Company Quick10K Filing
Quick10K
Atmos Energy
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$100.17 117 $11,710
10-Q 2018-12-31 Quarter: 2018-12-31
10-K 2018-09-30 Annual: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-Q 2017-12-31 Quarter: 2017-12-31
10-K 2017-09-30 Annual: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-Q 2016-12-31 Quarter: 2016-12-31
10-K 2016-09-30 Annual: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-Q 2015-12-31 Quarter: 2015-12-31
10-K 2015-09-30 Annual: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-Q 2014-12-31 Quarter: 2014-12-31
10-K 2014-09-30 Annual: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-Q 2013-12-31 Quarter: 2013-12-31
8-K 2019-02-11 Amend Bylaw, Shareholder Vote, Exhibits
8-K 2019-02-05 Earnings, Exhibits
8-K 2018-11-28 Enter Agreement, Regulation FD, Other Events, Exhibits
8-K 2018-11-16 Enter Agreement, Exhibits
8-K 2018-11-07 Earnings, Exhibits
8-K 2018-11-01 Officers, Exhibits
8-K 2018-10-04 Enter Agreement, Exhibits
8-K 2018-10-01 Other Events, Exhibits
8-K 2018-08-08 Earnings, Exhibits
8-K 2018-08-06 Officers, Exhibits
8-K 2018-02-14 Regulation FD
8-K 2018-02-07 Shareholder Vote, Other Events
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OII Oceaneering 1,690
TMP Tompkins Financial 1,220
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AXSM Axsome Therapeutics 515
VSEC VSE 356
GPL Great Panther Silver 238
WTT Wireless Telecom Group 31
UHN United States Diesel-Heating Oil Fund 0
ATO 2018-12-31
Part I. Financial Information
Item 1. Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 6. Exhibits
EX-15 ato20181231ex-15.htm
EX-31 ato20181231ex-31.htm
EX-32 ato20181231ex-32.htm

Atmos Energy Earnings 2018-12-31

ATO 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 ato2018123110-q.htm 10-Q Document


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
Texas and Virginia
 
75-1743247
(State or other jurisdiction of
incorporation or organization)
 
(IRS employer
identification no.)
 
 
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 
75240
(Zip code)
(Address of principal executive offices)
 
 
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
 
Emerging growth company ¨
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of January 30, 2019.
Class
  
Shares Outstanding
No Par Value
  
116,897,373




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 
 
December 31,
2018
 
September 30,
2018
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
12,948,229

 
$
12,567,373

Less accumulated depreciation and amortization
2,250,000

 
2,196,226

Net property, plant and equipment
10,698,229

 
10,371,147

Current assets
 
 
 
Cash and cash equivalents
218,197

 
13,771

Accounts receivable, net
478,373

 
253,295

Gas stored underground
146,552

 
165,732

Other current assets
69,616

 
46,055

Total current assets
912,738

 
478,853

Goodwill
730,419

 
730,419

Deferred charges and other assets
274,403

 
294,018

 
$
12,615,789

 
$
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: December 31, 2018 — 116,892,959 shares; September 30, 2018 — 111,273,683 shares
$
584

 
$
556

Additional paid-in capital
3,476,476

 
2,974,926

Accumulated other comprehensive loss
(114,115
)
 
(83,647
)
Retained earnings
1,985,250

 
1,878,116

Shareholders’ equity
5,348,195

 
4,769,951

Long-term debt
3,084,779

 
2,493,665

Total capitalization
8,432,974

 
7,263,616

Current liabilities
 
 
 
Accounts payable and accrued liabilities
301,734

 
217,283

Other current liabilities
578,764

 
547,068

Short-term debt

 
575,780

Current maturities of long-term debt
575,000

 
575,000

Total current liabilities
1,455,498

 
1,915,131

Deferred income taxes
1,191,824

 
1,154,067

Regulatory excess deferred taxes (See Note 13)
717,758

 
739,670

Regulatory cost of removal obligation
468,825

 
466,405

Pension and postretirement liabilities
176,582

 
177,520

Deferred credits and other liabilities
172,328

 
158,028

 
$
12,615,789

 
$
11,874,437

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 December 31
 
2018
 
2017
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
838,835

 
$
860,792

Pipeline and storage segment
134,470

 
126,463

Intersegment eliminations
(95,523
)
 
(98,063
)
Total operating revenues
877,782

 
889,192

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
437,732

 
463,758

Pipeline and storage segment
(358
)
 
912

Intersegment eliminations
(95,209
)
 
(97,753
)
Total purchased gas cost
342,165

 
366,917

Operation and maintenance expense
138,600

 
129,045

Depreciation and amortization expense
96,065

 
88,374

Taxes, other than income
64,488

 
62,773

Operating income
236,464

 
242,083

Other non-operating expense
(7,723
)
 
(2,557
)
Interest charges
27,849

 
31,509

Income before income taxes
200,892

 
208,017

Income tax expense (benefit)
43,246

 
(106,115
)
Net income
$
157,646

 
$
314,132

Basic net income per share
$
1.38

 
$
2.89

Diluted net income per share
$
1.38

 
$
2.89

Cash dividends per share
$
0.525

 
$
0.485

Basic weighted average shares outstanding
113,800

 
108,564

Diluted weighted average shares outstanding
113,832

 
108,564

 
 
 
 
Net income
$
157,646

 
$
314,132

Other comprehensive income (loss), net of tax
 
 
 
Net unrealized holding losses on available-for-sale securities, net of tax of $0 and $62 (See Note 2)

 
(107
)
Cash flow hedges:
 
 
 
Amortization and unrealized loss on interest rate agreements, net of tax of $6,580 and $549
(22,258
)
 
(955
)
Total other comprehensive loss
(22,258
)
 
(1,062
)
Total comprehensive income
$
135,388

 
$
313,070

See accompanying notes to condensed consolidated financial statements.

 
 
 
 

4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Three Months Ended 
 December 31
 
2018
 
2017
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
157,646

 
$
314,132

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
96,065

 
88,374

Deferred income taxes
40,339

 
53,149

One-time income tax benefit

 
(161,884
)
Other
6,231

 
6,915

Net assets / liabilities from risk management activities
(2,458
)
 
2,030

Net change in operating assets and liabilities
(133,139
)
 
(129,478
)
Net cash provided by operating activities
164,684

 
173,238

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(416,404
)
 
(383,238
)
Debt and equity securities activities, net
(963
)
 
(135
)
Other, net
2,074

 
2,001

Net cash used in investing activities
(415,293
)
 
(381,372
)
Cash Flows From Financing Activities
 
 
 
Net decrease in short-term debt
(575,780
)
 
(110,929
)
Net proceeds from equity offering
494,734

 
395,099

Issuance of common stock through stock purchase and employee retirement plans
4,241

 
5,660

Proceeds from issuance of long-term debt
596,994

 

Cash dividends paid
(58,722
)
 
(51,837
)
Debt issuance costs
(6,432
)
 

Other

 
(1,518
)
Net cash provided by financing activities
455,035

 
236,475

Net increase in cash and cash equivalents
204,426

 
28,341

Cash and cash equivalents at beginning of period
13,771

 
26,409

Cash and cash equivalents at end of period
$
218,197

 
$
54,750


See accompanying notes to condensed consolidated financial statements.

5



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2018
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 December 31, 2018, covered service areas located in eight states.
Our pipeline and storage business, which is also subject to federal and state regulations, includes the transportation of natural gas to our Texas and Louisiana distribution systems and the management of our underground storage facilities used to support our distribution business in various states.

2.    Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis, 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 three-month period ended December 31, 2018 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.
Accounting pronouncements adopted in fiscal 2019
In May 2014, the Financial Accounting Standards Board (FASB) issued a comprehensive new revenue recognition standard that superseded virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, an entity recognizes revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We adopted the new guidance October 1, 2018 using the modified retrospective method. See Note 5 for our discussion of the effects of implementing this standard.
In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. Effective October 1, 2018, changes in the fair value of our equity securities formerly designated as available-for-sale are now recognized in other non-operating expense on our condensed consolidated statement of comprehensive income. 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 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 accumulated other comprehensive income.
In March 2017, the FASB issued new guidance related to the statement of comprehensive income presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit cost from the other components and present it with other current compensation costs for related employees in the statement of comprehensive income. The other components of net benefit cost will be presented outside of income from operations on the statement of comprehensive income. 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). The Federal Energy Regulatory Commission

6



(FERC), which regulates interstate transmission pipelines and also establishes, through its Uniform System of Accounts, accounting practices for rate-regulated entities, has issued guidance that states it will permit an election to either continue to capitalize non-service benefit costs or to cease capitalizing such costs for regulatory purposes.  Accounting guidelines by the FERC are typically also followed by state commissions.  As such, we continue to capitalize into property, plant and equipment all components of net periodic benefit cost for ratemaking purposes and will defer the non-service cost components as a regulatory asset for U.S. GAAP reporting purposes on a prospective basis in accordance with the new guidance.
We adopted the new guidance beginning on October 1, 2018. We continue to present the service cost component of net periodic benefit cost within operation and maintenance expense; however, other components of the net periodic benefit cost are now presented separately within other non-operating expense on our condensed consolidated statement of comprehensive income. The changes in presentation were implemented on a retrospective basis in accordance with the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the condensed statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for each component of the net periodic benefit cost in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard to all prior periods presented. The new standard did not have a material impact on our financial position, results of operations or cash flows.
In August 2018, the FASB issued new guidance aligning the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract 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, beginning October 1, 2018. As a result of the new guidance, we will defer onto the balance sheet those up-front costs of cloud computing arrangements if they would have been capitalized in a similar on-premise software solution. The new standard did not have a material impact on our financial position, results of operations or cash flows.
Accounting pronouncements that will be effective after fiscal 2019
In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019. The new leasing standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. In January 2018, the FASB issued a practical expedient to allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance. In July 2018, the FASB issued a practical expedient providing an additional and optional transition method to adopt the standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations, cash flows and business processes.
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, 2021; 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 presented. Early adoption is permitted. The adoption of this new guidance impacts only our disclosures; however we are still evaluating the timing of our adoption.
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

7



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 December 31, 2018 and September 30, 2018 included the following:
 
December 31,
2018
 
September 30,
2018
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs
$
7,188

 
$
6,496

Infrastructure mechanisms(1)
85,071

 
96,739

Deferred gas costs
11,621

 
1,927

Recoverable loss on reacquired debt
8,076

 
8,702

Deferred pipeline record collection costs
22,122

 
20,467

Rate case costs
1,866

 
2,741

Other
6,422

 
6,739

 
$
142,366

 
$
143,811

Regulatory liabilities:
 
 
 
Regulatory excess deferred taxes(2)
$
740,896

 
$
744,895

Regulatory cost of service reserve(3)
19,281

 
22,508

Regulatory cost of removal obligation
523,644

 
522,175

Deferred gas costs
85,820

 
94,705

Asset retirement obligation
12,887

 
12,887

APT annual adjustment mechanism
44,619

 
35,228

Pension and postretirement benefit costs
70,969

 
69,113

Other
14,354

 
9,486

 
$
1,512,470

 
$
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, $23.1 million 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.
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.


8



Income statements and capital expenditures for the three months ended December 31, 2018 and 2017 by segment are presented in the following tables:
 
Three Months Ended December 31, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
838,181

 
$
39,601

 
$

 
$
877,782

Intersegment revenues
654

 
94,869

 
(95,523
)
 

Total operating revenues
838,835

 
134,470

 
(95,523
)
 
877,782

Purchased gas cost
437,732

 
(358
)
 
(95,209
)
 
342,165

Operation and maintenance expense
105,767

 
33,147

 
(314
)
 
138,600

Depreciation and amortization expense
69,709

 
26,356

 

 
96,065

Taxes, other than income
56,190

 
8,298

 

 
64,488

Operating income
169,437

 
67,027

 

 
236,464

Other non-operating expense
(6,477
)
 
(1,246
)
 

 
(7,723
)
Interest charges
18,210

 
9,639

 

 
27,849

Income before income taxes
144,750

 
56,142

 

 
200,892

Income tax expense
30,365

 
12,881

 

 
43,246

Net income
$
114,385

 
$
43,261

 
$

 
$
157,646

Capital expenditures
$
302,545

 
$
113,859

 
$

 
$
416,404


 
Three Months Ended December 31, 2017
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
860,453

 
$
28,739

 
$

 
$
889,192

Intersegment revenues
339

 
97,724

 
(98,063
)
 

Total operating revenues
860,792

 
126,463

 
(98,063
)
 
889,192

Purchased gas cost
463,758

 
912

 
(97,753
)
 
366,917

Operation and maintenance expense
103,215

 
26,140

 
(310
)
 
129,045

Depreciation and amortization expense
65,434

 
22,940

 

 
88,374

Taxes, other than income
55,107

 
7,666

 

 
62,773

Operating income
173,278

 
68,805

 

 
242,083

Other non-operating expense
(1,922
)
 
(635
)
 

 
(2,557
)
Interest charges
21,368

 
10,141

 

 
31,509

Income before income taxes
149,988

 
58,029

 

 
208,017

Income tax benefit
(99,111
)
 
(7,004
)
 

 
(106,115
)
Net income
$
249,099

 
$
65,033

 
$

 
$
314,132

Capital expenditures
$
241,249

 
$
141,989

 
$

 
$
383,238

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

9



Balance sheet information at December 31, 2018 and September 30, 2018 by segment is presented in the following tables:
 
December 31, 2018
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
7,889,901

 
$
2,808,328

 
$

 
$
10,698,229

Total assets
$
11,836,888

 
$
3,040,831

 
$
(2,261,930
)
 
$
12,615,789

 
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. 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 months ended December 31, 2018 and 2017 are calculated as follows:

 
Three Months Ended 
 December 31
 
2018
 
2017
 
(In thousands, except per share amounts)
Basic Earnings Per Share
 
 
 
Net income
$
157,646

 
$
314,132

Less: Income allocated to participating securities
135

 
328

Income available to common shareholders
$
157,511

 
$
313,804

Basic weighted average shares outstanding
113,800

 
108,564

Net income per share — Basic
$
1.38

 
$
2.89

Diluted Earnings Per Share
 
 
 
Income available to common shareholders
$
157,511

 
$
313,804

Effect of dilutive shares

 

Income available to common shareholders
$
157,511

 
$
313,804

Basic weighted average shares outstanding
113,800

 
108,564

Dilutive shares (1)
32

 

Diluted weighted average shares outstanding
113,832

 
108,564

Net income per share - Diluted
$
1.38

 
$
2.89


(1)
Dilutive shares were the result of the forward sale agreements entered into during fiscal 2019. See Note 7 for further discussion.

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 business processes. However, the guidance introduced new disclosures which are presented below. The following table

10



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 December 31, 2018
 
Distribution
 
Pipeline and Storage
 
(In thousands)
Gas sales revenues:
 
 
 
Residential
$
547,928

 
$

Commercial
218,938

 

Industrial
34,537

 

Public authority and other
13,285

 

Total gas sales revenues
814,688

 

Transportation revenues
25,400

 
147,424

Miscellaneous revenues
6,950

 
1,682

Revenues from contracts with customers
847,038

 
149,106

Alternative revenue program revenues
(8,739
)
 
(14,636
)
Other revenues
536

 

Total operating revenues
$
838,835

 
$
134,470


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 prices 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.
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. These amounts can be either additional revenue or given back to customers depending on actual results as compared to the weather in our distribution segment or versus the benchmark in our pipeline and storage segment. These mechanisms are considered to be alternative revenue programs under accounting

11



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 three months ended December 31, 2018.
Long-term debt at December 31, 2018 and September 30, 2018 consisted of the following:
 
 
December 31, 2018
 
September 30, 2018
 
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019
$
450,000

 
$
450,000

Unsecured 3.00% Senior Notes, due 2027
500,000

 
500,000

Unsecured 5.95% Senior Notes, due 2034
200,000

 
200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

 
400,000

Unsecured 4.15% Senior Notes, due 2043
500,000

 
500,000

Unsecured 4.125% Senior Notes, due 2044
750,000

 
750,000

Unsecured 4.30% Senior Notes, due 2048
600,000

 

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
(1,472
)
 
(4,439
)
Debt issuance cost
26,693

 
20,774

Current maturities
575,000

 
575,000

 
$
3,084,779

 
$
2,493,665

    
(1)
Up to $200 million can be drawn under this term loan.
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 by construction work in progress and the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility that expires on September 25, 2022. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a spread ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At December 31, 2018, there were no amounts outstanding under our commercial paper program. At September 30, 2018, a total of $575.8 million was outstanding.
Additionally, we have a $25 million 364-day unsecured facility and a $10 million 364-day unsecured revolving credit facility, which is used primarily to issue letters of credit. At December 31, 2018, there were no borrowings outstanding under

12



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 December 31, 2018, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 42 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 December 31, 2018. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

7.    Shareholders' Equity

The following tables present a reconciliation of changes in stockholders' equity for the three months ended December 31, 2018 and 2017.
 
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


 
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


13



Shelf Registration, At-the-Market Equity Sales Program and Equity Issuance
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 December 31, 2018, approximately $1.8 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. During the three months ended December 31, 2018, no shares of common stock were sold under the ATM equity sales program.
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 the underwriting discount, net proceeds from the offering were $494.7 million. Concurrently, we entered into separate forward sale agreements with two underwriters who borrowed and sold 2,668,464 shares of our common stock. Under the agreements we have the ability to settle these shares before March 31, 2020 at a price based on the offering price established on November 28, 2018. During the three months ended December 31, 2018, no shares of common stock were settled under the forward sale agreements. If we had settled all shares under the forward agreements at December 31, 2018, we would have received approximately $245.2 million, based on a net price of $91.90 per share.
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 loss before reclassifications

 
(22,716
)
 
(22,716
)
Amounts reclassified from accumulated other comprehensive income

 
458

 
458

Net current-period other comprehensive loss

 
(22,258
)
 
(22,258
)
Cumulative effect of accounting change (See Note 2)
(8,210
)
 

 
(8,210
)
December 31, 2018
$
(86
)
 
$
(114,029
)
 
$
(114,115
)
 
 
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 loss before reclassifications
(107
)
 
(1,332
)
 
(1,439
)
Amounts reclassified from accumulated other comprehensive income

 
377

 
377

Net current-period other comprehensive loss
(107
)
 
(955
)
 
(1,062
)
December 31, 2017
$
6,941

 
$
(113,257
)
 
$
(106,316
)

(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.

14




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 months ended December 31, 2018 and 2017 are presented in the following table. 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 December 31
 
Pension Benefits
 
Other Benefits
 
2018
 
2017
 
2018
 
2017
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,045

 
$
4,560

 
$
2,702

 
$
3,020

Interest cost(1)
6,799

 
6,430

 
2,961

 
2,727

Expected return on assets(1)
(7,113
)
 
(6,917
)
 
(2,665
)
 
(2,002
)
Amortization of prior service cost (credit)(1)
(58
)
 
(58
)
 
43

 
3

Amortization of actuarial (gain) loss(1)
1,608

 
3,089

 
(2,045
)
 
(1,618
)
Net periodic pension cost
$
5,281

 
$
7,104

 
$
996

 
$
2,130


(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 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. The plaintiffs seek over $1.0 million in damages for, among with others, wrongful death and personal injury.
We are a party to various other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
Our distribution divisions maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area, which obligate it to purchase specified volumes at prices indexed to natural gas hubs. These

15



purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. There were no material changes to the purchase commitments for the three months ended December 31, 2018.
Leases
We have entered into operating leases for towers, office and warehouse space, vehicles and heavy equipment used in our operations. During the three months ended December 31, 2018, we executed amendments to some of our lease agreements that impacted terms as well as our future minimum lease payments. As of December 31, 2018, 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 December 31, 2018 totaled $194.2 million
Regulatory Matters
Except for routine regulatory proceedings as discussed below, there were no material changes to regulatory matters for the three months ended December 31, 2018.
As of December 31, 2018, regulatory proceedings were in progress in our Colorado, Kansas, Kentucky, Louisiana, Mid-Tex, Tennessee, Virginia and West Texas service areas. These 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 TCJA.

10.    Financial Instruments
We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018. During the three months ended December 31, 2018, there were no material changes in our objectives, strategies and accounting for using financial instruments. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions. The following summarizes those objectives and strategies.

Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
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 to utilize financial instruments, we anticipate hedging 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
We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
As of December 31, 2018, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $450 million unsecured senior notes in fiscal 2019 at 3.78%, which we designated as a cash flow hedge at the time the swaps were executed. As of December 31, 2018, we had $47.7 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.
 
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.

16



As of December 31, 2018, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2018, we had 14,353 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 December 31, 2018 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 December 31, 2018 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)
December 31, 2018
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate swap agreements
Other current assets /
Other current liabilities
 
$

 
$
(85,930
)
Total
 
 

 
(85,930
)
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
3,241

 
(1,265
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
285

 

Total
 
 
3,526

 
(1,265
)
Gross / Net Financial Instruments
 
 
$
3,526

 
$
(87,195
)
 
 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2018
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate swap agreements
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, our distribution segment has interest rate swap agreements, which we designated as a cash flow hedge at the time the swaps were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of comprehensive income for the three months ended December 31, 2018 and 2017 was $0.6 million and $0.6 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 months ended December 31, 2018 and 2017. The

17



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 
 December 31
 
2018
 
2017
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate agreements
$
(22,716
)
 
$
(1,332
)
Recognition of losses in earnings due to settlements:
 
 
 
Interest rate agreements
458

 
377

Total other comprehensive income (loss) from hedging, net of tax
$
(22,258
)
 
$
(955
)
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 December 31, 2018, of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments at the date of settlement. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.
 
Interest Rate
Agreements
 
(In thousands)
Next twelve months
$
(1,878
)
Thereafter
(45,827
)
Total
$
(47,705
)
 
Financial Instruments Not Designated as Hedges
As discussed above, financial instruments used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of 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 three months ended December 31, 2018, there were no changes in these methods.
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 7 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 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

18



within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 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
 
December 31, 2018
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
3,526

 
$

 
$

 
$
3,526

Debt and equity securities
 
 
 
 
 
 
 
 
 
Registered investment companies
37,241

 

 

 

 
37,241

Bond mutual funds
21,523

 

 

 

 
21,523

Bonds(2)

 
30,096

 

 

 
30,096

Money market funds

 
3,319

 

 

 
3,319

Total debt and equity securities
58,764

 
33,415

 

 

 
92,179

Total assets
$
58,764

 
$
36,941

 
$

 
$

 
$
95,705

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
87,195

 
$

 
$

 
$
87,195


 
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 December 31, 2018 and September 30, 2018, our available-for-sale debt securities were recorded at amortized cost of $30.2 million and $31.5 million. At December 31, 2018, we maintained investments in bonds that have contractual maturity dates ranging from January 2019 through December 2021.
 
 
 
 
 
 
 
 


19



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 December 31, 2018 and September 30, 2018:
 
December 31, 2018
 
September 30, 2018
 
(In thousands)
Carrying Amount
$
3,685,000

 
$
3,085,000

Fair Value
$
3,746,697

 
$
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 three months ended December 31, 2018, 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 $161.9 million income tax benefit in our condensed consolidated statement of comprehensive income during the first quarter of fiscal 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 December 31, 2018 and September 30, 2018, this liability totaled $740.9 million and $744.9 million.
We have and continue to work with our regulators in each jurisdiction to fully incorporate the effects of the TCJA into customer bills. As of December 31, 2018, we have received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in our Colorado, Kansas, Kentucky, Louisiana, Mississippi, Tennessee and Texas service areas. We continue to work with regulators in Virginia to reflect the effects of the lower statutory income tax rate in our cost of service in rates.
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 December 31, 2018, we received approval from regulators to return these liabilities to customers in Colorado, Kansas, Louisiana and Texas. This regulatory liability totaled $19.3 million and $22.5 million as of December 31, 2018 and September 30, 2018.
As of December 31, 2018, we received approval from regulators to return excess deferred taxes in Colorado, Kentucky, Louisiana, Mississippi, Tennessee and Texas 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.

20



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 December 31, 2018, the related condensed consolidated statements of comprehensive income and cash flows for the three months ended December 31, 2018 and 2017, 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 December 31, 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
February 5, 2019

21



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 December 31, 2018 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

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

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

22



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 three months ended December 31, 2018.

Non-GAAP Financial Measures
Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the statement 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 $161.9 million for the three months ended December 31, 2017. 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, which is calculated as follows:
 
 
 
 
 
 
 
Three Months Ended December 31
 
2018
 
2017
 
Change
 
(In thousands, except per share data)
Net income
$
157,646

 
$
314,132

 
$
(156,486
)
TCJA non-cash income tax benefit

 
(161,884
)
 
161,884

Adjusted net income
$
157,646

 
$
152,248

 
$
5,398

 
 
 
 
 
 
Diluted net income per share
$
1.38

 
$
2.89

 
$
(1.51
)
Diluted EPS from TCJA non-cash income tax benefit

 
(1.49
)
 
1.49

Adjusted diluted net income per share
$
1.38

 
$
1.40

 
$
(0.02
)



23



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 three months ended December 31, 2018, we recorded net income of $157.6 million, or $1.38 per diluted share, compared to net income of $314.1 million, or $2.89 per diluted share for the three months ended December 31, 2017.
After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income of $152.2 million, or $1.40 per diluted share for the three months ended December 31, 2017. The period-over-period increase in adjusted net income of $5.4 million, or four percent largely reflects weather that was 20 percent colder than the prior year, positive rate outcomes in our pipeline and storage business and the impact of the TCJA on our effective income tax rate, partially offset by reduced revenues as a result of implementing the TCJA. Additionally, the period-over-period decrease in adjusted diluted earning per share reflects increases in our common stock outstanding due to common stock issuances in 2017 and 2018. During the three months ended December 31, 2018, we implemented regulatory actions which resulted in an increase in annual operating income of $22.4 million and had ten ratemaking efforts in progress at December 31, 2018, seeking a total increase in annual operating income of $20.9 million.
Capital expenditures for the three months ended December 31, 2018 increased nine percent period-over-period, to $416.4 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range from $1.65 billion to $1.75 billion for fiscal 2019. We funded our capital expenditures program primarily through operating cash flows of $164.7 million. Additionally, we completed $1.35 billion in external financing during the three months ended December 31, 2018 with the issuance of $600 million in 30-year senior notes and approximately $750 million of common stock. Approximately $245 million of the net proceeds from the equity offering were allocated to the forward sale agreements that expire in March 2020. The net proceeds from these issuances were used to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes.
As a result of our sustained financial performance, improved cash flows and capital structure, our Board of Directors increased the quarterly dividend by 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 has been approved by state regulatory commissions for approximately 97 percent of our residential and commercial meters in the following states for the following time periods:
 
 
Kansas, West Texas
October — May
Tennessee
October — April
Kentucky, Mississippi, Mid-Tex
November — April
Louisiana
December — March
Virginia
January — December
Our distribution operations are also affected by the cost of natural gas. 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

24



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 December 31, 2018 compared with Three Months Ended December 31, 2017
Financial and operational highlights for our distribution segment for the three months ended December 31, 2018 and 2017 are presented below.
 
Three Months Ended December 31
 
2018
 
2017
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
838,835

 
$
860,792

 
$
(21,957
)
Purchased gas cost
437,732

 
463,758

 
(26,026
)
Contribution Margin
401,103

 
397,034

 
4,069

Operating expenses
231,666

 
223,756

 
7,910

Operating income
169,437

 
173,278

 
(3,841
)
Other non-operating expense
(6,477
)
 
(1,922
)
 
(4,555
)
Interest charges
18,210

 
21,368

 
(3,158
)
Income before income taxes
144,750

 
149,988

 
(5,238
)
TCJA non-cash income tax benefit

 
(140,151
)
 
140,151

Income tax expense
30,365

 
41,040

 
(10,675
)
Net income
$
114,385

 
$
249,099

 
$
(134,714
)
Consolidated distribution sales volumes — MMcf
101,698

 
86,307

 
15,391

Consolidated distribution transportation volumes — MMcf
41,048

 
38,050

 
2,998

Total consolidated distribution throughput — MMcf
142,746

 
124,357

 
18,389

Consolidated distribution average cost of gas per Mcf sold
$
4.30

 
$
5.37

 
$
(1.07
)
Income before income taxes for our distribution segment decreased four percent, primarily due to a $7.9 million increase in operating expenses, partially offset by a $4.1 million increase in Contribution Margin. The quarter-over-quarter increase in Contribution Margin primarily reflects:
a $7.7 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.
a $3.7 million increase from customer growth primarily in our Mid-Tex Division.
a $7.3 million net decrease in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex and Kentucky/Mid-States Divisions.
The increase in operating expenses, which includes operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, is primarily attributable to an increase in depreciation expense and property taxes associated with increased capital investments.
The decrease in income tax expense reflects a reduction in our effective tax rate from 27.4% to 21.0%, as a result of the TCJA. As the Company's fiscal year end is September 30, the Internal Revenue Code required the Company to use a blended statutory federal corporate income tax rate for fiscal 2018 due to the enactment of the TCJA in the first fiscal quarter.
The following table shows our operating income by distribution division, in order of total rate base, for the three months ended December 31, 2018 and 2017. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

25



 
Three Months Ended December 31
 
2018
 
2017
 
Change
 
(In thousands)
Mid-Tex
$
72,406

 
$
72,925

 
$
(519
)
Kentucky/Mid-States
24,452

 
28,129

 
(3,677
)
Louisiana
22,153

 
23,268

 
(1,115
)
West Texas
15,823

 
15,761

 
62

Mississippi
19,588

 
18,275

 
1,313

Colorado-Kansas
13,789

 
12,931

 
858

Other
1,226

 
1,989

 
(763
)
Total
$
169,437

 
$
173,278

 
$
(3,841
)
 
 
 
 
 
 
 
 
 
 
 
 
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 three months of fiscal 2019, we implemented five regulatory proceedings, resulting in a $22.4 million increase in annual operating income as summarized below. The ratemaking outcomes for 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 (Decrease) in
Operating Income
 
 
(In thousands)
Annual formula rate mechanisms
 
$
22,378

Rate case filings
 

Other rate activity
 

 
 
$
22,378


The following ratemaking efforts, which reflect a 21% federal income tax rate resulting from the TCJA, seeking $20.9 million in increased annual operating income were in progress as of December 31, 2018:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income Requested
 
 
 
 
 
 
(In thousands)
Colorado-Kansas
 
SSIR
 
Colorado (1)
 
$
2,147

Colorado-Kansas
 
SSIR/GIS
 
Colorado (2)
 
87

Colorado-Kansas
 
Ad Valorem
 
Kansas (3)
 
214

Louisiana
 
RSC
 
Trans La
 
4,719

Mid-Tex
 
Rate Case
 
ATM Cities
 
4,252

Mid-Tex
 
Rate Case
 
Environs (4)
 
(1,875
)
Kentucky/Mid-States
 
Formula Rate Mechanism True-Up
 
Tennessee (5)
 
(3,220
)
Kentucky/Mid-States
 
Rate Case
 
Kentucky
 
14,424

Kentucky/Mid-States
 
Rate Case
 
Virginia
 
605

West Texas
 
Rate Case
 
Environs (4)
 
(485
)
 
 
 
 
 
 
$
20,868


(1)
The Colorado Public Utilities Commission approved the SSIR implementation at their December 19, 2018 meeting with rates effective January 1, 2019.
(2)
The Company has filed a request to recover Geographic Information System projects in a manner similar to its current SSIR program.
(3)
The Kansas Corporation Commission approved the Ad Valorem filing on January 8, 2019.
(4)
The Texas Railroad Commission approved these filings on December 11, 2018 with an operating income decrease of $2.7 million for Mid-Tex and $0.8 million for West Texas effective January 1, 2019.

26



(5)
The Tennessee Formula Mechanism True-up (True-up filing) test period ended May 2018 reflects the impact of the lower federal income tax rate between January 1, 2018 and May 31, 2018. The True-up filing was included in the Tennessee ARM filing made on February 1, 2019 with the Tennessee Public Utility Commission, which requested an operating income increase of $3.2 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) (2)
 
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.
(2)
The Company has proposed removal of the PRP tariff in a pending Kentucky Public Service Commission case and anticipates recovery of this program investment through annual forward-looking rate case filings.
    
The following annual formula rate mechanisms, which reflect a 21% federal income tax rate resulting from the TCJA, were approved during the three months ended December 31, 2018:
Division
 
Jurisdiction
 
Test Year
Ended
 
Increase (Decrease) in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2019 Filings:
 
 
 
 
 
 
 
 
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
 
 
 
 
 
$
22,378

 
 
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. There was no rate case activity completed during the three months ended December 31, 2018.
 
 
 
 
 
 
 

27



Other Ratemaking Activity
The Company had no other ratemaking activity during the three months ended December 31, 2018.
 
 
 
 
 
 
 
 
 
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.

Three Months Ended December 31, 2018 compared with Three Months Ended December 31, 2017
Financial and operational highlights for our pipeline and storage segment for the three months ended December 31, 2018 and 2017 are presented below.