ATMOS ENERGY CORP - Annual Report: 2019 (Form 10-K)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
☑ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2019
OR
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
Texas and Virginia 75-1743247
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)
1800 Three Lincoln Centre
5430 LBJ Freeway
Dallas, Texas 75240
(Address of principal executive offices) (Zip code)
Registrant’s telephone number, including area code:
(972) 934-9227
Securities registered pursuant to Section 12(b) of the Act:
Table of each class | Trading Symbol | Name of each exchange on which registered | |
Common stock | No Par Value | ATO | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | ☑ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No þ
The aggregate market value of the common voting stock held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter, March 31, 2019, was $11,826,627,172.
As of November 7, 2019, the registrant had 119,343,545 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Definitive Proxy Statement to be filed for the Annual Meeting of Shareholders on February 5, 2020 are incorporated by reference into Part III of this report.
TABLE OF CONTENTS
Page | ||
Part I | ||
Item 1. | ||
Item 1A. | ||
Item 1B. | ||
Item 2. | ||
Item 3. | ||
Item 4. | Mine Safety Disclosures | |
Part II | ||
Item 5. | ||
Item 6. | ||
Item 7. | ||
Item 7A. | ||
Item 8. | ||
Item 9. | ||
Item 9A. | ||
Item 9B. | ||
Part III | ||
Item 10. | ||
Item 11. | ||
Item 12. | ||
Item 13. | ||
Item 14. | ||
Part IV | ||
Item 15. | ||
Item 16. | ||
GLOSSARY OF KEY TERMS
Adjusted diluted net income per share | Non-GAAP measure defined as diluted net income per share before the one-time, non-cash income tax benefit |
Adjusted net income | Non-GAAP measure defined as net income before the one-time, non-cash income tax benefit |
AEC | Atmos Energy Corporation |
AEH | Atmos Energy Holdings, Inc. |
AEM | Atmos Energy Marketing, LLC |
AFUDC | Allowance for funds used during construction |
AOCI | Accumulated Other Comprehensive Income |
ARM | Annual Rate Mechanism |
ATO | Trading symbol for Atmos Energy Corporation common stock on the NYSE |
Bcf | Billion cubic feet |
Contribution Margin | Non-GAAP measure defined as operating revenues less purchased gas cost |
COSO | Committee of Sponsoring Organizations of the Treadway Commission |
DARR | Dallas Annual Rate Review |
ERISA | Employee Retirement Income Security Act of 1974 |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
GAAP | Generally Accepted Accounting Principles |
GRIP | Gas Reliability Infrastructure Program |
GSRS | Gas System Reliability Surcharge |
LTIP | 1998 Long-Term Incentive Plan |
Mcf | Thousand cubic feet |
MDWQ | Maximum daily withdrawal quantity |
Mid-Tex ATM Cities | Represents a coalition of 47 incorporated cities or approximately 8 percent of the Mid-Tex Division's customers. |
Mid-Tex Cities | Represents all incorporated cities other than Dallas and Mid-Tex ATM Cities, or approximately 72 percent of the Mid-Tex Division’s customers. |
MMcf | Million cubic feet |
Moody’s | Moody’s Investor Service, Inc. |
NGA | Natural Gas Act of 1938 |
NYMEX | New York Mercantile Exchange, Inc. |
NYSE | New York Stock Exchange |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
PPA | Pension Protection Act of 2006 |
PRP | Pipeline Replacement Program |
RRC | Railroad Commission of Texas |
RRM | Rate Review Mechanism |
RSC | Rate Stabilization Clause |
S&P | Standard & Poor’s Corporation |
SAVE | Steps to Advance Virginia Energy |
SEC | United States Securities and Exchange Commission |
SGR | Supplemental Growth Rider |
SIR | System Integrity Rider |
SRF | Stable Rate Filing |
SSIR | System Safety and Integrity Rider |
TCJA | Tax Cuts and Jobs Act of 2017 |
WNA | Weather Normalization Adjustment |
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PART I
The terms “we,” “our,” “us”, “Atmos Energy” and the “Company” refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise.
ITEM 1. | Business. |
Overview and Strategy
Atmos Energy Corporation, headquartered in Dallas, Texas, and incorporated in Texas and Virginia, is one of the country’s largest natural-gas-only distributors based on number of customers. We deliver safe, clean, reliable, efficient, affordable and abundant natural gas through regulated sales and transportation arrangements to over three million residential, commercial, public authority and industrial customers in eight states located primarily in the South. We also operate one of the largest intrastate pipelines in Texas based on miles of pipe.
Atmos Energy's vision is to be the safest provider of natural gas services. We intend to achieve this vision by:
• | operating our business exceptionally well |
• | investing in our people and infrastructure |
• | enhancing our culture. |
Since 2011, our operating strategy has focused on modernizing our distribution and transmission system to improve safety and reliability. Since that time, our capital expenditures have increased approximately 14% annually. Additionally, during this period, we have added new or modified existing regulatory mechanisms to reduce regulatory lag. Our ability to increase capital spending annually to modernize our system has increased our rate base, which has resulted in rising earnings per share and shareholder value.
Our core values include focusing on our employees and customers while conducting our business with honesty and integrity. We continue to strengthen our culture through ongoing communications with our employees and enhanced employee training.
Operating Segments
As of September 30, 2019, we manage and review our consolidated operations through the following reportable segments, which are discussed in further detail below.
• | 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. |
Prior to disposition, the natural gas marketing segment, which was comprised of our natural gas marketing business, was also a reportable segment.
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Distribution Segment Overview
The following table summarizes key information about our six regulated natural gas distribution divisions, presented in order of total rate base.
Division | Service Areas | Communities Served | Customer Meters | |||
Mid-Tex | Texas, including the Dallas/Fort Worth Metroplex | 550 | 1,722,424 | |||
Kentucky/Mid-States | Kentucky | 230 | 183,450 | |||
Tennessee | 154,004 | |||||
Virginia | 24,536 | |||||
Louisiana | Louisiana | 270 | 365,320 | |||
West Texas | Amarillo, Lubbock, Midland | 80 | 316,844 | |||
Mississippi | Mississippi | 110 | 266,727 | |||
Colorado-Kansas | Colorado | 170 | 121,883 | |||
Kansas | 136,647 | |||||
We operate in our service areas under terms of non-exclusive franchise agreements granted by the various cities and towns that we serve. At September 30, 2019, we held 1,017 franchises having terms generally ranging from five to 35 years. A significant number of our franchises expire each year, which require renewal prior to the end of their terms. Historically, we have successfully renewed these franchises and believe that we will continue to be able to renew our franchises as they expire.
Revenues in this operating segment are established by regulatory authorities in the states in which we operate. These rates are intended to be sufficient to cover the costs of conducting business, including a reasonable return on invested capital. In addition, we transport natural gas for others through our distribution systems.
Rates established by regulatory authorities often include cost adjustment mechanisms for costs that (i) are subject to significant price fluctuations compared to our other costs, (ii) represent a large component of our cost of service and (iii) are generally outside our control.
Purchased gas cost adjustment mechanisms represent a common form of cost adjustment mechanism. Purchased gas cost adjustment mechanisms provide a method of recovering purchased gas costs on an ongoing basis without filing a rate case because they provide a dollar-for-dollar offset to increases or decreases in the cost of natural gas. Therefore, although substantially all of our distribution operating revenues fluctuate with the cost of gas that we purchase, distribution Contribution Margin is generally not affected by fluctuations in the cost of gas.
Additionally, some jurisdictions have performance-based ratemaking adjustments to provide incentives to minimize purchased gas costs through improved storage management and use of financial instruments to reduce volatility in gas costs. Under the performance-based ratemaking adjustments, purchased gas costs savings are shared between the Company and its customers.
Our supply of natural gas is provided by a variety of suppliers, including independent producers, marketers and pipeline companies, withdrawals of gas from proprietary and contracted storage assets and peaking and spot purchase agreements, as needed.
Supply arrangements consist of both base load and swing supply (peaking) quantities and are contracted from our suppliers on a firm basis with various terms at market prices. Base load quantities are those that flow at a constant level throughout the month and swing supply quantities provide the flexibility to change daily quantities to match increases or decreases in requirements related to weather conditions.
Except for local production purchases, we select our natural gas suppliers through a competitive bidding process by periodically requesting proposals from suppliers that have demonstrated that they can provide reliable service. We select these suppliers based on their ability to deliver gas supply to our designated firm pipeline receipt points at the lowest reasonable cost. Major suppliers during fiscal 2019 were Castleton Commodities Merchant Trading L.P., CenterPoint Energy Services, Inc., Concord Energy LLC, ConocoPhillips Company, Devon Gas Services, L.P., Hartree Partners, L.P., Targa Gas Marketing LLC, Tenaska Marketing Ventures & Gas Storage, LLC, Texla Energy Management, Inc. and United Energy Trading, LLC.
The combination of base load, peaking and spot purchase agreements, coupled with the withdrawal of gas held in storage, allows us the flexibility to adjust to changes in weather, which minimizes our need to enter into long-term firm commitments.
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We estimate our peak-day availability of natural gas supply to be approximately 4.4 Bcf. The peak-day demand for our distribution operations in fiscal 2019 was on March 4, 2019, when sales to customers reached approximately 3.3 Bcf.
Currently, our distribution divisions utilize 37 pipeline transportation companies, both interstate and intrastate, to transport our natural gas. The pipeline transportation agreements are firm and many of them have “pipeline no-notice” storage service, which provides for daily balancing between system requirements and nominated flowing supplies. These agreements have been negotiated with the shortest term necessary while still maintaining our right of first refusal. The natural gas supply for our Mid-Tex Division is delivered primarily by our APT Division.
To maintain our deliveries to high priority customers, we have the ability, and have exercised our right, to curtail deliveries to certain customers under the terms of interruptible contracts or applicable state regulations or statutes. Our customers’ demand on our system is not necessarily indicative of our ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering, storage and transmission systems, the duration and severity of cold weather, the availability of gas reserves from our suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Curtailment rights provide us the flexibility to meet the human-needs requirements of our customers on a firm basis. Priority allocations imposed by federal and state regulatory agencies, as well as other factors beyond our control, may affect our ability to meet the demands of our customers. We do not anticipate any problems with obtaining additional gas supply as needed for our customers.
Pipeline and Storage Segment Overview
Our pipeline and storage segment consists of the pipeline and storage operations of APT and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas-producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the Permian Basin of West Texas. Through its system, APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies, industrial and electric generation customers, marketers and producers. As part of its pipeline operations, APT owns and operates five underground storage reservoirs in Texas.
Revenues earned from transportation and storage services for APT are subject to traditional ratemaking governed by the RRC. Rates are updated through periodic filings made under Texas’ GRIP. GRIP allows us to include in our rate base annually approved capital costs incurred in the prior calendar year provided that we file a complete rate case at least once every five years; the most recent of which was completed in August 2017. APT’s existing regulatory mechanisms allow certain transportation and storage services to be provided under market-based rates.
Our natural gas transmission operations in Louisiana are comprised of a 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 in Louisiana that serve distribution affiliates of the Company, which have been approved by applicable state regulatory commissions. Generally, these asset management plans require us to share with our distribution customers a significant portion of the cost savings earned from these arrangements.
Natural Gas Marketing Segment Overview
Through December 31, 2016, we were engaged in a nonregulated natural gas marketing business, which was conducted by Atmos Energy Marketing (AEM). AEM’s primary business was to aggregate and purchase gas supply, arrange transportation and storage logistics and ultimately deliver gas to customers at competitive prices. Additionally, AEM utilized proprietary and customer-owned transportation and storage assets to provide various services to its customers as requested.
As more fully described in Note 16, 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 fully exited the nonregulated natural gas marketing business. Accordingly, these operations have been reported as discontinued operations.
Ratemaking Activity
Overview
The method of determining regulated rates varies among the states in which our regulated businesses operate. The regulatory authorities have the responsibility of ensuring that utilities in their jurisdictions operate in the best interests of customers while providing utility companies the opportunity to earn a reasonable return on their investment. Generally, each regulatory authority reviews rate requests and establishes a rate structure intended to generate revenue sufficient to cover the costs of conducting business, including a reasonable return on invested capital.
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Our rate strategy focuses on reducing or eliminating regulatory lag, obtaining adequate returns and providing stable, predictable margins, which benefit both our customers and the Company. As a result of our ratemaking efforts in recent years, Atmos Energy has:
• | Formula rate mechanisms in place in four states that provide for an annual rate review and adjustment to rates. |
• | Infrastructure programs in place in the majority of our states that provide for an annual adjustment to rates for qualifying capital expenditures. Through our annual formula rate mechanisms and infrastructure programs, we have the ability to recover approximately 90 percent of our capital expenditures within six months and substantially all of our capital expenditures within twelve months. |
• | Authorization in tariffs, statute or commission rules that allows us to defer certain elements of our cost of service such as depreciation, ad valorem taxes and pension costs, until they are included in rates. |
• | WNA mechanisms in seven states that serve to minimize the effects of weather on approximately 97 percent of our distribution Contribution Margin. |
• | The ability to recover the gas cost portion of bad debts in five states. |
The following table provides a jurisdictional rate summary for our regulated operations as of September 30, 2019. This information is for regulatory purposes only and may not be representative of our actual financial position.
Division | Jurisdiction | Effective Date of Last Rate/GRIP Action | Rate Base (thousands)(1) | Authorized Rate of Return(1) | Authorized Debt/ Equity Ratio(1) | Authorized Return on Equity(1) | |||||
Atmos Pipeline — Texas | Texas | 05/07/2019 | $2,387,764 | 8.87% | 47/53 | 11.50% | |||||
Colorado-Kansas | Colorado | 05/03/2018 | 134,726 | 7.55% | 44/56 | 9.45% | |||||
Colorado SSIR | 01/01/2019 | 40,009 | 7.55% | 44/56 | 9.45% | ||||||
Kansas | 03/17/2016 | 200,564 | (3) | (3) | (3) | ||||||
Kansas GSRS | 05/01/2019 | 26,322 | (3) | (3) | (3) | ||||||
Kentucky/Mid-States | Kentucky | 05/08/2019 | 424,929 | 7.49% | 42/58 | 9.65% | |||||
Tennessee | 06/01/2019 | 389,061 | 7.79% | 42/58 | 9.80% | ||||||
Virginia | 04/01/2019 | 47,827 | 7.43% | 42/58 | 9.20% | ||||||
Louisiana | Trans La | 04/01/2019 | 192,586 | 7.81% | 41/59 | 9.80% | |||||
LGS | 07/01/2019 | 468,958 | 7.79% | 42/58 | 9.80% | ||||||
Mid-Tex | Mid-Tex Cities(8) | 10/01/2018 | 2,587,261(2) | 7.87% | 42/58 | 9.80% | |||||
Mid-Tex - ATM Cities | 09/26/2019 | 2,975,975(2) | 7.97% | 40/60 | 9.80% | ||||||
Mid-Tex - Environs | 06/04/2019 | 2,975,978(2) | 7.97% | 40/60 | 9.80% | ||||||
Dallas(11) | 06/01/2019 | 2,861,599(2) | 7.96% | 40/60 | 9.80% | ||||||
Mississippi | Mississippi(7) | 11/01/2018 | 415,627 | 7.81% | 45/55 | 10.24% | |||||
Mississippi - SIR(7) | 11/01/2018 | 126,049 | 7.81% | 45/55 | 10.24% | ||||||
West Texas | West Texas Cities(4) (9) | 10/01/2018 | 503,332(10) | 7.87% | 42/58 | 9.80% | |||||
West Texas - ALDC | 05/01/2019 | 594,539(10) | 8.57% | 48/52 | 10.50% | ||||||
West Texas - Environs | 06/04/2019 | 592,919(10) | 7.97% | 40/60 | 9.80% | ||||||
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Division | Jurisdiction | Bad Debt Rider(5) | Formula Rate | Infrastructure Mechanism | Performance Based Rate Program(6) | WNA Period | |||||
Atmos Pipeline — Texas | Texas | No | Yes | Yes | N/A | N/A | |||||
Colorado-Kansas | Colorado | No | No | Yes | No | N/A | |||||
Kansas | Yes | No | Yes | Yes | October-May | ||||||
Kentucky/Mid-States | Kentucky | Yes | No | Yes | Yes | November-April | |||||
Tennessee | Yes | Yes | No | Yes | October-April | ||||||
Virginia | Yes | No | Yes | No | January-December | ||||||
Louisiana | Trans La | No | Yes | Yes | No | December-March | |||||
LGS | No | Yes | Yes | No | December-March | ||||||
Mid-Tex Cities | Texas | Yes | Yes | Yes | No | November-April | |||||
Mid-Tex — Dallas | Texas | Yes | Yes | Yes | No | November-April | |||||
Mississippi | Mississippi | No | Yes | Yes | No | November-April | |||||
West Texas | Texas | Yes | Yes | Yes | No | October-May | |||||
(1) | The rate base, authorized rate of return, authorized debt/equity ratio and authorized return on equity presented in this table are those from the most recent regulatory filing for each jurisdiction. These rate bases, rates of return, debt/equity ratio and returns on equity are not necessarily indicative of current or future rate bases, rates of return or returns on equity. |
(2) | The Mid-Tex rate base represents a “system-wide,” or 100 percent, of the Mid-Tex Division’s rate base. |
(3) | A rate base, rate of return, return on equity or debt/equity ratio was not included in the respective state commission’s final decision. |
(4) | The West Texas Cities includes all West Texas Division cities except Amarillo, Channing, Dalhart and Lubbock (ALDC). |
(5) | The bad debt rider allows us to recover from ratepayers the gas cost portion of bad debts. |
(6) | The performance-based rate program provides incentives to distribution companies to minimize purchased gas costs by allowing the companies and their customers to share the purchased gas costs savings. |
(7) | The Mississippi Public Service Commission approved a settlement at its meeting on October 24, 2019, which included a rate base of $634.4 million and an authorized return of 7.81%. New rates were implemented November 1, 2019. |
(8) | The Mid-Tex Cities approved the Formula Rate Mechanism filing with rates effective October 1, 2019, which included a rate base of $3,052.6 million, an authorized return of 7.83%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%. |
(9) | The West Texas Cities approved the Formula Rate Mechanism filing with rates effective October 1, 2019, which included a rate base of $591.5 million, an authorized return of 7.83%, a debt/equity ratio of 42/58 and an authorized ROE of 9.80%. |
(10) | The West Texas rate base represents a "system-wide," or 100 percent, of the West Texas Division's rate base. |
(11) | The Company and the City of Dallas have arrived at a settlement. This settlement has not yet been approved by the Railroad Commission of Texas (RRC). The DARR rates were implemented subject to refund on June 1, 2019. |
Although substantial progress has been made in recent years to improve rate design and recovery of investment across our service areas, we are continuing to seek improvements in rate design to address cost variations and pursue tariffs that reduce regulatory lag associated with investments. Further, potential changes in federal energy policy, federal safety regulations and changing economic conditions will necessitate continued vigilance by the Company and our regulators in meeting the challenges presented by these external factors.
Recent Ratemaking Activity
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 the commission's or other governmental authority's final ruling. The following table summarizes our ratemaking outcomes for the last three fiscal years. The ratemaking outcomes for fiscal 2019 and 2018 include the effect of tax reform legislation enacted effective January 1, 2018 and do not reflect the true economic benefit of the outcomes because they do not include the corresponding income tax benefit we will receive due to the decrease in our statutory tax rate.
Annual Increase (Decrease) to Operating Income For the Fiscal Year Ended September 30 | ||||||||||||
Rate Action | 2019 | 2018 | 2017 | |||||||||
(In thousands) | ||||||||||||
Annual formula rate mechanisms | $ | 114,810 | $ | 92,472 | $ | 90,427 | ||||||
Rate case filings | 1,656 | (12,853 | ) | 12,961 | ||||||||
Other ratemaking activity | 214 | 457 | 784 | |||||||||
$ | 116,680 | $ | 80,076 | $ | 104,172 | |||||||
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Additionally, the following ratemaking efforts seeking $81.2 million in annual operating income were initiated during fiscal 2019 but had not been completed as of September 30, 2019:
Division | Rate Action | Jurisdiction | Operating Income Requested | |||||
(In thousands) | ||||||||
Colorado-Kansas | Rate Case | Kansas | $ | 3,697 | ||||
Kentucky/Mid-States | Infrastructure Mechanism | Kentucky (1) | 2,912 | |||||
Kentucky/Mid-States | Formula Rate Mechanism | Tennessee | 726 | |||||
Kentucky/Mid-States | Infrastructure Mechanism | Virginia (2) | 85 | |||||
Mid-Tex | Formula Rate Mechanism | Mid-Tex Cities (3) | 47,733 | |||||
Mississippi | Infrastructure Mechanism | Mississippi (4) | 8,569 | |||||
Mississippi | Formula Rate Mechanism | Mississippi (4) | 11,448 | |||||
West Texas | Formula Rate Mechanism | West Texas Cities (5) | 6,226 | |||||
West Texas | Rate Case | West Texas Triangle | (242 | ) | ||||
$ | 81,154 | |||||||
(1) | On September 24, 2019, the Kentucky Public Service Commission approved this filing with rates to be implemented beginning October 1, 2019. |
(2) | On September 24, 2019, the State Corporation Commission of Virginia approved a rate increase of $0.1 million effective October 1, 2019. |
(3) | The Mid-Tex Cities approved a rate increase of $34.4 million effective October 1, 2019. |
(4) The Mississippi Public Service Commission approved an increase in operating income of $7.6 million for the SIR filing and $6.9 million for the SRF filing. New rates were implemented November 1, 2019.
(5) | The West Texas Cities approved a rate increase of $4.9 million effective October 1, 2019. |
Our recent ratemaking activity is discussed in greater detail below.
Annual Formula Rate Mechanisms
As an instrument to reduce regulatory lag, formula rate mechanisms allow us to refresh our rates on an annual basis without filing a formal rate case. However, these filings still involve discovery by the appropriate regulatory authorities prior to the final determination of rates under these mechanisms. The following table summarizes our annual formula rate mechanisms by state.
Annual Formula Rate Mechanisms | ||||
State | Infrastructure Programs | Formula Rate Mechanisms | ||
Colorado | System Safety and Integrity Rider (SSIR) | — | ||
Kansas | Gas System Reliability Surcharge (GSRS) | — | ||
Kentucky | Pipeline Replacement Program (PRP) | — | ||
Louisiana | (1) | Rate Stabilization Clause (RSC) | ||
Mississippi | System Integrity Rider (SIR) | Stable Rate Filing (SRF) | ||
Tennessee | — | Annual Rate Mechanism (ARM) | ||
Texas | Gas Reliability Infrastructure Program (GRIP), (1) | Dallas Annual Rate Review (DARR), Rate Review Mechanism (RRM) | ||
Virginia | Steps to Advance Virginia Energy (SAVE) | — | ||
(1) | Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes (Texas only), until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates. |
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The following table summarizes our annual formula rate mechanisms with effective dates during the fiscal years ended September 30, 2019, 2018 and 2017:
Division | Jurisdiction | Test Year Ended | Increase (Decrease) in Annual Operating Income | Effective Date | ||||||
(In thousands) | ||||||||||
2019 Filings: | ||||||||||
Mid-Tex | ATM Cities | 12/2018 | $ | 6,591 | 09/26/2019 | |||||
Louisiana | LGS | 12/2018 | 7,124 | 07/01/2019 | ||||||
Mid-Tex | Environs | 12/2018 | 2,435 | 06/04/2019 | ||||||
West Texas | Environs | 12/2018 | 1,005 | 06/04/2019 | ||||||
Mid-Tex | DARR (1) | 09/2018 | 9,452 | 06/01/2019 | ||||||
Kentucky/Mid-States | Tennessee ARM | 05/2020 | 2,393 | 06/01/2019 | ||||||
Atmos Pipeline - Texas | Texas | 12/2018 | 49,225 | 05/07/2019 | ||||||
West Texas | Amarillo, Lubbock, Dalhart and Channing | 12/2018 | 5,692 | 05/01/2019 | ||||||
Colorado-Kansas | Kansas GSRS | 12/2018 | 1,562 | 05/01/2019 | ||||||
Louisiana | Trans La | 09/2018 | 4,719 | 04/01/2019 | ||||||
Colorado-Kansas | Colorado GIS | 12/2019 | 87 | 04/01/2019 | ||||||
Colorado-Kansas | Colorado SSIR | 12/2019 | 2,147 | 01/01/2019 | ||||||
Mississippi | Mississippi - SIR | 10/2019 | 7,135 | 11/01/2018 | ||||||
Mississippi | Mississippi - SRF | 10/2019 | (118 | ) | 11/01/2018 | |||||
Kentucky/Mid-States | Tennessee ARM | 05/2019 | (5,032 | ) | 10/15/2018 | |||||
Mid-Tex | Mid-Tex RRM Cities | 12/2017 | 17,633 | 10/01/2018 | ||||||
West Texas | West Texas Cities RRM | 12/2017 | 2,760 | 10/01/2018 | ||||||
Total 2019 Filings | $ | 114,810 | ||||||||
2018 Filings: | ||||||||||
Louisiana | LGS | 12/2017 | $ | (1,521 | ) | 07/01/2018 | ||||
West Texas | Amarillo, Lubbock, Dalhart and Channing | 12/2017 | 4,418 | 06/08/2018 | ||||||
Mid-Tex | Environs | 12/2017 | 1,604 | 06/05/2018 | ||||||
West Texas | Environs | 12/2017 | 826 | 06/05/2018 | ||||||
Atmos Pipeline - Texas | Texas | 12/2017 | 42,173 | 05/22/2018 | ||||||
Louisiana | Trans La | 09/2017 | (1,913 | ) | 05/01/2018 | |||||
Colorado-Kansas | Kansas GSRS | 09/2018 | 820 | 02/27/2018 | ||||||
Mississippi | Mississippi - SIR | 10/2018 | 7,658 | 01/01/2018 | ||||||
Mississippi | Mississippi - SGR (2) | 10/2018 | 1,245 | 01/01/2018 | ||||||
Mississippi | Mississippi - SRF (2) | 10/2018 | — | 01/01/2018 | ||||||
Colorado-Kansas | Colorado SSIR | 12/2018 | 2,228 | 12/20/2017 | ||||||
Atmos Pipeline - Texas | Texas | 12/2016 | 28,988 | 12/05/2017 | ||||||
Kentucky/Mid-States | Kentucky - PRP | 09/2018 | 5,638 | 10/27/2017 | ||||||
Kentucky/Mid-States | Virginia - SAVE | 09/2017 | 308 | 10/01/2017 | ||||||
Total 2018 Filings | $ | 92,472 | ||||||||
2017 Filings: | ||||||||||
Louisiana | LGS | 12/2016 | $ | 6,237 | 07/01/2017 | |||||
Mid-Tex | Mid-Tex DARR | 09/2016 | 9,672 | 06/01/2017 | ||||||
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Mid-Tex | Mid-Tex Cities RRM | 12/2016 | 36,239 | 06/01/2017 | ||||||
Kentucky/Mid-States | Tennessee ARM | 05/2018 | 6,740 | 06/01/2017 | ||||||
Mid-Tex | Environs | 12/2016 | 1,568 | 05/23/2017 | ||||||
West Texas | Environs | 12/2016 | 872 | 05/23/2017 | ||||||
West Texas | Amarillo, Lubbock, Dalhart and Channing | 12/2016 | 4,682 | 04/25/2017 | ||||||
Louisiana | Trans La | 09/2016 | 4,392 | 04/01/2017 | ||||||
West Texas | West Texas Cities RRM | 09/2016 | 4,255 | 03/15/2017 | ||||||
Colorado-Kansas | Kansas | 09/2016 | 801 | 02/09/2017 | ||||||
Mississippi | Mississippi - SRF | 10/2017 | 4,390 | 02/01/2017 | ||||||
Mississippi | Mississippi - SIR | 10/2017 | 3,334 | 01/01/2017 | ||||||
Mississippi | Mississippi - SGR | 10/2017 | 1,292 | 01/01/2017 | ||||||
Colorado-Kansas | Colorado - SSIR | 12/2017 | 1,350 | 01/01/2017 | ||||||
Kentucky/Mid-States | Kentucky - PRP | 09/2017 | 4,981 | 10/14/2016 | ||||||
Kentucky/Mid-States | Virginia - SAVE | 09/2017 | (378 | ) | 10/01/2016 | |||||
Total 2017 Filings | $ | 90,427 | ||||||||
(1) | The Company and the City of Dallas have arrived at a settlement. This settlement has not yet been approved by the RRC. The DARR rates were implemented subject to refund on June 1, 2019. |
(2) | Beginning in fiscal 2019, our SGR rate base was combined with our SRF rate base, per Commission order. |
Rate Case Filings
A rate case is a formal request from Atmos Energy to a regulatory authority to increase rates that are charged to customers. Rate cases may also be initiated when the regulatory authorities request us to justify our rates. This process is referred to as a “show cause” action. Adequate rates are intended to provide for recovery of the Company’s costs as well as a reasonable rate of return to our shareholders and ensure that we continue to safely deliver reliable, reasonably priced natural gas service to our customers. The following table summarizes our recent rate cases:
Division | State | Increase (Decrease) in Annual Operating Income | Effective Date | |||||
(In thousands) | ||||||||
2019 Rate Case Filings: | ||||||||
Mid-Tex (ATM Cities) | Texas | $ | 2,113 | 06/01/2019 | ||||
Kentucky/Mid-States | Kentucky | 3,441 | 05/08/2019 | |||||
Kentucky/Mid-States | Virginia | (400 | ) | 04/01/2019 | ||||
Mid-Tex (Environs) | Texas | (2,674 | ) | 01/01/2019 | ||||
West Texas (Environs) | Texas | (824 | ) | 01/01/2019 | ||||
Total 2019 Rate Case Filings | $ | 1,656 | ||||||
2018 Rate Case Filings: | ||||||||
Colorado-Kansas | Colorado | $ | (241 | ) | 05/03/2018 | |||
Kentucky/Mid-States | Kentucky | (7,504 | ) | 05/03/2018 | ||||
Mid-Tex - City of Dallas | Texas | (5,108 | ) | 02/14/2018 | ||||
Total 2018 Rate Case Filings | $ | (12,853 | ) | |||||
2017 Rate Case Filings: | ||||||||
Atmos Pipeline - Texas | Texas | $ | 12,955 | 08/01/2017 | ||||
Kentucky/Mid-States | Virginia | 6 | 12/27/2016 | |||||
Total 2017 Rate Case Filings | $ | 12,961 | ||||||
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Other Ratemaking Activity
The following table summarizes other ratemaking activity during the fiscal years ended September 30, 2019, 2018 and 2017:
Division | Jurisdiction | Rate Activity | Increase in Annual Operating Income | Effective Date | ||||||
(In thousands) | ||||||||||
2019 Other Rate Activity: | ||||||||||
Colorado-Kansas | Kansas | Ad Valorem (1) | $ | 214 | 02/01/2019 | |||||
Total 2019 Other Rate Activity | $ | 214 | ||||||||
2018 Other Rate Activity: | ||||||||||
Colorado-Kansas | Kansas | Ad Valorem(1) | $ | 457 | 02/01/2018 | |||||
Total 2018 Other Rate Activity | $ | 457 | ||||||||
2017 Other Rate Activity: | ||||||||||
Colorado-Kansas | Kansas | Ad-Valorem(1) | $ | 784 | 02/01/2017 | |||||
Total 2017 Other Rate Activity | $ | 784 | ||||||||
(1) | The Ad Valorem filing relates to property taxes that are either over or undercollected compared to the amount included in our Kansas service area's base rates. |
Other Regulation
We are regulated by various state or local public utility authorities. We are also subject to regulation by the United States Department of Transportation with respect to safety requirements in the operation and maintenance of our transmission and distribution facilities. In addition, our operations are also subject to various state and federal laws regulating environmental matters. From time to time, we receive inquiries regarding various environmental matters. We believe that our properties and operations comply with, and are operated in conformity with, applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations. Our environmental claims have arisen primarily from former manufactured gas plant sites. The Pipeline and Hazardous Materials Safety Administration (PHMSA), within the U.S. Department of Transportation, develops and enforces regulations for the safe, reliable and environmentally sound operation of the pipeline transportation system. The PHMSA pipeline safety statutes provide for states to assume safety authority over intrastate natural transmission and distribution gas pipelines. State pipeline safety programs are responsible for adopting and enforcing the federal and state pipeline safety regulations for intrastate natural gas transmission and distribution pipelines.
The Federal Energy Regulatory Commission (FERC) allows, pursuant to Section 311 of the Natural Gas Policy Act (NGA), gas transportation services through our APT assets “on behalf of” interstate pipelines or local distribution companies served by interstate pipelines, without subjecting these assets to the jurisdiction of the FERC under the NGA. Additionally, the FERC has regulatory authority over the use and release of interstate pipeline and storage capacity. The FERC also has authority to detect and prevent market manipulation and to enforce compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. We have taken what we believe are the necessary and appropriate steps to comply with these regulations.
The SEC and the Commodities Futures Trading Commission, pursuant to the Dodd–Frank Act, established numerous regulations relating to U.S. financial markets. We enacted procedures and modified existing business practices and contractual arrangements to comply with such regulations. There are, however, some rulemaking proceedings that have not yet been finalized, including those relating to capital and margin rules for (non–cleared) swaps. We do not expect these rules to directly impact our business practices or collateral requirements. However, depending on the substance of these final rules, in addition to certain international regulatory requirements still under development that are similar to Dodd–Frank, our swap counterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate counterparties to increase our collateral requirements or cash postings.
Competition
Although our regulated distribution operations are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas, we do compete with other natural gas suppliers and suppliers of alternative fuels for sales to industrial customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Electric utilities offer electricity as a rival energy source and
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compete for the space heating, water heating and cooking markets. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. The principal means to compete against alternative fuels is lower prices, and natural gas historically has maintained its price advantage in the residential, commercial and industrial markets.
Our pipeline and storage operations have historically faced competition from other existing intrastate pipelines seeking to provide or arrange transportation, storage and other services for customers. In the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.
Employees
At September 30, 2019, we had 4,776 employees, consisting of 4,645 employees in our distribution operations and 131 employees in our pipeline and storage operations.
Available Information
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports, and amendments to those reports, and other forms that we file with or furnish to the Securities and Exchange Commission (SEC) at their website, www.sec.gov, are also available free of charge at our website, www.atmosenergy.com, under “Publications and SEC Filings” under the “Investors” tab under "Our Company", as soon as reasonably practicable, after we electronically file these reports with, or furnish these reports to, the SEC. We will also provide copies of these reports free of charge upon request to Shareholder Relations at the address and telephone number appearing below:
Shareholder Relations
Atmos Energy Corporation
P.O. Box 650205
Dallas, Texas 75265-0205
972-855-3729
Corporate Governance
In accordance with and pursuant to relevant related rules and regulations of the SEC as well as corporate governance-related listing standards of the New York Stock Exchange (NYSE), the Board of Directors of the Company has established and periodically updated our Corporate Governance Guidelines and Code of Conduct, which is applicable to all directors, officers and employees of the Company. In addition, in accordance with and pursuant to such NYSE listing standards, our Chief Executive Officer during fiscal 2019, Michael E. Haefner, certified to the New York Stock Exchange that he was not aware of any violations by the Company of NYSE corporate governance listing standards. The Board of Directors also annually reviews and updates, if necessary, the charters for each of its Audit, Human Resources and Nominating and Corporate Governance Committees. All of the foregoing documents are posted on our website, www.atmosenergy.com, under "Governance" under the "Corporate Responsibility" tab under "Our Company". We will also provide copies of all corporate governance documents free of charge upon request to Shareholder Relations at the address listed above.
ITEM 1A. | Risk Factors. |
Our financial and operating results are subject to a number of risk factors, many of which are not within our control. Investors should carefully consider the following discussion of risk factors as well as other information appearing in this report. These factors include the following:
We are subject to state and local regulations that affect our operations and financial results.
We are subject to regulatory oversight from various state and local regulatory authorities in the eight states that we serve. Therefore, our returns are continuously monitored and are subject to challenge for their reasonableness by the appropriate regulatory authorities or other third-party intervenors. In the normal course of business, as a regulated entity, we often need to place assets in service and establish historical test periods before rate cases that seek to adjust our allowed returns to recover that investment can be filed. Further, the regulatory review process can be lengthy in the context of traditional ratemaking. Because of this process, we suffer the negative financial effects of having placed assets in service without the benefit of rate relief, which is commonly referred to as “regulatory lag.”
However, in the last several years, a number of regulatory authorities in the states we serve have approved rate mechanisms that provide for annual adjustments to rates that allow us to recover the cost of investments made to replace existing infrastructure or reflect changes in our cost of service. These mechanisms work to effectively reduce the regulatory lag inherent in the ratemaking process. However, regulatory lag could significantly increase if the regulatory authorities modify or terminate these rate mechanisms. The regulatory process also involves the risk that regulatory authorities may (i) review our
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purchases of natural gas and adjust the amount of our gas costs that we pass through to our customers or (ii) limit the costs we may have incurred from our cost of service that can be recovered from customers.
We are also subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties or interruptions in our operations that could be significant to our financial results. In addition, existing environmental regulations may be revised or our operations may become subject to new regulations.
Some of our operations are subject to increased federal regulatory oversight that could affect our operations and financial results.
FERC has regulatory authority over some of our operations, including the use and release of interstate pipeline and storage capacity. FERC has adopted rules designed to prevent market power abuse and market manipulation and to promote compliance with FERC’s other rules, policies and orders by companies engaged in the sale, purchase, transportation or storage of natural gas in interstate commerce. These rules carry increased penalties for violations. Although we have taken steps to structure current and future transactions to comply with applicable current FERC regulations, changes in FERC regulations or their interpretation by FERC or additional regulations issued by FERC in the future could also adversely affect our business, financial condition or financial results.
We may experience increased federal, state and local regulation of the safety of our operations.
The safety and protection of the public, our customers and our employees is our top priority. We constantly monitor and maintain our pipeline and distribution systems to ensure that natural gas is delivered safely, reliably and efficiently through our network of more than 75,000 miles of distribution and transmission lines. As in recent years, natural gas distribution and pipeline companies are continuing to encounter increasing federal, state and local oversight of the safety of their operations. Although we believe these are costs ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results.
We may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.
PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in “high consequence areas” where a leak or rupture could potentially do the most harm. As pipeline operator, the Company will be required to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a “high consequence area”
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventative and mitigating actions.
The Company incurs significant costs associated with its compliance with existing PHMSA and comparable state regulations. Although we believe these are costs ultimately recoverable through our rates, the costs of complying with new laws and regulations may have at least a short-term adverse impact on our operating costs and financial results. For example, the adoption of new regulations requiring more comprehensive or stringent safety standards could require installation of new or modified safety controls, new capital projects, or accelerated maintenance programs, all of which could require a potentially significant increase in operating costs.
Distributing, transporting and storing natural gas involve risks that may result in accidents and additional operating costs.
Our operations involve a number of hazards and operating risks inherent in storing and transporting natural gas that could affect the public safety and reliability of our distribution system. While Atmos Energy, with the support from each of its regulatory commissions, is accelerating the replacement of aging pipeline infrastructure, operating issues such as as leaks, accidents, equipment problems and incidents, including explosions and fire, could result in legal liability, repair and remediation costs, increased operating costs, significant increased capital expenditures, regulatory fines and penalties and other costs and a loss of customer confidence. We maintain liability and property insurance coverage in place for many of these hazards and risks. However, because some of our transmission pipeline and storage facilities are near or are in populated areas,
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any loss of human life or adverse financial results resulting from such events could be large. If these events were not fully covered by our general liability and property insurance, which policies are subject to certain limits and deductibles, our operations or financial results could be adversely affected.
Our growth in the future may be limited by the nature of our business, which requires extensive capital spending.
Our operations are capital-intensive. We must make significant capital expenditures on a long-term basis to modernize our distribution and transmission system to improve the safety and reliability and to comply with the safety rules and regulations issued by the regulatory authorities responsible for the service areas we operate. In addition, we must continually build new capacity to serve the growing needs of the communities we serve. The magnitude of these expenditures may be affected by a number of factors, including new regulations, the general state of the economy and weather.
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. The cost and availability of borrowing funds from third party lenders or issuing equity is dependent on the liquidity of the credit markets, interest rates and other market conditions. This in turn may limit the amount of funds we can invest in our infrastructure.
The Company is dependent on continued access to the credit and capital markets to execute our business strategy.
Our long-term debt is currently rated as “investment grade” by Standard & Poor’s Corporation and Moody’s Investors Service, Inc. Similar to most companies, we rely upon access to both short-term and long-term credit and capital markets to satisfy our liquidity requirements. If adverse credit conditions were to cause a significant limitation on our access to the private credit and public capital markets, we could see a reduction in our liquidity. A significant reduction in our liquidity could in turn trigger a negative change in our ratings outlook or even a reduction in our credit ratings by one or more of the credit rating agencies. Such a downgrade could further limit our access to private credit and/or public capital markets and increase our costs of borrowing.
While we believe we can meet our capital requirements from our operations and the sources of financing available to us, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near term. The future effects on our business, liquidity and financial results of a deterioration of current conditions in the credit and capital markets could be material and adverse to us, both in the ways described above or in other ways that we do not currently anticipate.
We are exposed to market risks that are beyond our control, which could adversely affect our financial results.
We are subject to market risks beyond our control, including (i) commodity price volatility caused by market supply and demand dynamics, counterparty performance or counterparty creditworthiness, and (ii) interest rate risk. We are generally insulated from commodity price risk through our purchased gas cost mechanisms. With respect to interest rate risk, we have been operating in a relatively low interest-rate environment in recent years compared to historical norms for both short and long-term interest rates. However, increases in interest rates could adversely affect our future financial results to the extent that we do not recover our actual interest expense in our rates.
The concentration of our operations in the State of Texas exposes our operations and financial results to economic conditions, weather patterns and regulatory decisions in Texas.
Approximately 70 percent of our consolidated operations are located in the State of Texas. This concentration of our business in Texas means that our operations and financial results may be significantly affected by changes in the Texas economy in general, weather patterns and regulatory decisions by state and local regulatory authorities in Texas.
A deterioration in economic conditions could adversely affect our customers and negatively impact our financial results.
Any adverse changes in economic conditions in the United States, especially in the states in which we operate, could adversely affect the financial resources of many domestic households. As a result, our customers could seek to use less gas and it may be more difficult for them to pay their gas bills. This would likely lead to slower collections and higher than normal levels of accounts receivable. This, in turn, could increase our financing requirements. Additionally, should economic conditions deteriorate, our industrial customers could seek alternative energy sources, which could result in lower sales volumes.
Increased gas costs could adversely impact our customer base and customer collections and increase our level of indebtedness.
Rapid increases in the costs of purchased gas would cause us to experience a significant increase in short-term debt. We must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our natural gas distribution collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher than normal
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accounts receivable. This could result in higher short-term debt levels, greater collection efforts and increased bad debt expense.
If contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner, our ability to meet our customers’ natural gas requirements may be impaired and our financial condition may be adversely affected.
In order to meet our customers’ annual and seasonal natural gas demands, we must obtain a sufficient supply of natural gas, interstate pipeline capacity and storage capacity. If we are unable to obtain these, either from our suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, our financial condition and results of operations may be adversely affected. If a substantial disruption to or reduction in interstate natural gas pipelines’ transmission and storage capacity occurred due to operational failures or disruptions, legislative or regulatory actions, hurricanes, tornadoes, floods, terrorist or cyber-attacks or acts of war, our operations or financial results could be adversely affected.
Our operations are subject to increased competition.
In residential and commercial customer markets, our distribution operations compete with other energy products, such as electricity and propane. Our primary product competition is with electricity for heating, water heating and cooking. Increases in the price of natural gas could negatively impact our competitive position by decreasing the price benefits of natural gas to the consumer. This could adversely impact our business if our customer growth slows or if our customers further conserve their use of gas, resulting in reduced gas purchases and customer billings.
In the case of industrial customers, such as manufacturing plants, adverse economic conditions, including higher gas costs, could cause these customers to use alternative sources of energy, such as electricity, or bypass our systems in favor of special competitive contracts with lower per-unit costs. Our pipeline and storage operations historically have faced limited competition from other existing intrastate pipelines and gas marketers seeking to provide or arrange transportation, storage and other services for customers. However, in the last few years, several new pipelines have been completed, which has increased the level of competition in this segment of our business.
Adverse weather conditions could affect our operations or financial results.
We have weather-normalized rates for approximately 97 percent of our residential and commercial meters in our distribution operations, which substantially mitigates the adverse effects of warmer-than-normal weather for meters in those service areas. However, there is no assurance that we will continue to receive such regulatory protection from adverse weather in our rates in the future. The loss of such weather-normalized rates could have an adverse effect on our operations and financial results. In addition, our operating results may continue to vary somewhat with the actual temperatures during the winter heating season. Additionally, sustained cold weather could challenge our ability to adequately meet customer demand in our operations.
The costs of providing health care benefits, pension and postretirement health care benefits and related funding requirements may increase substantially.
We provide health care benefits, a cash-balance pension plan and postretirement health care benefits to eligible full-time employees. The costs of providing health care benefits to our employees could significantly increase over time due to rapidly increasing health care inflation, and any future legislative changes related to the provision of health care benefits. The impact of additional costs which are likely to be passed on to the Company is difficult to measure at this time.
The costs of providing a cash-balance pension plan to eligible full-time employees prior to 2011 and postretirement health care benefits to eligible full-time employees and related funding requirements could be influenced by changes in the market value of the assets funding our pension and postretirement health care plans. Any significant declines in the value of these investments due to sustained declines in equity markets or a reduction in bond yields could increase the costs of our pension and postretirement health care plans and related funding requirements in the future. Further, our costs of providing such benefits and related funding requirements are also subject to a number of factors, including (i) changing demographics, including longer life expectancy of beneficiaries and an expected increase in the number of eligible former employees over the next five to ten years; (ii) various actuarial calculations and assumptions which may differ materially from actual results due primarily to changing market and economic conditions, including changes in interest rates, and higher or lower withdrawal rates; and (iii) future government regulation.
The costs to the Company of providing these benefits and related funding requirements could also increase materially in the future, should there be a material reduction in the amount of the recovery of these costs through our rates or should significant delays develop in the timing of the recovery of such costs, which could adversely affect our financial results.
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The inability to continue to hire, train and retain operational, technical and managerial personnel could adversely affect our results of operations.
Although the average age of the employee base of Atmos Energy is not significantly changing year over year, there are still a number of employees who will become eligible to retire within the next five to 10 years. If we were unable to hire appropriate personnel or contractors to fill future needs, the Company could encounter operating challenges and increased costs, primarily due to a loss of knowledge, errors due to inexperience or the lengthy time period typically required to adequately train replacement personnel. In addition, higher costs could result from loss of productivity or increased safety compliance issues. The inability to hire, train and retain new operational, technical and managerial personnel adequately and to transfer institutional knowledge and expertise could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.
The operations and financial results of the Company could be adversely impacted as a result of climate change.
As climate change occurs, our businesses could be adversely impacted, although we believe it is likely that any such resulting impacts would occur very gradually over a long period of time and thus would be difficult to quantify with any degree of specificity. Such climate change could cause shifts in population, including customers moving away from our service territories.
It could also result in more frequent and more severe weather events, such as hurricanes and tornadoes, which could increase our costs to repair damaged facilities and restore service to our customers. If we were unable to deliver natural gas to our customers, our financial results would be impacted by lost revenues, and we generally would have to seek approval from regulators to recover restoration costs. To the extent we would be unable to recover those costs, or if higher rates resulting from our recovery of such costs would result in reduced demand for our services, our future business, financial condition or financial results could be adversely impacted.
Greenhouse gas emissions or other legislation or regulations intended to address climate change could increase our operating costs, adversely affecting our financial results, growth, cash flows and results of operations.
Federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Such laws or regulations could impose costs tied to greenhouse gas emissions, operational requirements or restrictions, or additional charges to fund energy efficiency activities. They could also provide a cost advantage to alternative energy sources, impose costs or restrictions on end users of natural gas, or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. The focus on climate change could adversely impact the reputation of fossil fuel products or services. The occurrence of the foregoing events could put upward pressure on the cost of natural gas relative to other energy sources, increase our costs and the prices we charge to customers, reduce the demand for natural gas or cause fuel switching to other energy sources, and impact the competitive position of natural gas and the ability to serve new or existing customers, adversely affecting our business, results of operations and cash flows.
Increased dependence on technology may hinder the Company’s business operations and adversely affect its financial condition and results of operations if such technologies fail.
Over the last several years, the Company has implemented or acquired a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. These tools and systems support critical functions including, scheduling and dispatching of service technicians, automated meter reading systems, customer care and billing, operational plant logistics, management reporting, and external financial reporting. The failure of these or other similarly important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations.
Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts would protect against all potential issues related to the loss of any such technologies.
Cyber-attacks or acts of cyber-terrorism could disrupt our business operations and information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information.
Our business operations and information technology systems may be vulnerable to an attack by individuals or organizations intending to disrupt our business operations and information technology systems, even though the Company has implemented policies, procedures and controls to prevent and detect these activities. We use our information technology systems to manage our distribution and intrastate pipeline and storage operations and other business processes. Disruption of those systems could adversely impact our ability to safely deliver natural gas to our customers, operate our pipeline and storage
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systems or serve our customers timely. Accordingly, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected.
In addition, we use our information technology systems to protect confidential or sensitive customer, employee and Company information developed and maintained in the normal course of our business. Any attack on such systems that would result in the unauthorized release of customer, employee or other confidential or sensitive data could have a material adverse effect on our business reputation, increase our costs and expose us to additional material legal claims and liability. Even though we have insurance coverage in place for many of these cyber-related risks, if such an attack or act of terrorism were to occur, our operations and financial results could be adversely affected to the extent not fully covered by such insurance coverage.
Natural disasters, terrorist activities or other significant events could adversely affect our operations or financial results.
Natural disasters are always a threat to our assets and operations. In addition, the threat of terrorist activities could lead to increased economic instability and volatility in the price of natural gas that could affect our operations. Also, companies in our industry may face a heightened risk of exposure to actual acts of terrorism, which could subject our operations to increased risks. As a result, the availability of insurance covering such risks may become more limited, which could increase the risk that an event could adversely affect our operations or financial results.
ITEM 1B. | Unresolved Staff Comments. |
Not applicable.
ITEM 2. | Properties. |
Distribution, transmission and related assets
At September 30, 2019, in our distribution segment, we owned an aggregate of 70,875 miles of underground distribution and transmission mains throughout our distribution systems. These mains are located on easements or rights-of-way. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. Through our pipeline and storage segment we owned 5,669 miles of gas transmission lines as well.
Storage Assets
We own underground gas storage facilities in several states to supplement the supply of natural gas in periods of peak demand. The following table summarizes certain information regarding our underground gas storage facilities at September 30, 2019:
State | Usable Capacity (Mcf) | Cushion Gas (Mcf)(1) | Total Capacity (Mcf) | Maximum Daily Delivery Capability (Mcf) | ||||||||
Distribution Segment | ||||||||||||
Kentucky | 7,956,991 | 9,562,283 | 17,519,274 | 158,100 | ||||||||
Kansas | 3,239,000 | 2,300,000 | 5,539,000 | 45,000 | ||||||||
Mississippi | 1,907,571 | 2,442,917 | 4,350,488 | 31,000 | ||||||||
Total | 13,103,562 | 14,305,200 | 27,408,762 | 234,100 | ||||||||
Pipeline and Storage Segment | ||||||||||||
Texas | 46,083,549 | 15,878,025 | 61,961,574 | 1,710,000 | ||||||||
Louisiana | 411,040 | 256,900 | 667,940 | 56,000 | ||||||||
Total | 46,494,589 | 16,134,925 | 62,629,514 | 1,766,000 | ||||||||
Total | 59,598,151 | 30,440,125 | 90,038,276 | 2,000,100 | ||||||||
(1) | Cushion gas represents the volume of gas that must be retained in a facility to maintain reservoir pressure. |
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Additionally, we contract for storage service in underground storage facilities on many of the interstate and intrastate pipelines serving us to supplement our proprietary storage capacity. The following table summarizes our contracted storage capacity at September 30, 2019:
Segment | Division/Company | Maximum Storage Quantity (MMBtu) | Maximum Daily Withdrawal Quantity (MDWQ)(1) | |||||
Distribution Segment | ||||||||
Colorado-Kansas Division | 6,343,728 | 147,965 | ||||||
Kentucky/Mid-States Division | 8,175,103 | 226,739 | ||||||
Louisiana Division | 2,514,875 | 173,765 | ||||||
Mid-Tex Division | 4,000,000 | 150,000 | ||||||
Mississippi Division | 5,099,536 | 164,764 | ||||||
West Texas Division | 5,500,000 | 176,000 | ||||||
Total | 31,633,242 | 1,039,233 | ||||||
Pipeline and Storage Segment | ||||||||
Trans Louisiana Gas Pipeline, Inc. | 1,000,000 | 47,500 | ||||||
Total Contracted Storage Capacity | 32,633,242 | 1,086,733 | ||||||
(1) | Maximum daily withdrawal quantity (MDWQ) amounts will fluctuate depending upon the season and the month. Unless otherwise noted, MDWQ amounts represent the MDWQ amounts as of November 1, which is the beginning of the winter heating season. |
Offices
Our administrative offices and corporate headquarters are consolidated in a leased facility in Dallas, Texas. We also maintain field offices throughout our service territory, some of which are located in leased facilities.
ITEM 3. | Legal Proceedings. |
See Note 12 to the consolidated financial statements, which is incorporated in this Item 3 by reference.
ITEM 4. | Mine Safety Disclosures. |
Not applicable.
PART II
ITEM 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Our stock trades on the New York Stock Exchange under the trading symbol “ATO.” The dividends paid per share of our common stock for fiscal 2019 and 2018 are listed below.
Fiscal 2019 | Fiscal 2018 | |||||||
Quarter ended: | ||||||||
December 31 | $ | 0.525 | $ | 0.485 | ||||
March 31 | 0.525 | 0.485 | ||||||
June 30 | 0.525 | 0.485 | ||||||
September 30 | 0.525 | 0.485 | ||||||
$ | 2.10 | $ | 1.94 | |||||
Dividends are payable at the discretion of our Board of Directors out of legally available funds. The Board of Directors typically declares dividends in the same fiscal quarter in which they are paid. As of October 31, 2019, there were 11,806 holders of record of our common stock. Future payments of dividends, and the amounts of these dividends, will depend on our
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financial condition, results of operations, capital requirements and other factors. We sold no securities during fiscal 2019 that were not registered under the Securities Act of 1933, as amended.
Performance Graph
The performance graph and table below compares the yearly percentage change in our total return to shareholders for the last five fiscal years with the total return of the S&P 500 Stock Index (S&P 500) and the cumulative total return of a customized peer company group, the Comparison Company Index. The Comparison Company Index is comprised of natural gas distribution companies with similar revenues, market capitalizations and asset bases to that of the Company. The graph and table below assume that $100.00 was invested on September 30, 2014 in our common stock, the S&P 500 and in the common stock of the companies in the Comparison Company Indices, as well as a reinvestment of dividends paid on such investments throughout the period.
Comparison of Five-Year Cumulative Total Return
among Atmos Energy Corporation, S&P 500 Index
and Comparison Company Index
Cumulative Total Return | |||||||||||||||||
9/30/2014 | 9/30/2015 | 9/30/2016 | 9/30/2017 | 9/30/2018 | 9/30/2019 | ||||||||||||
Atmos Energy Corporation | 100.00 | 125.54 | 164.58 | 189.56 | 217.10 | 268.76 | |||||||||||
S&P 500 Stock Index | 100.00 | 99.39 | 114.72 | 136.07 | 160.44 | 167.27 | |||||||||||
Comparison Company Index | 100.00 | 110.80 | 136.77 | 159.21 | 168.54 | 219.86 | |||||||||||
The Comparison Company Index reflects the cumulative total return of companies in our peer group, which is comprised of a hybrid group of utility companies, primarily natural gas distribution companies, recommended by our independent executive compensation consulting firm and approved by the Board of Directors. The companies in the index are Alliant Energy Corporation, Ameren Corporation, CenterPoint Energy, Inc., CMS Energy Corporation, DTE Energy Company, National Fuel Gas Company, NiSource Inc., ONE Gas, Inc., Spire Inc. (formerly The Laclede Group, Inc.), Vectren Corporation(1), WEC Energy Group, Inc., and Xcel Energy, Inc.
(1) | Vectren Corporation merged with CenterPoint Energy, Inc. prior to September 30, 2019. As a result, the cumulative total return of Vectren Corporation is not included in the Comparison Company Index represented in the graph above. |
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The following table sets forth the number of securities authorized for issuance under our equity compensation plans at September 30, 2019.
Number of securities to be issued upon exercise of outstanding options, restricted stock units, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||
(a) | (b) | (c) | |||||||
Equity compensation plans approved by security holders: | |||||||||
1998 Long-Term Incentive Plan | 1,004,158 | (1) | $ | — | 1,489,985 | ||||
Total equity compensation plans approved by security holders | 1,004,158 | — | 1,489,985 | ||||||
Equity compensation plans not approved by security holders | — | — | — | ||||||
Total | 1,004,158 | $ | — | 1,489,985 | |||||
(1) | Comprised of a total of 384,056 time-lapse restricted stock units, 343,467 director share units and 276,635 performance-based restricted stock units at the target level of performance granted under our 1998 Long-Term Incentive Plan. |
ITEM 6. | Selected Financial Data. |
The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein.
Fiscal Year Ended September 30 | |||||||||||||||||||
2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
(In thousands, except per share data) | |||||||||||||||||||
Results of Operations | |||||||||||||||||||
Operating revenues | $ | 2,901,848 | $ | 3,115,546 | $ | 2,759,735 | $ | 2,454,648 | $ | 2,926,985 | |||||||||
Contribution Margin | $ | 2,043,011 | $ | 1,947,698 | $ | 1,834,199 | $ | 1,708,456 | $ | 1,631,310 | |||||||||
Income from continuing operations | $ | 511,406 | $ | 603,064 | $ | 382,711 | $ | 345,542 | $ | 305,623 | |||||||||
Net income | $ | 511,406 | $ | 603,064 | $ | 396,421 | $ | 350,104 | $ | 315,075 | |||||||||
Diluted income per share from continuing operations | $ | 4.35 | $ | 5.43 | $ | 3.60 | $ | 3.33 | $ | 3.00 | |||||||||
Diluted net income per share | $ | 4.35 | $ | 5.43 | $ | 3.73 | $ | 3.38 | $ | 3.09 | |||||||||
Cash dividends declared per share | $ | 2.10 | $ | 1.94 | $ | 1.80 | $ | 1.68 | $ | 1.56 | |||||||||
Financial Condition | |||||||||||||||||||
Net property, plant and equipment(1) | $ | 11,787,669 | $ | 10,371,147 | $ | 9,259,182 | $ | 8,268,606 | $ | 7,416,700 | |||||||||
Total assets | $ | 13,367,619 | $ | 11,874,437 | $ | 10,749,596 | $ | 10,010,889 | $ | 9,075,072 | |||||||||
Capitalization: | |||||||||||||||||||
Shareholders’ equity | $ | 5,750,223 | $ | 4,769,951 | $ | 3,898,666 | $ | 3,463,059 | $ | 3,194,797 | |||||||||
Long-term debt (excluding current maturities) | 3,529,452 | 2,493,665 | 3,067,045 | 2,188,779 | 2,437,515 | ||||||||||||||
Total capitalization | $ | 9,279,675 | $ | 7,263,616 | $ | 6,965,711 | $ | 5,651,838 | $ | 5,632,312 | |||||||||
(1) | Amounts shown are net of assets held for sale related to the divestiture of our natural gas marketing business for fiscal years 2016 and 2015. |
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ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
INTRODUCTION
This section provides management’s discussion of the financial condition, changes in financial condition and results of operations of Atmos Energy Corporation and its consolidated subsidiaries with specific information on results of operations and liquidity and capital resources. It includes management’s interpretation of our financial results, the factors affecting these results, the major factors expected to affect future operating results and future investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto.
Several factors exist that could influence our future financial performance, some of which are described in Item 1A above, “Risk Factors”. They should be considered in connection with evaluating forward-looking statements contained in this report or otherwise made by or on behalf of us since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.
Cautionary Statement for the Purposes of the Safe Harbor under the Private Securities Litigation Reform Act of 1995
The statements contained in this Annual Report on Form 10-K may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report are forward-looking statements made in good faith by us and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of our documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “goal”, “intend”, “objective”, “plan”, “projection”, “seek”, “strategy” or similar words are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements relating to our strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: state and local regulatory trends and decisions, including the impact of rate proceedings before various state regulatory commissions; increased federal regulatory oversight and potential penalties; possible increased federal, state and local regulation of the safety of our operations; 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 capital-intensive nature of our business; our ability to continue to access the credit and capital markets to execute our business strategy; market risks beyond our control affecting our risk management activities, including commodity price volatility, counterparty performance or creditworthiness and interest rate risk; the concentration of our operations in Texas; the impact of adverse economic conditions on our customers; changes in the availability and price of natural gas; the availability and accessibility of contracted gas supplies, interstate pipeline and/or storage services; increased competition from energy suppliers and alternative forms of energy; adverse weather conditions; increased costs of providing health care benefits, along with pension and postretirement health care benefits and increased funding requirements; the inability to continue to hire, train and retain operational, technical and managerial personnel; the impact of climate change; the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change; 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. 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 16 to our consolidated financial statements. The accounting policies discussed below are both important to the presentation of our financial condition and results of operations and require management to make difficult, subjective or complex accounting estimates. Accordingly, these critical accounting policies are reviewed periodically by the Audit Committee of the Board of Directors.
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Critical Accounting Policy | Summary of Policy | Factors Influencing Application of the Policy |
Regulation | Our distribution and pipeline operations meet the criteria of a cost-based, rate-regulated entity under accounting principles generally accepted in the United States. Accordingly, the financial results for these operations reflect the effects of the ratemaking and accounting practices and policies of the various regulatory commissions to which we are subject. As a result, certain costs that would normally be expensed under accounting principles generally accepted in the United States are permitted to be capitalized or deferred on the balance sheet because it is probable they can be recovered through rates. Further, regulation may impact the period in which revenues or expenses are recognized. The amounts expected to be recovered or recognized are based upon historical experience and our understanding of the regulations. Discontinuing the application of this method of accounting for regulatory assets and liabilities or changes in the accounting for our various regulatory mechanisms could significantly increase our operating expenses as fewer costs would likely be capitalized or deferred on the balance sheet, which could reduce our net income. | Decisions of regulatory authorities Issuance of new regulations or regulatory mechanisms Assessing the probability of the recoverability of deferred costs Continuing to meet the criteria of a cost-based, rate regulated entity for accounting purposes |
Unbilled Revenue | We follow the revenue accrual method of accounting for distribution segment revenues whereby revenues attributable to gas delivered to customers, but not yet billed under the cycle billing method, are estimated and accrued and the related costs are charged to expense. When permitted, we implement rates that have not been formally approved by our regulatory authorities, subject to refund.We recognize this revenue and establish a reserve for amounts that could be refunded based on our experience for the jurisdiction in which the rates were implemented. | Estimates of delivered sales volumes based on actual tariff information and weather information and estimates of customer consumption and/or behavior Estimates of purchased gas costs related to estimated deliveries Estimates of amounts billed subject to refund |
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Critical Accounting Policy | Summary of Policy | Factors Influencing Application of the Policy |
Pension and other postretirement plans | Pension and other postretirement plan costs and liabilities are determined on an actuarial basis using a September 30 measurement date and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets, assumed discount rates and current demographic and actuarial mortality data. The assumed discount rate and the expected return are the assumptions that generally have the most significant impact on our pension costs and liabilities. The assumed discount rate, the assumed health care cost trend rate and assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net periodic pension and postretirement benefit plan costs. When establishing our discount rate, we consider high quality corporate bond rates based on bonds available in the marketplace that are suitable for settling the obligations, changes in those rates from the prior year and the implied discount rate that is derived from matching our projected benefit disbursements with currently available high quality corporate bonds. The expected long-term rate of return on assets is utilized in calculating the expected return on plan assets component of our annual pension and postretirement plan costs. We estimate the expected return on plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater than or less than the assumed rate, that year’s annual pension or postretirement plan costs are not affected. Rather, this gain or loss reduces or increases future pension or postretirement plan costs over a period of approximately ten to twelve years. The market-related value of our plan assets represents the fair market value of the plan assets, adjusted to smooth out short-term market fluctuations over a five-year period. The use of this methodology will delay the impact of current market fluctuations on the pension expense for the period. We estimate the assumed health care cost trend rate used in determining our postretirement net expense based upon our actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual review of our participant census information as of the measurement date. | General economic and market conditions Assumed investment returns by asset class Assumed future salary increases Assumed discount rate Projected timing of future cash disbursements Health care cost experience trends Participant demographic information Actuarial mortality assumptions Impact of legislation Impact of regulation |
Impairment assessments | We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstance indicate that such carrying values may not be recoverable, and at least annually for goodwill, as required by U.S. accounting standards. The evaluation of our goodwill balances and other long-lived assets or identifiable assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to the commodity prices, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge. | General economic and market conditions Projected timing and amount of future discounted cash flows Judgment in the evaluation of relevant data |
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Non-GAAP Financial Measures
Our operations are affected by the cost of natural gas, which is passed through to our customers without markup and includes commodity price, transportation, storage, injection and withdrawal fees and settlements of financial instruments used to mitigate commodity price risk. These costs are reflected in the consolidated statements of comprehensive income as purchased gas cost. Therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Accordingly, we believe Contribution Margin, a non-GAAP financial measure, defined as operating revenues less purchased gas cost, is a more useful and relevant measure to analyze our financial performance than operating revenues. As such, the following discussion and analysis of our financial performance will reference Contribution Margin rather than operating revenues and purchased gas cost individually. Further, the term Contribution Margin is not intended to represent operating income, the most comparable GAAP financial measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.
As described further in Note 13, the enactment of the Tax Cuts and Jobs Act of 2017 (the "TCJA") required us to remeasure our deferred tax assets and liabilities at our new federal statutory income tax rate as of December 22, 2017. The remeasurement of our net deferred tax liabilities resulted in the recognition of a non-cash income tax benefit of $158.8 million for the fiscal year ended September 30, 2018. Due to the non-recurring nature of this benefit, we believe that net income and diluted net income per share before the non-cash income tax benefit provide a more relevant measure to analyze our financial performance than net income and diluted net income per share in order to allow investors to better analyze our core results and allow the information to be presented on a comparative basis to the prior year. Accordingly, the following discussion and analysis of our financial performance will reference adjusted net income and adjusted diluted earnings per share, non-GAAP measures, which are calculated as follows:
For the Fiscal Year Ended September 30 | |||||||||||
2019 | 2018 | Change | |||||||||
(In thousands, except per share data) | |||||||||||
Net income | $ | 511,406 | $ | 603,064 | $ | (91,658 | ) | ||||
TCJA non-cash income tax benefit | — | (158,782 | ) | 158,782 | |||||||
Adjusted net income | $ | 511,406 | $ | 444,282 | $ | 67,124 | |||||
Diluted net income per share | $ | 4.35 | $ | 5.43 | $ | (1.08 | ) | ||||
Diluted EPS from TCJA non-cash income tax benefit | — | (1.43 | ) | 1.43 | |||||||
Adjusted diluted net income per share | $ | 4.35 | $ | 4.00 | $ | 0.35 | |||||
RESULTS OF OPERATIONS
Overview
Atmos Energy strives to operate its businesses safely and reliably while delivering superior shareholder value. Our commitment to modernizing our natural gas distribution and transmission systems requires a significant level of capital spending. We have the ability to begin recovering a significant portion of these investments timely through rate designs and mechanisms that reduce or eliminate regulatory lag and separate the recovery of our approved rate from customer usage patterns. The execution of our capital spending program, the ability to recover these investments timely and our ability to access the capital markets to satisfy our financing needs are the primary drivers that affect our financial performance.
During fiscal 2019, we recorded net income of $511.4 million, or $4.35 per diluted share, compared to net income of $603.1 million, or $5.43 per diluted share in the prior year. After adjusting for the nonrecurring benefit recognized after implementing the TCJA in fiscal 2018, we recorded adjusted net income of $444.3 million, or $4.00 per diluted share for the year ended September 30, 2018.
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The following table details our consolidated net income by segment during the last three fiscal years:
For the Fiscal Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Distribution segment | $ | 328,814 | $ | 442,966 | $ | 268,369 | |||||
Pipeline and storage segment | 182,592 | 160,098 | 114,342 | ||||||||
Net income from continuing operations | 511,406 | 603,064 | 382,711 | ||||||||
Net income from discontinued operations | — | — | 13,710 | ||||||||
Net income | $ | 511,406 | $ | 603,064 | $ | 396,421 | |||||
The year-over-year increase in adjusted net income of $67.1 million, or 15 percent, largely reflects positive rate outcomes driven by safety and reliability spending, customer growth in our distribution business, positive Contribution Margin in our pipeline and storage business primarily due to positive supply and demand dynamics affecting the Permian Basin due to wider spreads and the impact of the TCJA on our effective income tax rate. During the year ended September 30, 2019, we implemented ratemaking regulatory actions which resulted in an increase in annual operating income of $116.7 million and had nine ratemaking efforts in progress at September 30, 2019, seeking a total increase in annual operating income of $81.2 million.
Capital expenditures for fiscal 2019 increased 15 percent period-over-period, to $1.7 billion. Over 80 percent was invested to improve the safety and reliability of our distribution and transmission systems, with a significant portion of this investment incurred under regulatory mechanisms that reduce regulatory lag to six months or less. We funded a portion of our current-year capital expenditures program through operating cash flows of $968.8 million. Additionally, we completed over $2 billion in external financing during the year ended September 30, 2019 with the issuance of $1.1 billion in 30-year senior notes and over $1.0 billion of common stock, of which approximately $470 million was allocated to forward sale agreements which have not yet been settled. The net proceeds from these issuances, together with available cash, were used to repay at maturity our $450 million 8.5% unsecured senior notes, to repay short-term debt under our commercial paper program, to fund capital spending and for general corporate purposes.
Additionally, on October 2, 2019, we completed a public offering of $300 million of 2.625% senior notes due 2029 and $500 million of 3.375% senior notes due 2049. We received net proceeds from the offering, after underwriting discount and estimated offering expenses of approximately $791.6 million, that were used for general corporate purposes, including the repayment of working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 2.72% and 3.42% after giving effect to the offering costs.
As a result of the continued contribution and stability of our earnings, cash flows and capital structure, our Board of Directors increased the quarterly dividend by 9.5% percent for fiscal 2020.
Distribution Segment
The distribution segment is primarily comprised of our regulated natural gas distribution and related sales operations in eight states. The primary factors that impact the results of our distribution operations are our ability to earn our authorized rates of return, competitive factors in the energy industry and economic conditions in our service areas.
Our ability to earn our authorized rates is based primarily on our ability to improve the rate design in our various ratemaking jurisdictions to minimize regulatory lag and, ultimately, separate the recovery of our approved rates from customer usage patterns. Improving rate design is a long-term process and is further complicated by the fact that we operate in multiple rate jurisdictions. The “Ratemaking Activity” section of this Form 10-K describes our current rate strategy, progress towards implementing that strategy and recent ratemaking initiatives in more detail.
We are generally able to pass the cost of gas through to our customers without markup under purchased gas cost adjustment mechanisms; therefore, increases in the cost of gas are offset by a corresponding increase in revenues. Contribution Margin in our Texas and Mississippi service areas include franchise fees and gross receipt taxes, which are calculated as a percentage of revenue (inclusive of gas costs). Therefore, the amount of these taxes included in revenue is influenced by the cost of gas and the level of gas sales volumes. We record the associated tax expense as a component of taxes, other than income. Although changes in revenue related taxes arising from changes in gas costs affect Contribution Margin, over time the impact is offset within operating income.
Although the cost of gas typically does not have a direct impact on our Contribution Margin, higher gas costs may adversely impact our accounts receivable collections, resulting in higher bad debt expense, and may require us to increase borrowings under our credit facilities resulting in higher interest expense. In addition, higher gas costs, as well as competitive factors in the industry and general economic conditions may cause customers to conserve or, in the case of industrial consumers, to use alternative energy sources. Currently, gas cost risk has been mitigated by rate design that allows us to collect
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from our customers the gas cost portion of our bad debt expense on approximately 76 percent of our residential and commercial margins.
During fiscal 2019, we completed 22 regulatory proceedings in our distribution segment, resulting in a $67.5 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, 2019, 2018 and 2017 are presented below.
For the Fiscal Year Ended September 30 | |||||||||||||||||||
2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||
(In thousands, unless otherwise noted) | |||||||||||||||||||
Operating revenues | $ | 2,745,461 | $ | 3,003,047 | $ | 2,649,175 | $ | (257,586 | ) | $ | 353,872 | ||||||||
Purchased gas cost | 1,268,591 | 1,559,836 | 1,269,456 | (291,245 | ) | 290,380 | |||||||||||||
Contribution Margin | 1,476,870 | 1,443,211 | 1,379,719 | 33,659 | 63,492 | ||||||||||||||
Operating expenses(1) | 1,006,098 | 957,544 | 865,995 | 48,554 | 91,549 | ||||||||||||||
Operating income | 470,772 | 485,667 | 513,724 | (14,895 | ) | (28,057 | ) | ||||||||||||
Other non-operating income (expense)(1) | 6,241 | (6,649 | ) | (9,777 | ) | 12,890 | 3,128 | ||||||||||||
Interest charges | 60,031 | 65,850 | 79,789 | (5,819 | ) | (13,939 | ) | ||||||||||||
Income before income taxes | 416,982 | 413,168 | 424,158 | 3,814 | (10,990 | ) | |||||||||||||
Income tax expense | 88,168 | 107,880 | 155,789 | (19,712 | ) | (47,909 | ) | ||||||||||||
TCJA non-cash income tax benefit | — | (137,678 | ) | — | 137,678 | (137,678 | ) | ||||||||||||
Net income | $ | 328,814 | $ | 442,966 | $ | 268,369 | $ | (114,152 | ) | $ | 174,597 | ||||||||
Consolidated distribution sales volumes — MMcf | 315,476 | 300,817 | 246,825 | 14,659 | 53,992 | ||||||||||||||
Consolidated distribution transportation volumes — MMcf | 155,078 | 150,566 | 141,540 | 4,512 | 9,026 | ||||||||||||||
Total consolidated distribution throughput — MMcf | 470,554 | 451,383 | 388,365 | 19,171 | 63,018 | ||||||||||||||
Consolidated distribution average cost of gas per Mcf sold | $ | 4.02 | $ | 5.19 | $ | 5.14 | $ | (1.17 | ) | $ | 0.05 | ||||||||
(1) | In accordance with our adoption of new accounting standards, changes in income statement presentation were implemented on a retrospective basis and impacted previously issued financial statements for the fiscal years ended 2018 and 2017, as discussed in greater detail in Note 2. |
Fiscal year ended September 30, 2019 compared with fiscal year ended September 30, 2018
Income before income taxes for our distribution segment increased slightly, primarily due to a $33.7 million increase in Contribution Margin and a combined $18.7 million decrease in other non-operating expense and interest charges, partially offset by a $48.6 million increase in operating expenses. The year-to-date increase in Contribution Margin primarily reflects:
• | a $33.0 million net increase in rate adjustments, after the effect of the TCJA, primarily in our Mid-Tex, Mississippi and West Texas Divisions. |
• | a $12.8 million increase from customer growth primarily in our Mid-Tex Division. |
• | a $9.6 million decrease in revenue-related taxes primarily in our Mid-Tex Division, offset by a corresponding $9.8 million decrease in the related tax expense. |
• | a $2.3 million decrease in residential and commercial net consumption. |
Operating expenses, which include operating and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income, increased $48.6 million primarily due to:
• | a $35.9 million increase in depreciation expense and property taxes associated with increased capital investments. |
• | a $20.7 million increase in pipeline maintenance and related activities. |
• | a $13.7 million increase in employee and training costs as we have increased service-related headcount to support operations in our fastest growing service territories. |
• | a $3.5 million increase in software maintenance fees. |
• | a $24.3 million decrease in nonrecurring expenses related to the planned outage of our natural gas distribution system in Northwest Dallas in March 2018. |
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The year-over-year decrease in other non-operating expense and interest charges of $18.7 million is primarily due to increased capitalized interest and AFUDC, as well as decreases due to the adoption of new accounting standards. As discussed further in Note 2, we are now required to recognize changes in the fair value of our equity securities formerly designated as available-for-sale on our consolidated statements of comprehensive income and the components of net periodic cost other than the service cost component are included in other non-operating expense in the consolidated statements of comprehensive income. These decreases are partially offset by an increase in interest expense due to the issuance of long-term debt during fiscal 2019.
The decrease in income tax expense reflects a reduction in our effective tax rate from 26.1% to 21.1%, as a result of the TCJA.
The fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017 for our distribution segment is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2018.
The following table shows our operating income by distribution division, in order of total rate base, for the fiscal years ended September 30, 2019, 2018 and 2017. 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 | |||||||||||||||||||
2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||
(In thousands) | |||||||||||||||||||
Mid-Tex | $ | 202,050 | $ | 202,444 | $ | 233,158 | $ | (394 | ) | $ | (30,714 | ) | |||||||
Kentucky/Mid-States | 73,965 | 81,105 | 75,214 | (7,140 | ) | 5,891 | |||||||||||||
Louisiana | 70,440 | 70,609 | 69,300 | (169 | ) | 1,309 | |||||||||||||
West Texas | 44,902 | 45,494 | 46,859 | (592 | ) | (1,365 | ) | ||||||||||||
Mississippi | 46,229 | 47,237 | 38,505 | (1,008 | ) | 8,732 | |||||||||||||
Colorado-Kansas | 34,362 | 32,333 | 34,658 | 2,029 | (2,325 | ) | |||||||||||||
Other | (1,176 | ) | 6,445 | 16,030 | (7,621 | ) | (9,585 | ) | |||||||||||
Total | $ | 470,772 | $ | 485,667 | $ | 513,724 | $ | (14,895 | ) | $ | (28,057 | ) | |||||||
Pipeline and Storage Segment
Our pipeline and storage segment consists of the pipeline and storage operations of APT and our natural gas transmission operations in Louisiana. APT is one of the largest intrastate pipeline operations in Texas with a heavy concentration in the established natural gas producing areas of central, northern and eastern Texas, extending into or near the major producing areas of the Barnett Shale, the Texas Gulf Coast and the 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. 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 influences the volumes of gas transported for shippers through Texas pipeline systems and rates for such transportation.
The results of APT are also significantly impacted by the natural gas requirements of its local distribution company customers. Additionally, its operations may be impacted by the timing of when costs and expenses are incurred and when these costs and expenses are recovered through its tariffs.
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APT annually uses GRIP to recover capital costs incurred in the prior calendar year. On February 15, 2019, APT made a GRIP filing that covered changes in net investment from January 1, 2018 through December 31, 2018 with a requested increase in operating income of $49.2 million. On May 7, 2019, the RRC approved the Company's GRIP filing.
On December 21, 2016, the Louisiana Public Service Commission approved an annual increase of five percent to the demand fee charged by our natural gas transmission pipeline for each of the next 10 years, effective October 1, 2017.
Review of Financial and Operating Results
Financial and operational highlights for our pipeline and storage segment for the fiscal years ended September 30, 2019, 2018 and 2017 are presented below.
For the Fiscal Year Ended September 30 | |||||||||||||||||||
2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||
(In thousands, unless otherwise noted) | |||||||||||||||||||
Mid-Tex / Affiliate transportation revenue | $ | 369,743 | $ | 354,885 | $ | 338,850 | $ | 14,858 | $ | 16,035 | |||||||||
Third-party transportation revenue | 183,014 | 140,231 | 100,100 | 42,783 | 40,131 | ||||||||||||||
Other revenue | 14,267 | 12,597 | 18,080 | 1,670 | (5,483 | ) | |||||||||||||
Total operating revenues | 567,024 | 507,713 | 457,030 | 59,311 | 50,683 | ||||||||||||||
Total purchased gas cost | (360 | ) | 1,978 | 2,506 | (2,338 | ) | (528 | ) | |||||||||||
Contribution Margin | 567,384 | 505,735 | 454,524 | 61,649 | 51,211 | ||||||||||||||
Operating expenses | 292,098 | 263,468 | 232,620 | 28,630 | 30,848 | ||||||||||||||
Operating income | 275,286 | 242,267 | 221,904 | 33,019 | 20,363 | ||||||||||||||
Other non-operating income (expense) | 1,163 | (3,495 | ) | (1,575 | ) | 4,658 | (1,920 | ) | |||||||||||
Interest charges | 43,122 | 40,796 | 40,393 | 2,326 | 403 | ||||||||||||||
Income before income taxes | 233,327 | 197,976 | 179,936 | 35,351 | 18,040 | ||||||||||||||
Income tax expense | 50,735 | 58,982 | 65,594 | (8,247 | ) | (6,612 | ) | ||||||||||||
TCJA non-cash income tax benefit | — | (21,104 | ) | — | 21,104 | (21,104 | ) | ||||||||||||
Net income | $ | 182,592 | $ | 160,098 | $ | 114,342 | $ | 22,494 | $ | 45,756 | |||||||||
Gross pipeline transportation volumes — MMcf | 939,376 | 871,904 | 770,348 | 67,472 | 101,556 | ||||||||||||||
Consolidated pipeline transportation volumes — MMcf | 721,998 | 663,900 | 596,179 | 58,098 | 67,721 | ||||||||||||||
Fiscal year ended September 30, 2019 compared with fiscal year ended September 30, 2018
Income before income taxes for our pipeline and storage segment increased 18 percent, primarily due to a $61.6 million increase in Contribution Margin, partially offset by a $28.6 million increase in operating expenses. The increase in Contribution Margin primarily reflects:
• | a $46.5 million net increase in rate adjustments, after the effect of the TCJA, primarily from the approved GRIP filings approved in May 2018 and May 2019. The increase in rates was driven primarily by increased safety and reliability spending. |
• | a net increase of $12.2 million primarily from positive supply and demand dynamics affecting the Permian Basin, due to wider spreads. |
The increase in operating expenses is primarily due to higher depreciation expense of $11.6 million associated with increased capital investments and higher system maintenance expense of $15.3 million primarily due to spending on hydro testing and in-line inspections.
The decrease in income tax expense primarily reflects a reduction in our effective tax rate from 29.8% to 21.7%, as a result of the TCJA.
The fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017 for our pipeline and storage segment is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2018.
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.
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As more fully described in Note 16, 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 fully exited the nonregulated natural gas marketing business. Accordingly, a gain on sale from discontinued operations for $2.7 million was recorded and net income of $11.0 million for AEM is reported as discontinued operations for the year ended September 30, 2017.
The fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017 for our natural gas marketing segment is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2018.
LIQUIDITY AND CAPITAL RESOURCES
The liquidity required to fund our working capital, capital expenditures and other cash needs is provided from a combination of internally generated cash flows and external debt and equity financing. External debt financing is provided primarily through the issuance of long-term debt, a $1.5 billion commercial paper program and three committed revolving credit facilities with a total availability from third-party lenders of approximately $1.5 billion. The commercial paper program and credit facilities provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company's desired capital structure with an equity-to-total-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Additionally, we have various uncommitted trade credit lines with our gas suppliers that we utilize to purchase natural gas on a monthly basis. The liquidity provided by these sources is expected to be sufficient to fund the Company's working capital needs and capital expenditures program for fiscal year 2020 and beyond.
To support our capital market activities, we filed a registration statement with the SEC on November 13, 2018 that permits us to issue a total of $3.0 billion in common stock and/or debt securities. The registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At September 30, 2019, approximately $1.3 billion of securities remained available for issuance under the shelf registration statement.
On November 19, 2018, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million (including shares of common stock that may be sold pursuant to forward sale agreements entered into concurrently with the ATM equity sales program). At September 30, 2019, approximately $75 million remained available under the ATM equity sales program.
For the year ended September 30, 2019, we completed over $2 billion of long-term debt and equity financing. During fiscal 2019, we executed forward sales with various forward sellers who borrowed and sold 6,813,135 shares of our common stock for initial aggregate proceeds of approximately $673 million.
The following table summarizes the remaining availability under our various forward sales as of September 30, 2019:
Issue Quarter | Shares Available | Net Proceeds Available (In thousands) | Maturity | Forward Price | |||||
December 31, 2018 | 485,189 | $ | 44,342 | 3/31/2020 | $ | 91.39 | |||
March 31, 2019 | 1,670,509 | 158,348 | 3/31/2020 | $ | 94.79 | ||||
June 30, 2019 | 1,050,563 | 106,034 | 9/30/2020 | $ | 100.93 | ||||
September 30, 2019 | 1,423,599 | 154,631 | 9/30/2020 | $ | 108.62 | ||||
Total | 4,629,860 | $ | 463,355 | ||||||
The following table presents our capitalization as of September 30, 2019 and 2018:
September 30 | |||||||||||||
2019 | 2018 | ||||||||||||
(In thousands, except percentages) | |||||||||||||
Short-term debt | $ | 464,915 | 4.8 | % | $ | 575,780 | 6.8 | % | |||||
Long-term debt | 3,529,452 | 36.2 | % | 3,068,665 | 36.5 | % | |||||||
Shareholders’ equity | 5,750,223 | 59.0 | % | 4,769,951 | 56.7 | % | |||||||
Total capitalization, including short-term debt | $ | 9,744,590 | 100.0 | % | $ | 8,414,396 | 100.0 | % | |||||
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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, 2019, 2018 and 2017 are presented below.
For the Fiscal Year Ended September 30 | |||||||||||||||||||
2019 | 2018 | 2017 | 2019 vs. 2018 | 2018 vs. 2017 | |||||||||||||||
(In thousands) | |||||||||||||||||||
Total cash provided by (used in) | |||||||||||||||||||
Operating activities | $ | 968,769 | $ | 1,124,662 | $ | 867,090 | $ | (155,893 | ) | $ | 257,572 | ||||||||
Investing activities | (1,683,660 | ) | (1,463,566 | ) | (1,056,306 | ) | (220,094 | ) | (407,260 | ) | |||||||||
Financing activities | 725,670 | 326,266 | 168,091 | 399,404 | 158,175 | ||||||||||||||
Change in cash and cash equivalents | 10,779 | (12,638 | ) | (21,125 | ) | 23,417 | 8,487 | ||||||||||||
Cash and cash equivalents at beginning of period | 13,771 | 26,409 | 47,534 | (12,638 | ) | (21,125 | ) | ||||||||||||
Cash and cash equivalents at end of period | $ | 24,550 | $ | 13,771 | $ | 26,409 | $ | 10,779 | $ | (12,638 | ) | ||||||||
Cash flows for the fiscal year ended September 30, 2018 compared with fiscal year ended September 30, 2017 is described in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the fiscal year ended September 30, 2018.
Cash flows from operating activities
For the fiscal year ended September 30, 2019, we generated cash flow from operating activities of $968.8 million compared with $1,124.7 million in the prior year. The year-over-year decrease is primarily attributable to the change in net income and working capital changes, particularly in our distribution segment resulting from the timing of payments for natural gas purchases and deferred gas cost recoveries.
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 84 percent of our capital spending has been committed to improving the safety and reliability of our system.
We allocate our capital spending among our service areas using risk management models and subject matter experts to identify, assess and develop a plan of action to address our highest risk facilities. We have regulatory mechanisms in most of our service areas that provide the opportunity to include approved capital costs in rate base on a periodic basis without being required to file a rate case. These mechanisms permit us a reasonable opportunity to earn a fair return on our investment without compromising safety or reliability.
For the fiscal year ended September 30, 2019, we had $1.7 billion in capital expenditures compared with $1.5 billion for the fiscal year ended September 30, 2018. Capital spending increased by $225.9 million, or 15%, as a result of planned increases in our distribution segment to repair and replace vintage pipe and increases in spending in our pipeline and storage segment to improve the reliability of gas service to our local distribution company customers.
Cash flows from financing activities
Our financing activities provided $725.7 million and $326.3 million in cash for fiscal years 2019 and 2018. Our significant financing activities for the fiscal years ended September 30, 2019 and 2018 are summarized as follows:
2019
During the fiscal year ended September 30, 2019, we received $1.7 billion in net proceeds from the issuance and repayment of long-term debt and issuance of equity. This activity is summarized below:
• | In October 2018, we completed the public offering of $600 million of 30-year 4.30% senior notes. The net proceeds of $590.6 million were used to repay working capital borrowings pursuant to our commercial paper program. |
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• | In November 2018, we sold 5,390,836 shares of common stock for $500 million. The net proceeds of $494.1 million were used to fund our capital expenditure program and for general corporate purposes. |
• | In March 2019, we completed the public offering of $450 million of 30-year 4.125% senior notes. The net proceeds of $443.4 million, together with available cash, were used to repay at maturity our $450 million 8.50% 10-year unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps for $90.1 million. |
• | In May and August 2019, we settled forward sale agreements for 2,183,275 shares of common stock for net proceeds of approximately $200 million. |
• | In September 2019, we repaid our $125 million floating rate term loan at its maturity. |
Additionally, cash dividends increased due to an 8.2 percent increase in our dividend rate and an increase in shares outstanding.
2018
During the fiscal year ended September 30, 2018, we used $395.1 million in net proceeds from equity financing to reduce short-term debt, to support our capital spending and for other general corporate purposes.
The following table shows the number of shares issued for the fiscal years ended September 30, 2019, 2018 and 2017:
For the Fiscal Year Ended September 30 | ||||||||
2019 | 2018 | 2017 | ||||||
Shares issued: | ||||||||
Direct Stock Purchase Plan | 110,063 | 131,213 | 112,592 | |||||
Retirement Savings Plan | 81,456 | 94,081 | 228,326 | |||||
1998 Long-Term Incentive Plan (LTIP) | 299,612 | 385,351 | 529,662 | |||||
Equity Offering(1) | 7,574,111 | 4,558,404 | — | |||||
At-the-Market (ATM) Equity Sales Program(1) | — | — | 1,303,494 | |||||
Total shares issued | 8,065,242 | 5,169,049 | 2,174,074 | |||||
(1) | Share amounts do not include shares issued under forward sale agreements until the shares have been settled. |
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 operating cash flow less dividends to debt. In addition, the rating agencies consider qualitative factors such as consistency of our earnings over time, the risks associated with our business 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). On December 14, 2018, Moody's affirmed our debt ratings and changed their outlook from stable to positive, citing improvements to our regulatory construct that reduce investment recovery lag and our balanced fiscal policy. As of September 30, 2019, S&P 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.
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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, 2019. Our debt covenants are described in Note 6 to the consolidated financial statements.
Contractual Obligations and Commercial Commitments
The following table provides information about contractual obligations and commercial commitments at September 30, 2019.
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) | $ | 3,560,000 | $ | — | $ | — | $ | — | $ | 3,560,000 | |||||||||
Short-term debt(1) | 464,915 | 464,915 | — | — | — | ||||||||||||||
Interest charges(2) | 3,392,249 | 155,742 | 311,484 | 311,484 | 2,613,539 | ||||||||||||||
Capital lease obligations(3) | 5,608 | 243 | 501 | 521 | 4,343 | ||||||||||||||
Operating leases(4) | 200,136 | 21,017 | 39,786 | 33,789 | 105,544 | ||||||||||||||
Financial instrument obligations(5) | 5,801 | 4,552 | 1,249 | — | — | ||||||||||||||
Pension and postretirement benefit plan contributions(6) | 308,033 | 44,994 | 61,954 | 48,900 | 152,185 | ||||||||||||||
Uncertain tax positions (7) | 27,716 | — | 27,716 | — | — | ||||||||||||||
Total contractual obligations | $ | 7,964,458 | $ | 691,463 | $ | 442,690 | $ | 394,694 | $ | 6,435,611 | |||||||||
(1) | See Note 6 to the consolidated financial statements. |
(2) | Interest charges were calculated using the effective rate for each debt issuance. |
(3) | Capital lease payments shown above include interest totaling $3.0 million. See Note 11 to the consolidated financial statements. |
(4) | Future minimum lease payments do not include amounts for fleet leases and other de minimis items that can be renewed beyond the initial lease term. The Company anticipates renewing the leases beyond the initial term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and therefore are not included above. Expected payments for these leases are $17.6 million in 2020, $18.0 million in 2021, $11.8 million in 2022, $8.5 million in 2023, $5.4 million in 2024 and $2.7 million thereafter. See Note 11 to the consolidated financial statements. |
(5) | Represents liabilities for natural gas commodity financial instruments that were valued as of September 30, 2019. The ultimate settlement amounts of these remaining liabilities are unknown because they are subject to continuing market risk until the financial instruments are settled. |
(6) | Represents expected contributions to our defined benefit and postretirement benefit plans, which are discussed in Note 8 to the consolidated financial statements. Based upon current market conditions, the current funded position of the plans and the funding requirements under the PPA, we do not anticipate minimum required contributions for the foreseeable future. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels. |
(7) | Represents liabilities associated with uncertain tax positions claimed or expected to be claimed on tax returns. The amount does not include interest and penalties that may be applied to these positions. |
We maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of individual contracts. Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at market and fixed prices. At September 30, 2019, we were committed to purchase 40.1 Bcf within one year and 1.6 Bcf within two to three years under indexed contracts.
The change in deferred taxes related to our cost of service ratemaking (referred to as excess deferred taxes) was reclassified into a regulatory liability and will be returned to ratepayers in accordance with regulatory requirements. At September 30, 2019, this liability totaled $726.3 million. We received approval from regulators to return excess deferred taxes in most of our jurisdictions in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to
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51 years. In our remaining jurisdictions, the treatment of the effects of the TCJA in rates is being addressed in ongoing or will be addressed in future regulatory proceedings. See Note 13 for further information.
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. In the past we managed interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
We record our financial instruments as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. Substantially all of our financial instruments are valued using external market quotes and indices.
The following table shows the components of the change in fair value of our financial instruments for the fiscal year ended September 30, 2019 (in thousands):
Fair value of contracts at September 30, 2018 | $ | (55,218 | ) |
Contracts realized/settled | 97,288 | ||
Fair value of new contracts | (300 | ) | |
Other changes in value | (45,760 | ) | |
Fair value of contracts at September 30, 2019 | (3,990 | ) | |
Netting of cash collateral | — | ||
Cash collateral and fair value of contracts at September 30, 2019 | $ | (3,990 | ) |
The fair value of our financial instruments at September 30, 2019, is presented below by time period and fair value source:
Fair Value of Contracts at September 30, 2019 | |||||||||||||||||||
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 | $ | (2,966 | ) | $ | (1,024 | ) | $ | — | $ | — | $ | (3,990 | ) | ||||||
Prices based on models and other valuation methods | — | — | — | — | — | ||||||||||||||
Total Fair Value | $ | (2,966 | ) | $ | (1,024 | ) | $ | — | $ | — | $ | (3,990 | ) | ||||||
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.
ITEM 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
We are exposed to risks associated with commodity prices and interest rates. Commodity price risk is the potential loss that we may incur as a result of changes in the fair value of a particular instrument or commodity. Interest-rate risk is the potential increased cost we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. Additionally, interest-rate risk could affect our ability to issue cost effective equity instruments.
We conduct risk management activities in our distribution and pipeline and storage segments. In our distribution segment, we use a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season. Our risk management activities and related accounting treatment are described in further detail in Note 14 to the consolidated financial statements. Additionally, our earnings are affected by changes in short-term interest rates as a result of our issuance of short-term commercial paper and our other short-term borrowings.
Commodity Price Risk
We purchase natural gas for our distribution operations. Substantially all of the costs of gas purchased for distribution operations are recovered from our customers through purchased gas cost adjustment mechanisms. Therefore, our distribution operations have limited commodity price risk exposure.
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Interest Rate Risk
Our earnings are exposed to changes in short-term interest rates associated with our short-term commercial paper program and other short-term borrowings. We use a sensitivity analysis to estimate our short-term interest rate risk. For purposes of this analysis, we estimate our short-term interest rate risk as the difference between our actual interest expense for the period and estimated interest expense for the period assuming a hypothetical average one percent increase in the interest rates associated with our short-term borrowings. Had interest rates associated with our short-term borrowings increased by an average of one percent, our interest expense would not have been materially increased during 2019.
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ITEM 8. | Financial Statements and Supplementary Data. |
Index to financial statements and financial statement schedule:
Page | |
Financial statements and supplementary data: | |
Financial statement schedule for the years ended September 30, 2019, 2018 and 2017 | |
All other financial statement schedules are omitted because the required information is not present, or not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements and accompanying notes thereto.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atmos Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Atmos Energy Corporation (the “Company“) as of September 30, 2019 and 2018, the related consolidated statements of comprehensive income, shareholders‘ equity, and cash flows, for each of the three years in the period ended September 30, 2019, and the related notes and financial statement schedule listed in the Index at Item 8 (collectively referred to as the "financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2019, in conformity with US generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated November 12, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Determination of Capital Costs | |
Description of the Matter | As more fully described in Note 2 to the financial statements, the Company capitalizes the direct and indirect costs of construction. Once a project is completed, it is placed into service and included in the Company’s rate base. Costs of maintenance and repairs that are not included in the Company’s rate base are charged to expense. For the year ended September 30, 2019, the Company capitalized approximately $1.8 billion of construction-related costs for regulated property, plant and equipment. Auditing management’s identification of capital additions and maintenance and repairs expense involved significant effort and auditor judgment. These amounts have both a higher magnitude and a higher likelihood of potential misstatement. As a cost-based, rate-regulated entity, the rates charged to customers are designed to recover the entity’s costs and provide a rate of return on rate base. Net property, plant and equipment is the most significant component of the Company’s rate base. As a result, inappropriate capitalization of costs could affect the amount, timing and classification of revenues and expenses in the consolidated financial statements. |
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How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over the initial determination and approval of expenditures for either capital additions or maintenance and repair. For example, we selected a sample of projects initiated during the year to evaluate the effectiveness of management’s review controls to determine the proper categorization of project expenditures as either capitalizable costs or current-period expense. Our audit procedures included, among others, testing a sample of projects initiated during the year, including the evaluation of the nature of the project, with Company personnel outside of accounting and financial reporting. For example, we evaluated project setup through inspection of each project’s description for compliance with the Company’s capitalization policy as described in Note 2 and a series of inquiries of the project approver to understand how they assessed whether projects should be treated as capital or expense. Other audit procedures included evaluating whether the descriptions and amounts included on third-party invoices either support or contradict the project classification as capital, evaluating the appropriateness of individuals capitalizing direct labor charges to projects by assessing the relevance of their job function to the capital project, and recalculating other overhead costs capitalized to projects. |
/s/ Ernst & Young LLP
We have served as the Company‘s auditor since 1983.
Dallas, Texas
November 12, 2019
38
ATMOS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands, except share data) | |||||||
ASSETS | |||||||
Property, plant and equipment | $ | 13,758,899 | $ | 12,217,648 | |||
Construction in progress | 421,694 | 349,725 | |||||
14,180,593 | 12,567,373 | ||||||
Less accumulated depreciation and amortization | 2,392,924 | 2,196,226 | |||||
Net property, plant and equipment | 11,787,669 | 10,371,147 | |||||
Current assets | |||||||
Cash and cash equivalents | 24,550 | 13,771 | |||||
Accounts receivable, less allowance for doubtful accounts of $15,899 in 2019 and $14,795 in 2018 | 230,571 | 253,295 | |||||
Gas stored underground | 130,138 | 165,732 | |||||
Other current assets | 72,772 | 46,055 | |||||
Total current assets | 458,031 | 478,853 | |||||
Goodwill | 730,706 | 730,419 | |||||
Deferred charges and other assets | 391,213 | 294,018 | |||||
$ | 13,367,619 | $ | 11,874,437 | ||||
CAPITALIZATION AND LIABILITIES | |||||||
Shareholders’ equity | |||||||
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: 2019 — 119,338,925 shares, 2018 — 111,273,683 shares | $ | 597 | $ | 556 | |||
Additional paid-in capital | 3,712,194 | 2,974,926 | |||||
Accumulated other comprehensive loss | (114,583 | ) | (83,647 | ) | |||
Retained earnings | 2,152,015 | 1,878,116 | |||||
Shareholders’ equity | 5,750,223 | 4,769,951 | |||||
Long-term debt | 3,529,452 | 2,493,665 | |||||
Total capitalization | 9,279,675 | 7,263,616 | |||||
Commitments and contingencies (See Note 12) | |||||||
Current liabilities | |||||||
Accounts payable and accrued liabilities | 265,024 | 217,283 | |||||
Other current liabilities | 479,501 | 547,068 | |||||
Short-term debt | 464,915 | 575,780 | |||||
Current maturities of long-term debt | — | 575,000 | |||||
Total current liabilities | 1,209,440 | 1,915,131 | |||||
Deferred income taxes | 1,300,015 | 1,154,067 | |||||
Regulatory excess deferred taxes (See Note 13) | 705,101 | 739,670 | |||||
Regulatory cost of removal obligation | 473,172 | 466,405 | |||||
Pension and postretirement liabilities | 279,083 | 177,520 | |||||
Deferred credits and other liabilities | 121,133 | 158,028 | |||||
$ | 13,367,619 | $ | 11,874,437 | ||||
See accompanying notes to consolidated financial statements.
39
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands, except per share data) | |||||||||||
Operating revenues | |||||||||||
Distribution segment | $ | 2,745,461 | $ | 3,003,047 | $ | 2,649,175 | |||||
Pipeline and storage segment | 567,024 | 507,713 | 457,030 | ||||||||
Intersegment eliminations | (410,637 | ) | (395,214 | ) | (346,470 | ) | |||||
Total operating revenues | 2,901,848 | 3,115,546 | 2,759,735 | ||||||||
Purchased gas cost | |||||||||||
Distribution segment | 1,268,591 | 1,559,836 | 1,269,456 | ||||||||
Pipeline and storage segment | (360 | ) | 1,978 | 2,506 | |||||||
Intersegment eliminations | (409,394 | ) | (393,966 | ) | (346,426 | ) | |||||
Total purchased gas cost | 858,837 | 1,167,848 | 925,536 | ||||||||
Operation and maintenance expense | 630,308 | 594,795 | 538,716 | ||||||||
Depreciation and amortization expense | 391,456 | 361,083 | 319,448 | ||||||||
Taxes, other than income | 275,189 | 263,886 | 240,407 | ||||||||
Operating income | 746,058 | 727,934 | 735,628 | ||||||||
Other non-operating income (expense) | 7,404 | (10,144 | ) | (11,352 | ) | ||||||
Interest charges | 103,153 | 106,646 | 120,182 | ||||||||
Income from continuing operations before income taxes | 650,309 | 611,144 | 604,094 | ||||||||
Income tax expense | 138,903 | 8,080 | 221,383 | ||||||||
Income from continuing operations | 511,406 | 603,064 | 382,711 | ||||||||
Income from discontinued operations, net of tax ($0, $0 and $6,841) | — | — | 10,994 | ||||||||
Gain on sale of discontinued operations, net of tax ($0, $0 and $10,215) | — | — | 2,716 | ||||||||
Net Income | $ | 511,406 | $ | 603,064 | $ | 396,421 | |||||
Basic net income per share | |||||||||||
Income per share from continuing operations | $ | 4.36 | $ | 5.43 | $ | 3.60 | |||||
Income per share from discontinued operations | — | — | 0.13 | ||||||||
Net income per share - basic | $ | 4.36 | $ | 5.43 | $ | 3.73 | |||||
Diluted net income per share | |||||||||||
Income per share from continuing operations | $ | 4.35 | $ | 5.43 | $ | 3.60 | |||||
Income per share from discontinued operations | — | — | 0.13 | ||||||||
Net income per share - diluted | $ | 4.35 | $ | 5.43 | $ | 3.73 | |||||
Weighted average shares outstanding: | |||||||||||
Basic | 117,200 | 111,012 | 106,100 | ||||||||
Diluted | 117,461 | 111,012 | 106,100 | ||||||||
Net income | $ | 511,406 | $ | 603,064 | $ | 396,421 | |||||
Other comprehensive income (loss), net of tax | |||||||||||
Net unrealized holding gains (losses) on available-for-sale securities, net of tax of $64, $(146) and $1,473 (See Note 2) | 218 | (395 | ) | 2,564 | |||||||
Cash flow hedges: | |||||||||||
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $(6,782), $13,017 and $43,238 | (22,944 | ) | 44,936 | 75,222 | |||||||
Net unrealized gains on commodity cash flow hedges, net of tax of $0, $0 and $3,183 | — | — | 4,982 | ||||||||
Total other comprehensive income (loss) | (22,726 | ) | 44,541 | 82,768 | |||||||
Total comprehensive income | $ | 488,680 | $ | 647,605 | $ | 479,189 | |||||
See accompanying notes to consolidated financial statements.
40
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
Common stock | Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Total | ||||||||||||||||||
Number of Shares | Stated Value | |||||||||||||||||||||
(In thousands, except share and per share data) | ||||||||||||||||||||||
Balance, September 30, 2016 | 103,930,560 | $ | 520 | $ | 2,388,027 | $ | (188,022 | ) | $ | 1,262,534 | $ | 3,463,059 | ||||||||||
Net income | — | — | — | — | 396,421 | 396,421 | ||||||||||||||||
Other comprehensive income | — | — | — | 82,768 | — | 82,768 | ||||||||||||||||
Cash dividends ($1.80 per share) | — | — | — | — | (191,931 | ) | (191,931 | ) | ||||||||||||||
Common stock issued: | ||||||||||||||||||||||
Public offering | 1,303,494 | 6 | 98,749 | — | — | 98,755 | ||||||||||||||||
Direct stock purchase plan | 112,592 | 1 | 8,970 | — | — | 8,971 | ||||||||||||||||
Retirement savings plan | 228,326 | 1 | 17,551 | — | — | 17,552 | ||||||||||||||||
1998 Long-term incentive plan | 529,662 | 3 | 3,698 | — | — | 3,701 | ||||||||||||||||
Employee stock-based compensation | — | — | 19,370 | — | — | 19,370 | ||||||||||||||||
Balance, September 30, 2017 | 106,104,634 | 531 | 2,536,365 | (105,254 | ) | 1,467,024 | 3,898,666 | |||||||||||||||
Net income | — | — | — | — | 603,064 | 603,064 | ||||||||||||||||
Other comprehensive income | — | — | — | 44,541 | — | 44,541 | ||||||||||||||||
Cash dividends ($1.94 per share) | — | — | — | — | (214,906 | ) | (214,906 | ) | ||||||||||||||
Cumulative effect of accounting change | — | — | — | (22,934 | ) | 22,934 | — | |||||||||||||||
Common stock issued: | ||||||||||||||||||||||
Public offering | 4,558,404 | 22 | 395,070 | — | — | 395,092 | ||||||||||||||||
Direct stock purchase plan | 131,213 | 1 | 11,322 | — | — | 11,323 | ||||||||||||||||
Retirement savings plan | 94,081 | — | 8,240 | — | — | 8,240 | ||||||||||||||||
1998 Long-term incentive plan | 385,351 | 2 | 3,469 | — | — | 3,471 | ||||||||||||||||
Employee stock-based compensation | — | — | 20,460 | — | — | 20,460 | ||||||||||||||||
Balance, September 30, 2018 | 111,273,683 | 556 | 2,974,926 | (83,647 | ) | 1,878,116 | 4,769,951 | |||||||||||||||
Net income | — | — | — | — | 511,406 | 511,406 | ||||||||||||||||
Other comprehensive loss | — | — | — | (22,726 | ) | — | (22,726 | ) | ||||||||||||||
Cash dividends ($2.10 per share) | — | — | — | — | (245,717 | ) | (245,717 | ) | ||||||||||||||
Cumulative effect of accounting change (1) | — | — | — | (8,210 | ) | 8,210 | — | |||||||||||||||
Common stock issued: | ||||||||||||||||||||||
Public offering | 7,574,111 | 38 | 694,065 | — | — | 694,103 | ||||||||||||||||
Direct stock purchase plan | 110,063 | 1 | 11,070 | — | — | 11,071 | ||||||||||||||||
Retirement savings plan | 81,456 | — | 8,252 | — | — | 8,252 | ||||||||||||||||
1998 Long-term incentive plan | 299,612 | 2 | 2,946 | — | — | 2,948 | ||||||||||||||||
Employee stock-based compensation | — | — | 20,935 | — | — | 20,935 | ||||||||||||||||
Balance, September 30, 2019 | 119,338,925 | $ | 597 | $ | 3,712,194 | $ | (114,583 | ) | $ | 2,152,015 | $ | 5,750,223 | ||||||||||
(1) | See Note 2, "Recent Accounting Pronouncements" for additional information. |
See accompanying notes to consolidated financial statements.
41
ATMOS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
Net income | $ | 511,406 | $ | 603,064 | $ | 396,421 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and amortization | 391,456 | 361,083 | 319,633 | ||||||||
Deferred income taxes | 132,004 | 158,271 | 227,183 | ||||||||
One-time income tax benefit | — | (158,782 | ) | — | |||||||
Gain on sale of discontinued operations | — | — | (12,931 | ) | |||||||
Discontinued cash flow hedging for commodity contracts | — | — | (10,579 | ) | |||||||
Stock-based compensation | 11,121 | 12,863 | 14,064 | ||||||||
Amortization of debt issuance costs | 9,464 | 7,865 | 6,469 | ||||||||
Equity component of AFUDC | (11,165 | ) | — | — | |||||||
Other | 1,169 | 5,437 | 97 | ||||||||
Changes in assets and liabilities: | |||||||||||
(Increase) decrease in accounts receivable | 18,724 | (29,208 | ) | (58,696 | ) | ||||||
(Increase) decrease in gas stored underground | 35,594 | 18,921 | (35,126 | ) | |||||||
(Increase) decrease in other current assets | (26,590 | ) | 60,424 | 9,991 | |||||||
(Increase) decrease in deferred charges and other assets | (58,403 | ) | (10,049 | ) | 102,254 | ||||||
Increase (decrease) in accounts payable and accrued liabilities | 9,908 | (11,857 | ) | 53,017 | |||||||
Increase (decrease) in other current liabilities | (103,895 | ) | 74,707 | (78,651 | ) | ||||||
Increase (decrease) in deferred credits and other liabilities | 47,976 | 31,923 | (66,056 | ) | |||||||
Net cash provided by operating activities | 968,769 | 1,124,662 | 867,090 | ||||||||
CASH FLOWS USED IN INVESTING ACTIVITIES | |||||||||||
Capital expenditures | (1,693,477 | ) | (1,467,591 | ) | (1,137,089 | ) | |||||
Acquisition | — | — | (86,128 | ) | |||||||
Proceeds from the sale of discontinued operations | 4,000 | 3,000 | 140,253 | ||||||||
Purchases of debt and equity securities | (29,153 | ) | (46,401 | ) | (53,597 | ) | |||||
Proceeds from sale of debt and equity securities | 6,070 | 22,360 | 31,792 | ||||||||
Maturities of debt securities | 20,299 | 15,716 | 9,332 | ||||||||
Use tax refund | — | 790 | 29,790 | ||||||||
Other, net | 8,601 | 8,560 | 9,341 | ||||||||
Net cash used in investing activities | (1,683,660 | ) | (1,463,566 | ) | (1,056,306 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
Net increase (decrease) in short-term debt | (110,865 | ) | 128,035 | (382,066 | ) | ||||||
Proceeds from issuance of long-term debt, net of premium/discount | 1,045,221 | — | 884,911 | ||||||||
Net proceeds from equity offering | 694,103 | 395,092 | 98,755 | ||||||||
Issuance of common stock through stock purchase and employee retirement plans | 19,323 | 19,563 | 26,523 | ||||||||
Settlement of interest rate swaps | (90,141 | ) | — | (36,996 | ) | ||||||
Interest rate swaps cash collateral | — | — | 25,670 | ||||||||
Repayment of long-term debt | (575,000 | ) | — | (250,000 | ) | ||||||
Cash dividends paid | (245,717 | ) | (214,906 | ) | (191,931 | ) | |||||
Debt issuance costs | (11,254 | ) | — | (6,775 | ) | ||||||
Other | — | (1,518 | ) | — | |||||||
Net cash provided by financing activities | 725,670 | 326,266 | 168,091 | ||||||||
Net increase (decrease) in cash and cash equivalents | 10,779 | (12,638 | ) | (21,125 | ) | ||||||
Cash and cash equivalents at beginning of year | 13,771 | 26,409 | 47,534 | ||||||||
Cash and cash equivalents at end of year | $ | 24,550 | $ | 13,771 | $ | 26,409 | |||||
See accompanying notes to consolidated financial statements.
42
ATMOS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and its subsidiaries are engaged in the regulated natural gas distribution and pipeline and storage businesses. Through our distribution business, we deliver natural gas through sales and transportation arrangements to over three million residential, commercial, public-authority and industrial customers through our six regulated distribution divisions in the service areas described below:
Division | Service Area | |
Atmos Energy Colorado-Kansas Division | Colorado, Kansas | |
Atmos Energy Kentucky/Mid-States Division | Kentucky, Tennessee, Virginia(1) | |
Atmos Energy Louisiana Division | Louisiana | |
Atmos Energy Mid-Tex Division | Texas, including the Dallas/Fort Worth metropolitan area | |
Atmos Energy Mississippi Division | Mississippi | |
Atmos Energy West Texas Division | West Texas | |
(1) | Denotes location where we have more limited service areas. |
In addition, we transport natural gas for others through our distribution system. Our distribution business is subject to federal and state regulation and/or regulation by local authorities in each of the states in which our distribution divisions operate. Our corporate headquarters and shared-services function are located in Dallas, Texas, and our customer support centers are located in Amarillo and Waco, Texas.
Our pipeline and storage business, which is also subject to federal and state regulation, consists of the the pipeline and storage operations of our Atmos Pipeline–Texas (APT) Division and our natural gas transmission business in Louisiana. The APT division provides transportation and storage services to our Mid-Tex Division, other third-party local distribution companies, industrial and electric generation customers, as well as marketers and producers. As part of its pipeline operations, APT manages five underground storage facilities in Texas. We also provide ancillary services customary to the pipeline industry including parking arrangements, lending and sales of inventory on hand. 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.
2. Summary of Significant Accounting Policies
Principles of consolidation — The accompanying consolidated financial statements include the accounts of Atmos Energy Corporation and its wholly-owned subsidiaries. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process.
Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The most significant estimates include the allowance for doubtful accounts, unbilled revenues, contingency accruals, pension and postretirement obligations, deferred income taxes, impairment of long-lived assets, risk management and trading activities, fair value measurements and the valuation of goodwill and other long-lived assets. Actual results could differ from those estimates.
Regulation — Our distribution and pipeline and storage operations are subject to regulation with respect to rates, service, maintenance of accounting records and various other matters by the respective regulatory authorities in the states in which we operate. Our accounting policies recognize the financial effects of the ratemaking and accounting practices and policies of the various regulatory commissions. Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. The amounts to be recovered or recognized are based upon historical experience and our understanding of the regulations. Further, regulation may impact the period in which revenues or expenses are recognized.
43
Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and our regulatory liabilities are recorded as a component of other current liabilities and deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the long-term portion of regulatory excess deferred taxes and regulatory cost of removal obligation are reported separately. Significant regulatory assets and liabilities as of September 30, 2019 and 2018 included the following:
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Regulatory assets: | |||||||
Pension and postretirement benefit costs | $ | 86,089 | $ | 6,496 | |||
Infrastructure mechanisms(1) | 131,894 | 96,739 | |||||
Deferred gas costs | 23,766 | 1,927 | |||||
Recoverable loss on reacquired debt | 6,551 | 8,702 | |||||
Deferred pipeline record collection costs | 26,418 | 20,467 | |||||
Rate case costs | 1,346 | 2,741 | |||||
Other | 8,483 | 6,739 | |||||
$ | 284,547 | $ | 143,811 | ||||
Regulatory liabilities: | |||||||
Regulatory excess deferred taxes(2) | $ | 726,307 | $ | 744,895 | |||
Regulatory cost of service reserve | 5,238 | 22,508 | |||||
Regulatory cost of removal obligation | 528,893 | 522,175 | |||||
Deferred gas costs | 14,112 | 94,705 | |||||
Asset retirement obligation | 17,054 | 12,887 | |||||
APT annual adjustment mechanism | 78,402 | 35,228 | |||||
Pension and postretirement benefit costs | — | 69,113 | |||||
Other | 16,120 | 9,486 | |||||
$ | 1,386,126 | $ | 1,510,997 | ||||
(1) | Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all eligible expenses associated with capital expenditures incurred pursuant to these rules, including the recording of interest on the deferred expenses until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recovered through base rates. |
(2) | The TCJA resulted in the remeasurement of the net deferred tax liability included in our rate base. Of this amount, $21.2 million as of September 30, 2019 and $5.2 million as of September 30, 2018 is recorded in other current liabilities. The period and timing of the return of the excess deferred taxes is being determined by regulators in each of our jurisdictions. See Note 13 for further information. |
Revenue recognition — Effective October 1, 2018, we adopted the new guidance under Accounting Standards Codification (ASC) Topic 606. See “Accounting pronouncements adopted in fiscal 2019” herein and Note 5 for information regarding our adoption of ASC 606 and the related disclosures.
Distribution Revenues
Distribution revenues represent the delivery of natural gas to residential, commercial, industrial and public authority customers at prices based on tariff rates established by regulatory authorities in the states in which we operate. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered and simultaneously consumed by our customer. We have elected to use the invoice practical expedient and recognize revenue for volumes delivered that we have the right to invoice our customers. We read meters and bill our customers on a monthly cycle basis. Accordingly, we estimate volumes from the last meter read to the balance sheet date and accrue revenue for gas delivered but not yet billed.
In our Texas and Mississippi jurisdictions, we pay franchise fees and gross receipt taxes to operate in these service areas. These franchise fees and gross receipts taxes are required to be paid regardless of our ability to collect from our customers. Accordingly, we account for these amounts on a gross basis in revenue and we record the associated tax expense as a component of taxes, other than income.
44
Pipeline and Storage Revenues
Pipeline and storage revenues primarily represent the transportation and storage of natural gas on our APT system and the transmission of natural gas through our 21-mile pipeline in Louisiana. APT provides transportation and storage services to our Mid-Tex Division, other third party local distribution companies and certain industrial customers under tariff rates approved by the RRC. APT also provides certain transportation and storage services to industrial and electric generation customers, as well as marketers and producers, under negotiated rates. Our pipeline in Louisiana is primarily used to aggregate gas supply for our Louisiana Division under a long-term contract and on a more limited basis to third parties. The demand fee charged to our Louisiana Division is subject to regulatory approval by the Louisiana Public Service Commission. We also manage two asset management plans with distribution affiliates of the Company at terms that have been approved by the applicable state regulatory commissions. The performance obligations for these transportation customers are satisfied by means of transporting customer-supplied gas to the designated location. Revenue is recognized and our performance obligation is satisfied over time when natural gas is delivered to the customer. Management determined that these arrangements qualify for the invoice practical expedient for recognizing revenue. For demand fee arrangements, revenue is recognized and our performance obligation is satisfied by standing ready to transport natural gas over the period of each individual month.
Alternative Revenue Program Revenues
In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our Contribution Margin. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark of $69.4 million that was established in its most recent rate case. Differences between actual revenues and revenues calculated under these mechanisms adjust the amount billed to customers. These mechanisms are considered to be alternative revenue programs under accounting standards generally accepted in the United States as they are deemed to be contracts between us and our regulator. Accordingly, revenue under these mechanisms are excluded from revenue from contracts with customers.
Purchased gas costs — Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas costs through purchased gas cost adjustment mechanisms. Purchased gas cost adjustment mechanisms provide gas distribution companies a method of recovering purchased gas costs on an ongoing basis without filing a rate case to address all of their non-gas costs. There is no margin generated through purchased gas cost adjustments, but they provide a dollar-for-dollar offset to increases or decreases in our distribution segment’s gas costs. The effects of these purchased gas cost adjustment mechanisms are recorded as deferred gas costs on our consolidated balance sheets.
Discontinued operations — Accounting policies specific to our discontinued natural gas marketing business are described in more detail in Note 16.
Cash and cash equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Accounts receivable and allowance for doubtful accounts — Accounts receivable arise from natural gas sales to residential, commercial, industrial, municipal and other customers. We establish an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect based on our collection experience or where we are aware of a specific customer’s inability or reluctance to pay. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
Gas stored underground — Our gas stored underground is comprised of natural gas injected into storage to support the winter season withdrawals for our distribution operations. The average cost method is used for all of our distribution operations. Gas in storage that is retained as cushion gas to maintain reservoir pressure is classified as property, plant and equipment and is valued at cost.
Property, plant and equipment — Regulated property, plant and equipment is stated at original cost, net of contributions in aid of construction. The cost of additions includes direct construction costs, payroll related costs (taxes, pensions and other fringe benefits), administrative and general costs and an allowance for funds used during construction. The allowance for funds used during construction (AFUDC) represents the capitalizable total cost of funds used to finance the construction of major projects.
45
The following table details amounts capitalized for the fiscal year ended September 30.
2019 | 2018 | 2017 | ||||||||||
Component of AFUDC | Statement of Comprehensive Income Location | (In thousands) | ||||||||||
Debt | Interest charges | $ | 7,643 | $ | 6,810 | $ | 2,479 | |||||
Equity | Other non-operating income (expense) | 11,165 | — | — | ||||||||
$ | 18,808 | $ | 6,810 | $ | 2,479 | |||||||
Major renewals, including replacement pipe, and betterments that are recoverable through our regulatory rate base are capitalized while the costs of maintenance and repairs that are not capitalizable are charged to expense as incurred. The costs of large projects are accumulated in construction in progress until the project is completed. When the project is completed, tested and placed in service, the balance is transferred to the regulated plant in service account included in the rate base and depreciation begins.
Regulated property, plant and equipment is depreciated at various rates on a straight-line basis. These rates are approved by our regulatory commissions and are comprised of two components: one based on average service life and one based on cost of removal. Accordingly, we recognize our cost of removal expense as a component of depreciation expense. The related cost of removal accrual is reflected as a regulatory liability on the consolidated balance sheet. At the time property, plant and equipment is retired, removal expenses less salvage, are charged to the regulatory cost of removal accrual. The composite depreciation rate was 3.1 percent, 3.2 percent and 3.1 percent for the fiscal years ended September 30, 2019, 2018 and 2017.
Other property, plant and equipment is stated at cost. Depreciation is generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives.
Asset retirement obligations — We record a liability at fair value for an asset retirement obligation when the legal obligation to retire the asset has been incurred with an offsetting increase to the carrying value of the related asset. Accretion of the asset retirement obligation due to the passage of time is recorded as an operating expense.
As of September 30, 2019 and 2018, we had asset retirement obligations of $17.1 million and $12.9 million. Additionally, we had $11.3 million and $7.5 million of asset retirement costs recorded as a component of property, plant and equipment that will be depreciated over the remaining life of the underlying associated assets.
We believe we have a legal obligation to retire our natural gas storage facilities. However, we have not recognized an asset retirement obligation associated with our storage facilities because we are not able to determine the settlement date of this obligation as we do not anticipate taking our storage facilities out of service permanently. Therefore, we cannot reasonably estimate the fair value of this obligation.
Impairment of long-lived assets — We evaluate whether events or circumstances have occurred that indicate that other long-lived assets may not be recoverable or that the remaining useful life may warrant revision. When such events or circumstances are present, we assess the recoverability of long-lived assets by determining whether the carrying value will be recovered through the expected future cash flows. In the event the sum of the expected future cash flows resulting from the use of the asset is less than the carrying value of the asset, an impairment loss equal to the excess of the asset’s carrying value over its fair value is recorded.
Goodwill — We annually evaluate our goodwill balances for impairment during our second fiscal quarter or more frequently as impairment indicators arise. During the second quarter of fiscal 2019, we completed our annual goodwill impairment assessment using a qualitative assessment, as permitted under U.S. GAAP. We test goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit. Based on the assessment performed, we determined that our goodwill was not impaired. Although not applicable for the fiscal 2019 analysis, if the qualitative assessment resulted in impairment indicators, we would then use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. These calculations are dependent on several subjective factors including the timing of future cash flows, future growth rates and the discount rate. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value.
Marketable securities — As of September 30, 2019, we hold marketable securities classified as either equity or debt securities. Beginning on October 1, 2018, changes in fair value of our equity securities were recorded in net income as discussed further below in the Recent accounting pronouncements section. Debt securities, which are considered available for sale securities, are reported at market value with unrealized gains and losses shown as a component of accumulated other
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comprehensive income (loss). During fiscal 2018 and under the previous accounting guidance, all our debt and equity securities were considered available for sale securities.
We regularly evaluate the performance of our available for sale debt securities on an investment by investment basis for impairment, taking into consideration the securities’ purpose, volatility and current returns. If a determination is made that a decline in fair value is other than temporary, the related investment is written down to its estimated fair value.
Financial instruments and hedging activities — We currently use financial instruments to mitigate commodity price risk in our distribution and pipeline and storage segments and in the past have also used financial instruments to mitigate interest rate risk. The objectives and strategies for using financial instruments have been tailored to our business and are discussed in Note 14.
We record all of our financial instruments on the balance sheet at fair value, with changes in fair value ultimately recorded in the statement of comprehensive income. These financial instruments are reported as risk management assets and liabilities and are classified as current or noncurrent other assets or liabilities based upon the anticipated settlement date of the underlying financial instrument. We record the cash flow impact of our financial instruments in operating cash flows based upon their balance sheet classification.
The timing of when changes in fair value of our financial instruments are recorded in the statement of comprehensive income depends on whether the financial instrument has been designated and qualifies as a part of a hedging relationship or if regulatory rulings require a different accounting treatment. Changes in fair value for financial instruments that do not meet one of these criteria are recognized in the statement of comprehensive income as they occur.
Financial Instruments Associated with Commodity Price Risk
In our distribution segment, the costs associated with and the realized gains and losses arising from the use of financial instruments to mitigate commodity price risk are included in our purchased gas cost adjustment mechanisms in accordance with regulatory requirements. Therefore, changes in the fair value of these financial instruments are initially recorded as a component of deferred gas costs and recognized in the consolidated statements of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue in accordance with accounting principles generally accepted in the United States. Accordingly, there is no earnings impact on our distribution segment as a result of the use of these financial instruments.
Financial Instruments Associated with Interest Rate Risk
In connection with the planned issuance of long-term debt, we may use financial instruments to manage interest rate risk. We historically managed this risk through the use of forward starting interest rate swaps to fix the Treasury yield component of the interest cost associated with anticipated financings. We designate these financial instruments as cash flow hedges at the time the agreements are executed. Unrealized gains and losses associated with the instruments are recorded as a component of accumulated other comprehensive income (loss). When the instruments settle, the realized gain or loss is recorded as a component of accumulated other comprehensive income (loss) and recognized as a component of interest charges over the life of the related financing arrangement. Hedge ineffectiveness to the extent incurred is reported as a component of interest charges. As of September 30, 2019 and September 30, 2018, no cash was required to be held in margin accounts.
Fair Value Measurements — We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We primarily use quoted market prices and other observable market pricing information in valuing our financial assets and liabilities and minimize the use of unobservable pricing inputs in our measurements.
Fair-value estimates also consider our own creditworthiness and the creditworthiness of the counterparties involved. Our counterparties consist primarily of financial institutions and major energy companies. This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions. We seek to minimize counterparty credit risk through an evaluation of their financial condition and credit ratings and the use of collateral requirements under certain circumstances.
Amounts reported at fair value are subject to potentially significant volatility based upon changes in market prices, including, but not limited to, the valuation of the portfolio of our contracts, maturity and settlement of these contracts and newly originated transactions and interest rates, each of which directly affect the estimated fair value of our financial instruments. We believe the market prices and models used to value these financial instruments represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. Values are adjusted to reflect the potential impact of an orderly liquidation of our positions over a reasonable period of time under then current market conditions.
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Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). The levels of the hierarchy are described below:
Level 1 — Represents unadjusted quoted prices in active markets for identical assets or liabilities. An active market for the asset or liability is defined as a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Prices actively quoted on national exchanges are used to determine the fair value of most of our assets and liabilities recorded on our balance sheet at fair value.
Our Level 1 measurements consist primarily of our debt and equity securities. The Level 1 measurements for investments in the Atmos Energy Corporation Master Retirement Trust (the Master Trust), Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of exchange-traded financial instruments.
Level 2 — Represents pricing inputs other than quoted prices included in Level 1 that are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data. Our Level 2 measurements primarily consist of non-exchange-traded financial instruments, such as over-the-counter options and swaps and municipal and corporate bonds where market data for pricing is observable. The Level 2 measurements for investments in our Master Trust, Supplemental Executive Benefit Plan and postretirement benefit plan consist primarily of non-exchange traded financial instruments such as corporate bonds and government securities.
Level 3 — Represents generally unobservable pricing inputs which are developed based on the best information available, including our own internal data, in situations where there is little if any market activity for the asset or liability at the measurement date. The pricing inputs utilized reflect what a market participant would use to determine fair value. We currently do not have any Level 3 investments.
Pension and other postretirement plans — Pension and other postretirement plan costs and liabilities are determined on an actuarial basis 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. Our measurement date is September 30. 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. For the valuation performed as of September 30, 2019, decreases in the discount rate resulted in actuarial losses that increased our plan obligations.
The discount rate is utilized principally in calculating the actuarial present value of our pension and postretirement obligation and net pension and postretirement cost. 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 the annual pension and postretirement plan cost. 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 when 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 cost is not affected. Rather, this gain or loss is amortized over the expected future working lifetime of the plan participants.
The expected return on plan assets is then calculated by applying the expected long-term rate of return on plan assets to the market-related value of the plan assets. 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 calculation will delay the impact of current market fluctuations on the pension expense for the period.
We use a corridor approach to amortize actuarial gains and losses. Under this approach, net gains or losses in excess of ten percent of the larger of the pension benefit obligation or the market-related value of the assets are amortized on a straight-line basis. The period of amortization is the average remaining service of active participants who are expected to receive benefits under the plan.
We estimate the assumed health care cost trend rate used in determining our annual postretirement net cost 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 the annual review of our participant census information as of the measurement date.
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Income taxes — Income taxes are determined based on the liability method, which results in income tax assets and liabilities arising from temporary differences. Temporary differences are differences between the tax bases of assets and liabilities and their reported amounts in the financial statements that will result in taxable or deductible amounts in future years. The liability method requires the effect of tax rate changes on accumulated deferred income taxes to be reflected in the period in which the rate change was enacted. The liability method also requires that deferred tax assets be reduced by a valuation allowance unless it is more likely than not that the assets will be realized.
The Company may recognize the tax benefit from uncertain tax positions only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon settlement with the taxing authorities. We recognize accrued interest related to unrecognized tax benefits as a component of interest charges. We recognize penalties related to unrecognized tax benefits as a component of miscellaneous income (expense) in accordance with regulatory requirements.
Tax collections — We are allowed to recover from customers revenue-related taxes that are imposed upon us. We record such taxes as operating expenses and record the corresponding customer charges as operating revenues. However, we do collect and remit various other taxes on behalf of various governmental authorities, and we record these amounts in our consolidated balance sheets on a net basis. We do not collect income taxes from our customers on behalf of governmental authorities.
Contingencies — In the normal course of business, we are confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties or the action of various regulatory agencies. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts and our estimates of the ultimate outcome or resolution of the liability in the future. Actual results may differ from estimates, depending on actual outcomes or changes in the facts or expectations surrounding each potential exposure.
Subsequent events — Except as noted in Note 6 regarding the public offering of senior notes, no events occurred subsequent to the balance sheet date that would require recognition or disclosure in the financial statements.
Recent accounting pronouncements
Accounting pronouncements adopted in fiscal 2019
During fiscal 2019, we adopted the following accounting guidance updates. The adoption of this new guidance, individually and collectively, did not have a material impact on our financial position, results of operations or cash flows.
• | Revenue recognition - We adopted the new guidance October 1, 2018 using the modified retrospective method. Under the new guidance, we are required to recognize revenue when we transfer promised goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The implementation of the new guidance did not have a material impact on our financial position, results of operations, cash flow or business processes. However, the guidance introduced new disclosures which are presented in Note 5. |
• | Classification and measurement of financial instruments - The new guidance requires that we recognize changes in the fair value of our equity securities formerly designated as available-for-sale in other non-operating income (expense) in our consolidated statement of comprehensive income on a prospective basis from the date of adoption. However, we continue to classify cash flows from purchases and sales of equity securities within investing activities given the nature of these securities. Additionally, in accordance with the guidance, we reclassified a net $8.2 million unrealized gain related to these equity securities from accumulated other comprehensive income (AOCI) to retained earnings at October 1, 2018. The accounting for debt securities designated as available-for-sale did not change as a result of this new guidance. Accordingly, changes in the fair value of these securities will continue to be recorded as a component of AOCI. |
• | Presentation of the Components of Net Periodic Benefit Cost - On October 1, 2018, we adopted the new guidance, which requires us to present only the current service cost component of the net benefit cost within operations and maintenance expense in the consolidated statements of comprehensive income. The remaining components of net benefit cost are now recorded in other non-operating income (expense) in our consolidated statements of comprehensive income. The change in presentation of these costs was implemented on a retrospective basis as required by the guidance. In lieu of determining how each component of the net periodic benefit cost was actually reflected in the prior periods’ statement of comprehensive income, we elected to utilize a practical expedient that permits the use of the amounts disclosed for these costs in our pension and post-retirement benefit plans footnote as the basis to retroactively apply this standard. |
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In addition, under the new guidance, only the service cost component of net benefit cost is eligible for capitalization (e.g., as part of inventory or property, plant, and equipment). We continue to capitalize these costs into property, plant and equipment.
However, the FERC, which establishes the regulatory accounting practices for rate-regulated entities, issued guidance that permits such entities the option to continue to capitalize non-service benefit costs for regulatory purposes. Since the accounting guidelines by the FERC are typically followed by our state regulatory authorities, for U.S. GAAP reporting purposes, we are prospectively deferring into a regulatory asset the portion of non-service components of net periodic benefit cost that are capitalizable for regulatory purposes.
• | Accounting for Implementation Costs Incurred in A Hosting Arrangement That Is A Service Contract - The new guidance aligns the requirements for capitalizing implementation costs incurred for these contracts with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). We elected to early adopt the new guidance on a prospective basis effective October 1, 2018. Accordingly, we will capitalize the up-front costs incurred for cloud computing arrangements had they been capitalizable in a similar on-premise software solution. |
• | Disclosures of Defined Benefit Pension and Other Postretirement Plans - As of September 30, 2019, we elected to early adopt the new guidance, issued by the FASB in August 2018, that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The guidance removes the disclosure requirements for the amounts of gain/loss and prior service cost/credit amortization expected in the following year and the disclosure of the effect of a one-percentage-point change in the health care cost trend rate, among other changes. The guidance adds certain disclosures including the weighted average interest crediting rate for cash balance plans and a narrative description for the significant change in gains and losses as well as any other significant change in the plan obligations or assets. The adoption of this new guidance impacted only our disclosures, see Note 8. |
Accounting pronouncements that will be effective after fiscal 2019
In February 2016, the FASB issued a comprehensive new leasing standard that will require lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with an initial term greater than 12 months on its balance sheet. Subsequently, the FASB issued practical expedients to 1) allow entities to not evaluate existing or expired land easements that were not previously accounted for as leases under the current guidance and 2) allow entities the option to adopt the standard and recognize a cumulative–effect adjustment to the opening balance of retained earnings in the period of adoption rather than applying the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The new standard was effective for us beginning on October 1, 2019.
The impact of this change on our financial position is expected to be material and we will be required to make additional disclosures. We do not anticipate the adoption of this standard will have a material impact to our results of operations or cash flows. We adopted the following practical expedients and accounting policy elections:
•land easements practical expedient under the provisions of ASU 2018-01, as described above,
•package of three practical expedients described in ASC 842-10-65-1,
•transition method practical expedient provided in ASU 2018-11, as described above,
•lease and non-lease component accounting policy election accounted for as single component, and
•short-term lease exemption to not apply Topic 842, as permitted.
We are implementing a new lease accounting system, which we will utilize to capture, track and account for lease data. The new system will also aid in automating the compilation of disclosure information. Additionally, we are implementing internal controls to adhere to the new accounting guidance and to facilitate in the preparation of financial information.
In June 2016, the FASB issued new guidance which will require credit losses on most financial assets measured at amortized cost and certain other instruments to be measured using an expected credit loss model. Under this model, entities will estimate credit losses over the entire contractual term of the instrument from the date of initial recognition of that instrument. In contrast, current U.S. GAAP is based on an incurred loss model that delays recognition of credit losses until it is probable the loss has been incurred. The new guidance also introduces a new impairment recognition model for available-for-sale debt securities that will require credit losses for available-for-sale debt securities to be recorded through an allowance account. The new standard will be effective for us beginning on October 1, 2020; early adoption is permitted. We are currently evaluating the potential impact of this new guidance on our financial position, results of operations and cash flows.
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3. Segment Information
As of September 30, 2019, we manage and review our consolidated operations through the following two 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. |
Prior to disposition, the natural gas marketing segment, which was comprised of our natural gas marketing business, was also a reportable segment.
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers. Although our distribution segment operations are geographically dispersed, they are aggregated and reported as a single segment as each natural gas distribution division has similar economic characteristics. In addition, because the pipeline and storage operations of our Atmos Pipeline-Texas division and our natural gas transmission operations in Louisiana have similar economic characteristics, they have been aggregated and reported as a single segment.
The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate performance based on net income or loss of the respective operating units. We allocate interest and pension expense to the pipeline and storage segment; however, there is no debt or pension liability recorded on the pipeline and storage segment balance sheet. All material intercompany transactions have been eliminated; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Income taxes are allocated to each segment as if each segment’s income taxes were calculated on a separate return basis.
Income statements and capital expenditures by segment are shown in the following tables.
Year Ended September 30, 2019 | |||||||||||||||
Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Operating revenues from external parties | $ | 2,742,824 | $ | 159,024 | $ | — | $ | 2,901,848 | |||||||
Intersegment revenues | 2,637 | 408,000 | (410,637 | ) | — | ||||||||||
Total operating revenues | 2,745,461 | 567,024 | (410,637 | ) | 2,901,848 | ||||||||||
Purchased gas cost | 1,268,591 | (360 | ) | (409,394 | ) | 858,837 | |||||||||
Operation and maintenance expense | 480,222 | 151,329 | (1,243 | ) | 630,308 | ||||||||||
Depreciation and amortization expense | 283,697 | 107,759 | — | 391,456 | |||||||||||
Taxes, other than income | 242,179 | 33,010 | — | 275,189 | |||||||||||
Operating income | 470,772 | 275,286 | — | 746,058 | |||||||||||
Other non-operating income | 6,241 | 1,163 | — | 7,404 | |||||||||||
Interest charges | 60,031 | 43,122 | — | 103,153 | |||||||||||
Income before income taxes | 416,982 | 233,327 | — | 650,309 | |||||||||||
Income tax expense | 88,168 | 50,735 | — | 138,903 | |||||||||||
Net income | $ | 328,814 | $ | 182,592 | $ | — | $ | 511,406 | |||||||
Capital expenditures | $ | 1,274,613 | $ | 418,864 | $ | — | $ | 1,693,477 | |||||||
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Year Ended September 30, 2018 | |||||||||||||||
Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Operating revenues from external parties | $ | 3,000,404 | $ | 115,142 | $ | — | $ | 3,115,546 | |||||||
Intersegment revenues | 2,643 | 392,571 | (395,214 | ) | — | ||||||||||
Total operating revenues | 3,003,047 | 507,713 | (395,214 | ) | 3,115,546 | ||||||||||
Purchased gas cost | 1,559,836 | 1,978 | (393,966 | ) | 1,167,848 | ||||||||||
Operation and maintenance expense | 461,048 | 134,995 | (1,248 | ) | 594,795 | ||||||||||
Depreciation and amortization expense | 264,930 | 96,153 | — | 361,083 | |||||||||||
Taxes, other than income | 231,566 | 32,320 | — | 263,886 | |||||||||||
Operating income | 485,667 | 242,267 | — | 727,934 | |||||||||||
Other non-operating expense | (6,649 | ) | (3,495 | ) | — | (10,144 | ) | ||||||||
Interest charges | 65,850 | 40,796 | — | 106,646 | |||||||||||
Income before income taxes | 413,168 | 197,976 | — | 611,144 | |||||||||||
Income tax (benefit) expense | (29,798 | ) | 37,878 | — | 8,080 | ||||||||||
Net income | $ | 442,966 | $ | 160,098 | $ | — | $ | 603,064 | |||||||
Capital expenditures | $ | 1,025,800 | $ | 441,791 | $ | — | $ | 1,467,591 | |||||||
Year Ended September 30, 2017 | |||||||||||||||||||
Distribution | Pipeline and Storage | Natural Gas Marketing | Eliminations | Consolidated | |||||||||||||||
(In thousands) | |||||||||||||||||||
Operating revenues from external parties | $ | 2,647,813 | $ | 111,922 | $ | — | $ | — | $ | 2,759,735 | |||||||||
Intersegment revenues | 1,362 | 345,108 | — | (346,470 | ) | — | |||||||||||||
Total operating revenues | 2,649,175 | 457,030 | — | (346,470 | ) | 2,759,735 | |||||||||||||
Purchased gas cost | 1,269,456 | 2,506 | — | (346,426 | ) | 925,536 | |||||||||||||
Operation and maintenance expense | 404,995 | 133,765 | — | (44 | ) | 538,716 | |||||||||||||
Depreciation and amortization expense | 249,071 | 70,377 | — | — | 319,448 | ||||||||||||||
Taxes, other than income | 211,929 | 28,478 | — | — | 240,407 | ||||||||||||||
Operating income | 513,724 | 221,904 | — | — | 735,628 | ||||||||||||||
Other non-operating expense | (9,777 | ) | (1,575 | ) | — | — | (11,352 | ) | |||||||||||
Interest charges | 79,789 | 40,393 | — | — | 120,182 | ||||||||||||||
Income from continuing operations before income taxes | 424,158 | 179,936 | — | — | 604,094 | ||||||||||||||
Income tax expense | 155,789 | 65,594 | — | — | 221,383 | ||||||||||||||
Income from continuing operations | 268,369 | 114,342 | — | — | 382,711 | ||||||||||||||
Income from discontinued operations, net of tax | — | — | 10,994 | — | 10,994 | ||||||||||||||
Gain on sale of discontinued operations, net of tax | — | — | 2,716 | — | 2,716 | ||||||||||||||
Net income | $ | 268,369 | $ | 114,342 | $ | 13,710 | $ | — | $ | 396,421 | |||||||||
Capital expenditures | $ | 849,950 | $ | 287,139 | $ | — | $ | — | $ | 1,137,089 | |||||||||
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The following table summarizes our revenues from external parties, excluding intersegment revenues, by products and services for the fiscal years ended September 30.
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Distribution revenues: | |||||||||||
Gas sales revenues: | |||||||||||
Residential | $ | 1,733,548 | $ | 1,916,101 | $ | 1,642,918 | |||||
Commercial | 711,284 | 797,073 | 708,167 | ||||||||
Industrial | 118,046 | 131,267 | 133,372 | ||||||||
Public authority and other | 42,613 | 47,714 | 45,820 | ||||||||
Total gas sales revenues | 2,605,491 | 2,892,155 | 2,530,277 | ||||||||
Transportation revenues | 95,629 | 99,250 | 86,332 | ||||||||
Other gas revenues | 41,704 | 8,999 | 31,204 | ||||||||
Total distribution revenues | 2,742,824 | 3,000,404 | 2,647,813 | ||||||||
Pipeline and storage revenues | 159,024 | 115,142 | 111,922 | ||||||||
Total operating revenues | $ | 2,901,848 | $ | 3,115,546 | $ | 2,759,735 | |||||
Balance sheet information at September 30, 2019 and 2018 by segment is presented in the following tables.
September 30, 2019 | |||||||||||||||
Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Property, plant and equipment, net | $ | 8,737,590 | $ | 3,050,079 | $ | — | $ | 11,787,669 | |||||||
Total assets | $ | 12,579,741 | $ | 3,279,323 | $ | (2,491,445 | ) | $ | 13,367,619 | ||||||
September 30, 2018 | |||||||||||||||
Distribution | Pipeline and Storage | Eliminations | Consolidated | ||||||||||||
(In thousands) | |||||||||||||||
Property, plant and equipment, net | $ | 7,644,693 | $ | 2,726,454 | $ | — | $ | 10,371,147 | |||||||
Total assets | $ | 11,109,128 | $ | 2,963,480 | $ | (2,198,171 | ) | $ | 11,874,437 | ||||||
4. Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic weighted average shares outstanding is calculated based upon the weighted average number of common shares outstanding during the periods presented. Also, this calculation includes fully vested stock awards that have not yet been issued as common stock. Additionally, the weighted average shares outstanding for diluted EPS includes the incremental effects of the forward sale agreements, discussed in Note 7, when the impact is dilutive.
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Basic and diluted earnings per share for the fiscal years ended September 30 are calculated as follows:
2019 | 2018 | 2017 | |||||||||
(In thousands, except per share data) | |||||||||||
Basic Earnings Per Share from continuing operations | |||||||||||
Income from continuing operations | $ | 511,406 | $ | 603,064 | $ | 382,711 | |||||
Less: Income from continuing operations allocated to participating securities | 416 | 580 | 475 | ||||||||
Income from continuing operations available to common shareholders | $ | 510,990 | $ | 602,484 | $ | 382,236 | |||||
Basic weighted average shares outstanding | 117,200 | 111,012 | 106,100 | ||||||||
Income from continuing operations per share — Basic | $ | 4.36 | $ | 5.43 | $ | 3.60 | |||||
Basic Earnings Per Share from discontinued operations | |||||||||||
Income from discontinued operations | $ | — | $ | — | $ | 13,710 | |||||
Less: Income from discontinued operations allocated to participating securities | — | — | 12 | ||||||||
Income from discontinued operations available to common shareholders | $ | — | $ | — | $ | 13,698 | |||||
Basic weighted average shares outstanding | 117,200 | 111,012 | 106,100 | ||||||||
Income from discontinued operations per share - Basic | $ | — | $ | — | $ | 0.13 | |||||
Net Income per share — Basic | $ | 4.36 | $ | 5.43 | $ | 3.73 | |||||
Diluted Earnings Per Share from continuing operations | |||||||||||
Income from continuing operations available to common shareholders | $ | 510,990 | $ | 602,484 | $ | 382,236 | |||||
Effect of dilutive shares | — | — | — | ||||||||
Income from continuing operations available to common shareholders | $ | 510,990 | $ | 602,484 | $ | 382,236 | |||||
Basic weighted average shares outstanding | 117,200 | 111,012 | 106,100 | ||||||||
Dilutive shares | 261 | — | — | ||||||||
Diluted weighted average shares outstanding | 117,461 | 111,012 | 106,100 | ||||||||
Income from continuing operations per share — Diluted | $ | 4.35 | $ | 5.43 | $ | 3.60 | |||||
Diluted Earnings Per Share from discontinued operations | |||||||||||
Income from discontinued operations available to common shareholders | $ | — | $ | — | $ | 13,698 | |||||
Effect of dilutive shares | — | — | — | ||||||||
Income from discontinued operations available to common shareholders | $ | — | $ | — | $ | 13,698 | |||||
Basic weighted average shares outstanding | 117,200 | 111,012 | 106,100 | ||||||||
Dilutive shares | 261 | — | — | ||||||||
Diluted weighted average shares outstanding | 117,461 | 111,012 | 106,100 | ||||||||
Income from discontinued operations per share - Diluted | $ | — | $ | — | $ | 0.13 | |||||
Net Income per share — Diluted | $ | 4.35 | $ | 5.43 | $ | 3.73 | |||||
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5. Revenue
The following table disaggregates our revenue from contracts with customers by customer type and segment and provides a reconciliation to total operating revenues, including intersegment revenues, for the period presented.
Year Ended September 30, 2019 | |||||||
Distribution | Pipeline and Storage | ||||||
(In thousands) | |||||||
Gas sales revenues: | |||||||
Residential | $ | 1,755,229 | $ | — | |||
Commercial | 716,757 | — | |||||
Industrial | 118,060 | — | |||||
Public authority and other | 42,796 | — | |||||
Total gas sales revenues | 2,632,842 | — | |||||
Transportation revenues | 97,495 | 623,808 | |||||
Miscellaneous revenues | 26,050 | 8,060 | |||||
Revenues from contracts with customers | 2,756,387 | 631,868 | |||||
Alternative revenue program revenues(1) | (12,958 | ) | (64,844 | ) | |||
Other revenues | 2,032 | — | |||||
Total operating revenues | $ | 2,745,461 | $ | 567,024 | |||
(1) | In our distribution segment, we have weather-normalization adjustment mechanisms that serve to minimize the effects of weather on our Contribution Margin. Additionally, APT has a regulatory mechanism that requires that we share with its tariffed customers 75% of the difference between the total non-tariffed revenues earned during a test period and a revenue benchmark. |
6. Debt
Long-term debt
Long-term debt at September 30, 2019 and 2018 consisted of the following:
2019 | 2018 | ||||||
(In thousands) | |||||||
Unsecured 8.50% Senior Notes, due March 2019 | $ | — | $ | 450,000 | |||
Unsecured 3.00% Senior Notes, due 2027 | 500,000 | 500,000 | |||||
Unsecured 5.95% Senior Notes, due 2034 | 200,000 | 200,000 | |||||
Unsecured 5.50% Senior Notes, due 2041 | 400,000 | 400,000 | |||||
Unsecured 4.15% Senior Notes, due 2043 | 500,000 | 500,000 | |||||
Unsecured 4.125% Senior Notes, due 2044 | 750,000 | 750,000 | |||||
Unsecured 4.30% Senior Notes, due 2048 | 600,000 | — | |||||
Unsecured 4.125% Senior Notes, due 2049 | 450,000 | — | |||||
Medium term Series A notes, 1995-1, 6.67%, due 2025 | 10,000 | 10,000 | |||||
Unsecured 6.75% Debentures, due 2028 | 150,000 | 150,000 | |||||
Floating-rate term loan, due September 2019(1) | — | 125,000 | |||||
Total long-term debt | 3,560,000 | 3,085,000 | |||||
Less: | |||||||
Original issue (premium) / discount on unsecured senior notes and debentures | 193 | (4,439 | ) | ||||
Debt issuance cost | 30,355 | 20,774 | |||||
Current maturities | — | 575,000 | |||||
$ | 3,529,452 | $ | 2,493,665 | ||||
(1) | Up to $200 million was available to be drawn under this term loan prior to its maturity in September 2019. |
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Maturities of long-term debt at September 30, 2019 were as follows (in thousands):
2020 | $ | — | |
2021 | — | ||
2022 | — | ||
2023 | — | ||
2024 | — | ||
Thereafter | 3,560,000 | ||
$ | 3,560,000 | ||
On October 2, 2019, we completed a public offering of $300 million of 2.625% senior notes due 2029 and $500 million of 3.375% senior notes due 2049. We received net proceeds from the offering, after the underwriting discount and estimated offering expenses, of $791.6 million, that were used for general corporate purposes, including the repayment of working capital borrowings pursuant to our commercial paper program. The effective interest rate on these notes is 2.72% and 3.42%, after giving effect to the offering costs.
On September 20, 2019, we repaid our $125 million floating rate term loan at its maturity.
On March 4, 2019, we completed a public offering of $450 million of 4.125% senior notes due 2049. The effective interest rate of these notes is 4.86%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds, after the underwriting discount and offering expenses, of $443.4 million, together with available cash, was used to repay at maturity our $450 million 8.50% unsecured senior notes due March 15, 2019 and the related settlement of our interest rate swaps.
On October 4, 2018, we completed a public offering of $600 million of 4.30% senior notes due 2048. We received net proceeds from the offering, after the underwriting discount and offering expenses, of $590.6 million, that were used to repay working capital borrowings pursuant to our commercial paper program. The effective interest rate of these notes is 4.37% after giving effect to the offering costs.
We utilize short-term debt to provide cost-effective, short-term financing until it can be replaced with a balance of long-term debt and equity financing that achieves the Company’s desired capital structure with an equity-to-capitalization ratio between 50% and 60%, inclusive of long-term and short-term debt. Our short-term borrowing requirements are driven primarily by construction work in progress and the seasonal nature of the natural gas business.
Currently, our short-term borrowing requirements are satisfied through a combination of a $1.5 billion commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.5 billion of total working capital funding. The primary source of our funding is our commercial paper program, which is supported by a five-year unsecured $1.5 billion credit facility. On March 29, 2019, we executed our final one-year extension option which extended the maturity date from September 25, 2022 to September 25, 2023. The facility bears interest at a base rate or at a LIBOR-based rate for the applicable interest period, plus a margin ranging from zero percent to 1.25 percent, based on the Company’s credit ratings. Additionally, the facility contains a $250 million accordion feature, which provides the opportunity to increase the total committed loan to $1.75 billion. At September 30, 2019 and 2018, there was $464.9 million and $575.8 million outstanding under our commercial paper program with weighted average interest rates of 2.24% and 2.15% and weighted average maturities of less than one month.
Additionally, we have a $25 million 364-day unsecured facility, which was renewed on April 1, 2019, and a $10 million 364-day unsecured revolving credit facility, which was renewed September 30, 2019, and is used primarily to issue letters of credit. At September 30, 2019, there were no borrowings outstanding under either of these facilities; however, outstanding letters of credit reduced the total amount available to us under our $10 million unsecured revolving facility to $4.4 million.
The availability of funds under these credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total-debt-to-total-capitalization of no greater than 70 percent. At September 30, 2019, our total-debt-to-total-capitalization ratio, as defined, was 42 percent. In addition, both the interest margin and the fee that we pay on unused amounts under each of these facilities are subject to adjustment depending upon our credit ratings.
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These credit facilities and our public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers. Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity. We were in compliance with all of our debt covenants as of September 30, 2019. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.
7. Shareholders' Equity
Shelf Registration, At-the-Market Equity Sales Program and Equity Issuances
On November 13, 2018, we filed a registration statement with the Securities and Exchange Commission (SEC) to issue, from time to time, up to $3.0 billion in common stock and/or debt securities, which expires November 13, 2021. This registration statement replaced our previous registration statement that was effectively exhausted in October 2018. At September 30, 2019, approximately $1.3 billion of securities remained available for issuance under the shelf registration statement.
On November 19, 2018, we filed a prospectus supplement under the registration statement relating to an at-the-market (ATM) equity sales program under which we may issue and sell shares of our common stock up to an aggregate offering price of $500 million (including shares of common stock that may be sold pursuant to a forward sale agreement entered into in connection with the ATM equity sales program), which expires November 13, 2021. During the year ended September 30, 2019, we executed forward sales under the ATM with various forward sellers who borrowed and sold 4,144,671 shares of our common stock for $425.0 million. As of September 30, 2019, the ATM program had approximately $75 million of equity available for issuance.
On November 30, 2018, we filed a prospectus supplement under the registration statement relating to an underwriting agreement to sell 5,390,836 shares of our common stock for $500 million. After expenses, net proceeds from the offering were $494.1 million. Concurrently, we entered into separate forward sale agreements with two forward sellers who borrowed and sold 2,668,464 shares of our common stock for $247.5 million. During the year ended September 30, 2019, we settled 2,183,275 shares for net proceeds of $200.0 million.
If we had settled all shares that remain available under our various forward sale agreements as of September 30, 2019, we would have received proceeds of $463.4 million, based on a net price of $100.08 per share.
The following table presents information relevant to the forward sales during fiscal 2019.
Maturity | ||||||||||||||||||
September 30, 2020 | March 31, 2020 | Total | ||||||||||||||||
Shares | Price(1) | Shares | Price(1) | Shares | Price(1) | |||||||||||||
Available Balance September 30, 2018 | — | $ | — | — | $ | — | — | $ | — | |||||||||
Q1 Issuance | — | — | 2,668,464 | 91.77 | 2,668,464 | 91.77 | ||||||||||||
Q2 Issuance | — | — | 1,670,509 | 95.46 | 1,670,509 | 95.46 | ||||||||||||
Q3 Issuance | 1,050,563 | 101.41 | — | — | 1,050,563 | 101.41 | ||||||||||||
Q3 Settlement | — | — | (1,089,700 | ) | 91.44 | (1,089,700 | ) | 91.44 | ||||||||||
Q4 Issuance | 1,423,599 | 108.70 | — | — | 1,423,599 | 108.70 | ||||||||||||
Q4 Settlement | — | — | (1,093,575 | ) | 91.78 | (1,093,575 | ) | 91.78 | ||||||||||
Available Balance September 30, 2019 | 2,474,162 | 2,155,698 | 4,629,860 | |||||||||||||||
(1) | Issued price as disclosed is calculated as the weighted average price for activity occurring during the quarter. |
On November 30, 2017, we filed a prospectus supplement under the previous registration statement relating to an underwriting agreement to sell 4,558,404 shares of our common stock for $400 million. After expenses, net proceeds from the offering were $395.1 million.
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1998 Long-Term Incentive Plan
In August 1998, the Board of Directors approved and adopted the 1998 Long-Term Incentive Plan (LTIP), which became effective in October 1998 after approval by our shareholders. The LTIP is a comprehensive, long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best available personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire our common stock.
Accumulated Other Comprehensive Income (Loss)
We record deferred gains (losses) in accumulated other comprehensive income (AOCI) related to available-for-sale debt securities and interest rate agreement cash flow hedges. Deferred gains (losses) for our available-for-sale debt securities are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as a component of interest charges, as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income (loss).
Available- for-Sale Securities (1) | Interest Rate Agreement Cash Flow Hedges | Total | |||||||||
(In thousands) | |||||||||||
September 30, 2018 | $ | 8,124 | $ | (91,771 | ) | $ | (83,647 | ) | |||
Other comprehensive income (loss) before reclassifications | 219 | (25,966 | ) | (25,747 | ) | ||||||
Amounts reclassified from accumulated other comprehensive income | (1 | ) | 3,022 | 3,021 | |||||||
Net current-period other comprehensive income (loss) | 218 | (22,944 | ) | (22,726 | ) | ||||||
Cumulative effect of accounting change (See Note 2) | (8,210 | ) | — | (8,210 | ) | ||||||
September 30, 2019 | $ | 132 | $ | (114,715 | ) | $ | (114,583 | ) | |||
Available- for-Sale Securities (1) | Interest Rate Agreement Cash Flow Hedges | Total | |||||||||
(In thousands) | |||||||||||
September 30, 2017 | $ | 7,048 | $ | (112,302 | ) | $ | (105,254 | ) | |||
Other comprehensive income (loss) before reclassifications | 1,426 | 43,184 | 44,610 | ||||||||
Amounts reclassified from accumulated other comprehensive income | (1,821 | ) | 1,752 | (69 | ) | ||||||
Net current-period other comprehensive income (loss) | (395 | ) | 44,936 | 44,541 | |||||||
Cumulative effect of accounting change | 1,471 | (24,405 | ) | (22,934 | ) | ||||||
September 30, 2018 | $ | 8,124 | $ | (91,771 | ) | $ | (83,647 | ) | |||
(1) | Available-for-sale securities reported in fiscal 2018 include both debt and equity securities, while fiscal 2019 includes only debt securities. See Note 2 for further discussion regarding our adoption of the new accounting standard. |
8. Retirement and Post-Retirement Employee Benefit Plans
We have both funded and unfunded noncontributory defined benefit plans that together cover most of our employees. We also maintain post-retirement plans that provide health care benefits to retired employees. Finally, we sponsor a defined contribution plan that covers substantially all employees. These plans are discussed in further detail below.
As a rate regulated entity, most of our net periodic pension and other postretirement benefits costs are recoverable through our rates over a period of up to 15 years. A portion of these costs is capitalized into our rate base or deferred as a regulatory asset or liability. The remaining costs are recorded as a component of operation and maintenance expense or other non-
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operating expense. Additionally, the amounts that have not yet been recognized in net periodic pension cost that have been recorded as regulatory assets or liabilities are as follows:
Defined Benefit Plan | Supplemental Executive Retirement Plans | Postretirement Plans | Total | ||||||||||||
(In thousands) | |||||||||||||||
September 30, 2019 | |||||||||||||||
Unrecognized prior service (credit) cost | $ | (815 | ) | $ | — | $ | 1,125 | $ | 310 | ||||||
Unrecognized actuarial (gain) loss | 67,191 | 56,784 | (43,782 | ) | 80,193 | ||||||||||
$ | 66,376 | $ | 56,784 | $ | (42,657 | ) | $ | 80,503 | |||||||
September 30, 2018 | |||||||||||||||
Unrecognized prior service (credit) cost | $ | (1,047 | ) | $ | — | $ | 1,298 | $ | 251 | ||||||
Unrecognized actuarial (gain) loss | (2,310 | ) | 33,912 | (100,966 | ) | (69,364 | ) | ||||||||
$ | (3,357 | ) | $ | 33,912 | $ | (99,668 | ) | $ | (69,113 | ) | |||||
Defined Benefit Plans
Employee Pension Plan
As of September 30, 2019, we maintained one defined benefit plan, the Atmos Energy Corporation Pension Account Plan (the Plan). The assets of the Plan are held within the Atmos Energy Corporation Master Retirement Trust (the Master Trust). The Plan is a cash balance pension plan that was established effective January 1999 and covers most of the employees of Atmos Energy that were hired on or before September 30, 2010. The plan was closed to new participants effective October 1, 2010.
Opening account balances were established for participants as of January 1999 equal to the present value of their respective accrued benefits under the pension plans which were previously in effect as of December 31, 1998. The Plan credits an allocation to each participant’s account at the end of each year according to a formula based on the participant’s age, service and total pay (excluding incentive pay). In addition, at the end of each year, a participant’s account is credited with interest on the employee’s prior year account balance. Participants are fully vested in their account balances after three years of service and may choose to receive their account balances as a lump sum or an annuity.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974, including the funding requirements under the Pension Protection Act of 2006 (PPA). 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.
During fiscal 2019 and 2018 we contributed $8.5 million and $7.0 million in cash to the Plan to achieve a desired level of funding while maximizing the tax deductibility of this payment. Based upon market conditions at September 30, 2019, the current funded position of the Plan and the funding requirements under the PPA, we do not anticipate a minimum required contribution for fiscal 2020. However, we may consider whether a voluntary contribution is prudent to maintain certain funding levels.
We make investment decisions and evaluate performance of the assets in the Master Trust on a medium-term horizon of at least three to five years. We also consider our current financial status when making recommendations and decisions regarding the Master Trust’s assets. Finally, we strive to ensure the Master Trust’s assets are appropriately invested to maintain an acceptable level of risk and meet the Master Trust’s long-term asset investment policy adopted by the Board of Directors.
To achieve these objectives, we invest the Master Trust’s assets in equity securities, fixed income securities, interests in commingled pension trust funds, other investment assets and cash and cash equivalents. Investments in equity securities are diversified among the market’s various subsectors in an effort to diversify risk and maximize returns. Fixed income securities are invested in investment grade securities. Cash equivalents are invested in securities that either are short term (less than 180 days) or readily convertible to cash with modest risk.
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The following table presents asset allocation information for the Master Trust as of September 30, 2019 and 2018.
Targeted Allocation Range | Actual Allocation September 30 | ||||
Security Class | 2019 | 2018 | |||
Domestic equities | 35%-55% | 40.6% | 44.3% | ||
International equities | 10%-20% | 14.5% | 15.4% | ||
Fixed income | 5%-30% | 18.8% | 16.9% | ||
Company stock | 0%-15% | 15.4% | 12.7% | ||
Other assets | 0%-20% | 10.7% | 10.7% | ||
At September 30, 2019 and 2018, the Plan held 716,700 shares of our common stock which represented 15.4 percent and 12.7 percent of total Plan assets. These shares generated dividend income for the Plan of approximately $1.5 million and $1.4 million during fiscal 2019 and 2018.
Our employee pension plan expenses and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates and demographic data. We review the estimates and assumptions underlying our employee pension plans annually based upon a September 30 measurement date. The development of our assumptions is fully described in our significant accounting policies in Note 2. The actuarial assumptions used to determine the pension liability for the Plan was determined as of September 30, 2019 and 2018 and the actuarial assumptions used to determine the net periodic pension cost for the Plan was determined as of September 30, 2018, 2017 and 2016. On October 23, 2019, 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, 2019, we updated our assumed mortality rates to incorporate the updated mortality table.
Additional assumptions are presented in the following table:
Pension Liability | Pension Cost | |||||||||||||
2019 | 2018 | 2019 | 2018 | 2017 | ||||||||||
Discount rate | 3.29 | % | 4.38 | % | 4.38 | % | 3.89 | % | 3.73 | % | ||||
Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | ||||
Expected return on plan assets | 6.50 | % | 6.75 | % | 6.75 | % | 6.75 | % | 7.00 | % | ||||
Interest crediting rate | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | ||||
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The following table presents the Plan’s accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2019 and 2018:
2019 | 2018 | ||||||
(In thousands) | |||||||
Accumulated benefit obligation | $ | 541,287 | $ | 478,750 | |||
Change in projected benefit obligation: | |||||||
Benefit obligation at beginning of year | $ | 504,719 | $ | 533,455 | |||
Service cost | 15,311 | 17,264 | |||||
Interest cost | 22,071 | 20,803 | |||||
Actuarial (gain) loss | 71,139 | (29,087 | ) | ||||
Benefits paid | (35,970 | ) | (37,716 | ) | |||
Benefit obligation at end of year | 577,270 | 504,719 | |||||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of year | 531,691 | 508,244 | |||||
Actual return on plan assets | 25,888 | 54,163 | |||||
Employer contributions | 8,500 | 7,000 | |||||
Benefits paid | (35,970 | ) | (37,716 | ) | |||
Fair value of plan assets at end of year | 530,109 | 531,691 | |||||
Reconciliation: | |||||||
Funded status | (47,161 | ) | 26,972 | ||||
Unrecognized prior service cost | — | — | |||||
Unrecognized net loss | — | — | |||||
Net amount recognized | $ | (47,161 | ) | $ | 26,972 | ||
Net periodic pension cost for the Plan for fiscal 2019, 2018 and 2017 is presented in the following table.
Fiscal Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Components of net periodic pension cost: | |||||||||||
Service cost | $ | 15,311 | $ | 17,264 | $ | 18,109 | |||||
Interest cost(1) | 22,071 | 20,803 | 20,443 | ||||||||
Expected return on assets(1) | (28,451 | ) | (27,666 | ) | (27,975 | ) | |||||
Amortization of prior service credit(1) | (232 | ) | (231 | ) | (231 | ) | |||||
Recognized actuarial loss(1) | 4,201 | 9,114 | 12,744 | ||||||||
Net periodic pension cost | $ | 12,900 | $ | 19,284 | $ | 23,090 | |||||
(1) | The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2. |
The following tables set forth by level, within the fair value hierarchy, the Plan's assets at fair value as of September 30, 2019 and 2018. As required by authoritative accounting literature, assets are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement. The methods used to determine fair value for the assets held by the Plan are fully described in Note 2. Investments in our common/collective trusts and limited partnerships that are measured at net asset value per share equivalent are not classified in the fair value hierarchy. The net asset value amounts presented are intended to reconcile the fair value hierarchy to the total investments. In addition to the assets shown below, the Plan had net accounts receivable of $1.3 million and $2.0 million at September 30, 2019 and 2018, which materially approximates fair value due to the short-term nature of these assets.
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Assets at Fair Value as of September 30, 2019 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In thousands) | |||||||||||||||
Investments: | |||||||||||||||
Common stocks | $ | 212,785 | $ | — | $ | — | $ | 212,785 | |||||||
Money market funds | — | 16,419 | — | 16,419 | |||||||||||
Registered investment companies | 26,326 | — | — | 26,326 | |||||||||||
Government securities: | |||||||||||||||
Mortgage-backed securities | — | 19,986 | — | 19,986 | |||||||||||
U.S. treasuries | 22,930 | 885 | — | 23,815 | |||||||||||
Corporate bonds | — | 55,774 | — | 55,774 | |||||||||||
Total investments measured at fair value | $ | 262,041 | $ | 93,064 | $ | — | 355,105 | ||||||||
Investments measured at net asset value: | |||||||||||||||
Common/collective trusts (1) | 108,975 | ||||||||||||||
Limited partnerships (1) | 64,718 | ||||||||||||||
Total investments | $ | 528,798 | |||||||||||||
Assets at Fair Value as of September 30, 2018 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In thousands) | |||||||||||||||
Investments: | |||||||||||||||
Common stocks | $ | 197,577 | $ | — | $ | — | $ | 197,577 | |||||||
Money market funds | — | 19,153 | — | 19,153 | |||||||||||
Registered investment companies | 50,895 | — | — | 50,895 | |||||||||||
Government securities: | |||||||||||||||
Mortgage-backed securities | — | 18,821 | — | 18,821 | |||||||||||
U.S. treasuries | 23,071 | 868 | — | 23,939 | |||||||||||
Corporate bonds | — | 46,498 | — | 46,498 | |||||||||||
Total investments measured at fair value | $ | 271,543 | $ | 85,340 | $ | — | 356,883 | ||||||||
Investments measured at net asset value: | |||||||||||||||
Common/collective trusts (1) | 108,391 | ||||||||||||||
Limited partnerships (1) | 64,399 | ||||||||||||||
Total investments | $ | 529,673 | |||||||||||||
(1) | The fair value of our common/collective trusts and limited partnerships are measured using the net asset value per share practical expedient. There are no redemption restrictions, redemption notice periods or unfunded commitments for these investments. The redemption frequency is daily. |
Supplemental Executive Retirement Plans
We have three nonqualified supplemental plans which provide additional pension, disability and death benefits to our officers, division presidents and certain other employees of the Company.
The first plan is referred to as the Supplemental Executive Benefits Plan (SEBP) and covers our officers, division presidents and certain other employees of the Company who were employed on or before August 12, 1998. The SEBP is a defined benefit arrangement which provides a benefit equal to 75 percent of covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SEBP.
In August 1998, we adopted the Supplemental Executive Retirement Plan (SERP) (formerly known as the Performance-Based Supplemental Executive Benefits Plan), which covers all officers or division presidents selected to participate in the plan between August 12, 1998 and August 5, 2009 and any corporate officer who was appointed to the Management Committee through December 31, 2015. The SERP is a defined benefit arrangement which provides a benefit equal to 60 percent of
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covered compensation under which benefits paid from the underlying qualified defined benefit plan are an offset to the benefits under the SERP.
Effective August 5, 2009, we adopted a new defined benefit Supplemental Executive Retirement Plan (the 2009 SERP), for corporate officers, division presidents or any other employees selected at the discretion of the Board. Under the 2009 SERP, a nominal account has been established for each participant, to which the Company contributes at the end of each calendar year an amount equal to ten percent (25 percent for members of the Management Committee appointed on or after January 1, 2016) of the total of each participant’s base salary and cash incentive compensation earned during each prior calendar year, beginning December 31, 2009. The benefits vest after three years of service and attainment of age 55 and earn interest credits at the same annual rate as the Company’s Pension Account Plan.
Similar to our employee pension plans, we review the estimates and assumptions underlying our supplemental plans annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for the supplemental plans were determined as of September 30, 2019 and 2018 and the actuarial assumptions used to determine the net periodic pension cost for the supplemental plans were determined as of September 30, 2018, 2017 and 2016. These assumptions are presented in the following table:
Pension Liability | Pension Cost | |||||||||||||
2019 | 2018 | 2019 | 2018 | 2017 | ||||||||||
Discount rate(1) | 3.29 | % | 4.38 | % | 4.38 | % | 4.08 | % | 3.73 | % | ||||
Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | 3.50 | % | ||||
Interest crediting rate | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | 4.69 | % | ||||
(1) | Reflects a weighted average discount rate for pension cost for fiscal 2018 due to settlements during the year. |
The following table presents the supplemental plans’ accumulated benefit obligation, projected benefit obligation and funded status as of September 30, 2019 and 2018:
2019 | 2018 | ||||||
(In thousands) | |||||||
Accumulated benefit obligation | $ | 138,772 | $ | 116,943 | |||
Change in projected benefit obligation: | |||||||
Benefit obligation at beginning of year | $ | 121,370 | $ | 134,480 | |||
Service cost | 869 | 1,332 | |||||
Interest cost | 5,127 | 4,988 | |||||
Actuarial (gain) loss | 25,099 | (1,020 | ) | ||||
Benefits paid | (8,478 | ) | (4,523 | ) | |||
Settlements | — | (13,887 | ) | ||||
Benefit obligation at end of year | 143,987 | 121,370 | |||||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of year | — | — | |||||
Employer contribution | 8,478 | 18,410 | |||||
Benefits paid | (8,478 | ) | (4,523 | ) | |||
Settlements | — | (13,887 | ) | ||||
Fair value of plan assets at end of year | — | — | |||||
Reconciliation: | |||||||
Funded status | (143,987 | ) | (121,370 | ) | |||
Unrecognized prior service cost | — | — | |||||
Unrecognized net loss | — | — | |||||
Accrued pension cost | $ | (143,987 | ) | $ | (121,370 | ) | |
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Assets for the supplemental plans are held in separate rabbi trusts. At September 30, 2019 and 2018, assets held in the rabbi trusts consisted of equity securities of $44.0 million and $46.5 million, which are included in our fair value disclosures in Note 15.
Net periodic pension cost for the supplemental plans for fiscal 2019, 2018 and 2017 is presented in the following table.
Fiscal Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Components of net periodic pension cost: | |||||||||||
Service cost | $ | 869 | $ | 1,332 | $ | 2,756 | |||||
Interest cost(1) | 5,127 | 4,988 | 4,744 | ||||||||
Recognized actuarial loss(1) | 2,227 | 3,079 | 4,251 | ||||||||
Settlements(1) | — | 4,159 | 2,685 | ||||||||
Net periodic pension cost | $ | 8,223 | $ | 13,558 | $ | 14,436 | |||||
(1) | The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2. |
Estimated Future Benefit Payments
The following benefit payments for our defined benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years:
Pension Plan | Supplemental Plans | ||||||
(In thousands) | |||||||
2020 | $ | 33,238 | $ | 26,197 | |||
2021 | 35,037 | 24,407 | |||||
2022 | 36,128 | 8,978 | |||||
2023 | 37,851 | 9,105 | |||||
2024 | 39,395 | 8,440 | |||||
2025-2029 | 207,634 | 50,187 | |||||
Postretirement Benefits
We sponsor the Retiree Medical Plan for Retirees and Disabled Employees of Atmos Energy Corporation (the Atmos Retiree Medical Plan). This plan provides medical and prescription drug protection to all qualified participants based on their date of retirement. The Atmos Retiree Medical Plan provides different levels of benefits depending on the level of coverage chosen by the participants and the terms of predecessor plans; however, we generally pay 80 percent of the projected net claims and administrative costs and participants pay the remaining 20 percent. Effective January 1, 2015, for employees who had not met the participation requirements by September 30, 2009, the contribution rates for the Company are limited to a three percent cost increase in claims and administrative costs each year, with the participant responsible for the additional costs.
Generally, our funding policy is to contribute annually an amount in accordance with the requirements of ERISA. However, additional voluntary contributions are made annually 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. We expect to contribute between $10 million and $20 million to our postretirement benefits plan during fiscal 2020.
We maintain a formal investment policy with respect to the assets in our postretirement benefits plan to ensure the assets funding the postretirement benefit plan are appropriately invested to maintain an acceptable level of risk. We also consider our current financial status when making recommendations and decisions regarding the postretirement benefits plan.
We currently invest the assets funding our postretirement benefit plan in diversified investment funds which consist of common stocks, preferred stocks and fixed income securities. The diversified investment funds may invest up to 75 percent of assets in common stocks and convertible securities. The following table presents asset allocation information for the postretirement benefit plan assets as of September 30, 2019 and 2018.
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Actual Allocation September 30 | |||
Security Class | 2019 | 2018 | |
Diversified investment funds | 97.1% | 97.5% | |
Cash and cash equivalents | 2.9% | 2.5% | |
Similar to our employee pension and supplemental plans, we review the estimates and assumptions underlying our postretirement benefit plan annually based upon a September 30 measurement date using the same techniques as our employee pension plans. The actuarial assumptions used to determine the pension liability for our postretirement plan were determined as of September 30, 2019 and 2018 and the actuarial assumptions used to determine the net periodic pension cost for the postretirement plan were determined as of September 30, 2018, 2017 and 2016. The assumptions are presented in the following table:
Postretirement Liability | Postretirement Cost | |||||||||||||
2019 | 2018 | 2019 | 2018 | 2017 | ||||||||||
Discount rate | 3.29 | % | 4.38 | % | 4.38 | % | 3.89 | % | 3.73 | % | ||||
Expected return on plan assets | 5.14 | % | 5.33 | % | 5.33 | % | 4.29 | % | 4.45 | % | ||||
Initial trend rate | 6.25 | % | 6.50 | % | 6.50 | % | 7.00 | % | 7.50 | % | ||||
Ultimate trend rate | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | 5.00 | % | ||||
Ultimate trend reached in | 2025 | 2022 | 2022 | 2022 | 2022 | |||||||||
The following table presents the postretirement plan’s benefit obligation and funded status as of September 30, 2019 and 2018:
2019 | 2018 | ||||||
(In thousands) | |||||||
Change in benefit obligation: | |||||||
Benefit obligation at beginning of year | $ | 265,986 | $ | 274,098 | |||
Service cost | 10,810 | 12,078 | |||||
Interest cost | 11,839 | 10,907 | |||||
Plan participants’ contributions | 5,901 | 4,720 | |||||
Actuarial (gain) loss | 39,472 | (17,252 | ) | ||||
Benefits paid | (17,975 | ) | (18,565 | ) | |||
Benefit obligation at end of year | 316,033 | 265,986 | |||||
Change in plan assets: | |||||||
Fair value of plan assets at beginning of year | 199,361 | 184,790 | |||||
Actual return on plan assets | 1,125 | 10,997 | |||||
Employer contributions | 13,489 | 17,419 | |||||
Plan participants’ contributions | 5,901 | 4,720 | |||||
Benefits paid | (17,975 | ) | (18,565 | ) | |||
Fair value of plan assets at end of year | 201,901 | 199,361 | |||||
Reconciliation: | |||||||
Funded status | (114,132 | ) | (66,625 | ) | |||
Unrecognized transition obligation | — | — | |||||
Unrecognized prior service cost | — | — | |||||
Unrecognized net loss | — | — | |||||
Accrued postretirement cost | $ | (114,132 | ) | $ | (66,625 | ) | |
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Net periodic postretirement cost for fiscal 2019, 2018 and 2017 is presented in the following table.
Fiscal Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Components of net periodic postretirement cost: | |||||||||||
Service cost | $ | 10,810 | $ | 12,078 | $ | 12,436 | |||||
Interest cost(1) | 11,839 | 10,907 | 10,679 | ||||||||
Expected return on assets(1) | (10,659 | ) | (8,006 | ) | (7,185 | ) | |||||
Amortization of transition obligation(1) | — | — | — | ||||||||
Amortization of prior service cost (credit)(1) | 173 | 11 | (1,644 | ) | |||||||
Recognized actuarial gain(1) | (8,178 | ) | (6,473 | ) | (2,827 | ) | |||||
Net periodic postretirement cost | $ | 3,985 | $ | 8,517 | $ | 11,459 | |||||
(1) | The components of net periodic cost other than the service cost component are included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income or are capitalized on the consolidated balance sheets as a regulatory asset or liability, as described in Note 2. |
We are currently recovering other postretirement benefits costs through our regulated rates in substantially all of our service areas under accrual accounting as prescribed by accounting principles generally accepted in the United States. Other postretirement benefits costs have been specifically addressed in rate orders in each jurisdiction served by our Kentucky/Mid-States, West Texas, Mid-Tex and Mississippi Divisions as well as our Kansas jurisdiction and APT or have been included in a rate case and not disallowed. Management believes that this accounting method is appropriate and will continue to seek rate recovery of accrual-based expenses in its ratemaking jurisdictions that have not yet approved the recovery of these expenses.
The following tables set forth by level, within the fair value hierarchy, the Retiree Medical Plan’s assets at fair value as of September 30, 2019 and 2018. The methods used to determine fair value for the assets held by the Retiree Medical Plan are fully described in Note 2.
Assets at Fair Value as of September 30, 2019 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In thousands) | |||||||||||||||
Investments: | |||||||||||||||
Money market funds | $ | — | $ | 5,972 | $ | — | $ | 5,972 | |||||||
Registered investment companies | 195,929 | — | — | 195,929 | |||||||||||
Total investments measured at fair value | $ | 195,929 | $ | 5,972 | $ | — | $ | 201,901 | |||||||
Assets at Fair Value as of September 30, 2018 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In thousands) | |||||||||||||||
Investments: | |||||||||||||||
Money market funds | $ | — | $ | 5,003 | $ | — | $ | 5,003 | |||||||
Registered investment companies | 194,358 | — | — | 194,358 | |||||||||||
Total investments measured at fair value | $ | 194,358 | $ | 5,003 | $ | — | $ | 199,361 | |||||||
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Estimated Future Benefit Payments
The following benefit payments paid by us, retirees and prescription drug subsidy payments for our postretirement benefit plans, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years. Company payments for fiscal 2019 include contributions to our postretirement plan trusts.
Company Payments | Retiree Payments | Subsidy Payments | Total Postretirement Benefits | ||||||||||||
(In thousands) | |||||||||||||||
2020 | $ | 18,797 | $ | 3,901 | $ | — | $ | 22,698 | |||||||
2021 | 14,161 | 4,150 | — | 18,311 | |||||||||||
2022 | 14,408 | 4,470 | — | 18,878 | |||||||||||
2023 | 15,277 | 4,939 | — | 20,216 | |||||||||||
2024 | 16,078 | 5,369 | — | 21,447 | |||||||||||
2025-2029 | 89,998 | 32,135 | — | 122,133 | |||||||||||
Defined Contribution Plan
The Atmos Energy Corporation Retirement Savings Plan and Trust (the Retirement Savings Plan) covers substantially all employees and is subject to the provisions of Section 401(k) of the Internal Revenue Code. Effective January 1, 2007, employees automatically become participants of the Retirement Savings Plan on the date of employment. Participants may elect a salary reduction up to a maximum of 65 percent of eligible compensation, as defined by the Plan, not to exceed the maximum allowed by the Internal Revenue Service. New participants are automatically enrolled in the Plan at a contribution rate of four percent of eligible compensation, from which they may opt out. We match 100 percent of a participant’s contributions, limited to four percent of the participant’s salary. Participants are eligible to receive matching contributions after completing one year of service, in which they are immediately vested. Participants are also permitted to take out a loan against their accounts subject to certain restrictions. Employees hired on or after October 1, 2010 participate in the enhanced plan in which participants receive a fixed annual contribution of four percent of eligible earnings to their Retirement Savings Plan account. Participants will continue to be eligible for company matching contributions of up to four percent of their eligible earnings and will be fully vested in the fixed annual contribution after three years of service.
Matching and fixed annual contributions to the Retirement Savings Plan are expensed as incurred and amounted to $16.7 million, $16.2 million and $15.4 million for fiscal years 2019, 2018 and 2017. At September 30, 2019 and 2018, the Retirement Savings Plan held 2.6 percent and 3.2 percent of our outstanding common stock.
9. Stock and Other Compensation Plans
Stock-Based Compensation Plans
Total stock-based compensation cost was $23.9 million, $23.9 million and $23.1 million for the fiscal years ended September 30, 2019, 2018 and 2017. Of this amount, $12.8 million, $11.1 million and $9.0 million was capitalized. Tax benefits related to stock-based compensation were $0.7 million, $2.3 million and $4.4 million for the fiscal years ended September 30, 2019, 2018 and 2017.
1998 Long-Term Incentive Plan
We have a Long-Term Incentive Plan (LTIP), which provides a long-term incentive compensation plan providing for discretionary awards of incentive stock options, non-qualified stock options, stock appreciation rights, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units to certain employees and non-employee directors of the Company and our subsidiaries. The objectives of this plan include attracting and retaining the best available personnel, providing for additional performance incentives and promoting our success by providing employees with the opportunity to acquire common stock.
We were originally authorized to grant awards up to a maximum cumulative amount of 11.2 million shares of common stock under this plan subject to certain adjustment provisions. As of September 30, 2019, non-qualified stock options, bonus stock, time-lapse restricted stock, time-lapse restricted stock units, performance-based restricted stock units and stock units had been issued under this plan, and 1.5 million shares are available for future issuance through September 30, 2021.
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Restricted Stock Units Award Grants
As noted above, the LTIP provides for discretionary awards of restricted stock units to help attract, retain and reward employees of Atmos Energy and its subsidiaries. Certain of these awards vest based upon the passage of time and other awards vest based upon the passage of time and the achievement of specified performance targets. The fair value of the awards granted is based on the market price of our stock at the date of grant. We estimate forfeitures using our historical forfeiture rate. The associated expense is recognized ratably over the vesting period. We use authorized and unissued shares to meet share requirements for the vesting of restricted stock units.
Employees who are granted time-lapse restricted stock units under our LTIP have a nonforfeitable right to dividend equivalents that are paid at the same rate and at the same time at which they are paid on shares of stock without restrictions. Time-lapse restricted stock units contain only a service condition that the employee recipients render continuous services to the Company for a period of three years from the date of grant, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions). There are no performance conditions required to be met for employees to be vested in time-lapse restricted stock units.
Employees who are granted performance-based restricted stock units under our LTIP have a forfeitable right to dividend equivalents that accrue at the same rate at which they are paid on shares of stock without restrictions. Dividend equivalents on the performance-based restricted stock units are paid either in cash or in the form of shares upon the vesting of the award. Performance-based restricted stock units contain a service condition that the employee recipients render continuous services to the Company for a period of three years from the beginning of the applicable three-year performance period, except for accelerated vesting in the event of death, disability, change of control of the Company or termination without cause (with certain exceptions) and a performance condition based on a cumulative earnings per share target amount.
The following summarizes information regarding the restricted stock units granted under the plan during the fiscal years ended September 30, 2019, 2018 and 2017:
2019 | 2018 | 2017 | ||||||||||||||||||
Number of Restricted Units | Weighted Average Grant-Date Fair Value | Number of Restricted Units | Weighted Average Grant-Date Fair Value | Number of Restricted Units | Weighted Average Grant-Date Fair Value | |||||||||||||||
Nonvested at beginning of year | 538,592 | $ | 80.91 | 570,814 | $ | 69.45 | 782,431 | $ | 57.66 | |||||||||||
Granted | 241,472 | 98.25 | 248,710 | 85.62 | 273,497 | 74.15 | ||||||||||||||
Vested | (269,347 | ) | 76.71 | (274,392 | ) | 64.43 | (448,326 | ) | 52.23 | |||||||||||
Forfeited | (7,645 | ) | 86.37 | (6,540 | ) | 74.87 | (36,788 | ) | 63.48 | |||||||||||
Nonvested at end of year | 503,072 | $ | 91.66 | 538,592 | $ | 80.91 | 570,814 | $ | 69.45 | |||||||||||
As of September 30, 2019, there was $13.7 million of total unrecognized compensation cost related to nonvested restricted stock units granted under the LTIP. That cost is expected to be recognized over a weighted average period of 1.6 years. The fair value of restricted stock vested during the fiscal years ended September 30, 2019, 2018 and 2017 was $20.5 million, $17.2 million and $23.4 million.
Other Plans
Direct Stock Purchase Plan
We maintain a Direct Stock Purchase Plan, open to all investors, which allows participants to have all or part of their cash dividends paid quarterly in additional shares of our common stock. The minimum initial investment required to join the plan is $1,250. Direct Stock Purchase Plan participants may purchase additional shares of our common stock as often as weekly with voluntary cash payments of at least $25, up to an annual maximum of $100,000.
Equity Incentive and Deferred Compensation Plan for Non-Employee Directors
We have an Equity Incentive and Deferred Compensation Plan for Non–Employee Directors, which provides non-employee directors of Atmos Energy with the opportunity to defer receipt, until retirement, of compensation for services rendered to the Company and invest deferred compensation into either a cash account or a stock account.
Other Discretionary Compensation Plans
We have an annual incentive program covering substantially all employees to give each employee an opportunity to share in our financial success based on the achievement of key performance measures considered critical to achieving business
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objectives for a given year with minimum and maximum thresholds. The Company must meet the minimum threshold for the plan to be funded and distributed to employees. These performance measures may include earnings growth objectives, improved cash flow objectives or crucial customer satisfaction and safety results. We monitor progress towards the achievement of the performance measures throughout the year and record accruals based upon the expected payout using the best estimates available at the time the accrual is recorded. During the last several fiscal years, we have used earnings per share as our sole performance measure.
10. Details of Selected Financial Statement Captions
The following tables provide additional information regarding the composition of certain financial statement captions.
Balance Sheet
Accounts receivable
Accounts receivable was comprised of the following at September 30, 2019 and 2018:
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Billed accounts receivable | $ | 126,984 | $ | 138,794 | |||
Unbilled revenue | 78,986 | 81,005 | |||||
Contributions in aid of construction receivable | 22,378 | 23,015 | |||||
Other accounts receivable | 18,122 | 25,276 | |||||
Total accounts receivable | 246,470 | 268,090 | |||||
Less: allowance for doubtful accounts | (15,899 | ) | (14,795 | ) | |||
Net accounts receivable | $ | 230,571 | $ | 253,295 | |||
Other current assets
Other current assets as of September 30, 2019 and 2018 were comprised of the following accounts.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Deferred gas costs | $ | 23,766 | $ | 1,927 | |||
Prepaid expenses | 38,895 | 33,233 | |||||
Materials and supplies | 5,916 | 8,106 | |||||
Assets from risk management activities | 1,586 | 1,369 | |||||
Other | 2,609 | 1,420 | |||||
Total | $ | 72,772 | $ | 46,055 | |||
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Property, plant and equipment
Property, plant and equipment was comprised of the following as of September 30, 2019 and 2018:
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Storage plant | $ | 431,286 | $ | 414,857 | |||
Transmission plant | 3,157,316 | 2,851,423 | |||||
Distribution plant | 9,333,011 | 8,141,733 | |||||
General plant | 799,095 | 771,355 | |||||
Intangible plant | 38,191 | 38,280 | |||||
13,758,899 | 12,217,648 | ||||||
Construction in progress | 421,694 | 349,725 | |||||
14,180,593 | 12,567,373 | ||||||
Less: accumulated depreciation and amortization | (2,392,924 | ) | (2,196,226 | ) | |||
Net property, plant and equipment(1) | $ | 11,787,669 | $ | 10,371,147 | |||
(1) | Net property, plant and equipment includes plant acquisition adjustments of $(46.7) million and $(55.5) million at September 30, 2019 and 2018. |
Goodwill
The following presents our goodwill balance allocated by segment and changes in the balance for the fiscal year ended September 30, 2019:
Distribution | Pipeline and Storage | Total | |||||||||
(In thousands) | |||||||||||
Balance as of September 30, 2018 | $ | 587,342 | $ | 143,077 | $ | 730,419 | |||||
Deferred tax adjustments on prior acquisitions(1) | 262 | 25 | 287 | ||||||||
Balance as of September 30, 2019 | $ | 587,604 | $ | 143,102 | $ | 730,706 | |||||
(1) | We annually adjust certain deferred taxes recorded in connection with an acquisition completed in fiscal 2005, which resulted in an increase to goodwill and net deferred tax liabilities of $0.3 million for fiscal 2019. |
Deferred charges and other assets
Deferred charges and other assets as of September 30, 2019 and 2018 were comprised of the following accounts.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Marketable securities | $ | 101,883 | $ | 99,385 | |||
Regulatory assets | 260,220 | 141,778 | |||||
Assets from risk management activities | 225 | 250 | |||||
Pension asset | — | 26,972 | |||||
Tax receivable | 10,099 | 10,099 | |||||
Other | 18,786 | 15,534 | |||||
Total | $ | 391,213 | $ | 294,018 | |||
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Accounts payable and accrued liabilities
Accounts payable and accrued liabilities as of September 30, 2019 and 2018 were comprised of the following accounts.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Trade accounts payable | $ | 176,581 | $ | 135,159 | |||
Accrued gas payable | 36,817 | 48,721 | |||||
Accrued liabilities | 51,626 | 33,403 | |||||
Total | $ | 265,024 | $ | 217,283 | |||
Other current liabilities
Other current liabilities as of September 30, 2019 and 2018 were comprised of the following accounts.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Customer credit balances and deposits | $ | 54,617 | $ | 52,648 | |||
Accrued employee costs | 55,216 | 52,101 | |||||
Deferred gas costs | 14,112 | 94,705 | |||||
Accrued interest | 51,381 | 39,486 | |||||
Liabilities from risk management activities | 4,552 | 56,734 | |||||
Taxes payable | 135,597 | 123,457 | |||||
Pension and postretirement obligations | 26,197 | 10,475 | |||||
Regulatory cost of service reserve | 4,209 | 22,508 | |||||
Regulatory cost of removal obligation | 55,721 | 55,770 | |||||
APT annual adjustment mechanism | 52,856 | 19,918 | |||||
Regulatory excess deferred taxes (See Note 13) | 21,206 | 5,225 | |||||
Other | 3,837 | 14,041 | |||||
Total | $ | 479,501 | $ | 547,068 | |||
Deferred credits and other liabilities
Deferred credits and other liabilities as of September 30, 2019 and 2018 were comprised of the following accounts.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Customer advances for construction | $ | 12,566 | $ | 11,010 | |||
Other regulatory liabilities | 16,120 | 78,599 | |||||
Asset retirement obligation | 17,054 | 12,887 | |||||
Liabilities from risk management activities | 1,249 | 103 | |||||
APT annual adjustment mechanism | 25,545 | 15,310 | |||||
Unrecognized tax benefits | 27,716 | 26,203 | |||||
Other | 20,883 | 13,916 | |||||
Total | $ | 121,133 | $ | 158,028 | |||
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Statement of Comprehensive Income
Other non-operating income (expense)
Other non-operating income (expense) for the fiscal years ended September 30, 2019, 2018 and 2017 were comprised of the following accounts.
Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Equity component of AFUDC | $ | 11,165 | $ | — | $ | — | |||||
Performance-based rate program | 6,737 | 6,745 | 9,240 | ||||||||
Pension and other postretirement non-service credit (cost)(1) | 3,016 | (5,770 | ) | (8,469 | ) | ||||||
Interest income | 4,160 | 1,450 | 1,390 | ||||||||
Donations | (4,771 | ) | (6,053 | ) | (4,413 | ) | |||||
Unrealized loss on equity securities(1) | (1,349 | ) | — | — | |||||||
Miscellaneous | (11,554 | ) | (6,516 | ) | (9,100 | ) | |||||
Total Other non-operating income (expense) | $ | 7,404 | $ | (10,144 | ) | $ | (11,352 | ) | |||
(1) | In accordance with our adoption of new accounting standards, the net periodic non-service credit (cost) and unrealized loss on equity securities are now included in the line item other non-operating income (expense) in the consolidated statements of comprehensive income, as described in Note 2. |
Statement of Cash Flows
Supplemental disclosures of cash flow information for the fiscal years ended September 30, 2019, 2018 and 2017 were as follows:
Year Ended September 30 | |||||||||||
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Cash Paid During The Period For: | |||||||||||
Interest | $ | 184,852 | $ | 169,987 | $ | 156,668 | |||||
Income taxes | $ | 11,467 | $ | 6,102 | $ | 5,264 | |||||
Non-Cash Transactions: | |||||||||||
Capital expenditures included in current liabilities | $ | 149,993 | $ | 112,211 | $ | 116,194 | |||||
11. Leases
We are the lessee for substantially all of our leasing activity, which primarily includes operating leases for towers, office and warehouse space, vehicles and heavy equipment used in our operations. We are also a lessee in a capital lease for office and warehouse space. The remaining lease terms range from one to 21 years and generally provide for the payment of taxes, insurance and maintenance by the lessee. Renewal options exist for certain of these leases.
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The related future minimum lease payments at September 30, 2019 were as follows:
Operating Leases(1) | Capital Lease | ||||||
(In thousands) | |||||||
2020 | $ | 21,017 | $ | 243 | |||
2021 | 20,416 | 248 | |||||
2022 | 19,370 | 253 | |||||
2023 | 18,071 | 258 | |||||
2024 | 15,718 | 263 | |||||
Thereafter | 105,544 | 4,343 | |||||
Total minimum lease payments | $ | 200,136 | 5,608 | ||||
Less amount representing interest | 3,018 | ||||||
Present value of net minimum lease payments | $ | 2,590 | |||||
(1) | Future minimum lease payments do not include amounts for fleet leases and other de minimis items that can be renewed beyond the initial lease term. The Company anticipates renewing the leases beyond the initial term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and therefore are not included above. Expected payments are $17.6 million in 2020, $18.0 million in 2021, $11.8 million in 2022, $8.5 million in 2023, $5.4 million in 2024 and $2.7 million thereafter. |
Consolidated lease and rental expense amounted to $40.4 million, $33.8 million and $32.7 million for fiscal 2019, 2018 and 2017.
12. Commitments and Contingencies
Litigation and Environmental Matters
In the normal course of business, we are subject to various legal and regulatory proceedings. For such matters, we record liabilities when they are considered probable and estimable, based on currently available facts, our historical experience and our estimates of the ultimate outcome or resolution of the liability in the future. While the outcome of these proceedings is uncertain and a loss in excess of the amount we have accrued is possible though not reasonably estimable, it is the opinion of management that any amounts exceeding the accruals will not have a material adverse impact on our financial position, results of operations or cash flows.
We maintain liability insurance for various risks associated with the operation of our natural gas pipelines and facilities, including for property damage and bodily injury. These liability insurance policies generally require us to be responsible for the first $1.0 million (self-insured retention) of each incident.
The National Transportation Safety Board (NTSB) is investigating an incident that occurred at a Dallas, Texas residence on February 23, 2018 that resulted in one fatality and injuries to four other residents. Together with the RRC and the PHMSA, Atmos Energy is a party to the investigation and in that capacity is working closely with the NTSB to help determine the cause of this incident.
On March 29, 2018, a civil action was filed in Dallas, Texas against Atmos Energy in response to the February 23rd incident. In May 2019, the parties resolved the civil action to their mutual satisfaction subject to our self-insured retention noted above.
We are a party to various other litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.
Purchase Commitments
Our distribution 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 the individual contract.
Our Mid-Tex Division maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at prices indexed to natural gas trading hubs. At September 30, 2019, we were committed to purchase 40.1 Bcf within one year and 1.6 Bcf within two to three years under
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indexed contracts. Purchases under these contracts totaled $50.8 million, $57.2 million and $49.7 million for 2019, 2018 and 2017.
Rate Regulatory Proceedings
Except for routine rate regulatory proceedings as discussed in further detail above in the Business — Ratemaking Activity section, there were no material changes to rate regulatory proceedings during the year ended September 30, 2019.
As of September 30, 2019, rate regulatory proceedings were in progress in almost all of our service areas. These regulatory proceedings are discussed in further detail above in the Business — Ratemaking Activity section. Additionally, as discussed in further detail in Note 13, all jurisdictions are addressing impacts of the TCJA.
13. Income Taxes
Income Tax Expense
The components of income tax expense from continuing operations for 2019, 2018 and 2017 were as follows:
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Current | |||||||||||
Federal | $ | — | $ | (10,099 | ) | $ | — | ||||
State | 8,412 | 11,075 | 9,022 | ||||||||
Deferred | |||||||||||
Federal | 113,331 | 150,556 | 197,013 | ||||||||
State | 17,160 | 15,330 | 15,348 | ||||||||
TCJA Impact | — | (158,782 | ) | — | |||||||
$ | 138,903 | $ | 8,080 | $ | 221,383 | ||||||
Reconciliations of the provision for income taxes computed at the statutory rate to the reported provisions for income taxes from continuing operations for 2019, 2018 and 2017 are set forth below:
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Tax at statutory rate(1) | $ | 136,565 | $ | 149,730 | $ | 211,433 | |||||
Common stock dividends deductible for tax reporting | (1,460 | ) | (1,745 | ) | (2,584 | ) | |||||
State taxes (net of federal benefit) | 20,202 | 19,826 | 16,100 | ||||||||
Amortization of excess deferred taxes | (14,085 | ) | (1,219 | ) | — | ||||||
Remeasurement due to TCJA | — | (158,782 | ) | — | |||||||
Other, net | (2,319 | ) | 270 | (3,566 | ) | ||||||
Income tax expense | $ | 138,903 | $ | 8,080 | $ | 221,383 | |||||
(1) | Tax expense is calculated at the statutory federal income tax rate of 21%, 24.5%, 35% for the year ended September 30, 2019, 2018 and 2017. |
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Deferred income taxes reflect the tax effect of differences between the basis of assets and liabilities for book and tax purposes. The tax effect of temporary differences that gave rise to significant components of the deferred tax liabilities and deferred tax assets at September 30, 2019 and 2018 are presented below:
2019 | 2018 | ||||||
(In thousands) | |||||||
Deferred tax assets: | |||||||
Employee benefit plans | $ | 70,929 | $ | 72,745 | |||
Interest rate swaps | 33,918 | 27,135 | |||||
Net operating loss carryforwards | 485,133 | 461,481 | |||||
Charitable and other credit carryforwards | 8,241 | 6,818 | |||||
Regulatory excess deferred tax | 165,701 | 169,947 | |||||
Other | 13,186 | 13,804 | |||||
Total deferred tax assets | 777,108 | 751,930 | |||||
Valuation allowance | (1,894 | ) | (1,465 | ) | |||
Net deferred tax assets | 775,214 | 750,465 | |||||
Deferred tax liabilities: | |||||||
Difference in net book value and net tax value of assets | (2,004,516 | ) | (1,859,787 | ) | |||
Pension funding | (4,384 | ) | (6,986 | ) | |||
Gas cost adjustments | (18,072 | ) | 1,005 | ||||
Other | (48,257 | ) | (38,764 | ) | |||
Total deferred tax liabilities | (2,075,229 | ) | (1,904,532 | ) | |||
Net deferred tax liabilities | $ | (1,300,015 | ) | $ | (1,154,067 | ) | |
Deferred credits for rate regulated entities | $ | 2,582 | $ | 762 | |||
At September 30, 2019, we had $451.8 million of federal net operating loss carryforwards. The federal net operating loss carryforwards are available to offset taxable income and will begin to expire in 2029. The Company also has $10.1 million of federal alternative minimum tax credit carryforwards, which do not expire and are expected to be fully refunded to us between 2020 and 2022 as a result of changes introduced by the TCJA. These credit carryforwards are now reflected as taxes receivable within the deferred charges and other assets line item on our consolidated balance sheet. In addition, the Company has $5.5 million in remeasured charitable contribution carryforwards to offset future taxable income. The Company’s charitable contribution carryforwards expiration period begins in 2020.
The Company also has $33.3 million of state net operating loss carryforwards (net of $8.8 million of federal effects) and $1.8 million of state tax credits carryforwards (net of $0.5 million of federal effects). Depending on the jurisdiction in which the state net operating loss was generated, the carryforwards expiration period begins in 2020.
We believe it is more likely than not that the benefit from certain state net operating loss carryforwards and state credit carryforwards will not be realized. Due to the uncertainty of realizing a benefit from the deferred tax asset recorded for the carryforwards, a valuation allowance of $1.8 million was established for the year ended September 30, 2019.
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At September 30, 2019, we had recorded liabilities associated with unrecognized tax benefits totaling $27.7 million. The following table reconciles the beginning and ending balance of our unrecognized tax benefits:
2019 | 2018 | 2017 | |||||||||
(In thousands) | |||||||||||
Unrecognized tax benefits - beginning balance | $ | 26,203 | $ | 23,719 | $ | 20,298 | |||||
Increase (decrease) resulting from prior period tax positions | (923 | ) | 22 | (366 | ) | ||||||
Increase resulting from current period tax positions | 2,436 | 2,462 | 3,787 | ||||||||
Unrecognized tax benefits - ending balance | 27,716 | 26,203 | 23,719 | ||||||||
Less: deferred federal and state income tax benefits | (5,820 | ) | (5,503 | ) | (8,302 | ) | |||||
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year | $ | 21,896 | $ | 20,700 | $ | 15,417 | |||||
The Company recognizes interest accrued related to unrecognized tax benefits in interest expense and penalties included within interest charges in our consolidated statements of comprehensive income. During the years ended September 30, 2019, 2018 and 2017, the Company recognized approximately $2.2 million, $1.6 million and $1.1 million in interest and penalties. The Company had approximately $7.9 million, $6.1 million and $4.5 million for the payment of interest and penalties accrued at September 30, 2019, 2018 and 2017.
We file income tax returns in the U.S. federal jurisdiction as well as in various states where we have operations. We have concluded substantially all U.S. federal income tax matters through fiscal year 2009 and concluded substantially all Texas income tax matters through fiscal year 2010.
Impact of the Tax Cuts and Jobs Act of 2017
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the "TCJA") was signed into law. As a result of the implementation of the TCJA, we recognized a $158.8 million income tax benefit in our consolidated statement of comprehensive income for the year ended September 30, 2018 related to a change in deferred taxes that were not related to our cost of service ratemaking. The change in deferred taxes related to our cost of service ratemaking (referred to as excess deferred taxes) was reclassified into a regulatory liability and will be returned to ratepayers in accordance with regulatory requirements. As of September 30, 2019 and 2018, this liability totaled $726.3 million and $744.9 million.
We have worked and continue to work with our regulators in each jurisdiction to fully incorporate the effects of the TCJA into customer bills. As of September 30, 2019, we have received approval from regulators to update our cost of service rates to reflect the decrease in the statutory income tax rate in all of our service areas.
Regulators in all of our service areas issued accounting orders that required us to establish, effective January 1, 2018, a separate regulatory liability for the difference in taxes included in our rates that were calculated based on a 35% statutory income tax rate and rates based on the new 21% statutory income tax rate until the new rates could be established. As of September 30, 2019, we received approval from most of our regulators to return these liabilities to customers. This regulatory liability totaled $5.2 million and $22.5 million as of September 30, 2019 and 2018.
As of September 30, 2019, we received approval from regulators to return excess deferred taxes in most of our jurisdictions in accordance with regulatory proceedings on a provisional basis over periods ranging from 13 to 51 years. In our remaining jurisdictions, the treatment of the effects of the TCJA in rates is being addressed in ongoing or will be addressed in future regulatory proceedings.
The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118), which allowed us to record provisional amounts during a one-year measurement period, similar to the measurement period in accounting for business combinations. The Company recorded provisional amounts for the income tax effects of the TCJA for the fiscal year ended September 30, 2018. Although the Company no longer considers the accounting effects of the TCJA to be provisional under SAB 118, many aspects of the TCJA remain unclear and its impact on the Company's income tax balances may change following further interpretation of TCJA provisions by issuance of U.S. Treasury regulations or guidance from the Internal Revenue Service. We continue to monitor and assess the accounting implications of the TCJA developments on the consolidated financial statements.
14. Financial Instruments
We currently use financial instruments to mitigate commodity price risk and in the past have also used financial instruments to mitigate interest rate risk. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause accelerated payments when our financial instruments are in net liability positions.
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As discussed in Note 2 and Note 16, we report our financial instruments as risk management assets and liabilities, each of which is classified as current or noncurrent based upon the anticipated settlement date of the underlying financial instrument. The following table shows the fair values of our risk management assets and liabilities at September 30, 2019 and 2018.
September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Assets from risk management activities, current | $ | 1,586 | $ | 1,369 | |||
Assets from risk management activities, noncurrent | 225 | 250 | |||||
Liabilities from risk management activities, current | (4,552 | ) | (56,734 | ) | |||
Liabilities from risk management activities, noncurrent | (1,249 | ) | (103 | ) | |||
Net liabilities | $ | (3,990 | ) | $ | (55,218 | ) | |
Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
Our distribution gas supply department is responsible for executing this segment’s commodity risk management activities in conformity with regulatory requirements. In jurisdictions where we are permitted to mitigate commodity price risk through financial instruments, the relevant regulatory authorities may establish the level of heating season gas purchases that can be hedged. Historically, if the regulatory authority does not establish this level, we seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2018-2019 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we hedged approximately 33 percent, or approximately 18.9 Bcf of the winter flowing gas requirements at a weighted average cost of approximately $2.86 per Mcf. We have not designated these financial instruments as hedges for accounting purposes.
Interest Rate Risk Management Activities
In fiscal 2014 and 2015, we entered into forward starting interest rate swaps to effectively fix the Treasury yield component associated with $450 million of the anticipated issuance of $450 million unsecured senior notes in fiscal 2019. These notes were issued as planned in March 2019 and we settled the swaps with the payment of $90.1 million. Because the swaps were effective, the realized loss was recorded as a component of AOCI and is being recognized as a component of interest charges over the 30-year life of the senior notes.
As of September 30, 2019, we had $114.7 million of net realized losses in AOCI associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest charges over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2049.
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our consolidated balance sheet and statements of comprehensive income.
As of September 30, 2019, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of September 30, 2019, we had 24,270 MMcf of net long commodity contracts outstanding. These contracts have not been designated as hedges.
Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments as of September 30, 2019 and 2018. The gross amounts of recognized assets and liabilities are netted within our consolidated balance sheets to the extent that we have netting arrangements with the counterparties. However, as of September 30, 2019 and 2018, no gross amounts and no cash collateral were netted within our consolidated balance sheet.
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Balance Sheet Location | Assets | Liabilities | |||||||
(In thousands) | |||||||||
September 30, 2019 | |||||||||
Not Designated As Hedges: | |||||||||
Commodity contracts | Other current assets / Other current liabilities | $ | 1,586 | $ | (4,552 | ) | |||
Commodity contracts | Deferred charges and other assets / Deferred credits and other liabilities | 225 | (1,249 | ) | |||||
Total | 1,811 | (5,801 | ) | ||||||
Gross / Net Financial Instruments | $ | 1,811 | $ | (5,801 | ) | ||||
Balance Sheet Location | Assets | Liabilities | |||||||
(In thousands) | |||||||||
September 30, 2018 | |||||||||
Designated As Hedges: | |||||||||
Interest rate swaps | Other current assets / Other current liabilities | $ | — | $ | (56,499 | ) | |||
Total | — | (56,499 | ) | ||||||
Not Designated As Hedges: | |||||||||
Commodity contracts | Other current assets / Other current liabilities | 1,369 | (235 | ) | |||||
Commodity contracts | Deferred charges and other assets / Deferred credits and other liabilities | 250 | (103 | ) | |||||
Total | 1,619 | (338 | ) | ||||||
Gross / Net Financial Instruments | $ | 1,619 | $ | (56,837 | ) | ||||
Impact of Financial Instruments on the Statement of Comprehensive Income
Cash Flow Hedges
As discussed above, the interest rate agreements we executed in prior years were designated as cash flow hedges when those agreements were executed. The net loss on settled interest rate agreements reclassified from AOCI into interest charges on our consolidated statements of comprehensive income for the years ended September 30, 2019, 2018 and 2017 was $3.9 million, $2.4 million and $1.0 million.
The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), for the years ended September 30, 2019 and 2018. The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the statement of comprehensive income as incurred.
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Fiscal Year Ended September 30 | |||||||
2019 | 2018 | ||||||
(In thousands) | |||||||
Increase (decrease) in fair value: | |||||||
Interest rate agreements | $ | (25,966 | ) | $ | 43,184 | ||
Recognition of losses in earnings due to settlements: | |||||||
Interest rate agreements | 3,022 | 1,752 | |||||
Total other comprehensive income (loss) from hedging, net of tax | $ | (22,944 | ) | $ | 44,936 | ||
Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments. The following amounts, net of deferred taxes, represent the expected recognition in earnings, as of September 30, 2019, of the deferred losses recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments at the date of settlement.
Interest Rate Agreements | |||
(In thousands) | |||
2020 | $ | (4,212 | ) |
2021 | (4,212 | ) | |
2022 | (4,212 | ) | |
2023 | (4,212 | ) | |
2024 | (4,212 | ) | |
Thereafter | (93,655 | ) | |
Total | $ | (114,715 | ) |
Financial Instruments Not Designated as Hedges
As discussed above, commodity contracts which are used in our distribution segment are not designated as hedges. However, there is no earnings impact on our distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statements of comprehensive income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
15. Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2.
Fair value measurements also apply to the valuation of our pension and post-retirement plan assets. The fair value of these assets is presented in Note 8.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2019 and 2018. As required under authoritative accounting literature, assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.
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Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2)(1) | Significant Other Unobservable Inputs (Level 3) | Netting and Cash Collateral | September 30, 2019 | |||||||||||||||
(In thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Financial instruments | $ | — | $ | 1,811 | $ | — | $ | — | $ | 1,811 | |||||||||
Debt and equity securities | |||||||||||||||||||
Registered investment companies | 41,406 | — | — | — | 41,406 | ||||||||||||||
Bond mutual funds | 25,966 | — | — | — | 25,966 | ||||||||||||||
Bonds(2) | — | 31,915 | — | — | 31,915 | ||||||||||||||
Money market funds | — | 2,596 | — | — | 2,596 | ||||||||||||||
Total debt and equity securities | 67,372 | 34,511 | — | — | 101,883 | ||||||||||||||
Total assets | $ | 67,372 | $ | 36,322 | $ | — | $ | — | $ | 103,694 | |||||||||
Liabilities: | |||||||||||||||||||
Financial instruments | $ | — | $ | 5,801 | $ | — | $ | — | $ | 5,801 | |||||||||
Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2)(1) | Significant Other Unobservable Inputs (Level 3) | Netting and Cash Collateral | September 30, 2018 | |||||||||||||||
(In thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Financial instruments | $ | — | $ | 1,619 | $ | — | $ | — | $ | 1,619 | |||||||||
Debt and equity securities | |||||||||||||||||||
Registered investment companies | 42,644 | — | — | — | 42,644 | ||||||||||||||
Bond mutual funds | 21,507 | — | — | — | 21,507 | ||||||||||||||
Bonds(2) | — | 31,400 | — | — | 31,400 | ||||||||||||||
Money market funds | — | 3,834 | — | — | 3,834 | ||||||||||||||
Total debt and equity securities | 64,151 | 35,234 | — | — | 99,385 | ||||||||||||||
Total assets | $ | 64,151 | $ | 36,853 | $ | — | $ | — | $ | 101,004 | |||||||||
Liabilities: | |||||||||||||||||||
Financial instruments | $ | — | $ | 56,837 | $ | — | $ | — | $ | 56,837 | |||||||||
(1) | Our Level 2 measurements consist of over-the-counter options and swaps, which are valued using a market-based approach in which observable market prices are adjusted for criteria specific to each instrument, such as the strike price, notional amount or basis differences, municipal and corporate bonds, which are valued based on the most recent available quoted market prices and money market funds which are valued at cost. |
(2) | Our investments in bonds are considered available-for-sale debt securities in accordance with current accounting guidance as described in Note 2. |
At September 30, 2019 and 2018, our available-for-sale debt securities amortized cost was $31.7 million and $31.5 million. At September 30, 2019 we maintained investments in bonds that have contractual maturity dates ranging from October 2019 through September 2022.
Other Fair Value Measures
In addition to the financial instruments above, we have several financial and nonfinancial assets and liabilities subject to fair value measures. These financial assets and liabilities include cash and cash equivalents, accounts receivable, accounts payable and debt. The nonfinancial assets and liabilities include asset retirement obligations and pension and post-retirement plan assets. We record cash and cash equivalents, accounts receivable, accounts payable and debt at carrying value. For cash and cash equivalents, accounts receivable and accounts payable, we consider carrying value to materially approximate fair value due to the short-term nature of these assets and liabilities.
Our debt is recorded at carrying value. The fair value of our debt is determined using third party market value quotations, which are considered Level 1 fair value measurements for debt instruments with a recent, observable trade or Level 2 fair value
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measurements for debt instruments where fair value is determined using the most recent available quoted market price. The following table presents the carrying value and fair value of our debt as of September 30, 2019:
September 30, 2019 | |||
(In thousands) | |||
Carrying Amount | $ | 3,560,000 | |
Fair Value | $ | 4,216,249 | |
16. Discontinued Operations
On October 29, 2016, we entered into a Membership Interest Purchase Agreement (the Agreement) with CenterPoint Energy Services, Inc., a subsidiary of CenterPoint Energy, Inc. (CES) to sell all of the equity interests of AEM. The transaction closed on January 3, 2017, with an effective date of January 1, 2017. CES paid a cash purchase price of $38.3 million plus working capital of $109.0 million for total cash consideration of $147.3 million. Of this amount, $7.0 million was placed into escrow, to be paid to the Company within 24 months, net of any indemnification claims agreed upon between the two companies. In January 2018, $3.0 million of this escrowed amount was released and received by the Company. In January 2019, the remaining $4.0 million of this escrowed amount was released and received by the Company. We recognized a net gain of $0.03 per diluted share on the sale in the second quarter of fiscal 2017 and completed the working capital true–up during the third quarter of fiscal 2017.
The operating results of our natural gas marketing reportable segment have been reported on the consolidated statements of comprehensive income as income from discontinued operations, net of income tax for the year ended September 30, 2017. Accordingly, expenses related to allocable general corporate overhead and interest expense are not included in these results. The decision to report this segment as a discontinued operation was predicated, in part, on the following qualitative and quantitative factors: 1) the disposal resulted in the company becoming a fully regulated entity; 2) the fact that an entire reportable segment was disposed and 3) the fact the disposed segment represented in excess of 30 percent of consolidated revenues over the last five fiscal years.
The tables below set forth selected financial information related to discontinued operations. Operating expenses include operation and maintenance expense, provision for doubtful accounts, depreciation and amortization expense and taxes, other than income.
The following table presents statement of comprehensive income data related to discontinued operations.
Year Ended September 30, 2017 | |||
(In thousands) | |||
Operating revenues | $ | 303,474 | |
Purchased gas cost | 277,554 | ||
Operating expenses | 7,874 | ||
Operating income | 18,046 | ||
Other nonoperating expense | (211 | ) | |
Income from discontinued operations before income taxes | 17,835 | ||
Income tax expense | 6,841 | ||
Income from discontinued operations | 10,994 | ||
Gain on sale from discontinued operations, net of tax ($10,215) | 2,716 | ||
Net income from discontinued operations | $ | 13,710 | |
The following table presents statement of cash flow data related to discontinued operations.
Year Ended September 30, 2017 | |||
(In thousands) | |||
Depreciation and amortization | $ | 185 | |
Capital expenditures | $ | — | |
Non-cash loss in commodity contract cash flow hedges | $ | (8,165 | ) |
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Significant Accounting Policies Related to Discontinued Operations
Except as noted below, AEM adhered to the same Significant Accounting Policies as described in Note 2.
Revenue recognition — We adopted ASC 606 using the modified retrospective approach so AEM's revenue recognition was not impacted by the adoption of the new standard. Operating revenues for our natural gas marketing segment were recognized in the period in which actual volumes were transported and storage services were provided. Operating revenues for our natural gas marketing segment and the associated carrying value of natural gas inventory (inclusive of storage costs) were recognized when we sold the gas and physically delivered it to our customers. Operating revenues include realized gains and losses arising from the settlement of financial instruments used in our natural gas marketing activities.
Gas stored underground — Gas stored underground was comprised of natural gas injected into storage to conduct the operations of the natural gas marketing segment. Our natural gas marketing segment utilized the average cost method; however, most of this inventory was hedged and was therefore reported at fair value at the end of each month.
Property, plant and equipment — Natural gas marketing property, plant and equipment was stated at cost. Depreciation was generally computed on the straight-line method for financial reporting purposes based upon estimated useful lives ranging from 3 to 30 years.
Financial instruments and hedging activities — In our natural gas marketing segment, we previously designated most of the natural gas inventory held by this operating segment as the hedged item in a fair-value hedge. This inventory was marked to market at the end of each month based on the Gas Daily index, with changes in fair value recognized as unrealized gains or losses in purchased gas cost, which is reflected in income from discontinued operations in the period of change. The financial instruments associated with this natural gas inventory were designated as fair-value hedges and were marked to market each month based upon the NYMEX price with changes in fair value recognized as unrealized gains or losses in purchased gas cost in the period of change. We elected to exclude this spot/forward differential for purposes of assessing the effectiveness of these fair-value hedges.
Additionally, we previously elected to treat fixed-price forward contracts used in our natural gas marketing segment to deliver natural gas as normal purchases and normal sales. As such, these deliveries were recorded on an accrual basis in accordance with our revenue recognition policy. Financial instruments used to mitigate the commodity price risk associated with these contracts were designated as cash flow hedges of anticipated purchases and sales at indexed prices. Accordingly, unrealized gains and losses on these open financial instruments were recorded as a component of accumulated other comprehensive income, and were recognized in earnings as a component of purchased gas cost which is reflected in income from discontinued operations when the hedged volumes were sold.
Gains and losses from hedge ineffectiveness were recognized in the statement of comprehensive income. Fair value and cash flow hedge ineffectiveness arising from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the financial instruments is referred to as basis ineffectiveness. Ineffectiveness arising from changes in the fair value of the fair value hedges due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity is referred to as timing ineffectiveness. Hedge ineffectiveness, to the extent incurred, is reported as a component of purchased gas cost reflected in income from discontinued operations for the year ended September 30, 2017.
Our natural gas marketing segment also utilized master netting agreements with significant counterparties that allow us to offset gains and losses arising from financial instruments that would be settled in cash with gains and losses arising from financial instruments that could be settled with the physical commodity. Assets and liabilities from risk management activities, as well as accounts receivable and payable, reflect the master netting agreements in place. Additionally, the accounting guidance for master netting arrangements requires us to include the fair value of cash collateral or the obligation to return cash in the amounts that have been netted under master netting agreements used to offset gains and losses arising from financial instruments.
Fair Value Measurements — Our discontinued operations used the same fair value measurement policies as described in Note 2 for our continuing operations. Level 1 measurements included primarily exchange-traded financial instruments and gas stored underground that was been designated as the hedged item in a fair value hedge. Within our natural gas marketing operations, we utilized a mid-market pricing convention (the mid-point between the bid and ask prices), as permitted under current accounting standards. Values derived from these sources reflected the market in which transactions involving these financial instruments are executed. Level 2 measurements primarily consisted of non-exchange-traded financial instruments, such as over-the-counter options and swaps.
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Short-term Debt Related to Discontinued Operations
AEM had one uncommitted $25 million 364-day bilateral credit facility that was scheduled to expire on July 31, 2017 and one committed $15 million 364-day bilateral credit facility that was scheduled to expire on September 30, 2017. In connection with the sale of AEM, both facilities were terminated on January 3, 2017.
Commodity Risk Management Activities
Our discontinued natural gas marketing segment was exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. Through December 31, 2016, we managed our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Effective January 1, 2017, as a result of the sale of AEM, these activities were discontinued.
Due to the sale of AEM, we determined that the cash flows associated with our natural gas marketing commodity cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of December 31, 2016. As a result, we reclassified the gain in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of purchased gas cost and recognized a pre-tax gain of $10.6 million, which is included in income from discontinued operations on the consolidated statement of comprehensive income for the year ended September 30, 2017.
The Company's other risk management activities are discussed in Note 14.
Impact of Financial Instruments on the Statement of Comprehensive Income
Hedge ineffectiveness for our natural gas marketing segment was recorded as a component of purchased gas cost, which is included in discontinued operations on the consolidated statement of comprehensive income, and primarily results from differences in the location and timing of the derivative instrument and the hedged item. For the years ended September 30, 2017, we recognized a gain arising from fair value and cash flow hedge ineffectiveness of $3.4 million. Additional information regarding ineffectiveness recognized in the statement of comprehensive income is included in the tables below.
Fair Value Hedges
The impact of our natural gas marketing segment commodity contracts designated as fair value hedges and the related hedged item on the results of discontinued operations on our consolidated statement of comprehensive income for the year ended September 30, 2017 is presented below.
Year Ended September 30, 2017 | |||
(In thousands) | |||
Commodity contracts | $ | (9,567 | ) |
Fair value adjustment for natural gas inventory designated as the hedged item | 12,858 | ||
Total decrease in purchased gas cost reflected in income from discontinued operations | $ | 3,291 | |
The decrease in purchased gas cost reflected in income from discontinued operations is comprised of the following: | |||
Basis ineffectiveness | $ | (597 | ) |
Timing ineffectiveness | 3,888 | ||
$ | 3,291 | ||
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost.
Cash Flow Hedges
The impact of our natural gas marketing segment cash flow hedges on our consolidated statement of comprehensive income for the year ended September 30, 2017 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transactions. Therefore, this presentation is not indicative of the economic margin we realized when the underlying physical and financial transactions were settled.
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Year Ended September 30, 2017 | |||
(In thousands) | |||
Loss reclassified from AOCI for effective portion of natural gas marketing commodity contracts | $ | (2,612 | ) |
Gain arising from ineffective portion of natural gas marketing commodity contracts | 111 | ||
Gain on discontinuance of cash flow hedging of natural gas marketing commodity contracts reclassified from AOCI | 10,579 | ||
Total impact on purchased gas cost reflected in income from discontinued operations | $ | 8,078 | |
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our consolidated statement of comprehensive income for the year ended September 30, 2017 was a decrease in purchased gas cost reflected in income from discontinued operations of $6.8 million, which is included in discontinued operations on the consolidated statements of comprehensive income. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic margin we realized when the underlying physical and financial transactions were settled.
17. Concentration of Credit Risk
Credit risk is the risk of financial loss to us if a customer fails to perform its contractual obligations. We engage in transactions for the purchase and sale of products and services with major companies in the energy industry and with industrial, commercial, residential and municipal energy consumers. These transactions principally occur in the southern and midwestern regions of the United States. We believe that this geographic concentration does not contribute significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the distribution segment is mitigated by the large number of individual customers and the diversity in our customer base. The credit risk for our other segment is not significant.
18. Selected Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data is presented below. The sum of net income per share by quarter may not equal the net income per share for the fiscal year due to variations in the weighted average shares outstanding used in computing such amounts. Our businesses are seasonal due to weather conditions in our service areas. For further information on its effects on quarterly results, see the “Results of Operations” discussion included in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section herein.
Quarter Ended | |||||||||||||||
December 31 | March 31 | June 30 | September 30 | ||||||||||||
(In thousands, except per share data) | |||||||||||||||
Fiscal year 2019: | |||||||||||||||
Operating revenues | |||||||||||||||
Distribution | $ | 838,835 | $ | 1,057,889 | $ | 444,944 | $ | 403,793 | |||||||
Pipeline and storage | 134,470 | 135,650 | 149,198 | 147,706 | |||||||||||
Intersegment eliminations | (95,523 | ) | (98,894 | ) | (108,404 | ) | (107,816 | ) | |||||||
Total operating revenues | 877,782 | 1,094,645 | 485,738 | 443,683 | |||||||||||
Purchased gas cost | 342,165 | 471,676 | 31,326 | 13,670 | |||||||||||
Operating income | 236,464 | 297,677 | 122,202 | 89,715 | |||||||||||
Net Income | 157,646 | 214,888 | 80,466 | 58,406 | |||||||||||
Basic net income per share | $ | 1.38 | $ | 1.83 | $ | 0.68 | $ | 0.49 | |||||||
Diluted net income per share | $ | 1.38 | $ | 1.82 | $ | 0.68 | $ | 0.49 | |||||||
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Quarter Ended | |||||||||||||||
December 31 | March 31 | June 30 | September 30 | ||||||||||||
(In thousands, except per share data) | |||||||||||||||
Fiscal year 2018: | |||||||||||||||
Operating revenues | |||||||||||||||
Distribution | $ | 860,792 | $ | 1,199,291 | $ | 535,488 | $ | 407,476 | |||||||
Pipeline and storage | 126,463 | 120,955 | 127,633 | 132,662 | |||||||||||
Intersegment eliminations | (98,063 | ) | (100,837 | ) | (100,876 | ) | (95,438 | ) | |||||||
Total operating revenues | 889,192 | 1,219,409 | 562,245 | 444,700 | |||||||||||
Purchased gas cost | 366,917 | 626,960 | 130,886 | 43,085 | |||||||||||
Operating income | 242,083 | 270,902 | 124,320 | 90,629 | |||||||||||
Net Income | 314,132 | 178,992 | 71,193 | 38,747 | |||||||||||
Basic net income per share | $ | 2.89 | $ | 1.60 | $ | 0.64 | $ | 0.35 | |||||||
Diluted net income per share | $ | 2.89 | $ | 1.60 | $ | 0.64 | $ | 0.35 | |||||||
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ITEM 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. |
None.
ITEM 9A. | Controls and Procedures. |
Management’s Evaluation of Disclosure Controls and Procedures
We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the Company’s disclosure controls and procedures, as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act). Based on this evaluation, the Company’s principal executive officer and principal financial officer have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2019 to provide reasonable assurance that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms, including a reasonable level of assurance that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f), in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (COSO). Based on our evaluation under the framework in Internal Control-Integrated Framework issued by COSO and applicable Securities and Exchange Commission rules, our management concluded that our internal control over financial reporting was effective as of September 30, 2019, in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Ernst & Young LLP has issued its report on the effectiveness of the Company’s internal control over financial reporting. That report appears below.
/s/ JOHN K. AKERS | /s/ CHRISTOPHER T. FORSYTHE | |
John K. Akers | Christopher T. Forsythe | |
President, Chief Executive Officer and Director | Senior Vice President and Chief Financial Officer | |
November 12, 2019 | ||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atmos Energy Corporation
Opinion on Internal Control over Financial Reporting
We have audited Atmos Energy Corporation’s internal control over financial reporting as of September 30, 2019, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atmos Energy Corporation (the Company) maintained, in all material respects, effective internal control over financial reporting as of September 30, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 consolidated financial statements of the Company and our report dated November 12, 2019 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Dallas, Texas
November 12, 2019
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Changes in Internal Control over Financial Reporting
We did not make any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Act) during the fourth quarter of the fiscal year ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. | Other Information. |
Not applicable.
PART III
ITEM 10. | Directors, Executive Officers and Corporate Governance. |
Information regarding directors and delinquent Section 16(a) reports, if applicable, is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020. Information regarding executive officers is reported below:
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The following table sets forth certain information as of September 30, 2019, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.
Name | Age | Years of Service | Office Currently Held | |||
Kim R. Cocklin | 68 | 13 | Executive Chairman of the Board | |||
Michael E. Haefner | 59 | 11 | President, Chief Executive Officer and Director | |||
Christopher T. Forsythe | 48 | 16 | Senior Vice President and Chief Financial Officer | |||
David J. Park | 48 | 25 | Senior Vice President, Utility Operations | |||
John K. Akers | 56 | 28 | Executive Vice President | |||
Karen E. Hartsfield | 49 | 4 | Senior Vice President, General Counsel and Corporate Secretary | |||
John M. Robbins | 49 | 6 | Senior Vice President, Human Resources | |||
Kim R. Cocklin was named Executive Chairman of the Board on October 1, 2017. From October 1, 2010 through September 30, 2015, Mr. Cocklin served the Company as President and Chief Executive Officer and from October 1, 2015 through September 30, 2017, as Chief Executive Officer. Mr. Cocklin joined the Company in June 2006 and served as President and Chief Operating Officer of the Company from October 1, 2008 through September 30, 2010, after having served as Senior Vice President, Regulated Operations from October 2006 through September 2008. Mr. Cocklin was appointed to the Board of Directors on November 10, 2009.
Michael E. Haefner was named President and Chief Executive Officer, effective October 1, 2017. Mr. Haefner was appointed to the Board of Directors on November 4, 2015. Mr. Haefner joined the Company in June 2008 as Senior Vice President, Human Resources. On January 19, 2015, Mr. Haefner was promoted to Executive Vice President and assumed oversight responsibility for APT, Atmos Energy Holdings, Inc. and the gas supply and services function. On October 1, 2015, Mr. Haefner was promoted to the role of President and Chief Operating Officer in which he also assumed oversight responsibility for the operations of our six utility divisions and customer service. From October 1, 2015 through September 30, 2017, Mr. Haefner served the Company as President and Chief Operating Officer. Mr. Haefner has announced his plans to retire from the Company and the Board of Directors, effective January 1, 2020.
Christopher T. Forsythe was named Senior Vice President and Chief Financial Officer effective February 1, 2017. Mr. Forsythe joined the Company in June 2003 and prior to his promotion, served as the Company's Vice President and Controller from May 2009 through January 2017. Prior to joining Atmos Energy, Mr. Forsythe worked in public accounting for 10 years.
David J. Park was named Senior Vice President of Utility Operations, effective January 1, 2017. In this role, Mr. Park is responsible for the operations of Atmos Energy’s six utility divisions as well as gas supply. Prior to this promotion, Mr. Park served as the President of the West Texas Division from July 2012 to December 2016. Mr. Park also served as Vice President of
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Rates and Regulatory Affairs in the Mid-Tex Division and previously held positions in Engineering and Public Affairs. Mr. Park's years of service include 10 years at a company acquired by Atmos Energy in 2004.
John K. (Kevin) Akers was named President and Chief Executive Officer and was appointed to the Board of Directors effective October 1, 2019. Mr. Akers joined the company in 1991. Mr. Akers assumed increased responsibilities over time and was named President of the Mississippi Division in 2002. He was later named President of the Kentucky/Mid-States Division in May 2007, a position he held until December 2016. Effective January 1, 2017, Mr. Akers was named Senior Vice President, Safety and Enterprise Services and was responsible for customer service, facilities management, safety and supply chain management. In November 2018, Mr. Akers was named Executive Vice President and assumed oversight responsibility for APT.
Karen E. Hartsfield was named Senior Vice President, General Counsel and Corporate Secretary of Atmos Energy, effective August 7, 2017. Ms. Hartsfield joined the Company in June 2015, after having served in private practice for 19 years, most recently as Managing Partner of Jackson Lewis LLP in its Dallas office from July 2013 to June 2015. Prior to joining Jackson Lewis as a partner in January 2009, Ms. Hartsfield was a partner with Baker Botts LLP in Dallas.
John M. (Matt) Robbins was named Senior Vice President, Human Resources, effective January 1, 2017. Mr. Robbins joined the Company in May 2013 and prior to this promotion served as Vice President, Human Resources from February 2015 to December 2016. Before joining Atmos Energy, Mr. Robbins had over 20 years of experience in human resources.
Identification of the members of the Audit Committee of the Board of Directors as well as the Board of Directors’ determination as to whether one or more audit committee financial experts are serving on the Audit Committee of the Board of Directors is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020.
The Company has adopted a code of ethics for its principal executive officer, principal financial officer and principal accounting officer. Such code of ethics is represented by the Company’s Code of Conduct, which is applicable to all directors, officers and employees of the Company, including the Company’s principal executive officer, principal financial officer and principal accounting officer. A copy of the Company’s Code of Conduct is posted on the Company’s website at www.atmosenergy.com, under "Governance" under the "Corporate Responsibility" tab. In addition, any amendment to or waiver granted from a provision of the Company’s Code of Conduct will be posted on the Company’s website also under "Governance" under the "Corporate Responsibility" tab.
ITEM 11. | Executive Compensation. |
Information on executive compensation is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020, under the captions "Human Resources Committee Report," "Compensation Discussion and Analysis," "Other Executive Compensation Matters" and "Named Executive Officer Compensation."
ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
Security ownership of certain beneficial owners and of management is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020, under the heading "Beneficial Ownership of Common Stock." Information concerning our equity compensation plans is provided in Part II, Item 5, “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”, of this Annual Report on Form 10-K.
ITEM 13. | Certain Relationships and Related Transactions, and Director Independence. |
Information on certain relationships and related transactions as well as director independence is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020, under the heading "Corporate Governance and Other Board Matters," "Proposal One – Election of Directors," and "Director Compensation."
ITEM 14. | Principal Accountant Fees and Services. |
Information on our principal accountant’s fees and services is incorporated herein by reference to the Company’s Definitive Proxy Statement for the Annual Meeting of Shareholders on February 5, 2020, under the heading "Proposal Two – Ratification of Appointment of Independent Registered Public Accounting Firm."
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PART IV
ITEM 15. | Exhibits and Financial Statement Schedules. |
(a) 1. and 2. Financial statements and financial statement schedules.
The financial statements and financial statement schedule listed in the Index to Financial Statements in Item 8 are filed as part of this Form 10-K.
3. Exhibits
Exhibit Number | Description | Page Number or Incorporation by Reference to | ||
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession | ||||
2.1 | Membership Interest Purchase Agreement by and between Atmos Energy Holdings, Inc. as Seller and CenterPoint Energy Services, Inc. as Buyer, dated as of October 29, 2016 | |||
Articles of Incorporation and Bylaws | ||||
3.1 | Restated Articles of Incorporation of Atmos Energy Corporation - Texas (As Amended Effective February 3, 2010) | |||
3.2 | Restated Articles of Incorporation of Atmos Energy Corporation - Virginia (As Amended Effective February 3, 2010) | |||
3.3 | Amended and Restated Bylaws of Atmos Energy Corporation (as of February 5, 2019) | |||
Instruments Defining Rights of Security Holders, Including Indentures | ||||
4.1(a) | Specimen Common Stock Certificate (Atmos Energy Corporation) | |||
4.1(b) | ||||
4.2 | Indenture dated as of November 15, 1995 between United Cities Gas Company and Bank of America Illinois, Trustee | |||
4.3 | Indenture dated as of July 15, 1998 between Atmos Energy Corporation and U.S. Bank Trust National Association, Trustee | |||
4.4 | Indenture dated as of May 22, 2001 between Atmos Energy Corporation and SunTrust Bank, Trustee | |||
4.5 | Indenture dated as of March 23, 2009 between Atmos Energy Corporation and U.S. Bank National Corporation, Trustee | |||
4.6(a) | Debenture Certificate for the 6 3/4% Debentures due 2028 | |||
4.6(b) | Global Security for the 5.95% Senior Notes due 2034 | |||
4.6(c) | Global Security for the 5.5% Senior Notes due 2041 | |||
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4.6(d) | Global Security for the 4.15% Senior Notes due 2043 | |||
4.6(e) | Global Security for the 4.125% Senior Notes due 2044 | |||
4.6(f) | Global Security for the 3.000% Senior Notes due 2027 | |||
4.6(g) | Global Security for the 4.125% Senior Notes due 2044 | |||
4.6(h) | Global Security for the 4.300% Senior Notes due 2048 | |||
4.6(i) | Global Security for the 4.300% Senior Notes due 2048 | |||
4.6(j) | Global Security for the 4.125% Senior Notes due 2049 | |||
4.6(k) | Global Security for the 2.625% Senior Notes due 2029 | |||
4.6(l) | Global Security for the 3.375% Senior Notes due 2049 | |||
Material Contracts | ||||
10.1(a) | Revolving Credit Agreement, dated as of September 25, 2015 among Atmos Energy Corporation, the Lenders from time to time parties thereto, Crédit Agricole Corporate and Investment Bank as Administrative Agent, and Mizuho Bank Ltd., as Syndication Agent | |||
10.1(b) | First Amendment to Revolving Credit Agreement, dated as of October 5, 2016, by and among Atmos Energy Corporation, the lenders from time to time parties thereto (the "Lenders") and Credit Agricole Corporate and Investment Bank, in its capacity as administrative agent for the Lenders | |||
10.1(c) | Second Amendment to Revolving Credit Agreement, dated as of September 7, 2017, by and among Atmos Energy Corporation, the lenders from time to time parties thereto (the "Lenders") and Credit Agricole Corporate and Investment Bank, in its capacity as administrative agent for the Lenders | |||
10.2(a) | Equity Distribution Agreement, dated as of November 16, 2018, among Atmos Energy Corporation and the Managers and Forward Purchasers named in Schedule A thereto | |||
10.2(b) | Form of Master Forward Sale Confirmation | |||
10.2(c) | Forward Sale Agreement between Atmos Energy Corporation and Goldman Sachs & Co. LLC dated as of November 28, 2018 | |||
10.2(d) | Forward Sale Agreement between Atmos Energy Corporation and Bank of America, N.A. dated as of November 28, 2018 | |||
10.2(e) | Additional Forward Sale Agreement between Atmos Energy Corporation and Goldman Sachs & Co. LLC dated as of November 29, 2018 | |||
10.2(f) | Additional Forward Sale Agreement between Atmos Energy Corporation and Bank of America, N.A. dated as of November 29, 2018 | |||
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Executive Compensation Plans and Arrangements | ||||
10.3(a)* | Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier I | |||
10.3(b)* | Form of Atmos Energy Corporation Change in Control Severance Agreement - Tier II | |||
10.4(a)* | Atmos Energy Corporation Executive Retiree Life Plan | |||
10.4(b)* | Amendment No. 1 to the Atmos Energy Corporation Executive Retiree Life Plan | |||
10.5* | Atmos Energy Corporation Annual Incentive Plan for Management (as amended and restated October 1, 2016) | |||
10.6(a)* | Atmos Energy Corporation Supplemental Executive Benefits Plan, Amended and Restated in its Entirety August 7, 2007 | |||
10.6(b)* | Form of Individual Trust Agreement for the Supplemental Executive Benefits Plan | |||
10.7(a)* | Atmos Energy Corporation Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016) | |||
10.7(b)* | Atmos Energy Corporation Performance-Based Supplemental Executive Benefits Plan Trust Agreement, Effective Date December 1, 2000 | |||
10.8* | Atmos Energy Corporation Account Balance Supplemental Executive Retirement Plan (As Amended and Restated, Effective as of January 1, 2016) | |||
10.9(a)* | Mini-Med/Dental Benefit Extension Agreement dated October 1, 1994 | |||
10.9(b)* | Amendment No. 1 to Mini-Med/Dental Benefit Extension Agreement dated August 14, 2001 | |||
10.9(c)* | Amendment No. 2 to Mini-Med/Dental Benefit Extension Agreement dated December 31, 2002 | |||
10.10* | Atmos Energy Corporation Equity Incentive and Deferred Compensation Plan for Non-Employee Directors, Amended and Restated as of January 1, 2012 | |||
10.11(a)* | ||||
10.11(b)* | ||||
10.11(c)* | ||||
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10.11(d)* | ||||
10.11(e)* | ||||
Other Exhibits, as indicated | ||||
21 | ||||
23.1 | ||||
24 | Power of Attorney | Signature page of Form 10-K for fiscal year ended September 30, 2019 | ||
31 | ||||
32 | ||||
Interactive Data File | ||||
101.INS | XBRL Instance Document - the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | |||
101.SCH | Inline XBRL Taxonomy Extension Schema | |||
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase | |||
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase | |||
101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase | |||
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | |||
104 | Cover Page Interactive Data File - the cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document | |||
* | This exhibit constitutes a "management contract or compensatory plan, contract, or arrangement." |
** | These certifications pursuant to 18 U.S.C. Section 1350 by the Company’s Chief Executive Officer and Chief Financial Officer, furnished as Exhibit 32 to this Annual Report on Form 10-K, will not be deemed to be filed with the Securities and Exchange Commission or incorporated by reference into any filing by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates such certifications by reference. |
ITEM 16. | Form 10-K Summary. |
Not applicable.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ATMOS ENERGY CORPORATION | ||||
(Registrant) | ||||
By: | /s/ CHRISTOPHER T. FORSYTHE | |||
Christopher T. Forsythe Senior Vice President and Chief Financial Officer | ||||
Date: November 12, 2019
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints John K. Akers and Christopher T. Forsythe, or either of them acting alone or together, as his true and lawful attorney-in-fact and agent with full power to act alone, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
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/s/ KIM R. COCKLIN | Executive Chairman of the Board | November 12, 2019 | ||
Kim R. Cocklin | ||||
/s/ JOHN K. AKERS | President, Chief Executive Officer and Director | November 12, 2019 | ||
John K. Akers | ||||
/s/ CHRISTOPHER T. FORSYTHE | Senior Vice President and Chief Financial Officer | November 12, 2019 | ||
Christopher T. Forsythe | ||||
/s/ RICHARD M. THOMAS | Vice President and Controller (Principal Accounting Officer) | November 12, 2019 | ||
Richard M. Thomas | ||||
/s/ ROBERT W. BEST | Director | November 12, 2019 | ||
Robert W. Best | ||||
/s/ KELLY H. COMPTON | Director | November 12, 2019 | ||
Kelly H. Compton | ||||
/s/ SEAN DONOHUE | Director | November 12, 2019 | ||
Sean Donohue | ||||
/s/ RAFAEL G. GARZA | Director | November 12, 2019 | ||
Rafael G. Garza | ||||
/s/ RICHARD K. GORDON | Director | November 12, 2019 | ||
Richard K. Gordon | ||||
/s/ ROBERT C. GRABLE | Director | November 12, 2019 | ||
Robert C. Grable | ||||
/s/ MICHAEL E. HAEFNER | Director | November 12, 2019 | ||
Michael E. Haefner | ||||
/s/ NANCY K. QUINN | Director | November 12, 2019 | ||
Nancy K. Quinn | ||||
/s/ RICHARD A. SAMPSON | Director | November 12, 2019 | ||
Richard A. Sampson | ||||
/s/ STEPHEN R. SPRINGER | Director | November 12, 2019 | ||
Stephen R. Springer | ||||
/s/ DIANA J. WALTERS | Director | November 12, 2019 | ||
Diana J. Walters | ||||
/s/ RICHARD WARE II | Director | November 12, 2019 | ||
Richard Ware II | ||||
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Schedule II
ATMOS ENERGY CORPORATION
Valuation and Qualifying Accounts
Three Years Ended September 30, 2019
Additions | ||||||||||||||||||||
Balance at beginning of period | Charged to cost & expenses | Charged to other accounts | Deductions | Balance at end of period | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
2019 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 14,795 | $ | 17,633 | $ | — | $ | 16,529 | (1) | $ | 15,899 | |||||||||
2018 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 10,865 | $ | 14,894 | $ | — | $ | 10,964 | (1) | $ | 14,795 | |||||||||
2017 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 11,056 | $ | 12,269 | $ | — | $ | 12,460 | (1) | $ | 10,865 | |||||||||
(1) | Uncollectible accounts written off. |
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