sold pursuant to a forward sale agreement entered into concurrently with the ATM equity sales program), which expires November 13, 2021. As of June 30, 2019, the ATM program had approximately $231 million of equity available for issuance.
On November 30, 2018, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 5,390,836 shares of our common stock for $500 million. After expenses, net proceeds from the offering were $494.1 million. Concurrently, we entered into separate forward sale agreements with two forward sellers, collectively referred to as the block.


17



The following table presents information relevant to the forward sales during fiscal year 2019.
Maturity
 
September 30, 2020
 
March 31, 2020
 
Total
 
 
Shares
Price(1)
Proceeds
(in millions)
 
Shares
Price(1)
Proceeds
(in millions)
 
Shares
Price(1)
Proceeds
 (in millions)
Available Balance
September 30, 2018
 

$

$

 

$

$

 

$

$

Issued via Block
 


 
 
2,668,464

91.77

 
 
2,668,464

91.77

 
Available Balance
 December 31, 2018 (2)
 



 
2,668,464

91.90

245.2

 
2,668,464

91.90

245.2

Issued via ATM
 


 
 
1,670,509

95.46

 
 
1,670,509

95.46

 
Available Balance
 March 31, 2019 (2)
 



 
4,338,973

93.08

403.9

 
4,338,973

93.08

403.9

Issued via ATM
 
1,050,563

101.41

 
 


 
 
1,050,563

101.41

 
Settled Block
 


 
 
(1,089,700
)
91.44

 
 
(1,089,700
)
91.44

 
Available Balance
June 30, 2019 (2)
 
1,050,563

$
101.11

$
106.2

 
3,249,273

$
93.34

$
303.3

 
4,299,836

$
95.24

$
409.5


(1)
Issued price as disclosed is calculated as the weighted average price for activity occurring during the quarter.
(2)
If we had settled all shares available under the forward agreements as of the period end, including forward price adjustments, we would receive proceeds based on the stated net price.
On November 30, 2017, we filed a prospectus supplement under the previous registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common stock for $400 million. After expenses, net proceeds from the offering were $395.1 million.

Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in AOCI related to available-for-sale debt securities and interest rate agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt securities 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(1)
 
Interest Rate
Agreement
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2018
$
8,124

 
$
(91,771
)
 
$
(83,647
)
Other comprehensive income (loss) before reclassifications
192

 
(25,966
)
 
(25,774
)
Amounts reclassified from accumulated other comprehensive income
(1
)
 
1,969

 
1,968

Net current-period other comprehensive income (loss)
191

 
(23,997
)
 
(23,806
)
Cumulative effect of accounting change (See Note 2)
(8,210
)
 

 
(8,210
)
June 30, 2019
$
105

 
$
(115,768
)
 
$
(115,663
)

 
 
Available-
for-Sale
Securities(1)
 
Interest Rate
Agreement
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2017
$
7,048

 
$
(112,302
)
 
$
(105,254
)
Other comprehensive income before reclassifications
148

 
28,315

 
28,463

Amounts reclassified from accumulated other comprehensive income
(884
)
 
1,294

 
410

Net current-period other comprehensive income (loss)
(736
)
 
29,609

 
28,873

June 30, 2018
$
6,312

 
$
(82,693
)
 
$
(76,381
)


(1)
Available-for-sale-securities reported in fiscal 2018 include both debt and equity securities, while fiscal 2019 includes only debt securities. See Note 2 for further discussion regarding our adoption of the new accounting standard.

18




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 nine months ended June 30, 2019 and 2018 are presented in the following tables. Most of these costs are recoverable through our tariff rates. A portion of these costs is capitalized into our rate base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-operating expense.
 
Three Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,044

 
$
4,794

 
$
2,702

 
$
3,020

Interest cost(1)
6,799

 
6,448

 
2,960

 
2,726

Expected return on assets(1)
(7,113
)
 
(6,917
)
 
(2,664
)
 
(2,002
)
Amortization of prior service cost (credit)(1)
(57
)
 
(57
)
 
43

 
2

Amortization of actuarial (gain) loss(1)
1,606

 
3,050

 
(2,045
)
 
(1,618
)
Settlements(1)

 
888

 

 

Net periodic pension cost
$
5,279

 
$
8,206

 
$
996

 
$
2,128


 
Nine Months Ended June 30
 
Pension Benefits
 
Other Benefits
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
12,134

 
$
13,929

 
$
8,107

 
$
9,059

Interest cost(1)
20,399

 
19,311

 
8,879

 
8,180

Expected return on assets(1)
(21,339
)
 
(20,750
)
 
(7,994
)
 
(6,005
)
Amortization of prior service cost (credit)(1)
(173
)
 
(173
)
 
130

 
8

Amortization of actuarial (gain) loss(1)
4,821

 
9,224

 
(6,134
)
 
(4,855
)
Settlements(1)

 
3,303

 

 

Net periodic pension cost
$
15,842

 
$
24,844

 
$
2,988

 
$
6,387



(1)
The components of net periodic cost other than the service cost component are included in the line item other non-operating expense in the condensed consolidated statement of comprehensive income or are capitalized on the condensed consolidated balance sheets as a regulatory asset or liability, as described in Note 2.

 
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.
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

19



Texas (RRC) 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. In May 2019, the parties resolved the civil action to their mutual satisfaction subject to our self-insured retention noted above.
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. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. At June 30, 2019, we were committed to purchase 53.9 Bcf within one year and 1.8 Bcf within two to three years under indexed contracts.
Leases
We have entered into operating leases for towers, office and warehouse space, vehicles and heavy equipment used in our operations. During the nine months ended June 30, 2019, we executed amendments to some of our lease agreements that impacted terms as well as our future minimum lease payments. As of June 30, 2019, the remaining lease terms range from one to 20 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases. The related future minimum lease payments at June 30, 2019 totaled $194.9 million.
Rate Regulatory Proceedings
Except for routine rate regulatory proceedings as discussed below, there were no material changes to rate regulatory proceedings for the nine months ended June 30, 2019.
As of June 30, 2019, rate regulatory proceedings were in progress in some of our service areas. These rate regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments. Additionally, as discussed in further detail in Note 13, all jurisdictions are addressing impacts of the Tax Cuts and Jobs Act of 2017 (the "TCJA").

10.    Financial Instruments
We currently use financial instruments to mitigate commodity price risk and in the past have also used financial instruments to mitigate 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, 2018. During the nine months ended June 30, 2019, 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.
We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2018-2019 heating season (generally October through March), in the jurisdictions where we are permitted

20



to utilize financial instruments, we hedged approximately 33 percent, or 18.9 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Interest Rate Risk Management Activities
Historically, we managed interest rate risk by periodically entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
In fiscal 2014 and 2015, we entered into forward starting interest rate swaps to fix the Treasury yield component associated with $450 million of the then anticipated issuance of $450 million unsecured senior notes in fiscal 2019. These notes were issued as planned in March 2019 and we settled the swaps with the payment of $90.1 million. Because the swaps were effective, the realized loss was recorded as a component of AOCI and is being recognized as a component of interest expense over the 30-year life of the senior notes.
As of June 30, 2019, we had $115.8 million of net realized losses in 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 2049.
 
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 statements of comprehensive income.
As of June 30, 2019, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of June 30, 2019, we had 16,784 MMcf of net long 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 June 30, 2019 and September 30, 2018. 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. However, for June 30, 2019 and September 30, 2018, no gross amounts and no cash collateral were netted within our consolidated balance sheet.
 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
June 30, 2019
 
 
 
 
 
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$
2,408

 
$
(3,358
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
149

 
(513
)
Total
 
 
2,557

 
(3,871
)
Gross / Net Financial Instruments
 
 
$
2,557

 
$
(3,871
)

 

21



 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2018
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate swaps
Other current assets /
Other current liabilities
 
$

 
$
(56,499
)
Total
 
 

 
(56,499
)
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
1,369

 
(235
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
250

 
(103
)
Total
 
 
1,619

 
(338
)
Gross / Net Financial Instruments
 
 
$
1,619

 
$
(56,837
)
 
Impact of Financial Instruments on the Statement of Comprehensive Income
Cash Flow Hedges
As discussed above, in the past our distribution segment had interest rate agreements, which we designated as cash flow hedges at the time the agreements were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of comprehensive income for the three months ended June 30, 2019 and 2018 was $1.4 million and $0.6 million and for the nine months ended June 30, 2019 and 2018 was $2.6 million and $1.8 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 nine months ended June 30, 2019 and 2018. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the statement of comprehensive income as incurred.
 
Three Months Ended June 30
 
Nine Months Ended June 30
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
 
 
 
 
Interest rate agreements
$

 
$
7,861

 
$
(25,966
)
 
$
28,315

Recognition of losses in earnings due to settlements:
 
 
 
 
 
 
 
Interest rate agreements
1,053

 
459

 
1,969

 
1,294

Total other comprehensive income (loss) from hedging, net of tax
$
1,053

 
$
8,320

 
$
(23,997
)
 
$
29,609


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 June 30, 2019, 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.
 
Interest Rate
Agreements
 
(In thousands)
Next twelve months
$
(4,212
)
Thereafter
(111,556
)
Total
$
(115,768
)





22




Financial Instruments Not Designated as Hedges
As discussed above, commodity contracts which are 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 comprehensive 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, 2018. During the nine months ended June 30, 2019, 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, 2018.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2019 and September 30, 2018. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral
 
June 30, 2019
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
2,557

 
$

 
$

 
$
2,557

Debt and equity securities
 
 
 
 
 
 
 
 
 
Registered investment companies
43,798

 

 

 

 
43,798

Bond mutual funds
25,778

 

 

 

 
25,778

Bonds(2)

 
31,097

 

 

 
31,097

Money market funds

 
1,369

 

 

 
1,369

Total debt and equity securities
69,576

 
32,466

 

 

 
102,042

Total assets
$
69,576

 
$
35,023

 
$

 
$

 
$
104,599

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
3,871

 
$

 
$

 
$
3,871



23



 
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, 2018
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
1,619

 
$

 
$

 
$
1,619

Debt and equity securities
 
 
 
 
 
 
 
 
 
Registered investment companies
42,644

 

 

 

 
42,644

Bond mutual funds
21,507

 

 

 

 
21,507

Bonds(2)

 
31,400

 

 

 
31,400

Money market funds

 
3,834

 

 

 
3,834

Total debt and equity securities
64,151

 
35,234

 

 

 
99,385

Total assets
$
64,151

 
$
36,853

 
$

 
$

 
$
101,004

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
56,837

 
$

 
$

 
$
56,837


 
(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 that are valued at cost.
(2)
Our investments in bonds are considered available-for-sale debt securities in accordance with current accounting guidance as described in Note 2.
Debt and equity securities are comprised of our available-for-sale debt securities and our equity securities. We regularly evaluate the performance of our available-for-sale debt securities on an investment by investment basis for impairment, taking into consideration the investment’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related investment is written down to its estimated fair value and the other-than-temporary impairment is recognized in the statement of comprehensive income. At June 30, 2019 and September 30, 2018, our available-for-sale debt securities amortized cost was $31.0 million and $31.5 million. At June 30, 2019, we maintained investments in bonds that have contractual maturity dates ranging from July 2019 through February 2022.
Other Fair Value Measures
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of June 30, 2019 and September 30, 2018:
 
June 30, 2019
 
September 30, 2018
 
(In thousands)
Carrying Amount
$
3,685,000

 
$
3,085,000

Fair Value
$
4,144,253

 
$
3,161,679



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, 2018. During the nine months ended June 30, 2019, there were no material changes in our concentration of credit risk.

13.    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. As a result of the implementation of the TCJA, we recognized a $165.5 million income tax benefit in our condensed consolidated statement of comprehensive income during the nine months ended June 30, 2018 related to a change in deferred taxes that were not related to our cost of service ratemaking. The change in deferred taxes related to our cost of service ratemaking (referred to as excess deferred taxes) was reclassified into a regulatory liability and will be returned to ratepayers in accordance with regulatory requirements. As of June 30, 2019 and September 30, 2018, this liability totaled $731.8 million and $744.9 million.

24



We have worked and continue to work with our regulators in each jurisdiction to fully incorporate the effects of the TCJA into customer bills. As of June 30, 2019, we have received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in all of our service areas.
Regulators in all of our service areas issued accounting orders that required us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that were calculated based on a 35% statutory income tax rate and rates based on the new 21% statutory income tax rate until the new rates could be established. As of June 30, 2019, we received approval from substantially all regulators to return these liabilities to customers. This regulatory liability totaled $6.1 million and $22.5 million as of June 30, 2019 and September 30, 2018.
As of June 30, 2019, we received approval from regulators to return excess deferred taxes in most of our jurisdictions in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to 51 years. In our remaining jurisdictions, the treatment of the effects of the TCJA in rates is being addressed in ongoing or will be addressed in future regulatory proceedings.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allowed us to record provisional amounts during a one-year measurement period, similar to the measurement period in accounting for business combinations. The Company recorded provisional amounts for the income tax effects of the TCJA for the fiscal year ended September 30, 2018. Although the Company no longer considers the accounting effects of the TCJA to be provisional under SAB 118, many aspects of the TCJA remain unclear and its impact on the Company's income tax balances may change following further interpretation of TCJA provisions by issuance of U.S. Treasury regulations or guidance from the Internal Revenue Service. We continue to monitor and assess the accounting implications of the TCJA developments on the consolidated financial statements.

25



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of Atmos Energy Corporation

Results of Review of Interim Financial Statements
We have reviewed the accompanying condensed consolidated balance sheet of Atmos Energy Corporation as of June 30, 2019, the related condensed consolidated statements of comprehensive income for the three and nine month periods ended June 30, 2019 and 2018, the condensed consolidated statements of cash flows for the nine month periods ended June 30, 2019 and 2018 and the related notes (collectively referred to as the "condensed consolidated interim financial statements"). Based on our reviews, we are not aware of any material modifications that should be made to the condensed consolidated interim financial statements 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) (PCAOB), the consolidated balance sheet of the Company as of September 30, 2018, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and related notes and schedule (not presented herein); and in our report dated November 13, 2018, 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, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
These financial statements are the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the SEC and the PCAOB. We conducted our review in accordance with the standards of the PCAOB. A review of interim financial statements 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 PCAOB, 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.
/s/    ERNST & YOUNG LLP
Dallas, Texas
August 7, 2019

26



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, 2018.
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: state and local regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; 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; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; 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; the impact of climate change or related additional legislation or regulation in the future; 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 June 30, 2019 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.

27



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, 2018 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 nine months ended June 30, 2019.

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 condensed consolidated statements of comprehensive income 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 13, 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 non-cash income tax benefit of $165.5 million for the nine months ended June 30, 2018. Due to the non-recurring nature of this benefit, we believe that net income and diluted net income per share before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than net income and diluted net income per share in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis to the prior year. Accordingly, the following discussion and analysis of our financial performance will reference adjusted net income and adjusted diluted earnings per share, non-GAAP financial measures, which are calculated as follows:
 
 
 
 
 
 
 
Nine Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands, except per share data)
Net income
$
453,000

 
$
564,317

 
$
(111,317
)
TCJA non-cash income tax benefit

 
(165,522
)
 
165,522

Adjusted net income
$
453,000

 
$
398,795

 
$
54,205

 
 
 
 
 
 
Diluted net income per share
$
3.88

 
$
5.09

 
$
(1.21
)
Diluted EPS from TCJA non-cash income tax benefit

 
(1.49
)
 
1.49

Adjusted diluted net income per share
$
3.88

 
$
3.60

 
$
0.28



28



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 a significant level of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs and mechanisms 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 nine months ended June 30, 2019, we recorded net income of $453.0 million, or $3.88 per diluted share, compared to net income of $564.3 million, or $5.09 per diluted share for the nine months ended June 30, 2018.
After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income of $398.8 million, or $3.60 per diluted share for the nine months ended June 30, 2018. The period-over-period increase in adjusted net income of $54.2 million, or 14 percent, largely reflects positive rate outcomes, customer growth in our distribution business, positive Contribution Margins in our pipeline and storage business due to positive supply and demand dynamics affecting the Permian Basin primarily due to wider spreads and the impact of the TCJA on our effective income tax rate. During the nine months ended June 30, 2019, we implemented ratemaking regulatory actions which resulted in an increase in annual operating income of $102.9 million and had seven ratemaking efforts in progress at June 30, 2019, seeking a total increase in annual operating income of $79.9 million.
Capital expenditures for the nine months ended June 30, 2019 increased 10 percent period-over-period, to $1.2 billion. 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 range from $1.65 billion to $1.75 billion for fiscal 2019. We funded our capital expenditures program primarily through operating cash flows of $808.9 million. Additionally, we completed over $2 billion in external financing during the nine months ended June 30, 2019 with the issuance of $1.1 billion in 30-year senior notes and approximately $1.0 billion of common stock, of which approximately $417 million was allocated to forward sale agreements which have not yet been settled. The net proceeds from these issuances, together with available cash, were used to repay at maturity our $450 million 8.50% unsecured senior notes, 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 8.2 percent for fiscal 2019.
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, 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 to minimize regulatory lag and, ultimately, separate the recovery of our approved rates 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 have 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. We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of

29



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 revenue-related taxes arising from changes in gas costs affect Contribution Margin, over time the impact is offset within operating income.
Although the cost of gas typically does not have a direct impact on our Contribution Margin, higher gas costs 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. Currently, gas cost risk has been mitigated by rate design that allows 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 June 30, 2019 compared with Three Months Ended June 30, 2018
Financial and operational highlights for our distribution segment for the three months ended June 30, 2019 and 2018 are presented below.
 
Three Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
444,944

 
$
535,488

 
$
(90,544
)
Purchased gas cost
139,518

 
230,887

 
(91,369
)
Contribution Margin
305,426

 
304,601

 
825

Operating expenses
256,743

 
241,492

 
15,251

Operating income
48,683

 
63,109

 
(14,426
)
Other non-operating income (expense)
3,005

 
(2,518
)
 
5,523

Interest charges
10,597

 
13,315

 
(2,718
)
Income before income taxes
41,091

 
47,276

 
(6,185
)
Income tax expense
8,693

 
11,932

 
(3,239
)
Net income
$
32,398

 
$
35,344

 
$
(2,946
)
Consolidated distribution sales volumes — MMcf
41,683

 
49,369

 
(7,686
)
Consolidated distribution transportation volumes — MMcf
34,509

 
33,079

 
1,430

Total consolidated distribution throughput — MMcf
76,192

 
82,448

 
(6,256
)
Consolidated distribution average cost of gas per Mcf sold
$
3.35

 
$
4.68

 
$
(1.33
)
Income before income taxes for our distribution segment decreased 13 percent, primarily due to a $15.3 million increase in operating expenses, slightly offset by an $0.8 million increase in Contribution Margin and a $5.5 million increase in other non-operating income. The quarter-over-quarter increase in Contribution Margin primarily reflects:
a $7.1 million net increase in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex and West Texas Divisions.
a $2.9 million increase from customer growth primarily in our Mid-Tex Division.
a $3.8 million decrease in residential and commercial net consumption, primarily due to warmer weather than the prior year period.
a $4.6 million decrease in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $7.1 million decrease in the related tax expense.
Operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $15.3 million, primarily due to:
a $9.0 million increase in pipeline maintenance and related activities.
a $7.4 million increase in depreciation expense and property taxes associated with increased capital investments.
a $4.5 million increase in employee and training costs as we have increased service-related headcount to support operations in our fastest growing service territories.
These increases are partially offset by a decrease in revenue-related taxes of $7.1 million, corresponding to the decrease in revenue-related taxes within Contribution Margin as described above.

30



Additionally, the quarter-over-quarter increase in other non-operating income primarily reflects the adoption of new accounting standards. As discussed further in Note 2, we are now required to recognize changes in the fair value of our equity securities formerly designated as available-for-sale on our condensed consolidated statement of comprehensive income and the components of net periodic cost other than the service cost component are included in the line item other non-operating expense in the condensed consolidated statement of comprehensive income.
The following table shows our operating income by distribution division, in order of total rate base, for the three months ended June 30, 2019 and 2018. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Three Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands)
Mid-Tex
$
23,757

 
$
24,612

 
$
(855
)
Kentucky/Mid-States
10,486

 
11,546

 
(1,060
)
Louisiana
8,517

 
10,821

 
(2,304
)
West Texas
5,053

 
5,135

 
(82
)
Mississippi
1,694

 
5,421

 
(3,727
)
Colorado-Kansas
2,399

 
2,043

 
356

Other
(3,223
)
 
3,531

 
(6,754
)
Total
$
48,683

 
$
63,109

 
$
(14,426
)

Nine Months Ended June 30, 2019 compared with Nine Months Ended June 30, 2018
Financial and operational highlights for our distribution segment for the nine months ended June 30, 2019 and 2018 are presented below.
 
Nine Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
2,341,668

 
$
2,595,571

 
$
(253,903
)
Purchased gas cost
1,147,598

 
1,421,698

 
(274,100
)
Contribution Margin
1,194,070

 
1,173,873

 
20,197

Operating expenses
746,987

 
725,666

 
21,321

Operating income
447,083

 
448,207

 
(1,124
)
Other non-operating income (expense)
1,791

 
(5,961
)
 
7,752

Interest charges
44,703

 
51,581

 
(6,878
)
Income before income taxes
404,171

 
390,665

 
13,506

TCJA non-cash income tax benefit

 
(143,789
)
 
143,789

Income tax expense
85,195

 
104,768

 
(19,573
)
Net income
$
318,976

 
$
429,686

 
$
(110,710
)
Consolidated distribution sales volumes — MMcf
282,623

 
269,722

 
12,901

Consolidated distribution transportation volumes — MMcf
121,747

 
117,061

 
4,686

Total consolidated distribution throughput — MMcf
404,370

 
386,783

 
17,587

Consolidated distribution average cost of gas per Mcf sold
$
4.06

 
$
5.27

 
$
(1.21
)
Income before income taxes for our distribution segment increased three percent, primarily due to a $20.2 million increase in Contribution Margin, a combined $14.6 million decrease in other non-operating expense and interest charges, partially offset by a $21.3 million increase in operating expenses. The year-over-year increase in Contribution Margin primarily reflects:
a $23.8 million net increase in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex and Mississippi Divisions.
a $10.6 million increase from customer growth primarily in our Mid-Tex Division.

31



an $8.7 million decrease in revenue-related taxes primarily in our Mid-Tex Division, partially offset by a corresponding $7.8 million decrease in the related tax expense.
a $4.7 million decrease in residential and commercial net consumption.
Operating expenses increased $21.3 million primarily due to:
a $22.8 million increase in depreciation expense and property taxes associated with increased capital investments.
an $11.7 million increase in pipeline maintenance and related activities.
a $6.6 million increase in employee and training costs as we have increased service-related headcount to support operations in our fastest growing service territories.
a $3.0 million increase in software licensing fees.
These increases are partially offset by a $24 million decrease in nonrecurring expenses related to the planned outage of our natural gas distribution system in Northwest Dallas in March 2018.
The year-over-year increase in other non-operating income primarily reflects the adoption of new accounting standards. As discussed further in Note 2, we are now required to recognize changes in the fair value of our equity securities formerly designated as available-for-sale on our condensed consolidated statement of comprehensive income and the components of net periodic cost other than the service cost component are included in the line item other non-operating expense in the condensed consolidated statement of comprehensive income.
Additionally, the year-over-year decrease in interest charges reflects higher capitalized interest associated with increased capital spending.
The decrease in income tax expense reflects a reduction in our effective tax rate from 26.8% to 21.1%, as a result of the TCJA, as described above.
The following table shows our operating income by distribution division, in order of total rate base, for the nine months ended June 30, 2019 and 2018. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

 
Nine Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands)
Mid-Tex
$
189,294

 
$
175,727

 
$
13,567

Kentucky/Mid-States
69,960

 
76,204

 
(6,244
)
Louisiana
63,571

 
64,849

 
(1,278
)
West Texas
41,797

 
42,326

 
(529
)
Mississippi
48,392

 
48,792

 
(400
)
Colorado-Kansas
35,892

 
32,448

 
3,444

Other
(1,823
)
 
7,861

 
(9,684
)
Total
$
447,083

 
$
448,207

 
$
(1,124
)

Recent Ratemaking Developments
The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first nine months of fiscal 2019, we implemented twenty regulatory proceedings, resulting in a $53.7 million increase in annual operating income as summarized below. The ratemaking outcomes for rate case activity in fiscal 2019 include the effect of tax reform legislation enacted effective January 1, 2018 and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit we will receive due to the decrease in our statutory tax rate.
Rate Action
 
Annual Increase in
Operating Income
 
 
(In thousands)
Annual formula rate mechanisms
 
$
51,870

Rate case filings
 
1,656

Other rate activity
 
214

 
 
$
53,740


32




The following ratemaking efforts seeking $79.9 million in increased annual operating income were in progress as of June 30, 2019:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income Requested
 
 
 
 
 
 
(In thousands)
Colorado-Kansas
 
Rate Case
 
Kansas
 
$
3,697

Kentucky/Mid-States
 
Infrastructure Mechanism
 
Virginia
 
85

Louisiana
 
Formula Rate Mechanism
 
LGS (1)
 
7,124

Mid-Tex
 
Formula Rate Mechanism
 
Mid-Tex Cities
 
47,733

Mid-Tex
 
Infrastructure Mechanism
 
ATM Cities
 
6,591

Mississippi
 
Infrastructure Mechanism
 
Mississippi (2)
 
8,433

West Texas
 
Formula Rate Mechanism
 
West Texas Cities
 
6,226

 
 
 
 
 
 
$
79,889


(1)
On June 19, 2019, the Louisiana Public Service Commission approved this filing with rates to be implemented beginning July 1, 2019.
(2)
On July 1, 2019, we updated this filing to increase the amount requested to $8.6 million.

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)
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.


33



The following annual formula rate mechanisms, which reflect a 21% federal income tax rate resulting from the TCJA, were approved during the nine months ended June 30, 2019:
Division
 
Jurisdiction
 
Test Year
Ended
 
Increase (Decrease) in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2019 Filings:
 
 
 
 
 
 
 
 
Mid-Tex
 
Environs
 
12/31/2018
 
$
2,435

 
06/04/2019
West Texas
 
Environs
 
12/31/2018
 
1,005

 
06/04/2019
Mid-Tex
 
DARR (1)
 
09/30/2018
 
9,452

 
06/01/2019
Kentucky/Mid-States
 
Tennessee ARM
 
05/31/2020
 
2,393

 
06/01/2019
West Texas
 
Amarillo, Lubbock, Dalhart and Channing
 
12/31/2018
 
5,692

 
05/01/2019
Colorado-Kansas
 
Kansas GSRS
 
12/31/2018
 
1,562

 
05/01/2019
Louisiana
 
Trans La
 
09/30/2018
 
4,719

 
04/01/2019
Colorado-Kansas
 
Colorado GIS
 
12/31/2019
 
87

 
04/01/2019
Colorado-Kansas
 
Colorado SSIR
 
12/31/2019
 
2,147

 
01/01/2019
Mississippi
 
Mississippi - SIR
 
10/31/2019
 
7,135

 
11/01/2018
Mississippi
 
Mississippi - SRF
 
10/31/2019
 
(118
)
 
11/01/2018
Kentucky/Mid-States
 
Tennessee ARM
 
05/31/2019
 
(5,032
)
 
10/15/2018
Mid-Tex
 
Mid-Tex RRM Cities
 
12/31/2017
 
17,633

 
10/01/2018
West Texas
 
West Texas Cities RRM
 
12/31/2017
 
2,760

 
10/01/2018
Total 2019 Filings
 
 
 
 
 
$
51,870

 
 

(1)
The Company and the City of Dallas were unable to arrive at a mutually agreeable settlement; therefore the DARR rates were implemented subject to refund, pending the outcome of an appeal filed with the Texas Railroad Commission.
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, which reflect a 21% federal income tax rate resulting from the TCJA, that were completed during the nine months ended June 30, 2019.
Division
 
State
 
Increase (Decrease) in Annual
Operating Income
 
Effective
Date
 
 
 
 
(In thousands)
 
 
2019 Rate Case Filings:
 
 
 
 
 
 
Mid-Tex (ATM Cities)
 
Texas
 
$
2,113

 
06/01/2019
Kentucky/Mid-States
 
Kentucky
 
3,441

 
05/08/2019
Kentucky/Mid-States
 
Virginia
 
(400
)
 
04/01/2019
Mid-Tex (Environs)
 
Texas
 
(2,674
)
 
01/01/2019
West Texas (Environs)
 
Texas
 
(824
)
 
01/01/2019
Total 2019 Rate Case Filings
 
 
 
$
1,656

 
 

34



Other Ratemaking Activity
The following table summarizes other ratemaking activity during the nine months ended June 30, 2019.
Division
 
Jurisdiction
 
Rate Activity
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
 
 
(In thousands)
 
 
2019 Other Rate Activity:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Kansas
 
Ad Valorem (1)
 
$
214

 
02/01/2019
Total 2019 Other Rate Activity
 
 
 
 
 
$
214

 
 

(1)
The Ad Valorem filing relates to property taxes that are either over or undercollected compared to 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 and eastern 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 distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas.
Our natural gas transmission operations in Louisiana are comprised of a 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 supply areas that we serve, which may influence the level of throughput we may be able to transport on our pipelines. 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 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. On February 15, 2019, APT made a GRIP filing that covered changes in net investment from January 1, 2018 through December 31, 2018 with a requested increase in operating income of $49.2 million. On May 7, 2019, the Texas Railroad Commission approved the Company's GRIP filing.

35



Three Months Ended June 30, 2019 compared with Three Months Ended June 30, 2018
Financial and operational highlights for our pipeline and storage segment for the three months ended June 30, 2019 and 2018 are presented below.
 
Three Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue
$
94,092

 
$
83,592

 
$
10,500

Third-party transportation revenue
50,801

 
40,515

 
10,286

Other revenue
4,305

 
3,526

 
779

Total operating revenues
149,198

 
127,633

 
21,565

Total purchased gas cost
(96
)
 
561

 
(657
)
Contribution Margin
149,294

 
127,072

 
22,222

Operating expenses
75,775

 
65,861

 
9,914

Operating income
73,519

 
61,211

 
12,308

Other non-operating expense
(1,360
)
 
(812
)
 
(548
)
Interest charges
8,995

 
10,034

 
(1,039
)
Income before income taxes
63,164

 
50,365

 
12,799

Income tax expense
15,096

 
14,516

 
580

Net income
$
48,068

 
$
35,849

 
$
12,219

Gross pipeline transportation volumes — MMcf
214,627

 
215,775

 
(1,148
)
Consolidated pipeline transportation volumes — MMcf
181,292

 
180,371

 
921

Income before income taxes for our pipeline and storage segment increased 25 percent, primarily due to a $22.2 million increase in Contribution Margin, partially offset by a $9.9 million increase in operating expenses. The quarter-over-quarter increase in Contribution Margin primarily reflects:
a $16.5 million net increase in rate adjustments, after the effect of the TCJA, primarily from the approved GRIP filings approved in May 2018 and May 2019. The increase in rates was driven primarily by increased safety and reliability spending.
a net increase of $4.5 million from positive supply and demand dynamics affecting the Permian Basin, primarily due to wider spreads.
Operating expenses increased $9.9 million, primarily due to higher depreciation expense associated with increased capital investments and higher system maintenance expense of $6.7 million primarily due to spending on hydro testing and in-line inspections.

36



Nine Months Ended June 30, 2019 compared with Nine Months Ended June 30, 2018
Financial and operational highlights for our pipeline and storage segment for the nine months ended June 30, 2019 and 2018 are presented below.
 
Nine Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue
$
276,815

 
$
267,121

 
$
9,694

Third-party transportation revenue
131,623

 
97,860

 
33,763

Other revenue
10,880

 
10,070

 
810

Total operating revenues
419,318

 
375,051

 
44,267

Total purchased gas cost
(544
)
 
1,906

 
(2,450
)
Contribution Margin
419,862

 
373,145

 
46,717

Operating expenses
210,602

 
184,047

 
26,555

Operating income
209,260

 
189,098

 
20,162

Other non-operating expense
(3,637
)
 
(2,093
)
 
(1,544
)
Interest charges
29,687

 
30,581

 
(894
)
Income before income taxes
175,936

 
156,424

 
19,512

TCJA non-cash income tax benefit

 
(21,733
)
 
21,733

Income tax expense
41,912

 
43,526

 
(1,614
)
Net income
$
134,024

 
$
134,631

 
$
(607
)
Gross pipeline transportation volumes — MMcf
708,315

 
666,079

 
42,236

Consolidated pipeline transportation volumes — MMcf
517,188

 
484,456

 
32,732

Income before income taxes for our pipeline and storage segment increased 12 percent, primarily due to a $46.7 million increase in Contribution Margin, partially offset by a $26.6 million increase in operating expenses. The year-over-year increase in Contribution Margin primarily reflects:
a $33.3 million net increase in rate adjustments, after the effect of the TCJA, from the approved GRIP filings approved in December 2017, May 2018 and May 2019. The increase in rates was driven primarily by increased safety and reliability spending.
a net increase of $9.4 million primarily from positive supply and demand dynamics affecting the Permian Basin, primarily due to wider spreads.
Operating expenses increased $26.6 million, primarily due to higher depreciation expense of $9.5 million associated with increased capital investments and higher system maintenance expense of $13.8 million primarily due to spending on hydro testing and in-line inspections.
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 2019 and beyond.
To continue to support our capital market activities, we filed a registration statement with the SEC on November 13, 2018 that permits us to issue a total of $3.0 billion in common stock and/or debt securities. This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At June 30, 2019, approximately $1.3 billion of securities remained available for issuance under the shelf registration statement.
On November 19, 2018, 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

37



of $500 million (including shares of common stock that may be sold pursuant to forward sale agreements entered into concurrently with the ATM equity sales program). At June 30, 2019, approximately $231 million remained available under the ATM equity sales program.
During the nine months ended June 30, 2019, we completed over $2 billion of long-term debt and equity financing.
In October 2018, we completed the public offering of $600 million of 30-year 4.30% senior notes. The net proceeds of $590.6 million were used to repay working capital borrowings pursuant to our commercial paper program.

In November 2018, we sold 5,390,836 shares of common stock for $500 million. The net proceeds of $494.1 million were used to fund our capital expenditure program and for general corporate purposes.

In March 2019, we completed the public offering of $450 million of 30-year 4.125% senior notes. The net proceeds of $443.4 million, together with available cash, were used to repay at maturity our $450 million 8.50% 10-year unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps for $90.1 million.

In November 2018, February 2019 and May 2019, we executed forward sales with various forward sellers who borrowed and sold 5,389,536 million shares of our common stock for initial aggregate proceeds of approximately $516 million.

In May 2019, we settled forward sale agreements for 1,089,700 million shares of common stock based on a net price of $91.44 per share for net proceeds of $99.6 million.

The following table summarizes the remaining availability under our various forward sales as of June 30, 2019:
Issue Quarter
Issued Under
Shares Available
Net Proceeds Available
(In thousands)
Maturity
Forward Price
December 31, 2018
Block
1,578,764

$
144,608

3/31/2020
$
91.60

March 31, 2019
ATM
1,670,509

158,684

3/31/2020
$
94.99

June 30, 2019
ATM
1,050,563

106,219

9/30/2020
$
101.11

Total
 
4,299,836

$
409,511

 
 

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of June 30, 2019September 30, 2018 and June 30, 2018:
 
 
June 30, 2019
 
September 30, 2018
 
June 30, 2018
 
(In thousands, except percentages)
Short-term debt
$
74,942

 
0.8
%
 
$
575,780

 
6.8
%
 
$
244,777

 
3.0
%
Long-term debt(1)
3,654,135

 
39.0
%
 
3,068,665

 
36.5
%
 
3,068,315

 
38.0
%
Shareholders’ equity
5,641,996

 
60.2
%
 
4,769,951

 
56.7
%
 
4,759,552

 
59.0
%
Total
$
9,371,073

 
100.0
%
 
$
8,414,396

 
100.0
%
 
$
8,072,644

 
100.0
%

(1)
In September 2019, our $125 million term loan, which we plan to refinance, will mature.

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

38



Cash flows from operating, investing and financing activities for the nine months ended June 30, 2019 and 2018 are presented below.
 
Nine Months Ended June 30
 
2019
 
2018
 
Change
 
(In thousands)
Total cash provided by (used in)
 
 
 
 
 
Operating activities
$
808,928

 
$
1,035,296

 
$
(226,368
)
Investing activities
(1,195,401
)
 
(1,087,224
)
 
(108,177
)
Financing activities
418,865

 
46,449

 
372,416

Change in cash and cash equivalents
32,392

 
(5,479
)
 
37,871

Cash and cash equivalents at beginning of period
13,771

 
26,409

 
(12,638
)
Cash and cash equivalents at end of period
$
46,163

 
$
20,930

 
$
25,233

Cash flows from operating activities
For the nine months ended June 30, 2019, we generated cash flow from operating activities of $808.9 million compared with $1,035.3 million for the nine months ended June 30, 2018. The $226.4 million decrease in operating cash flows is primarily attributable to the change in net income and working capital changes, particularly in our distribution segment resulting from the timing of payments for natural gas purchases and deferred gas cost recoveries.
Cash flows from investing activities
Our capital expenditures are primarily used to improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and to enhance and expand our system to meet customer needs. Over the last three fiscal years, approximately 82 percent of our capital spending has been committed to improving the safety and reliability of our system.
We allocate our capital spending among our service areas using risk management models and subject matter experts to identify, assess and develop a plan of action to address our highest risk facilities. We have regulatory mechanisms in most of our service areas that provide the opportunity to include approved capital costs in rate base on a periodic basis without being required to file a rate case. These mechanisms permit us a reasonable opportunity to earn a fair return on our investment without compromising safety or reliability.
For the nine months ended June 30, 2019, cash used for investing activities was $1.2 billion compared to $1.1 billion for the nine months ended June 30, 2018. Capital spending increased by $110.7 million, or 10 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.
Cash flows from financing activities
For the nine months ended June 30, 2019, our financing activities provided $418.9 million of cash compared with $46.4 million of cash provided by financing activities in the prior-year period.
In the nine months ended June 30, 2019, we received $1.6 billion in net proceeds from the issuance of long-term debt and equity. The net proceeds were used primarily to support capital spending, reduce short term debt, repay at maturity our $450 million 8.50% unsecured senior notes and the settlement of related interest rate swaps for $90.1 million and for other general corporate purposes. Cash dividends increased due to an 8.2 percent increase in our dividend rate and an increase in shares outstanding.
In the nine months ended June 30, 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.

39



The following table summarizes our share issuances for the nine months ended June 30, 2019 and 2018:
 
Nine Months Ended June 30
 
2019
 
2018
Shares issued:
 
 
 
Direct Stock Purchase Plan
78,697

 
111,727

1998 Long-Term Incentive Plan
299,368

 
347,213

Retirement Savings Plan and Trust
63,829

 
73,470

Equity Issuance
6,480,536

 
4,558,404

Total shares issued
6,922,430

 
5,090,814

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 but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities. 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). On December 14, 2018, Moody's affirmed our debt ratings and improved their outlook from stable to positive, citing improvements to our regulatory construct that reduce investment recovery lag and our balanced fiscal policy. As of June 30, 2019, S&P 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 two 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 June 30, 2019. Our debt covenants are described in greater detail in Note 6 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 nine months ended June 30, 2019.

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. In the past we managed interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

40



The following table shows the components of the change in fair value of our financial instruments for the three and nine months ended June 30, 2019 and 2018:
 
Three Months Ended June 30
 
Nine Months Ended June 30
 
2019
 
2018
 
2019
 
2018
 
(In thousands)
Fair value of contracts at beginning of period
$
1,573

 
$
(86,342
)
 
$
(55,218
)
 
$
(109,159
)
Contracts realized/settled
6

 
(13
)
 
96,380

 
(1,213
)
Fair value of new contracts
(1,226
)
 
109

 
(337
)
 
(607
)
Other changes in value
(1,667
)
 
10,719

 
(42,139
)
 
35,452

Fair value of contracts at end of period
(1,314
)
 
(75,527
)
 
(1,314
)
 
(75,527
)
Netting of cash collateral

 

 

 

Cash collateral and fair value of contracts at period end
$
(1,314
)
 
$
(75,527
)
 
$
(1,314
)
 
$
(75,527
)
The fair value of our financial instruments at June 30, 2019 is presented below by time period and fair value source:
 
Fair Value of Contracts at June 30, 2019
 
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
$
(950
)
 
$
(364
)
 
$

 
$

 
$
(1,314
)
Prices based on models and other valuation methods

 

 

 

 

Total Fair Value
$
(950
)
 
$
(364
)
 
$

 
$

 
$
(1,314
)
Pension and Postretirement Benefits Obligations
For the nine months ended June 30, 2019 and 2018, our total net periodic pension and other postretirement benefits costs were $18.8 million and $31.2 million. Most of these costs are recoverable through our rates. A portion of these costs is capitalized into our rate base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-operating expense as discussed in Note 8.
Our fiscal 2019 costs were determined using a September 30, 2018 measurement date. As of September 30, 2018, interest and corporate bond rates were higher than the rates as of September 30, 2017. Therefore, we increased the discount rate used to measure our fiscal 2019 net periodic cost from 3.89 percent to 4.38 percent. The expected return on plan assets remained consistent with prior year at 6.75 percent in the determination of our fiscal 2019 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 2019 net periodic pension cost to be lower than fiscal 2018.
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, 2019, we were not required to make a minimum contribution to our defined benefit plan during fiscal 2019. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.
For the nine months ended June 30, 2019 we contributed $10.1 million to our postretirement medical plans. We anticipate contributing a total of between $10 million and $20 million to our postretirement plans during fiscal 2019.
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.


41




OPERATING STATISTICS AND OTHER INFORMATION
The following tables present certain operating statistics for our distribution and pipeline and storage segments for the three and nine month periods ended June 30, 2019 and 2018.
Distribution Sales and Statistical Data
 
Three Months Ended June 30
 
Nine Months Ended June 30
 
2019
 
2018
 
2019
 
2018
METERS IN SERVICE, end of period
 
 
 
 
 
 
 
Residential
3,001,552

 
2,969,270

 
3,001,552

 
2,969,270

Commercial
272,942

 
270,455

 
272,942

 
270,455

Industrial
1,668

 
1,667

 
1,668

 
1,667

Public authority and other
8,560

 
8,388

 
8,560

 
8,388

Total meters
3,284,722

 
3,249,780

 
3,284,722

 
3,249,780

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
49.1

 
47.5

 
49.1

 
47.5

SALES VOLUMES — MMcf(1)
 
 
 
 
 
 
 
Gas sales volumes
 
 
 
 
 
 
 
Residential
17,469

 
21,399

 
162,090

 
150,872

Commercial
15,838

 
17,368

 
90,395

 
85,273

Industrial
7,389

 
9,325

 
24,290

 
27,491

Public authority and other
987

 
1,277

 
5,848

 
6,086

Total gas sales volumes
41,683

 
49,369

 
282,623

 
269,722

Transportation volumes
36,367

 
34,989

 
127,453

 
122,691

Total throughput
78,050

 
84,358

 
410,076

 
392,413

OPERATING REVENUES (000’s)(1)(2)
 
 
 
 
 
 
 
Gas sales revenues
 
 
 
 
 
 
 
Residential
$
270,237

 
$
318,501

 
$
1,492,043

 
$
1,680,155

Commercial
113,848

 
145,685

 
605,939

 
687,577

Industrial
25,226

 
31,283

 
95,677

 
104,300

Public authority and other
6,352

 
8,581

 
36,482

 
41,150

Total gas sales revenues
415,663

 
504,050

 
2,230,141

 
2,513,182

Transportation revenues
22,686

 
23,965

 
75,568

 
79,266

Other gas revenues(3)
6,595

 
7,473

 
35,959

 
3,123

Total operating revenues
$
444,944

 
$
535,488

 
$
2,341,668

 
$
2,595,571

Average cost of gas per Mcf sold
$
3.35

 
$
4.68

 
$
4.06

 
$
5.27

See footnote following these tables.


42



Pipeline and Storage Operations Sales and Statistical Data
 
Three Months Ended June 30
 
Nine Months Ended June 30
 
2019
 
2018
 
2019
 
2018
CUSTOMERS, end of period
 
 
 
 
 
 
 
Industrial
93

 
93

 
93

 
93

Other
234

 
237

 
234

 
237

Total
327

 
330

 
327

 
330

 
 
 
 
 
 
 
 
INVENTORY STORAGE BALANCE — Bcf
1.3

 
0.5

 
1.3

 
0.5

PIPELINE TRANSPORTATION VOLUMES — MMcf(1)
214,627

 
215,775

 
708,315

 
666,079

OPERATING REVENUES (000’s)(1)(2)
$
149,198

 
$
127,633

 
$
419,318

 
$
375,051

Note to preceding tables:

(1) 
Sales volumes and revenues reflect segment operations, including intercompany sales and transportation amounts.
(2) 
Operating revenues include revenues from our alternative revenue programs as defined in Note 5.
(3) 
Other gas revenues include impacts of the TCJA.
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, 2018. During the nine months ended June 30, 2019, there were no material changes in our quantitative and qualitative disclosures about market risk.

Item 4.
Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2019 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
    
We did not make any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of the fiscal year ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


43



PART II. OTHER INFORMATION
Item 1.
Legal Proceedings
During the nine months ended June 30, 2019, 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, 2018. 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
3.1
 
Restated Articles of Incorporation of Atmos Energy Corporation - Texas (As Amended Effective February 3, 2010)
3.2
 
Restated Articles of Incorporation of Atmos Energy Corporation - Virginia (As Amended Effective February 3, 2010)
3.3
 
Amended and Restated Bylaws of Atmos Energy Corporation (as of February 5, 2019)
15
  
 
31
  
 
32
  
 
101.INS
  
XBRL Instance Document - the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH
  
Inline XBRL Taxonomy Extension Schema
 
101.CAL
  
Inline XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
  
Inline XBRL Taxonomy Extension Definition Linkbase
 
101.LAB
  
Inline XBRL Taxonomy Extension Labels Linkbase
 
101.PRE
  
Inline 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.

44



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: August 7, 2019

45