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.

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 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.

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

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.

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

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.

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.

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			12.3	%
Long-term debt	3,067,045				41.4	%		2,438,779				36.2	%
Shareholders’ equity	3,898,666				52.6	%		3,463,059				51.5	%
Total capitalization, including short-term debt	$	7,413,456			100.0	%		$	6,731,649			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, 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)
Total cash provided by (used in)
Operating activities	$	867,090			$	794,990			$	811,914			$	72,100			$	(16,924	)
Investing activities	(1,056,306		)		(1,079,732		)		(956,602		)		23,426				(123,130		)
Financing activities	168,091				303,623				131,083				(135,532		)		172,540
Change in cash and cash equivalents	(21,125		)		18,881				(13,605		)		(40,006		)		32,486
Cash and cash equivalents at beginning of period	47,534				28,653				42,258				18,881				(13,605		)
Cash and cash equivalents at end of period	$	26,409			$	47,534			$	28,653			$	(21,125	)		$	18,881

Cash flows from operating activities

Year-over-year changes in our operating cash flows primarily are attributable to changes in net income, 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, 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 the prior year. The year-over-year increase primarily reflects the positive cash effect of successful rate case outcomes achieved in fiscal 2016.

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

For the fiscal year ended September 30, 2016, we generated operating cash flows of $795.0 million compared with $811.9 million in fiscal 2015. The year-over-year decrease primarily reflects the timing of deferred gas cost recoveries.

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 enhance the safety and reliability of the 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 80 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, 2017, we had $1,137.1 million in capital expenditures compared with $1,087.0 million for the fiscal year ended September 30, 2016 and $963.6 million for the fiscal year ended September 30, 2015.

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:

•	$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 Enlink Pipeline in the first fiscal quarter of 2017.

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

The $123.4 million increase in capital expenditures in fiscal 2016 compared to fiscal 2015 primarily reflects:

•	A $69.6 million increase in capital spending in our distribution segment, which reflects the repair and replacement of our transmission and distribution pipelines as part of a planned increase in safety and reliability investment in fiscal 2016, the installation and replacement of measurement and regulating equipment and other pipeline integrity projects.

•	A $53.6 million increase in capital spending in our pipeline and storage segment, primarily related to the enhancement and fortification of two storage fields to ensure the reliability of gas service to our Mid-Tex Division.

Cash flows from financing activities

We generated a net amount of $168.1 million, $303.6 million and $131.1 million in cash from financing activities for fiscal years 2017, 2016 and 2015. Our significant financing activities for the fiscal years ended September 30, 2017, 2016 and 2015 are summarized as follows:

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.

2015

During the fiscal year ended September 30, 2015, our financing activities generated $131.1 million of cash compared with $68.2 million of cash generated in fiscal 2014. The increase is primarily due to timing between short-term debt borrowings and repayments during fiscal 2015, proceeds from the issuance of $500 million unsecured 4.125% senior notes in October 2014 and the settlement of the associated forward starting interest rate swaps. Partially offsetting these increases were the repayment of $500 million 4.95% senior unsecured notes at maturity on October 15, 2014, compared with short-term debt borrowings and repayments in fiscal 2014 and proceeds generated from the equity offering completed in February 2014.

The following table shows the number of shares issued for the fiscal years ended September 30, 2017, 2016 and 2015:

	For the Fiscal Year Ended September 30
	2017			2016			2015
Shares issued:
Direct Stock Purchase Plan	112,592			133,133			176,391
Retirement Savings Plan	228,326			359,414			398,047
1998 Long-Term Incentive Plan (LTIP)	529,662			598,439			664,752
At-the-Market (ATM) Equity Sales Program	1,303,494			1,360,756			—
Total shares issued	2,174,074			2,451,742			1,239,190

The decrease in the number of shares issued in fiscal 2017 compared with the number of shares issued in fiscal 2016 primarily reflects fewer shares issued under the Retirement Savings Plan and the LTIP. At September 30, 2017, of the 11.2 million aggregate shares authorized for issuance from the LTIP, 2,035,861 shares remained available.

The increase in the number of shares issued in fiscal 2016 compared with the number of shares issued in fiscal 2015 primarily reflects shares issued under the ATM program.

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, the risks associated with our regulated and nonregulated businesses 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, 2017, 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, 2017. 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, 2017.

	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)	447,745				447,745				—				—				—
Interest charges(2)	2,408,200				152,676				243,823				222,759				1,788,942
Operating leases(3)	114,937				17,170				31,875				30,376				35,516
Financial instrument obligations(4)	112,398				322				112,076				—				—
Pension and postretirement benefit plan contributions(5)	312,295				33,798				52,499				50,223				175,775
Uncertain tax positions (6)	23,719				—				23,719				—				—
Total contractual obligations	$	6,504,294			$	651,711			$	1,038,992			$	303,358			$	4,510,233

(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, 2017. 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.

Our distribution and pipeline and storage segments 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, 2017, we were committed to purchase 20.9 Bcf within one year, 37.9 Bcf within two to three years and 0.3 Bcf after three years under indexed contracts.

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. Through December 31, 2016, we managed our exposure to the risk of natural gas price changes in our natural gas marketing segment by locking in our gross profit margin through a combination of storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Risk management assets and liabilities associated with our former natural gas marketing operations have been classified as held for sale at September 30, 2016. The change in fair value of these risk management assets and liabilities are included below.

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, 2017 (in thousands):

Fair value of contracts at September 30, 2016	$	(279,543	)
Contracts realized/settled	49,187
Fair value of new contracts	(288		)
Other changes in value	121,485
Fair value of contracts at September 30, 2017	(109,159		)
Netting of cash collateral	—
Cash collateral and fair value of contracts at September 30, 2017	$	(109,159	)

The fair value of our financial instruments at September 30, 2017, is presented below by time period and fair value source:

	Fair Value of Contracts at September 30, 2017
	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	$	2,114			$	(111,273	)		$	—			$	—			$	(109,159	)
Prices based on models and other valuation methods	—				—				—				—				—
Total Fair Value	$	2,114			$	(111,273	)		$	—			$	—			$	(109,159	)

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 six percent. For fiscal 2018, we anticipate the medical and prescription drug inflation rate will continue at approximately six percent, primarily due to the inflation of health care costs.

Net Periodic Pension and Postretirement Benefit Costs

For the fiscal year ended September 30, 2017, our total net periodic pension and other benefits costs was $49.0 million, compared with $46.0 million and $58.9 million for the fiscal years ended September 30, 2016 and 2015. 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 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.

Our fiscal 2016 costs were determined using a September 30, 2015 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, 2014, the measurement date for our fiscal 2015 net periodic cost. Therefore, we increased the discount rate used to measure our fiscal 2016 net periodic cost from 4.43 percent to 4.55 percent. We lowered expected return on plan assets from 7.25 percent to 7.00 percent in the determination of our fiscal 2016 net periodic pension cost based upon expected market returns for our targeted asset allocation. As a result of the net impact of these and other assumptions, our fiscal 2016 pension and postretirement medical costs were lower than in 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, 2017. Based on this valuation, we contributed cash of $5.0 million, $15.0 million and $38.0 million to our pension plans during fiscal 2017, 2016 and 2015. Each contribution increased the level of our plan assets to achieve a desired PPA funding threshold.

We contributed $13.7 million, $16.6 million and $20.0 million to our postretirement benefits plans for the fiscal years ended September 30, 2017, 2016 and 2015. 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 2018 and Beyond

As of September 30, 2017, interest and corporate bond rates were higher than the rates as of September 30, 2016. 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 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, we expect our fiscal 2018 net periodic pension cost to be approximately 25 percent lower than fiscal 2017.

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 2018. 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 2018.

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 $3.0 million. A 0.25 percent change in our expected rate of return would impact our pension and postretirement costs by approximately $1.3 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.