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: state and local regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; the inherent hazards and risks involved in distributing, transporting and storing natural gas; the capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain operational, technical and managerial personnel; the impact of climate change or related additional legislation or regulation in the future; the threat of cyber-attacks or acts of cyber-terrorism that could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information; natural disasters, terrorist activities or other events and other risks and uncertainties discussed herein, all of which are difficult to predict and many of which are beyond our control. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

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.

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

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

Non-GAAP Financial Measures

Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the income statement as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Contribution Margin, a non-GAAP financial measure, defined as operating revenues less purchased gas cost, is a more useful and relevant measure to analyze our financial performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference Contribution Margin rather than operating revenues and purchased gas cost individually. Further, the term Contribution Margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

As described further in Note 12, the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a non-cash income tax benefit of $158.8 million for the fiscal year ended September 30, 2018. Due to the non-recurring nature of this benefit, we believe that income from continuing operations and diluted earnings per share from continuing operations before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than income from continuing operations and consolidated diluted earnings per share from continuing operations in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis to the prior year. Accordingly, the following discussion and analysis of our financial performance will reference adjusted income from continuing operations and diluted earnings per share, which is calculated as follows:

	For the Fiscal Year Ended September 30
	2018				2017				Change
	(In thousands, except per share data)
Income from continuing operations	$	603,064			$	382,711			$	220,353
TCJA non-cash income tax benefit	(158,782		)		—				(158,782		)
Adjusted income from continuing operations	$	444,282			$	382,711			$	61,571
Consolidated diluted EPS from continuing operations	$	5.43			$	3.60			$	1.83
Diluted EPS from TCJA non-cash income tax benefit	(1.43		)		—				(1.43		)
Adjusted diluted EPS from continuing operations	$	4.00			$	3.60			$	0.40

RESULTS OF OPERATIONS

Overview

Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires a significant level of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs and mechanisms that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.

During fiscal 2018, we recorded income from continuing operations of $603.1 million, or $5.43 per diluted share, compared to income from continuing operations of $382.7 million, or $3.60 per diluted share in the prior year.

After adjusting for the nonrecurring benefit recognized after implementing the TCJA, we recognized adjusted income from continuing operations of $444.3 million, or $4.00 per diluted share for the year ended September 30, 2018, compared to adjusted income from continuing operations of $382.7 million, or $3.60 per diluted share for the year ended September 30, 2017. The year-over-year increase of $61.6 million, or 16 percent, largely reflects rate increases driven by safety and reliability spending, weather that was 36 percent colder than the prior year, customer growth in our distribution business and the impact of the TCJA on our effective income tax rate, partially offset by reduced revenues as a result of implementing the TCJA. During the year ended September 30, 2018, we completed 18 regulatory proceedings, resulting in an increase in annual operating income of $80.1 million and had 11 ratemaking efforts in progress at September 30, 2018, seeking a total increase in annual operating income of $52.8 million.

Capital expenditures for fiscal 2018 totaled $1,467.6 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. We funded our current-year capital expenditures program primarily through operating cash flows of $1,124.7 million. Additionally, we issued $400 million of common stock during the year ended September 30, 2018. The net proceeds from the issuance were primarily used to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes. On October 4, 2018, we completed a public offering of $600 million 4.30% senior notes due 2048. We received net proceeds from the offering, after underwriting discount and estimated offering expenses of approximately $591 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 4.37% after giving effect to the offering costs.

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 8.2% percent for fiscal 2019.

TCJA Impact

The TCJA introduced several significant changes to corporate income tax laws in the United States, which have been reflected in our consolidated financial statements for the year ended September 30, 2018. As a rate regulated entity, the effects of lower tax rates included in our cost of service rates will ultimately flow through to our utility customers in the form of adjusted rates. Therefore, the favorable impact of the reduction in our federal statutory income tax rate on our financial performance will be limited to items that impact our income before income taxes in the current period that have not yet been reflected in our rates (most notably increases to and decreases in commission-approved regulatory assets and liabilities recorded on our consolidated balance sheet) and market-based revenues that are earned from customers who utilize our assets. Note 12 to the consolidated financial statements details the various impacts of the TCJA on our financial position and results from operations. The most significant changes are summarized as follows:

•	Because our fiscal year started on October 1, 2017, our federal statutory income tax rate for fiscal 2018 was reduced from 35% to 24.5%. Our effective income tax rate for fiscal 2018 was 27.5%, before the effect of the return of the excess deferred tax liability and the one-time, non-cash income tax benefit. Our federal statutory income tax rate declined to 21% on October 1, 2018.

•

As a result of implementing the TCJA, we remeasured our net deferred tax liability using our new federal statutory income tax rate, which reduced our net deferred tax liability by $905.3 million. Of this amount, $746.5 million was reclassified to a regulatory liability called excess deferred tax liability. The remaining $158.8 million was recognized as a one-time, non-cash income tax benefit in our consolidated statement of income for the year ended September 30, 2018.

•	Atmos Energy supports our regulators' efforts to ensure our utility customers receive the full benefits of changes in our cost of service rates arising from tax reform. Income taxes, like other costs, are passed through to our customers in our rates; however, changes to customer rates must be approved by our regulators.

◦

Beginning in the second quarter of fiscal 2018, we established regulatory liabilities in all our jurisdictions for the difference in taxes included in our cost of service rates that have been calculated based on a 35% statutory income tax rate and a 21% statutory income tax rate, which reduced our revenues. We have received approval from most of our regulators to adjust customer rates for the lower statutory income tax rate.

◦	We have also received approval from regulators in several of our states to return amounts to customers related to the regulatory liability recorded for differences in our cost of service rates due to the change in the statutory income tax rate within one year.

◦	We have received approval from regulators in several of our states to begin returning the Excess Deferred Tax Liability created upon implementation of the TCJA, as discussed above, over a period ranging from 18 to 40 years. For the year ended September 30, 2018, we amortized $1.6 million of this regulatory liability.

•

The enactment of the TCJA is expected to reduce our future cash flows from operations primarily due to 1) the collection of taxes at a lower rate and 2) the return of regulatory liabilities established in response to the enactment of the TCJA and regulatory activities to our utility customers. We intend to externally finance this reduction in operating cash flow in a balanced fashion in order to maintain an equity-to-total-capitalization ratio ranging from 50% to 60% to maintain our current credit ratings.

Consolidated Results

The following table presents our consolidated financial highlights for the fiscal years ended September 30, 2018, 2017 and 2016.

	For the Fiscal Year Ended September 30
	2018				2017				2016
	(In thousands, except per share data)
Operating revenues	$	3,115,546			$	2,759,735			$	2,454,648
Purchased gas cost	1,167,848				925,536				746,192
Operating expenses	1,224,564				1,106,653				1,051,226
Operating income	723,134				727,546				657,230
Interest charges	106,646				120,182				114,812
Income from continuing operations before income taxes	611,144				604,094				542,184
Income tax expense	166,862				221,383				196,642
One-time, non-cash income tax benefit	(158,782		)		—				—
Net income from continuing operations	603,064				382,711				345,542
Net income from discontinued operations	—				13,710				4,562
Net income	$	603,064			$	396,421			$	350,104
Diluted net income from continuing operations per share	$	5.43			$	3.60			$	3.33
Diluted net income from discontinued operations per share	—				0.13				0.05
Diluted net income per share	$	5.43			$	3.73			$	3.38

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
	2018				2017				2016
	(In thousands)
Distribution segment	$	442,966			$	268,369			$	233,830
Pipeline and storage segment	160,098				114,342				111,712
Net income from continuing operations	603,064				382,711				345,542
Net income from discontinued natural gas marketing operations	—				13,710				4,562
Net income	$	603,064			$	396,421			$	350,104

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. Contribution margin 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 Contribution Margin, over time the impact is offset within operating income.

Although the cost of gas typically does not have a direct impact on our Contribution Margin, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. Currently, gas cost risk has been mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.

During fiscal 2018, we completed 16 regulatory proceedings in our distribution segment, resulting in an $8.9 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, 2018, 2017 and 2016 are presented below.

	For the Fiscal Year Ended September 30
	2018				2017				2016				2018 vs. 2017				2017 vs. 2016
	(In thousands, unless otherwise noted)
Operating revenues	$	3,003,047			$	2,649,175			$	2,339,778			$	353,872			$	309,397
Purchased gas cost	1,559,836				1,269,456				1,058,576				290,380				210,880
Contribution Margin	1,443,211				1,379,719				1,281,202				63,492				98,517
Operating expenses	962,344				874,077				839,318				88,267				34,759
Operating income	480,867				505,642				441,884				(24,775		)		63,758
Miscellaneous income (expense)	(1,849		)		(1,695		)		1,171				(154		)		(2,866		)
Interest charges	65,850				79,789				78,238				(13,939		)		1,551
Income before income taxes	413,168				424,158				364,817				(10,990		)		59,341
Income tax expense	107,880				155,789				130,987				(47,909		)		24,802
One-time, non-cash income tax benefit	(137,678		)		—				—				(137,678		)		—
Net income	$	442,966			$	268,369			$	233,830			$	174,597			$	34,539
Consolidated distribution sales volumes — MMcf	300,817				246,825				258,650				53,992				(11,825		)
Consolidated distribution transportation volumes — MMcf	150,566				141,540				133,378				9,026				8,162
Total consolidated distribution throughput — MMcf	451,383				388,365				392,028				63,018				(3,663		)
Consolidated distribution average cost of gas per Mcf sold	$	5.19			$	5.14			$	4.09			$	0.05			$	1.05

Fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017

Income before income taxes for our distribution segment decreased three percent, primarily due to an $88.3 million increase in operating expenses, partially offset by a $63.5 million increase in Contribution Margin. The year-to-date increase in Contribution Margin primarily reflects:

•	a $70.7 million net increase in rate adjustments, excluding rate adjustments resulting from the TCJA, primarily in our Mid-Tex, Kentucky/Mid-States, Mississippi and West Texas Divisions. These rate adjustments were driven primarily by increased safety and reliability spending.

•	a $12.2 million increase in net consumption, primarily in our Mid-Tex, Mississippi, Kentucky/Mid-States and Louisiana Divisions.

•	a $14.8 million increase in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $15.5 million increase in the related tax expense.

•	an $8.9 million increase in transportation margin primarily in our Kentucky/Mid-States Division.

•	an $8.4 million increase from customer growth, primarily in our Mid-Tex Division.

•

a $51.3 million decrease in Contribution Margin due to the inclusion of the lower statutory federal income tax rate in our revenues due to implementation of the TCJA. Of this amount, $30.0 million has been reflected in customer bills. The remaining $21.3 million relates to the establishment of regulatory liabilities for the difference between the former 35% federal statutory income tax rate and the current 21% rate.

The increase in operating expenses, which include operation and maintenance expense, bad debt expense, depreciation and amortization expense and taxes, other than income, largely reflects expenses incurred after we decided to undertake a planned outage of our natural gas distribution system in Northwest Dallas that affected approximately 2,400 homes. While the system was replaced, we provided financial assistance to the affected residents and incurred other related costs of approximately $24 million.

The remaining increase in operating expenses is primarily attributable to an increase in employee-related costs and incremental system integrity activities of $19.3 million, increased revenue-related taxes, as discussed above, and increased depreciation and property taxes of $22.5 million associated with increased capital investments.

Interest charges decreased $13.9 million, primarily from interest deferrals associated with our infrastructure spending activities in Texas and Louisiana.

The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 36.7% to 26.1%, as a result of the TCJA. During fiscal 2018, in certain jurisdictions, we began amortizing the excess deferred income taxes in the amount of $1.6 million.

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

Income before income taxes for our distribution segment increased 16 percent, primarily due to a $98.5 million increase in Contribution Margin, partially offset by a $34.8 million increase in operating expenses. The year-over-year increase in Contribution Margin primarily reflects:

•	a $72.4 million net increase in rate adjustments, primarily in our Mid-Tex, Louisiana, Mississippi and West Texas Divisions. These rate adjustments were driven primarily by increased safety and reliability spending.

•	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 margin, 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 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.

The following table shows our operating income by distribution division, in order of total rate base, for the fiscal years ended September 30, 2018, 2017 and 2016. 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
	2018				2017				2016				2018 vs. 2017				2017 vs. 2016
	(In thousands)
Mid-Tex	$	202,444			$	233,158			$	210,608			$	(30,714	)		$	22,550
Kentucky/Mid-States	81,105				75,214				63,730				5,891				11,484
Louisiana	70,609				69,300				55,857				1,309				13,443
West Texas	45,494				46,859				41,131				(1,365		)		5,728
Mississippi	47,237				38,505				37,398				8,732				1,107
Colorado-Kansas	32,333				34,658				31,840				(2,325		)		2,818
Other	1,645				7,948				1,320				(6,303		)		6,628
Total	$	480,867			$	505,642			$	441,884			$	(24,775	)		$	63,758

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. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Delaware and Midland Basins of West Texas. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas.

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

Our pipeline and storage segment is impacted by seasonal weather patterns, competitive factors in the energy industry and economic conditions in our Texas and Louisiana service areas. Natural gas prices do not directly impact the results of this segment as revenues are derived from the transportation and storage of natural gas. However, natural gas prices and demand for natural gas could influence the level of drilling activity in the supply areas that we serve, which may influence the level of throughput we may be able to transport on our pipelines. Further, natural gas price differences between the various hubs that we serve in Texas could influences the volumes of gas transported for shippers through Texas pipeline systems and rates for such transportation.

The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.

APT annually uses the Gas Reliability Infrastructure Program (GRIP) to recover capital costs incurred in the prior calendar year. Following the conclusion of its rate case in August 2017, APT made a GRIP filing that covered changes in net investment from October 1, 2016 through December 31, 2016 with a requested increase in operating income of $29.0 million. On December 5, 2017, the filing was approved. On February 15, 2018, APT made a GRIP filing that covered changes in net investment from January 1, 2017 through December 31, 2017 with a requested increase in operating income of $42.2 million. On May 22, 2018, the filing was approved.

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.

Review of Financial and Operating Results

Financial and operational highlights for our pipeline and storage segment for the fiscal years ended September 30, 2018, 2017 and 2016 are presented below.

	For the Fiscal Year Ended September 30
	2018				2017				2016				2018 vs. 2017				2017 vs. 2016
	(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue	$	354,885			$	338,850			$	315,726			$	16,035			$	23,124
Third-party transportation revenue	140,231				100,100				89,498				40,131				10,602
Other revenue	12,597				18,080				21,972				(5,483		)		(3,892		)
Total operating revenues	507,713				457,030				427,196				50,683				29,834
Total purchased gas cost	1,978				2,506				(58		)		(528		)		2,564
Contribution Margin	505,735				454,524				427,254				51,211				27,270
Operating expenses	263,468				232,620				211,908				30,848				20,712
Operating income	242,267				221,904				215,346				20,363				6,558
Miscellaneous expense	(3,495		)		(1,575		)		(1,405		)		(1,920		)		(170		)
Interest charges	40,796				40,393				36,574				403				3,819
Income before income taxes	197,976				179,936				177,367				18,040				2,569
Income tax expense	58,982				65,594				65,655				(6,612		)		(61		)
One-time, non-cash income tax benefit	(21,104		)		—				—				(21,104		)		—
Net income	$	160,098			$	114,342			$	111,712			$	45,756			$	2,630
Gross pipeline transportation volumes — MMcf	871,904				770,348				686,042				101,556				84,306
Consolidated pipeline transportation volumes — MMcf	663,900				596,179				505,303				67,721				90,876

Fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017

Income before income taxes for our pipeline and storage segment increased ten percent, primarily due to a $51.2 million increase in Contribution Margin, partially offset by a $30.8 million increase in operating expenses. The increase in Contribution Margin primarily reflects:

•	a $74.3 million increase in rates from the approved APT rate case and the GRIP filings approved in December 2017 and May 2018. The increase in rates was driven primarily by increased safety and reliability spending.

•	a net increase of $1.3 million due to wider spreads and positive supply and demand dynamics affecting the Permian Basin.

•	a $24.1 million decrease in Contribution Margin due to the inclusion of the lower statutory federal income tax rate in our revenues due to implementation of the TCJA. Of this amount, $11.4 million has been reflected in customer bills. The remaining $12.7 million relates to the establishment of regulatory liabilities, as discussed above.

The increase in operating expenses is primarily due to higher depreciation expense of $25.8 million associated with increased capital investments and an increase in employee-related costs.

The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 36.5% to 29.8%, as a result of the TCJA.

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

Income before income taxes for our pipeline and storage segment increased slightly, primarily due to a $27.3 million increase in Contribution Margin, partially offset by a $20.7 million increase in operating expenses. The increase in Contribution Margin 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 a pipeline acquired in the first quarter of fiscal 2017. Partially offsetting these increases was a decrease in Contribution Margin 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.

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, a gain on sale from discontinued operations for $2.7 million was recorded and net income of $11.0 million for AEM is reported as discontinued operations for the year ended September 30, 2017, compared to net income of $4.6 million for AEM reported for discontinued operations for the year ended September 30, 2016.

Review of Financial and Operating Results

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

	For the Fiscal Year Ended September 30
	2017				2016				2017 vs. 2016
	(In thousands, unless otherwise noted)
Operating revenues	$	303,474			$	1,005,090			$	(701,616	)
Purchased gas cost	277,554				968,118				(690,564		)
Contribution Margin	25,920				36,972				(11,052		)
Operating expenses	7,874				26,184				(18,310		)
Operating income	18,046				10,788				7,258
Miscellaneous income	30				109				(79		)
Interest charges	241				2,604				(2,363		)
Income before income taxes	17,835				8,293				9,542
Income tax expense	6,841				3,731				3,110
Income from discontinued operations	10,994				4,562				6,432
Gain on sale of discontinued operations, net of tax	2,716				—				2,716
Net income from discontinued operations	$	13,710			$	4,562			$	9,148
Gross natural gas marketing delivered gas sales volumes — MMcf	90,223				371,319				(281,096		)
Consolidated natural gas marketing delivered gas sales volumes — MMcf	78,646				325,537				(246,891		)
Net physical position (Bcf)	—				18.1				(18.1		)

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.

LIQUIDITY AND CAPITAL RESOURCES

The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. External debt financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program and three committed revolving credit facilities with a total availability from third-party lenders of approximately $1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditures program for fiscal year 2019 and beyond. Please refer to the TCJA Impact section above regarding anticipated impacts on our liquidity, capital resources and cash flows.

To support our capital market activities, we have a registration statement on file with the SEC that permits us to issue a total of $2.5 billion in common stock and/or debt securities. The shelf registration statement expires on March 26, 2019. Under

the shelf registration statement, in November 2017, we filed a prospectus supplement for an at-the-market (ATM) equity distribution program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million.

At September 30, 2018, approximately $650.0 million of securities remained available for issuance under the shelf registration statement. On October 4, 2018, we completed a public offering of $600 million of 4.30% senior notes due 2048. The effective rate of this note is 4.37% after giving effect to the offering costs. We received net proceeds from the offering, after underwriting discount and estimated offering expenses of approximately $591 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The issuance of these notes effectively exhausted our existing shelf registration statement.

During the first quarter of fiscal 2019, we intend to file a new registration statement for the issuance, from time to time, of up to $3.0 billion in common stock and/or debt securities In addition, during the first quarter of fiscal 2019, we plan to enter into a new ATM equity distribution agreement under which we may issue and sell shares of our common stock, up to an aggregate offering price of $500 million, under the new shelf registration statement.

The following table presents our capitalization as of September 30, 2018 and 2017:

	September 30
	2018							2017
	(In thousands, except percentages)
Short-term debt	$	575,780			6.8	%		$	447,745			6.0	%
Long-term debt	3,068,665				36.5	%		3,067,045				41.4	%
Shareholders’ equity	4,769,951				56.7	%		3,898,666				52.6	%
Total capitalization, including short-term debt	$	8,414,396			100.0	%		$	7,413,456			100.0	%

Cash Flows

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

Cash flows from operating, investing and financing activities for the years ended September 30, 2018, 2017 and 2016 are presented below.

	For the Fiscal Year Ended September 30
	2018				2017				2016				2018 vs. 2017				2017 vs. 2016
	(In thousands)
Total cash provided by (used in)
Operating activities	$	1,124,662			$	867,090			$	794,990			$	257,572			$	72,100
Investing activities	(1,463,566		)		(1,056,306		)		(1,079,732		)		(407,260		)		23,426
Financing activities	326,266				168,091				303,623				158,175				(135,532		)
Change in cash and cash equivalents	(12,638		)		(21,125		)		18,881				8,487				(40,006		)
Cash and cash equivalents at beginning of period	26,409				47,534				28,653				(21,125		)		18,881
Cash and cash equivalents at end of period	$	13,771			$	26,409			$	47,534			$	(12,638	)		$	(21,125	)

Cash flows from operating activities

Year-over-year changes in our operating cash flows primarily are attributable to changes in net income and working capital changes, particularly within our distribution segment resulting from changes in the price of natural gas and the timing of customer collections, payments for natural gas purchases and deferred gas cost recoveries.

Fiscal Year ended September 30, 2018 compared with fiscal year ended September 30, 2017

For the fiscal year ended September 30, 2018, we generated operating cash flows of $1,124.7 million compared with $867.1 million in the prior year. The year-over-year increase primarily reflects the positive cash effects of successful rate case outcomes achieved in fiscal 2017 driven primarily by increased safety and reliability spending and changes in working capital, primarily as a result of the timing of gas cost recoveries under our purchase gas cost mechanisms as a result of a year-over-year increase in sale volumes. This increase in sales volumes also contributed to the year-over-year increase in operating cash flow.

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

For the fiscal year ended September 30, 2017, we generated operating cash flows of $867.1 million compared with $795.0 million in fiscal 2016. The year-over-year increase primarily reflects the positive cash effect of successful rate case outcomes achieved in fiscal 2016.

Cash flows from investing activities

In recent years, we have used substantial amounts of cash to fund our ongoing construction program, which enables us to improve safety and reliability by modernizing our distribution and transmission system, used to provide distribution services to our existing customer base, expand our natural gas distribution services into new markets, enhance the integrity of our pipelines and, more recently, expand our intrastate pipeline network. Over the last three fiscal years, approximately 82 percent of our capital spending has been committed to improving the safety and reliability of our system.

In executing our regulatory strategy, we target our capital spending on regulatory mechanisms that permit us to earn an adequate return timely on our investment without compromising the safety or reliability of our system. Substantially all of our regulated jurisdictions have rate tariffs that provide the opportunity to include in their rate base approved capital costs on a periodic basis without being required to file a rate case.

For the fiscal year ended September 30, 2018, we had $1,467.6 million in capital expenditures compared with $1,137.1 million for the fiscal year ended September 30, 2017 and $1,087.0 million for the fiscal year ended September 30, 2016.

Fiscal Year ended September 30, 2018 compared with fiscal year ended September 30, 2017

The $330.5 million increase in capital expenditures in fiscal 2018 compared to fiscal 2017 primarily reflects planned increases to modernize our distribution and transmission system, and increases in spending in our pipeline and storage segment to improve the reliability of gas service to our local distribution company customers. The year-over-year increase also reflects the absence in the current year period of $140.3 million in net proceeds received from the sale of AEM, $29.8 million in proceeds received from the completion of a State of Texas use tax audit and the $86.1 million used to acquire a pipeline in December 2016.

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

The $50.1 million increase in capital expenditures in fiscal 2017 compared to fiscal 2016 primarily reflects a:

•	$109.7 million increase due to planned increases in our distribution segment to replace vintage pipe.

•	$59.2 million decrease in spending in our pipeline and storage segment as a result of the substantial completion of an APT project to improve the reliability of gas service to its local distribution company customers.

Cash flows from investing activities for the year ended September 30, 2017 also include proceeds of $140.3 million received from the sale of AEM, proceeds received from the completion of a State of Texas use tax audit and $86.1 million used to purchase a pipeline in the first fiscal quarter of 2017.

Cash flows from financing activities

We generated a net amount of $326.3 million, $168.1 million and $303.6 million in cash from financing activities for fiscal years 2018, 2017 and 2016. Our significant financing activities for the fiscal years ended September 30, 2018, 2017 and 2016 are summarized as follows:

2018

During the fiscal year ended September 30, 2018, our financing activities generated $326.3 million of cash compared with $168.1 million of cash generated in the prior year. The $158.2 million increase in cash provided by financing activities reflects higher net short-term borrowings due to increased capital expenditures and period-over-period changes in working capital funding needs compared to the prior year, as well as net proceeds received of $395.1 million from equity financing. Cash dividends increased due to a 7.8% increase in our dividend rate and an increase in shares outstanding.

2017

During the fiscal year ended September 30, 2017, our financing activities generated $168.1 million of cash compared with $303.6 million of cash generated in the prior year. The $135.5 million decrease in cash provided by financing activities is primarily due to the reduction in our short–term debt, partially offset by an increase in our long-term debt.

During fiscal 2017, we completed approximately $975 million of debt and equity financing. On June 8, 2017, we completed a public offering of $500 million of 3.00% senior unsecured notes due 2027 and $250 million of 4.125% senior unsecured notes due 2044. The net proceeds of approximately $753 million were used to repay our $250 million 6.35% senior unsecured notes at maturity on June 15, 2017 and for general corporate purposes, including the repayment of working capital

borrowings pursuant to our commercial paper program. In October 2016, we issued $125 million of long-term debt under our three year, $200 million multi-draw term loan agreement.

Additionally, during fiscal 2017 we issued 1.3 million shares under our ATM program and received net proceeds of $98.8 million. As of September 30, 2017, substantially all of shares under this program had been issued.

2016

During the fiscal year ended September 30, 2016, our financing activities generated $303.6 million of cash compared with $131.1 million of cash generated in fiscal 2015. The increase is primarily due to higher net short-term borrowings due to increased capital expenditures and period-over-period changes in working capital funding needs compared to the prior year, as well as proceeds received from the issuance of common stock under our ATM program in the third fiscal quarter of 2016.

The following table shows the number of shares issued for the fiscal years ended September 30, 2018, 2017 and 2016:

	For the Fiscal Year Ended September 30
	2018			2017			2016
Shares issued:
Direct Stock Purchase Plan	131,213			112,592			133,133
Retirement Savings Plan	94,081			228,326			359,414
1998 Long-Term Incentive Plan (LTIP)	385,351			529,662			598,439
November 2017 Offering	4,558,404			—			—
At-the-Market (ATM) Equity Sales Program	—			1,303,494			1,360,756
Total shares issued	5,169,049			2,174,074			2,451,742

Credit Ratings

Our credit ratings directly affect our ability to obtain short-term and long-term financing, in addition to the cost of such financing. In determining our credit ratings, the rating agencies consider a number of quantitative factors, including debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities and funding status. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the quality of our management and business strategy and the regulatory environment in the states where we operate.

Our debt is rated by two rating agencies: Standard & Poor’s Corporation (S&P) and Moody’s Investors Service (Moody’s). As of September 30, 2018, both rating agencies maintained a stable outlook.

Our current debt ratings are all considered investment grade and are as follows:

		S&P				Moody’s
Senior unsecured long-term debt		A				A2
Short-term debt		A-1				P-1

A significant degradation in our operating performance or a significant reduction in our liquidity caused by more limited access to the private and public credit markets as a result of deteriorating global or national financial and credit conditions could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by the two credit rating agencies. This would mean more limited access to the private and public credit markets and an increase in the costs of such borrowings.

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating is AAA for S&P and Aaa for Moody’s. The lowest investment grade credit rating is BBB- for S&P and Baa3 for Moody’s. Our credit ratings may be revised or withdrawn at any time by the rating agencies, and each rating should be evaluated independently of any other rating. There can be no assurance that a rating will remain in effect for any given period of time or that a rating will not be lowered, or withdrawn entirely, by a rating agency if, in its judgment, circumstances so warrant.

Debt Covenants

We were in compliance with all of our debt covenants as of September 30, 2018. Our debt covenants are described in Note 5 to the consolidated financial statements.

Contractual Obligations and Commercial Commitments

The following table provides information about contractual obligations and commercial commitments at September 30, 2018.

	Payments Due by Period
	Total				Less than 1 year				1-3 years				3-5 years				More than 5 years
									(In thousands)
Contractual Obligations
Long-term debt(1)	$	3,085,000			$	575,000			$	—			$	—			$	2,510,000
Short-term debt(1)	575,780				575,780				—				—				—
Interest charges(2)	2,257,307				134,227				222,759				222,759				1,677,562
Operating leases(3)	104,191				17,655				32,685				31,625				22,226
Financial instrument obligations(4)	56,837				56,734				103				—				—
Pension and postretirement benefit plan contributions(5)	275,907				24,882				56,310				63,525				131,190
Uncertain tax positions (6)	26,203				—				26,203				—				—
Total contractual obligations	$	6,381,225			$	1,384,278			$	338,060			$	317,909			$	4,340,978

(1)	See Note 5 to the consolidated financial statements.

(2)	Interest charges were calculated using the effective rate for each debt issuance.

(3)	See Note 10 to the consolidated financial statements.

(4)	Represents liabilities for natural gas commodity and interest rate financial instruments that were valued as of September 30, 2018. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled.

(5)	Represents expected contributions to our pension and postretirement benefit plans, which are discussed in Note 7 to the consolidated financial statements.

(6)	Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax returns. The amount does not include interest and penalties that may be applied to these positions.

We maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of individual contracts. Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. At September 30, 2018, we were committed to purchase 54.1 Bcf within one year and 37.2 Bcf within two to three years under indexed contracts.

The passage of the TCJA resulted in the remeasurement of our net deferred tax liability. At September 30, 2018, we recorded $744.9 million, which relates to our regulated operations and has been recorded as a regulatory liability. The period and timing of the return of the excess deferred taxes is being determined by regulators in each of our jurisdictions. See Note 12 for further information.

Risk Management Activities

We use financial instruments to mitigate commodity price risk and, periodically, to manage interest rate risk. In our distribution and pipeline and storage segments, we use a combination of physical storage, fixed physical contracts and fixed financial contracts to reduce our exposure to unusually large winter-period gas price increases. Additionally, we manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

We record our financial instruments as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. Substantially all of our financial instruments are valued using external market quotes and indices.

The following table shows the components of the change in fair value of our financial instruments for the fiscal year ended September 30, 2018 (in thousands):

Fair value of contracts at September 30, 2017	$	(109,159	)
Contracts realized/settled	(1,254		)
Fair value of new contracts	241
Other changes in value	54,954
Fair value of contracts at September 30, 2018	(55,218		)
Netting of cash collateral	—
Cash collateral and fair value of contracts at September 30, 2018	$	(55,218	)

The fair value of our financial instruments at September 30, 2018, is presented below by time period and fair value source:

	Fair Value of Contracts at September 30, 2018
	Maturity in years
Source of Fair Value	Less than 1				1-3				4-5				Greater than 5				Total Fair Value
	(In thousands)
Prices actively quoted	$	(55,365	)		$	147			$	—			$	—			$	(55,218	)
Prices based on models and other valuation methods	—				—				—				—				—
Total Fair Value	$	(55,365	)		$	147			$	—			$	—			$	(55,218	)

Employee Benefits Programs

An important element of our total compensation program, and a significant component of our operation and maintenance expense, is the offering of various benefits programs to our employees. These programs include medical and dental insurance coverage and pension and postretirement programs.

Medical and Dental Insurance

We offer medical and dental insurance programs to substantially all of our employees. We believe these programs are compliant with all current regulatory provisions and are consistent with other programs in our industry. In recent years, we have endeavored to actively manage our health care costs through the introduction of a wellness strategy that is focused on helping employees to identify health risks and to manage these risks through improved lifestyle choices.

Over the last five fiscal years, we have experienced annual medical and prescription inflation of approximately seven percent. For fiscal 2019, we anticipate the medical and prescription drug inflation rate will increase at approximately six percent, primarily due to the inflation of health care costs and normalization of large claim activity.

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2018, our total net periodic pension and other benefits costs was $41.4 million, compared with $49.0 million and $46.0 million for the fiscal years ended September 30, 2017 and 2016. These costs are recoverable through our rates. A portion of these costs is capitalized into our distribution rate base and the remaining costs are recorded as a component of operation and maintenance expense.

Our fiscal 2018 costs were determined using a September 30, 2017 measurement date. At that date, interest and corporate bond rates utilized to determine our discount rates were higher than the interest and corporate bond rates as of September 30, 2016, the measurement date for our fiscal 2017 net periodic cost. Therefore, we increased the discount rate used to measure our fiscal 2018 net periodic cost from 3.73 percent to 3.89 percent. We lowered the expected return on plan assets from 7.00 percent to 6.75 percent in the determination of our fiscal 2018 net periodic pension cost based upon expected market returns for our targeted asset allocation. On October 20, 2017, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States. As of September 30, 2017, we updated our assumed mortality rates to incorporate the updated mortality table. As a result of the net impact of changes in these and other assumptions, our fiscal 2018 pension and postretirement medical costs were higher than in the prior year.

Our fiscal 2017 costs were determined using a September 30, 2016 measurement date. At that date, interest and corporate bond rates utilized to determine our discount rates were lower than the interest and corporate bond rates as of September 30,

2015, the measurement date for our fiscal 2016 net periodic cost. Therefore, we decreased the discount rate used to measure our fiscal 2017 net periodic cost from 4.55 percent to 3.73 percent. We maintained the expected return on plan assets of 7.00 percent in the determination of our fiscal 2017 net periodic pension cost based upon expected market returns for our targeted asset allocation. On October 20, 2016, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States. As of September 30, 2016, we updated our assumed mortality rates to incorporate the updated mortality table. As a result of the net impact of changes in these and other assumptions, our fiscal 2017 pension and postretirement medical costs were consistent with the prior year.

Pension and Postretirement Plan Funding

Generally, our funding policy is to contribute annually an amount that will at least equal the minimum amount required to comply with the Employee Retirement Income Security Act of 1974 (ERISA). However, additional voluntary contributions are made from time to time as considered necessary. Contributions are intended to provide not only for benefits attributed to service to date but also for those expected to be earned in the future.

In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2018, 2017 and 2016. Based on these valuations, we have not had a minimum required contribution for the last three fiscal years. However, we made voluntary contributions of $7.0 million, $5.0 million and $15.0 million to our pension plans during fiscal 2018, 2017 and 2016 to achieve a desired PPA funding threshold.

We contributed $17.4 million, $13.7 million and $16.6 million to our postretirement benefits plans for the fiscal years ended September 30, 2018, 2017 and 2016. The contributions represent the portion of the postretirement costs we are responsible for under the terms of our plan and minimum funding required by state regulatory commissions.

Outlook for Fiscal 2019 and Beyond

As of September 30, 2018, interest and corporate bond rates were higher than the rates as of September 30, 2017. Therefore, we increased the discount rate used to measure our fiscal 2019 net periodic cost from 3.89 percent to 4.38 percent. The expected return on plan assets remained consistent with the prior year at 6.75 percent in the determination of our fiscal 2019 net periodic pension cost based upon expected market returns for our targeted asset allocation. On October 23, 2018, the Society of Actuaries released its annually-updated mortality improvement scale for pension plans incorporating new assumptions surrounding life expectancies in the United States. As of September 30, 2018, we updated our assumed mortality rates to incorporate the updated mortality table. As a result of the net impact of changes in these and other assumptions, we expect our fiscal 2019 net periodic pension cost to be lower than fiscal 2018.

Based upon current market conditions, the current funded position of the plans and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2019. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels. The amount of this funding is contingent upon several factors, including the issuance of new mortality tables by the US Treasury Department used to establish plan funding requirements. With respect to our postretirement medical plans, we anticipate contributing between $10 million and $20 million during fiscal 2019.

Actual changes in the fair market value of plan assets and differences between the actual and expected return on plan assets could have a material effect on the amount of pension costs ultimately recognized. A 0.25 percent change in our discount rate would impact our pension and postretirement costs by approximately $2.5 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $1.4 million.

The projected liability, future funding requirements and the amount of expense or income recognized for each of our pension and other post-retirement benefit plans are subject to change, depending on the actuarial value of plan assets, and the determination of future benefit obligations as of each subsequent calculation date. These amounts are impacted by actual investment returns, changes in interest rates, changes in the demographic composition of the participants in the plans and other actuarial assumptions.

RECENT ACCOUNTING DEVELOPMENTS

Recent accounting developments and their impact on our financial position, results of operations and cash flows are described in Note 2 to the consolidated financial statements.