Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

The following discussion should be read in conjunction with the condensed consolidated financial statements in this Quarterly Report on Form 10-Q and Management’s Discussion and Analysis in our Annual Report on Form 10-K for the year ended September 30, 2021.

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

The statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: federal, state and local regulatory and political 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 impact of greenhouse gas emissions or other legislation or regulations intended to address climate change; possible significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs; the inherent hazards and risks involved in distributing, transporting and storing 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; the impact of climate change; the inability to continue to hire, train and retain operational, technical and managerial personnel; increased dependence on technology that may hinder the Company's business if such technologies fail; 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; 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; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; and the outbreak of COVID-19 and its impact on business and economic conditions. Accordingly, while we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements whether as a result of new information, future events or otherwise.

OVERVIEW

Atmos Energy and our subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. We distribute natural gas through sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers throughout our six distribution divisions, which at December 31, 2021 covered service areas located in eight states. In addition, we transport natural gas for others through our distribution and pipeline systems.

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

• The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states.

• The pipeline and storage segment is comprised primarily of the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates, including those related to the allowance for doubtful accounts, legal and environmental accruals, insurance accruals, pension and postretirement obligations, deferred income taxes and the valuation of goodwill and other long-lived assets. Actual results may differ from such estimates.

Our critical accounting policies used in the preparation of our consolidated financial statements are described in our Annual Report on Form 10-K for the fiscal year ended September 30, 2021 and include the following:

• Regulation

• Unbilled revenue

• Pension and other postretirement plans

• Impairment assessments

Our critical accounting policies are reviewed periodically by the Audit Committee of our Board of Directors. There were no significant changes to these critical accounting policies during the three months ended December 31, 2021.

RESULTS OF OPERATIONS

Executive Summary

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

During the three months ended December 31, 2021, we recorded net income of $249.2 million, or $1.86 per diluted share, compared to net income of $217.7 million, or $1.71 per diluted share for the three months ended December 31, 2020.

The 14.5 percent year-over-year increase in net income largely reflects positive rate outcomes driven by safety and reliability spending and customer growth in our distribution segment, offset by higher spending on certain operating and maintenance expenses in both our segments due to the timing of certain activities.

During the three months ended December 31, 2021, we implemented ratemaking regulatory actions which resulted in an increase in annual operating income of $24.9 million. Excluding the impact of the refund of excess deferred income taxes resulting from previously enacted tax reform legislation, our total rate outcomes were $68.5 million for the three months ended December 31, 2021. Additionally, as of December 31, 2021, we had ratemaking efforts in progress seeking a total increase in annual operating income of $22.0 million.

Capital expenditures for the three months ended December 31, 2021 were $684.2 million. Over 85 percent was invested to improve the safety and reliability of our distribution and transportation systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce lag to six months or less.

During the three months ended December 31, 2021, we completed approximately $862 million of long-term debt and equity financing. As of December 31, 2021, our equity capitalization was 51.0 percent. Excluding the $2.2 billion of incremental financing issued in conjunction with Winter Storm Uri, our equity capitalization was 59.0 percent. As of December 31, 2021, we had approximately $3.1 billion in total liquidity, including cash and cash equivalents and funds available through equity forward sales agreements.

As a result of our sustained financial performance, our Board of Directors increased the quarterly dividend by 8.8 percent for fiscal 2022.

The following discusses the results of operations for each of our operating segments.

Distribution Segment

The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of this segment are our ability to earn our authorized rates of return, competitive factors in the energy industry and economic conditions in our service areas.

Our ability to earn our authorized rates of return is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. Under our current rate design, approximately 70 percent of our distribution segment revenues are earned through the first six months of the fiscal year. Additionally, we currently recover approximately 60 percent of our distribution segment revenue, excluding gas costs, through the base customer charge, which partially separates the recovery of our approved rate from customer usage patterns.

Seasonal weather patterns can also affect our distribution operations. However, the effect of weather that is above or below normal is substantially offset through weather normalization adjustments, known as WNA, which have been approved by state regulatory commissions for approximately 96 percent of our residential and commercial revenues in the following states for the following time periods:

Kansas, West Texas			October — May
Tennessee			October — April
Kentucky, Mississippi, Mid-Tex			November — April
Louisiana			December — March
Virginia			January — December

Our distribution operations are also affected by the cost of natural gas. We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Revenues in our Texas and Mississippi service areas include franchise fees and gross receipts taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenues is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income.

The cost of gas typically does not have a direct impact on our operating income because these costs are recovered through our purchased gas cost adjustment mechanisms. However, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense. This risk is currently mitigated by rate design that allows us to collect from our customers the gas cost portion of our bad debt expense on approximately 79 percent of our residential and commercial revenues. Additionally, higher gas costs may require us to increase borrowings under our credit facilities, resulting in higher interest expense. Finally, 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.

Three Months Ended December 31, 2021 compared with Three Months Ended December 31, 2020

Financial and operational highlights for our distribution segment for the three months ended December 31, 2021 and 2020 are presented below.

			Three Months Ended December 31
			2021						2020						Change
			(In thousands, unless otherwise noted)
Operating revenues			$	972,422					$	876,650					$	95,772
Purchased gas cost			496,799						411,072						85,727
Operating expenses			285,126						256,024						29,102
Operating income			190,497						209,554						(19,057)
Other non-operating income			1,916						835						1,081
Interest charges			8,548						10,712						(2,164)
Income before income taxes			183,865						199,677						(15,812)
Income tax expense			4,294						45,985						(41,691)
Net income			$	179,571					$	153,692					$	25,879
Consolidated distribution sales volumes — MMcf			69,545						88,861						(19,316)
Consolidated distribution transportation volumes — MMcf			38,597						39,609						(1,012)
Total consolidated distribution throughput — MMcf			108,142						128,470						(20,328)
Consolidated distribution average cost of gas per Mcf sold			$	7.14					$	4.63					$	2.51

Operating income for our distribution segment decreased nine percent. During the three months ended December 31, 2021 we refunded $28.8 million more excess deferred taxes to customers in the distribution segment compared to the prior year, which reduced operating income year over year and reduced the interim effective income tax rate for this segment to 2.3% compared to 23.0% in the prior year. Additional key drivers for the change in operating income include:

• a $32.2 million increase in rate adjustments, primarily in our Mid-Tex, Louisiana and Kentucky/Mid-States Divisions.

• a $4.3 million increase in customers, primarily in our Mid-Tex Division.

Partially offset by:

• a $10.1 million increase in depreciation expense and property taxes associated with increased capital investments.

• a $3.2 million increase in pipeline maintenance and related activities.

• an $11.3 million increase in other operation and maintenance expense, primarily due to employee related costs, insurance premiums and other administrative costs.

The following table shows our operating income by distribution division, in order of total rate base, for the three months ended December 31, 2021 and 2020. The presentation of our distribution operating income is included for financial reporting purposes and may not be appropriate for ratemaking purposes.

			Three Months Ended December 31
			2021						2020						Change
			(In thousands)
Mid-Tex			$	106,358					$	102,320					$	4,038
Kentucky/Mid-States			25,538						24,106						1,432
Louisiana			21,154						23,119						(1,965)
West Texas			20,874						20,047						827
Mississippi			24,700						24,634						66
Colorado-Kansas			2,815						13,230						(10,415)
Other			(10,942)						2,098						(13,040)
Total			$	190,497					$	209,554					$	(19,057)

Recent Ratemaking Developments

The amounts described in the following sections represent the operating income that was requested or received in each rate filing, which may not necessarily reflect the stated amount referenced in the final order, as certain operating costs may have changed as a result of a commission’s or other governmental authority’s final ruling. During the first three months of fiscal 2022, we implemented regulatory proceedings, resulting in a $24.9 million increase in annual operating income as summarized below. Ratemaking outcomes include the refund of excess deferred income taxes resulting from previously enacted tax reform legislation and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit. Excluding these amounts, our total rate outcomes for ratemaking activities for the three months ended December 31, 2021 were $68.5 million.

Rate Action						Annual Increase in Operating Income
						(In thousands)
Annual formula rate mechanisms						$	24,881
Rate case filings						—
Other rate activity						—
						$	24,881

The following ratemaking efforts seeking $22.0 million in increased annual operating income were in progress as of December 31, 2021:

Division						Rate Action						Jurisdiction						Operating Income (Loss) Requested
																		(In thousands)
Colorado-Kansas						Infrastructure Mechanism						Colorado (1)						$	2,610
Colorado-Kansas						Infrastructure Mechanism						Kansas (2)						1,829
Colorado-Kansas						Ad Valorem						Kansas (3)						(370)
Kentucky/Mid-States						Rate Case						Kentucky (4)						14,394
Kentucky/Mid-States						Infrastructure Mechanism						Kentucky						3,506
																		$	21,969

(1) The Colorado Public Utilities Commission approved the SSIR implementation at their December 22, 2021 meeting with rates effective January 1, 2022.

(2) The Kansas Corporation Commission approved the GSRS filing on January 27, 2022, with rates effective February 1, 2022..

(3) The Kansas Corporation Commission approved the Ad Valorem filing on January 13, 2022, with rates effective February 1, 2022.

(4) Included with the Kentucky rate case filing is the $3.5 million filing related to the annual Kentucky pipeline replacement program.

Annual Formula Rate Mechanisms

As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. We currently have formula rate mechanisms in our Louisiana, Mississippi and Tennessee operations and in substantially all the service areas in our Texas divisions. Additionally, we have specific infrastructure programs in substantially all of our distribution divisions with tariffs in place to permit the investment associated with these programs to have their surcharge rate adjusted annually to recover approved capital costs incurred in a prior test-year period. The following table summarizes our annual formula rate mechanisms by state:

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

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

The following annual formula rate mechanisms were approved during the three months ended December 31, 2021:

Division						Jurisdiction						Test Year Ended						Increase (Decrease) in Annual Operating Income						Effective Date
												(In thousands)
2022 Filings:
Mid-Tex						Mid-Tex Cities RRM (1)						12/31/2020						$	21,673					12/01/2021
West Texas						West Texas Cities RRM (1)						12/31/2020						151						12/01/2021
Mississippi						Mississippi - SIR (1)						10/31/2022						8,354						11/01/2021
Mississippi						Mississippi - SRF (1)						10/31/2022						(5,624)						11/01/2021
Kentucky/Mid-States						Virginia - SAVE						09/30/2022						327						10/01/2021
Total 2022 Filings																		$	24,881

(1) The rate change for the RRM and Mississippi filings include $33.8 million for the Mid-Tex Cities RRM filing, $3.3 million for the West Texas Cities RRM filing, $2.1 million for the Mississippi SIR filing and $4.3 million for the Mississippi SRF filing related to the refund of excess deferred income taxes that will be offset by lower income tax expense. Excluding the amounts related to the refund of excess deferred taxes, our total rate outcomes for our formulate rate mechanisms for the three months ended December 31, 2021 were $68.5 million.

Rate Case Filings

A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to our customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a fair rate of return and ensure that we continue to deliver reliable, reasonably priced natural gas service safely to our customers. There was no rate case activity completed during the three months ended December 31, 2021.

Other Ratemaking Activity

The Company had no other ratemaking activity during the three months ended December 31, 2021.

Pipeline and Storage Segment

Our pipeline and storage segment consists of the pipeline and storage operations of our Atmos Pipeline–Texas Division (APT) and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Permian Basin 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. Over 80 percent of this segment’s revenues are derived from these services. As part of its pipeline operations, APT owns and operates five underground storage facilities in Texas.

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

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

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

Three Months Ended December 31, 2021 compared with Three Months Ended December 31, 2020

Financial and operational highlights for our pipeline and storage segment for the three months ended December 31, 2021 and 2020 are presented below.

			Three Months Ended December 31
			2021						2020						Change
			(In thousands, unless otherwise noted)
Mid-Tex / Affiliate transportation revenue			$	127,323					$	125,261					$	2,062
Third-party transportation revenue			30,625						30,821						(196)
Other revenue			4,970						3,631						1,339
Total operating revenues			162,918						159,713						3,205
Total purchased gas cost			(3,411)						(1,244)						(2,167)
Operating expenses			80,965						71,671						9,294
Operating income			85,364						89,286						(3,922)
Other non-operating income			6,786						5,237						1,549
Interest charges			11,303						11,298						5
Income before income taxes			80,847						83,225						(2,378)
Income tax expense			11,209						19,239						(8,030)
Net income			$	69,638					$	63,986					$	5,652
Gross pipeline transportation volumes — MMcf			181,468						204,865						(23,397)
Consolidated pipeline transportation volumes — MMcf			136,067						144,587						(8,520)

Operating income for our pipeline and storage segment decreased four percent. During the three months ended December 31, 2021, we refunded $10.0 million in excess deferred taxes to pipeline and storage customers, which reduced operating income year over year and reduced the interim effective income tax rate for this segment to 13.9% compared to 23.1% in the prior year. Additional drivers for the change in operating income include:

• a $14.5 million increase due to rate adjustments from the GRIP filing approved in May 2021. The increase in rates was driven by increased safety and reliability spending.

Partially offset by:

• a $5.8 million increase in system maintenance expense primarily due to spending on hydro testing.

• a $2.5 million net decrease in APT's thru-system activities primarily associated with the tightening of regional spreads driven by increased competing takeaway capacity in the Permian Basin.

• a $3.1 million increase in depreciation expense and property taxes associated with increased capital investments.

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. Additionally, we have a $1.5 billion commercial paper program and four committed revolving credit facilities with $2.5 billion in total availability from third-party lenders. 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.

We have a shelf registration statement on file with the Securities and Exchange Commission (SEC) that allows us to issue up to $5.0 billion in common stock and/or debt securities. As of the date of this report, $3.2 billion of securities were available for issuance under the shelf registration statement, which expires June 29, 2024.

We also have an at-the-market (ATM) equity sales program that allows us to issue and sell shares of our common stock up to an aggregate offering price of $1.0 billion (including shares of common stock that may be sold pursuant to forward sale agreements entered into in connection with the ATM equity sales program), which expires June 29, 2024. As of December 31, 2021, $499.7 million of equity was available for issuance under this ATM equity sales program. Additionally, as of

December 31, 2021, we had $294.7 million in proceeds from executed forward sale agreements available through June 30, 2023. Additional details are summarized in Note 7 to the unaudited condensed consolidated financial statements.

The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditure program for the remainder of fiscal year 2022. Additionally, we expect to continue to be able to obtain financing upon reasonable terms as necessary.

The following table presents our capitalization inclusive of short-term debt and the current portion of long-term debt as of December 31, 2021, September 30, 2021 and December 31, 2020:

			December 31, 2021												September 30, 2021												December 31, 2020
			(In thousands, except percentages)
Short-term debt			$	—					—		%				$	—					—		%				$	—					—		%
Long-term debt(1)			7,956,554						49.0		%				7,330,657						48.1		%				5,125,033						41.5		%
Shareholders’ equity(2)			8,289,545						51.0		%				7,906,889						51.9		%				7,213,156						58.5		%
Total			$	16,246,099					100.0		%				$	15,237,546					100.0		%				$	12,338,189					100.0		%

(1) Inclusive of our finance leases.

(2) Excluding the $2.2 billion of incremental financing issued to pay for the purchased gas costs incurred during Winter Storm Uri, our equity capitalization ratio was 59.0% at December 31, 2021 and 60.6% at September 30, 2021 .

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, 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 three months ended December 31, 2021 and 2020 are presented below.

			Three Months Ended December 31
			2021						2020						Change
			(In thousands)
Total cash provided by (used in)
Operating activities			$	61,824					$	157,069					$	(95,245)
Investing activities			(679,748)						(453,592)						(226,156)
Financing activities			765,206						733,314						31,892
Change in cash and cash equivalents			147,282						436,791						(289,509)
Cash and cash equivalents at beginning of period			116,723						20,808						95,915
Cash and cash equivalents at end of period			$	264,005					$	457,599					$	(193,594)

Cash flows from operating activities

For the three months ended December 31, 2021, we generated cash flow from operating activities of $61.8 million compared with $157.1 million for the three months ended December 31, 2020. The $95.2 million decrease in operating cash flows reflects working capital changes, primarily due to the timing of gas cost recoveries under our purchase gas cost mechanisms partially offset by the positive effects of successful rate case outcomes achieved in fiscal 2021.

Cash flows from investing activities

Our capital expenditures are primarily used to improve the safety and reliability of our distribution and transmission system through pipeline replacement and system modernization and to enhance and expand our system to meet customer needs. Over the last three fiscal years, approximately 88 percent of our capital spending has been committed to improving the safety and reliability of our system.

For the three months ended December 31, 2021, cash used for investing activities was $679.7 million compared to $453.6 million for the three months ended December 31, 2020. Capital spending increased $227.4 million, primarily as a result of timing of spending in our distribution and pipeline and storage segments.

Cash flows from financing activities

For the three months ended December 31, 2021, our financing activities provided $765.2 million of cash compared with $733.3 million of cash provided by financing activities in the prior-year period.

In the three months ended December 31, 2021, we received $851.7 million in net proceeds from the issuance of long-term debt and equity. We completed a public offering of $600 million of 2.85% senior notes due 2052 and received net proceeds from the offering, after the underwriting discount and offering expenses, of $589.8 million. Additionally, during the three months ended December 31, 2021, we settled 2,689,327 shares that had been sold on a forward basis for net proceeds of $261.9 million. The net proceeds were used primarily to support capital spending and for other general corporate purposes.

Cash dividends increased due to an 8.8 percent increase in our dividend rate and an increase in shares outstanding.

In the three months ended December 31, 2020, we received $808.3 million in net proceeds from the issuance of long-term debt and equity. The net proceeds were used primarily to support capital spending and for other general corporate purposes. Cash dividends increased due to an 8.7 percent increase in our dividend rate and an increase in shares outstanding.

The following table summarizes our share issuances for the three months ended December 31, 2021 and 2020:

			Three Months Ended December 31
			2021						2020
Shares issued:
Direct Stock Purchase Plan			20,983						19,918
1998 Long-Term Incentive Plan			275,212						144,366
Retirement Savings Plan and Trust			19,805						20,708
Equity Issuance			2,689,327						2,085,492
Total shares issued			3,005,327						2,270,484

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 but not limited to, debt to total capitalization, operating cash flow relative to outstanding debt, operating cash flow coverage of interest and pension liabilities. 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 businesses and the regulatory structures that govern our rates 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 December 31, 2021, our outlook and current debt ratings, which are all considered investment grade are as follows:

			S&P									Moody’s
Senior unsecured long-term debt			A-									A1
Short-term debt			A-2									P-1
Outlook			Negative									Negative

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 December 31, 2021. Our debt covenants are described in greater detail in Note 6 to the unaudited condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

Except as noted in Note 10 to the unaudited condensed consolidated financial statements, there were no significant changes in our contractual obligations and commercial commitments during the three months ended December 31, 2021.

Risk Management Activities

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 periodically entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.

The following table shows the components of the change in fair value of our financial instruments for the three months ended December 31, 2021 and 2020:

			Three Months Ended December 31
			2021						2020
			(In thousands)
Fair value of contracts at beginning of period			$	225,417					$	78,663
Contracts realized/settled			22,601						1,332
Fair value of new contracts			1,184						87
Other changes in value			(129,284)						68,473
Fair value of contracts at end of period			119,918						148,555
Netting of cash collateral			—						—
Cash collateral and fair value of contracts at period end			$	119,918					$	148,555

The fair value of our financial instruments at December 31, 2021 is presented below by time period and fair value source:

			Fair Value of Contracts at December 31, 2021
			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			$	67,198					$	60,088					$	(7,368)					$	—					$	119,918
Prices based on models and other valuation methods			—						—						—						—						—
Total Fair Value			$	67,198					$	60,088					$	(7,368)					$	—					$	119,918

OPERATING STATISTICS AND OTHER INFORMATION

The following tables present certain operating statistics for our distribution and pipeline and storage segments for the three months ended December 31, 2021 and 2020.

Distribution Sales and Statistical Data

			Three Months Ended December 31
			2021						2020
METERS IN SERVICE, end of period
Residential			3,120,873						3,077,786
Commercial			282,155						281,840
Industrial			1,653						1,673
Public authority and other			8,248						8,323
Total meters			3,412,929						3,369,622
INVENTORY STORAGE BALANCE — Bcf			70.5						58.1
SALES VOLUMES — MMcf (1)
Gas sales volumes
Residential			37,834						53,530
Commercial			23,008						26,687
Industrial			7,073						6,651
Public authority and other			1,630						1,993
Total gas sales volumes			69,545						88,861
Transportation volumes			40,315						41,285
Total throughput			109,860						130,146

Pipeline and Storage Operations Sales and Statistical Data

			Three Months Ended December 31
			2021						2020
CUSTOMERS, end of period
Industrial			95						92
Other			202						217
Total			297						309
INVENTORY STORAGE BALANCE — Bcf			1.4						1.3
PIPELINE TRANSPORTATION VOLUMES — MMcf (1)			181,468						204,865

Note to preceding tables:

(1)Sales and transportation volumes reflect segment operations, including intercompany sales and transportation amounts.

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 unaudited condensed consolidated financial statements.