(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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TEXAS AND VIRGINIA 75-1743247
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
THREE LINCOLN CENTRE, SUITE 1800 75240
5430 LBJ FREEWAY, DALLAS, TEXAS (Zip code)
(Address of principal executive offices)
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common stock, No Par Value New York Stock Exchange |
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 [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the registrant was $816,053,202 as of October 31, 2001. On October 31, 2001 the registrant had 40,841,501 shares of common stock outstanding.
Portions of the registrant's Definitive Proxy Statement to be filed for the
Annual Meeting of Shareholders on February 13, 2002 are incorporated by
reference into Part III of this report.
The terms "we," "our," "us" and "Atmos" refer to Atmos Energy Corporation and its subsidiaries, unless the context suggests otherwise. The abbreviations "Mcf," "MMcf" and "Bcf" mean thousand cubic feet, million cubic feet and billion cubic feet.
ITEM 1. BUSINESS
OPERATIONS
We distribute and sell natural gas to approximately 1.4 million residential, commercial, industrial, agricultural and other customers. We operate through five divisions in service areas located in Colorado, Georgia, Illinois, Iowa, Kansas, Kentucky, Louisiana, Missouri, Tennessee, Texas and Virginia. In addition, we transport natural gas for others through our distribution system.
We provide natural gas storage services and own or hold an interest in natural gas storage fields in Kansas, Kentucky and Louisiana to supplement natural gas used by customers in Kansas, Kentucky, Tennessee, Louisiana and other states. We also provide energy management and gas marketing services to industrial customers, municipalities and other local distribution companies. We also provide electrical power generation to meet peak load demands for a municipality regulated by the Tennessee Valley Authority. In addition, we market natural gas to industrial and agricultural customers primarily in West Texas and to industrial customers in Louisiana.
FORMATION
We were organized under the laws of Texas in 1983 as Energas Company, a subsidiary of Pioneer Corporation, for the purposes of owning and operating Pioneer's natural gas distribution business in Texas. Immediately following the transfer by Pioneer to Atmos of its gas distribution business, which Pioneer and its predecessors had operated since 1906, Pioneer distributed our outstanding stock to its shareholders. In September 1988, we changed our name from Energas Company to Atmos Energy Corporation. As a result of the merger with United Cities Gas Company in July 1997, we also became incorporated in Virginia.
RECENT DEVELOPMENTS
Completion of acquisition of remaining equity interest in Woodward Marketing. We acquired a 45 percent interest in Woodward Marketing, L.L.C. in 1997 as a result of the merger of Atmos and United Cities Gas Company, which had acquired that interest in 1995. In April 2001, we acquired the 55 percent interest in Woodward Marketing, L.L.C. that we did not already own in exchange for 1,423,193 restricted shares of our common stock. The consideration is subject to an upward adjustment, based on our share price, of up to 232,547 shares plus an amount of shares to compensate for dividends paid after the completion of the acquisition. As a result of the completion of the acquisition, the guaranty by one of our subsidiaries of Woodward Marketing's $140.0 million short-term working capital and letter of credit facility increased from 45 percent to 100 percent of any amounts outstanding. Under the facility, as of September 30, 2001, $28.0 million was outstanding, and letters of credit totaling $38.8 million had been issued. Since April 1, 2001, our subsidiary has been the sole guarantor of all payables, up to $40.0 million, of Woodward Marketing for natural gas purchases and transportation services.
Completion of acquisition of natural gas operations in Louisiana. In July 2001, we acquired from Citizens Communications Company the natural gas operations of its Louisiana Gas Service Company division and its subsidiary LGS Natural Gas Company for $363.4 million in cash. Upon completion of the acquisition, we became the largest natural gas distributor in Louisiana, and our national customer base increased to about 1.4 million customers, making us the fifth largest pure natural gas local distribution company in the United States.
The acquired operations provide natural gas distribution service to approximately 279,000 residential and commercial meters in communities in southeastern and northern Louisiana. The service territory includes the suburban areas of metropolitan New Orleans (excluding Orleans Parish), the north shore of Lake Pontchar- train and the Monroe/West Monroe metropolitan area. The unregulated operations, which include an intrastate pipeline company, provides gas transportation service to industrial customers and to the acquired operations.
Pending acquisition of Mississippi Valley Gas Company. In September 2001, we entered into a definitive agreement to acquire Mississippi Valley Gas Company, a privately held natural gas utility, for $75.0 million cash, $75.0 million of Atmos common stock and the assumption of approximately $45.0 million of long-term debt. Mississippi Valley Gas provides natural gas distribution service to more than 261,500 residential, commercial, industrial and other customers located primarily in the northern and central regions of Mississippi. Mississippi Valley Gas has a 5,500 mile distribution system and 335 miles of intrastate pipeline. It also has two underground storage facilities with 2.05 Bcf of working gas capacity. The acquisition is subject to state and federal regulatory approval. It is anticipated that the acquisition will be completed in fiscal 2002.
Atmos Power Systems, Inc. constructs power plant. In May 2001, our subsidiary, Atmos Power Systems, Inc., entered into a definitive agreement with the City of Bolivar, Tennessee Electric Department to construct a 20-megawatt electric generating plant and associated facilities. Atmos Power Systems leased the peaking plant to the Electric Department of the City of Bolivar for 10 years, with an option for Bolivar to purchase the plant beginning in the fifth year of the lease. Because of the success of this first project, Atmos is considering other opportunities to build and lease power plants. Although results to date have not been material, we anticipate growth in this type of business.
Acquisition of Southern Resources, IGS and Kentucky storage assets. Woodward Marketing completed the purchases of Southern Resources, Inc. and certain assets of Innovative Gas Services, Incorporated in the fourth quarter of fiscal year 2001 thereby expanding our gas marketing operations. We expect to complete the acquisition of certain storage assets in Kentucky in the first quarter of fiscal year 2002. The acquisition will enable us to provide additional gas storage capacity. Total cost of the acquisitions is approximately $16.0 million in cash.
STRATEGY
Our overall strategy is to:
- deliver superior shareholder value,
- continue to manage our utility operations efficiently,
- profitably grow our non-utility operations to complement our utility operations, and
- profitably grow our business through acquisitions.
We are running our operations efficiently by:
- managing our operating and maintenance expenses,
- leveraging our technology, such as our 24 hour call center, to achieve more efficient operations,
- focusing on regulatory rate proceedings to increase revenue,
- mitigating weather-related risks through weather normalized rates in some jurisdictions and purchasing weather insurance in others, and
- disposing of non-growth assets.
We are growing our non-utility operations by:
- completing the purchase of the remaining interest in Woodward Marketing,
- increasing our non-regulated gas sales, and
- entering into new non-utility businesses, such as distributed electrical power generation.
Our operations are divided into two segments, a utility operations segment, which includes our natural gas distribution and sales operations, and our non-regulated segment, which includes all of our other operations.
UTILITY OPERATIONS SEGMENT OVERVIEW
Our utility operations segment is operated through our five regulated natural gas divisions:
- Atmos Energy Louisiana Gas Company,
- Energas Company,
- Greeley Gas Company,
- United Cities Gas Company, and
- Western Kentucky Gas Company
Atmos Energy Louisiana. Our Atmos Energy Louisiana Gas division includes the operations of the assets of Louisiana Gas Service Company acquired in July 2001 and our previously existing Trans Louisiana Gas division. Our Atmos Energy Louisiana Gas division operates in Louisiana and is regulated by the Louisiana Public Service Commission, which regulates utility services, rates and other matters. In most of the areas in which we operate in Louisiana, we do so pursuant to a non-exclusive franchise granted by the governing authority of each area. Direct sales of natural gas to industrial customers in Louisiana, who use gas for fuel or in manufacturing processes, and sales of natural gas for vehicle fuel are exempt from regulation.
In connection with its review of our acquisition of Louisiana Gas Service, the Louisiana Public Service Commission has approved a rate structure that requires us to share any cost savings that result from the acquisition with the customers of Louisiana Gas Service. The shared cost savings will be the difference between operation and maintenance expense in any future year and the 1998 normalized expense for Louisiana Gas Service, indexed for inflation, annual changes in labor costs and customer growth. The customers are not assured any savings in 2001. In 2002 and in future years, the customers are assured annual savings, which will be indexed for inflation, annual changes in labor costs and customer growth. The sharing mechanism will remain in place for 20 years subject to established modification procedures.
The rates of Louisiana Gas Service are subject to a purchased gas adjustment clause that allows it to pass changes in gas costs on to its customers. In addition, on January 29, 2001, the Louisiana Public Service Commission approved a rate stabilization clause for Louisiana Gas Service for a three-year period beginning January 1, 2001. Under the rate stabilization clause, Louisiana Gas Service will be allowed to earn a return on equity within certain ranges that will be monitored on an annual basis. After the completion of the acquisition of Louisiana Gas Service, our Atmos Energy Louisiana division also became subject to the adjustment and stabilization clause.
Louisiana Gas Service is currently involved in a proceeding with the Louisiana Public Service Commission relating to past costs associated with the purchase of gas that it charged to its customers. Although, after completion of the acquisition, we took over the defense of this proceeding and will have responsibility for any finding of liability on the part of Louisiana Gas Service, we believe the outcome of this proceeding will not have a material adverse impact on our operations as Citizens has agreed to fully indemnify us for any liability as a result of this proceeding.
The Louisiana Public Service Commission approved a Rate Stabilization Clause for three years for our former Trans La Division with an allowed return on common equity between 10.5 percent and 11.5 percent. This decision increased the service charge amounts from about 20 percent to about 70 percent of actual costs and increased the monthly customer charges from $6 to $9, both effective November 1, 1999.
Energas. Our Energas division operates in Texas. The governing body of each municipality we serve has original jurisdiction over all utility rates, operations and services within its city limits, except with respect to sales of natural gas for vehicle fuel and agricultural use. We operate pursuant to non-exclusive franchises granted by the municipalities we serve, which are subject to renewal from time to time. The Railroad Commission of Texas has exclusive appellate jurisdiction over all rate and regulatory orders and ordinances of the municipalities and exclusive original jurisdiction over rates and services to customers not located within the limits of a municipality. The Railroad Commission is currently conducting a gas cost audit of all local distribution companies in Texas, including Energas, in response to the high gas costs this past winter. At and for the year ended September 30, 2001, we had 314,734 utility meters in service and total throughput of 53,586 MMcf. At and for the year ended September 30, 2000, we had 302,662 utility meters in service and total throughput of 53,922 MMcf.
Greeley Gas. Our Greeley Gas division operates in Colorado, Kansas and Missouri and is regulated by the respective states' public service commission with respect to accounting, rates and charges, operating matters and the issuance of securities. We operate under terms of non-exclusive franchises granted by the various cities. At and for the year ended September 30, 2001, Greeley had 212,484 utility meters in service and total throughput of 37,797 MMcf. At and for the year ended September 30, 2000, Greeley had 207,161 meters in service and total throughput of 34,455 MMcf.
United Cities. Our United Cities Gas division operates in Georgia, Illinois, Iowa, Missouri, Tennessee and Virginia. In each of these states, our rates, services and operations as a natural gas distribution company are subject to general regulation by each state's public service commission. We operate in each community, where necessary, under a franchise granted by the municipality for a fixed term of years. In Tennessee and Georgia, we have performance based rates, which provide incentives for us to find ways to lower costs. Any cost savings are then shared with our customers. We also have weather normalization adjustments to our rates in Tennessee and Georgia. At and for the year ended September 30, 2001, United Cities had 308,394 utility meters in service and total throughput of 64,924 MMcf. At and for the year ended September 30, 2000, United Cities had 312,018 meters in service and total throughput of 56,698 MMcf.
Western Kentucky Gas. Our Western Kentucky Gas division operates in Kentucky and is regulated by the Kentucky Public Service Commission, which regulates utility services, rates, issuance of securities and other matters. We operate in the various incorporated cities pursuant to non-exclusive franchises granted to us by these cities. Sales of natural gas for use as vehicle fuel in Kentucky are unregulated. We have been operating under a performance based rate program since July 1998. We also have weather normalization adjustments to our rates in Kentucky. At and for the year ended September 30, 2001, Western Kentucky Gas had 182,275 utility meters in service and total throughput of 46,530 MMcf. At and for the year ended September 30, 2000, Western Kentucky Gas had 181,066 meters in service and total throughput of 47,129 MMcf.
NON-REGULATED SEGMENT OVERVIEW
Our non-regulated segment is primarily composed of the following three parts:
- Atmos Energy Marketing, LLC. Atmos Energy Marketing provides a variety of natural gas management services to natural gas utility systems and industrial natural gas consumers in several states and to our Atmos Energy Louisiana Gas, Greeley Gas, United Cities Gas and Western Kentucky Gas divisions. These services consist primarily of acquisition and provision of natural gas supplies at fixed and market-based prices, load forecasting and management, gas storage and transportation services, peaking sales and balancing services and gas price hedging through the use of derivative products. Woodward Marketing, L.L.C. is a wholly owned subsidiary of Atmos Energy Marketing.
- Atmos Power Systems, Inc. Atmos Power Systems constructs and operates electrical power generating plants and associated facilities. Atmos Power Systems may also enter into agreements to either lease or sell such plants.
WOODWARD MARKETING ACTIVITIES
We acquired a 45 percent interest in Woodward Marketing, L.L.C. in 1997 as a result of the merger of Atmos and United Cities Gas Company, which had acquired that interest in 1995. In April 2001, we acquired the 55 percent interest that we did not own from J.D. Woodward and others for 1,423,193 restricted shares of our common stock. Immediately following the acquisition, Mr. Woodward was elected as a Senior Vice President of Atmos in charge of all non-regulated business activities, a position he has held since April 2001. Prior to that time, Mr. Woodward had not been an officer or employee of Atmos.
The principal business of Woodward Marketing, including the activities of Trans Louisiana Industrial Gas Company, Inc., is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the Southwestern and Midwestern United States. This business involves the sale of natural gas by Woodward Marketing to its customers and the management of storage and transportation contracts for its customers under contracts generally having one to two-year terms. At September 30, 2001, Woodward Marketing had a total of 78 municipal and local gas utility customers and 195 industrial customers. Woodward Marketing also sells natural gas to certain of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. In addition, Woodward Marketing supplies us with a portion of our natural gas requirements on a competitive bid basis.
In the management of natural gas requirements for municipal and other local utilities, Woodward Marketing sells physical natural gas for future delivery and hedges the associated price risk through the use of gas futures, including forwards, over-the-counter and exchange-traded options, and swap contracts with counterparties. These financial contracts are marked-to-market at the daily close of business. Woodward Marketing links gas futures to physical delivery of natural gas and balances its futures positions at the end of each trading day. Over-the-counter swap agreements require Woodward Marketing to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Woodward Marketing uses these futures and swaps to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas, which are also carried on a mark to market basis. Options held to hedge price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. Woodward Marketing uses options to manage margins and to limit overall price risk exposure.
Energy related services provided by Woodward Marketing include the sale of natural gas to its various customer classes and management of transportation and storage assets and inventories. More specifically, energy services include contract negotiation and administration, load forecasting, storage acquisition, natural gas purchase and delivery and capacity utilization strategies. In providing these services, Woodward Marketing generates income from its utility, municipal and industrial customers through negotiated prices based on the volume of gas supplied to the customer. Woodward Marketing also generates income by taking advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices by utilizing storage and transportation capacity that it controls.
Woodward Marketing also engages in limited speculative natural gas trading
for its own account, subject to a risk management policy established by us which
limits the level of trading loss in any fiscal year to a maximum of 25 percent
of the budgeted annual operating income of Woodward Marketing. Compliance with
such risk management policy is monitored on a daily basis. In addition, Woodward
Marketing's bank credit facility limits trading positions that are not closed at
the end of the day (open positions) to 2.5 Bcf of natural gas. At September 30,
2001, Woodward Marketing's open positions in its trading operations totaled 2.3
Bcf. In its speculative trading, Woodward Marketing's open trading positions are
monitored on a daily basis but are
Financial instruments, which subject Woodward Marketing to counterparty risk, consist primarily of financial instruments arising from trading and risk management activities and overnight repurchase agreements that are not insured. Counterparty risk is the risk of loss from nonperformance by financial counterparties to a contract. Exchange-traded future and option contracts are generally guaranteed by the exchanges.
Woodward Marketing's operations are concentrated in the natural gas industry, and its customers and suppliers may be subject to economic risks affecting that industry.
OPERATING STATISTICS
The following table shows the operating statistics of Atmos for each of the five fiscal years from 1997 through 2001. It is followed by two additional tables that show utility only sales and operating statistics by business unit for 2001 and 2000. Certain prior year amounts have been reclassified to conform with the current year presentation.
YEAR ENDED SEPTEMBER 30,
--------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
METERS IN SERVICE, end of year
Residential......................... 1,243,625 970,873 919,012 889,074 870,747
Commercial.......................... 122,274 104,019 98,268 94,302 92,703
Industrial (including
agricultural)..................... 13,020 14,259 14,329 16,322 17,217
Public authority and other.......... 7,404 7,448 6,386 4,834 4,781
---------- ---------- ---------- ---------- ----------
Total meters...................... 1,386,323 1,096,599 1,037,995 1,004,532 985,448
Propane customers(1)................ -- -- 39,539 37,400 29,097
---------- ---------- ---------- ---------- ----------
Total............................. 1,386,323 1,096,599 1,077,534 1,041,932 1,014,545
========== ========== ========== ========== ==========
HEATING DEGREE DAYS(2)
Actual (weighted average)........... 2,753 2,096 3,374 3,799 3,909
Percent of normal................... 107% 82% 85% 95% 98%
SALES VOLUMES -- MMcf
Residential......................... 79,000 63,285 67,128 73,472 75,215
Commercial.......................... 36,922 30,707 31,457 36,083 37,382
Industrial(including
agricultural)..................... 33,730 38,687 35,741 44,881 46,416
Public authority and other.......... 6,892 5,520 5,793 4,937 5,195
---------- ---------- ---------- ---------- ----------
Total sales volumes............... 156,544 138,199 140,119 159,373 164,208
Transportation volumes -- MMcf........ 61,230 59,365 55,468 56,224 48,800
---------- ---------- ---------- ---------- ----------
TOTAL THROUGHPUT -- MMcf.............. 217,774 197,564 195,587 215,597 213,008
========== ========== ========== ========== ==========
PROPANE -- Gallons (000's)(1)......... -- 19,329 22,291 23,412 25,204
========== ========== ========== ========== ==========
OPERATING REVENUES (000's)
Gas sales revenues
Residential......................... $ 788,902 $ 405,552 $ 349,691 $ 410,538 $ 452,864
Commercial.......................... 342,945 176,712 144,836 184,046 193,302
Industrial (including
agricultural)..................... 208,168 171,447 117,382 161,382 168,386
Public authority and other.......... 58,539 27,198 22,330 20,504 23,898
---------- ---------- ---------- ---------- ----------
Total gas sales revenues.......... 1,398,554 780,909 634,239 776,470 838,450
Transportation revenues............... 28,668 23,610 23,101 23,971 19,885
Other gas revenues.................... 10,925 4,674 4,500 8,121 6,385
---------- ---------- ---------- ---------- ----------
Total gas revenues................ 1,438,147 809,193 661,840 808,562 864,720
Propane revenues(1)................... -- 22,550 22,944 29,091 33,194
Other revenues........................ 4,128 18,409 5,412 10,555 8,921
---------- ---------- ---------- ---------- ----------
Total operating revenues.......... $1,442,275 $ 850,152 $ 690,196 $ 848,208 $ 906,835
========== ========== ========== ========== ==========
AVERAGE SALES PRICE/Mcf............... $ 8.93 $ 5.65 $ 4.53 $ 4.87 $ 5.11
AVERAGE COST OF GAS/Mcf SOLD.......... 6.83 3.79 2.79 3.24 3.51
AVERAGE TRANSPORTATION
REVENUES/Mcf...................... .47 .40 .42 .43 .41
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See footnotes following these tables.
YEAR ENDED SEPTEMBER 30, 2001
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ATMOS
ENERGY UNITED WESTERN TOTAL
LOUISIANA ENERGAS GREELEY CITIES KENTUCKY UTILITY
--------- -------- -------- -------- -------- ----------
METERS IN SERVICE, at end of
year
Residential............... 344,870 273,850 192,056 271,233 161,616 1,243,625
Commercial................ 22,650 27,128 18,376 35,518 18,602 122,274
Industrial................ -- 11,498 414 711 397 13,020
Public authority and
other.................. 916 2,258 1,638 932 1,660 7,404
-------- -------- -------- -------- -------- ----------
Total.................. 368,436 314,734 212,484 308,394 182,275 1,386,323
======== ======== ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual.................... 2,076 3,782 6,041 1,315 4,534 2,753
Percent of normal......... 117% 107% 106% 104% 104% 107%
SALES VOLUMES -- MMcf(4)
Residential............... 5,257 22,905 18,027 19,978 12,833 79,000
Commercial................ 2,448 7,992 6,845 13,968 5,669 36,922
Industrial................ -- 8,395 1,224 10,473 3,018 23,110
Public authority and
other.................. 919 2,618 1,497 339 1,519 6,892
-------- -------- -------- -------- -------- ----------
Total.................. 8,624 41,910 27,593 44,758 23,039 145,924
TRANSPORTATION
VOLUMES -- MMcf(4)........ 3,954 11,676 10,204 20,166 23,491 69,491
-------- -------- -------- -------- -------- ----------
TOTAL THROUGHPUT --
MMcf(4)................... 12,578 53,586 37,797 64,924 46,530 215,415
======== ======== ======== ======== ======== ==========
OTHER STATISTICS
Operating revenues
(000's)................ $ 96,511 $311,414 $270,678 $464,498 $237,047 $1,380,148
Miles of pipe............. 7,934 13,345 6,344 7,536 3,779 38,938
Employees(5).............. 488 342 272 470 247 1,819
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See footnotes following these tables.
YEAR ENDED SEPTEMBER 30, 2000
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ATMOS
ENERGY UNITED WESTERN TOTAL
LOUISIANA ENERGAS GREELEY CITIES KENTUCKY UTILITY
--------- -------- -------- -------- -------- ----------
METERS IN SERVICE, at end of
year
Residential................ 74,943 273,664 187,121 274,580 160,565 970,873
Commercial................. 5,568 26,231 17,946 35,808 18,466 104,019
Industrial................. -- 513 406 660 407 1,986
Public authority and
other................... 908 2,254 1,688 970 1,628 7,448
------- -------- -------- -------- -------- ----------
Total................... 81,419 302,662 207,161 312,018 181,066 1,084,326
======= ======== ======== ======== ======== ==========
HEATING DEGREE DAYS(2)
Actual..................... 1,237 2,875 4,678 1,130 3,702 2,096
Percent of normal.......... 69% 81% 82% 89% 85% 81%
SALES VOLUMES -- MMcf(4)
Residential................ 3,070 19,201 14,727 14,703 11,584 63,285
Commercial................. 1,379 6,365 5,829 12,102 5,032 30,707
Industrial................. -- 1,651 1,927 13,191 3,189 19,958
Public authority and
other................... 751 2,026 1,216 228 1,299 5,520
------- -------- -------- -------- -------- ----------
Total................... 5,200 29,243 23,699 40,224 21,104 119,470
TRANSPORTATION
VOLUMES -- MMcf(4)......... 2,248 24,679 10,756 16,474 26,025 80,182
------- -------- -------- -------- -------- ----------
TOTAL THROUGHPUT
-- MMcf(4)................ 7,448 53,922 34,455 56,698 47,129 199,652
======= ======== ======== ======== ======== ==========
OTHER STATISTICS
Operating revenues
(000's)................. $45,469 $146,100 $147,116 $280,029 $121,237 $ 739,951
Miles of pipe.............. 2,283 13,169 6,000 5,140 3,437 30,029
Employees(5)............... 123 350 271 495 249 1,488
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See footnotes following these tables.
Notes to preceding tables:
(1) Prior to August 2000, propane revenues and expenses were fully consolidated. Subsequent to August 2000, the results of propane are shown on the equity basis.
(2) A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the natural gas industry to measure the relative coldness of weather experienced and to compare relative temperatures between one geographic area and another. Normal degree days are based on 30-year average National Weather Service data for selected locations. Degree day information for 2001 and 2000 are presented excluding service areas with weather normalized operations. Degree day information for 1999, 1998 and 1997 does not exclude service areas with weather normalized operations as that information was not available.
(3) These tables present data for our five utility business units. Their operations include the regulated local distribution companies located in their respective service areas. The operations of Louisiana Gas are included in Atmos Energy Louisiana since July 1, 2001, the date of acquisition.
(4) Utility sales volumes and revenues reflect utility segment operations, including intercompany sales and transportation amounts.
(5) The number of employees excludes 480 and 369 Atmos shared services and customer support center employees and 62 and 28 non-utility employees in 2001 and 2000.
SEGMENT OVERVIEW
We consider each business unit within our utility segment to be a reporting unit of the utility segment and not a reportable segment. Our chief executive officer makes decisions about allocating resources to the utility segment as a whole and not to individual reporting units.
The following table summarizes certain information regarding the operations of the utility and non-regulated segments of Atmos as of and for each of the three years ended September 30, 2001. The information is net of intersegment eliminations.
NON-
UTILITY REGULATED TOTAL
---------- --------- ----------
(IN THOUSANDS)
2001
Operating revenues.............................. $1,378,159 $ 64,116 $1,442,275
Operating income................................ 127,980 2,301 130,281
Net income...................................... 49,881 6,209 56,090
Identifiable assets............................. 1,732,296 303,884 2,036,180
2000
Operating revenues.............................. $ 734,835 $115,317 $ 850,152
Operating income................................ 77,207 8,109 85,316
Net income...................................... 22,459 13,459 35,918
Identifiable assets............................. 1,246,782 101,976 1,348,758
1999
Operating revenues.............................. $ 617,313 $ 72,883 $ 690,196
Operating income................................ 49,000 5,239 54,239
Net income...................................... 10,800 6,944 17,744
Identifiable assets............................. 1,125,691 104,846 1,230,537
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The utility segment is composed of our five regulated utility divisions:
the Atmos Energy Louisiana Gas Division which operates in Louisiana, the Energas
Division which operates in Texas, the Greeley Gas Division which operates in
Colorado, Kansas and Missouri, the United Cities Gas Division which operates in
Georgia, Illinois, Iowa, Missouri, Tennessee and Virginia and the Western
Kentucky Gas Division which operates in Kentucky. For further discussion on the
utility segment operations, see "Utility Operations Segment Overview".
For a further discussion of our non-regulated segment operations see "Non-Regulated Segment Overview".
GAS SALES
Our natural gas distribution business is seasonal and highly dependent on weather conditions in our service areas. Gas sales to residential and commercial customers are greater during the winter months than during the remainder of the year. The volumes of gas sales during the winter months will vary with the temperatures during these months. The seasonal nature of our sales to residential and commercial customers is partially offset by our sales in the spring and summer months to our agricultural customers in Texas, Colorado and Kansas who use natural gas to operate irrigation equipment.
In addition to weather, our revenues are affected by the cost of natural gas and economic conditions in the areas that we serve. Higher gas costs, which we are generally able to pass through to our customers under purchased gas adjustment clauses, may cause customers to conserve, or, in the case of industrial customers, to use alternative energy sources.
To protect against volatility in gas prices, we are hedging gas costs for the 2001-2002 heating season by utilizing a combination of financial tools and fixed forward physical contracts to stabilize gas prices. For the 2001-2002 heating season, we plan to cover approximately 64 percent of our anticipated requirements through storage and hedging instruments. The gas hedges should help moderate the effects of higher customer accounts receivable caused by higher gas prices.
We also have weather normalization adjustments in our rate jurisdictions in Tennessee, Georgia and Kentucky. We purchased weather hedges for our Texas and Louisiana operations effective for the 2000-2001 heating season. We also purchased a three-year weather insurance policy for our Texas and Louisiana operations commencing with the 2001-2002 heating season, with an option to cancel in the third year. The policy covers the entire heating season of October to March. See "Weather and seasonality" in Management's Discussion and Analysis of Operations.
Our distribution systems have experienced aggregate peak day deliveries of approximately 2.0 Bcf per day. We have the ability to curtail deliveries to certain customers under the terms of interruptible contracts and applicable state statutes or regulations which enable us to maintain our deliveries to high priority customers. We have not imposed curtailment in our Energas Division since we began independent operations in 1983 or in our Atmos Energy Louisiana Gas Division since we acquired Trans Louisiana Gas Company in 1986 and Louisiana Gas Service in 2001. The Western Kentucky Gas Division curtailed deliveries to certain interruptible customers during exceptionally cold periods in December 1989, January 1994 and during the winter of 1996. Neither the Greeley Gas Division nor its predecessor, Greeley Gas Company, has curtailed deliveries to its sales customers since prior to 1980. The United Cities Gas Division curtails interruptible service customers from time to time each year in accordance with the interruptible contracts and tariffs.
GAS SUPPLY
We receive gas deliveries through 35 pipeline transportation companies, both interstate and intrastate, to satisfy our sales market requirements. 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 Western Kentucky Gas Division's gas supply is delivered primarily by the following pipelines: Williams Pipeline-Texas Gas, Tennessee Gas, Trunkline, Midwestern Pipeline and ANR. During 1998, the Western Kentucky Gas Division sought and was granted approval by the Kentucky Public Service Commission for a performance-based rate program which commenced in July 1998. Under the performance-based program, we and our customers jointly share in any actual gas cost savings achieved when compared to pre-determined benchmarks. We also have similar gas cost performance-based rate mechanisms in Georgia and Tennessee.
The United Cities Gas Division is served by 13 interstate pipelines. The majority of the volumes are transported through East Tennessee Pipeline, Southern Natural Gas, Tennessee Gas Pipeline and Columbia Gulf.
Colorado Interstate Gas Company, Williams Pipeline-Central, Public Service Company of Colorado and Northwest Pipeline are the principal transporters of the Greeley Gas Division's requirements. Additionally, the Greeley Gas Division purchases substantial volumes from producers that are connected directly to its distribution system.
Louisiana Intrastate Gas Company, Acadian Pipeline, Gulf South and Williams Pipeline-Texas Gas pipelines deliver most of the Atmos Energy Louisiana Gas Division's requirements.
We also own or hold an interest in and operate numerous natural gas storage facilities in Kentucky, Kansas and Louisiana which are used to help meet customer requirements during peak demand periods and to reduce the need to contract for additional pipeline capacity to meet such peak demand periods. Additionally, we operate one propane plant and a liquified natural gas plant for peak shaving purposes. We also contract for storage service in underground storage facilities on many of the interstate pipelines serving us. See "Item 2. Properties" below for further information regarding the peak shaving facilities.
We normally inject gas into pipeline storage systems and company owned storage facilities during the summer months and withdraw it in the winter months. Our underground storage facilities in Kansas, Kentucky and Louisiana have a combined maximum daily output capability of approximately 226,000 Mcf.
We purchase our gas supply from various producers and marketers. Supply arrangements are contracted on a firm basis with various terms at market prices. The firm supply consists of both base load and swing supply quantities. 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 suppliers through a competitive bidding process by sending out a request for proposal to 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 and the best cost. Major suppliers during fiscal 2001 were Reliant Energy, Sonat Marketing, Cinergy, Pioneer Natural Resources, Texaco, Woodward Marketing, ONEOK Gas Marketing, Aquila, BP Energy, Enron, Enbridge, Anadarko and Tenaska Marketing. We do not anticipate problems with securing additional gas supply as needed for our customers.
REGULATION
Each of our utility divisions is 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 gas distribution facilities. Our distribution operations are also subject to various state and federal laws regulating environmental matters. From time to time we receive inquiries regarding various environmental matters. We believe that our properties and operations substantially comply with and are operated in substantial conformity with applicable safety and environmental statutes and regulations. There are no administrative or judicial proceedings arising under environmental quality statutes pending or known to be contemplated by governmental agencies which would have a material adverse effect on us or our operations.
RATES
The method of determining regulated rates varies among the states in which we operate. The regulators have the responsibility of ensuring that utilities under their jurisdiction operate in the best interests of customers while providing the utilities the opportunity to earn a reasonable return on investment. In a general rate case, the applicable regulatory authority, which is typically the state public utility commission, establishes a base margin, which is the amount of revenue authorized to be collected from customers to recover authorized operating expense (other than the cost of gas), depreciation, interest, taxes and return on rate base. The divisions in our utility operations segment perform annual deficiency studies for each rate jurisdiction to determine when to file rate cases, which are typically filed every two to five years.
Substantially all of the sales charged by us to our customers fluctuate with the cost of gas purchased by us. Rates established by regulatory authorities are adjusted for increases and decreases in our purchased gas cost through purchased gas adjustment mechanisms. Purchased gas adjustment mechanisms provide gas utilities a method of recovering purchased gas costs on an ongoing basis without the necessity of a rate case addressing all of the utilities' non-gas costs. These mechanisms are commonly utilized when regulatory authorities recognize a particular type of expense, such as purchased gas costs, that (i) is subject to significant price fluctuations compared to the utility's other costs, (ii) represents a large component of the utility's cost of service and (iii) is generally outside the control of the gas utility. Such purchased gas adjustment mechanisms are not designed to allow the utility to earn a profit but are designed to allow a dollar-for-dollar recovery of fuel costs. Therefore, while our operating revenues may fluctuate, gross profit (which is defined as operating revenues less purchased gas cost) is generally not eroded or enhanced because of gas cost increases or decreases.
Approximately 96 percent of our revenues in the fiscal year ended September 30, 2001, and approximately 87 percent of our revenues in fiscal 2000 were derived from sales at rates set by or subject to approval by local or state authorities. Generally, the regulatory authority reviews our rate request and establishes a rate structure intended to generate revenue sufficient to cover our costs of doing business and provide a reasonable return on invested capital.
The following table sets forth major rate requests made by us or other parties during the most recent five years and the action taken on such requests:
AMOUNT
EFFECTIVE AMOUNT RECEIVED
JURISDICTION DATE REQUESTED (REDUCED)
------------ --------- --------- ---------
(IN THOUSANDS)
Texas
West Texas System.................................. 11/01/96 $ 7,676 $ 5,800 (a)
12/01/00 9,827 3,011
Amarillo System.................................... 01/01/00 4,354 2,200
Louisiana............................................ 11/01/99 (b) -- (b)
Kentucky............................................. 12/21/99 14,127 9,900 (c)
Colorado............................................. 01/21/98 -- (1,600)(d)
05/04/01 4,200 2,750
Iowa................................................. 03/05/01 (e) (326)(e)
Georgia.............................................. 12/02/96 5,003 3,160
Illinois............................................. 07/09/97 1,234 428
10/23/00 2,100 1,367
Virginia............................................. 10/01/98 -- (248)(f)
04/01/01 2,100 (534)
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(a) This increase includes $500,000 applicable to areas outside the city limits which became effective in April 1997.
(b) The Louisiana Public Service Commission approved a Rate Stabilization Clause for three years for our former Trans La Division with an allowed return on common equity between 10.5 percent and 11.5 percent. This decision increased the service charge amounts from about 20 percent to about 70 percent of actual costs and increased the monthly customer charges from $6 to $9, both effective November 1, 1999.
(c) The Kentucky rate order also included a provision for a five-year pilot program for weather normalization which began in November 2000.
(d) Rate reduction as a result of settlement in a case initiated by the Colorado Consumer Council.
(e) Rate reduction as a result of an agreement initiated by the Iowa Consumer Advocate Division of the Department of Justice.
(f) Rate reduction as a result of a settlement with the Virginia State Corporation Commission staff.
We are not currently in significant direct competition with any other distributors of natural gas to residential and commercial customers within our service areas. However, we do compete with other natural gas suppliers and suppliers of alternate fuels for sales to industrial and agricultural customers. We compete in all aspects of our business with alternative energy sources, including, in particular, electricity. Competition for residential and commercial customers is increasing. Promotional incentives, improved equipment efficiencies and promotional rates all contribute to the acceptability of electrical equipment. Electric utilities offer electricity as a rival energy source and compete for the space heating, water heating and cooking markets. 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. In addition, through Atmos Energy Marketing, we compete with other natural gas brokers in obtaining natural gas supplies for customers.
EMPLOYEES
At September 30, 2001, we had 2,361 employees. See "Utility Sales and Statistical Data by Business Unit" for the number of employees by business unit.
ITEM 2. PROPERTIES
We own an aggregate of 38,938 miles of underground distribution and transmission mains throughout our gas distribution systems. These mains are located on easements or rights-of-way which generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair and believe that our system of mains is in good condition. We also own and operate one propane peak shaving plant with a total capacity of approximately 180,000 gallons that can produce an equivalent of approximately 3,300 Mcf daily. We also own a liquefied natural gas storage facility with a capacity of 500,000 Mcf which can inject a daily volume of 30,000 Mcf into the system, as well as underground storage fields, as discussed below, that are used to supplement the supply of natural gas in periods of peak demand.
We have six underground gas storage facilities in Kentucky and four in Kansas. We own a 25 percent interest in a gas storage facility in Napoleonville, Louisiana. This gas storage facility is operated by Acadian Gas Pipeline System who also owns the remaining 75 percent interest. Our 25 percent usable capacity is 364,782 Mcf. In addition to the usable capacity we maintain 332,917 Mcf of cushion gas to maintain reservoir pressure. The Napoleonville facility has a maximum daily delivery capability of approximately 56,000 Mcf. We also have a contract through March 2003 with Bridgeline Gas Distribution LLC for 250,000 Mcf of usable storage capacity in a storage facility in Sorrento, Louisiana. The Sorrento facility has a maximum daily delivery capability of approximately 25,000 Mcf.
Our total storage capacity is approximately 21.9 Bcf. However, approximately 10.3 Bcf of gas in the storage facilities must be retained as cushion gas to maintain reservoir pressure. The maximum daily delivery capability of these storage facilities is approximately 226,000 Mcf.
Substantially all of our properties in our Greeley Gas Division and United Cities Gas Division with net book values of approximately $174.4 million and $314.1 million are subject to liens under First Mortgage Bonds assumed in our mergers with Greeley Gas Company and United Cities Gas Company. At September 30, 2001, the liens collateralized $17.0 million of outstanding 9.4 percent Series J First Mortgage Bonds due May 1, 2021, and $92.2 million of outstanding Series P, Q, R, T, U and V First Mortgage Bonds due at various dates from 2004 through 2022.
Our administrative offices are consolidated in Dallas, Texas under one lease. We also maintain field offices throughout our distribution system, the majority of which are located in leased premises.
Net property, plant and equipment at September 30, 2001 included approximately $1,280.6 million for utility and $54.8 million for non-regulated.
ITEM 3. LEGAL PROCEEDINGS
See Note 5 of notes to consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of fiscal 2001.
The following table sets forth certain information as of September 30, 2001, regarding the executive officers of the Company. It is followed by a brief description of the business experience of each executive officer.
YEARS OF
NAME AGE SERVICE OFFICE CURRENTLY HELD
---- --- -------- ---------------------
Robert W. Best................ 54 4 Chairman, President and Chief Executive
Officer
John P. Reddy................. 48 3 Senior Vice President and Chief Financial
Officer
R. Earl Fischer............... 62 39 Senior Vice President, Utility Operations
J. D. Woodward III............ 51 -- Senior Vice President, Non-Utility
Operations
Louis P. Gregory.............. 46 1 Senior Vice President and General Counsel
Wynn D. McGregor.............. 48 13 Vice President, Human Resources
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Robert W. Best was named Chairman of the Board, President and Chief Executive Officer in March 1997. He previously served as Senior Vice President -- Regulated Businesses of Consolidated Natural Gas Company (1996-March 1997) and was responsible for its transmission and distribution companies.
John P. Reddy was named Senior Vice President and Chief Financial Officer in September 2000. From April 2000 to September 2000, he was Senior Vice President, Chief Financial Officer and Treasurer. Mr. Reddy previously served the Company as Vice President, Corporate Development and Treasurer from December 1998 to March 2000. He joined the Company in August 1998 from Pacific Enterprises, a Los Angeles, California based utility holding company whose principal subsidiary was Southern California Gas Co. where he was Vice President of Planning and Advisory Services responsible for corporate development and merger and acquisition activities. Mr. Reddy was with Pacific Enterprises from 1980 to 1998 in various management and financial positions.
R. Earl Fischer was named Senior Vice President, Utility Operations in May 2000. He previously served the Company as President of the Energas Division from January 1999 to April 2000 and as President of the Western Kentucky Division from February 1989 to December 1998.
J. D. Woodward was named Senior Vice President, Non-Utility Operations in April 2001. Prior to joining the Company, Mr. Woodward was President of Woodward Marketing, LLC from January 1995 to March 2001.
Louis P. Gregory joined the Company as Senior Vice President and General Counsel in September 2000. Prior to joining the Company, he practiced law from April 1999 to August 2000 with the law firm of McManemin & Smith. Prior to that, he served as a consultant and independent contractor from August 1996 to December 1998 for Nomas Corp. (formerly known as Lomas Mortgage USA, Inc.) and Siena Holdings, Inc. (formerly known as Lomas Financial Corporation).
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our stock trades on the New York Stock Exchange under the trading symbol "ATO." The high and low sale prices and dividends paid per share of our common stock for fiscal 2001 and 2000 are listed below. The high and low prices listed are the actual closing NYSE quotes for shares of our common stock.
DIVIDENDS
HIGH LOW PAID
------ ------ ---------
FISCAL YEAR 2001
Quarter ended:
December 31............................................. $26.25 $19.31 $.290
March 31................................................ 25.25 21.50 .290
June 30................................................. 24.46 21.45 .290
September 30............................................ 23.64 19.79 .290
-----
$1.16
=====
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DIVIDENDS
HIGH LOW PAID
------ ------ ---------
FISCAL YEAR 2000
Quarter ended:
December 31............................................. $25.00 $20.00 $.285
March 31................................................ 20.19 15.56 .285
June 30................................................. 20.56 14.75 .285
September 30............................................ 23.25 18.50 .285
-----
$1.14
=====
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See Note 3 of notes to consolidated financial statements for restriction on payment of dividends. The number of record holders of our common stock on September 30, 2001 was 30,524.
The following table sets forth selected financial data of the Company and should be read in conjunction with the consolidated financial statements included herein.
YEAR ENDED SEPTEMBER 30
--------------------------------------------------------------
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Operating revenues....... $1,442,275 $ 850,152 $ 690,196 $ 848,208 $ 906,835
========== ========== ========== ========== ==========
Net income............... $ 56,090 $ 35,918 $ 17,744 $ 55,265 $ 23,838
========== ========== ========== ========== ==========
Diluted net income per
share.................. $ 1.47 $ 1.14 $ .58 $ 1.84 $ .81
========== ========== ========== ========== ==========
Cash dividends declared
per share.............. $ 1.16 $ 1.14 $ 1.10 $ 1.06 $ 1.01
========== ========== ========== ========== ==========
Total assets at end of
year................... $2,036,180 $1,348,758 $1,230,537 $1,141,390 $1,088,311
========== ========== ========== ========== ==========
Long-term debt at end of
year................... $ 692,399 $ 363,198 $ 377,483 $ 398,548 $ 302,981
========== ========== ========== ========== ==========
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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, cash flows and results of operations of Atmos Energy Corporation with specific information on liquidity, capital resources and results of operations. It includes management's interpretation of such 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 the Company's consolidated financial statements and notes thereto.
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 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 the Company 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 the Company's documents or oral presentations, the words "anticipate," "expect," "estimate," "plans," "believes," "objective," "forecast," "goal" 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 the Company's strategy, operations, markets, services, rates, recovery of costs, availability of gas supply and other factors. These risks and uncertainties include the following: adverse weather conditions such as warmer than normal weather in the Company's service territories; national, regional and local economic conditions, including competition from other energy suppliers as well as alternative forms of energy; recent national events; regulatory approvals, including the impact of rate proceedings before various state regulatory commissions; successful completion and integration of pending acquisition; inflation and increased gas costs, including their effect on commodity prices for natural gas; increased competition; further deregulation or "unbundling" of the natural gas distribution industry; hedging and market risk activities and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes 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, the Company undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.
RATEMAKING ACTIVITY
The following is a discussion of our ratemaking activity for rate cases that are currently pending as of September 30, 2001 or rate proceedings completed during the three years ended September 30, 2001.
Results of our rate activity for the three years ended September 30, 2001 can be summarized as follows: net annual rate increases totaling $6.4 million implemented in 2001, annual rate increases totaling $12.1 million implemented in 2000 and no rate changes in 1999.
In August 1999, the Energas Division filed rate cases in its West Texas System cities and Amarillo, Texas, requesting rate increases of approximately $9.8 million and $4.4 million. The Energas Division received an increase in annual revenues of approximately $2.1 million in base rates plus an increase of $.1 million in service charges in Amarillo, Texas, effective for bills rendered on or after January 1, 2000. The agreement with Amarillo also provided for changes in the rate structure to reduce the impact of warmer than normal weather and to improve the recovery of the actual cost of service calls. The Energas Division's request for an annual increase of approximately $9.8 million from the 67 cities served by its West Texas System was denied. In March 2000, this decision was appealed to the Railroad Commission of Texas. Subsequently, 59 cities representing approximately 58 percent of Energas' customers ratified a non-binding Settlement Agreement. The Settlement Agreement capped the rate increase at $3.0 million and entitled the ratifying cities to accept a rate increase below $3.0 million in the event the Railroad Commission adopted a lesser increase for the non-ratifying cities. Eight cities declined to participate in the settlement and a hearing with the Railroad Commission was held in August 2000. In December 2000, the Railroad Commission approved an increase in annual revenues of approximately $3.0 million effective December 1, 2000. In addition, the Railroad Commission approved a new rate design providing more protection from warmer than normal weather for our West Texas System.
In June 1999, the Trans La operations of the Atmos Energy Louisiana Gas Division appeared before the Louisiana Public Service Commission for a rate investigation and to redesign rates to mitigate the effects of warm winter weather. A decision was rendered by the Louisiana Commission in October 1999 that increased service charges associated with customer service calls and increased the monthly customer charges from $6 to $9, both effective November 1, 1999. While these changes are revenue neutral, they have mitigated the impact of warmer than normal winter weather on earnings. The decision also included a three-year rate stabilization clause which will allow the Trans La operations of Atmos Energy Louisiana Gas Division's rates to be adjusted annually to allow us to earn a minimum return on equity of 10.5 percent.
In connection with its review of our acquisition of Louisiana Gas Service, the Louisiana Public Service Commission approved a rate structure that requires us to share any cost savings that result from the acquisition with the customers of Louisiana Gas Service. The shared cost savings will be the difference between operation and maintenance expense in any future year and the 1998 normalized expense for Louisiana Gas Service, indexed for inflation, annual changes in labor costs and customer growth. The customers are not assured any savings in 2001. In 2002 and in future years, the customers are assured annual savings, which will be indexed for inflation, annual changes in labor costs and customer growth. The sharing mechanism will remain in place for 20 years subject to established modification procedures.
In May 1999, the Western Kentucky Gas Division requested from the Kentucky Public Service Commission an increase in revenues, a weather normalization adjustment and changes in rate design to shift a portion of revenues from commodity charges to fixed rates. In December 1999, the Kentucky Commission granted an increase in annual revenues of approximately $9.9 million. The new rates were effective for services rendered on or after December 21, 1999. In addition, the Kentucky Commission approved a five-year pilot program for weather normalization beginning in November 2000.
On June 9, 1998, the Kentucky Commission issued an Order approving a three year experimental Performance-based Ratemaking mechanism related to gas procurement and gas transportation activities filed by the Western Kentucky Gas Division. The Performance-based Ratemaking mechanism is incorporated into the Western Kentucky Gas Division's gas cost adjustment clause. As discussed above, it provides for sharing of purchased gas cost savings between the consumers and us. We recognized other income of $0.2 million and $2.1 million under the Kentucky Performance-based Ratemaking mechanism in fiscal 2001 and fiscal 2000. The experimental Performance-based Ratemaking mechanism expired on June 30, 2001 and the Kentucky Commission has extended it while it considers the Western Kentucky Gas Division's request for another mechanism.
In November 2000, the Greeley Gas Division filed a rate case with the Colorado Public Utilities Commission for approximately $4.2 million in additional annual revenues. In May 2001, we received an increase in annual revenues of approximately $2.8 million from the Colorado Public Utilities Commission. The new rates went into effect on May 4, 2001.
Effective April 1, 1999, the Tennessee Regulatory Authority approved the United Cities Gas Division's request to continue its Performance-based Ratemaking mechanism related to gas procurement and gas transportation activities for a three-year period. The Tennessee Regulatory Authority revised the mechanism from the original two-year experimental period, by increasing the cap for incentive gains and/or losses to $1.25 million per year. Similar to Tennessee, the Georgia Public Service Commission renewed our Performance-based Ratemaking program for an additional three years effective May 1, 1999. The gas purchase and capacity release mechanisms of the Performance-based Ratemaking mechanism are designed to provide us incentives to find innovative methods to lower gas costs to our customers. We recognized other income of $1.0 million and $0.2 million in fiscal years 2001 and 2000 for the Georgia and Tennessee Performance-based Ratemaking mechanisms.
In February 2000, the United Cities Gas Division filed a rate case in Illinois with the Illinois Commerce Commission requesting an increase in annual revenues of approximately $3.1 million. After review by the Illinois Commerce Commission, the amount requested was revised to approximately $2.1 million. The United Cities Gas Division received an increase in annual revenues of approximately $1.4 million. The new rates went into effect on October 23, 2000 and are collected primarily through an increase in monthly customer charges.
In March 2000, the United Cities Gas Division filed a rate case in Virginia with the State Corporation Commission of the Commonwealth of Virginia requesting an increase in annual revenues of approximately $2.3 million. The State Corporation Commission of Virginia reviewed the filing to determine if it met the appropriate rules and regulations. In July 2000, we refiled the case requesting an increase in revenues of approximately $2.1 million. The Commission accepted the revised filing. In April 2001, the United Cities Gas Division agreed to an annual rate reduction of $0.5 million effective beginning with the April 2001 billing cycle.
In March 2001, the United Cities Gas Division and the Iowa Consumer Advocate Division of the Department of Justice reached an agreement for an annual rate reduction of $0.3 million relating to our Iowa operations. The rate reduction was effective in March 2001.
We continue to monitor rates in all of our service areas to ensure that they are adequate for the recovery of service costs and return on investment.
On September 10, 2001, the United Cities Gas Division filed a request for accounting order related to uncollectable delinquencies associated with Moratorium Order of Georgia Public Service Commission dated January 17, 2001. In our request, we asked the Georgia Commission to issue an accounting authority order authorizing us to defer as a regulatory asset all costs incurred in connection with the Moratorium on disconnects ordered by the Georgia Commission which lasted from January 17, 2001 through April 1, 2001. On September 28, 2001, the Georgia Commission issued an order authorizing us to create a mechanism for the recovery of uncollectable delinquencies with an effective date of November 1, 2001. The United Cities Gas Division is authorized to recover through the recovery mechanism up to $500,000.
Our natural gas distribution business and irrigation sales business is seasonal and dependent upon weather conditions in our service areas. Natural gas sales to residential, commercial and public authority customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Sales to industrial customers are much less weather sensitive. Sales to agricultural customers, who typically use natural gas to power irrigation pumps during the period from March through September, are affected by rainfall amounts. The effects of colder than normal winter weather in 2001 and the effects of significantly warmer than normal winter weather in 2000 and 1999 on our consolidated volumes delivered are illustrated by the following degree day information. The degree day information for 2001 and 2000 presented below excludes service areas with weather normalized operations. Information concerning service areas with weather normalized operations for 1999 was not available; thus, degree day information presented for 1999 includes service areas having weather normalized operations.
YEAR ENDED SEPTEMBER 30,
------------------------
2001 2000 1999
------ ------ ------
Sales volumes -- Bcf........................................ 156.6 138.2 140.1
Transportation volumes -- Bcf............................... 61.2 59.4 55.5
----- ----- -----
Total.................................................. 217.8 197.6 195.6
===== ===== =====
Degree days:
Actual.................................................... 2,753 2,096 3,374
Percent of normal......................................... 107% 81% 85%
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The effects of weather that is above or below normal are partially offset in the Tennessee and Georgia jurisdictions served by the United Cities Gas Division and in the Kentucky jurisdiction served by the Western Kentucky Gas Division through weather normalization adjustments. The Georgia Public Service Commission, the Tennessee Regulatory Authority and the Kentucky Public Service Commission have approved weather normalization adjustments. The weather normalization adjustments, effective October through May each year in Georgia, and November through April each year in Tennessee and Kentucky, allow the United Cities Gas Division and the Western Kentucky Gas Division to increase the base rate portion of customers' bills when weather is warmer than normal and decrease the base rate when weather is colder than normal. The net effect of the weather normalization adjustments was a decrease in revenues of approximately $3.3 million for 2001 compared to an increase in revenues of $4.1 million and $4.4 million in 2000 and 1999. Approximately 375,000 or 26 percent of our meters in service are located in Georgia, Tennessee and Kentucky. We did not have weather normalization adjustments in our other service areas during the year ended September 30, 2001. We also received approval to change our rate structure in our West Texas System of the Energas Division beginning in December 2000 to help offset some of the negative effects of weather.
In July 2000, we entered into an agreement to purchase weather hedges for our Texas and Louisiana operations effective for the 2000 - 2001 heating season. The hedges were designed to help mitigate the effects of weather that was at least seven percent warmer than normal in both Texas and Louisiana while preserving any upside. The cost of the weather hedges was approximately $4.9 million which was amortized over the 2000 - 2001 heating season. The cost of the weather hedges was more than offset by the positive effects of colder weather on our gross profit.
In June 2001, we purchased a three year weather insurance policy with an option to cancel in the third year if we obtain weather protection in our rate structures. The policy is for our Texas and Louisiana operations and covers the entire heating season of October to March beginning with the 2001 - 2002 heating season. The cost of the three year policy was approximately $13.2 million which was prepaid and will be amortized over the appropriate heating seasons based on degree days. The insurance is designed to protect against weather that is at least seven percent warmer than normal.
For further information regarding the impact of weather and seasonality on operating results, see Note 16, "Selected Quarterly Financial Data (unaudited)" in notes to consolidated financial statements herein.
Fiscal 2001 was a year in which total cash inflows exceeded total cash outflows. This was generally the result of increased cash flows from operating activities as a result of colder than normal weather partially offset by increased capital expenditures. Net proceeds from the issuance of long-term debt were used to finance the Louisiana Gas Service Company and LGS Natural Gas Company acquisition in 2001. Net proceeds from our equity offering were used to reduce commercial paper debt. Common stock issued primarily through our Employee Stock Ownership Plan and our Direct Stock Purchase Plan was also used to finance operations.
CASH FLOWS FROM OPERATING ACTIVITIES
Items on the Consolidated Statement of Cash Flows for the year ended September 30, 2001 reflect changes in balances for the year, net of assets acquired and liabilities assumed in the acquisition of the additional interest in Woodward Marketing, L.L.C. and the assets of Louisiana Gas Service Company and LGS Natural Gas Company. See Note 10 of the accompanying notes to consolidated financial statements.
Cash flows from operating activities as reported in the consolidated statement of cash flows totaled $83.0 million for 2001 compared to $54.2 million for 2000 and $84.7 million for 1999. The increase in net cash provided by operating activities from 2000 to 2001 was primarily the result of increases in net income and other current liabilities and a decrease in accounts receivable and deferred gas costs partially offset by an increase in cash held on deposit in margin accounts and a decrease in accounts payable. Also, the net change in our assets/liabilities from risk management activities added to the increase in net cash provided by operating activities in 2001. The increase in net income was primarily due to higher gross profits due to increased volumes and rate increases. The increase in gross profits was partially offset by an increase in operating expenses and an increase in interest expense. Also reducing gross profit was a decrease in miscellaneous income (expense) as a result of charges incurred related to our performance based-ratemaking mechanisms and the cost of weather hedges purchased for our Louisiana and Texas operations. In addition, miscellaneous income (expense) was reduced in 2001 as the result of a gain recognized on the sale of certain non-regulated assets in 2000 which did not occur in 2001.
CASH FLOWS FROM INVESTING ACTIVITIES
During the last three years, a substantial portion of our cash resources was used to fund technology improvements, acquisitions and our ongoing construction program to provide natural gas services to a growing customer base. Net cash used in investing activities totaled $468.1 million in 2001 compared with $100.1 million in 2000 and $109.6 million in 1999. Capital expenditures in fiscal 2001 amounted to $113.1 million, compared with $75.6 million in 2000 and $110.4 million in 1999. The increase in capital expenditures from 2000 to 2001 was primarily the result of additional capital requirements needed due to our growing customer base. Included in investing activities for 2001 is $363.4 million used to acquire the assets of Louisiana Gas Service Company and LGS Natural Gas Company as discussed in Note 2 of the notes to consolidated financial statements. Included in investing activities in 2000 was $32.0 million used to acquire the Missouri natural gas distribution assets of Associated Natural Gas. Currently budgeted capital expenditures for fiscal 2002 total approximately $122.0 million and include funds for additional mains, services, meters and equipment. In fiscal 2002, we also plan to complete the Mississippi Valley Gas Company acquisition for $150.0 million plus the assumption of approximately $45.0 million of long-term debt as discussed in Note 2 of the notes to consolidated financial statements. Capital expenditures and acquisitions for fiscal 2002 are planned to be financed from internally generated funds and financing activities as discussed below. In 2001, we had $5.4 million in expenditures for assets to be used in leasing activities. In connection with our acquisition of Woodward Marketing, we received $8.6 million in cash. In 2001, we received net proceeds of $6.6 million in connection with the sale of certain utility assets. In 2000, we received net proceeds of $6.5 million in connection with the sale of certain propane assets to Heritage Propane Partners, L.P.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by financing activities totaled $393.0 million for 2001 compared with $44.7 million for 2000 and $28.7 million for 1999. Financing activities during these periods included issuance of common stock, dividend payments, short-term borrowings from banks under our credit facilities and issuance and repayment of long-term debt. The increase in cash provided by financing activities in 2001 as compared to 2000 was due primarily to the issuance of long-term debt and the issuance of common stock during 2001. In 2001 we received $347.1 million in net proceeds from our $350.0 million debt offering in May 2001. The net proceeds were used to help finance the completion of the Louisiana Gas Service Company and LGS Natural Gas Company acquisition in July 2001. Long-term debt repayments totaled $17.7 million, $14.6 million and $61.0 million for 2001, 2000 and 1999. Repayments of long-term debt in 2001, 2000 and 1999 consisted of annual installments under the various loan documents. During 2001, short-term debt decreased $48.8 million due primarily to the use of the net proceeds from our equity offering in December 2000 to reduce commercial paper debt. During 2000, short-term debt increased $81.7 million due to the effect of warmer weather on net income for 2000, the acquisition of the Missouri natural gas distribution assets of Associated Natural Gas for $32.0 million and increases in accounts receivable, cost of gas stored underground and deferred charges. During 1999, short-term debt increased $101.9 million due largely to lower net income and cash requirements of $61.0 million for repayments of long-term debt and capital expenditures of $110.4 million primarily for technology improvements.
Issuance of common stock. We issued 674,468, 704,540 and 849,481 shares of common stock in 2001, 2000 and 1999 under our various plans. See the Consolidated Statements of Shareholders' Equity and Note 6 of the accompanying notes to consolidated financial statements for the number of shares previously issued and available for future issuance under each of our plans. In addition to the shares issued under our various plans, we also issued 6,741,500 shares through our equity offering in December 2000 and 1,423,193 shares of restricted common stock for the acquisition of the remaining 55 percent of Woodward Marketing in April 2001. The net proceeds from the equity offering were used to reduce commercial paper debt as discussed above.
Cash dividends paid. We paid $44.1 million in cash dividends during 2001 compared with $36.0 million in 2000 and $33.9 million in 1999. We raised the dividend $.02 per share during 2001 and $.04 per share during each of 2000 and 1999. The increase in cash dividends in 2001 over 2000 was also due to the increase in the number of shares outstanding as discussed above.
LIQUIDITY
The excess of cash inflows over outflows has resulted in a slight decrease in debt as a percentage of total capitalization, including short-term debt, as shown in the table below.
SEPTEMBER 30
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2001 2000
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(IN THOUSANDS, EXCEPT PERCENTAGES)
Short-term debt............................... $ 201,247 13.4% $ 250,047 24.4%
Long-term debt................................ 713,094 47.6% 380,764 37.2%
Shareholders' equity.......................... 583,864 39.0% 392,466 38.4%
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Total capitalization, including short-term
debt........................................ $1,498,205 100.0% $1,023,277 100.0%
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The debt as a percentage of total capitalization, including short-term debt, was 61.0 percent and 61.6 percent at September 30, 2001 and 2000. Our long-term plans are to decrease the debt to capitalization ratio to nearer its target range of 50-52 percent through cash flow generated from operations, continued issuance of new common stock under our Direct Stock Purchase Plan and Employee Stock Ownership Plan, access to the debt and equity capital markets and limiting annual maintenance capital expenditures. It is likely that the debt to capitalization ratio will remain in its current range in the near term.
At September 30, 2001, we had short-term committed credit facilities totaling $318.0 million. One short-term unsecured credit facility is for $300.0 million and serves as a backup liquidity facility for our commercial paper program. At September 30, 2001, $171.0 million of commercial paper was outstanding. On August 2, 2001, this facility was renewed for $300.0 million with an option to increase the amount by $100.0 million. We have a second facility in place for $18.0 million. At September 30, 2001, $2.2 million was outstanding under this credit facility. These credit facilities are negotiated at least annually and are used for working capital purposes.
At September 30, 2001, our Woodward Marketing subsidiary has an uncommitted credit facility for $140.0 million which is used for its non-regulated business. Atmos Energy Marketing, LLC, our wholly owned subsidiary, is the sole guarantor of all amounts outstanding under this facility. At September 30, 2001, $28.0 million was outstanding under this credit facility. Related letters of credit totaling $38.8 million further reduced the amount available under this facility. Woodward Marketing also has up to $100.0 million available from Atmos for its non-regulated business. At September 30, 2001, $100.0 million was outstanding.
At September 30, 2001, we also had uncommitted short-term credit lines of $40.0 million, all of which were unused. The uncommitted lines are renewed or renegotiated at least annually with varying terms and we pay no fee for the availability of the lines. Borrowings under these lines are made on a when-and as-available basis at the discretion of the banks.
The loan agreements pursuant to which our Senior Notes and First Mortgage Bonds have been issued contain covenants by us with respect to the maintenance of certain debt-to-equity ratios and cash flows and restrictions on the payment of dividends. See Note 3 of the accompanying notes to consolidated financial statements for more information on these covenants.
FUTURE CAPITAL REQUIREMENTS
We believe that internally generated funds, our credit facilities, commercial paper program and access to the public debt and equity capital markets will provide necessary working capital and liquidity for capital expenditures and other cash needs for fiscal 2002.
YEAR ENDED SEPTEMBER 30, 2001 COMPARED WITH YEAR ENDED SEPTEMBER 30, 2000
Operating revenues increased by 70 percent to $1.4 billion for 2001 from $850.2 million for 2000. The most significant factors contributing to the increase in operating revenues were a 58 percent increase in average sales price due to the increased cost of gas and a 10 percent increase in sales and transportation volumes due to colder weather. During 2001, excluding service areas with weather normalized operations, temperatures were 31 percent colder than in the corresponding period of the prior year and were seven percent colder than the 30-year normal. The total volume of gas sold and transported for 2001 was 217.8 Bcf compared with 197.6 Bcf for 2000. The average sales price per Mcf sold increased $3.28 to $8.93 primarily due to an increase in the average cost of gas. During the early part of our 2001 fiscal year, natural gas prices throughout the country began to increase significantly. The average cost of gas per Mcf sold increased to $6.83 for 2001 from $3.79 for 2000. Although we expect to recover our purchased gas costs from customers through purchased gas adjustment mechanisms, generally there is a lag between the time we pay for gas purchases and the time when regulators allow us to place higher rates in service and recover those gas costs. As a result, we have from time to time used short-term borrowings to temporarily finance unrecovered purchased gas costs. Where permitted, we have increased our purchased gas adjustments to help mitigate the increased cost of gas.
Subsequent to September 30, 2001, gas prices had declined to approximately $2 to $3 per Mcf. In addition, as a result of the increased gas costs, our accounts receivable balances during fiscal 2001 increased significantly and, consequently, we also increased our allowance for doubtful accounts, which we consider to be adequate. We do not, however, expect this rise in natural gas prices to have a material adverse effect on our financial condition, results of operations or net cash flows.
In addition, operating revenues increased due to the impact of rate increases in Kentucky, Illinois, Colorado, Amarillo, Texas, and West Texas. Also contributing to the increase in operating revenues was the addition of approximately 48,000 customers in Missouri due to the Associated Natural Gas acquisition completed in fiscal 2000 and the addition of approximately 279,000 residential and commercial meters in Louisiana due to the completion of the Louisiana Gas Service Company acquisition in July 2001. However, operating revenues were partially offset by a reduction related to our former propane assets which were placed into a joint venture partnership in August 2000.
Gross profit increased by 15 percent to $374.7 million for 2001 from $325.7 million for 2000. The increase in gross profit was due primarily to the increase in volumes sold to weather sensitive customers, an increase of $5.1 million in transportation revenues due to higher average transportation revenue per Mcf and increased volumes and a $6.7 million non-recurring adjustment to purchased gas cost to reflect state filings. In addition, gross profit increased due to the impact of rate increases and additional customers, partially offset by a reduction related to our former propane operations, as discussed previously. Changes in the cost of gas do not directly affect gross profit because the fluctuations in gas prices are passed through to our customers.
On April 1, 2001, we completed our acquisition of the remaining 55 percent interest in Woodward Marketing, L.L.C. As a result of this acquisition, the revenues and expenses of Woodward Marketing are now shown on a consolidated basis.
Operating expenses increased to $244.9 million for 2001 from $240.4 million for 2000. Operation and maintenance expense decreased due to savings resulting from the continued cost control initiatives started during fiscal 2000 and reduced operation and maintenance expenses associated with our former propane operations which were placed into a joint venture partnership in fiscal 2000. An increase in the provision for doubtful accounts of $8.5 million and pension costs of $4.5 million partially offset this decrease. Pension costs will increase by $4.4 million in fiscal 2002 over fiscal 2001. Depreciation and amortization expense increased due to the completion of the Louisiana Gas Service Company and LGS Natural Gas Company acquisition in July 2001. Taxes other than income increased as a result of increased city franchise taxes and state gross receipts taxes, which are revenue based. However, these taxes are paid by our customers; thus, these amounts are offset in revenues through customer billings and have no effect on net income.
Operating income increased 53 percent for 2001 to $130.3 million from $85.3 million for 2000. The increase in operating income resulted primarily from increased gross profit described above.
Equity in earnings of Woodward Marketing, L.L.C. was $8.1 million for the six months ended March 31, 2001 compared with $7.3 million for the year 2000.
Miscellaneous income (expense) decreased $9.3 million to $(1.9) million for 2001 compared to $7.4 million for 2000. This decrease was due primarily to charges incurred related to our Performance-based Ratemaking mechanisms and the amortization of $4.9 million related to weather hedges purchased for our Louisiana and Texas operations. In addition, we recognized a gain of $5.8 million in 2000 resulting from the sale of certain non-utility assets. No such gain occurred in 2001. Partially offsetting the decrease in miscellaneous income (expense) during 2001 was an increase of $3.0 million in interest income due primarily to interest income earned on the proceeds from our $350.0 million debt offering in May 2001. We invested these proceeds in short-term investments until the completion of the Louisiana Gas Service Company and LGS Natural Gas Company acquisition in July 2001.
Interest expense increased $3.2 million to $47.0 million for 2001 compared to $43.8 million for 2000. This increase was due primarily to interest expense on the $350.0 million debt offering in May 2001.
YEAR ENDED SEPTEMBER 30, 2000 COMPARED WITH YEAR ENDED SEPTEMBER 30, 1999
Operating revenues increased by 23 percent to $850.2 million in 2000 from $690.2 million in 1999. The most significant factors contributing to the increase in operating revenues were a 25 percent increase in average sales price due to the increased cost of gas and the impact of rate increases in Amarillo, Texas and Kentucky. The average sales price per Mcf sold increased $1.12 or 25 percent to $5.65 in 2000 primarily due to an increase in the average cost of gas. The average cost of gas per Mcf sold increased 36 percent to $3.79 for 2000 from $2.79 for 1999. Also contributing to the increase in operating revenues was an increase in our non-regulated West Texas irrigation sales volumes related to irrigation demand and, secondly, to higher average sales prices reflecting higher gas costs. The increase in irrigation revenues was due to decreased rainfall during the growing season in West Texas in 2000. Partially offsetting the increase in operating revenues was a one percent decrease in sales volumes due to warmer weather. For 2000, excluding service areas with weather normalized operations, temperatures were five percent warmer than in 1999 and were 18 percent warmer than the 30-year normal. The total volume of gas sold for 2000 was 138.2 Bcf compared with 140.1 Bcf for 1999.
Gross profit increased by nine percent to $325.7 million for 2000 from $299.8 million for 1999. The increase in gross profit was due primarily to the impact of rate increases discussed previously. The increase in gross profit was also due to the addition of approximately 48,000 Missouri customers due to the acquisition of the Missouri natural gas distribution assets of Associated Natural Gas and increased volumes associated with the irrigation business. The increase in gross profit was slightly offset by a decrease in volumes sold to weather sensitive customers. Changes in the cost of gas do not directly affect gross profit because the fluctuations in gas prices are passed through to our customers.
Operating expenses decreased to $240.4 million for 2000 from $245.6 million for 1999. Operation and maintenance expense decreased due to savings resulting from the cost control initiatives implemented during 2000 due to the warm winter weather. However, this decrease was partially offset by an increase in the provision for doubtful accounts of $8.8 million. The increase in the provision for doubtful accounts occurred during the transition from local offices to a centralized customer service center and the implementation of a new company-wide customer billing system. During this transition, we temporarily suspended service cutoffs and our normal efforts to collect past due receivables. Actions to address those issues were initiated in 2000. Depreciation and amortization expense also increased during 2000 as a result of the first full year of depreciation being recognized on our process improvement initiatives related to the new customer information and billing system and the accounting and human resource systems placed into service during 1999, as well as the acquisition of the Missouri natural gas distribution assets of Associated Natural Gas in May of 2000.
Operating income increased 57 percent for 2000 to $85.3 million from $54.2 million in 1999. The increase in operating income resulted primarily from increased gross profit and decreased operating expenses described above.
Miscellaneous income (expense), net increased $4.4 million to $7.4 million in 2000 compared to $3.0 million in 1999. The increase was primarily due the $5.8 million ($3.7 million after tax) gain resulting from the sale of certain non-utility assets.
Interest charges increased $6.7 million to $43.8 million in 2000 from $37.1 million in 1999. The increase in 2000 was primarily due to $3.7 million of interest being capitalized in 1999 in connection with the significant technology projects being completed in 1999 and higher average debt outstanding and higher interest rates for 2000. The increase in average debt outstanding was related to funding infrastructure, technology, process changes and customer support investments, as well as additional working capital needed for the increasing gas costs.
FACTORS THAT MAY AFFECT FUTURE PERFORMANCE OF THE COMPANY
Our performance in the future will primarily depend on the results of our utility operations. Several factors exist that could influence Atmos' future financial performance, some of which are described below. 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 projected in these forward-looking statements.
Our natural gas sales volumes and related revenues are directly correlated with heating requirements that result from cold winter weather. Our agricultural sales volumes are associated with the rainfall levels during the growing season in our West Texas irrigation market. Weather is one of the most significant factors influencing our performance. However, as was more fully discussed above, we have purchased weather insurance to mitigate the effect of warmer than historically normal weather in our Texas and Louisiana service areas. In addition, weather normalized rates are in effect in several of our jurisdictions, which should mitigate the adverse effects of warmer or drier than normal weather on our operating results.
Our operations will always be affected by the conditions and overall strength of the national, regional and local economies, including interest rates, changes in the capital markets and increases in the costs of our primary commodity, natural gas. These factors impact the amount of residential, industrial and commercial growth in our service territories. Higher costs of natural gas in recent years have already lead many of our customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation methods.
Our company and our operations have already been indirectly impacted by the tragic events of September 11, 2001. The terrorist activities on that day have heightened our awareness of safety and security concerns and have prompted a company-wide review and assessment of the adequacy of our safety and security procedures relating to the protection of our customers, employees and our physical assets. We will continue to monitor and assess our safety and security procedures and will take all precautions necessary to minimize any adverse effects on us or our operations. Accordingly, through taking these added precautions, we believe that we have minimized any potential adverse effects that any future terrorist activities could have on us or our operations.
Our utility business is subject to various regulated returns on its rate base in each of the 11 states in which we operate. We monitor the allowed rates of return, our effectiveness in earning such rates and initiate rate proceedings or operating changes as needed. In addition, in the normal course of the regulatory environment, assets are placed in service and historical test periods are established before rate cases can be filed. Once rate cases are filed, regulatory bodies have the authority to suspend implementation of the new rates while studying the cases. Because of this process, we must temporarily 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". In addition, our debt and equity financing programs are also subject to approval by regulatory bodies in five states, which could limit our ability to take advantage of favorable market conditions.
Our acquisition strategy depends on our ability to successfully acquire and integrate the operations of companies such as Mississippi Valley Gas Company, which acquisition is currently pending. Acquisitions such as Mississippi Valley should help us achieve greater economies of scale by spreading the fixed costs of the utility business over a larger customer base. Completion of this acquisition is subject to state and federal regulatory approval. In addition, the integration of this acquisition into our operations during the next fiscal year will require a substantial commitment of financial resources and management time.
We believe that inflation has caused, and will continue to cause, increases in certain operating expenses, and has required, and will continue to require, assets to be replaced at higher costs. We have a process in place to continually review the adequacy of our gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investment within the amounts authorized to be collected in rates and intend to continue to do so. The ability to control expenses is an important factor that will influence future results.
In addition, the rapid increases in the price of purchased gas during the past year caused us to experience a significant increase in short-term debt because we must pay suppliers for such gas when it is purchased long before such costs may be recovered through the collection of monthly customer bills for gas delivered. Also, the increases in purchased gas costs caused more customers to be slow to pay their gas bills, leading to accounts receivable that were higher than normal which in turn lead to higher short-term debt levels and increased bad debts in fiscal 2001. Should the price of purchased gas increase significantly in the upcoming heating season, we would expect similar increases in our short-term debt and accounts receivable during fiscal 2002.
We are facing increased competition from other energy suppliers as well as electric companies and from energy marketing and trading companies. In the case of industrial customers, such as manufacturing plants, and agricultural customers, adverse economic conditions, including higher gas costs, could cause such customers to use alternative sources of energy such as electricity or to bypass our systems in favor of special competitive contracts with lower per-unit costs.
We are closely monitoring the development of unbundling initiatives in the natural gas industry. Unbundling is the separation of the provision and pricing of local distribution gas services into discrete components. It typically focuses on the separation of the distribution and gas supply components and the resulting opening of the regulated components of sales services to alternative unregulated suppliers of those services. Because of brand loyalty in our service areas, and our enhanced technology and distribution system infrastructures, we believe that we are now positively positioned as unbundling evolves. Consequently, we do not expect there would be a significant adverse effect on our business should unbundling or further deregulation of the natural gas distribution service business occur.
To protect against volatility in gas prices, we are hedging gas costs for the 2001-2002 heating season by utilizing a combination of financial tools and fixed forward physical contracts to stabilize gas prices. For the 2001-2002 heating season, we plan to cover approximately 64 percent of our anticipated requirements through storage and hedging instruments. The gas hedges should help moderate the effects of higher customer accounts receivable caused by higher gas prices.
We acquired a 45 percent interest in Woodward Marketing, L.L.C. in 1997 as a result of the merger of Atmos and United Cities Gas Company, which had acquired that interest in 1995. In April 2001, we acquired the 55 percent interest that we did not own from J.D. Woodward and others for 1,423,193 restricted shares of our common stock. Immediately following the acquisition, Mr. Woodward was elected as a Senior Vice President of Atmos in charge of all non-regulated business activities, a position he has held since April 2001. Prior to that time, Mr. Woodward had not been an officer or employee of Atmos.
The principal business of Woodward Marketing, including the activities of Trans Louisiana Industrial Gas Company, Inc., is the overall management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the Southwestern and Midwestern United States. This business involves the sale of natural gas by Woodward Marketing to its customers and the management of storage and transportation contracts for its customers under contracts generally having one to two-year terms. At September 30, 2001, Woodward Marketing had a total of 78 municipal and local gas utility customers and 195 industrial customers. Woodward Marketing also sells natural gas to certain of its industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. In addition, Woodward Marketing supplies us with a portion of our natural gas requirements on a competitive bid basis.
In the management of natural gas requirements for municipal and other local utilities, Woodward Marketing sells physical natural gas for future delivery and hedges the associated price risk through the use of gas futures, including forwards, over-the-counter and exchange-traded options, and swap contracts with counterparties. These financial contracts are marked-to-market at the daily close of business. Woodward Marketing links gas futures to physical delivery of natural gas and balances its futures positions at the end of each trading day. Over-the-counter swap agreements require Woodward Marketing to receive or make payments based on the difference between a fixed price and the market price of natural gas on the settlement date. Woodward Marketing uses these futures and swaps to manage margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas, which are also carried on a mark to market basis. Options held to hedge price risk provide the right, but not the requirement, to buy or sell energy commodities at a fixed price. Woodward Marketing uses options to manage margins and to limit overall price risk exposure.
Energy related services provided by Woodward Marketing include the sale of natural gas to its various customer classes and management of transportation and storage assets and inventories. More specifically, energy services include contract negotiation and administration, load forecasting, storage acquisition, natural gas purchase and delivery and capacity utilization strategies. In providing these services, Woodward Marketing generates income from its utility, municipal and industrial customers through negotiated prices based on the volume of gas supplied to the customer. Woodward Marketing also generates income by taking advantage of the difference between near-term gas prices and prices for future delivery as well as the daily movement of gas prices by utilizing storage and transportation capacity that it controls.
Woodward Marketing also engages in limited speculative natural gas trading for its own account, subject to a risk management policy established by us which limits the level of trading loss in any fiscal year to a maximum of 25 percent of the budgeted annual operating income of Woodward Marketing. Compliance with such risk management policy is monitored on a daily basis. In addition, Woodward Marketing's bank credit facility limits trading positions that are not closed at the end of the day (open positions) to 2.5 Bcf of natural gas. At September 30, 2001, Woodward Marketing's open positions in its trading operations totaled 2.3 Bcf. In its speculative trading, Woodward Marketing's open trading positions are monitored on a daily basis but are not required to be closed if they remain within the limits set by the bank loan agreement. Woodward Marketing had an unrealized trading gain of $4.5 million for the fiscal year ended September 30, 2001, but there can be no assurance that Woodward Marketing will have any speculative trading gain in the future. In some prior years, Woodward Marketing has experienced losses in its speculative trading business. The financial exposure that results from the daily fluctuations of gas prices and the potential for daily price movements constitutes a risk of loss since the price of natural gas purchased for future delivery at the beginning of the day may not be hedged until later in the day.
Woodward Marketing's operations are concentrated in the natural gas industry, and its customers and suppliers may be subject to economic risks affecting that industry.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The risk inherent in our market risk sensitive instruments is the potential loss arising from adverse changes in natural gas commodity prices and interest rates as discussed below. The sensitivity analysis does not, however, consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions we may take to mitigate exposure to such changes. Actual results may differ.
GAS PRICES
We purchase natural gas for our regulated and non-regulated natural gas operations. Substantially all of the cost of gas purchased for regulated operations is recovered through purchased gas adjustment mechanisms. We have a limited market risk in gas prices related to gas purchases in the open market at spot prices for sale to non-regulated energy services customers at fixed prices. As a result, our earnings could be affected by changes in the price and availability of such gas. To protect against volatility in gas prices, we from time to time hedge our gas costs by purchasing futures contracts. Our utility segment does not use such financial instruments for trading purposes and we are not a party to any leveraged derivatives. Market risk is estimated as a hypothetical 10 percent increase in the portion of our gas cost related to fixed-price non-regulated sales. Based on projected fiscal 2002 non-regulated gas sales at fixed prices, such an increase would result in an increase to cost of gas of approximately $2.7 million in fiscal 2002, before considering the effect of swap agreements outstanding as of September 30, 2001. As of September 30, 2001, we had entered into swap agreements to lock in gas costs for certain outstanding fixed-price sales agreements. We plan to mitigate the risk of increased gas purchase costs for fixed-price customers by entering into swap agreements to lock in purchased gas cost for estimated sales volumes in fiscal 2002.
In April 2001, we acquired the 55 percent interest in Woodward Marketing that we did not already own. Woodward Marketing's principal business is the management of natural gas requirements for municipalities, local gas utility companies and industrial customers located primarily in the Southwestern and Midwestern United States. This business involves the sale of natural gas and the management of storage and transportation contracts for customers under contracts generally having one to two-year terms. Woodward Marketing also sells natural gas to industrial customers on a delivered burner tip basis under contract terms from 30 days to two years. In the management of natural gas requirements for municipal and other local utilities, Woodward Marketing sells natural gas for future delivery and hedges price risk through the use of gas futures including forwards, over-the-counter and exchange-traded options, futures and swap contracts. Financial contracts are marked-to-market at the daily close of business.
Woodward Marketing also engages in limited speculative natural gas trading for its own account, subject to a risk management policy established by us which limits the level of trading loss in any fiscal year to a maximum of 25 percent of the budgeted operating income of Woodward Marketing. Compliance with such risk management policy is monitored on a daily basis. In addition, Woodward Marketing's bank credit facility limits open trading positions to 2.5 Bcf of natural gas. At September 30, 2001, Woodward Marketing's open positions in its trading operations totaled 2.3 Bcf. In its trading, Woodward Marketing's open trading positions are monitored on a daily basis but are not required to be closed if within the limits set by the bank credit facility. The financial exposure that results from the daily fluctuations of gas prices and the potential for daily price movements have an impact on the net open position. Based on its open positions at September 30, 2001, a $.50 increase in market strip would result in a $1.2 million decrease in the speculative trading gain. A $.50 decrease in market strip would result in a $1.2 million increase in the speculative trading gain.