Edgar Filing: ATMOS ENERGY CORP

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2017

¨ 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 (IRS employer

incorporation or organization) identification no.)

Three Lincoln Centre, Suite 1800

5430 LBJ Freeway, Dallas, Texas 75240

(Address of principal executive offices) (Zip code)

Registrant’s telephone number, including area code:

(972) 934-9227

Securities registered pursuant to Section 12(b) of the Act:

Name of Each Exchange

Title of Each Class on Which Registered

Common stock, No Par Value New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

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 corporate Web site, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.45) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See 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 Act). Yes ¨ No þ

The aggregate market value of the common voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2017, was $8,146,262,574.

As of November 8, 2017, the registrant had 106,112,709 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 7, 2018 are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS




		Page
Glossary of Key Terms		3

	Part I
Item 1.	Business	4
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	17
Item 3.	Legal Proceedings	18
Item 4.	Mine Safety Disclosures	18

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
Item 6.	Selected Financial Data	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	88
Item 9A.	Controls and Procedures	88
Item 9B.	Other Information	90

	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	90
Item 11.	Executive Compensation	91
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	91
Item 13.	Certain Relationships and Related Transactions, and Director Independence	91
Item 14.	Principal Accountant Fees and Services	91

	Part IV
Item 15.	Exhibits and Financial Statement Schedules	91

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GLOSSARY OF KEY TERMS




AEC	Atmos Energy Corporation
AEH	Atmos Energy Holdings, Inc.
AEM	Atmos Energy Marketing, LLC
AOCI	Accumulated Other Comprehensive Income
ARM	Annual Rate Mechanism
ATO	Trading symbol for Atmos Energy Corporation common stock on the New York Stock Exchange
Bcf	Billion cubic feet
COSO	Committee of Sponsoring Organizations of the Treadway Commission
DARR	Dallas Annual Rate Review
ERISA	Employee Retirement Income Security Act of 1974
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GRIP	Gas Reliability Infrastructure Program
Gross Profit	Non-GAAP measure defined as operating revenues less purchased gas cost
GSRS	Gas System Reliability Surcharge
KPSC	Kentucky Public Service Commission
LTIP	1998 Long-Term Incentive Plan
Mcf	Thousand cubic feet
MDWQ	Maximum daily withdrawal quantity
Mid-Tex Cities	Represents all incorporated cities other than Dallas, or approximately 80 percent of the Mid-Tex Division’s customers, with whom a settlement agreement was reached during the fiscal 2008 second quarter.
MMcf	Million cubic feet
Moody’s	Moody’s Investor Service, Inc.
NGA	Natural Gas Act of 1938
NYMEX	New York Mercantile Exchange, Inc.
NYSE	New York Stock Exchange
PAP	Pension Account Plan
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
WNA	Weather Normalization Adjustment

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PART I

The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.



ITEM 1.	Business.

Overview and Strategy

Atmos Energy Corporation, headquartered in Dallas, Texas, and incorporated in Texas and Virginia, is one of the country’s largest natural-gas-only distributors based on number of customers. We deliver natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in eight states located primarily in the South. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.

Through December 31, 2016, we were also engaged in certain nonregulated businesses that provided natural gas management, marketing, transportation and storage services to municipalities, local gas distribution companies, including certain of our natural gas distribution divisions, and industrial customers principally in the Midwest and Southeast. Effective January 1, 2017, we sold all of the equity interests of Atmos Energy Marketing, LLC (AEM) to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated gas marketing business.

Atmos Energy's vision is to be the safest provider of natural gas services. We intend to achieve this vision by:


•	operating our business exceptionally well


•	investing in our people and infrastructure


•	enhancing our culture.

We believe the successful execution of this strategy has delivered excellent shareholder value. Over the last six years, regulatory mechanisms designed to minimize regulatory lag have enabled us to make significant capital investments to fortify and upgrade our distribution and transmission systems. The timely recovery of these investments has increased our rate base which has resulted in rising earnings per share during this time.

Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We continue to strengthen our culture through ongoing communications with our employees and enhanced employee training.

Operating Segments

As of September 30, 2017, we manage and review our consolidated operations through the following three 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 is comprised of our discontinued natural gas marketing business.

These operating segments are described in greater detail below.

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Distribution Segment Overview

Our distribution segment is primarily comprised of the regulated natural gas distribution and related sales and storage operations in our six regulated natural gas distribution divisions, which are used to support our regulated natural gas distribution operations in those states. The following table summarizes key information about these divisions, presented in order of total rate base. We operate in our service areas under terms of non-exclusive franchise agreements granted by the various cities and towns that we serve. At September 30, 2017, we held 1,008 franchises having terms generally ranging from five to 35 years. A significant number of our franchises expire each year, which require renewal prior to the end of their terms. Historically, we have successfully renewed these franchises and believe that we will continue to be able to renew our franchises as they expire.



Division	Service Areas	Communities Served	Customer Meters
Mid-Tex	Texas, including the Dallas/Fort Worth Metroplex	550	1,672,581
Kentucky/Mid-States	Kentucky	230	181,638
	Tennessee		147,620
	Virginia		24,153
Louisiana	Louisiana	270	359,920
West Texas	Amarillo, Lubbock, Midland	80	311,188
Mississippi	Mississippi	110	270,754
Colorado-Kansas	Colorado	170	118,410
	Kansas		135,141

Revenues in this operating segment are established by regulatory authorities in the states in which we operate. These rates are intended to be sufficient to cover the costs of conducting business and to provide a reasonable return on invested capital. In addition, we transport natural gas for others through our distribution systems.

Rates established by regulatory authorities often include cost adjustment mechanisms for costs that (i) are subject to significant price fluctuations compared to our other costs, (ii) represent a large component of our cost of service and (iii) are generally outside our control.

Purchased gas cost adjustment mechanisms represent a common form of cost adjustment mechanism. Purchased gas cost adjustment mechanisms provide natural gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case because they provide a dollar-for-dollar offset to increases or decreases in the cost natural gas. Therefore, although substantially all of our distribution operating revenues fluctuate with the cost of gas that we purchase, distribution gross profit (which is defined as operating revenues less purchased gas cost) is generally not affected by fluctuations in the cost of gas.

Additionally, some jurisdictions have performance-based ratemaking adjustments to provide incentives to distribution companies to minimize purchased gas costs through improved storage management and use of financial instruments to lock in gas costs. Under the performance-based ratemaking adjustments, purchased gas costs savings are shared between the utility and its customers.

Our supply of natural gas is provided by a variety of suppliers, including independent producers, marketers and pipeline companies, withdrawals of gas from proprietary and contracted storage assets and peaking and spot purchase agreements, as needed.

Supply arrangements consist of both base load and swing supply (peaking) quantities and are contracted from our suppliers on a firm basis with various terms at market prices. Base load quantities are those that flow at a constant level throughout the month and swing supply quantities provide the flexibility to change daily quantities to match increases or decreases in requirements related to weather conditions.

Except for local production purchases, we select our natural gas suppliers through a competitive bidding process by periodically requesting proposals from suppliers that have demonstrated that they can provide reliable service. We select these suppliers based on their ability to deliver gas supply to our designated firm pipeline receipt points at the lowest reasonable cost. Major suppliers during fiscal 2017 were BP Energy Company, Castleton Commodities Merchant Trading L.P., CenterPoint

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Energy Services, Inc., Concord Energy LLC, ConocoPhillips Company, Devon Gas Services, L.P., Sequent Energy Management, L.P., Targa Gas Marketing LLC, Tenaska Gas Storage, LLC and Texla Energy Management, Inc.

The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments. We estimate our peak-day availability of natural gas supply to be approximately 4.4 Bcf. The peak-day demand for our distribution operations in fiscal 2017 was on January 6, 2017, when sales to customers reached approximately 3.6 Bcf.

Currently, our distribution divisions utilize 38 pipeline transportation companies, both interstate and intrastate, to transport our natural gas. The pipeline transportation agreements are firm and many of them have “pipeline no-notice” storage service, which provides for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term necessary while still maintaining our right of first refusal. The natural gas supply for our Mid-Tex Division is delivered primarily by our Atmos Pipeline — Texas Division (APT).

To maintain our deliveries to high priority customers, we have the ability, and have exercised our right, to curtail deliveries to certain customers under the terms of interruptible contracts or applicable state regulations or statutes. Our customers’ demand on our system is not necessarily indicative of our ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering, storage and transmission systems, the duration and severity of cold weather, the availability of gas reserves from our suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Curtailment rights provide us the flexibility to meet the human-needs requirements of our customers on a firm basis. Priority allocations imposed by federal and state regulatory agencies, as well as other factors beyond our control, may affect our ability to meet the demands of our customers. We do not anticipate any problems with obtaining additional gas supply as needed for our customers.

Pipeline and Storage Segment Overview

Our pipeline and storage segment consists of the pipeline and storage operations of APT and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Through it's system, APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage reservoirs in Texas.

Gross profit earned from transportation and storage services for APT is subject to traditional ratemaking governed by the RRC. Rates are updated through periodic filings made under Texas’ Gas Reliability Infrastructure Program (GRIP). GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years, the most recent filing was completed in 2017. APT’s existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates.

Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in New Orleans, Louisiana that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans in Louisiana with distribution affiliates of the Company, which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.

Natural Gas Marketing Segment Overview

Through December 31, 2016, we were engaged in a nonregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices.

As more fully described in Note 15, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, these operations have been reported as discontinued operations.

Ratemaking Activity

Overview

The method of determining regulated rates varies among the states in which our regulated businesses operate. The regulatory authorities have the responsibility of ensuring that utilities in their jurisdictions operate in the best interests of customers while providing utility companies the opportunity to earn a reasonable return on their investment. Generally, each

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regulatory authority reviews rate requests and establishes a rate structure intended to generate revenue sufficient to cover the costs of conducting business and to provide a reasonable return on invested capital.

Our rate strategy focuses on reducing or eliminating regulatory lag, obtaining adequate returns and providing stable, predictable margins, which benefit both our customers and the Company. As a result of our ratemaking efforts in recent years, Atmos Energy has:


•	Formula rate mechanisms in place in four states that provide for an annual rate review and adjustment to rates.


•	Infrastructure programs in place in the majority of our states that provide for an annual adjustment to rates for qualifying capital expenditures. Through our annual formula rate mechanisms and infrastructure programs, we have the ability to recover over 95 percent of our capital expenditures within six months.


•	Authorization in tariffs, statute or commission rules that allows us to defer certain elements of our cost of service such as depreciation, ad valorem taxes and pension costs, until they are included in rates.


•	WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 97 percent of our distribution gross profit.


•	The ability to recover the gas cost portion of bad debts in five states.

The following table provides a jurisdictional rate summary for our regulated operations. This information is for regulatory purposes only and may not be representative of our actual financial position.



Division	Jurisdiction	Effective Date of Last Rate/GRIP Action	Rate Base (thousands)⁽¹⁾	Authorized Rate of Return⁽¹⁾	Authorized Debt/ Equity Ratio	Authorized Return on Equity⁽¹⁾
Atmos Pipeline — Texas	Texas	08/01/2017	$1,767,600	8.87%	47/53	11.50%
Colorado-Kansas	Colorado	01/01/2016	129,094	7.82%	48/52	9.60%
	Colorado SSIR	01/01/2017	13,500	7.82%	48/52	9.60%
	Kansas	03/17/2016	200,564	(3)	(3)	(3)
	Kansas GSRS	02/09/2017	6,633	(3)	(3)	(3)
Kentucky/Mid-States	Kentucky	08/15/2016	335,833	(3)	(3)	(3)
	Kentucky PRP	11/14/2016	38,173	7.71%	51/49	9.80%
	Tennessee	06/01/2017	302,953	7.49%	47/53	9.80%
	Virginia	11/07/2016	47,581	(3)	(3)	(3)
Louisiana	Trans La	04/01/2017	156,200	7.50%	47/53	9.80%
	LGS	07/01/2017	385,435	7.43%	47/53	9.80%
Mid-Tex Cities	Texas	06/01/2017	2,362,937⁽²⁾	8.36%	45/55	10.50%
Mid-Tex — Dallas	Texas	06/01/2017	2,273,567⁽²⁾	8.38%	41/59	10.10%
Mississippi	Mississippi	01/12/2017	387,252	7.85%	47/53	9.73%
	Mississippi - SIR	01/01/2017	21,345	7.85%	47/53	9.73%
	Mississippi - SGR	01/01/2017	17,437	9.04%	47/53	12.00%
West Texas⁽⁴⁾	Texas	03/15/2017	(3)	(3)	(3)	10.50%
	Texas-GRIP	05/23/2017	476,665	8.57%	48/52	10.50%

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Division	Jurisdiction	Bad Debt Rider⁽⁵⁾	Formula Rate	Infrastructure Mechanism	Performance Based Rate Program⁽⁶⁾	WNA Period
Atmos Pipeline — Texas	Texas	No	Yes	Yes	N/A	N/A
Colorado-Kansas	Colorado	No	No	Yes	No	N/A
	Kansas	Yes	No	Yes	No	October-May
Kentucky/Mid-States	Kentucky	Yes	No	Yes	Yes	November-April
	Tennessee	Yes	Yes	No	Yes	October-April
	Virginia	Yes	No	Yes	No	January-December
Louisiana	Trans La	No	Yes	Yes	No	December-March
	LGS	No	Yes	Yes	No	December-March
Mid-Tex Cities	Texas	Yes	Yes	Yes	No	November-April
Mid-Tex — Dallas	Texas	Yes	Yes	Yes	No	November-April
Mississippi	Mississippi	No	Yes	Yes	Yes	November-April
West Texas⁽⁴⁾	Texas	Yes	Yes	Yes	No	October-May


(1)	The rate base, authorized rate of return and authorized return on equity presented in this table are those from the most recent regulatory filing for each jurisdiction. These rate bases, rates of return and returns on equity are not necessarily indicative of current or future rate bases, rates of return or returns on equity.


(2)	The Mid-Tex Rate Base amounts for the Mid-Tex Cities and Mid-Tex Dallas areas, combined, represent “system-wide”, or 100 percent, of the Mid-Tex Division’s rate base.


(3)	A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision.


(4)	On April 1, 2014, a rate case settlement approved by the West Texas Cities reestablished an annual rate mechanism for all West Texas Division cities except Amarillo, Channing, Dalhart and Lubbock.


(5)	The bad debt rider allows us to recover from ratepayers the gas cost portion of uncollectible accounts.


(6)	The performance-based rate program provides incentives to distribution companies to minimize purchased gas costs by allowing the companies and its customers to share the purchased gas costs savings.

Although substantial progress has been made in recent years by improving rate design and recovery of investment across Atmos Energy’s operating areas, we will continue to seek improvements in rate design to address cost variations and pursue tariffs that reduce regulatory lag associated with investments. Further, potential changes in federal energy policy, federal safety regulations and adverse economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.

Recent Ratemaking Activity

Substantially all of our regulated revenues in the fiscal years ended September 30, 2017, 2016 and 2015 were derived from sales at rates set by or subject to approval by local or state authorities. Net operating income increases resulting from ratemaking activity totaling $104.2 million, $122.5 million and $114.5 million, became effective in fiscal 2017, 2016 and 2015, as summarized below:



	Annual Increase to Operating Income For the Fiscal Year Ended September 30
Rate Action	2017		2016			2015
	(In thousands)
Annual formula rate mechanisms	$	90,427	$	114,974		$	113,706
Rate case filings	12,961		7,716			711
Other ratemaking activity	784		(183		)	78
	$	104,172	$	122,507		$	114,495

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Additionally, the following ratemaking efforts seeking $59.4 million in annual operating income were initiated during fiscal 2017 but had not been completed as of September 30, 2017:




Division	Rate Action	Jurisdiction	Operating Income Requested
			(In thousands)
Atmos Pipeline - Texas	GRIP	Texas	$	28,988
Colorado-Kansas	Rate Case	Colorado	2,916
Kentucky/Mid-States	SAVE ⁽¹⁾	Virginia	308
	PRP ^{(1) (4)}	Kentucky	5,638
	Rate Case	Kentucky	4,778
	ARM ⁽²⁾ True-Up	Tennessee	850
Mississippi	SIR ⁽¹⁾	Mississippi	8,111
	SGR ⁽³⁾	Mississippi	1,385
	SRF	Mississippi	4,214
Mid-Tex	Rate Case	City of Dallas	2,247
			$	59,435


(1)	The Steps to Advance Virginia Energy (SAVE) Plan, the Pipeline Replacement Program (PRP) and the System Integrity Rider (SIR) surcharges relate to long-term programs to replace aging infrastructure.


(2)	The Annual Rate Mechanism (ARM) is a formula rate mechanism that refreshes the Company's rates on an annual basis.


(3)	The Mississippi Supplemental Growth Rider (SGR) permits the Company to pursue eligible industrial growth projects beyond the division's normal main extension policies with prior approval from the Mississippi Public Service Commission. For fiscal 2017, the Commission approved a total of $13.2 million and has also approved $10.2 million under the program for fiscal 2018.


(4)	On October 27, 2017, we received a final order from the Kentucky Public Service Commission approving this increase.

Our recent ratemaking activity is discussed in greater detail below.

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 of our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions and our Atmos Pipeline - Texas Division with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state.



	Annual Formula Rate Mechanisms
State	Infrastructure Programs	Formula Rate Mechanisms

Colorado	System Safety and Integrity Rider (SSIR)	—
Kansas	Gas System Reliability Surcharge (GSRS)	—
Kentucky	Pipeline Replacement Program (PRP)	—
Louisiana	(1)	Rate Stabilization Clause (RSC)
Mississippi	System Integrity Rider (SIR)	Stable Rate Filing (SRF), Supplemental Growth Filing (SGR)
Tennessee	—	Annual Rate Mechanism (ARM)
Texas	Gas Reliability Infrastructure Program (GRIP), (1)	Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM)
Virginia	Steps to Advance Virginia Energy (SAVE)	—


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

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The following table summarizes our annual formula rate mechanisms with effective dates during the fiscal years ended September 30, 2017, 2016 and 2015:



Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
			(In thousands)
2017 Filings:
Louisiana	LGS	12/2016	$	6,237		07/01/2017
Mid-Tex	Mid-Tex DARR⁽¹⁾	09/2016	9,672			06/01/2017
Mid-Tex	Mid-Tex Cities RRM	12/2016	36,239			06/01/2017
Kentucky/Mid-States	Tennessee ARM	05/2018	6,740			06/01/2017
Mid-Tex	Mid-Tex Environs	12/2016	1,568			05/23/2017
West Texas	West Texas Environs	12/2016	872			05/23/2017
West Texas	West Texas ALDC	12/2016	4,682			04/25/2017
Louisiana	TransLa	09/2016	4,392			04/01/2017
West Texas	West Texas Cities RRM	09/2016	4,255			03/15/2017
Colorado-Kansas	Kansas	09/2016	801			02/09/2017
Mississippi	Mississippi-SRF	10/2017	4,390			02/01/2017
Mississippi	Mississippi-SIR	10/2017	3,334			01/01/2017
Mississippi	Mississippi-SGR	10/2017	1,292			01/01/2017
Colorado-Kansas	Colorado-SSIR	12/2017	1,350			01/01/2017
Kentucky/Mid-States	Kentucky-PRP	09/2017	4,981			10/14/2016
Kentucky/Mid-States	Virginia-SAVE	09/2017	(378		)	10/01/2016
Total 2017 Filings			$	90,427

2016 Filings:
Louisiana	LGS	12/2015	$	8,686		07/01/2016
Kentucky/Mid-States	Tennessee	05/2017	4,888			06/01/2016
Mid-Tex	Mid-Tex Cities RRM	12/2015	25,816			06/01/2016
Mid-Tex	Mid-Tex DARR	09/2015	5,429			06/01/2016
Mid-Tex	Mid-Tex Environs	12/2015	1,325			05/03/2016
Atmos Pipeline — Texas	Texas	12/2015	40,658			05/03/2016
West Texas	West Texas Environs	12/2015	646			05/03/2016
West Texas	West Texas ALDC	12/2015	3,484			04/26/2016
Louisiana	Trans La	09/2015	6,216			04/01/2016
Colorado-Kansas	Colorado	12/2016	764			01/01/2016
Mississippi	Mississippi-SRF	10/2016	9,192			01/01/2016
Mississippi	Mississippi-SGR	10/2016	250			12/01/2015
Kentucky/Mid-States	Kentucky-PRP	09/2016	3,786			10/01/2015
Kentucky/Mid-States	Virginia-SAVE	09/2016	118			10/01/2015
West Texas	West Texas Cities	09/2015	3,716			10/01/2015
Total 2016 Filings			$	114,974

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Division	Jurisdiction	Test Year Ended	Increase (Decrease) in Annual Operating Income			Effective Date
			(In thousands)
2015 Filings:
Louisiana	LGS	12/2014	$	1,321		07/01/2015
West Texas	West Texas Environs	12/2014	697			06/12/2015
Mid-Tex	Mid-Tex Environs	12/2014	1,158			06/01/2015
Mid-Tex	Mid-Tex Cities	12/2014	16,801			06/01/2015
Mid-Tex	Mid-Tex DARR	09/2014	4,420			06/01/2015
West Texas	West Texas ALDC	12/2014	4,593			05/01/2015
Atmos Pipeline — Texas	Texas	12/2014	37,248			04/08/2015
Louisiana	Trans La	09/2014	(286		)	04/01/2015
West Texas	West Texas Cities	09/2014	4,300			03/15/2015
Colorado-Kansas	Kansas	09/2014	301			02/01/2015
Mississippi	Mississippi-SRF	10/2015	4,441			02/01/2015
Mississippi	Mississippi-SGR	10/2015	782			11/01/2014
Kentucky/Mid-States	Kentucky	09/2015	4,382			10/10/2014
Kentucky/Mid-States	Virginia	09/2015	133			10/01/2014
Mid-Tex	Mid-Tex Cities	12/2013	33,415			06/01/2014
Total 2015 Filings			$	113,706

(1)

The Company and the City of Dallas were unable to arrive at a mutually agreeable settlement; therefore, the DARR rates were implemented, subject to refund, pending the outcome of an appeal filed with the Texas Railroad Commission. The examiners issued a proposal for decision on October 30, 2017 recommending an increase of $9.2 million. The Company expects the Commission to issue a final order in December 2017.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to 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 to our shareholders and ensure that we continue to safely deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:



Division	State	Increase in Annual Operating Income		Effective Date
		(In thousands)
2017 Rate Case Filings:
Atmos Pipeline - Texas	Texas	$	12,955	08/01/2017
Kentucky/Mid-States	Virginia	6		12/27/2016
Total 2017 Rate Case Filings		$	12,961
2016 Rate Case Filings:
Kentucky/Mid-States	Kentucky	$	2,723	08/15/2016
Kentucky/Mid-States	Virginia	537		04/01/2016
Colorado-Kansas	Kansas	2,372		03/17/2016
Colorado-Kansas	Colorado	2,084		01/01/2016
Total 2016 Rate Case Filings		$	7,716
2015 Rate Case Filings:
Kentucky/Mid-States	Tennessee	$	711	06/01/2015
Total 2015 Rate Case Filings		$	711

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Other Ratemaking Activity

The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2017, 2016 and 2015:



Division	Jurisdiction	Rate Activity	Increase in Annual Operating Income			Effective Date
			(In thousands)
2017 Other Rate Activity:
Colorado-Kansas	Kansas	Ad-Valorem⁽¹⁾	$	784		02/01/2017
Total 2017 Other Rate Activity			$	784
2016 Other Rate Activity:
Colorado-Kansas	Kansas	Ad-Valorem⁽¹⁾	$	(183	)	02/01/2016
Total 2016 Other Rate Activity			$	(183	)
2015 Other Rate Activity:
Colorado-Kansas	Kansas	Ad Valorem⁽¹⁾	$	78		02/01/2015
Total 2015 Other Rate Activity			$	78


(1)	The Ad Valorem filing relates to property taxes that are either over or uncollected compared to the amount included in our Kansas service area’s base rates.

Other Regulation

We are regulated by various state or local public utility authorities. We are also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of our transmission and distribution facilities. In addition, our operations are also subject to various state and federal laws regulating environmental matters. From time to time, we receive inquiries regarding various environmental matters. We believe that our properties and operations substantially comply with, and are operated in substantial conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. Our environmental claims have arisen primarily from former manufactured gas plant sites.

The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act, gas transportation services through our Atmos Pipeline—Texas assets “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting these assets to the jurisdiction of the FERC under the NGA. Additionally, the FERC has regulatory authority over the use and release of interstate pipeline and storage capacity. The FERC also has authority to detect and prevent market manipulation and to enforce compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. We have taken what we believe are the necessary and appropriate steps to comply with these regulations.

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act required various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, to establish regulations for implementation of many of the provisions of the Dodd-Frank Act. A number of those regulations were adopted; we enacted procedures and modified existing business practices and contractual arrangements to comply with such regulations.

Competition

Although our regulated distribution operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas, we do compete with other natural gas suppliers and suppliers of alternative fuels for sales to industrial customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential, commercial and industrial markets.

Our pipeline and storage operations historically faced competition from other existing intrastate pipelines seeking to provide or arrange transportation, storage and other services for customers. In the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

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Within our discontinued natural gas marketing operations, AEM competed with other natural gas marketers to provide natural gas management and other related services primarily to smaller customers requiring higher levels of balancing, scheduling and other related management services. AEM experienced increased competition in recent years primarily from investment banks and major integrated oil and natural gas companies who offer lower cost, basic services. The increased competition has reduced margins most notably on its high-volume accounts.

Employees

At September 30, 2017, we had 4,565 employees, consisting of 4,504 employees in our distribution operations and 61 employees in our pipeline and storage operations.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) are available free of charge at our website, www.atmosenergy.com, under “Publications and Filings” under the “Investors” tab, as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:

Shareholder Relations

Atmos Energy Corporation

P.O. Box 650205

Dallas, Texas 75265-0205

972-855-3729

Corporate Governance

In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer during fiscal 2017, Kim R. Cocklin, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on the Corporate Governance page of our website. We will also provide copies of all corporate governance documents free of charge upon request to Shareholder Relations at the address listed above.



ITEM 1A.	Risk Factors.

Our financial and operating results are subject to a number of risk factors, many of which are not within our control. Although we have tried to discuss key risk factors below, please be aware that other or new risks may prove to be important in the future. Investors should carefully consider the following discussion of risk factors as well as other information appearing in this report. These factors include the following:

The Company is dependent on continued access to the credit and capital markets to execute our business strategy.

Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation and Moody’s Investors Service, Inc. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private credit and public capital markets, we could see a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook or even a reduction in our credit ratings by one or more of the credit rating agencies. Such a downgrade could further limit our access to private credit and/or public capital markets and increase our costs of borrowing.

While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near term. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.

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We are subject to state and local regulations that affect our operations and financial results.

We are subject to regulatory oversight from various state and local regulatory authorities in the eight states that we serve. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of business, as a regulated entity, we often need to place assets in service and establish historical test periods before rate cases that seek to adjust our allowed returns to recover that investment can be filed. Further, the regulatory review process can be lengthy in the context of traditional ratemaking. Because of this process, we suffer the negative financial effects of having placed assets in service without the benefit of rate relief, which is commonly referred to as “regulatory lag.”

However, in the last several years, a number of regulatory authorities in the states we serve have approved rate mechanisms that provide for annual adjustments to rates that allow us to recover the cost of investments made to replace existing infrastructure or reflect changes in our cost of service. These mechanisms work to effectively reduce the regulatory lag inherent in the ratemaking process. However, regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. The regulatory process also involves the risk that regulatory authorities may (i) review our purchases of natural gas and adjust the amount of our gas costs that we pass through to our customers or (ii) limit the costs we may have incurred from our cost of service that can be recovered from customers.

A deterioration in economic conditions could adversely affect our customers and negatively impact our financial results.

Any adverse changes in economic conditions in the United States, especially in the states in which we operate, could adversely affect the financial resources of many domestic households and lead to an increase in mortgage defaults and significant decreases in the values of our customers’ homes and investment assets. As a result, our customers could seek to use less gas and make it more difficult for them to pay their gas bills. This would likely lead to slower collections and higher than normal levels of accounts receivable. This, in turn, could increase our financing requirements. Additionally, should economic conditions deteriorate, our industrial customers could seek alternative energy sources, which could result in lower sales volumes.

Inflation and increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.

Over time, inflation has caused increases in some of our operating expenses and has required assets to be replaced at higher costs. We have a process in place to continually review the adequacy of our gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates and intend to continue to do so. However, the ability to control expenses is an important factor that could impact future financial results.

In addition, rapid increases in the costs of purchased gas would cause us to experience a significant increase in short-term debt. We must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our natural gas distribution collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal accounts receivable. This could result in higher short-term debt levels, greater collection efforts and increased bad debt expense.

If contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner, our ability to meet our customers’ natural gas requirements may be impaired and our financial condition may be adversely affected.

In order to meet our customers’ annual and seasonal natural gas demands, we must obtain a sufficient supply of natural gas, interstate pipeline capacity and storage capacity. If we are unable to obtain these, either from our suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, our financial condition and results of operations may be adversely affected. If a substantial disruption to or reduction in interstate natural gas pipelines’ transmission and storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, terrorist or cyber-attacks or acts of war, our operations or financial results could be adversely affected.

We are exposed to market risks that are beyond our control, which could adversely affect our financial results and capital requirements.

We are subject to market risks beyond our control, including (i) commodity price volatility caused by market supply and demand dynamics, counterparty performance or counterparty creditworthiness, and (ii) interest rate risk. We are generally insulated from commodity price risk through our purchased gas cost mechanisms. With respect to interest rate risk, we have been operating in a relatively low interest-rate environment in recent years compared to historical norms for both short and long-term interest rates. However, increases in interest rates could adversely affect our future financial results to the extent that we do not recover our actual interest expense in our rates.

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The concentration of our operations in the State of Texas exposes our operations and financial results to economic conditions, weather patterns and regulatory decisions in Texas.

Over 50 percent of our distribution customers and most of our pipeline and storage assets and operations are located in the State of Texas. This concentration of our business in Texas means that our operations and financial results may be significantly affected by changes in the Texas economy in general, weather patterns and regulatory decisions by state and local regulatory authorities in Texas.

Our operations are subject to increased competition.

In residential and commercial customer markets, our distribution operations compete with other energy products, such as electricity and propane. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This could adversely impact our business if, as a result, our customer growth slows, reducing our ability to make capital expenditures, or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.

In the case of industrial customers, such as manufacturing plants, adverse economic conditions, including higher gas costs, could cause these customers to use alternative sources of energy, such as electricity, or bypass our systems in favor of special competitive contracts with lower per-unit costs. Our pipeline and storage operations historically have faced limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, in the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.

Adverse weather conditions could affect our operations or financial results.

We have weather-normalized rates for over 95 percent of our residential and commercial meters in our distribution operations, which substantially mitigates the adverse effects of warmer-than-normal weather for meters in those service areas. However, there is no assurance that we will continue to receive such regulatory protection from adverse weather in our rates in the future. The loss of such weather-normalized rates could have an adverse effect on our operations and financial results. In addition, our operating results may continue to vary somewhat with the actual temperatures during the winter heating season. Additionally, sustained cold weather could challenge our ability to adequately meet customer demand in our operations.

Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.

Our operations are capital-intensive. We must make significant capital expenditures to renew or replace our facilities on a long-term basis to improve the safety and reliability of our facilities and to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas we operate. In addition, we must continually build new capacity to serve the growing needs of the communities we serve. The magnitude of these expenditures may be affected by a number of factors, including new regulations, the general state of the economy and weather.

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. The cost and availability of borrowing funds from third party lenders or issuing equity is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit the amount of funds we can invest in our infrastructure.

The costs of providing health care benefits, pension and postretirement health care benefits and related funding requirements may increase substantially.

We provide health care benefits, a cash-balance pension plan and postretirement health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company is difficult to measure at this time.

The costs of providing a cash-balance pension plan to eligible full-time employees prior to 2011 and postretirement health care benefits to eligible full-time employees and related funding requirements could be influenced by changes in the market value of the assets funding our pension and postretirement health care plans. Any significant declines in the value of these investments due to sustained declines in equity markets or a reduction in bond yields could increase the costs of our pension and postretirement health care plans and related funding requirements in the future. Further, our costs of providing such benefits and related funding requirements are also subject to a number of factors, including (i) changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years; (ii) various actuarial calculations and assumptions which may differ materially from actual results due primarily to changing market and economic conditions, including changes in interest rates, and higher or lower withdrawal rates; and (iii) future government regulation.

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The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.

The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.

The average age of the employee base of Atmos Energy has been increasing for a number of years, with a number of employees becoming eligible to retire within the next five to 10 years. If we were unable to hire appropriate personnel to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from the increased use of contractors to replace retiring employees, loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

We may experience increased federal, state and local regulation of the safety of our operations.

The safety and protection of the public, our customers and our employees is our top priority. We constantly monitor and maintain our pipeline and distribution systems to ensure that natural gas is delivered safely, reliably and efficiently through our network of more than 75,000 miles of pipeline and distribution lines. However, in recent years, natural gas distribution and pipeline companies have continued to face increasing federal, state and local oversight of the safety of their operations. Although we believe these costs should be ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results.

Some of our operations are subject to increased federal regulatory oversight that could affect our operations and financial results.

FERC has regulatory authority over some of our operations, including the use and release of interstate pipeline and storage capacity. FERC has adopted rules designed to prevent market power abuse and market manipulation and to promote compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. These rules carry increased penalties for violations. Although we have taken steps to structure current and future transactions to comply with applicable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regulations issued by FERC in the future could also adversely affect our business, financial condition or financial results.

We are subject to environmental regulations which could adversely affect our operations or financial results.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could be significant to our financial results. In addition, existing environmental regulations may be revised or our operations may become subject to new regulations.

The operations and financial results of the Company could be adversely impacted as a result of climate change or related additional legislation or regulation in the future.

To the extent climate change occurs, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. To the extent climate change would result in warmer temperatures in our service territories, financial results could be adversely affected through lower gas volumes and revenues. Such climate change could also cause shifts in population, including customers moving away from our service territories near the Gulf Coast in Louisiana and Mississippi.

Another possible climate change would be more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase our costs to repair damaged facilities and restore service to our customers. If we were unable to deliver natural gas to our customers, our financial results would be impacted by lost revenues, and we generally would have to seek approval from regulators to recover restoration costs. To the extent we would be unable to recover those costs, or if higher rates resulting from our recovery of such costs would result in reduced demand for our services, our future business, financial condition or financial results could be adversely impacted.

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In addition, there have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The adoption of this type of legislation by Congress or similar legislation by states or the adoption of related regulations by federal or state governments mandating a substantial reduction in greenhouse gas emissions in the future could have far-reaching and significant impacts on the energy industry. Such new legislation or regulations could result in increased compliance costs for us or additional operating restrictions on our business, affect the demand for natural gas or impact the prices we charge to our customers. At this time, we cannot predict the potential impact of such laws or regulations that may be adopted on our future business, financial condition or financial results.

Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.

Our operations involve a number of hazards and operating risks that cannot be completely avoided, such as leaks, accidents and operational problems, which could cause loss of human life, as well as substantial financial losses resulting from property damage, damage to the environment and to our operations. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our transmission pipeline and storage facilities are near or are in populated areas, any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected.

Cyber-attacks or acts of cyber-terrorism 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.

Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our distribution and intrastate pipeline and storage operations and other business processes. Disruption of those systems could adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline and storage systems or serve our customers timely. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected.

In addition, we use our information technology systems to protect confidential or sensitive customer, employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of customer, employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. Even though we have insurance coverage in place for many of these cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.

Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.

Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance covering such risks may become more limited, which could increase the risk that an event could adversely affect our operations or financial results.



ITEM 1B.	Unresolved Staff Comments.

Not applicable.



ITEM 2.	Properties.

Distribution, transmission and related assets

At September 30, 2017, in our distribution segment, we owned an aggregate of 70,605 miles of underground distribution and transmission mains throughout our distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Through our pipeline and storage segment we owned 5,682 miles of gas transmission lines as well.

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Storage Assets

We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities at September 30, 2017:



State	Usable Capacity (Mcf)	Cushion Gas (Mcf)⁽¹⁾	Total Capacity (Mcf)	Maximum Daily Delivery Capability (Mcf)
Distribution Segment
Kentucky	7,881,596	9,562,283	17,443,879	158,100
Kansas	3,239,000	2,300,000	5,539,000	45,000
Mississippi	1,907,571	2,442,917	4,350,488	31,000
Total	13,028,167	14,305,200	27,333,367	234,100
Pipeline and Storage Segment
Texas	46,083,549	15,878,025	61,961,574	1,559,000
Louisiana	438,583	300,973	739,556	56,000
Total	46,522,132	16,178,998	62,701,130	1,615,000
Total	59,550,299	30,484,198	90,034,497	1,849,100


(1)	Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure.

Additionally, we contract for storage service in underground storage facilities on many of the interstate and intrastate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2017:



Segment	Division/Company	Maximum Storage Quantity (MMBtu)	Maximum Daily Withdrawal Quantity (MDWQ)⁽¹⁾
Distribution Segment
	Colorado-Kansas Division	5,129,562	124,830
	Kentucky/Mid-States Division	8,175,103	226,739
	Louisiana Division	2,480,779	173,605
	Mid-Tex Division	3,500,000	175,000
	Mississippi Division	3,823,800	126,334
	West Texas Division	5,000,000	161,000
Total		28,109,244	987,508
Pipeline and Storage Segment
	Trans Louisiana Gas Pipeline, Inc.	1,674,000	67,507

Total Contracted Storage Capacity		29,783,244	1,055,015


(1)	Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season.

Offices

Our administrative offices and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our service territory, the majority of which are located in leased facilities.



ITEM 3.	Legal Proceedings.

See Note 11 to the consolidated financial statements, which is incorporated in this Item 3 by reference.

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ITEM 4.	Mine Safety Disclosures.

Not applicable.

PART II



ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our stock trades on the New York Stock Exchange under the trading symbol “ATO.” The high and low sale prices and dividends paid per share of our common stock for fiscal 2017 and 2016 are listed below. The high and low prices listed are the closing NYSE quotes, as reported on the NYSE composite tape, for shares of our common stock:



	Fiscal 2017						Fiscal 2016
	High		Low		Dividends Paid		High		Low		Dividends Paid
Quarter ended:
December 31	$	74.73	$	68.96	$	0.45	$	64.25	$	57.82	$	0.42
March 31	80.40		73.21		0.45		74.33		61.74		0.42
June 30	85.54		78.90		0.45		81.32		70.60		0.42
September 30	88.69		82.42		0.45		81.16		71.88		0.42
					$	1.80					$	1.68

Dividends are payable at the discretion of our Board of Directors out of legally available funds. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. The number of record holders of our common stock on October 31, 2017 was 13,341. Future payments of dividends, and the amounts of these dividends, will depend on our financial condition, results of operations, capital requirements and other factors. We sold no securities during fiscal 2017 that were not registered under the Securities Act of 1933, as amended.

Performance Graph

The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the S&P 500 Stock Index and the cumulative total return of two different customized peer company groups, the New Comparison Company Index and the Old Comparison Company Index. The New Comparison Company Index is comprised of natural gas distribution companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2012 in our common stock, the S&P 500 Index and in the common stock of the companies in the New and Old Comparison Company Indices, as well as a reinvestment of dividends paid on such investments throughout the period.

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Comparison of Five-Year Cumulative Total Return

among Atmos Energy Corporation, S&P 500 Index

and Comparison Company Index



	Cumulative Total Return
	9/30/2012	9/30/2013	9/30/2014	9/30/2015	9/30/2016	9/30/2017
Atmos Energy Corporation	100.00	123.32	142.46	178.85	234.47	270.05
S&P 500 Index	100.00	119.34	142.89	142.02	163.93	194.44
Old Comparison Company Index	100.00	118.55	140.49	154.76	197.60	240.77
New Comparison Company Index	100.00	115.80	135.84	149.18	186.87	222.79

The New Comparison Company Index reflects the cumulative total return of companies in our peer group, which is comprised of a hybrid group of utility companies, primarily natural gas distribution companies, recommended by our independent executive compensation consulting firm and approved by the Board of Directors. The companies in the index are Alliant Energy Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, DTE Energy Company, National Fuel Gas Company, NextEra Energy, Inc., NiSource Inc., ONE Gas, Inc., Spire, Inc. (formerly The Laclede Group, Inc.), Vectren Corporation, WEC Energy Group, Inc., WGL Holdings, Inc., and Xcel Energy, Inc. The Old Comparison Company Index includes AGL Resources Inc.⁽¹⁾, CenterPoint Energy, Inc., CMS Energy Corporation, NiSource Inc., ONE Gas, Inc., Piedmont Natural Gas Company, Inc.⁽¹⁾, Questar Corporation⁽¹⁾, TECO Energy, Inc.⁽¹⁾, Spire, Inc. (formerly The Laclede Group, Inc.), Vectren Corporation and WGL Holdings, Inc.


(1)	AGL Resources Inc., Piedmont Natural Gas Company, Inc., Questar Corporation and TECO Energy, Inc. were acquired prior to September 30, 2017. As a result, the cumulative total return of these companies is not included in the Old Comparison Company Index represented in the graph above.

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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2017.



	Number of securities to be issued upon exercise of outstanding options, restricted stock units, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders:
1998 Long-Term Incentive Plan	1,143,243	⁽¹⁾	$	—	2,035,861
Total equity compensation plans approved by security holders	1,143,243		—		2,035,861
Equity compensation plans not approved by security holders	—		—		—
Total	1,143,243		$	—	2,035,861


(1)	Comprised of a total of 478,367 time-lapse restricted stock units, 361,381 director share units and 303,495 performance-based restricted stock units at the target level of performance granted under our 1998 Long-Term Incentive Plan.



ITEM 6.	Selected Financial Data.

The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein.



	Fiscal Year Ended September 30
	2017		2016		2015		2014		2013
	(In thousands, except per share data)
Results of Operations
Operating revenues	$	2,759,735	$	2,454,648	$	2,926,985	$	3,243,904	$	2,572,488
Gross profit	$	1,834,199	$	1,708,456	$	1,631,310	$	1,521,844	$	1,377,392
Income from continuing operations	$	382,711	$	345,542	$	305,623	$	270,331	$	232,378
Net income	$	396,421	$	350,104	$	315,075	$	289,817	$	243,194
Diluted income per share from continuing operations	$	3.60	$	3.33	$	3.00	$	2.76	$	2.52
Diluted net income per share	$	3.73	$	3.38	$	3.09	$	2.96	$	2.64
Cash dividends declared per share	$	1.80	$	1.68	$	1.56	$	1.48	$	1.40
Financial Condition
Net property, plant and equipment⁽¹⁾	$	9,259,182	$	8,268,606	$	7,416,700	$	6,709,926	$	6,013,975
Total assets	$	10,749,596	$	10,010,889	$	9,075,072	$	8,581,006	$	7,919,069
Capitalization:
Shareholders’ equity	$	3,898,666	$	3,463,059	$	3,194,797	$	3,086,232	$	2,580,409
Long-term debt (excluding current maturities)	3,067,045		2,188,779		2,437,515		2,442,288		2,440,472
Total capitalization	$	6,965,711	$	5,651,838	$	5,632,312	$	5,528,520	$	5,020,881


(1)	Amounts shown are net of assets held for sale related to the divestiture of our natural gas marketing business.

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ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.

INTRODUCTION

This section provides management’s discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors”. They should be considered in connection with evaluating forward-looking statements contained in this report or otherwise made by or on behalf of us since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995

The statements contained in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: our ability to continue to access the credit and capital markets to satisfy our liquidity requirements; regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; the impact of adverse economic conditions on our customers; the effects of inflation and changes in the availability and price of natural gas; 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 creditworthiness or performance and interest rate risk; the concentration of our distribution and pipeline and storage operations in Texas; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; the capital-intensive nature of our distribution and pipeline and storage businesses; increased costs of providing health care benefits along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain appropriate personnel; possible increased federal, state and local regulation of the safety of our operations; increased federal regulatory oversight and potential penalties; the impact of environmental regulations on our business; the impact of climate change or related additional legislation or regulation in the future; the inherent hazards and risks involved in operating our distribution and pipeline and storage businesses; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

CRITICAL ACCOUNTING POLICIES

Our 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 base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from estimates.

Our significant accounting policies are discussed in Notes 2 and 15 to our consolidated financial statements. The accounting policies discussed below are both important to the presentation of our financial condition and results of operations and require management to make difficult, subjective or complex accounting estimates. Accordingly, these critical accounting policies are reviewed periodically by the Audit Committee of the Board of Directors.

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Regulation	Our distribution and pipeline operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the United States. Accordingly, the financial results for these operations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts expected to be recovered or recognized are based upon historical experience and our understanding of the regulations. Discontinuing the application of this method of accounting for regulatory assets and liabilities or changes in the accounting for our various regulatory mechanisms could significantly increase our operating expenses as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income.	Decisions of regulatory authorities Issuance of new regulations or regulatory mechanisms Assessing the probability of the recoverability of deferred costs Continuing to meet the criteria of a cost-based, rate regulated entity for accounting purposes
Unbilled Revenue	We follow the revenue accrual method of accounting for distribution segment revenues whereby revenues attributable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. When permitted, we implement rates that have not been formally approved by our regulatory authorities, subject to refund.We recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented.	Estimates of delivered sales volumes based on actual tariff information and weather information and estimates of customer consumption and/or behavior Estimates of purchased gas costs related to estimated deliveries Estimates of amounts billed subject to refund

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Critical Accounting Policy	Summary of Policy	Factors Influencing Application of the Policy
Pension and other postretirement plans	Pension and other postretirement plan costs and liabilities are determined on an actuarial basis using a September 30 measurement date and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net periodic pension and postretirement benefit plan costs. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds. The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan costs are not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs over a period of approximately ten to twelve years. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this methodology will delay the impact of current market fluctuations on the pension expense for the period. We estimate the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date.	General economic and market conditions Assumed investment returns by asset class Assumed future salary increases Assumed discount rate Projected timing of future cash disbursements Health care cost experience trends Participant demographic information Actuarial mortality assumptions Impact of legislation Impact of regulation
Impairment assessments	We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstance indicate that such carrying values may not be recoverable, and at least annually for goodwill, as required by U.S. accounting standards. The evaluation of our goodwill balances and other long-lived assets or identifiable assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to the commodity prices, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge.	General economic and market conditions Projected timing and amount of future discounted cash flows Judgment in the evaluation of relevant data

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Non-GAAP Financial Measure

Our operations are affected by the cost of natural gas. The cost of gas 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, a non-GAAP financial measure defined as operating revenues less purchased gas cost, is a better indicator of our financial performance than operating revenues as it provides a useful and more relevant measure to analyze our financial performance. As such, the following discussion and analysis of our financial performance will reference gross profit rather than operating revenues and purchased gas cost individually.

RESULTS OF OPERATIONS

Overview

Atmos Energy strives to operate our businesses safely and reliably while delivering superior shareholder value. In recent years we have implemented rate designs that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. Additionally, we have significantly increased investments in the safety and reliability of our natural gas distribution and transmission infrastructure. This increased level of investment and timely recovery of these investments through our various regulatory mechanisms has resulted in increased earnings and operating cash flow in recent years.

This trend continued during fiscal 2017 as net income increased to $396.4 million, or $3.73 per diluted share for the year ended September 30, 2017, compared with net income of $350.1 million or $3.38 per diluted share in the prior year. The year-over-year increase largely reflects positive rate outcomes, which more than offset weather that was 12 percent warmer than the prior year. Results for fiscal 2017 include $0.13 per diluted share from discontinued operations. In January 2017, we completed the sale of our nonregulated natural gas marketing business. We received $140.3 million in cash proceeds, including working capital and recognized a net gain of $0.03 per diluted share on the sale in the second quarter of fiscal 2017. The proceeds from the sale were redeployed to fund infrastructure investments in our remaining businesses. As a result of the sale, we have fully exited the nonregulated gas marketing business.

Capital expenditures for fiscal 2017 totaled $1,137.1 million. Over 80 percent was invested to improve the safety and reliability of our distribution and transmission systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce regulatory lag to six months or less. Fiscal 2016 and 2017 spending under these and other mechanisms enabled the Company to complete 19 regulatory filings during fiscal 2017 that should increase annual operating income from regulated operations by $104.2 million. We funded over 75 percent of our current-year capital expenditure program primarily through operating cash flows of $867.1 million.

In addition, we acquired EnLink Pipeline in the first fiscal quarter of 2017 for an all–cash price of $86.1 million, inclusive of working capital. The acquisition of EnLink Pipeline increased the capacity on our APT intrastate pipeline to serve transportation customers in North Texas, which continues to experience significant population growth.

As we continue to invest in the safety and reliability of our distribution and transmission systems, we expect our capital spending will increase in future periods. We intend to fund future investments through a combination of internally generated cash flows and external debt and equity financing. During fiscal 2017 we received net proceeds of $885 million through the issuance of long-term debt and $99 million through the issuance of common stock. The net proceeds from these issuances were primarily used to repay maturing long-term debt, reduce short-term debt and for general corporate purposes, including funding a portion of our fiscal 2017 capital expenditures.

As a result of the continued contribution and stability of our earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 7.8 percent for fiscal 2018.

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Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2017, 2016 and 2015.



	For the Fiscal Year Ended September 30
	2017		2016		2015
	(In thousands, except per share data)
Operating revenues	$	2,759,735	$	2,454,648	$	2,926,985
Purchased gas cost	925,536		746,192		1,295,675
Operating expenses	1,106,653		1,051,226		1,019,078
Operating income	727,546		657,230		612,232
Interest charges	120,182		114,812		116,241
Income from continuing operations before income taxes	604,094		542,184		495,172
Net income from continuing operations	382,711		345,542		305,623
Net income from discontinued operations	13,710		4,562		9,452
Net income	$	396,421	$	350,104	$	315,075

Diluted net income from continuing operations per share	$	3.60	$	3.33	$	3.00
Diluted net income from discontinued operations per share	0.13		0.05		0.09
Diluted net income per share	$	3.73	$	3.38	$	3.09

Our consolidated net income during the last three fiscal years was earned across our business segments as follows:



	For the Fiscal Year Ended September 30
	2017		2016		2015
	(In thousands)
Distribution segment	$	268,369	$	233,830	$	205,820
Pipeline and storage segment	114,342		111,712		99,803
Net income from continuing operations	382,711		345,542		305,623
Net income from discontinued natural gas marketing operations	13,710		4,562		9,452
Net income	$	396,421	$	350,104	$	315,075

See the following discussion regarding the results of operations for each of our business 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 our distribution operations are our ability to earn our authorized rates of return, competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy, progress towards implementing that strategy and recent ratemaking initiatives in more detail.

We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Gross profit in our Texas and Mississippi service areas include franchise fees and gross receipt taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenue is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in revenue related taxes arising from changes in gas costs affect gross profit, over time the impact is offset within operating income.

Although the cost of gas typically does not have a direct impact on our gross profit, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings

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under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. Currently, gas cost risk has been mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.

During fiscal 2017, we completed 18 regulatory proceedings in our distribution segment, which should result in a $91.2 million increase in annual operating income.

Review of Financial and Operating Results

Financial and operational highlights for our distribution segment for the fiscal years ended September 30, 2017, 2016 and 2015 are presented below.



	For the Fiscal Year Ended September 30
	2017			2016		2015		2017 vs. 2016			2016 vs. 2015
	(In thousands, unless otherwise noted)
Operating revenues	$	2,649,175		$	2,339,778	$	2,821,362	$	309,397		$	(481,584	)
Purchased gas cost	1,269,456			1,058,576		1,574,447		210,880			(515,871		)
Gross profit	1,379,719			1,281,202		1,246,915		98,517			34,287
Operating expenses	874,077			839,318		824,223		34,759			15,095
Operating income	505,642			441,884		422,692		63,758			19,192
Miscellaneous income (expense)	(1,695		)	1,171		284		(2,866		)	887
Interest charges	79,789			78,238		83,087		1,551			(4,849		)
Income before income taxes	424,158			364,817		339,889		59,341			24,928
Income tax expense	155,789			130,987		134,069		24,802			(3,082		)
Net income	$	268,369		$	233,830	$	205,820	$	34,539		$	28,010
Consolidated distribution sales volumes — MMcf	246,825			258,650		307,985		(11,825		)	(49,335		)
Consolidated distribution transportation volumes — MMcf	141,540			133,378		135,972		8,162			(2,594		)
Total consolidated distribution throughput — MMcf	388,365			392,028		443,957		(3,663		)	(51,929		)
Consolidated distribution average cost of gas per Mcf sold	$	5.14		$	4.09	$	5.11	$	1.05		$	(1.02	)

Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016

Net income for our distribution segment increased 15 percent, primarily due to a $98.5 million increase in gross profit, partially offset by a $34.8 million increase in operating expenses. The year-to-date increase in gross profit primarily reflects:


•	a $72.4 million net increase in rate adjustments, primarily in our Mid-Tex, Louisiana, Mississippi and West Texas Divisions.


•	Customer growth, primarily in our Mid-Tex and Kentucky/Mid-States Divisions, which contributed an incremental $5.8 million.


•	a $5.8 million increase in transportation gross profit, primarily in the Kentucky/Mid-States and Mid-Tex Divisions.


•	a $5.2 million increase in revenue-related taxes primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $5.1 million increase in the related tax expense.


•	a $2.9 million increase in net consumption, despite weather that was 12 percent warmer than the prior year.

The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, was primarily due to increased depreciation expense and property taxes associated with increased capital investments, higher employee-related costs, increased revenue-related taxes, as discussed above, and higher pipeline maintenance and related activities, partially offset by lower legal costs.

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Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our distribution segment increased 14 percent, primarily due to a $34.3 million increase in gross profit, partially offset by a $15.1 million increase in operating expenses. The year-over-year increase in gross profit primarily reflects:


•	a $47.5 million net increase in rate adjustments. Our Mid-Tex Division accounted for $20.9 million of this increase. We also experienced increases in our Mississippi and West Texas Divisions.


•	The impact of weather that was 25 percent warmer than the prior year, before adjusting for weather normalization mechanisms. Therefore, although sales volumes declined 16 percent, gross margin experienced just a $3.4 million decline from lower consumption.


•	Customer growth, primarily in our Mid-Tex, Louisiana and Tennessee service areas, which contributed an incremental $6.6 million.


•	a $15.4 million decrease in revenue-related taxes primarily in our Mid-Tex and West Texas Divisions, offset by a corresponding $16.1 million decrease in the related tax expense.

The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, was primarily due to pipeline maintenance and related activities and increased depreciation expense associated with increased capital investments.

Net income for the year ended September 30, 2016 included a $5.0 million income tax benefit for equity awards that vested during the current year as a result of adopting the new stock-based accounting guidance, as described in Note 2 to our consolidated financial statements.

The following table shows our operating income by distribution division, in order of total rate base, for the fiscal years ended September 30, 2017, 2016 and 2015. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.



	For the Fiscal Year Ended September 30
	2017		2016		2015		2017 vs. 2016		2016 vs. 2015
	(In thousands)
Mid-Tex	$	233,158	$	210,608	$	196,847	$	22,550	$	13,761
Kentucky/Mid-States	75,214		63,730		58,849		11,484		4,881
Louisiana	69,300		55,857		55,633		13,443		224
West Texas	46,859		41,131		37,041		5,728		4,090
Mississippi	38,505		37,398		34,210		1,107		3,188
Colorado-Kansas	34,658		31,840		28,606		2,818		3,234
Other	7,948		1,320		11,506		6,628		(10,186		)
Total	$	505,642	$	441,884	$	422,692	$	63,758	$	19,192

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of Atmos Pipeline-Texas Division (APT) and our natural gas transmission operations in Louisiana, which were previously included in our former nonregulated segment. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT manages five underground storage reservoirs in Texas.

Our natural gas transmission operations in Louisiana are comprised of a proprietary 21-mile pipeline located in New Orleans, Louisiana that is primarily used to aggregate gas supply for our distribution division in Louisiana under a long-term contract and on a more limited basis, to third parties. The demand fee charged to our Louisiana distribution division for these services is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.

Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in APT's service area. Natural gas prices do not directly impact the results of this segment as revenues

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are derived from the transportation of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the markets that we serve, which may influence the level of throughput we may be able to transport on our pipeline. Further, natural gas price differences between the various hubs that we serve determine the market value for transportation services between those geographic areas.

The results of APT are also significantly impacted by the natural gas requirements of the Mid-Tex Division because APT is the Mid-Tex Division's primary transporter of natural gas.

APT annually uses the Gas Reliability Infrastructure Program (GRIP) to recover capital costs incurred in the prior calendar year. However, GRIP also requires a utility to file a statement of intent at least once every five years to review its costs and expenses, including capital costs filed for recovery under GRIP. On August 1, 2017, a final order was issued in our most recent APT rate case, resulting in a $13 million increase in annual operating income. On September 1, 2017, APT filed its 2016 GRIP filing covering changes in net investment from October 1, 2016 through December 31, 2016 with a requested increase in operating income of $29.0 million.

On December 21, 2016, the Louisiana Public Service Commission approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017. This agreement replaces the existing agreement that expired in September 2017.

Finally, as a regulated pipeline, the operations of APT may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

Review of Financial and Operating Results

Financial and operational highlights for our pipeline and storage segment for the fiscal years ended September 30, 2017, 2016 and 2015 are presented below.



	For the Fiscal Year Ended September 30
	2017			2016			2015			2017 vs. 2016			2016 vs. 2015
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	338,850		$	315,726		$	271,009		$	23,124		$	44,717
Third-party transportation revenue	100,100			89,498			98,638			10,602			(9,140		)
Other revenue	18,080			21,972			15,310			(3,892		)	6,662
Total operating revenues	457,030			427,196			384,957			29,834			42,239
Total purchased gas cost	2,506			(58		)	562			2,564			(620		)
Gross profit	454,524			427,254			384,395			27,270			42,859
Operating expenses	232,620			211,908			194,855			20,712			17,053
Operating income	221,904			215,346			189,540			6,558			25,806
Miscellaneous expense	(1,575		)	(1,405		)	(1,103		)	(170		)	(302		)
Interest charges	40,393			36,574			33,154			3,819			3,420
Income before income taxes	179,936			177,367			155,283			2,569			22,084
Income tax expense	65,594			65,655			55,480			(61		)	10,175
Net income	$	114,342		$	111,712		$	99,803		$	2,630		$	11,909
Gross pipeline transportation volumes — MMcf	770,348			686,042			745,728			84,306			(59,686		)
Consolidated pipeline transportation volumes — MMcf	596,179			505,303			528,068			90,876			(22,765		)

Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016

Net income for our pipeline and storage segment increased two percent, primarily due to a $27.3 million increase in gross profit, partially offset by a $20.7 million increase in operating expenses. The increase in gross profit primarily reflects a $24.6 million increase in rates from the approved 2016 GRIP filing and the rate case finalized in August 2017 and higher through system revenue of $8.3 million, largely related to higher basis spreads due to increased production in the Permian Basin and incremental throughput on the EnLink Pipeline, which was acquired in the first quarter of fiscal 2017. Partially offsetting these increases was a decrease in gross profit of $2.3 million due to lower excess retention gas sales in the current year. As noted above, as a result of the annual rate case, we did not file our annual GRIP filing during the second quarter of fiscal 2017, which influenced this segment's performance year-over-year.

Operating expenses increased $20.7 million, primarily due to increased depreciation expense and property taxes associated with increased capital investments.

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Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our pipeline and storage segment increased 12 percent, primarily due to a $42.9 million increase in gross profit, partially offset by a $17.1 million increase in operating expenses. The increase in gross profit primarily reflects a $39.6 million increase in rates from the approved 2015 and 2016 GRIP filings. Additionally, gross profit reflects a $3.6 million increase from the sale of excess retention gas, which was offset by a $4.0 million decrease in through-system volumes and lower storage and blending fees due to warmer weather in the current year compared to the prior year.

Operating expenses increased $17.1 million, primarily due to increased levels of pipeline maintenance activities to improve the safety and reliability of our system and increased property taxes and depreciation expense associated with increased capital investments.

Natural Gas Marketing Segment

Through December 31, 2016, we were engaged in an unregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices.

As more fully described in Note 15, effective January 1, 2017, we sold all of the equity interests of AEM to CenterPoint Energy Services, Inc. (CES), a subsidiary of CenterPoint Energy Inc. As a result of the sale, Atmos Energy has fully exited the nonregulated natural gas marketing business. Accordingly, these operations have been reported as discontinued operations.

Review of Financial and Operating Results

Financial and operational highlights for our natural gas marketing segment for the fiscal years ended September 30, 2017, 2016 and 2015 are presented below.



	For the Fiscal Year Ended September 30
	2017		2016		2015			2017 vs. 2016			2016 vs. 2015
	(In thousands, unless otherwise noted)
Operating revenues	$	303,474	$	1,005,090	$	1,409,071		$	(701,616	)	$	(403,981	)
Purchased gas cost	277,554		968,118		1,359,832			(690,564		)	(391,714		)
Gross profit	25,920		36,972		49,239			(11,052		)	(12,267		)
Operating expenses	7,874		26,184		30,076			(18,310		)	(3,892		)
Operating income	18,046		10,788		19,163			7,258			(8,375		)
Miscellaneous income (expense)	30		109		(1,863		)	(79		)	1,972
Interest charges	241		2,604		1,707			(2,363		)	897
Income before income taxes	17,835		8,293		15,593			9,542			(7,300		)
Income tax expense	6,841		3,731		6,141			3,110			(2,410		)
Income from discontinued operations	10,994		4,562		9,452			6,432			(4,890		)
Gain on sale of discontinued operations, net of tax	2,716		—		—			2,716			—
Net income from discontinued operations	$	13,710	$	4,562	$	9,452		$	9,148		$	(4,890	)
Gross natural gas marketing delivered gas sales volumes — MMcf	90,223		371,319		395,409			(281,096		)	(24,090		)
Consolidated natural gas marketing delivered gas sales volumes — MMcf	78,646		325,537		336,792			(246,891		)	(11,255		)
Net physical position (Bcf)	—		18.1		12.4			(18.1		)	5.7

Fiscal year ended September 30, 2017 compared with fiscal year ended September 30, 2016

The $9.1 million year-over-year increase in net income from discontinued operations primarily reflects the recognition of a net $6.6 million noncash gain from unwinding hedge accounting for certain of the natural gas marketing business's financial positions in connection with the sale of AEM. Additionally we recognized a $2.7 million net gain on sale upon completion of the sale of AEM to CES in January 2017.

Fiscal year ended September 30, 2016 compared with fiscal year ended September 30, 2015

Net income for our natural gas marketing segment decreased 52 percent compared to fiscal 2015 primarily due to lower gross profit.

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The $12.3 million year-over-year decrease in gross profit was primarily due to a decrease in asset optimization margins combined with a decrease in delivered gas margins. As a result of warmer weather, we modified storage positions to meet customer needs throughout the winter and captured less favorable spread values on the related supply repurchases. Additionally, we experienced an increase in storage demand fees related primarily to higher park and loan activity. Delivered gas margins decreased primarily due to a three percent decrease in consolidated sales volumes due to warmer weather. However, lower net transportation costs and other variable costs driven by fewer deliveries resulted in per-unit margins of 12 cents per Mcf, which is consistent with fiscal 2015 per-unit margins.

Operating expenses decreased $3.9 million, primarily due to lower administrative expenses.

LIQUIDITY AND CAPITAL RESOURCES

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. External debt financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program and three committed revolving credit facilities with a total availability from third-party lenders of approximately $1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity-to-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for fiscal year 2018 and beyond.

To support our capital market activities, we filed a registration statement with the SEC on March 28, 2016 to issue, from time to time, up to $2.5 billion in common stock and/or debt securities. At September 30, 2017, approximately $1.6 billion of securities remained available for issuance under the shelf registration statement, which expires March 26, 2019.

The following table presents our capitalization as of September 30, 2017 and 2016:



	September 30
	2017				2016
	(In thousands, except percentages)
Short-term debt	$	447,745	6.0	%	$	829,811