10-Q 1 ato2017123110-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, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
Texas and Virginia
 
75-1743247
(State or other jurisdiction of
incorporation or organization)
 
(IRS employer
identification no.)
 
 
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 
75240
(Zip code)
(Address of principal executive offices)
 
 
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
 
Emerging growth company ¨
(Do not check if a smaller reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of February 1, 2018.
Class
  
Shares Outstanding
No Par Value
  
110,967,636




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

2



PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS 
 
December 31,
2017
 
September 30,
2017
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
11,609,627

 
$
11,301,304

Less accumulated depreciation and amortization
2,090,835

 
2,042,122

Net property, plant and equipment
9,518,792

 
9,259,182

Current assets
 
 
 
Cash and cash equivalents
54,750

 
26,409

Accounts receivable, net
489,217

 
222,263

Gas stored underground
163,959

 
184,653

Other current assets
70,984

 
106,321

Total current assets
778,910

 
539,646

Goodwill
730,132

 
730,132

Deferred charges and other assets
236,886

 
220,636

 
$
11,264,720

 
$
10,749,596

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $0.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2017 — 110,962,112 shares; September 30, 2017 — 106,104,634 shares
$
555

 
$
531

Additional paid-in capital
2,940,062

 
2,536,365

Accumulated other comprehensive loss
(106,316
)
 
(105,254
)
Retained earnings
1,729,319

 
1,467,024

Shareholders’ equity
4,563,620

 
3,898,666

Long-term debt
3,067,469

 
3,067,045

Total capitalization
7,631,089

 
6,965,711

Current liabilities
 
 
 
Accounts payable and accrued liabilities
285,675

 
233,050

Other current liabilities
336,919

 
332,648

Short-term debt
336,816

 
447,745

Total current liabilities
959,410

 
1,013,443

Deferred income taxes
1,033,206

 
1,878,699

Regulatory excess deferred taxes (See Note 6)
746,246

 

Regulatory cost of removal obligation
480,086

 
485,420

Pension and postretirement liabilities
233,337

 
230,588

Deferred credits and other liabilities
181,346

 
175,735

 
$
11,264,720

 
$
10,749,596

See accompanying notes to condensed consolidated financial statements.

3



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 December 31
 
2017
 
2016
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Distribution segment
$
860,792

 
$
754,656

Pipeline and storage segment
126,463

 
109,952

Intersegment eliminations
(98,063
)
 
(84,440
)
Total operating revenues
889,192

 
780,168

 
 
 
 
Purchased gas cost
 
 
 
Distribution segment
463,758

 
395,346

Pipeline and storage segment
912

 
355

Intersegment eliminations
(97,753
)
 
(84,396
)
Total purchased gas cost
366,917

 
311,305

Operation and maintenance expense
129,567

 
124,938

Depreciation and amortization expense
88,374

 
76,958

Taxes, other than income
62,773

 
57,049

Operating income
241,561

 
209,918

Miscellaneous expense, net
(2,035
)
 
(994
)
Interest charges
31,509

 
31,030

Income from continuing operations before income taxes
208,017

 
177,894

Income tax (benefit) expense
(106,115
)
 
63,856

Income from continuing operations
314,132

 
114,038

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

 
10,994

Net income
$
314,132

 
$
125,032

Basic and diluted net income per share
 
 
 
Income per share from continuing operations
$
2.89

 
$
1.08

Income per share from discontinued operations

 
0.11

Net income per share - basic and diluted
$
2.89

 
$
1.19

Cash dividends per share
$
0.485

 
$
0.450

Basic and diluted weighted average shares outstanding
108,564

 
105,284

See accompanying notes to condensed consolidated financial statements.
 
 
 
 

4




ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 December 31
 
2017
 
2016
 
(Unaudited)
(In thousands)
Net income
$
314,132

 
$
125,032

Other comprehensive income (loss), net of tax
 
 
 
Net unrealized holding losses on available-for-sale securities, net of tax of $62 and $476
(107
)
 
(828
)
Cash flow hedges:
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(549) and $52,429
(955
)
 
91,214

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

 
4,982

Total other comprehensive income (loss)
(1,062
)
 
95,368

Total comprehensive income
$
313,070

 
$
220,400


See accompanying notes to condensed consolidated financial statements.

5



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Three Months Ended 
 December 31
 
2017
 
2016
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
314,132

 
$
125,032

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
88,374

 
77,143

Deferred income taxes
53,149

 
67,241

One-time income tax benefit
(161,884
)
 

Discontinued cash flow hedging for natural gas marketing commodity contracts

 
(10,579
)
Other
6,915

 
4,842

Net assets / liabilities from risk management activities
2,030

 
3,969

Net change in operating assets and liabilities
(129,478
)
 
(150,685
)
Net cash provided by operating activities
173,238

 
116,963

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(383,238
)
 
(297,962
)
Acquisition

 
(85,714
)
Available-for-sale securities activities, net
(135
)
 
(10,263
)
Other, net
2,001

 
1,802

Net cash used in investing activities
(381,372
)
 
(392,137
)
Cash Flows From Financing Activities
 
 
 
Net (decrease) increase in short-term debt
(110,929
)
 
110,936

Net proceeds from equity offering
395,099

 
49,400

Issuance of common stock through stock purchase and employee retirement plans
5,660

 
8,998

Proceeds from issuance of long-term debt

 
125,000

Interest rate agreements cash collateral

 
25,670

Cash dividends paid
(51,837
)
 
(47,740
)
Other
(1,518
)
 

Net cash provided by financing activities
236,475

 
272,264

Net increase (decrease) in cash and cash equivalents
28,341

 
(2,910
)
Cash and cash equivalents at beginning of period
26,409

 
47,534

Cash and cash equivalents at end of period
$
54,750

 
$
44,624


See accompanying notes to condensed consolidated financial statements.

6



ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2017
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) is engaged in the regulated natural gas distribution and pipeline and storage businesses. Our distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our regulated divisions and subsidiaries operate.
Our distribution business delivers natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at December 31, 2017, covered service areas located in eight states.
Our pipeline and storage business, which is also subject to federal and state regulations, includes the transportation of natural gas to our Texas and Louisiana distribution systems and the management of our underground storage facilities used to support our distribution business in various states.

2.    Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2017 are not indicative of our results of operations for the full 2018 fiscal year, which ends September 30, 2018.
Except for the actions of our regulators regarding tax reform as discussed in Note 6 and the receipt of funds held in escrow related to the prior year sale of AEM, no events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

Significant accounting policies
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017.
In May 2014, the Financial Accounting Standards Board (FASB) issued a comprehensive new revenue recognition standard that will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current guidance. The new guidance will become effective for us October 1, 2018 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption.
As of December 31, 2017, we had substantially completed the evaluation of our sources of revenue and the impact that the new guidance will have on our financial position, results of operations, cash flows and business processes. Based on this evaluation, we currently do not believe the implementation of the new guidance will have a material effect on our financial position, results of operations, cash flows or business processes. We expect to apply the new guidance using the modified retrospective method on the date of adoption. We are currently still evaluating the impact on our financial statement presentation and related disclosures.
In January 2016, the FASB issued guidance related to the classification and measurement of financial instruments. The amendments modify the accounting and presentation for certain financial liabilities and equity investments not consolidated or reported using the equity method. The guidance is effective for us beginning October 1, 2018; limited early adoption is permitted. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.
In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The new standard will be effective for us beginning on October 1, 2019; early adoption is permitted. The new leasing standard requires modified retrospective transition, which requires application of the new guidance at the beginning of the

7



earliest comparative period presented in the year of adoption. Additionally, in January 2018, the FASB issued amendments to the standard that provides a practical expedient for entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance. We are currently evaluating the effect of this standard and amendments on our financial position, results of operations and cash flows.
In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2021; early adoption is permitted beginning on October 1, 2019. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.
In January 2017, the FASB issued new guidance that simplifies the accounting for goodwill impairments by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to that reporting unit. The new standard will be effective for our fiscal 2021 goodwill impairment test; however, early adoption is permitted for goodwill impairment tests performed on testing dates after January 1, 2017. We have elected to early adopt the new standard, which will be effective for our goodwill impairment test performed in our second fiscal quarter. We do not anticipate the new standard will have a material impact on our results of operations, consolidated balance sheets or cash flows. 
In March 2017, the FASB issued new guidance related to the income statement presentation of the components of net periodic benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. The new guidance requires entities to disaggregate the current service cost component of the net benefit cost from the other components and present it with other current compensation costs for related employees in the statement of income. The other components of net benefit cost will be presented outside of income from operations on the statement of income. In addition, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). However, we believe that we will be allowed to defer the other components of net periodic benefit cost as a regulatory asset and that we will still be allowed to capitalize all components of net periodic benefit cost for ratemaking purposes. The new guidance will be effective for us in the fiscal year beginning on October 1, 2018 and for interim periods within that year. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and a portion of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and our regulatory excess deferred taxes and regulatory cost of removal obligation is reported separately.


8



Significant regulatory assets and liabilities as of December 31, 2017 and September 30, 2017 included the following:
 
December 31,
2017
 
September 30,
2017
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
24,598

 
$
26,826

Infrastructure mechanisms(2)
54,571

 
46,437

Deferred gas costs
18,505

 
65,714

Recoverable loss on reacquired debt
10,580

 
11,208

Deferred pipeline record collection costs
12,942

 
11,692

APT annual adjustment mechanism

 
2,160

Rate case costs
3,160

 
2,629

Other
9,703

 
10,132

 
$
134,059

 
$
176,798

Regulatory liabilities:
 
 
 
Regulatory excess deferred taxes(3)
$
746,246

 
$

Regulatory cost of removal obligation
520,483

 
521,330

Deferred gas costs
19,739

 
15,559

Asset retirement obligation
12,827

 
12,827

APT annual adjustment mechanism
1,720

 

Other
7,673

 
5,941

 
$
1,308,688

 
$
555,657

 
(1)
Includes $8.6 million and $9.4 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2)
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.
(3)
The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. The excess deferred taxes will be returned to utility customers in accordance with regulatory requirements. See Note 6 for further information.

3.    Segment Information

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

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

Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.

The accounting policies of the segments are the same as those described in the summary of significant accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s taxes were calculated on a separate return basis.

9



Income statements and capital expenditures for the three months ended December 31, 2017 and 2016 by segment are presented in the following tables:
 
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
103,737

 
26,140

 
(310
)
 
129,567

Depreciation and amortization expense
65,434

 
22,940

 

 
88,374

Taxes, other than income
55,107

 
7,666

 

 
62,773

Operating income
172,756

 
68,805

 

 
241,561

Miscellaneous expense
(1,400
)
 
(635
)
 

 
(2,035
)
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


 
Three Months Ended December 31, 2016
 
Distribution
 
Pipeline and Storage
 
Natural Gas Marketing
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
754,266

 
$
25,902

 
$

 
$

 
$
780,168

Intersegment revenues
390

 
84,050

 

 
(84,440
)
 

Total operating revenues
754,656

 
109,952

 

 
(84,440
)
 
780,168

Purchased gas cost
395,346

 
355

 

 
(84,396
)
 
311,305

Operation and maintenance expense
92,714

 
32,268

 

 
(44
)
 
124,938

Depreciation and amortization expense
61,157

 
15,801

 

 

 
76,958

Taxes, other than income
50,546

 
6,503

 

 

 
57,049

Operating income
154,893

 
55,025

 

 

 
209,918

Miscellaneous expense
(633
)
 
(361
)
 

 

 
(994
)
Interest charges
21,118

 
9,912

 

 

 
31,030

Income from continuing operations before income taxes
133,142

 
44,752

 

 

 
177,894

Income tax expense
47,778

 
16,078

 

 

 
63,856

Income from continuing operations
85,364

 
28,674

 

 

 
114,038

Income from discontinued operations, net of tax

 

 
10,994

 

 
10,994

Net income
$
85,364

 
$
28,674

 
$
10,994

 
$

 
$
125,032

Capital expenditures
$
222,484

 
$
75,478

 
$

 
$

 
$
297,962


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



10




Balance sheet information at December 31, 2017 and September 30, 2017 by segment is presented in the following tables:

 
December 31, 2017
 
Distribution
 
Pipeline and Storage
 
Eliminations
 
Consolidated
 
(In thousands)
Property, plant and equipment, net
$
7,010,709

 
$
2,508,083

 
$

 
$
9,518,792

Total assets
$
10,633,234

 
$
2,729,455

 
$
(2,097,969
)
 
$
11,264,720

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

 
$
2,409,665

 
$

 
$
9,259,182

Total assets
$
10,050,164

 
$
2,621,601

 
$
(1,922,169
)
 
$
10,749,596


4.    Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three months ended December 31, 2017 and 2016 are calculated as follows:

 
Three Months Ended 
 December 31
 
2017
 
2016
 
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share from continuing operations
 
 
 
Income from continuing operations
$
314,132

 
$
114,038

Less: Income from continuing operations allocated to participating securities
328

 
153

Income from continuing operations available to common shareholders
$
313,804

 
$
113,885

Basic and diluted weighted average shares outstanding
108,564

 
105,284

Income from continuing operations per share — Basic and Diluted
$
2.89

 
$
1.08

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

 
$
10,994

Less: Income from discontinued operations allocated to participating securities

 
14

Income from discontinued operations available to common shareholders
$

 
$
10,980

Basic and diluted weighted average shares outstanding
108,564

 
105,284

Income from discontinued operations per share — Basic and Diluted
$

 
$
0.11

Net income per share — Basic and Diluted
$
2.89

 
$
1.19




11



5.    Debt
The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. There were no material changes in the terms of our debt instruments during the three months ended December 31, 2017.
Long-term debt at December 31, 2017 and September 30, 2017 consisted of the following:
 
 
December 31, 2017
 
September 30, 2017
 
(In thousands)
Unsecured 8.50% Senior Notes, due March 2019
$
450,000

 
$
450,000

Unsecured 3.00% Senior Notes, due 2027
500,000

 
500,000

Unsecured 5.95% Senior Notes, due 2034
200,000

 
200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

 
400,000

Unsecured 4.15% Senior Notes, due 2043
500,000

 
500,000

Unsecured 4.125% Senior Notes, due 2044
750,000

 
750,000

Medium-term note Series A, 1995-1, 6.67%, due 2025
10,000

 
10,000

Unsecured 6.75% Debentures, due 2028
150,000

 
150,000

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

 
125,000

Total long-term debt
3,085,000

 
3,085,000

Less:
 
 
 
Original issue premium / discount on unsecured senior notes and debentures
(4,398
)
 
(4,384
)
Debt issuance cost
21,929

 
22,339

 
$
3,067,469

 
$
3,067,045

    
(1)
Up to $200 million can be drawn under this term loan.
    
We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity–to–capitalization ratio between 50% and 60%, inclusive of long–term and short–term debt. Our short–term borrowing requirements are affected primarily by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short–term borrowings typically reach their highest levels in the winter months.
Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility that expires September 25, 2021. 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, 2017 and September 30, 2017 a total of $336.8 million and $447.7 million was outstanding under our commercial paper program.

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, 2017, there were no borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total amount available to us under our $10 million facility to $4.4 million.
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At December 31, 2017, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 44 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.

12



These credit facilities and our public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. We were in compliance with all of our debt covenants as of December 31, 2017. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
6.    Impact of the Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. The TCJA introduced several significant changes to corporate income tax laws in the United States. The most significant change that will affect Atmos Energy is the reduction of the federal statutory income tax rate from 35% to 21%. As a rate-regulated entity, the accelerated capital expensing and the limitation on interest deductibility provisions included in the TCJA are not applicable to us.
Under generally accepted accounting principles, we use the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
At September 30, 2017, we measured our net deferred tax liability using the enacted federal statutory tax rate of 35%. The enactment of the TCJA on December 22, 2017 required us to remeasure our deferred tax assets and liabilities, including our U.S. federal income tax net operating loss carryforwards, at the newly enacted federal statutory income tax rate. As the Company’s fiscal year end is September 30, the Internal Revenue Code requires the Company to use a blended statutory federal corporate income tax rate of 24.5% for fiscal 2018.
The decrease in the federal statutory income tax rate reduced our net deferred tax liability by $908.1 million. Of this amount, $746.2 million relates to regulated operations and has been recorded as a regulatory liability, which will be returned to utility customers. The period and timing of these revenue adjustments are subject to Internal Revenue Code provisions and regulatory actions in each of the eight states in which we operate. The remaining $161.9 million has been reflected as a one-time income tax benefit in our condensed consolidated statement of income because these taxes were not considered in our cost of service ratemaking.
At December 31, 2017, we had $330.4 million of remeasured federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset future taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards that do not expire and are expected to be fully refunded to us between 2019 and 2022 as a result of changes introduced by the TCJA. These credit carryforwards are now reflected as taxes receivable within the deferred charges and other assets line item on our condensed consolidated balance sheet. In addition, the Company has $5.1 million in remeasured charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expire between 2018 and 2023.
The Company also has $25.9 million of state net operating loss carryforwards and $1.5 million of state tax credit carryforwards (net of $6.9 million and $0.4 million of remeasured federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards will begin to expire between 2018 and 2032.
Due to the changes introduced by the TCJA, we now believe it is more likely than not that the benefit from certain charitable contribution carryforwards for which a valuation allowance was previously established will be realized. As a result, we reduced our valuation allowance by $4.2 million during the first quarter. This amount is included in the $161.9 million one-time income tax benefit.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allows us to record provisional amounts during a one-year measurement period, similar to the measurement period in accounting for business combinations. The Company has determined a reasonable estimate for the measurement and accounting for certain effects of the TCJA, including the remeasurement of our net deferred tax liabilities and the establishment of a regulatory liability, which have been reflected as provisional amounts in the December 31, 2017 condensed consolidated financial statements and are described in further detail above. The amounts represent our best estimates based upon records, information and current guidance. We are still analyzing certain aspects of the TCJA, refining our calculations and expect additional guidance relating to the TCJA from the U.S. Department of the Treasury and the Internal Revenue Service.  Any additional issued guidance or future actions of our regulators could potentially affect the final determination of the accounting effects arising from the implementation of the TCJA.

13



We are actively working with our regulators in each jurisdiction to address the impact of the TCJA on our cost of service based rates. Accounting orders have been issued for our Colorado, Kansas, Kentucky, Tennessee and Virginia service areas that require us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that have been calculated based on a 35% statutory income tax rate and the new 21% statutory income tax rate. The establishment of this regulatory liability relating to our cost of service rates will result in a reduction to our revenues beginning in the second quarter of fiscal 2018. The period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.
Regulators in our other services areas, including Texas, Mississippi and Louisiana, have also taken action in response to the TCJA:
On January 23, 2018, the Railroad Commission of Texas directed the Commission Staff to develop recommendations to ensure that, beginning January 1, 2018, all gas utility customers in Texas receive the full benefit of the TCJA.
On January 26, 2018, the Mississippi Public Service Commission (MPSC) entered an order requiring each utility to file within thirty days a detailed description identifying how the TCJA will be reflected in the formula rate plan or other rate structures under which the utility operates.
On January 31, 2018, Louisiana Public Service Commission (LPSC) directed utilities to file reports on February 14, 2018, regarding savings for ratepayers as a result of the new federal tax laws. The LPSC is also considering an accounting order to direct the utilities to track and record the impacts of the TCJA and a rule making docket to address the TCJA. 

7.    Shareholders' Equity

Shelf Registration, At-the-Market Equity Sales Program and Equity Issuance
On March 28, 2016, we filed a registration statement with the Securities and Exchange Commission (SEC) that originally permitted us to issue, from time to time, up to $2.5 billion in common stock and/or debt securities, which expires March 28, 2019. At December 31, 2017, approximately $1.2 billion of securities remained available for issuance under the shelf registration statement.
On November 14, 2017, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million, which expires March 28, 2019. During the three months ended December 31, 2017, no shares of common stock were sold under the ATM program.
On November 30, 2017, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common stock. We received aggregate gross proceeds of $400 million and received net proceeds, after expenses, of $395.1 million from the offering.

Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate cash flow hedges and prior to the sale of Atmos Energy Marketing on January 3, 2017, commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income (loss):
 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2017
$
7,048

 
$
(112,302
)
 
$
(105,254
)
Other comprehensive 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
)
 

14



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

 
$
(187,524
)
 
$
(4,982
)
 
$
(188,022
)
Other comprehensive income (loss) before reclassifications
(828
)
 
91,127

 
9,847

 
100,146

Amounts reclassified from accumulated other comprehensive income

 
87

 
(4,865
)
 
(4,778
)
Net current-period other comprehensive income (loss)
(828
)
 
91,214

 
4,982

 
95,368

December 31, 2016
$
3,656

 
$
(96,310
)
 
$

 
$
(92,654
)

The following tables detail reclassifications out of AOCI for the three months ended December 31, 2017 and 2016. Amounts in parentheses below indicate decreases to net income in the statement of income:
 
Three Months Ended December 31, 2017
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Cash flow hedges
 
 
 
Interest rate agreements
$
(594
)
 
Interest charges
 
(594
)
 
Total before tax
 
217

 
Tax benefit
Total reclassifications
$
(377
)
 
Net of tax
 
Three Months Ended December 31, 2016
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Cash flow hedges
 
 
 
Interest rate agreements
$
(137
)
 
Interest charges
Commodity contracts
7,967

 
Purchased gas cost(1)
 
7,830

 
Total before tax
 
(3,052
)
 
Tax expense
Total reclassifications
$
4,778

 
Net of tax
(1)    Amounts are presented as part of income from discontinued operations in the condensed consolidated statements of income.
 
 
 
 
 
 
 
 
8.     Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2017 and 2016 are presented in the following table. Most of these costs are recoverable through our tariff rates; however, a portion of these costs is capitalized into our rate base. The remaining costs are recorded as a component of operation and maintenance expense.

15



 
Three Months Ended December 31
 
Pension Benefits
 
Other Benefits
 
2017
 
2016
 
2017
 
2016
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,560

 
$
5,216

 
$
3,020

 
$
3,109

Interest cost
6,430

 
6,297

 
2,727

 
2,670

Expected return on assets
(6,917
)
 
(6,994
)
 
(2,002
)
 
(1,796
)
Amortization of prior service cost (credit)
(58
)
 
(58
)
 
3

 
(411
)
Amortization of actuarial (gain) loss
3,089

 
4,249

 
(1,618
)
 
(707
)
Net periodic pension cost
$
7,104

 
$
8,710

 
$
2,130

 
$
2,865

 
 
 
 
 
 
 
 
The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2017 and 2016 are as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
2017
 
2016
 
2017
 
2016
Discount rate
 
3.89%
 
3.73%
 
3.89%
 
3.73%
Rate of compensation increase
 
3.50%
 
3.50%
 
N/A
 
N/A
Expected return on plan assets
 
6.75%
 
7.00%
 
4.29%
 
4.45%
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plan as of January 1, 2017. Based on that determination, we were not required to make a minimum contribution to our defined benefit plan during the first quarter of fiscal 2018.
We contributed $3.9 million to our other post-retirement benefit plans during the three months ended December 31, 2017. We expect to contribute a total of between $10 million and $20 million to these plans during fiscal 2018.
9.    Commitments and Contingencies
Litigation and Environmental Matters
With respect to the litigation and environmental-related matters or claims that were disclosed in Note 11 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2017.
We are a party to various litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
Our distribution divisions maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area, which obligate it to purchase specified volumes at prices indexed to natural gas hubs. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. There were no material changes to the purchase commitments for the three months ended December 31, 2017.

16



Regulatory Matters
Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations.  Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.
As of December 31, 2017, formula rate mechanisms were pending regulatory approval in our Louisiana and Tennessee service areas, infrastructure mechanisms were pending regulatory approval in our Kansas service area, an ad valorem tax rider filing was in progress in our Kansas service area and rate cases were pending regulatory approval in our Colorado, Kentucky and Mid-Tex 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 6, all jurisdictions are addressing impacts of the TCJA.
10.    Financial Instruments
We currently use financial instruments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments and the related accounting for these financial instruments are fully described in Notes 2 and 13 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the three months ended December 31, 2017, 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 2017-2018 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 26 percent, or 15.0 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Interest Rate Risk Management Activities
We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
As of December 31, 2017, 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, 2017, we had $40.8 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.
 
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of December 31, 2017, 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, 2017, we had 12,143 MMcf of net short commodity contracts outstanding. These contracts have not been designated as hedges.
Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments as of December 31, 2017 and September 30, 2017. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with our counterparties.

17



 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
December 31, 2017
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 
(114,175
)
Total
 
 

 
(114,175
)
Not Designated As Hedges:
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
456

 
(2,738
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
190

 
(262
)
Total
 
 
646

 
(3,000
)
Gross Financial Instruments
 
 
646

 
(117,175
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
Contract netting
 
 

 

Net Financial Instruments
 
 
646

 
(117,175
)
Cash collateral
 
 

 

Net Assets/Liabilities from Risk Management Activities
 
 
$
646

 
$
(117,175
)
 
 
 
 
 
 
Balance Sheet Location
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2017
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 

 
(112,076
)
Total
 
 

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

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

 

Total
 
 
3,239

 
(322
)
Gross Financial Instruments
 
 
3,239

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

 

Net Financial Instruments
 
 
3,239

 
(112,398
)
Cash collateral
 
 

 

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

 
$
(112,398
)
 

18



Impact of Financial Instruments on the Income Statement
Cash Flow Hedges
As discussed above, our distribution segment has interest rate swap agreements, which we designated as a cash flow hedge at the time the swaps were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our condensed consolidated statements of income for the three months ended December 31, 2017 and 2016 was $0.6 million and $0.1 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, 2017 and 2016. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.
 
Three Months Ended 
 December 31
 
2017
 
2016 (1)
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate agreements
$
(1,332
)
 
$
91,127

Forward commodity contracts(2)

 
9,847

Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate agreements
377

 
87

Forward commodity contracts(2)

 
(4,865
)
Total other comprehensive income (loss) from hedging, net of tax
$
(955
)
 
$
96,196

 
(1)
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction for the three-month period ended December 31, 2016.
(2)
Due to the sale of AEM, these amounts are included in income from discontinued operations.
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 of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2017. 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
$
(1,508
)
Thereafter
(39,248
)
Total
$
(40,756
)
 
Financial Instruments Not Designated as Hedges
As discussed above, financial instruments used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
11.    Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the three months ended December 31, 2017, there were no changes in these methods.

19



Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 7 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and September 30, 2017. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
 
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, 2017
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
646

 
$

 
$

 
$
646

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Registered investment companies
43,065

 

 

 

 
43,065

Bond mutual funds
16,359

 

 

 

 
16,359

Bonds

 
30,861

 

 

 
30,861

Money market funds

 
614

 

 

 
614

Total available-for-sale securities
59,424

 
31,475

 

 

 
90,899

Total assets
$
59,424

 
$
32,121

 
$

 
$

 
$
91,545

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
117,175

 
$

 
$

 
$
117,175



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

 
$
3,239

 
$

 
$

 
$
3,239

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

 

 

 

 
41,097

Bond mutual funds
16,371

 

 

 

 
16,371

Bonds

 
29,104

 

 

 
29,104

Money market funds

 
1,837

 

 

 
1,837

Total available-for-sale securities
57,468

 
30,941

 

 

 
88,409

Total assets
$
57,468

 
$
34,180

 
$

 
$

 
$
91,648

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
$

 
$
112,398

 
$

 
$

 
$
112,398

 

20



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


Available-for-sale securities are comprised of the following:
 
Amortized
Cost
 
Gross
Unrealized
Gain
 
Gross
Unrealized
Loss
 
Fair
Value
 
(In thousands)
As of December 31, 2017
 
 
 
 
 
 
 
Domestic equity mutual funds
$
27,171

 
$
8,850

 
$
(14
)
 
$
36,007

Foreign equity mutual funds
4,725

 
2,333

 

 
7,058

Bond mutual funds
16,461

 

 
(102
)
 
16,359

Bonds
30,936

 
6

 
(81
)
 
30,861

Money market funds
614

 

 

 
614

 
$
79,907

 
$
11,189

 
$
(197
)
 
$
90,899

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

 
$
8,920

 
$

 
$
34,281

Foreign equity mutual funds
4,581

 
2,235

 

 
6,816

Bond mutual funds
16,391

 
2

 
(22
)
 
16,371

Bonds
29,074

 
46

 
(16
)
 
29,104

Money market funds
1,837

 

 

 
1,837

 
$
77,244

 
$
11,203

 
$
(38
)
 
$
88,409

At December 31, 2017 and September 30, 2017, our available-for-sale securities included $43.7 million and $42.9 million related to assets held in separate rabbi trusts for our supplemental executive benefit plans. At December 31, 2017, we maintained investments in bonds that have contractual maturity dates ranging from January 2018 through December 2020.
These securities are reported at market value with unrealized gains and losses shown as a component of accumulated other comprehensive income (loss). We regularly evaluate the performance of these investments on a fund by fund basis for impairment, taking into consideration the fund’s purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related fund is written down to its estimated fair value and the other-than-temporary impairment is recognized in the income statement.

21



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, 2017 and September 30, 2017:
 
December 31, 2017
 
September 30, 2017
 
(In thousands)
Carrying Amount
$
3,085,000

 
$
3,085,000

Fair Value
$
3,305,656

 
$
3,382,272


12.    Concentration of Credit Risk
Information regarding our concentration of credit risk is disclosed in Note 16 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017. During the three months ended December 31, 2017, there were no material changes in our concentration of credit risk.
13. Discontinued Operations
On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all of the equity interests of Atmos Energy Marketing, LLC (AEM). The transaction closed on January 3, 2017, with an effective date of January 1, 2017. CES paid a cash purchase price of $38.3 million plus working capital of $109.0 million for total cash consideration of $147.3 million. Of this amount, $7.0 million was placed into escrow and was to be paid to the Company within 24 months of the closing date, net of any indemnification claims agreed upon between the two companies. In January 2018, $3.0 million of this escrowed amount was released and received by the Company. We recognized a net gain of $0.03 per diluted share on the sale in the second quarter of fiscal 2017 and completed the working capital true–up during the third quarter of fiscal 2017.
The operating results of our natural gas marketing reportable segment have been reported on the condensed consolidated statement of income as income from discontinued operations, net of income tax, for the three months ended December 31, 2016.  Accordingly, expenses related to allocable general corporate overhead and interest expense are not included in these results. 
The tables below set forth selected financial information related to discontinued operations. Operating expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income. At December 31, 2017 and September 30, 2017 we did not have any assets or liabilities held for sale.
The following table presents statement of income data related to discontinued operations:
 
 
 
Three Months Ended 
 December 31, 2016
 
(In thousands)
 
 
Operating revenues
$
303,474

Purchased gas cost
277,554

Operating expenses
7,874

Operating income
18,046

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

Income tax expense
6,841

Net income from discontinued operations
$
10,994

 
 
 
 



22




The following table presents statement of cash flow data related to discontinued operations:
 
Three Months Ended 
 December 31, 2016
 
(In thousands)
Depreciation and amortization expense
$
185

Capital expenditures
$

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

Natural Gas Marketing Commodity Risk Management Activities
Our discontinued natural gas marketing segment was exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. Through December 31, 2016, we managed our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.
Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax gain of $10.6 million, which is included in income from discontinued operations on the condensed consolidated statement of income for the three months ended December 31, 2016.
The Company's other risk management activities are discussed in Note 10.
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas cost, which is included in discontinued operations on the condensed consolidated statements of income, and primarily results from differences in the location and timing of the derivative instrument and the hedged item. For the three months ended December 31, 2016 , we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.4 million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 Fair Value Hedges
The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item on the results of discontinued operations on our condensed consolidated income statement for the three months ended December 31, 2016 is presented below.
 
Three Months Ended 
 December 31, 2016
 
(In thousands)
Commodity contracts
$
(9,567
)
Fair value adjustment for natural gas inventory designated as the hedged item
12,858

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

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

 
$
3,291

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity.

23



Cash Flow Hedges
The impact of our natural gas marketing segment cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2016 is presented below:
 
Three Months Ended 
 December 31, 2016
 
(In thousands)

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

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

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

Financial Instruments Not Designated as Hedges
The impact of the natural gas marketing segment's financial instruments that had not been designated as hedges on our condensed consolidated income statements for the three months ended December 31, 2016 was a decrease in purchased gas cost of $6.8 million, which is included in discontinued operations on the condensed consolidated statements of income.



24



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Atmos Energy Corporation
We have reviewed the condensed consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of December 31, 2017 and the related condensed consolidated statements of income, comprehensive income and cash flows for the three-month periods ended December 31, 2017 and 2016. These financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the condensed consolidated financial statements referred to above for them to be in conformity with U.S. generally accepted accounting principles.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Atmos Energy Corporation and subsidiaries as of September 30, 2017, and the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, not presented herein, and in our report dated November 13, 2017, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of September 30, 2017, is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived.
/s/    ERNST & YOUNG LLP
Dallas, Texas
February 6, 2018

25



Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
INTRODUCTION
The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2017.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit and capital markets to execute our business strategy; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our business; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain operational, technical and managerial personnel; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of climate change or related additional legislation or regulation in the future; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.
OVERVIEW
Atmos Energy and our subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at December 31, 2017 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 and storage assets located in Kentucky and Tennessee.
The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.
The natural gas marketing segment was comprised of our discontinued natural gas marketing business.




26



CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to risk management and trading activities, the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill, indefinite-lived intangible assets and other long-lived assets. Actual results may differ from such estimates.
Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2017 and include the following:
Regulation
Unbilled revenue
Pension and other postretirement plans
Impairment assessments
Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the three months ended December 31, 2017.

Non-GAAP Financial Measures
Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Gross Profit, 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 gross profit rather than operating revenues and purchased gas cost individually.
As described further in Note 6, the enactment of the Tax Cuts and Jobs Act of 2017 (the TCJA) required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a one-time, non-cash income tax benefit of $161.9 million during the three months ended December 31, 2017. Due to the non-recurring nature of this benefit, we believe that income from continuing operations and diluted earnings per share from continuing operations before the one-time, non-cash income tax benefit provide a more relevant measure to analyze our financial performance than income from continuing operations and consolidated diluted earnings per share from continuing operations. Accordingly, the following discussion and analysis of our financial performance will reference adjusted income from continuing operations and diluted earnings per share, which is calculated as follows:
 
Three Months Ended December 31
 
2017
 
2016
 
Change
 
(In thousands, except per share data)
Income from continuing operations
$
314,132

 
$
114,038

 
$
200,094

One-time, non-cash income tax benefit
161,884

 

 
161,884

Adjusted income from continuing operations
$
152,248

 
$
114,038

 
$
38,210

 
 
 
 
 
 
Consolidated diluted EPS from continuing operations
$
2.89

 
$
1.08

 
$
1.81

Diluted EPS from one-time, non-cash income tax benefit
1.49

 

 
1.49

Adjusted diluted EPS from continuing operations
$
1.40

 
$
1.08

 
$
0.32







27



RESULTS OF OPERATIONS

Executive Summary
Atmos Energy strives to operate our businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires significant levels of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.
During the first three months of fiscal 2018, we recorded adjusted income from continuing operations of $152.2 million, or $1.40 per diluted share, compared to adjusted income from continuing operations of $114.0 million, or $1.08 per diluted share for the first three months of fiscal 2017. The period-over-period increase of $38.2 million, or 33.5%, largely reflects positive rate outcomes and the impact of the TCJA on our effective income tax rate. During the three months ended December 31, 2017, we completed seven regulatory proceedings, resulting in an increase in annual operating income of $46.1 million and had seven ratemaking efforts in progress at December 31, 2017 seeking a total increase in annual operating income of $13.3 million.
Capital expenditures for the first three months of fiscal 2018 were $383.2 million. Approximately 82 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less. We expect our capital expenditures to range between $1.3 billion and $1.4 billion for fiscal 2018. We funded our capital expenditures program primarily through operating cash flows of $173.2 million. Additionally, we issued $400 million of common stock during the three months ended December 31, 2017. The net proceeds from the issuance were primarily used to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes.
As a result of our sustained financial performance, improved cash flows and capital structure, our Board of Directors increased the quarterly dividend by 7.8 percent for fiscal 2018.
TCJA Impact
The TCJA introduced several significant changes to corporate income tax laws in the United States, which have been reflected in our condensed consolidated financial statements for the period ended December 31, 2017. As a rate regulated entity, the effects of lower tax rates included in our cost of service rates will ultimately flow through to our utility customers in the form of adjusted rates. Therefore, the favorable impact of the reduction in our federal statutory income tax rate on our financial performance will be limited to items that impact our income before income taxes in the current period that have not yet been reflected in our rates (most notably increases to and decreases in commission-approved regulatory assets and liabilities recorded on our condensed consolidated balance sheet) and market-based revenues that are earned from customers who utilize our assets. Note 6 to the condensed consolidated financial statements details the various impacts of the TCJA on our financial position and results from operations. The most significant changes are summarized as follows:
Because our fiscal year started on October 1, 2017, our federal statutory income tax rate for fiscal 2018 was reduced from 35% to 24.5%. We anticipate our effective income tax rate for fiscal 2018 will range from 26% to 28%, before the effect of the return of the excess deferred tax liability and the one-time, non-cash income tax benefit. Our federal statutory income tax rate will decline to 21% on October 1, 2018.
We remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $908.1 million. Of this amount, $746.2 million was reclassified to a regulatory liability, which will be returned to utility customers. The remaining $161.9 million was recognized as a one-time, non-cash income tax benefit in our condensed consolidated statement of income.
Atmos Energy supports our regulators' efforts to ensure our utility customers receive the full benefits of changes in our cost of service rates arising from tax reform. Income taxes, like other costs, are passed through to our customers in our rates; however, changes to customer rates must be approved by our regulators. Beginning in the second quarter of fiscal 2018, we will establish regulatory liabilities in jurisdictions that have issued orders requiring us to reduce future rates for the difference in taxes included in our cost of service rates that have been calculated based on a 35% statutory income tax rate and a 21% statutory income tax rate. As of February 6, 2018, we had received orders in five jurisdictions and anticipate receiving regulatory orders in the remaining jurisdictions by the end of the second quarter of fiscal 2018. The establishment of these regulatory liabilities for our cost of service rates will reduce our revenues. The timing of the establishment of regulatory liabilities as well as the period and timing of the return of these liabilities to utility customers will be determined by regulators in each of our jurisdictions.

28



The enactment of the TCJA is expected to reduce our cash flows from operations primarily due to 1) the collection of taxes at a lower rate and 2) the return of regulatory liabilities established in response to the enactment of the TCJA and regulatory activities to our utility customers. We intend to externally finance this reduction in operating cash flow in a balanced fashion in order to maintain an equity capitalization ratio ranging from 50% to 60% to maintain our current credit ratings. We currently anticipate this external financing need will range from $500 million to $600 million through fiscal 2022.
The following discusses the results of operations for each of our operating segments.
Distribution Segment
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment are our ability to earn our authorized rates of return, the cost of natural gas, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions by reducing or eliminating regulatory lag and, ultimately, separating the recovery of our approved margins from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions.
Seasonal weather patterns can also affect our distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which has been approved by state regulatory commissions for approximately 97 percent of our residential and commercial meters in the following states for the following time periods:
 
 
Kansas, West Texas
October — May
Tennessee
October — April
Kentucky, Mississippi, Mid-Tex
November — April
Louisiana
December — March
Virginia
January — December
Our distribution operations are also affected by the cost of natural gas. The cost of gas is passed through to our customers without markup. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Gross profit in our Texas and Mississippi service areas includes franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in these revenue-related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.
As discussed above, the cost of gas typically does not have a direct impact on our gross profit. However, higher gas costs mean higher bills for our customers, which may adversely impact our accounts receivable collections, resulting in higher bad debt expense and may require us to increase borrowings under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. However, gas cost risk has been mitigated in recent years through improvements in rate design that allow us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.
 
 
 
 
 
 
 
 
 
 
 
 

29



Three Months Ended December 31, 2017 compared with Three Months Ended December 31, 2016
Financial and operational highlights for our distribution segment for the three months ended December 31, 2017 and 2016 are presented below.
 
Three Months Ended December 31
 
2017
 
2016
 
Change
 
(In thousands, unless otherwise noted)
Operating revenues
$
860,792

 
$
754,656

 
$
106,136

Purchased gas cost
463,758

 
395,346

 
68,412

Gross profit
397,034

 
359,310

 
37,724

Operating expenses
224,278

 
204,417

 
19,861

Operating income
172,756

 
154,893

 
17,863

Miscellaneous expense
(1,400
)
 
(633
)
 
(767
)
Interest charges
21,368

 
21,118

 
250

Income before income taxes
149,988

 
133,142

 
16,846

One-time, non-cash income tax benefit
(140,151
)
 

 
(140,151
)
Income tax expense
41,040

 
47,778

 
(6,738
)
Net income
$
249,099

 
$
85,364

 
$
163,735

Consolidated distribution sales volumes — MMcf
86,307

 
74,430

 
11,877

Consolidated distribution transportation volumes — MMcf
38,050

 
36,175

 
1,875

Total consolidated distribution throughput — MMcf
124,357

 
110,605

 
13,752

Consolidated distribution average cost of gas per Mcf sold
$
5.37

 
$
5.31

 
$
0.06

Income before income taxes for our distribution segment increased 13 percent, primarily due to a $37.7 million increase in gross profit, partially offset with a $19.9 million increase in operating expenses. The quarter-over-quarter increase in gross profit primarily reflects:
a $25.6 million net increase in rate adjustments, primarily in our Mid-Tex, Mississippi, West Texas and Kentucky/Mid-States Divisions.
a $5.7 million increase in residential and commercial net consumption, primarily in our Mid-Tex and Mississippi Divisions.
a $3.5 million increase from customer growth, 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, was primarily due to incremental system integrity activities, increased depreciation and property tax expense associated with increased capital investments.
The decrease in income tax expense reflects a reduction in our effective tax rate from 35.9% to 27.4%, as a result of the TCJA, which is partially offset by an increase in income before income taxes.
The following table shows our operating income by distribution division, in order of total rate base, for the three months ended December 31, 2017 and 2016. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.
 
Three Months Ended December 31
 
2017
 
2016
 
Change
 
(In thousands)
Mid-Tex
$
72,925

 
$
72,743

 
$
182

Kentucky/Mid-States
28,129

 
22,738

 
5,391

Louisiana
23,268

 
19,863

 
3,405

West Texas
15,761

 
14,928

 
833

Mississippi
18,275

 
11,958

 
6,317

Colorado-Kansas
12,931

 
11,705

 
1,226

Other
1,467

 
958

 
509

Total
$
172,756

 
$
154,893

 
$
17,863

 
 
 
 
 
 

30



 
 
 
 
 
 
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 2018, we completed six regulatory proceedings, resulting in a $17.1 million increase in annual operating income as summarized below.
Rate Action
 
Annual Increase in
Operating Income
 
 
(In thousands)
Annual formula rate mechanisms
 
$
17,077

Rate case filings
 

Other rate activity
 

 
 
$
17,077


The following ratemaking efforts seeking $13.3 million in increased annual operating income were in progress as of December 31, 2017:
Division
 
Rate Action
 
Jurisdiction
 
Operating Income
Requested
 
 
 
 
 
 
(In thousands)
Colorado-Kansas
 
Rate Case (1)
 
Colorado
 
$
2,916

 
 
GSRS
 
Kansas
 
821

 
 
Ad Valorem
 
Kansas
 
457

Kentucky/Mid-States
 
Rate Case
 
Kentucky
 
4,778

 
 
ARM True-Up (2)
 
Tennessee
 
850

Louisiana
 
RSC
 
Trans La
 
1,195

Mid-Tex
 
Rate Case (3)
 
City of Dallas
 
2,247

 
 
 
 
 
 
$
13,264


(1)
A Recommended Decision for $2.1 million was issued on January 8, 2018. The Recommended Decision also recommended a five year extension of the Company's System Safety and Integrity Rider tariff.
(2)
The Annual Rate Mechanism (ARM) is a formula rate mechanism that refreshes the Company's rates on an annual basis.
(3)
The Company extended the deadline for the City of Dallas to act until February 15, 2018.
Annual Formula Rate Mechanisms
As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi and Tennessee operations and in substantially all the service areas in our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a

31



prior test-year period. The following table summarizes our annual formula rate mechanisms by state:
 
 
Annual Formula Rate Mechanisms
State
 
Infrastructure Programs
 
Formula Rate Mechanisms
 
 
 
 
 
Colorado
 
System Safety and Integrity Rider (SSIR)
 
Kansas
 
Gas System Reliability Surcharge (GSRS)
 
Kentucky
 
Pipeline Replacement Program (PRP)
 
Louisiana
 
(1)
 
Rate Stabilization Clause (RSC)
Mississippi
 
System Integrity Rider (SIR)
 
Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee
 
 
Annual Rate Mechanism (ARM)
Texas
 
Gas Reliability Infrastructure Program (GRIP), (1)
 
Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia
 
Steps to Advance Virginia Energy (SAVE)
 

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

The following annual formula rate mechanisms were approved during the three months ended December 31, 2017:
Division
 
Jurisdiction
 
Test Year
Ended
 
Increase in
Annual
Operating
Income
 
Effective
Date
 
 
 
 
(In thousands)
2018 Filings:
 
 
 
 
 
 
 
 
Colorado-Kansas
 
Colorado SSIR
 
12/31/2018
 
$
2,228

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

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

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

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

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

 
10/01/2017
Total 2018 Filings
 
 
 
 
 
$
17,077

 
 

(1)
In our next SRF filing, the SGR rate base will be combined with the SRF rate base, per Commission order.
(2)
The Company completed our Steps to Advance Virginia Energy (SAVE) program. On October 1, 2017 a refund factor was removed from the rate resulting in an operating income increase of $308,000.
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, 2017.
 
 
 
 
 
 
 
Other Ratemaking Activity
The Company had no other ratemaking activity during the three months ended December 31, 2017.