UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1998 Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia 58-2210952
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
303 Peachtree Street, N.E., Atlanta, Georgia
30308 404-584-9470
(Address and zip code of (Registrant's telephone
principal executive offices) number, including
area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Class Name of Exchange on which registered
-------------- ------------------------------------
Common Stock, $5 Par Value New York Stock Exchange
Preferred Share Purchase Rights 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, 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]
Aggregate market value of common stock held by non-affiliates of the
registrant, computed by reference to the closing price of such stock as of
December 1, 1998: $1,250,607,052.
The number of shares of Common Stock outstanding as of December 1, 1998 was
57,389,114 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 1998 Annual Report to Shareholders for AGL Resources Inc. for
the fiscal year ended September 30, 1998 (Annual Report) are incorporated herein
by reference in Parts I and II and portions of the Proxy Statement for the
1999 Annual Meeting of Shareholders (Proxy Statement) are incorporated herein
by reference in Part III.
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<TABLE>
<CAPTION>
TABLE OF CONTENTS
Page
<S> <C> <C>
PART I
Item 1. Business......................................................................................... 1
Item 2. Properties....................................................................................... 15
Item 3. Legal Proceedings................................................................................ 15
Item 4. Submission of Matters to a Vote of Security Holders.............................................. 15
Item 4.(A). Executive Officers of the Registrant............................................................. 16
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters........................................................................................ 17
Item 6. Selected Financial Data.......................................................................... 17
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition............................................................................ 17
Item 7.(A). Quantitative and Qualitative Disclosure About Market Risk........................................ 17
Item 8. Financial Statements and Supplementary Data...................................................... 18
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................................................... 18
PART III
Item 10. Directors and Executive Officers of the Registrant............................................... 19
Item 11. Executive Compensation........................................................................... 19
Item 12. Security Ownership of Certain Beneficial Owners and Management................................... 19
Item 13. Certain Relationships and Related Transactions................................................... 19
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................ 20
Signatures .................................................................................................. 30
</TABLE>
PART I
ITEM 1. BUSINESS
Forward-Looking Statements
Portions of the information contained in this Form 10-K contain forward
looking statements within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934, and AGL Resources
Inc. intends that such forward-looking statements be subject to the safe harbors
created thereby. Although AGL Resources Inc. believes that its expectations are
based on reasonable assumptions, it can give no assurance that such expectations
will be achieved.
Important factors that could cause actual results to differ materially
from those in the forward-looking statements include, but are not limited to,
the following:
- changes in price and demand for natural gas and related products;
- the impact of changes in state and federal legislation and
regulation on both the gas and electric industries;
- the effects of competition, particularly in markets where prices
and providers historically have been regulated;
- uncertainties about environmental issues;
- changes in accounting policies and practices;
- interest rate fluctuations; and
- changes in financial market conditions.
Business Overview
General. Following shareholder and regulatory approval on
March 6, 1996, AGL Resources Inc. became the holding company for:
- Atlanta Gas Light Company (AGLC) and its wholly owned subsidiary,
Chattanooga Gas Company (Chattanooga), which are local natural gas
distribution utilities; and
- several nonutility subsidiaries.
We collectively refer to AGL Resources Inc. and its subsidiaries as
"AGL Resources."
AGL Resources' consolidated operating revenues during the fiscal year
ended September 30, 1998, were $1.34 billion, of which $1.28 billion
(approximately 96%) was derived from the operations of AGLC and Chattanooga. See
Gas Sales and Statistics below.
Utility Business. AGLC conducts our primary business: the distribution of
natural gas in Georgia, including the Atlanta, Athens, Augusta, Brunswick,
Macon, Rome, Savannah, and Valdosta areas and in Tennessee, including the
Chattanooga and Cleveland areas. The Georgia Public Service Commission (GPSC)
regulates AGLC, and the Tennessee Regulatory Authority (TRA) regulates
Chattanooga. AGLC comprises substantially all of AGL Resources' assets,
revenues, and earnings. When we discuss the operations and activities of AGLC
and Chattanooga, we refer to them, collectively, as the utility.
The utility supplied natural gas service to an average of approximately
1.46 million customers in fiscal 1998. This represents an increase of
approximately 35,000, or 2.5%, in the average number of customers served over
the prior year. Substantially all of this growth was in the residential and
small commercial service categories.
1
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The utility holds franchises, permits, certificates and rights without
any substantial restrictions which management believes are sufficient for the
operation of its properties and adequate for the operation of its gas
distribution business.
Under Georgia's Natural Gas Competition and Deregulation Act, AGLC
elected to unbundle, or separate, the various components of its services to its
customers. As a result, numerous changes have occurred with respect to the
services being offered by AGLC and with respect to the manner in which AGLC
prices and accounts for those services. Consequently, AGLC's future expenses and
revenues will not follow the same pattern as they have historically.
Pursuant to Georgia's Natural Gas Competition and Deregulation Act,
regulated rates ended on October 6, 1998 for natural gas commodity sales to AGLC
customers. Consequently, AGLC will no longer defer any over-recoveries or
under-recoveries of gas costs and will refund to customers the over-recovery
that existed when the purchased gas adjustment (PGA) provisions were
deregulated.
Going forward, AGLC intends to design its prices for deregulated gas
sales in a manner that, at a minimum, will allow it to recover its annual gas
costs. Accordingly, substantial changes to future quarterly statements of income
are expected from this new regulatory approach. AGLC intends to recover all its
gas costs through the prices it will establish such that on an annual basis it
recovers, at a minimum, the actual costs of acquiring gas supplies for sales
services.
As part of the GPSC's rate case ruling, AGLC began billing customers on
July 1, 1998, under a rate structure that recovers nongas costs evenly
throughout the year consistent with the way the costs are incurred. The effect
of the new rate structure will be to levelize on a quarter-to-quarter basis the
revenues collected by AGLC for gas delivery services rendered by the utility.
Prior to July 1, rates to provide distribution service were based principally on
the amount of gas customers used. Therefore, total distribution rates were
typically lower in the summer when customers used less gas, and higher in the
winter when customers used more gas. Going forward, AGLC will collect such rates
evenly throughout the year regardless of volumetric summer and winter
differences in gas usage.
In addition, there are other AGLC revenues that reflect costs associated
with services deemed ancillary to distribution service that will change as
customers select a marketer for sales service. For example, as customers choose
a marketer, the associated revenues to AGLC for billing, billing inquiries,
payment collection, payment processing, and possibly meter reading will decrease
if those services are provided by the marketer. The regulatory provisions
provide for a reduction in the revenues associated with those services as AGLC
has the opportunity to avoid such future costs. Consequently, those provisions
will reduce some of the regulated revenue and associated expenses for AGLC.
2
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Nonutility Business. AGL Resources also operates the following wholly
owned nonutility subsidiaries:
- AGL Energy Services, Inc., a gas supply services company that has
one wholly owned nonutility subsidiary, Georgia Gas Company;
- AGL Interstate Pipeline Company which owns a 50% interest in
Cumberland Pipeline Company; Cumberland Pipeline Company is
expected to provide interstate pipeline services to customers in
Georgia and Tennessee beginning November 1, 2000;
- AGL Investments, Inc., which was established to develop and
manage certain nonutility businesses including:
* AGL Gas Marketing, Inc., which owns a 35% interest in Sonat
Marketing, L.P.; Sonat Marketing, L.P. engages in wholesale
and retail natural gas trading;
* AGL Power Services, Inc., which owns a 35% interest in Sonat
Power Marketing, L.P.; Sonat Power Marketing, L.P. engages in
wholesale power trading;
* AGL Propane, Inc., which engages in the sale of propane and
related products and services;
* Trustees Investments, Inc., which owns Trustees Gardens, a
residential and retail development located in Savannah,
Georgia; and
* Utilipro, Inc., which engages in the sale of integrated
customer care solutions to energy marketers; and
- AGL Peaking Services, Inc., which owns a 50% interest in Etowah
LNG Company LLC; Etowah LNG Company LLC is a joint venture with
Southern Natural Gas Company and was formed for the purpose of
constructing, owning, and operating a liquefied natural gas
peaking facility.
- Atlanta Gas Light Services, Inc., a retail energy marketing
company which owns an interest in SouthStar Energy Services, LLC;
SouthStar Energy Services, LLC was established to sell natural
gas, propane, fuel oil, electricity, and related services in the
Southeast.
Information pertaining to the investments in joint ventures and recent
acquisitions by AGL Resources' nonutility businesses is contained in Note 14,
"Joint Ventures and Nonutility Acquisitions," included in the Notes to
Consolidated Financial Statements in the Annual Report and is incorporated
herein by reference.
3
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<TABLE>
Gas Sales and Statistics
- ----------------------------------------------------------------------------------------------------------------------
For the years ended September 30,
--------------------------------------------------------------------
<CAPTION>
1998 1997 1996 1995 1994 1993
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<S> <C> <C> <C> <C> <C> <C>
Operating Revenues (Millions of Dollars)
Sales of natural gas
Residential $ 775.9 $ 728.5 $ 708.8 $ 610.6 $ 700.7 $ 658.2
Commercial 294.1 290.9 288.8 243.2 285.8 268.1
Industrial 152.6 148.0 178.8 169.4 172.1 154.2
Transportation revenues 34.8 28.5 21.5 23.9 22.6 33.8
Miscellaneous revenues 21.4 20.2 19.7 15.9 18.7 16.0
- ----------------------------------------------------------------------------------------------------------------------
Total utility operating revenues 1,278.8 1,216.1 1,217.6 1,063.0 1,199.9 1,130.3
- ----------------------------------------------------------------------------------------------------------------------
Other operating revenues 59.8 71.5 11.0 5.5
- ----------------------------------------------------------------------------------------------------------------------
Total operating revenues $ 1,338.6 $ 1,287.6 $ 1,228.6 $ 1,068.5 $ 1,199.9 $ 1,130.3
- ----------------------------------------------------------------------------------------------------------------------
Utility Throughput
Therms sold (Millions)
Residential 1,084.9 986.1 1,165.4 916.8 1,003.1 1,001.4
Commercial 467.8 455.5 538.2 454.0 478.9 478.5
Industrial 438.1 344.9 449.6 526.0 424.8 388.7
Therms transported 1,310.6 1,014.5 738.7 722.8 697.4 795.6
- ----------------------------------------------------------------------------------------------------------------------
Total utility throughput 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
- ----------------------------------------------------------------------------------------------------------------------
Average Utility Customers (Thousands)
Residential 1,351.5 1,319.0 1,289.4 1,250.4 1,215.2 1,182.7
Commercial 107.4 104.5 102.5 100.0 98.0 95.7
Industrial 2.6 2.7 2.6 2.6 2.5 2.5
- ----------------------------------------------------------------------------------------------------------------------
Total 1,461.5 1,426.2 1,394.5 1,353.0 1,315.7 1,280.9
- ----------------------------------------------------------------------------------------------------------------------
Sales, Per Average Residential
Utility Customer
Gas sold (Therms) 803 748 904 733 825 847
Revenue $574.10 $552.00 $550.00 $488.32 $576.61 $556.52
Revenue per therm (cents) 71.5 73.9 60.8 66.6 69.9 65.7
Degree Days - Atlanta Area
30-year normal 2,991 2,991 2,991 2,991 2,991 3,021
Actual 3,078 2,402 3,191 2,121 2,565 2,852
Percentage of actual to 30-year normal 102.9 80.3 106.7 70.9 85.8 94.4
Gas Account (Millions of Therms)
Natural gas purchased 1,459.1 1,323.4 1,632.9 1,406.9 1,453.6 1,629.9
Natural gas withdrawn from storage 604.7 472.4 596.0 520.7 500.3 276.4
Natural gas transported 1,310.8 1,014.5 738.7 722.8 697.4 795.6
- ----------------------------------------------------------------------------------------------------------------------
Total send-out 3,374.6 2,810.3 2,967.6 2,650.4 2,651.3 2,701.9
Less
Unaccounted for 66.2 1.3 60.4 20.4 37.2 29.0
Company use 7.0 8.0 15.3 10.4 9.9 8.7
- ----------------------------------------------------------------------------------------------------------------------
Sold and transported
to utility customers 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
- ----------------------------------------------------------------------------------------------------------------------
Cost of Gas (Millions of Dollars)
Natural gas purchased $ 558.8 $ 532.5 $ 547.1 $ 389.4 $ 550.1 $ 595.7
Natural gas withdrawn from storage 203.7 175.7 171.6 182.4 186.7 105.3
- ----------------------------------------------------------------------------------------------------------------------
Cost of gas - utility operations 762.5 708.2 718.7 571.8 736.8 701.0
- ----------------------------------------------------------------------------------------------------------------------
Cost of gas - other 33.5 58.3 6.8 2.3
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Total cost of gas $ 796.0 $ 766.5 $ 725.5 $ 574.1 $ 736.8 $ 701.0
- ----------------------------------------------------------------------------------------------------------------------
Utility Plant - End of Year
(Millions of Dollars)
Gross plant $ 2,133.5 $ 2,069.1 $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6
Net plant $ 1,452.6 $ 1,420.3 $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9
Gross plant investment per utility
customer (Thousands of Dollars) $ 1.5 $ 1.5 $ 1.4 $ 1.4 $ 1.4 $ 1.4
Capital Expenditures (Millions of Dollars) $ 118.2 $ 147.7 $ 132.5 $ 121.7 $ 122.5 $ 122.2
Gas Mains - Miles of 3" Equivalent 30,753 30,261 29,045 28,520 27,972 27,390
Employees - Average 3,024 2,986 2,942 3,249 3,764 3,764
Average Btu Content of Natural Gas 1,028 1,024 1,024 1,027 1,032 1,027
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</TABLE>
4
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Gas Supply Services
General. In 1992, the Federal Energy Regulatory Commission (FERC)
issued Order 636, which increased gas users' ability to choose various gas
purchasing, transportation, brokering, and storage options. Consequently, we now
buy all gas that we resell directly from various suppliers (rather than pipeline
companies)and arrange separately for transportation and storage. We offer gas
for sale to our residential customers on a firm basis, and to our commercial and
industrial customers on a firm or interruptible basis. Alternatively, we can
transport gas for our customers. We also participate in the interstate
markets, by releasing pipeline capacity or bundling pipeline capacity with gas
for off-system sales.
During fiscal year 1998, AGLC bought and sold natural gas under a gas
supply plan that was regulated by the GPSC. Pursuant to Georgia's Natural Gas
Competition and Deregulation Act, regulated rates ended on October 6, 1998 for
natural gas commodity sales to AGLC customers. During the transition period
contemplated by Georgia's Natural Gas Competition and Deregulation Act, AGLC
will continue to sell natural gas to its customers until those customers migrate
to certified natural gas marketers. Consequently, the supply of natural gas by
AGLC was a significant part of AGLC's business during fiscal year 1998 and will
continue to have a material impact on their business during fiscal year 1999.
AGLC is served directly by four interstate pipelines: Southern Natural
Gas Company (Southern), South Georgia Natural Gas Company (South Georgia),
Transcontinental Gas Pipe Line Company (Transco) and East Tennessee Natural Gas
Company (East Tennessee) in combination with its upstream pipeline, Tennessee
Gas Pipeline Company (Tennessee).
As a result of the FERC's Order 636 deregulation initiative, AGLC, along
with the nation's other local distribution companies, bear responsibility for
gas supply strategy decisions which are ultimately subject to review by state
regulatory commissions.
Gas Supply Plan Filing. Prior to the implementation of Georgia's Natural
Gas Competition and Deregulation Act, AGLC had been required by Georgia law to
submit annually for GPSC approval a proposed gas supply plan, as well as a
proposed cost recovery factor for the following year.
In September 1997, the GPSC approved AGLC's fiscal 1998 Gas Supply Plan,
which included limited gas supply hedging activities. Under that plan, AGLC was
allowed to hedge up to one-half of its estimated monthly winter wellhead
purchases. Furthermore, to help avoid price fluctuation, AGLC was able to set a
price for those purchases at an amount other than the beginning-of-the-month
index price. Because AGLC then passed on those costs directly to residential and
small commercial customers, its hedging program did not affect fiscal 1998
earnings.
On July 31, 1998, AGLC filed with the GPSC its fiscal 1999 Gas Supply
Plan (the 1999 Plan), which consisted of gas supply, transportation, and storage
options. The 1999 Plan was designed to provide reliable gas service to
residential and small commercial customers at the best cost (least cost
consistent with desired levels of reliability and flexibility). The GPSC
approved the 1999 Plan with some modifications on September 14, 1998.
Under Georgia's Natural Gas Competition and Deregulation Act, the 1999
Plan, as approved, became AGLC's first Capacity Supply Plan (Capacity Plan)
when, on October 6, 1998, the GPSC approved more than five marketers'
applications to begin selling natural gas services at market prices to Georgia
consumers. Capacity plans, which must be approved by the GPSC at least once
every three years, describe the array of interstate capacity assets selected by
AGLC to make gas available to end-use customers on its system. Rights to use
capacity assets as set forth in the Capacity Plan are assigned by AGLC to
marketers as the marketers acquire firm customers. Marketers are responsible for
paying fixed charges associated with the assigned capacity assets.
Firm Pipeline Transportation and Underground Storage. The table on the
following page shows the amount of firm transportation and describes the types
and amounts of underground storage that both AGLC and Chattanooga have elected
or been assigned under Order 636. The table also shows services that were not
affected by the implementation of Order 636.
5
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<TABLE>
<CAPTION>
Production Area Supplemental
Maximum Underground Underground
Firm Storage Maximum Storage Maximum
Transportation Withdrawal Withdrawal Expiration
DT/Day DT/Day (1) DT/Day (2) Date
------------ --------------- -------------- ---------
<S> <C> <C> <C> <C>
ATLANTA GAS LIGHT COMPANY
Southern
Firm Transportation 617,559 August 31, 2002
Firm Transportation 46,223 August 31, 2003
Firm Transportation 111,192 April 30, 2007
Firm Transportation 1,021 June 30, 2007
CSS 390,113 August 31, 2002
CSS 24,640 August 31, 2003
ANR - 50 113,000 March 31, 2003
ANR - 100 55,500 March 31, 2003
Transco
Firm Transportation 111,366 March 31, 2010
Firm Transportation 15,525 July 1, 2005
Firm Transportation 6,440 March 17, 2008
Firm Transportation 4,658 October 31, 2009
Firm Transportation 85,000 November 1, 2013
WSS 73,059 March 31, 2010
ESS 31,357 October 31, 2013
GSS 59,012 June 30, 2001 (3)
GSS 70,296 March 31, 2013 (3)
LSS 18,040 March 31, 1994 (4)
SS-1 20,918 March 31, 2008
LGA 42,975 October 31, 2002
Cove Point LNG 69,000 April 15, 2001
Supplemental Peaking 15,000 March 31, 2001
Tennessee/East Tennessee
Firm Transportation (ETN) 61,160 November 1, 2000
FS Storage 30,572 November 1, 2000
CNG 3,421 March 31, 2001
South Georgia
Firm Transportation (SGNG) 12,115 April 30, 2007
ANR - 100 708 March 31, 2003
CSS 6,906 February 28, 1999
------------ ----------- -----------
Total 1,072,259 560,068 464,449
============ =========== ===========
CHATTANOOGA GAS COMPANY
Southern
Firm Transportation 4,747 August 31, 2003
Firm Transportation 14,346 August 31, 2003
Firm Transportation 3,369 April 30, 2007
Firm Transportation 5,105 November 1, 2006
CSS 14,346 August 31, 2003
Tennessee/East Tennessee
Firm Transportation (TN) 39,792 November 1, 2000
Firm Transportation (ETN) 46,350 November 1, 2000
FS Storage 21,400 November 1, 2000
CNG 2471 March 31, 2001
------------ -----------
Total 73,917 38,217
============ ===========
<FN>
(1) Production area storage requires a complementary amount of the firm
transportation capacity identified in the first column to move storage gas
withdrawals to the Company's service area.
(2) Supplemental underground storage withdrawals include delivery to the
Company's service area and do not require any of the firm transportation
capacity identified in the first column. Injections into supplemental
underground storage require incremental transportation, primarily from
transportation identified in Column 1.
(3) Expiration dates are shown for this contract although it has not yet been
executed. AGLC is operating under Natural Gas Act (NGA) certificate
authority while negotiating this contract.
(4) The Company is operating under Natural Gas Act (NGA) certificate
authority while negotiating a contract.
"DT" is an abbreviation for dekatherms.
</FN>
</TABLE>
6
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Wellhead Supply. AGLC and Chattanooga have entered into firm wellhead
supply contracts for 346,940 dekatherms (DT)/day and 24,931 DT/day,
respectively, to supply their firm transportation and underground storage
capacity. AGLC and Chattanooga are finalizing contract negotiations for
additional firm wellhead supply contracts of 110,000 DT/day and 9,765 DT/day
respectively. Those contracts will be completed during the first quarter of
fiscal 1999. AGLC also purchases spot market gas as needed during the year.
Liquefied Natural Gas. To meet the demand for natural gas on the coldest
days of the winter months, AGLC must also maintain sufficient supplemental
quantities of liquefied natural gas (LNG) in its supply portfolio. AGLC's three
strategically located Georgia-based LNG plants - north and south of Atlanta and
near Macon - provide a combined maximum daily supplement of approximately
815,000 thousands of cubic feet (Mcf) and a combined usable storage capacity of
72 million gallons, equivalent to 5,952,000 Mcf. Chattanooga's LNG plant
provides a maximum daily supplement of approximately 90,000 Mcf and has a usable
storage capacity of 13 million gallons, equivalent to 1,076,000 Mcf.
Risk Management. AGLC's Gas Supply Plan for fiscal 1998 included limited
gas supply hedging activities. AGLC was authorized to begin an expanded program
to hedge up to one-half its estimated monthly winter wellhead purchases and to
establish a price for those purchases at an amount other than the
beginning-of-the-month index price. Such a program creates an additional element
of diversification and price stability. The financial results of all hedging
activities were passed through to residential and small commercial customers
under the PGA provisions of AGLC's rate schedules.
Accordingly, the hedging program did not affect our earnings.
Consistent with fiscal 1998, AGLC's Gas Supply Plan for fiscal 1999 will
include limited gas supply hedging activities. In conjunction with deregulation,
the fiscal 1999 hedging results will not pass through to residential and small
commercial customers through a regulated PGA mechanism. Accordingly, in fiscal
1999, the hedging program may affect earnings.
Beginning in November 1998, AGLC began to make public the price at which
it sells gas. AGLC also began a fixed-price option program to minimize the risk
of loss incurred as a result of gas volume and price volatility after the price
has been published. Each month before publishing the sales price, AGLC will
determine whether to enter into a fixed-price option agreement for the
respective month. In the event AGLC enters into such an agreement, it will pay a
monthly option premium based on the potential need for incremental wellhead
purchases. Such premium will fix AGLC's maximum gas purchase cost for
incremental wellhead purchases at the agreement's fixed price. Accordingly, in
the event actual gas prices on any day during the month exceed the agreement's
fixed price for the month, the option reimburses AGLC the difference in excess
of the fixed price. If the actual gas price on any day during the month is less
than the fixed price, AGLC pays the lesser price. The anticipated results of
fixed-price option agreements will be to limit the effect of gas price
volatility on earnings.
State Regulatory Matters
Unbundling and AGLC Rate Filing. Georgia's Natural Gas Competition and
Deregulation Act became law on April 14, 1997. It provides a legal framework for
comprehensive deregulation of many aspects of the natural gas business in
Georgia.
On November 26, 1997, AGLC filed the following items with the GPSC:
- a notice of AGLC's election to be subject to Georgia's Natural Gas
Competition and Deregulation Act; and
- an application to unbundle (offer separately and establish
separate rates for) the various components of AGLC's services to
its customers and to regulate distribution rates, charges,
classifications, and services under a performance-based
regulation plan.
7
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After hearings were held in that proceeding, the GPSC set the rates AGLC
will charge end-use customers (during the transition to competition) and
marketers (during and after the transition to competition) for natural gas
delivery and ancillary services. Those decisions are reflected in the GPSC's
initial order of June 30, 1998. On July 10, 1998, AGLC and other parties to the
proceeding petitioned the GPSC to reconsider some issues in its initial order.
The GPSC subsequently issued partial orders on reconsidered issues on September
18, October 16, and October 22, 1998.
Key decisions adopted by the GPSC are as follows:
- a $12.75 million annual rate decrease based on a fully forecasted
future test year for the 12 months ending May 31, 1999;
- an 11% rate of return on common equity;
- the end of regulated rates for natural gas commodity sales effective
October 6, 1998;
- separate, distinct ancillary service rates for meter reading,
billing, billing inquiries, payment processing, and payment
collection based on AGLC's fully allocated costs;
- balancing services, storage services, and peaking services provided
on a separate basis;
- denial of AGLC's proposed comprehensive performance-based rate
regulation plan;
- any customer may, during the transition period, return to the
natural gas commodity sales service offered by AGLC;
- advance payment by marketers to AGLC for fixed charges for services
to be provided;
- 90% of revenues from interruptible service by AGLC will go to a
universal service fund (see explanation below), and the remaining
10% will be revenue for AGLC;
- AGLC must conduct its business so that it does not give preference
to any marketer; and
- AGLC must implement a fully operational electronic bulletin board
(EBB); the EBB provides marketers with equal and timely access to
information about the availability of distribution service to
residential and small commercial customers.
As part of the GPSC's rate case ruling, AGLC began billing customers on
July 1, 1998, under a rate structure that recovers nongas costs evenly
throughout the year consistent with the way the costs are incurred. The new rate
structure:
- provides for a level monthly charge for gas delivery service;
- provides the opportunity to grow margins at a rate more
commensurate with AGLC's above average customer growth rate;
- eliminates the need for weather normalization; and
- eliminates the adverse effects of declining use per customer, which
AGLC has experienced for the past several years.
Georgia's Natural Gas Competition and Deregulation Act provides for a
transition period before competition is fully in effect. AGLC will unbundle, or
separate, all services to its natural gas customers; allocate delivery capacity
to approved marketers who sell the gas commodity to residential and small
commercial users; and create a secondary market for large commercial and
industrial transportation capacity.
Approved marketers, including our marketing affiliate, will compete to
sell natural gas to all end-use customers at market-based prices. AGLC will
continue to deliver gas to all end-use customers through its existing pipeline
system, subject to the GPSC's continued regulation. The GPSC's order
acknowledges that under Georgia's Natural Gas Competition and Deregulation Act,
the PGA mechanism will be deregulated when at least five nonaffiliated marketers
are authorized to serve an area of Georgia. The GPSC issued more than five such
authorizations on October 6, 1998. Consequently, AGLC will no longer defer any
over-recoveries or under-recoveries of gas costs, and will refund to customers
the over-recovery that existed when the PGA mechanism was deregulated on October
6, 1998.
8
<PAGE>
Going forward, AGLC intends to design its prices for deregulated gas
sales in a manner that, at a minimum, will allow it to recover its annual gas
costs. Even though the recovery of gas costs is not currently subject to price
regulation, the GPSC continues to regulate delivery rates, safety, access to
AGLC's system, and quality of service for all aspects of delivery service.
Generally, under Georgia's Natural Gas Competition and Deregulation Act,
the transition to full-scale competition occurs when residential and small
commercial customers who represent one-third of the peak day requirements for a
particular delivery group have voluntarily selected a marketer. When the GPSC
determines such market conditions exist, there will be a 120-day process to
notify and assign customers who have not selected a marketer. Following the
120-day period, residential and small commercial customers who have not yet
selected a marketer will be randomly assigned a marketer under the rules issued
by the GPSC.
Georgia's Natural Gas Competition and Deregulation Act provides marketing
standards and rules of business practice to ensure the benefits of a competitive
natural gas market are available to all customers on our system. It imposes on
marketers an obligation to serve end-use customers, and creates a universal
service fund. The universal service fund provides a method to fund the recovery
of marketers' uncollectible accounts, and it enables AGLC to expand its
facilities to serve the public interest.
Retail marketing companies, including our marketing affiliate, filed
separate applications with the GPSC to sell natural gas to AGLC's residential
and small commercial customers. On October 6, 1998, the GPSC approved 19
marketers' applications to begin selling natural gas services at market prices
to Georgia customers on November 1, 1998.
Chattanooga Gas Company - Rate Filing. On May 1, 1997, Chattanooga filed
a rate case with the TRA seeking an annual increase in revenues of $4.4 million.
Chattanooga sought the additional revenue in order to:
- improve and expand Chattanooga's natural gas distribution system;
- recover increased operation, maintenance and tax expenses; and
- provide a reasonable return to investors.
Hearings were held in February 1998. On July 21, 1998, the TRA voted to
direct Chattanooga to decrease rates by $1.2 million, primarily as a result of
the TRA's rejection of the proposed overhead allocation method and rejection of
proposed recovery of a previously incurred acquisition premium. Following the
TRA's October 7, 1998, written order, Chattanooga filed tariffs reflecting the
reduction in revenue for service beginning November 1, 1998.
AGLC Pipeline Safety. On January 8, 1998, the GPSC issued procedures and
set a schedule for hearings about alleged pipeline safety violations. On July
21, 1998, the GPSC approved a settlement between AGLC and the Adversary Staff of
the GPSC that details a 10-year replacement program for approximately 2,300
miles of cast iron and bare steel pipelines. Over that 10-year period, AGLC will
recover from customers the costs related to the program net of any cost savings
resulting from the replacement program.
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<PAGE>
Weather Normalization. The GPSC authorized a weather normalization
adjustment rider (WNAR) which was in effect during fiscal 1996, fiscal 1997, and
the first nine months of fiscal 1998. In addition, the TRA has authorized a
WNAR. WNARs are designed to offset the impact of unusually cold or warm weather
on customer billings and operating margin.
Consequently, weather normalization affected net income in the following manner:
- net income decreased by $1.2 million in fiscal 1998;
- net income increased by $16.2 million in fiscal 1997; and
- net income decreased by $4.4 million in fiscal 1996.
On June 30, 1998, the WNAR for AGLC was discontinued, since the rate
structure mandated by Georgia's Natural Gas Competition and Deregulation Act
eliminates the effect of weather-related volumetric variances on nongas cost
revenue collections. The WNAR for Chattanooga remains in effect.
Environmental. Before natural gas was available in the Southeast in the
early 1930s, AGLC manufactured gas from coal and other materials. Those
manufacturing operations were known as manufactured gas plants. Because of
recent environmental concerns, we are required to investigate possible
contamination at those plants and, if necessary, clean them up. Additional
information relating to environmental matters and disclosures is contained in
Note 12, "Environmental Matters" included in the Notes to Consolidated Financial
Statements in the Annual Report and is incorporated herein by reference.
We have two ways of recovering investigation and cleanup costs. First,
the GPSC has approved an "Environmental Response Cost Recovery Rider." It allows
us to recover our costs of investigation, testing, cleanup, and litigation.
Because of that rider, we have recorded an asset in the same amount as our
investigation and cleanup liability. The GPSC, however, is conducting hearings
about three aspects of the rider. Depending on how the GPSC rules, our
recoveries under the rider could be affected. If the GPSC were to limit
significantly our recovery under the rider, the results could be material. The
second way we could recover costs is by exercising the legal rights we believe
we have to recover a share of our costs from other corporations and from
insurance companies.
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Federal Regulatory Matters
FERC Order 636: Transition Costs Settlement Agreements. The utility
purchases natural gas transportation and storage services from interstate
pipeline companies, and the Federal Energy Regulatory Commission (FERC)
regulates those services and the rates the interstate pipeline companies charge
the utility. During the past decade, the FERC has dramatically transformed the
natural gas industry through a series of generic orders promoting competition in
the industry. As part of that transformation, the interstate pipelines that
serve the utility have been required to:
- unbundle, or separate, their transportation and gas supply services;
and
- provide a separate transportation service - on a
nondiscriminatory basis - for the gas that is supplied by numerous
gas producers or other third parties.
The FERC is considering further revisions to its rules, including the
following:
- its policies governing secondary market transactions for use of
pipeline capacity; and
- revisions that would permit pipelines and their customers to
establish individually negotiated terms and conditions of service
that depart from generally applicable pipeline tariff rules.
The utility cannot predict whether those changes will be adopted or how
they potentially might affect it.
The FERC has required the utility, as well as other interstate pipeline
customers, to pay transition costs associated with the separation of the
suppliers' transportation and gas supply services. Based on its pipeline
suppliers' filings with the FERC, the utility estimates the total portion of its
transition costs from all its pipeline suppliers will be approximately $106.2
million. As of September 30, 1998, approximately $97.8 million of those costs
had been incurred and were being recovered from the utility's customers under
the purchased gas provisions of its rate schedules. Going forward, AGLC will
recover the majority of the remaining costs through its gas sales. A small
portion of the costs will be recovered from certificated marketers as part of
the assignment process under its unbundling plan.
The largest portion of the transition costs the utility must pay consists
of gas supply realignment costs that Southern Natural Gas Company (Southern) and
Tennessee Gas Pipeline Company (Tennessee) bill the utility. The utility and
other parties have entered restructuring settlements with Southern and Tennessee
that resolve all transition cost issues for those pipelines.
Under the Southern settlement, the utility's share of Southern's
transition costs is approximately $88 million, of which the utility incurred
$84.5 million as of September 30, 1998. Under the Tennessee settlement, the
utility's share of Tennessee's transition costs is approximately $14.7 million,
of which the utility incurred approximately $10 million as of September 30,
1998.
AGLC requested and was granted clarification and assignment waiver of
certain FERC policies concerning interstate pipeline capacity. The request was
necessary to ensure that it would be able to make certain pipeline services it
receives available to certificated marketers as part of its unbundling plan.
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FERC Rate Proceedings. The utility is participating in various rate
proceedings before the FERC that involve its pipeline suppliers' filings for
rate changes. The proceedings typically involve numerous issues about the
pipeline's cost of providing service, allocation of costs to different services,
and rate design. A variety of cost allocation and rate design proposals
typically are advanced by the pipeline's customers, making it impossible to
forecast precisely how any given rate change will affect our operations.
During fiscal 1998, the utility was authorized to recover costs paid to
its pipeline suppliers from its customers through the purchased gas provisions
of its rate schedules. However, pursuant to Georgia's Natural Gas Competition
and Deregulation Act, regulated rates ended on October 6, 1998 for natural gas
commodity sales to AGLC customers. Therefore, going forward, AGLC intends to
recover costs related to pipeline suppliers through its prices for deregulated
gas sales such that on an annual basis it recovers, at a minimum, the actual
costs paid to pipeline suppliers. Chattanooga will continue to recover the costs
paid to its pipeline suppliers from its customers through the purchased gas
provisions of its rate schedules.
To the extent that the following cases have not been settled, the rates
filed in these proceedings have been accepted. However, they are subject to the
outcome of the FERC proceedings and could result in refunds.
Tennessee. The utility is involved in two ongoing Tennessee rate
proceedings:
- The FERC has approved a comprehensive settlement that provides
for a reduction of approximately $83 million in the cost of
service underlying Tennessee's rates that have been in effect
since July 1, 1995. The FERC's orders approving the settlement
were appealed to the United States Court of Appeals for the
District of Columbia Circuit (D.C. Circuit). On July 31, 1998,
that court sent the case back to the FERC for it to determine
whether Tennessee's rate design unlawfully hinders the development
of market centers. The utility's estimated annual reduction in
cost because of the settlement is $2.6 million; however, that
amount may change as a result of further action by the FERC on
remand from the D.C. Circuit.
- The FERC's orders, in a prior Tennessee rate case involving rate
design changes to be effective prospectively, have been appealed
to the D.C. Circuit.
Transco. AGLC is involved in three ongoing Transco rate proceedings:
- The FERC has approved a partial settlement providing for a
reduction of approximately $58 million in the cost of service
underlying Transco's rates that were in effect between September
1, 1995 and April 30, 1997. AGLC's estimated annual reduction in
cost because of the settlement is $2.4 million. The partial
settlement also reserves some issues for litigation, which is
ongoing. The FERC's orders approving the settlement have been
appealed to the D.C. Circuit.
- On June 12, 1998, the FERC issued an order approving a partial
settlement in Transco's current rate case, which provides for a
reduction of approximately $103.3 million in the cost of service
underlying Transco's rates that have been in effect since May 1,
1997. AGLC's estimated annual reduction in cost because of the
settlement is $5.5 million. The partial settlement also reserves
certain issues for litigation, which is ongoing. The FERC's order
approving that settlement is final.
- The FERC's orders in a prior Transco rate proceeding have been
appealed to the D.C. Circuit.
ANR Pipeline. On February 13, 1998, the FERC issued an order approving
a settlement that resolved ANR's rate case. The settlement authorizes AGLC to
receive reimbursement refunds for past overpayments and provides for reductions
of approximately $3.9 million in rates on a prospective basis. The FERC's order
approving the settlement is final.
Arcadian. On May 14, 1998, the United States Court of Appeals for the
Eleventh Circuit rejected AGLC's appeal to the FERC, whose earlier order had
approved a settlement between Southern and Arcadian Corporation (Arcadian)
allowing Southern to bypass AGLC's system and provide direct gas service to
Arcadian's fertilizer plant in Augusta, Georgia. The Eleventh Circuit agreed
with AGLC that the FERC should vacate specific prior orders that required
Southern to provide direct gas service to Arcadian, on the grounds that the
prior orders became moot as a result of the settlement between Southern and
Arcadian.
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Waiver Request. On May 1, 1998, AGLC filed a request for clarification
and waiver of specific FERC policies that govern the transfer of interstate
pipeline capacity from the holders of the capacity to third parties. AGLC filed
that request so it could make the necessary interstate pipeline services
available to marketers as part of the requirements of Georgia's Natural Gas
Competition and Deregulation Act. On July 31, 1998, the FERC issued an order
that authorized AGLC to make interstate pipeline capacity available to
marketers. The order granted AGLC a limited jurisdiction blanket certificate for
one year, which became effective when it unbundled its distribution system as
required by Georgia's Natural Gas Competition and Deregulation Act.
The FERC's authorization is subject to a further filing, which AGLC
submitted on August 31, 1998. A party to the proceeding has protested that
filing. Another party opposing our request for waiver has filed a rehearing
request with FERC challenging the FERC's order.
Etowah LNG. On April 20, 1998, Etowah LNG applied with the FERC seeking
authority to construct a new LNG storage facility in Polk County, Georgia, and
to provide a liquefied natural gas peaking service. AGLC has entered a precedent
agreement to subscribe to the new liquefied natural gas peaking service upon the
FERC's authorization. Etowah LNG's application is pending before the FERC.
The utility cannot predict the outcome of those federal proceedings nor
determine the ultimate effect, if any, the proceedings may have on the utility.
Competition
Utility. The utility competes to supply natural gas to large commercial
and industrial customers. Those customers can switch to alternative fuels,
including propane, fuel and waste oils, electricity and, in some cases,
combustible wood by-products. The utility also competes to supply gas to large
commercial and industrial customers who seek to bypass our distribution system.
Before the GPSC's rate case order of June 30, 1998, AGLC was providing
service under 56 negotiated contracts with customers who had the ability to
bypass its distribution system and receive service directly from interstate
pipelines. In addition, AGLC was providing service under seven special long-term
contracts that involve competing with alternative fuels where physical bypass is
not the relevant competition. Under the regulatory structure then in place, AGLC
was allowed to recover from other customers most of the discounts associated
with such contracts.
The change in the regulatory structure associated with unbundling and
restatement of rates removed the need to recover discounts going forward.
Nevertheless, the GPSC specifically authorized AGLC to continue to enter into
future contracts if the initial term of a contract does not exceed three years
and if all such future contracts include market-out provisions. The GPSC issued
a written order setting forth its decision on May 21, 1998.
Subsequent to July 1, 1998, AGLC can price distribution services to large
commercial and industrial customers in one of three ways:
- GPSC - approved rates in AGLC's tariff;
- discounted rates - if an existing rate is not priced competitively
with a customer's competitive alternative fuel; or
- special contracts approved by the GPSC.
Additionally, interruptible customers have the option of purchasing
delivery service directly from marketers, who are authorized to use capacity on
AGLC's distribution system that is allocated to the marketers for residential
and firm small business customers, whenever such capacity is not being used for
firm customers.
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<PAGE>
On November 27, 1996, the TRA approved an experimental rule allowing
Chattanooga to negotiate contracts with large commercial and industrial
customers who have long-term competitive options, including bypass. The
experimental rule requires that before a large Tennessee customer is allowed a
discounted rate, both the customer and Chattanooga must request that the TRA
approve the rates requested in the contract.
On October 7, 1997, the TRA denied requests from Chattanooga and four
large customers for discounted rates - after deciding that customer bypass was
not imminent. On January 14, 1998, however, the FERC issued an order authorizing
Southern Natural Gas Company to bypass Chattanooga to serve a large industrial
customer. Chattanooga later reached a settlement with that customer to avoid
bypass.
Nonutility. We engage in several competitive, energy-related businesses,
including gas supply services, wholesale and retail propane sales, wholesale gas
and power marketing, retail energy marketing, customer care services, and the
sale of energy-related products and services for residential, commercial, and
industrial customers throughout the Southeast.
Unlike the utility, our nonutility businesses are not regulated. Our
nonutility businesses typically face competition from other companies in the
same or similar businesses. Currently, our nonutility businesses do not have a
material effect on our consolidated financial statements.
Significant Customers
In fiscal 1998, we provided services to approximately 1.5 million
customers, substantially all of which are customers of the utility. No one of
our customers accounted for more than 10% of our total revenues or operating
income in any of our three most recent fiscal years.
Year 2000
Information relating to our year 2000 plan and disclosures is contained
under the caption "Year 2000 Readiness Disclosure" included in "Management's
Discussion and Analysis of Results of Operations and Financial Condition" in the
Annual Report and is incorporated herein by reference.
Environmental Matters
Information relating to environmental matters and disclosures is
contained in Note 12, "Environmental Matters" included in the Notes to
Consolidated Financial Statements in the Annual Report and is incorporated
herein by reference.
Employees
On September 30, 1998, AGL Resources and its subsidiaries had 2,791
employees. Of that total, approximately 700 employees are covered under
collective bargaining agreements. Those agreements provided for a $500 lump sum
payment to each bargaining unit employee in 1998. Based on current pay levels,
it is anticipated that the majority of bargaining unit employees will not
receive any base pay increases until October 1999, at which time base rates are
scheduled to increase by 3.5%. The collective bargaining agreements expire in
2000 and 2001.
14
<PAGE>
ITEM 2. PROPERTIES
AGL Resources considers its properties and the properties of its
subsidiaries to be well maintained, in good operating condition and suitable for
their intended purposes.
The utility's properties consist primarily of distribution systems and
related facilities and local offices serving 231 cities and surrounding areas in
the State of Georgia and 12 cities and surrounding areas in the State of
Tennessee. As of September 30, 1998, AGLC had 26,907 miles of mains and
5,952,000 Mcf of LNG storage capacity in three LNG plants to supplement the gas
supply in very cold weather or emergencies. As of September 30, 1998,
Chattanooga had 1,395 miles of mains and 1,076,000 Mcf of LNG storage capacity
in its LNG plant. At September 30, 1998, the utility's gross utility plant
amounted to approximately $2.1 billion.
At September 30, 1998, AGL Resources' gross nonutility property amounted
to approximately $106 million.
ITEM 3. LEGAL PROCEEDINGS
The nature of the business of AGL Resources and its subsidiaries
ordinarily results in periodic regulatory proceedings before various state and
federal authorities and/or litigation incidental to the business. For
information regarding regulatory proceedings, see the preceding sections in Part
I, Item 1, "Business - State Regulatory Matters", "Business - Federal Regulatory
Matters" and "Business - Environmental Matters"
With regard to other legal proceedings, AGL Resources is a party, as both
plaintiff and defendant, to a number of other suits, claims and counterclaims on
an ongoing basis. Management believes that the outcome of all litigation in
which it is involved will not have a material adverse effect on the consolidated
financial statements of AGL Resources.
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 the fiscal year covered by this report.
15
<PAGE>
ITEM 4.(A) EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below, in accordance with General Instruction G(3) of Form 10-K
and Instruction 3 of Item 401(b) of Regulation S-K, is certain information
regarding the executive officers of AGL Resources. Unless otherwise indicated,
the information set forth is as of September 30, 1998.
Walter M. Higgins, age 54, President and Chief Executive Officer of AGL
Resources and AGLC since January 1998; Director of AGL Resources since February
1998; Chairman of the Board, President and Chief Executive Officer of Sierra
Pacific Resources from January 1994 until January 1998; and President and Chief
Executive officer of Sierra Pacific Power Company, a wholly owned subsidiary of
Sierra Pacific Resources, from February 1994 until January 1998.
Charles W. Bass, age 51, President of AGL Investments, Inc. since May 1998;
Executive Vice President and Chief Operating Officer of AGL Resources from
August 1996 until May 1998; Executive Vice President Market Service and
Development of AGLC from 1994 until 1996; and Senior Vice President Governmental
and Regulatory Affairs of AGLC from 1988 until 1994.
J. Michael Riley, age 47, Senior Vice President and Chief Financial Officer of
AGL Resources and AGLC since May 1998; Vice President and Chief Financial
Officer of AGL Resources from August 1996 until May 1998; Vice President and
Chief Financial Officer of AGLC from November 1996 until May 1998; Vice
President Finance and Accounting of AGLC from 1994 until 1996; and Vice
President and Controller of AGLC from 1991 until 1994.
Paula G. Rosput, age 41, President and Chief Operating Officer of AGLC since
September 1998. Prior to joining AGLC, Ms. Rosput served as President and Chief
Executive Officer of Duke Energy Power Services, a subsidiary of Duke Energy.
Ms. Rosput was president of PanEnergy Power Services, Inc. prior to PanEnergy's
merger with Duke Power.
Paul R. Shlanta, age 41, Senior Vice President and General Counsel of AGL
Resources and AGLC since September 1998. From January 1, 1994 through August 31,
1998, Mr. Shlanta was a Principal with Rowe, Foltz & Martin, P.C., an Atlanta
law firm. Mr. Shlanta was the partner in charge of the firm's corporate
practice.
Richard H. Woodward, age 51, Senior Vice President Public Policy and
Communications of AGL Resources since May 1998; Vice President of AGL Resources
and President of AGL Investments, Inc. from August 1996 until May 1998; Senior
Vice President Business Development of AGLC from 1994 until 1996; and Senior
Vice President Corporate Services of AGLC from 1988 until 1994.
There are no family relationships among the executive officers.
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<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required by this item is set forth under the caption
"Shareholder Information" on page 67 in the Annual Report and is incorporated
herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this item is set forth under the caption
"Selected Financial Data" on page 64 in the Annual Report and is incorporated
herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
The information required by this item is set forth under the caption
"Management's Discussion and Analysis of Results of Operations and Financial
Condition" on pages 18 through 37 in the Annual Report and is incorporated
herein by reference.
ITEM 7.(A) QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
All financial instruments and positions held by AGL Resources described
below are held for purposes other than trading.
The fair value of AGL Resources' long-term debt and capital securities
are affected by changes in interest rates. The carying value of AGL
Resources' long-term debt and capital securities has been the same for the past
two years. The following presents the sensitivity of the fair value of AGL
Resources' long-term debt and capital securities to a hypothetical 10%
decrease in interest rates as of September 30, 1998:
<TABLE>
<CAPTION>
Hypothetical
Carrying Increase in
Value Fair Value (b) Fair Value (a)
-------- -------------- -------------
(Millions of Dollars)
<S> <C> <C> <C>
Long-term debt including current portion $660.0 $714.6 $28.7
Capital Securities $ 74.3 $ 81.5 $ 3.7
- --------------------
<FN>
(a) Calculated based on the change in discounted cash flow.
(b) Based on quoted market prices for these or similar issues.
</FN>
</TABLE>
17
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item with respect to financial
statements is set forth on pages 38 through 63 in the Annual Report. Such
information is incorporated herein by reference and includes:
- Statements of Consolidated Income for the years ended September 30,
1998, 1997 and 1996.
- Statements of Consolidated Cash Flows for the years ended September 30,
1998, 1997 and 1996.
- Consolidated Balance Sheets as of September 30, 1998 and 1997.
- Statements of Consolidated Common Stock Equity for the years ended
September 30, 1998, 1997 and 1996.
- Notes to Consolidated Financial Statements.
- Independent Auditors' Report.
The following supplemental data is submitted herewith:
- Financial Statement Schedule - Valuation and Qualifying Account -
Allowance for Uncollectible Accounts.
- Independent Auditors' Report.
Schedules other than those referred to above are omitted and are not
applicable or not required, or the required information is shown in the
financial statements or notes thereto.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not applicable.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item with respect to directors is set
forth under the caption "Election of Directors" in the Proxy Statement and is
incorporated herein by reference. The information required by this item with
respect to the executive officers is, pursuant to Instruction 3 of Item 401(b)
of Regulation S-K and General Instruction G(3) of Form 10-K, set forth at Part
I, Item 4(A) of this report under the caption "Executive Officers of the
Registrant."
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption
"Executive Compensation" in the Proxy Statement and is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth under the caption
"Security Ownership of Management" in the Proxy Statement and is incorporated
herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the caption
"Other Matters Involving Directors and Executive Officers" in the Proxy
Statement and is incorporated herein by reference.
19
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
FORM 8-K
(a) Documents Filed as Part of This Report:
1. Financial Statements
Included under Item 8 are the following financial statements:
Statements of Consolidated Income for the Years Ended September
30, 1998, 1997 and 1996.
Statements of Consolidated Cash Flows for the Years Ended
September 30, 1998, 1997 and 1996.
Consolidated Balance Sheets as of September 30, 1998 and 1997.
Statements of Consolidated Common Stock Equity for the Years
Ended September 30, 1998, 1997 and 1996.
Notes to Consolidated Financial Statements.
Independent Auditors' Report.
2. Supplemental Consolidated Financial Schedules for Each of the
Three Years in the Period Ended September 30, 1998
Independent Auditors' Report.
II. Valuation and Qualifying Account--Allowance for
Uncollectible Accounts.
Schedules other than those referred to above are omitted and are
not applicable or not required, or the required information is
shown in the financial statements or notes thereto.
3. Exhibits
Where an exhibit is filed by incorporation by reference to a
previously filed registration statement or report, such
registration statement or report is identified in parentheses.
3.1 Amended and Restated Articles of Incorporation filed
January 5, 1996, with the Secretary of State of the State of
Georgia (Exhibit B, Proxy Statement and Prospectus filed as
a part of Amendment No. 1 to Registration Statement
on Form S-4, No. 33-99826).
3.2 Bylaws, as amended and restated on August 7, 1998 (Exhibit 3,
AGL Resources Form 10-Q for the quarter ended June 30, 1998).
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<PAGE>
4.1 Specimen form of Common Stock certificate (Exhibit 4.1, Form
10-K for the fiscal year ended September 30, 1996).
4.2 Specimen form of Right certificate (Exhibit 1, 8-K filed
March 6, 1996).
4.3 Indenture, dated as of December 1, 1989, between Atlanta Gas
Light Company and Bankers Trust Company, as Trustee (Exhibit
4(a), Atlanta Gas Light Company Registration Statement on Form
S-3, No. 33-32274).
4.4 First Supplemental Indenture, dated as of March 16, 1992,
between Atlanta Gas Light Company and NationsBank of
Georgia, National Association, as Successor Trustee
(Exhibit 4(a), Atlanta Gas Light Company Registration
Statement on Form S-3, No. 33-46419).
10.1 Executive Compensation Plans and Arrangements.
10.1.a Executive Severance Pay Plan of AGL Resources Inc. (Exhibit
10.1.a, Form 10-K for the fiscal year ended September 30,
1996).
10.1.b AGL Resources Inc. 1998 Voluntary Early Retirement Plan for
Officers, together with form of Early Retirement Agreement
(Exhibit 10.1.a, AGL Resources Form 10-Q for the quarter ended
June 30, 1998).
10.1.c AGL Resources Inc. 1998 Severance Plan for Officers, together
with form of Separation Agreement (Exhibit 10.1.b, AGL
Resources Form 10-Q for the quarter ended June 30 , 1998).
10.1.d AGL Resources Inc. Long-Term Stock Incentive Plan of 1990
(Exhibit 10(ii), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1991).
10.1.e First Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit B to the Atlanta Gas Light
Company Proxy Statement for the Annual Meeting of Shareholders
held February 5, 1993).
10.1.f Second Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.d, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.1.g Third Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit C to the Proxy Statement and
Prospectus filed as a part of Amendment No. 1 to Registration
Statement on Form S-4, No. 33-99826).
10.1.h Fourth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.f, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.1.i Fifth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.g, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
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10.1.j Sixth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.a, AGL Resources Form 10-Q
for the quarter ended March 31, 1998).
10.1.k AGL Resources Inc. Nonqualified Savings Plan (Exhibit 10(a),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.1.l First Amendment to the AGL Resources Inc. Nonqualified Savings
Plan (Exhibit 10.1.i, AGL Resources Form 10-K for the fiscal
year ended September 30, 1997).
10.1.m Second Amendment to the AGL Resources Inc. Nonqualified
Savings Plan (Exhibit 10.1.j, AGL Resources Form 10-K for the
fiscal year ended September 30, 1997).
10.1.n Third Amendment to the AGL Resources Inc. Nonqualified Savings
Plan (Exhibit 10.1.a, AGL Resources Form 10-Q for the quarter
ended December 31, 1997).
10.1.o AGL Resources Inc. Non-Employee Directors Equity Compensation
Plan (Exhibit B, Proxy Statement and Prospectus filed as a part
of Amendment No. 1 to Registration Statement on Form S-4,
No. 33-99826).
10.1.p AGL Resources Inc. 1998 Common Stock Equivalent Plan for
Non-Employee Directors (Exhibit 10.1.b, AGL Resources Form
10-Q for the quarter ended December 31, 1997).
10.2 Service Agreement under Rate Schedule GSS dated April 13,
1972, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 5(c),
Registration No. 2-48297).
10.3 Service Agreement under Rate Schedule LG-A, effective August 16,
1974, between Atlanta Gas light Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 5(d),
Registration No. 2-58971).
10.4 Storage Transportation Agreement, dated June 1, 1979, between
Atlanta Gas Light Company and Southern Natural Gas Company,
(Exhibit 5(n), Registration No. 2-65487).
10.5 Letter of Intent dated September 18, 1987, between Atlanta
Gas Light Company and Jupiter Industries, Inc. relating to
the purchase by Atlanta Gas Light Company of the assets of the
Chattanooga Gas Company Division of Jupiter Industries, Inc.
(Exhibit 10(p), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1987).
10.6 Agreement for the Purchase of Assets dated April 5, 1988,
between Atlanta Gas Light Company and Jupiter Industries,
Inc., (Exhibit 10(q), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1988).
22
<PAGE>
10.7 100 Day Storage Service Agreement, dated June 1, 1979,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company, (Exhibit 10(r), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1989).
10.8 Service Agreement under Rate Schedule LSS, dated October 31,
1984, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation, (Exhibit 10(s), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1989).
10.9 Storage Transportation Agreement, dated June 1, 1979,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company, (Exhibit 10(v), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1990).
10.10 Firm Seasonal Transportation Agreement, dated June 29, 1990,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(bb), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1990).
10.11 Service Agreement under Rate Schedule WSS, dated June 1, 1990,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(cc), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1990).
10.12 Limited-Term Transportation Agreement Contract # A970 dated
April 1, 1988, between Atlanta Gas Light Company and CNG
Transmission Corporation, (Exhibit 10(bb), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1991).
10.13 Service Agreement System Contract #.2271 under Rate Schedule
FT, dated August 1, 1991, between Atlanta Gas Light Company
and Transcontinental Gas Pipe Line Corporation, (Exhibit
10(dd), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1991).
10.14 Service Agreement System Contract #.4984 dated August 1, 1991,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(ee), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1991).
10.15 Service Agreement Contract #830810 under Rate Schedule FT,
dated March 1, 1992, between Atlanta Gas Light Company and
South Georgia Natural Gas Company (Exhibit 10(aa), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
10.16 Firm Gas Transportation Contract #3699 under Rate Schedule FT,
dated February 1, 1992, between Atlanta Gas Light Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10(dd),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
23
<PAGE>
10.17 Firm Gas Transportation Agreement under Rate Schedule FT-1,
dated July 1, 1992, between Atlanta Gas Light Company and
East Tennessee Natural Gas Company (Exhibit 10(ff), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
10.18 Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated October 25, 1993, between
Atlanta Gas Light Company and CNG Transmission Corporation
(Exhibit 10(y), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1993).
10.19 Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated September, 1993, between
Chattanooga Gas Company and CNG Transmission Corporation
(Exhibit 10(z), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1993).
10.20 Firm Seasonal Transportation Agreement, dated February 1,
1992, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation amending Exhibit 10(bb), Atlanta Gas
Light Company Form 10-K for the fiscal year ended September
30, 1990 (Exhibit 10(cc), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1993).
10.21 Service Agreement under Rate Schedule SS-1, dated April 1,
1988, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10(z), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1994).
10.22 Firm Gas Transportation Agreement #5049 under Rate Schedule
FT-A, dated November 1, 1993, between Atlanta Gas Light
Company and Tennessee Gas Pipeline Company (Exhibit 10(aa),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.23 Firm Gas Transportation Agreement #5051 under Rate Schedule
FT-A, dated November 1, 1993, between Chattanooga Gas
Company and Tennessee Gas Pipeline Company (Exhibit
10(bb), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1994).
10.24 Gas Storage Contract #3998 under Rate Schedule FS, dated
November 1, 1993, between Atlanta Gas Light Company and
Tennessee Gas Pipeline Company (Exhibit 10(cc), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.25 Gas Storage Contract #3999 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and
Tennessee Gas Pipeline Company (Exhibit 10(dd), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.26 Gas Storage Contract #3923 under Rate Schedule FS, dated
November 1, 1993, between Atlanta Gas Light Company and
Tennessee Gas Pipeline Company (Exhibit 10(ee), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
24
<PAGE>
10.27 Gas Storage Contract #3947 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and
Tennessee Gas Pipeline Company (Exhibit 10(ff), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.28 Service Agreement #902470 under Rate Schedule FT, dated
September 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(hh), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.29 Service Agreement #904460 under Rate Schedule FT, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(ii), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.30 Service Agreement #904480 under Rate Schedule FT, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(jj), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.31 Service Agreement #904461 under Rate Schedule FT-NN, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(kk), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.32 Service Agreement #904481 under Rate Schedule FT-NN, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(ll), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.33 Service Agreement #S20140 under Rate Schedule CSS, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(mm), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.34 Service Agreement #S20150 under Rate Schedule CSS, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(nn), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.35 Service Agreement #904470 under Rate Schedule FT, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(oo), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994).
10.36 Service Agreement #904471 under Rate Schedule FT-NN, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(pp), Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1994).
25
<PAGE>
10.37 Service Agreement #S20130 under Rate Schedule CSS, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(qq), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994).
10.38 Firm Storage (FS) Agreement, dated November 1, 1994, between
Atlanta Gas Light Company and ANR Storage Company
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.39 Firm Storage (FS) Agreement, dated November 1, 1994, between
Atlanta Gas Light Company and ANR Storage Company
(Exhibit 10(b), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.40 Firm Transportation Agreement, dated March 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibits 10(jj), 10(ll) and 10(mm), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(c), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.41 Firm Transportation Agreement, dated March 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibits 10(hh), 10(ii), 10(kk) and 10(nn),
Atlanta Gas Light Company Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(d), Atlanta Gas Light
Company Form 10-Q for the quarter ended March 31, 1996).
10.42 Firm Transportation Agreement, dated March 1, 1996, between
Chattanooga Gas Company and Southern Natural Gas Company
amending Exhibits 10(oo), 10(pp) and 10(qq), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended June 30, 1996).
10.43 Firm Transportation Agreement, dated June 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibit 10(ii), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(tt),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.44 Firm Storage Agreement, effective December 1, 1994, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit
10(uu), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1995).
10.45 Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(vv),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
26
<PAGE>
10.46 Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(dd), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(ww),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.47 Firm Transportation Agreement, dated September 26, 1994,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company amending Exhibit 10(s), Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(xx), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1995).
10.48 Firm Storage Agreement, effective July 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ee), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(yy),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.49 Firm Storage Agreement, effective July 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(cc), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(zz),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.50 Firm Storage Agreement, effective January 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(z) and replacing Exhibit 10(u), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(a), Atlanta Gas Light
Company Form 10-Q for the quarter ended December 31, 1995).
10.51 Firm Storage Agreement, effective January 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(aa) and replacing Exhibit 10(dd), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(b), Atlanta Gas Light Company
Form 10-Q for the quarter ended December 31, 1995).
10.52 Gas Sales Agreement between Seller and Atlanta Gas Light
Company, as Buyer (Exhibit 10(a), Atlanta Gas Light Company
Form 10-Q for the quarter ended March 31, 1995).
10.53 FPS-1 Service Agreement, dated July 9, 1996, between Atlanta
Gas Light Company and Cove Point LNG Limited Partnership
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended June 30, 1996).
10.54 Amendment to FS Agreement, dated September 13, 1994, between
Atlanta Gas Light Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.54, Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1996).
27
<PAGE>
10.55 Amendment to Letter Agreement, dated July 13, 1994, among and
between Southern Natural Gas Company, Atlanta Gas Light Company
and Chattanooga Gas Company (Exhibit 10.55, Atlanta Gas
Light Company Form 10-K for the fiscal year ended
September 30, 1996).
10.56 Three-party agreement between ANR Storage Company, Atlanta
Gas Light Company and Southern Natural Gas Company, effective
November 1, 1994 (Exhibit 10.56, Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1996).
10.57 Displacement Service Agreement, effective December 15, 1996,
between Washington Gas Light Company and Atlanta Gas Light
Company (Exhibit 10.57, Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1996).
10.58 Amendment to Firm Storage Agreement, effective July 26, 1996,
between Chattanooga Gas Company and Southern Natural Gas
Company amending Exhibit 10(jj) , Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1995
(Exhibit 10.58, Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1996).
10.59 Amendatory Agreement, effective August 23, 1996, between
Southern Natural Gas Company and Atlanta Gas Light Company
amending Exhibits 10(ee), 10(ff), 10(hh) and 10(kk),
Atlanta Gas Light Company Form 10-K for the fiscal year
ended September 30, 1995 (Exhibit 10.59, Atlanta Gas
Light Company Form 10-K for the fiscal year ended
September 30, 1996).
10.60 Service Agreement and Amendments under Rate Schedule FS
between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10.60, AGL Resources
Form 10-K for the fiscal year ended September 30, 1997).
10.61 Gas Transportation Agreement under Rate Schedules FT-A and
FT-GS, dated October 16, 1997, between Atlanta Gas Light
Company and East Tennessee Natural Gas Company (Exhibit 10.61,
AGL Resources Form 10-K for the fiscal year ended September
30, 1997).
10.62 Gas Transportation Agreement under Rate Schedules FT-A and
FT-GS, dated October 16, 1997, between Chattanooga Gas Company
and East Tennessee Natural Gas Company (Exhibit 10.62, AGL
Resources Form 10-K for the fiscal year ended September 30,
1997).
10.63 Extension of Service Agreements #904480 under Rate Schedule
FT; #904481 under Rate Schedule FT-NN; and #S20140 under Rate
Schedule CSS, all dated November 1, 1994, between Atlanta Gas
Light Company and Southern Natural Gas Company (Exhibit 10.2,
AGL Resources Form 10-Q for the quarter ended December 31,
1998).
10.64 Amendment to Service Agreement between Transcontinental Gas
Pipe Line Corporation and Atlanta Gas Light Company dated
December 15, 1997 (Exhibit 10.2, AGL Resources Form
10-Q for the quarter ended March 31, 1998).
28
<PAGE>
10.65 Service Agreement between Transcontinental Gas Pipe Line
Corporation and Atlanta Gas Light Company dated
January 14, 1998 (Exhibit 10.3, AGL Resources Form 10-Q
for the quarter ended March 31, 1998).
10.66 Precedent Agreement dated April 16, 1998 between Etowah LNG
Company, LLC and Atlanta Gas Light Company (Exhibit 10.2,
AGL Resources Form 10-Q for the quarter ended June 30, 1998).
10.67 Service Agreement dated November 1, 1998 between
Transcontinental Gas Pipe Line Corporation and Atlanta Gas Light
Company under Part 284(G) which supercedes Rate Schedule X-289.
10.68 Service Agreement dated November 1, 1998 between
Transcontinental Gas Pipe Line Corporation and Atlanta Gas Light
Company under Rate Schedule WSS-Open Access.
13 Portions of the AGL Resources Inc. 1998 Annual Report to
Shareholders.
21 Subsidiaries of AGL Resources Inc.
23 Independent Auditors' Consent.
24 Powers of Attorney (included with Signature Page hereto).
27 Financial Data Schedule.
(b) Reports on Form 8-K
On July 15, 1998, AGL Resources filed a Current Report on Form 8-K
dated July 15, 1998, containing: "Item 5 Other Events" and Exhibit 99 -
Form of Press Release, dated July 15, 1998.
On August 7, 1998, AGL Resources filed a Current Report on Form 8-K
dated August 7, 1998, containing: "Item 5 Other Events" and Exhibit 99 -
Form of Press Release, dated August 7, 1998.
On September 10, 1998, AGL Resources filed a Current Report on Form
8-K dated September 10, 1998, containing: "Item 5 - Other Events" and
Exhibit 99 - Form of Press Release, dated September 10, 1998.
29
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on December 17, 1998.
AGL RESOURCES INC.
By: /s/ Walter M. Higgins
Walter M. Higgins
President and Chief Executive Officer
POWERS OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints Walter M. Higgins, Albert G. Norman, Jr.
and J. Michael Riley, and each of them, his or her true and lawful
attorneys-in-fact and agents, with full power of substitution and
resubstitution, for him or her and in his or her name, place and stead, in any
and all capacities, to sign the Annual Report on Form 10-K for the fiscal year
ended September 30, 1998 and any and all amendments to such Annual Report, and
to file the same, with all exhibits thereto and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and perform each and every act and thing requisite or necessary to be done, as
fully to all intents and purposes as he or she might or could do in person,
hereby ratifying and confirming all that said attorneys-in-fact and agents or
any of them, or their or his substitute or substitutes, may lawfully do or cause
to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated as of December 17, 1998.
Signatures Title
/s/ Walter M. Higgins President and Chief Executive Officer
Walter M. Higgins (Principal Executive Officer) and Director
/s/ J. Michael Riley Senior Vice President and Chief Financial Officer
J. Michael Riley (Principal Accounting and Financial Officer)
30
<PAGE>
/s/ Frank Barron, Jr. Director
Frank Barron, Jr.
/s/ W. Waldo Bradley Director
W. Waldo Bradley
/s/ Otis A. Brumby, Jr. Director
Otis A. Brumby, Jr.
/s/ David R. Jones Director
David R. Jones
Director
Wyck A. Knox, Jr.
/s/ Albert G. Norman, Jr. Director
Albert G. Norman, Jr.
/s/ D. Raymond Riddle Director
D. Raymond Riddle
/s/ Betty L. Siegel Director
Betty L. Siegel
/s/ Ben J. Tarbutton, Jr. Director
Ben J. Tarbutton, Jr.
/s/ Felker W. Ward, Jr. Director
Felker W. Ward, Jr.
31
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of AGL Resources Inc.:
We have audited the consolidated balance sheets of AGL Resources Inc. and
subsidiaries of September 30, 1998 and 1997 and the related statements of
consolidated income, common stock equity, and cash flows for each of the three
years in the period ended September 30, 1998, and have issued our report thereon
dated November 2, 1998; such financial statements and report are included in
your 1998 Annual Report to Shareholders and are incorporated herein by
reference. Our audits also included the financial statement schedule of AGL
Resources Inc. and subsidiaries, listed in Item 14. This financial statement
schedule is the responsibility of AGL Resources Inc.'s management. Our
responsibility is to express an opinion based on our audits. In our opinion,
such financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
November 2, 1998
32
<PAGE>
Schedule II
<TABLE>
AGL RESOURCES INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNT
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1998, 1997 AND 1996
(IN MILLIONS)
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance, beginning of year $ 2.6 $ 2.8 $ 4.4
Additions:
Provisions charged to income 8.1 9.8 4.7
- --------------------------------------------------------------------------------------------------------------------------
Total 10.7 12.6 9.1
Deduction:
Accounts written off as uncollectible, net 6.6 10.0 6.3
- --------------------------------------------------------------------------------------------------------------------------
Balance, end of year $ 4.1 $ 2.6 $ 2.8
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
33
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Description
Where an exhibit is filed by incorporation by reference to a
previously filed registration statement or report, such
registration statement or report is identified in parentheses.
3.1 Amended and Restated Articles of Incorporation filed
January 5, 1996, with the Secretary of State of the State of
Georgia (Exhibit B, Proxy Statement and Prospectus filed as
a part of Amendment No. 1 to Registration Statement
on Form S-4, No. 33-99826).
3.2 Bylaws, as amended and restated on August 7, 1998 (Exhibit 3,
AGL Resources Form 10-Q for the quarter ended June 30, 1998).
4.1 Specimen form of Common Stock certificate (Exhibit 4.1, Form
10-K for the fiscal year ended September 30, 1996).
4.2 Specimen form of Right certificate (Exhibit 1, 8-K filed
March 6, 1996).
4.3 Indenture, dated as of December 1, 1989, between Atlanta Gas
Light Company and Bankers Trust Company, as Trustee (Exhibit
4(a), Atlanta Gas Light Company Registration Statement on Form
S-3, No. 33-32274).
4.4 First Supplemental Indenture, dated as of March 16, 1992,
between Atlanta Gas Light Company and NationsBank of
Georgia, National Association, as Successor Trustee
(Exhibit 4(a), Atlanta Gas Light Company Registration
Statement on Form S-3, No. 33-46419).
10.1 Executive Compensation Plans and Arrangements.
10.1.a Executive Severance Pay Plan of AGL Resources Inc. (Exhibit
10.1.a, Form 10-K for the fiscal year ended September 30,
1996).
10.1.b AGL Resources Inc. 1998 Voluntary Early Retirement Plan for
Officers, together with form of Early Retirement Agreement
(Exhibit 10.1.a, AGL Resources Form 10-Q for the quarter ended
June 30, 1998).
10.1.c AGL Resources Inc. 1998 Severance Plan for Officers, together
with form of Separation Agreement (Exhibit 10.1.b, AGL
Resources Form 10-Q for the quarter ended June 30 , 1998).
10.1.d AGL Resources Inc. Long-Term Stock Incentive Plan of 1990
(Exhibit 10(ii), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1991).
10.1.e First Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit B to the Atlanta Gas Light
Company Proxy Statement for the Annual Meeting of Shareholders
held February 5, 1993).
10.1.f Second Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.d, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.1.g Third Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit C to the Proxy Statement and
Prospectus filed as a part of Amendment No. 1 to Registration
Statement on Form S-4, No. 33-99826).
10.1.h Fourth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.f, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.1.i Fifth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.g, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.1.j Sixth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.a, AGL Resources Form 10-Q
for the quarter ended March 31, 1998).
10.1.k AGL Resources Inc. Nonqualified Savings Plan (Exhibit 10(a),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.1.l First Amendment to the AGL Resources Inc. Nonqualified Savings
Plan (Exhibit 10.1.i, AGL Resources Form 10-K for the fiscal
year ended September 30, 1997).
10.1.m Second Amendment to the AGL Resources Inc. Nonqualified
Savings Plan (Exhibit 10.1.j, AGL Resources Form 10-K for the
fiscal year ended September 30, 1997).
10.1.n Third Amendment to the AGL Resources Inc. Nonqualified Savings
Plan (Exhibit 10.1.a, AGL Resources Form 10-Q for the quarter
ended December 31, 1997).
10.1.o AGL Resources Inc. Non-Employee Directors Equity Compensation
Plan (Exhibit B, Proxy Statement and Prospectus filed as a part
of Amendment No. 1 to Registration Statement on Form S-4,
No. 33-99826).
10.1.p AGL Resources Inc. 1998 Common Stock Equivalent Plan for
Non-Employee Directors (Exhibit 10.1.b, AGL Resources Form
10-Q for the quarter ended December 31, 1997).
10.2 Service Agreement under Rate Schedule GSS dated April 13,
1972, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 5(c),
Registration No. 2-48297).
10.3 Service Agreement under Rate Schedule LG-A, effective August 16,
1974, between Atlanta Gas light Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 5(d),
Registration No. 2-58971).
10.4 Storage Transportation Agreement, dated June 1, 1979, between
Atlanta Gas Light Company and Southern Natural Gas Company,
(Exhibit 5(n), Registration No. 2-65487).
10.5 Letter of Intent dated September 18, 1987, between Atlanta
Gas Light Company and Jupiter Industries, Inc. relating to
the purchase by Atlanta Gas Light Company of the assets of the
Chattanooga Gas Company Division of Jupiter Industries, Inc.
(Exhibit 10(p), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1987).
10.6 Agreement for the Purchase of Assets dated April 5, 1988,
between Atlanta Gas Light Company and Jupiter Industries,
Inc., (Exhibit 10(q), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1988).
10.7 100 Day Storage Service Agreement, dated June 1, 1979,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company, (Exhibit 10(r), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1989).
10.8 Service Agreement under Rate Schedule LSS, dated October 31,
1984, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation, (Exhibit 10(s), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1989).
10.9 Storage Transportation Agreement, dated June 1, 1979,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company, (Exhibit 10(v), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1990).
10.10 Firm Seasonal Transportation Agreement, dated June 29, 1990,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(bb), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1990).
10.11 Service Agreement under Rate Schedule WSS, dated June 1, 1990,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(cc), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1990).
10.12 Limited-Term Transportation Agreement Contract # A970 dated
April 1, 1988, between Atlanta Gas Light Company and CNG
Transmission Corporation, (Exhibit 10(bb), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1991).
10.13 Service Agreement System Contract #.2271 under Rate Schedule
FT, dated August 1, 1991, between Atlanta Gas Light Company
and Transcontinental Gas Pipe Line Corporation, (Exhibit
10(dd), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1991).
10.14 Service Agreement System Contract #.4984 dated August 1, 1991,
between Atlanta Gas Light Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(ee), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1991).
10.15 Service Agreement Contract #830810 under Rate Schedule FT,
dated March 1, 1992, between Atlanta Gas Light Company and
South Georgia Natural Gas Company (Exhibit 10(aa), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
10.16 Firm Gas Transportation Contract #3699 under Rate Schedule FT,
dated February 1, 1992, between Atlanta Gas Light Company and
Transcontinental Gas Pipe Line Corporation (Exhibit 10(dd),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
10.17 Firm Gas Transportation Agreement under Rate Schedule FT-1,
dated July 1, 1992, between Atlanta Gas Light Company and
East Tennessee Natural Gas Company (Exhibit 10(ff), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1992).
10.18 Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated October 25, 1993, between
Atlanta Gas Light Company and CNG Transmission Corporation
(Exhibit 10(y), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1993).
10.19 Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated September, 1993, between
Chattanooga Gas Company and CNG Transmission Corporation
(Exhibit 10(z), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1993).
10.20 Firm Seasonal Transportation Agreement, dated February 1,
1992, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation amending Exhibit 10(bb), Atlanta Gas
Light Company Form 10-K for the fiscal year ended September
30, 1990 (Exhibit 10(cc), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1993).
10.21 Service Agreement under Rate Schedule SS-1, dated April 1,
1988, between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10(z), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30,
1994).
10.22 Firm Gas Transportation Agreement #5049 under Rate Schedule
FT-A, dated November 1, 1993, between Atlanta Gas Light
Company and Tennessee Gas Pipeline Company (Exhibit 10(aa),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.23 Firm Gas Transportation Agreement #5051 under Rate Schedule
FT-A, dated November 1, 1993, between Chattanooga Gas
Company and Tennessee Gas Pipeline Company (Exhibit
10(bb), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1994).
10.24 Gas Storage Contract #3998 under Rate Schedule FS, dated
November 1, 1993, between Atlanta Gas Light Company and
Tennessee Gas Pipeline Company (Exhibit 10(cc), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.25 Gas Storage Contract #3999 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and
Tennessee Gas Pipeline Company (Exhibit 10(dd), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.26 Gas Storage Contract #3923 under Rate Schedule FS, dated
November 1, 1993, between Atlanta Gas Light Company and
Tennessee Gas Pipeline Company (Exhibit 10(ee), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.27 Gas Storage Contract #3947 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and
Tennessee Gas Pipeline Company (Exhibit 10(ff), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.28 Service Agreement #902470 under Rate Schedule FT, dated
September 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(hh), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.29 Service Agreement #904460 under Rate Schedule FT, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(ii), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.30 Service Agreement #904480 under Rate Schedule FT, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(jj), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.31 Service Agreement #904461 under Rate Schedule FT-NN, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(kk), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.32 Service Agreement #904481 under Rate Schedule FT-NN, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(ll), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.33 Service Agreement #S20140 under Rate Schedule CSS, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(mm), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.34 Service Agreement #S20150 under Rate Schedule CSS, dated
November 1, 1994, between Atlanta Gas Light Company and
Southern Natural Gas Company (Exhibit 10(nn), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1994).
10.35 Service Agreement #904470 under Rate Schedule FT, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(oo), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994).
10.36 Service Agreement #904471 under Rate Schedule FT-NN, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(pp), Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1994).
10.37 Service Agreement #S20130 under Rate Schedule CSS, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(qq), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994).
10.38 Firm Storage (FS) Agreement, dated November 1, 1994, between
Atlanta Gas Light Company and ANR Storage Company
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.39 Firm Storage (FS) Agreement, dated November 1, 1994, between
Atlanta Gas Light Company and ANR Storage Company
(Exhibit 10(b), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.40 Firm Transportation Agreement, dated March 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibits 10(jj), 10(ll) and 10(mm), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(c), Atlanta Gas Light Company Form 10-Q for the
quarter ended March 31, 1996).
10.41 Firm Transportation Agreement, dated March 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibits 10(hh), 10(ii), 10(kk) and 10(nn),
Atlanta Gas Light Company Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(d), Atlanta Gas Light
Company Form 10-Q for the quarter ended March 31, 1996).
10.42 Firm Transportation Agreement, dated March 1, 1996, between
Chattanooga Gas Company and Southern Natural Gas Company
amending Exhibits 10(oo), 10(pp) and 10(qq), Atlanta Gas Light
Company Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended June 30, 1996).
10.43 Firm Transportation Agreement, dated June 1, 1996, between
Atlanta Gas Light Company and Southern Natural Gas Company
amending Exhibit 10(ii), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(tt),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.44 Firm Storage Agreement, effective December 1, 1994, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit
10(uu), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1995).
10.45 Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(vv),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.46 Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(dd), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(ww),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.47 Firm Transportation Agreement, dated September 26, 1994,
between Atlanta Gas Light Company and South Georgia Natural
Gas Company amending Exhibit 10(s), Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(xx), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1995).
10.48 Firm Storage Agreement, effective July 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ee), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(yy),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.49 Firm Storage Agreement, effective July 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(cc), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit 10(zz),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.50 Firm Storage Agreement, effective January 1, 1996, between
Atlanta Gas Light Company and Tennessee Gas Pipeline Company
amending Exhibit 10(z) and replacing Exhibit 10(u), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(a), Atlanta Gas Light
Company Form 10-Q for the quarter ended December 31, 1995).
10.51 Firm Storage Agreement, effective January 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(aa) and replacing Exhibit 10(dd), Atlanta
Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(b), Atlanta Gas Light Company
Form 10-Q for the quarter ended December 31, 1995).
10.52 Gas Sales Agreement between Seller and Atlanta Gas Light
Company, as Buyer (Exhibit 10(a), Atlanta Gas Light Company
Form 10-Q for the quarter ended March 31, 1995).
10.53 FPS-1 Service Agreement, dated July 9, 1996, between Atlanta
Gas Light Company and Cove Point LNG Limited Partnership
(Exhibit 10(a), Atlanta Gas Light Company Form 10-Q for the
quarter ended June 30, 1996).
10.54 Amendment to FS Agreement, dated September 13, 1994, between
Atlanta Gas Light Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10.54, Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1996).
10.55 Amendment to Letter Agreement, dated July 13, 1994, among and
between Southern Natural Gas Company, Atlanta Gas Light Company
and Chattanooga Gas Company (Exhibit 10.55, Atlanta Gas
Light Company Form 10-K for the fiscal year ended
September 30, 1996).
10.56 Three-party agreement between ANR Storage Company, Atlanta
Gas Light Company and Southern Natural Gas Company, effective
November 1, 1994 (Exhibit 10.56, Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1996).
10.57 Displacement Service Agreement, effective December 15, 1996,
between Washington Gas Light Company and Atlanta Gas Light
Company (Exhibit 10.57, Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1996).
10.58 Amendment to Firm Storage Agreement, effective July 26, 1996,
between Chattanooga Gas Company and Southern Natural Gas
Company amending Exhibit 10(jj) , Atlanta Gas Light Company
Form 10-K for the fiscal year ended September 30, 1995
(Exhibit 10.58, Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1996).
10.59 Amendatory Agreement, effective August 23, 1996, between
Southern Natural Gas Company and Atlanta Gas Light Company
amending Exhibits 10(ee), 10(ff), 10(hh) and 10(kk),
Atlanta Gas Light Company Form 10-K for the fiscal year
ended September 30, 1995 (Exhibit 10.59, Atlanta Gas
Light Company Form 10-K for the fiscal year ended
September 30, 1996).
10.60 Service Agreement and Amendments under Rate Schedule FS
between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10.60, AGL Resources
Form 10-K for the fiscal year ended September 30, 1997).
10.61 Gas Transportation Agreement under Rate Schedules FT-A and
FT-GS, dated October 16, 1997, between Atlanta Gas Light
Company and East Tennessee Natural Gas Company (Exhibit 10.61,
AGL Resources Form 10-K for the fiscal year ended September
30, 1997).
10.62 Gas Transportation Agreement under Rate Schedules FT-A and
FT-GS, dated October 16, 1997, between Chattanooga Gas Company
and East Tennessee Natural Gas Company (Exhibit 10.62, AGL
Resources Form 10-K for the fiscal year ended September 30,
1997).
10.63 Extension of Service Agreements #904480 under Rate Schedule
FT; #904481 under Rate Schedule FT-NN; and #S20140 under Rate
Schedule CSS, all dated November 1, 1994, between Atlanta Gas
Light Company and Southern Natural Gas Company (Exhibit 10.2,
AGL Resources Form 10-Q for the quarter ended December 31,
1998).
10.64 Amendment to Service Agreement between Transcontinental Gas
Pipe Line Corporation and Atlanta Gas Light Company dated
December 15, 1997 (Exhibit 10.2, AGL Resources Form
10-Q for the quarter ended March 31, 1998).
10.65 Service Agreement between Transcontinental Gas Pipe Line
Corporation and Atlanta Gas Light Company dated
January 14, 1998 (Exhibit 10.3, AGL Resources Form 10-Q
for the quarter ended March 31, 1998).
10.66 Precedent Agreement dated April 16, 1998 between Etowah LNG
Company, LLC and Atlanta Gas Light Company (Exhibit 10.2,
AGL Resources Form 10-Q for the quarter ended June 30, 1998).
10.67 Service Agreement dated November 1, 1998 between
Transcontinental Gas Pipe Line Corporation and Atlanta Gas Light
Company under Part 284(G) which supercedes Rate Schedule X-289.
10.68 Service Agreement dated November 1, 1998 between
Transcontinental Gas Pipe Line Corporation and Atlanta Gas Light
Company under Rate Schedule WSS-Open Access.
13 Portions of the AGL Resources Inc. 1998 Annual Report to
Shareholders.
21 Subsidiaries of AGL Resources Inc.
23 Independent Auditors' Consent.
24 Powers of Attorney (included with Signature Page hereto).
27 Financial Data Schedule.
Contract # .4173
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
ATLANTA GAS LIGHT COMPANY
DATED
November 1, 1998
SERVICE AGREEMENT
THIS AGREEMENT entered into this first day of November, 1998, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation,
hereinafter referred to as "Seller," first party, and ATLANTA GAS LIGHT
COMPANY, hereinafter referred to as "Buyer," second party,
W I T N E S S E T H
WHEREAS, pursuant to Order Nos. 636, issued by the Federal Energy
Regulatory Commission (Commission), Buyer has notified Seller of its desire to
convert its firm transportation service under Seller=s Rate Schedule X-289 from
Service under Part 157 of the Commission=s regulations to service under Part
284(G) of the Commission=s regulations; and
WHEREAS, Buyer has designated that such Part 284(G) service will be
rendered under Seller=s Rate Schedule FT; and
WHEREAS, Seller has prepared this agreement for service for Buyer under
Rate Schedule FT, and this agreement will supersede and terminate the existing
service agreement between Seller and Buyer under Rate Schedule X-289.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of
Seller's Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to
Seller gas for transportation and Seller agrees to receive, transport and
redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up
to the dekatherm equivalent of a Transportation Contract Quantity (ATCQ@) of
a. 15,000 Mcf per day for the peak winter months of
December, January, and February, and
b. 13,500 Mcf per day for the shoulder winter months of
November and March
2. Transportation service rendered hereunder shall not be subject to
curtailment or interruption except as provided in Section 11 of the General
Terms and Conditions of Seller=s FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
SERVICE AGREEMENT (CONTINUED)
Buyer shall deliver or cause to be delivered gas at the point(s) of
receipt hereunder at a pressure sufficient to allow the gas to enter Seller=s
pipeline system at the varying pressures that may exist in such system from time
to time; provided, however, the pressure of the gas delivered or caused to be
delivered by Buyer shall not exceed the maximum operating pressure(s) of
Seller=s pipeline system at such point(s) of receipt. In the event the maximum
operating pressure(s) of Seller=s pipeline system, at the point(s) of receipt
hereunder, is from time to time increased or decreased, then the maximum
allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to
Seller at the point(s) of receipt shall be correspondingly increased or
decreased upon written notification of Seller to Buyer. The point(s) of receipt
for natural gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas
transported hereunder at the following point(s) of delivery and at a pressure(s)
of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of November 1, 1998 and shall
remain in force and effect until 9:00 a.m. Central Clock Time November 1, 2005
and thereafter until terminated by Seller or Buyer upon at least nine (9) months
prior written notice; provided, however, this agreement shall terminate
immediately and, subject to the receipt of necessary authorizations, if any,
Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable
judgment fails to demonstrate credit worthiness, and (b) Buyer fails to provide
adequate security in accordance with Section 32 of the General Terms and
Conditions of Seller's Volume No. 1 Tariff. As set forth in Section 8 of Article
II of Seller=s August 7,1989 revised Stipulation and Agreement in Docket Nos.
RP88-68 et. al., (a) pregranted abandonment under Section 284.221(d) of the
Commission=s Regulations shall not apply to any long term conversions from firm
sales service to transportation service under Seller=s Rate Schedule FT and (b)
Seller shall not exercise its right to terminate this service agreement as it
applies to transportation service resulting from conversions from firm sales
service so long as Buyer is willing to pay rates no less favorable than Seller
is otherwise able to collect from third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder
in accordance with Seller's Rate Schedule FT and the applicable provisions of
the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the
Federal Energy Regulatory Commission, and as the same may be legally amended or
superseded from time to time. Such Rate Schedule and General Terms and
Conditions are by this reference made a part hereof. In the event Buyer and
Seller mutually agree to a negotiated rate and specified term for service
hereunder, provisions governing such negotiated rate (including surcharges) and
term shall be set forth on Exhibit C to the service agreement.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers
or causes to be delivered to Seller shall include the quantity of gas retained
by Seller for applicable compressor fuel, line loss make-up (and injection fuel
under Seller=s Rate Schedule GSS, if applicable) in providing the transportation
service hereunder, which quantity may be changed from time to time and which
will be specified in the currently effective Sheet No. 44 of Volume No. 1 of
this Tariff which relates to service under this agreement and which is
incorporated herein.
3. In addition to the applicable charges for firm transportation
service pursuant to Section 3 of Seller=s Rate Schedule FT, Buyer shall
reimburse Seller for any and all filing fees incurred as a result of Buyer's
request for service under Seller=s Rate Schedule FT, to the extent such fees are
imposed upon Seller by the Federal Energy Regulatory Commission or any successor
governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This agreement supersedes and cancels as of the effective date
hereof the following contract(s) between the parties hereto:
Rate Schedule X-289 Service Agreement between Seller and
Buyer, dated June 29, 1990, as amended on February 1, 1992 and as
amended on February 1, 1993.
2. No waiver by either party of any one or more defaults by the other
in the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like or
different character.
3. The interpretation and performance of this agreement shall be in
accordance with the laws of the State of Texas, without recourse to the law
governing conflict of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of
the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered
as duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P. O. Box 1396
Houston, Texas 77251
Attention: Customer Services
(b) If to Buyer:
Atlanta Gas Light Company
P. O. Box 4569
Atlanta, Georgia 30302-4569
Attention: Eileen Stanek
Such addresses may be changed from time to time by mailing appropriate notice
thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Seller)
By /s/ Frank J. Ferazzi
Frank J. Ferazzi
Vice President - Customer Service and Rates
ATLANTA GAS LIGHT COMPANY
(Buyer)
By /s/ Paula G. Rosput
EXHIBIT A
<TABLE>
<CAPTION>
Buyer's Buyer's
Mainline Capacity Mainline Capacity
Entitlement Entitlement
Receipt Peak Months Shoulder Months
Point 1/ (Mcf per Day) 2/ (Mcf per Day) 3/
----- ----------------- -----------------
<S> <C> <C>
TIER I 1/ Holmesville 13,032 11,729
TIER II 1/ 13,032 11,729
Jefferson Davis County-
Miss Fuels
Hattiesburg - First Reserve
TIER III 1/ 15,000 13,500
Clarke County - Miss Fuels
Magnolia Pipeline Interconnect
Jonesboro - SNG
Heidelberg
Station 85 Main Line Pool
- --------
<FN>
1/ TIER I - Transco's mainline between Holmesville and Station 70
TIER II - Transco's mainline between Station 70 and Station 80
TIER III - Transco's mainline downstream of Station 80
2/ Transco's ability to receive gas under this Rate Schedule at specific
point(s) of receipt is subject to the operating limitations of Transco
and the upstream party at such point(s) and the availability of
capacity at such point(s) of receipt.
3/ These quantities do not include the additional quantities of gas
retained by Seller for applicable compressor fuel and line loss
make-up provided for in Article V, 2 of this Service Agreement,
which are subject to change as provided for in Article V, 2 hereof.
The volume provided for each tier represents the maximum allowable
firm capacity entitlement to be transported through the associated
tier from all receipt points within that tier. However, the total
cumulative capacity entitlement for all receipt points provided
herein shall not exceed the specified capacity entitlement provided
for Tier III, which amount shall equal Shipper's transportation
contract demand quantity. To the extent that on any day other
participants in Transco's Southern Expansion Project are not
utilizing their total daily TCQ within a Tier, Transco is willing to
receive additional quantities of gas from Shipper at such points
within such Tier, on an interruptible basis, not to exceed Shipper's
total daily TCQ.
</FN>
</TABLE>
EXHIBIT B
<TABLE>
<CAPTION>
Facility Group Facility Group
Delivery Point Increment Increment
Delivery Increment Peak Months Shoulder Months
Point(s) of Delivery and Pressure * (Mcf per Day) (Mcf per Day) (Mcf per Day)
<S> <C> <C> <C>
Group 6
Riverdale 5,000
----------- ------------- --------------
Total 5,000 4,500
Group 7
Stockbridge 15,000
Athens 6,000
Bogart 4,000
----------- ------------- --------------
Total 15,000 13,500
Total Transportation
Contract Quantity: 15,000 13,500
-------------- --------------
<FN>
* Subject to the conditions contained in this Agreement, Seller shall
make deliveries of gas for the account of Buyer at the Point(s) of
Delivery specified above at such pressures as may be available from
time to time in Seller's line serving such Point(s) of Delivery not to
exceed maximum allowable operating pressure, but not less than fifty
(50) psig or at such other pressures as may be agreed upon in the
day-to-day operations of Buyer and Seller.
Deliveries of gas to the Point(s) of Delivery shall be subject to the
limitations of Shipper's Delivery Point Entitlements (DPE) at such
points as set forth in Transco's FERC Gas Tariff.
</FN>
</TABLE>
SERVICE AGREEMENT UNDER RATE SCHEDULE WSS-OPEN ACCESS
THIS AGREEMENT entered into this 1st day of November, 1998, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation,
hereinafter referred to as "Seller", first party, and ATLANTA GAS LIGHT COMPANY,
hereinafter referred to as "Buyer", second party.
W I T N E S S E T H:
WHEREAS, Seller has made available to Buyer storage capacity from its
Washington Storage Field under Part 284 of the Commission's Regulations; and
Buyer desires to purchase and Seller desires to sell natural gas storage service
under Seller's Rate Schedule WSS-Open Access as set forth herein;
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
SERVICE TO BE RENDERED
Subject to the terms and provisions of this agreement and of Seller's
Rate Schedule WSS-Open Access, Seller agrees to inject into storage for Buyer's
account, store and withdraw from storage, quantities of natural gas as follows:
To withdraw from storage up to a maximum quantity on any day of 73,059
dt, which quantity shall be Buyer's Storage Demand Quantity, or such
greater daily quantity, as applicable from time to time, pursuant to
the terms and conditions of Seller's Rate Schedule WSS-Open Access.
To receive and store up to a total quantity at any one time of
6,210,000 dt, which quantity shall be Buyer's Storage Capacity
Quantity.
ARTICLE II
POINT(S) OF RECEIPT AND DELIVERY
The Point of Receipt for injection of natural gas delivered to Seller
by Buyer and the Point of Delivery for withdrawal of natural gas delivered by
Seller to Buyer under this agreement shall be Seller's Washington Storage Field
located at Seller's Station 54 in St. Landry Parish, Louisiana. Gas delivered or
received in Seller's pipeline system shall be at the prevailing pressure not to
exceed the maximum allowable operating pressure.
ARTICLE III
TERM OF AGREEMENT
This agreement shall be effective November 1, 1998 and shall remain in
force and effect until March 31, 2010, and year to year thereafter, subject to
termination by either party upon six months written notice to the other party.
ARTICLE IV
RATE SCHEDULE AND PRICE
Buyer shall pay Seller for natural gas service rendered hereunder in
accordance with Seller's Rate Schedule WSS-Open Access, and the applicable
provisions of the General Terms and Conditions of Seller's FERC Gas Tariff as
filed with the Federal Energy Regulatory Commission, and as the same may be
amended or superseded from time to time. Such Rate Schedule and General Terms
and Conditions are by this reference made a part hereof. In the event Buyer and
Seller mutually agree to a negotiated rate and specified term for service
hereunder, provisions governing such negotiated rate (including surcharges) and
term shall be set forth on Exhibit A to the service agreement.
ARTICLE V
MISCELLANEOUS
1. The subject headings of the Articles of this agreement are inserted
for the purpose of convenient reference and are not intended to be a part of
this agreement nor to be considered in any interpretation of the same.
2. This agreement supersedes and cancels as of the effective date
hereof the following contracts between the parties hereto: .0905
3. No waiver by either party of any one or more defaults by the other
in the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like or
different character.
4. This agreement shall be interpreted, performed and enforced in
accordance with the laws of the State of Texas.
5. This agreement shall be binding upon, and inure to the benefit of
the parties hereto and their respective successors and assigns.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller)
By /s/ Frank J. Ferazzi
Frank J. Ferazzi
Vice President
Customer Service and Rates
ATLANTA GAS LIGHT COMPANY
(Buyer)
By /s/ Paula G.Rosput
EXHIBIT A
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Specification of Negotiated Rate and Term
- -----------------------------------------
Management's Discussion and Analysis of Results of Operations and Financial
Condition
Forward-Looking Statements
The Private Securities Litigation Reform Act of 1995 requires public companies
to provide cautionary remarks about forward-looking statements that they make
in documents that are filed with the Securities and Exchange Commission.
Forward-looking statements in our Management's Discussion and Analysis
include statements about the following:
- - deregulation;
- - environmental investigations and cleanups; and
- - "Year 2000" readiness.
Important factors that could cause our actual results to differ substantially
from those in the forward-looking statements include, but are not limited to,
the following:
- - changes in price and demand for natural gas and related products;
- - uncertainties about state and federal legislative and regulatory issues;
- - the effects of deregulation and competition, particularly in markets
where prices and providers historically have been regulated;
- - changes in accounting policies and practices;
- - uncertainties about environmental and competitive issues; and
- - other factors discussed in the following section: Year 2000 Readiness
Disclosure - Forward-Looking Statements.
Nature of Our Business
Following shareholder and regulatory approval on March 6, 1996, AGL Resources
Inc. became the holding company for:
- - Atlanta Gas Light Company (AGLC) and its wholly owned subsidiary, Chattanooga
Gas Company (Chattanooga), which are local natural gas distribution utilities;
and
- - several nonutility subsidiaries.
We collectively refer to AGL Resources Inc. and its subsidiaries as "AGL
Resources."
AGLC conducts our primary business: the distribution of natural gas in
Georgia, including the Atlanta, Athens, Augusta, Brunswick, Macon, Rome,
Savannah, and Valdosta areas and in Tennessee, including the Chattanooga and
Cleveland areas. The Georgia Public Service Commission (GPSC) regulates AGLC,
and the Tennessee Regulatory Authority (TRA) regulates Chattanooga. AGLC
comprises substantially all of AGL Resources' assets, revenues, and earnings.
When we discuss the operations and activities of AGLC and Chattanooga, we refer
to them, collectively, as the "utility."
Graph depicts the utility service area (major cities).
AGL Resources also owns the following wholly owned nonutility subsidiaries:
- - AGL Energy Services, Inc., a gas supply services company that has one wholly
owned nonutility subsidiary, Georgia Gas Company;
- - AGL Interstate Pipeline Company which owns a 50% interest in Cumberland
Pipeline Company; Cumberland Pipeline Company is expected to provide interstate
pipeline services to customers in Georgia and Tennessee beginning November 1,
2000;
- - AGL Investments, Inc., which was established to develop and manage
certain nonutility businesses including:
* AGL Gas Marketing, Inc., which owns a 35% interest in Sonat Marketing, L.P.;
Sonat Marketing, L.P. engages in wholesale and retail natural gas trading;
* AGL Power Services, Inc., which owns a 35% interest in Sonat Power Marketing,
L.P.; Sonat Power Marketing, L.P. engages in wholesale power trading;
* AGL Propane, Inc., which engages in the sale of propane and related products
and services;
* Trustees Investments, Inc., which owns Trustees Gardens, a residential and
retail development located in Savannah, Georgia; and
* Utilipro, Inc., which engages in the sale of integrated customer care
solutions to energy marketers; and
- - AGL Peaking Services, Inc., which owns a 50% interest in Etowah LNG Company
LLC; Etowah LNG Company LLC is a joint venture with Southern Natural Gas
Company and was formed for the purpose of constructing, owning, and
operating a liquefied natural gas peaking facility.
In July 1998, AGL Resources formed a joint venture known as SouthStar Energy
Services LLC (SouthStar). SouthStar was established to sell natural gas,
propane, fuel oil, electricity, and related services to industrial, commercial,
and residential customers in Georgia and the Southeast. SouthStar is a joint
venture among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a
subsidiary of Dynegy, Inc., and Piedmont Energy Company, a subsidiary of
Piedmont Natural Gas Company. SouthStar filed for certification as a retail
marketer with the GPSC on July 15, 1998, and was approved on October 6, 1998.
SouthStar operates in Georgia under the name "Georgia Natural Gas Services."
Graph reflects throughput (utility operations) of therms sold and transported by
class of customer for the year ended September 30, 1998. Data presented is as
follows:
Throughput
(utility Percentage
Customer operations) of Total
- ----------------------------------------------
Industrial 1.7 billion 51%
Commercial .55 billion 16%
Residential 1.1 billion 33%
- ----------------------------------------------
Graph reflects margin (utility operations) by class of customer for the year
ended September 30, 1998. Data presented is as follows:
Margin
(utility
Customer operations)
- -------------------------------
Industrial 10%
Commercial 22%
Residential 68%
- -------------------------------
Results of Operations
In this section we compare the results of our operations for fiscal 1996, 1997,
and 1998. Our fiscal year ends on September 30.
Fiscal 1998 compared with fiscal 1997
Operating Revenues Our fiscal 1998 operating revenues increased 4.0%
compared with fiscal 1997 primarily for four reasons:
- - We sold more gas outside of the utility's distribution system;
- - The utility sold more gas to its customers due to weather that was 28.1%
colder in 1998 than in 1997;
- - We received increased revenues in the fourth quarter due to the timing of the
implementation of the new rate structure that became effective July 1, 1998,
for AGLC's gas distribution service. (For a discussion of the levelizing
effect that the new rate structure will have on the collection of revenues by
AGLC for its gas distribution service, see Financial Condition.); and
- - The utility sold more gas due to an increase of approximately 35,000 in
the average number of customers served.
The increase in operating revenues was offset somewhat because of a decrease of
$16.8 million in the amount that AGLC recovered through a rate rider for
expenses associated with an Integrated Resources Plan (IRP), a demand-side
management program that was phased out during fiscal 1998. AGLC balanced IRP
expenses, which were included in operating expenses, with revenues collected
under the rate rider, thereby eliminating the effect that recovery of IRP
expenses otherwise would have had on net income.
Cost of Sales We incur costs for the natural gas that we purchase and resell
to our customers. Our cost of sales increased 3.8% in fiscal 1998 compared with
fiscal 1997 for the following reasons:
- - We sold more gas outside of the utility's distribution system;
- - The utility sold more gas to its customers due to weather that was 28.1%
colder in 1998 than in 1997; and
- - The utility sold more gas due to an increase of approximately 35,000 in the
average number of customers served.
The utility's cost of gas per therm was 36.9 cents in fiscal 1998 and 39.4 cents
in fiscal 1997.
We charged our utility customers for the cost of the natural gas they
consumed using purchased gas adjustment (PGA) mechanisms approved by the GPSC
and the TRA. Under the PGA, we deferred (included as a current asset or
liability in our Consolidated Balance Sheets and excluded from our Statements of
Consolidated Income) the difference between the utility's actual cost of gas
and what the utility collected from its customers in a given period. Then,
the utility either billed or refunded its customers the deferred amount.
Operating Margin Because the utility's cost of gas was completely recovered
from its customers, the cost of gas had no effect on our operating margin. Our
operating margin increased 4.1% in fiscal 1998 over fiscal 1997 for three
primary reasons:
- - the timing of the implementation of the new rate structure that became
effective July 1, 1998, for AGLC's gas distribution service. (For a discussion
of the levelizing effect that the new rate structure will have on operating
margin associated with AGLCs gas distribution service, see Financial
Condition.);
- - an increase of approximately 35,000 in the average number of utility
customers served; and
- - increased margins of $10.7 million from nonutility operations.
The increase in operating margin was offset somewhat because of a decrease of
$16.8 million in the amount that AGLC recovered through a rate rider for
expenses associated with an IRP.
Other Operating Expenses Operation and maintenance expenses increased 7.6% in
fiscal 1998 compared with fiscal 1997 primarily because of the following:
- - noncash, nonrecurring charges of $13.9 million associated with the impairment
of certain assets no longer useful primarily due to changes in our information
systems strategy. (See Note 1 in Notes to Consolidated Financial Statements.);
- - increased expenses of $6.2 million related to maintenance of general plant
and distribution facilities;
- - start-up marketing expenses of $3.7 million for
Georgia Natural Gas Services the trade name in Georgia for SouthStar Energy
Services;
- - charges of $2.6 million related to management restructuring; and
- - increased operating expenses of $2.1 million for AGL Propane, Inc.,
reflecting twelve months' activity for propane operations acquired during
February and June 1997.
The increase in other operating expenses was offset somewhat because of a
decrease of $16.8 million in the amount that AGLC recovered through a rate rider
for expenses associated with an IRP.
Depreciation expense increased 6.8% in fiscal 1998 compared with fiscal 1997
primarily because of more depreciable plant in service. The composite
straight-line depreciation rate was approximately 3.2% for depreciable
utility and nonutility property, excluding transportation equipment, during
fiscal 1998 and fiscal 1997.
Taxes other than income taxes increased $1.4 million in fiscal 1998 compared
with fiscal 1997 primarily because of higher ad valorem taxes.
Other Income Other income increased $2.6 million in fiscal 1998 compared with
fiscal 1997 primarily because of increased income from two joint ventures: AGL
Power Services, Inc. and AGL Gas Marketing, Inc.
Interest Expense Total interest expense increased $2.7 million in fiscal 1998
compared with fiscal 1997 primarily because of higher amounts of long-term deb
outstanding during the period. That increase in interest expense was offset
partly by less interest expense for short-term debt due to decreased amounts of
short-term debt outstanding.
Dividends on Preferred Stock of Subsidiaries Dividends on Preferred Stock of
Subsidiaries increased $.5 million in fiscal 1998 compared with fiscal 1997.
That increase was due to dividend requirements for a full twelve-month period on
$75 million in principal amount of Capital Securities issued in June 1997.
Income Taxes Income taxes decreased $8.0 million in fiscal 1998 compared with
fiscal 1997 due to a decrease in taxable income and a reduction of income tax
expense related to a favorable resolution of certain outstanding income tax
issues. Income tax reserves related to those issues were reduced, thereby
reducing income tax expense. Also, tax benefits associated with the contribution
of certain assets to a private charitable foundation resulted in a decrease in
the effective tax rate for fiscal 1998. (See Note 3 in Notes to Consolidated
Financial Statements.)
Net Income, Earnings per Share, and Dividends per Share:
_______________________________________________________________________________
Basic Earnings Diluted Earnings Dividends
per Common per Common per Common
Fiscal Year Net Income Share Share Share
________________________________________________________________________________
1998 $80.6 million $1.41 $1.41 $1.08
________________________________________________________________________________
1997 $76.6 million $1.37 $1.36 $1.08
________________________________________________________________________________
Net Income and Earnings per Share Net income for fiscal 1998 was $80.6 million
compared with $76.6 million in fiscal 1997. The increase is primarily due to
increased operating margins and decreased income taxes. Increased operating
margins are due to the timing of the implementation of the new rate structure
that became effective July 1, 1998, for AGLC's gas distribution service. (For a
discussion of the levelizing effect that the new rate structure will have on
operating margin associated with AGLCs gas distribution service, see Financial
Condition.) Increased operating margins are also due to an increase of
approximately 35,000 in the average number of utility customers served. However,
that increase in operating margin was offset partly by higher operating
expenses resulting principally from charges associated with the impairment of
certain assets no longer useful primarily due to changes in our information
systems strategy. (See Note 1 in Notes to Consolidated Financial Statements.)
Basic earnings per share in fiscal 1998 were $1.41 compared with $1.37 in fiscal
1997. The weighted average number of common shares outstanding increased
from 56.1 million to 57.0 million. Diluted earnings per common share in fiscal
1998 were $1.41 compared with $1.36 in fiscal 1997. The weighted average
number of common shares outstanding and common share equivalents
increased from 56.2 million to 57.1 million.
Fiscal 1997 compared with fiscal 1996
Operating Revenues Our fiscal 1997 operating revenues increased 4.8% compared
with fiscal 1996 primarily for two reasons:
- - higher revenues from two subsidiaries - $54.4 million from a nonutility
retail energy marketing company, which was formed in June 1996, and $4.4
million from a nonutility gas supply services company, which was formed in
July 1996; and
- - higher utility base revenues as a result of approximately 32,000 new
customers served.
However, the increase in operating revenues was offset somewhat because of the
following:
- - The utility sold less gas to its customers due to weather that was 24.7%
warmer in 1997 than in 1996; and
- - Some industrial customers began using AGLCs transportation services only and
stopped buying gas from AGLC. Therefore, operating revenues related to
those industrial customers did not include revenues related to recovery of
gas costs.
Cost of Sales We incur costs for the natural gas we purchase and resell to
our customers. Our cost of sales increased 5.7% in fiscal 1997 compared with
fiscal 1996 for the following reasons:
- - a nonutility retail energy marketing company and a nonutility gas supply
services company formed in June and July 1996, incurred greater gas
costs of $30.2 million and $12.5 million, respectively.
- - The cost of gas for the utility was higher.
The increase in the cost of gas was offset somewhat by the following:
- - The utility sold less gas to its customers due to weather that was 24.7%
warmer in 1997 than in 1996.
- - As noted above, some industrial customers began using AGLCs transportation
services only and stopped buying gas from AGLC.
The utility's cost of gas per therm was 39.4 cents in fiscal 1997 and 32.2 cents
in fiscal 1996.
We charged our utility customers for the cost of the natural gas they
consumed using PGA mechanisms approved by the GPSC and the TRA. Under the PGA,
we deferred (included as a current asset or liability in our Consolidated
Balance Sheets and excluded from our Statements of Consolidated Income) the
difference between the utilitys actual cost of gas and what the utility
collected from its customers in a given period. Then, the utility either billed
or refunded its customers the deferred amount.
Operating Margin Because the utility's cost of gas was completely recovered
from its customers, the cost of gas had no effect on our operating margin. Our
operating margin increased 3.6% in fiscal 1997 over fiscal 1996 for two primary
reasons:
- - Approximately 32,000 additional utility customers generated higher base
revenues.
- - AGL Energy Services, Inc., which was formed in July 1996, and AGL Propane,
Inc., which acquired operating assets in February and June 1997, produced
greater operating margins.
Other Operating Expenses Operation and maintenance expenses increased 2.3% in
fiscal 1997 compared with fiscal 1996 primarily because of $4.3 million in
greater expenses related to uncollectible accounts, $3.9 million in greater
expenses related to AGL Propane, Inc., which acquired operating assets in
February and June 1997, and $1.9 million in greater expenses related to
maintenance of general plant.
Depreciation expense increased 5.2% in fiscal 1997 compared with fiscal 1996
primarily because of more depreciable plant in service. In fiscal 1997 and
fiscal 1996, the composite straight-line depreciation was approximately 3.2% for
depreciable utility and nonutility property excluding transportation equipment.
Taxes other than income taxes increased $1 million in fiscal 1997
compared with fiscal 1996 primarily because of higher gross receipts taxes and
ad valorem taxes.
Other Income Other income decreased $2.8 million in fiscal 1997 compared
with fiscal 1996 primarily for the following reasons:
- - $3.8 million less income from AGL Gas Marketing, Inc.;
- - $1.5 million less in recoveries of environmental response costs
(investigation, testing, cleanup and litigation costs associated with
our former manufactured gas production sites) from insurance carriers and
third parties; and
- - $1.3 million in higher carrying costs on recoveries of environmental
response costs from insurance carriers and third parties.
Partly offsetting the decrease in other income was the recovery from utility
customers of $2.7 million in increased carrying costs related to storage gas
inventories that were not included in base rates.
Interest Expense Total interest expense increased $3.1 million in fiscal 1997
compared with fiscal 1996 primarily because higher amounts of long-term and
short-term debt were outstanding during the period.
Dividends on Preferred Stock of Subsidiaries Dividends on preferred stock
of subsidiaries increased $1.8 million in fiscal 1997 compared with fiscal 1996.
That increase came from dividends on $75 million in Capital Securities that an
AGL Resources wholly owned business trust issued in June 1997. (See Note 7 in
Notes to Consolidated Financial Statements.)
Income Taxes Income taxes decreased $.7 million in fiscal 1997 compared
with fiscal 1996 because our effective tax rate was lower. The rate was lower
because we made a tax-deductible interest payment on subordinated debt that was
used to fund dividends on Capital Securities issued in June 1997.
Net Income, Earnings per Share, and Dividends per Share:
_______________________________________________________________________________
Basic Earnings Diluted Earnings Dividends
per Common per Common per Common
Fiscal Year Net Income Share Share Share
________________________________________________________________________________
1997 $76.6 million $1.37 $1.36 $1.08
________________________________________________________________________________
1996 $75.6 million $1.37 $1.36 $1.06
________________________________________________________________________________
Net Income and Earnings per Share Net income for fiscal 1997 was $76.6
million compared with $75.6 million in fiscal 1996. The increase in net income
was due to higher operating margins from approximately 32,000 new utility
customers and from two nonutility businesses that were formed during 1996.
However, that increase was offset partly by higher operating expenses and
financing costs and lower other income.
Basic earnings per common share in fiscal 1996 were unchanged compared to
fiscal 1997. The weighted average number of common shares outstanding
increased from 55.3 million to 56.1 million. Diluted earnings per common share
in fiscal 1996 were unchanged compared to fiscal 1997. The weighted average
number of common shares outstanding and common share equivalents increased from
55.4 million to 56.2 million.
Financial Condition
Impact of Deregulation Under Georgias Natural Gas Competition and Deregulation
Act (the Act), AGLC elected to unbundle, or separate, the various components
of its services to its customers. As a result, numerous changes have occurred
with respect to the services being offered by AGLC and with respect to the
manner in which AGLC prices and accounts for those services. Consequently,
AGLCs future expenses and revenues will not follow the same pattern as they
have historically.
Pursuant to the Act, regulated rates ended on October 6, 1998, for natural gas
commodity sales to AGLC customers. Consequently, AGLC will no longer defer
any over-recoveries or under-recoveries of gas costs and will refund to
customers the over-recovery that existed when the PGA provisions were
deregulated.
Going forward, AGLC intends to design its prices for deregulated gas sales
in a manner that, at a minimum, will allow it to recover its annual gas
costs. Accordingly, substantial changes to future quarterly statements of
income are expected from this new regulatory approach. AGLC intends to
recover all its gas costs through the prices it will establish such that on
an annual basis it recovers, at a minimum, the actual costs of acquiring gas
supplies for sales services.
As part of the GPSCs rate case ruling, AGLC began billing customers on
July 1, 1998, under a rate structure that recovers nongas costs evenly
throughout the year consistent with the way the costs are incurred. The
effect of the new rate structure will be to levelize on a
quarter-to-quarter basis the revenues collected by AGLC for gas delivery
services rendered by the utility. Prior to July 1, rates to provide
distribution service were based principally on the amount of gas
customers used.Therefore, total distribution rates were typically lower in
the summer when customers used less gas, and higher in the winter when customers
used more gas. Going forward, AGLC will collect such rates evenly throughout
the year regardless of volumetric summer and winter differences in gas usage.
Graph reflects consolidated operating revenues, operating expenses and operating
expenses as a percentage of operating revenues for the fiscal years ended
September 30, 1996 through 1998, inclusive. Data presented is as follows:
In millions of dollars * 1996 1997 1998
- ----------------------------------------------------
Operating Revenues * 1,229 1,288 1,339
Operating Expenses * 1,065 1,116 1,171
% Operating Expenses to
Operating Revenues 87% 87% 87%
- ----------------------------------------------------
Graph reflects common stock market value, book value and % market to book value
for the fiscal years ended September 30, 1996, through 1998, inclusive. Data
presented is as follows:
In dollars per share * 1996 1997 1998
- ----------------------------------------------------
Market value per share * 19.13 18.94 19.38
Book value per share * 10.56 10.99 11.42
% market value to book
value 181% 172% 170%
- ----------------------------------------------------
In addition, there are other AGLC revenues that reflect costs associated
with services deemed ancillary to distribution service that will change as
customers select a marketer for sales service. For example, as customers choose
a marketer, the associated revenues to AGLC for billing, billing inquiries,
payment collection, payment processing, and possibly meter reading will decrease
if those services are provided by the marketer. The regulatory provisions
provide for a reduction in the revenues associated with those services as AGLC
has the opportunity to avoid such future costs. Consequently, those provisions
will reduce some of the regulated revenue and associated expenses for AGLC.
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (Capital
Securities) In June 1997 we established AGL Capital Trust (the Trust), a
Delaware business trust. The Trust issued two types of securities. Common
voting securities were issued to AGL Resources. In addition, the Trust issued
and sold $75 million principal amount of 8.17% Capital Securities to certain
initial investors. The Trust used the proceeds to purchase 8.17% Junior
Subordinated Deferrable Interest Debentures, which are due June 1, 2037,
from AGL Resources.
The Capital Securities are subject to mandatory redemption at the time
of the repayment of the Junior Subordinated Debentures on June 1, 2037, or
the optional prepayment by AGL Resources after May 31, 2007.
AGL Resources fully and unconditionally guarantees all of the Trust's
obligations for the Capital Securities. We used the net proceeds of
approximately $74 million from the sale of the Junior Subordinated Debentures
to repay short-term debt, to redeem some of AGLC's outstanding issues of
preferred stock, and for other corporate purposes.
AGLC Preferred Securities On August 15, 1997, AGLC fully redeemed the
following:
- - 4.5% Cumulative Preferred Stock;
- - 4.72% Cumulative Preferred Stock;
- - 5% Cumulative Preferred Stock;
- - 7.84% Cumulative Preferred Stock; and
- - 8.32% Cumulative Preferred Stock.
Those issues of preferred stock were redeemed, at the call price in effect for
each issue, for a total of $14.7 million.
On December 1, 1997, AGLC redeemed all of its outstanding 7.70% Series
depositary preferred stock. Accordingly, a current liability associated with
that redemption of $44.5 million was recorded on the Consolidated Balance Sheets
as of September 30, 1997. (See Note 7 in Notes to Consolidated Financial
Statements for additional information regarding preferred stock.)
Common Stock We issued the following shares of common stock:
- - 739,380 shares in fiscal 1998;
- - 753,866 shares in fiscal 1997; and
- - 792,919 shares in fiscal 1996.
Those shares were issued under ResourcesDirect, a direct stock purchase
and dividend reinvestment plan; the Retirement Savings Plus Plan; the Long-Term
Stock Incentive Plan; the Nonqualified Savings Plan; and the Non-Employee
Directors Equity Compensation Plan.
Those issuances increased common equity by the following amounts:
- - $12.9 million in fiscal 1998;
- - $13.8 million in fiscal 1997; and
- - $14.0 million in fiscal 1996.
Ratios and Coverages: -----------------------------------
September 30,
-----------------------------------
1998 1997 1996
___________________________________
Weighted average cost of long-term debt 7.5% 7.5% 7.6%
-----------------------------------
Weighted average cost of preferred stock 8.1% 8.0% 7.5%
-----------------------------------
Return on average common equity 12.6% 12.7% 13.2%
-----------------------------------
Ratio of earnings to combined fixed
charges(1) and preferred stock dividends 2.77 2.90 3.08
-----------------------------------
Ratio of earnings to interest charges(2)
and preferred stock dividends 2.94 3.10 3.28
-----------------------------------
Ratio of earnings to interest charges(2) 3.30 3.46 3.58
___________________________________
(1) Fixed charges consist of interest on short- and long-term debt, other
interest, and the estimated interest components of rentals.
(2) Interest charges exclude the debt portion of allowance for funds used
during construction.
Long-Term Debt During fiscal 1997 we issued $105.5 million in principal
amount of medium-term notes, Series C, with maturity dates ranging from 20 to
30 years and with interest rates ranging from 6.55% to 7.30%. The notes are
unsecured and rank on parity with all other unsecured indebtedness. We used
the net proceeds to fund capital expenditures, repay short-term debt, and
for other corporate purposes. We issued no long-term debt
during fiscal 1998.
Short-Term Debt Because our primary business is highly seasonal, we use
short-term debt to meet seasonal working capital requirements. In addition,
capital expenditures are funded temporarily with short-term debt. Lines of
credit with various banks provide for direct borrowings and are subject to
annual renewal. The current lines of credit vary from $240 million in the
summer to $290 million for peak winter financing.
Short-term debt increased $47 million from $29.5 million as of September 30,
1997, to $76.5 million as of September 30, 1998, to meet working capital
requirements. (See Note 9 in Notes to Consolidated Financial Statements for
additional information concerning short-term debt.)
Capital Requirements Capital expenditures for construction of distribution
facilities, purchase of equipment, and other general improvements were $121.8
million during fiscal 1998. Typically, we provide funding for those
expenditures through a combination of internal sources, the issuance of
short-term and long-term debt, and issuance of equity securities.
We estimate our capital requirements for the next three years, ending on
September 30, 2001, to be approximately $471.9 million, of which approximately
$150 million is attributable to a pipeline replacement program approved
by the GPSC.
As of September 30, 1998, natural gas stored underground decreased $13.7
million to $138.1 million, primarily due to a decrease in the cost of the gas
that we placed into storage.
Ratios and Coverages On September 30, 1998, our capitalization ratios
consisted of:
- - 47.5% long-term debt;
- - 5.4% preferred securities; and
- - 47.1% common equity.
The weighted average cost of long-term debt decreased from 7.6% on
September 30, 1996, to 7.5% on September 30, 1998. The decrease was due to lower
interest rates for long-term debt issued in fiscal 1997.
The ratio of earnings to combined fixed charges and preferred stock
dividends decreased in fiscal 1998 compared with fiscal 1996 primarily due to
increased interest charges. The ratio of earnings to interest charges and
preferred stock dividends decreased in fiscal 1998 compared with fiscal 1996
primarily due to increased interest charges. The ratio of earnings to interest
charges decreased in fiscal 1998 compared with fiscal 1996 primarily due to
increased interest charges.
State Regulatory Activity
Unbundling and AGLC Rate Filing Georgia's Natural Gas Competition and
Deregulation Act became law on April 14, 1997. It provides a legal
framework for comprehensive deregulation of many aspects of the natural
gas business in Georgia.
On November 26, 1997, AGLC filed the following items with the GPSC:
- - a notice of AGLC's election to be subject to the Act; and
- - an application to unbundle (offer separately and establish separate rates for)
the various components of AGLC's services to its customers and to
regulate distribution rates, charges, classifications, and services
under a performance-based regulation plan.
After hearings were held in that proceeding, the GPSC set the rates AGLC will
charge end-use customers (during the transition to competition) and marketers
(during and after the transition to competition) for natural gas delivery and
ancillary services. Those decisions are reflected in the GPSC's initial order
of June 30, 1998. On July 10, 1998, AGLC and other parties to the proceeding
petitioned the GPSC to reconsider some issues in its initial order. The GPSC
subsequently issued partial orders on reconsidered issues on September 18,
October 16, and October 22, 1998.
Key decisions adopted by the GPSC are as follows:
- - a $12.75 million annual rate decrease based on a fully forecasted future test
year for the 12 months ending May 31, 1999;
- - an 11% rate of return on common equity;
- - the end of regulated rates for natural gas commodity sales effective
October 6, 1998;
- - separate, distinct ancillary service rates for meter reading, billing, billing
inquiries, payment processing, and payment collection based on AGLC's fully
allocated costs;
- - balancing services, storage services, and peaking services provided on a
separate basis;
- - denial of AGLC's proposed comprehensive performance-based rate regulation
plan;
- - any customer may, during the transition period, return to the natural gas
commodity sales service offered by AGLC;
- - advance payment by marketers to AGLC for fixed charges for services to
be provided;
- - 90% of revenues from interruptible service by AGLC will go to a
universal service fund (see explanation below), and the remaining 10% will
be revenue for AGLC;
- - AGLC must conduct its business so that it does not give preference to any
marketer; and
- - AGLC must implement a fully operational electronic bulletin board (EBB)
by November 1, 1998; the EBB provides marketers with equal and timely access
to information about the availability of distribution service to
residential and small commercial customers.
As part of the GPSC's rate case ruling, AGLC began billing customers on July 1,
1998, under a rate structure that recovers nongas costs evenly throughout
the year consistent with the way the costs are incurred. The new rate
structure:
- - provides for a level monthly charge for gas delivery service;
- - provides the opportunity to grow margins at a rate more commensurate with
AGLC's above average customer growth rate;
- - eliminates the need for weather normalization; and
- - eliminates the adverse effects of declining use per customer, which AGLC
has experienced for the past several years.
The Act provides for a transition period before competition is fully in effect.
AGLC will unbundle, or separate, all services to its natural gas customers;
allocate delivery capacity to approved marketers who sell the gas commodity
to residential and small commercial users; and create a secondary market for
large commercial and industrial transportation capacity.
Approved marketers, including our marketing affiliate, will compete to
sell natural gas to all end-use customers at market-based prices. AGLC will
continue to deliver gas to all end-use customers through its existing pipeline
system, subject to the GPSC's continued regulation. The GPSC's order
acknowledges that under the Act, the PGA mechanism will be deregulated when
at least five nonaffiliated marketers are authorized to serve an area of
Georgia. The GPSC issued more than five such authorizations on October 6, 1998.
Consequently, AGLC will no longer defer any over-recoveries or under-recoveries
of gas costs, and will refund to customers the over-recovery that existed when
the PGA mechanism was deregulated on October 6, 1998.
Going forward, AGLC intends to design its prices for deregulated gas
sales in a manner that, at a minimum, will allow it to recover its annual gas
costs. Even though the recovery of gas costs is not currently subject to price
regulation, the GPSC continues to regulate delivery rates, safety, access to
AGLC's system, and quality of service for all aspects of delivery service.
Generally, under the Act, the transition to full-scale competition
occurs when residential and small commercial customers who represent one-third
of the peak day requirements for a particular delivery group have voluntarily
selected a marketer. When the GPSC determines such market conditions exist,
there will be a 120-day process to notify and assign customers who have not
selected a marketer. Following the 120-day period, residential and small
commercial customers who have not yet selected a marketer will be randomly
assigned a marketer under the rules issued by the GPSC.
The Act provides marketing standards and rules of business practice to
ensure the benefits of a competitive natural gas market are available to
all customers on our system. It imposes on marketers an obligation to
serve end-use customers, and creates a universal service fund. The
universal service fund provides a method to fund the recovery of
marketer's uncollectible accounts, and it enables AGLC to expand its
facilities to serve the public interest.
Retail marketing companies, including our marketing affiliate, filed separate
applications with the GPSC to sell natural gas to AGLC's residential and small
commercial customers. On October 6, 1998, the GPSC approved 19 marketers'
applications to begin selling natural gas services at market prices to
Georgia customers on November 1, 1998.
Regulatory Accounting We have recorded regulatory assets and liabilities in
our Consolidated Balance Sheets in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71).
In July 1997, the Emerging Issues Task Force (EITF) concluded that once
legislation is passed to deregulate a segment of a utility and that legislation
includes sufficient detail for the enterprise to determine how the transition
plan will affect that segment, SFAS 71 should be discontinued for that segment
of the utility. The EITF consensus permits assets and liabilities of a
deregulated segment to be retained if they are recoverable through a segment
that remains regulated.
Georgia has enacted legislation, the Act, which allows deregulation of
natural gas sales and the separation of some ancillary services of local natural
gas distribution companies. However, the rates that AGLC, as the local gas
distribution company, charges to transport natural gas through its intrastate
pipe system will continue to be regulated by the GPSC. Therefore, we have
concluded that the continued application of SFAS 71 remains appropriate. The
remaining regulatory liability associated with the deregulated gas function will
be refunded.
Chattanooga Gas Company - Rate Filing On May 1, 1997, Chattanooga filed a
rate case with the TRA seeking an annual increase in revenues of $4.4
million. Chattanooga sought the additional revenue in order to:
- - improve and expand Chattanooga's natural gas distribution system;
- - recover increased operation, maintenance and tax expenses; and
- - provide a reasonable return to investors.
Hearings were held in February 1998. On July 21, 1998, the TRA voted to direct
Chattanooga to decrease rates by $1.2 million, primarily as a result of the
TRA's rejection of the proposed overhead allocation method and rejection of
proposed recovery of a previously incurred acquisition premium. Following
the TRA's October 7, 1998, written order, Chattanooga filed tariffs
reflecting the reduction in revenue for service beginning November 1, 1998.
Gas Supply Plan Filing AGLC had been required by Georgia law to submit
annually for GPSC approval a proposed gas supply plan, as well as a proposed
cost recovery factor for the following year.
In September 1997, the GPSC approved AGLC's fiscal 1998 Gas Supply Plan,
which included limited gas supply hedging activities. Under that plan, AGLC was
allowed to hedge up to one-half of its estimated monthly winter wellhead
purchases. Furthermore, to help avoid price fluctuation, AGLC was able to set a
price for those purchases at an amount other than the beginning-of-the-month
index price. Because AGLC then passed on those costs directly to residential and
small commercial customers, its hedging program did not affect fiscal 1998
earnings.
On July 31, 1998, AGLC filed with the GPSC its fiscal 1999 Gas Supply
Plan (the 1999 Plan), which consisted of gas supply, transportation, and storage
options. The 1999 Plan was designed to provide reliable gas service to
residential and small commercial customers at the best cost (least cost
consistent with desired levels of reliability and flexibility). The GPSC
approved the 1999 Plan with some modifications on September 14, 1998.
Under the Act, the 1999 Plan, as approved, became AGLCs first Capacity
Supply Plan (Capacity Plan) when, on October 6, 1998, the GPSC approved more
than five marketers' applications to begin selling natural gas services at
market prices to Georgia consumers. Capacity plans, which must be approved by
the GPSC at least once every three years, describe the array of interstate
capacity assets selected by AGLC to make gas available to end-use
customers on its system. Rights to use capacity assets as set forth in the
Capacity Plan are assigned by AGLC to marketers as the marketers acquire firm
customers. Marketers are responsible for paying fixed charges associated with
the assigned capacity assets.
AGLC Pipeline Safety On January 8, 1998, the GPSC issued procedures and set a
schedule for hearings about alleged pipeline safety violations. On July 21,
1998, the GPSC approved a settlement between AGLC and the Adversary Staff of
the GPSC that details a 10-year replacement program for approximately 2,300
miles of cast iron and bare steel pipelines. Over that 10-year period, AGLC
will recover from customers the costs related to the program net of any cost
savings resulting from the replacement program.
Weather Normalization The GPSC authorized a weather normalization adjustment
rider (WNAR) which was in effect during fiscal 1996, fiscal 1997, and the first
nine months of fiscal 1998. In addition, the TRA has authorized a WNAR. They are
designed to offset the impact of unusually cold or warm weather on customer
billings and operating margin. Consequently, weather normalization affected net
income in the following manner:
- - net income decreased by $1.2 million in fiscal 1998;
- - net income increased by $16.2 million in fiscal 1997; and
- - net income decreased by $4.4 million in fiscal 1996.
On June 30, 1998, the WNAR for AGLC
was discontinued, since the rate structure mandated by the Act eliminates the
effect of weather-related volumetric variances on nongas cost revenue
collections. The WNAR for Chattanooga remains in effect.
Inventory Assignment In Georgia's new competitive environment, certificated
marketing companies, including AGLC's marketing affiliate, began selling natural
gas to firm end-use customers at market-based prices in November 1998. Part of
the unbundling process that provides for this competitive environment is the
allocation of certain pipeline services that AGLC has under contract. In
particular, AGLC will allocate the majority of its pipeline storage services
that it has under contract to the certificated marketing companies along with a
corresponding amount of inventory. Consequently, AGLC has filed tariff
provisions with the GPSC to govern the sale of its gas storage inventories to
certificated marketers. Following the rules of the tariff, the sale price will
be the weighted-average cost of the storage inventory at the time of sale. AGLC
changed its inventory costing method for its gas inventories from first-in,
first-out to weighted average effective October 1, 1998. The weighted-average
cost-flow assumption provides for a more equitable pricing method for the sale
of gas inventories to certificated marketers.
Federal Regulatory Activity
FERC Order 636: Transition Costs Settlement Agreements The utility purchases
natural gas transportation and storage services from interstate pipeline
companies, and the Federal Energy Regulatory Commission (FERC) regulates those
services and the rates the interstate pipeline companies charge the utility.
During the past decade, the FERC has dramatically transformed the natural gas
industry through a series of generic orders promoting competition in the
industry. As part of that transformation, the interstate pipelines that serve
the utility have been required to:
- - unbundle, or separate, their transportation and gas supply services; and
- - provide a separate transportation service on a nondiscriminatory basis for the
gas that is supplied by numerous gas producers or other third parties.
The FERC is considering further revisions to its rules, including the following:
- - its policies governing secondary market transactions for use of pipeline
capacity; and
- - revisions that would permit pipelines and their customers to establish
individually negotiated terms and conditions of service that depart
from generally applicable pipeline tariff rules.
The utility cannot predict whether those changes will be adopted or how they
potentially might affect it.
The FERC has required the utility, as well as other interstate pipeline
customers, to pay transition costs associated with the separation of the
suppliers' transportation and gas supply services. Based on its pipeline
suppliers' filings with the FERC, the utility estimates the total portion of its
transition costs from all its pipeline suppliers will be approximately $106.2
million. As of September 30, 1998, approximately $97.8 million of those costs
had been incurred and were being recovered from the utility's customers under
the purchased gas provisions of its rate schedules. Going forward, AGLC will
recover the majority of the remaining costs through its gas sales. A small
portion of the costs will be recovered from certificated marketers as
part of the assignment process under its unbundling plan.
The largest portion of the transition costs the utility must pay
consists of gas supply realignment costs that Southern Natural Gas
Company (Southern) and Tennessee Gas Pipeline Company (Tennessee) bill
the utility. The utility and other parties have entered restructuring
settlements with Southern and Tennessee that resolve all transition cost
issues for those pipelines.
Under the Southern settlement, the utility's share of Southern's transition
costs is approximately $88 million, of which the utility incurred $84.5
million as of September 30, 1998. Under the Tennessee settlement, the utility's
share of Tennessee's transition costs is approximately $14.7 million, of
which the utility incurred approximately $10 million as of September 30, 1998.
AGLC requested and was granted clarification and assignment waiver of certain
FERC policies concerning interstate pipeline capacity. The request was
necessary to ensure that it would be able to make certain pipeline
services it receives available to certificated marketers as part of its
unbundling plan.
Environmental Matters Before natural gas was available in the Southeast in
the early 1930s, AGLC manufactured gas from coal and other materials. Those
manufacturing operations were known as "manufactured gas plants," or "MGPs."
Because of recent environmental concerns, we are required to investigate
possible contamination at those plants and, if necessary, clean them up.
Through the years AGLC has been associated with twelve MGP sites in
Georgia and three in Florida. Based on investigations to date, we believe that
some cleanup will be likely at most of the sites. In Georgia, the state
Environmental Protection Division supervises the investigation and cleanup of
MGP sites. In Florida, the U.S. Environmental Protection Agency has that
responsibility.
For each of the MGP sites, we estimated our share of the likely costs of
investigation and cleanup. We used the following process to make the estimates:
First, we eliminated the sites where we believe no cleanup or further
investigation is likely to be necessary. Second, we estimated the likely future
cost of investigation and cleanup at each of the remaining sites. Third, for
some sites, we estimated our likely "share" of the costs. We developed our
estimate based on any agreements for cost sharing we have, the legal principles
for sharing costs, our evaluation of other entities' ability to pay, and other
similar factors.
Using that process, we believe our total future cost of investigating and
cleaning up our MGP sites is between $47 million and $81.3 million. Within that
range, we cannot identify a single number as the "best" estimate. Therefore,
we have recorded the lower value, or $47 million, as a liability as of September
30, 1998. As of September 30, 1997, the liability which we had recorded was
$37.3 million. During the year, the liability increased $25.7 million. After
making payments of $16.0 million, related to legal fees and technical support,
the net increase in the liability was $9.7 million. The increase in the
liability was based on revised estimates, which resulted in a corresponding
increase in the unrecovered environmental response cost asset.
We have two ways of recovering investigation and cleanup costs. First,
the GPSC has approved an "Environmental Response Cost Recovery Rider." It allows
us to recover our costs of investigation, testing, cleanup, and litigation.
Because of that rider, we have recorded an asset in the same amount as our
investigation and cleanup liability. The GPSC, however, is conducting hearings
about three aspects of the rider. Depending on how the GPSC rules, our
recoveries under the rider could be affected. If the GPSC were to limit
significantly our recovery under the rider, the results could be material.
The second way we could recover costs is by exercising the legal rights
we believe we have to recover a share of our costs from other corporations and
from insurance companies. We have been actively pursuing those recoveries. In
fiscal 1998, we recovered $1.9 million. As required by the rider, we retained
$.9 million of that amount, and we credited the balance to our customers.
Accounting Developments In June 1997 the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" (SFAS 130) and Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS 131).
- - SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components (revenues, expenses, gains,
and losses) in a full set of general-purpose financial statements.
- - SFAS 131 establishes standards for the way public companies report
information about operating segments in annual financial statements.
It also requires those companies to report selected information about
operating segments in interim financial reports issued to shareholders.
We will adopt SFAS 130 and SFAS 131 in fiscal 1999.
In June 1998 the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133). SFAS 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. We will adopt
SFAS 133 in fiscal 2000.
In March 1998 the American Institute of Certified Public Accountants
issued Statement of Position 98-1 (SOP 98-1), "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." SOP 98-1 provides
guidance on accounting for the costs of computer software developed or
obtained for internal use. We will adopt SOP 98-1 in fiscal 2000.
We do not expect those new pronouncements to have a material effect on
our consolidated financial statements.
Competition
In this section we discuss the way competition affects our utility and
nonutility businesses.
Utility The utility competes to supply natural gas to large commercial and
industrial customers. Those customers can switch to alternative fuels,
including propane, fuel and waste oils, electricity and, in some cases,
combustible wood by-products. We also compete to supply gas to large
commercial and industrial customers who seek to bypass our distribution system.
Before the GPSCs rate case order of June 30, 1998, AGLC was providing
service under 56 negotiated contracts with customers who had the ability to
bypass our distribution system and receive service directly from interstate
pipelines. In addition, AGLC was providing service under seven special long-term
contracts that involve competing with alternative fuels where physical bypass is
not the relevant competition. Under the regulatory structure then in place, AGLC
was allowed to recover from other customers most of the discounts associated
with such contracts.
The change in the regulatory structure associated with unbundling and
restatement of rates removed the need to recover discounts going
forward. Nevertheless, the GPSC specifically authorized AGLC to continue
to enter into future contracts if the initial term of a contract does
not exceed three years and if all such future contracts include
market-out provisions. The GPSC issued a written order setting forth its
decision on May 21, 1998.
Subsequent to July 1, 1998, AGLC can price distribution services to large
commercial and industrial customers in one of three ways:
- - GPSC-approved rates in AGLCs tariff;
- - discounted rates - if an existing rate is not priced competitively with
a customers competitive alternative fuel; or
- - special contracts approved by the GPSC.
Additionally, interruptible customers have the option of purchasing delivery
service directly from marketers, who are authorized to use capacity on AGLCs
distribution system that is allocated to the marketers for residential and small
business firm customers, whenever such capacity is not being used for firm
customers.
On November 27, 1996, the TRA approved an experimental rule allowing
Chattanooga to negotiate contracts with large commercial and industrial
customers who have long-term competitive options, including bypass. The
experimental rule requires that before a large Tennessee customer is
allowed a discounted rate, both the customer and Chattanooga must
request that the TRA approve the rates requested in the contract.
On October 7, 1997, the TRA denied requests from Chattanooga and four large
customers for discounted rates after deciding that customer bypass was
not imminent. On January 14, 1998, however, the Federal Energy
Regulation Commission (FERC) issued an order authorizing Southern
Natural Gas Company to bypass Chattanooga to serve a large industrial
customer. Chattanooga later reached a settlement with that customer to
avoid bypass.
Nonutility We engage in several competitive, energy-related businesses,
including gas supply services, wholesale and retail propane sales, wholesale
gas and power marketing, retail energy marketing, customer care
services, and the sale of energy-related products and services for residential,
commercial, and industrial customers throughout the Southeast. (For a brief
description of each nonutility business refer to the section, Nature of Our
Business, at the beginning of this Managements Discussion and Analysis of
Results of Operations and Financial Condition.)
Unlike the utility, our nonutility businesses are not regulated. Our
nonutility businesses typically face competition from other companies in the
same or similar businesses. Currently, our nonutility businesses do not have a
material effect on our consolidated financial statements.
Year 2000 Readiness Disclosure
The widespread use by governments and businesses, including us, of computer
software that relies on two digits, rather than four digits, to define the
applicable year may cause computers, computer-controlled systems, and equipment
with embedded software to malfunction or incorrectly process data as we approach
and enter the year 2000.
Our Year 2000 Readiness Initiative In view of the potential adverse impact of
the "Year 2000" issue on our business, operations, and financial condition, we
have established a cross-functional team to coordinate, and to report to
management on a regular basis about, our assessment, remediation planning, and
plan implementation processes directed to Year 2000. We also have engaged
independent consultants to assist us in the assessment, remediation planning,
and implementation phases of our Year 2000 initiative. Our Year 2000 initiative
is proceeding on schedule.
The mission of our Year 2000 initiative is to define and provide a
continuing process for assessment, remediation planning, and plan implementation
to achieve a level of readiness that will meet the challenges presented to us by
the Year 2000 in a timely manner. Achieving Year 2000 readiness does not mean
correcting every Year 2000 limitation. Achieving Year 2000 readiness does mean
that critical systems, critical electronic assets, and relationships with key
business partners have been evaluated and are expected to be suitable for
continued use into and beyond the Year 2000, and that contingency plans are in
place.
Our Year 2000 readiness initiative involves a three-phase process. The
initiative is a continuing process with all phases of the initiative progressing
concurrently with respect to both IT and non-IT assets, as defined below, and
with respect to key business relationships. The three phases of our Year 2000
initiative are as follows:
1. Assessment -Assessment involves identifying and inventorying business assets
and processes. It also involves determining the Year 2000 readiness status
of our assets and of key business partners. Key business partners are
those customers and suppliers who we believe may be material to our business,
results of operations, or financial condition. In appropriate
circumstances, pre-remediation testing is conducted as a part of the
assessment phase. The assessment phase of our Year 2000 initiative includes
assessment for Year 2000 readiness of the following:
- - information technology (IT) assets - Computer systems and software maintained
by our Information Systems (IS) Department;
- - noninformation technology (non-IT) assets - including microprocessors embedded
in equipment, and information technology purchased and maintained by
business units other than our IS Department; and
- - and key business partners (customers and suppliers).
2. Preparation of Remediation Plans - The purpose of this phase is to develop
plans which, when implemented, will enable assets and business relationships
to be Year 2000 ready. This phase involves implementation planning and
prioritizing the implementation of remediation plans.
3. Implementation - This step involves the implementation of remediation plans,
including post-remediation testing and contingency planning.
State of Readiness We continue to assess the impact of the Year 2000 issue
throughout our business and operations, including our customer and supplier
base. The scope of our Year 2000 initiative includes AGL Resources and its
subsidiaries. A number of our joint ventures, including Sonat Power Services,
L.P., Sonat Marketing, L.P., and SouthStar Energy Services LLC, are not within
the scope of our Year 2000 initiative. We plan to address the Year 2000
readiness of those joint ventures using the same processes we use to assess the
Year 2000 readiness of key business partners. (See "Key Business Partners"
below.) The following is a description of the progress of our Year 2000
initiative in all business units that are within the scope of our Year 2000
initiative, with the exception of Utilipro, Inc., a recently acquired
subsidiary. The Year 2000 initiative is about to commence with respect to
Utilipro, Inc., and we expect Utilipro's business and operations to achieve
Year 2000 readiness.
IT Assets Assessment of IT assets is complete. Remediation planning and
implementation are underway. As part of our IT assessment process, we completed
the assessment of our 79 mainframe and personal computer systems. We deem 13 of
those 79 systems to be critical systems. The results of our Year 2000 initiative
with respect to IT assets indicate that, to date:
- - 29 systems now are ready for Year 2000, including 12 of the 13 critical
systems;
- - one critical system is being evaluated to determine whether replacement
or remediation is the most efficient course of action;
- - 10 systems are in testing to verify Year 2000 readiness;
- - two systems are in remediation for purposes of correcting
noncompliant Year 2000 code;
- - three systems have been eliminated; and
- - 34 systems are scheduled for either testing, replacement, remediation,
or elimination in the future.
We expect our one critical IT asset that is not yet
Year 2000 ready to be Year 2000 ready by March 31, 1999. Remediation completion
schedules for achieving Year 2000 readiness of noncritical IT assets are
expected to extend through September 1999.
Non-IT Assets Assessment of non-IT assets is complete. Our non-IT asset
assessment process involved the following:
- - identifying business processes;
- - identifying non-IT assets and defining the business process or processes
to which such assets relate;
- - identifying the mission criticality of each non-IT asset and business
process; and
- - documenting in a tracking database the existence, and the
mission-criticality, of each non-IT asset and business process.
We expect to complete remediation planning for critical non-IT assets by
December 15, 1998. The expected completion date for remediation plan
implementation for critical non-IT assets will depend on the results of the
remediation planning phase for non-IT assets, but is not expected to extend
beyond June 30, 1999.
Key Business Partners We are contacting key business partners, including
suppliers and customers, to evaluate their Year 2000 readiness plans and status
of readiness. We have contacted over 1,400 suppliers by letter. That group of
suppliers includes suppliers whom we consider key business partners as well as
other selected suppliers. However, to date, we have not received responses from
the majority of suppliers we contacted. We have begun following up by telephone
with those key suppliers from whom we have not yet received responses. We also
initiated contact with more than 2,500 commercial and industrial customers by
personal or telephone interview or by fax survey. To date, we have not received
responses from most of those customers. If key customers do not respond by
January 1, 1999, we plan to begin to follow up by fax or telephone with those
customers.
We are assessing the state of readiness of key business partners who
have responded to our request for information and will continue to do so as we
receive additional responses. As a general matter, we, like other businesses,
are vulnerable to key business partners' inability to achieve Year 2000
readiness. We cannot predict the outcome of our business partners' readiness
efforts. However, we plan to develop contingency plans to mitigate risks
associated with the Year 2000 readiness of certain business partners, including
key business partners. At this stage of our review of key business partners, we
do not have sufficient information to determine whether the Year 2000 readiness
of key business partners is likely to have a material impact on our business,
results of operations, or financial condition.
Costs to Address Year 2000 Issues Management intends to devote the resources
necessary to achieve a level of readiness that will meet our Year 2000
challenges in a timely manner. Through September 30, 1998, our cumulative
expenses in connection with our Year 2000 assessment, remediation planning, and
plan implementation processes were approximately $3 million. Through September
30, 1998, we had spent an additional $7.1 million for the replacement of our
general ledger and human resources information systems. Our primary reason for
replacing those systems was to achieve increased efficiency and functionality.
An added benefit of replacing those systems was the avoidance of the costs of
remediating Year 2000 problems associated with our previous general ledger and
human resources information systems. We will capitalize the costs of our new
general ledger and human resources information systems, in accordance with our
accounting policies and with generally accepted accounting principles.
We expect to spend approximately $6 million in fiscal 1999 in connection
with our Year 2000 initiative. That estimate includes costs associated with the
use of outside consultants as well as hardware and software costs. It also
includes direct costs associated with employees of our IS Department who work on
the Year 2000 initiative. However, the fiscal 1999 estimate is subject to
change, based on the results of our ongoing Year 2000 processes.
On June 30, 1998, the GPSC issued a rate case order in response to a
filing by AGLC. The GPSC provided for the deferral and amortization of some Year
2000 costs over a five-year period, beginning July 1, 1998. The portion of those
costs that will be deferred in this way includes costs that are required to be
expensed under generally accepted accounting principles and that are
attributable to AGLC. Going forward, we estimate that approximately 90% of our
Year 2000 costs will be attributable to AGLC. At September 30, 1998, AGLC had
deferred total costs of $2.0 million less accumulated amortization of $.1
million.
At present, the cost estimates associated with achieving Year 2000
readiness are not expected to materially impact our consolidated financial
statements. We will account for costs related to achieving Year 2000 readiness
in accordance with our accounting policies, with regulatory treatment, and with
generally accepted accounting principles.
Risks of Year 2000 Issues We are in the process of identifying our most
reasonably likely worst case Year 2000 scenarios. As such, we are not yet able
to comment on whether the consequences of such scenarios could have a material
impact on our business, results of operations, or financial condition. The
process of defining our most reasonably likely worst case scenarios is part of
the contingency planning effort that is currently underway. Our process for
identifying our most reasonably likely worst case scenarios includes the
following:
- - identifying core business processes;
- - identifying key business partners (including suppliers and customers);
- - conducting Year 2000 business impact analysis; and
- - reviewing experts' views of factors likely to contribute to such a scenario.
The contingency planning process and the process of developing most reasonably
likely worst case scenarios will be ongoing processes, requiring continuing
development, modification, and refinement as we obtain additional information
regarding (a) our internal systems and equipment during the implementation phase
of our Year 2000 initiative, and (b) the status, and the impact on us, of the
Year 2000 readiness of others.
Business Continuity and Contingency Planning
We are developing Year 2000 contingency plans. Those plans, which are intended
to enable us to deliver an acceptable level of service despite Year 2000
failures, include performing certain processes manually, changing suppliers, and
reducing or suspending certain noncritical aspects of our operations. We expect
our contingency planning effort to focus on our potential internal risks as well
as potential risks associated with our suppliers and customers. Identifying our
most reasonably likely worst case scenarios as described above will define the
boundaries of our contingency planning effort. The contingency planning process
also includes, but is not limited to the following:
- - identifying the nature of Year 2000 risks to understand the business impact of
those risks;
- - identifying our minimal acceptable service levels;
- - identifying alternative providers of goods and services;
- - identifying necessary investments in additional back-up equipment such as
generators and communications equipment; and
- - developing manual methods of performing critical functions currently
performed by electronic systems and equipment.
From February through June 1999, we expect to be testing and refining our
contingency plans, with a planned testing completion date of June 30, 1999.
Although the expected completion date for our contingency planning effort is
June 30, 1999, during the last half of 1999 we will update and refine our
contingency plans, as needed, to reflect system and business changes as
they evolve.
Presently, management believes that its assessment, remediation
planning, plan implementation and contingency planning processes will be
effective to achieve Year 2000 readiness in a timely manner.
Forward-Looking Statements The preceding "Year 2000 Readiness Disclosure"
discussion contains various forward-looking statements that represent our
beliefs or expectations regarding future events. When used in the "Year 2000
Readiness Disclosure" discussion, the words "believes," "intends," "expects,"
"estimates," "plans," "goals," and similar expressions are intended to
identify forward-looking statements. Forward-looking statements include,
without limitation, our expectations as to when we will complete the assessment,
remediation planning, and implementation phases of our Year 2000 initiative
as well as our Year 2000 contingency planning; our estimated cost of
achieving Year 2000 readiness; and our belief that our internal systems and
equipment will be Year 2000 ready in a timely and appropriate manner. All
forward-looking statements involve a number of risks and uncertainties that
could cause the actual results to differ materially from the projected results.
Factors that may cause those differences include availability of information
technology resources; customer demand for our products and services;
continued availability of materials, services, and data from our suppliers;
the ability to identify and remediate all date-sensitive lines of computer
code and to replace embedded computer chips in affected systems and equipment;
the failure of others to timely achieve appropriate Year 2000 readiness;
and the actions or inaction of governmental agencies and others with respect to
Year 2000 problems.
<PAGE>
<TABLE>
Statements of Consolidated Income
For the years ended September 30,
---------------------------------------------------------------------
<CAPTION>
In millions 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $ 1,338.6 $ 1,287.6 $ 1,228.6
Cost of Sales 796.0 766.5 725.5
- -----------------------------------------------------------------------------------------------------------------------------
Operating Margin 542.6 521.1 503.1
- -----------------------------------------------------------------------------------------------------------------------------
Other Operating Expenses
Operation 238.1 226.2 221.8
Maintenance 38.4 30.8 29.5
Depreciation 71.1 66.6 63.3
Taxes other than income taxes 27.4 26.0 25.0
- -----------------------------------------------------------------------------------------------------------------------------
Total other operating expenses 375.0 349.6 339.6
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 167.6 171.5 163.5
- -----------------------------------------------------------------------------------------------------------------------------
Other Income 12.9 10.3 13.1
- -----------------------------------------------------------------------------------------------------------------------------
Interest Expense and Preferred Stock
Dividends
Interest on long-term debt 49.7 45.1 42.2
Other interest 4.7 7.1 6.9
Dividends on preferred stock of subsidiary 6.7 6.2 4.4
- -----------------------------------------------------------------------------------------------------------------------------
Total interest expense and preferred stock
dividends 61.1 58.4 53.5
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 119.4 123.4 123.1
- -----------------------------------------------------------------------------------------------------------------------------
Income Taxes 38.8 46.8 47.5
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 80.6 $ 76.6 $ 75.6
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share (Note 1)
Basic $ 1.41 $ 1.37 $ 1.37
Diluted $ 1.41 $ 1.36 $ 1.36
- -----------------------------------------------------------------------------------------------------------------------------
Weighted Average Number of Common
Shares Outstanding (Note 1)
Basic 57.0 56.1 55.3
Diluted 57.1 56.2 55.4
- -----------------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
Statements of Consolidated Cash Flows
For the years ended September 30,
------------------------------------------------------
<CAPTION>
In millions 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net income $ 80.6 $ 76.6 $ 75.6
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization 75.7 70.3 67.5
Provision for writedown of assets 13.9
Deferred income taxes 11.3 18.5 25.7
Other 2.0 0.3 0.4
- -------------------------------------------------------------------------------------------------------------------
183.5 165.7 169.2
Changes in assets and liabilities
Receivables (29.6) 5.8 (29.6)
Inventories 13.1 (10.3) (35.8)
Deferred purchased gas adjustment 17.4 (3.8) (11.0)
Accounts payable (13.8) (12.8) 1.4
Other-net 6.9 8.6 (12.3)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from operating
activities 177.5 153.2 81.9
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses .9 1.7 1.8
Short-term borrowings, net 47.0 (124.0) 101.0
Redemptions of preferred securities (44.5) (14.7)
Sale of preferred securities, net of expenses 74.3
Sale of long-term debt 105.5
Dividends paid on common stock (51.6) (50.7) (49.1)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from financing
activities (48.2) (7.9) 53.7
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures (94.8) (123.5) (132.0)
Nonutility property expenditures (22.5) (23.3) .3
Cash received from joint ventures 3.0 2.0 3.1
Investment in joint ventures (12.9) (2.8) (1.0)
Other (6.0) (1.6) (1.0)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from investing
activities (133.2) (149.2) (130.6)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents (3.9) (3.9) 5.0
Cash and cash equivalents
at beginning of year 4.8 8.7 3.7
- -------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents
at end of year $ .9 $ 4.8 $ 8.7
- -------------------------------------------------------------------------------------------------------------------
Cash Paid During the Year for
Interest $ 51.5 $ 48.8 $ 49.2
Income taxes $ 39.2 $ 28.2 $ 19.3
- -------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
Consolidated Balance Sheets
Assets September 30,
------------------------------------------
<CAPTION>
In millions 1998 1997
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Current Assets
Cash and cash equivalents $ .9 $ 4.8
Receivables
Gas (less allowance for uncollectible accounts
of $3.7 in 1998 and $2.4 in 1997) 81.6 56.1
Integrated Resource Plan loans (less allowance
for uncollectible accounts of $.1) 3.2
Other (less allowance for uncollectible accounts
of $.4 in 1998 and $.1 in 1997) 8.7 10.8
Unbilled revenues 31.4 22.0
Inventories
Natural gas stored underground 138.1 151.8
Liquefied natural gas 17.7 17.5
Materials and supplies 10.0 8.2
Other 4.6 6.0
Deferred purchased gas adjustment 8.5
Other 1.9 2.0
- ---------------------------------------------------------------------------------------------------------------
Total current assets 294.9 290.9
- ---------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment
Utility plant 2,133.5 2,069.1
Less accumulated depreciation 680.9 648.8
- ---------------------------------------------------------------------------------------------------------------
Utility plant - net 1,452.6 1,420.3
- ---------------------------------------------------------------------------------------------------------------
Nonutility property 106.0 106.7
Less accumulated depreciation 24.6 29.5
- ---------------------------------------------------------------------------------------------------------------
Nonutility property - net 81.4 77.2
- ---------------------------------------------------------------------------------------------------------------
Total property, plant and equipment - net 1,534.0 1,497.5
- ---------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental response costs 77.6 55.0
Investment in joint ventures 46.3 34.5
Unrecovered postretirement benefits costs 9.3 10.0
Prepaid pension costs 3.2
Unamortized cost to repurchase long-term debt 1.0 2.2
Other 18.7 32.2
- ---------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 152.9 137.1
- ---------------------------------------------------------------------------------------------------------------
Total Assets $ 1,981.8 $ 1,925.5
- ---------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
Liabilities and Capitalization September 30,
------------------------------------------
<CAPTION>
In millions 1998 1997
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Current Liabilities
Accounts payable-trade $ 48.4 $ 62.2
Short-term debt 76.5 29.5
Customer deposits 30.5 29.2
Interest 32.8 29.6
Wages and salaries 14.8 8.0
Other accrued liabilities 12.1 21.3
Deferred purchased gas adjustment 8.9
Redemption requirements on preferred stock 44.5
Other 26.0 19.1
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 250.0 243.4
- ---------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes 203.0 191.7
- ---------------------------------------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs 47.0 37.3
Accrued pension costs 2.2
Accrued postretirement benefits costs 33.4 34.3
- ---------------------------------------------------------------------------------------------------------------
Total long-term liabilities 82.6 71.6
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits
Unamortized investment tax credit 25.8 27.3
Regulatory tax liability 17.3 18.3
Other 14.7 16.8
- ---------------------------------------------------------------------------------------------------------------
Total deferred credits 57.8 62.4
- ---------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 10 and 12)
- ---------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 660.0 660.0
Subsidiary obligated mandatorily redeemable
preferred securities 74.3 74.3
Common stockholders' equity (See accompanying
statements of consolidated common stock equity) 654.1 622.1
- ---------------------------------------------------------------------------------------------------------------
Total capitalization 1,388.4 1,356.4
- ---------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 1,981.8 $ 1,925.5
- ---------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
Statements of Consolidated Common Stock Equity
For the years ended September 30,
-------------------------------------------------
<CAPTION>
In millions, except per share amounts 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common Stock
$5 par value; authorized 100.0 shares;
outstanding, 57.3 in 1998, 56.6 in 1997
and 55.7 in 1996
Beginning of year $ 283.1 $ 278.4 $ 137.3
Benefit, stock compensation, dividend
reinvestment and stock purchase plans 3.5 3.7 3.6
Stock dividend 137.5
Acquisition of nonregulated operation 1.0
- -------------------------------------------------------------------------------------------------------------------------
End of year 286.6 283.1 278.4
- -------------------------------------------------------------------------------------------------------------------------
Premium on Capital Stock
Beginning of year 183.6 170.6 297.7
Benefit, stock compensation, dividend
reinvestment and stock purchase plans 9.4 10.1 10.4
Stock dividend (137.5)
Acquisition of nonregulated operation 2.9
- -------------------------------------------------------------------------------------------------------------------------
End of year 193.0 183.6 170.6
- -------------------------------------------------------------------------------------------------------------------------
Earnings Reinvested
Beginning of year 155.4 139.3 122.3
Net income 80.6 76.6 75.6
Common stock dividends ($1.08 a share in 1998, $1.08
a share in 1997 and $1.06 a share in 1996) (61.5) (60.5) (58.6)
- -------------------------------------------------------------------------------------------------------------------------
End of year 174.5 155.4 139.3
- -------------------------------------------------------------------------------------------------------------------------
Total common stock equity $ 654.1 $ 622.1 $ 588.3
- -------------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
</TABLE>
<PAGE>
Note 1. Significant Accounting Policies
Nature of Our Business
Following shareholder and regulatory approval on March 6, 1996, AGL Resources
Inc. became the holding company for:
- - Atlanta Gas Light Company (AGLC) and its wholly owned subsidiary, Chattanooga
Gas Company (Chattanooga), which are local natural gas distribution
utilities; and
- - several nonutility subsidiaries.
We collectively refer to AGL Resources Inc. and its subsidiaries as "AGL
Resources."
AGLC conducts our primary business: the distribution of natural gas in
Georgia, including the Atlanta, Athens, Augusta, Brunswick, Macon, Rome,
Savannah, and Valdosta areas and in Tennessee, including the Chattanooga and
Cleveland areas. The Georgia Public Service Commission (GPSC) regulates AGLC,
and the Tennessee Regulatory Authority (TRA) regulates Chattanooga. AGLC
comprises substantially all of AGL Resources' assets, revenues, and earnings.
When we discuss the operations and activities of AGLC and Chattanooga, we refer
to them, collectively, as the "utility."
AGL Resources also operates the following wholly owned nonutility
subsidiaries:
- - AGL Energy Services, Inc., a gas supply services company that has one
wholly owned nonutility subsidiary, Georgia Gas Company;
- - AGL Interstate Pipeline Company which owns a 50% interest in Cumberland
Pipeline Company; Cumberland Pipeline Company is expected to provide
interstate pipeline services to customers in Georgia and Tennessee beginning
November 1, 2000;
- - AGL Investments, Inc., which was established to develop and manage
certain nonutility businesses including:
* AGL Gas Marketing, Inc., which owns a 35% interest in Sonat Marketing,
L.P.; Sonat Marketing, L.P. engages in wholesale and retail natural gas
trading;
* AGL Power Services, Inc., which owns a 35% interest in Sonat Power
Marketing, L.P.; Sonat Power Marketing, L.P. engages in wholesale power
trading;
* AGL Propane, Inc., which engages in the sale of propane and
related products and services;
* Trustees Investments, Inc., which owns Trustees Gardens, a residentia
and retail development located in Savannah, Georgia; and
* Utilipro, Inc., which engages in the sale of integrated customer care
solutions to energy marketers; and
- - AGL Peaking Services, Inc., which owns a 50% interest in Etowah LNG Company
LLC; Etowah LNG Company LLC is a joint venture with Southern Natural Gas
Company and was formed for the purpose of constructing, owning, and operating
a liquefied natural gas peaking facility.
In July 1998, AGL Resources formed a joint venture known as SouthStar Energy
Services LLC (SouthStar). SouthStar was established to sell natural gas,
propane, fuel oil, electricity, and related services to industrial, commercial,
and residential customers in Georgia and the Southeast. SouthStar is a joint
venture among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a
subsidiary of Dynegy, Inc., and Piedmont Energy Company, a subsidiary of
Piedmont Natural Gas Company. SouthStar filed for certification as a retail
marketer with the GPSC on July 15, 1998, and was approved on October 6, 1998.
SouthStar operates in Georgia under the name Georgia Natural Gas Services.
Regulation of the Utility Business
The GPSC and the TRA regulate our utility business with respect to rates,
maintenance of accounting records, and various other matters. Generally, we use
the same accounting policies and practices nonutility companies use for
financial reporting under generally accepted accounting principles. However,
sometimes the GPSC and the TRA order an accounting treatment different from
that used by nonregulated companies to determine the rates we charge our
customers. (See Note 4 in Notes to Consolidated Financial Statements.)
Consolidation Policy
We use two different accounting methods to report our investments in our
subsidiaries or other companies: consolidation and the equity method.
Consolidation We use consolidation when we own a majority of the voting stock
of the subsidiary or if we can otherwise exercise control over the entity. That
means we combine our subsidiaries' accounts with our accounts. We eliminate
intercompany balances and transactions when we consolidate the accounts. Our
consolidated financial statements include the accounts of the following
subsidiaries:
- - AGLC and its subsidiary, Chattanooga;
- - AGL Energy Services, Inc. and its subsidiary;
- - AGL Interstate Pipeline Company;
- - AGL Investments, Inc. and its subsidiaries; and
- - AGL Peaking Services, Inc.
The Equity Method We use the equity method to report corporate joint
ventures where we hold a 20% to 50% voting interest, unless we can
exercise control over the entity. Under the equity method, we report our
interest in the entity as an investment in our Consolidated Balance
Sheets, and our percentage share of the earnings from the entity in our
Statements of Consolidated Income.
We use the equity method to report our investments in the following:
- - Sonat Power Marketing, L.P.;
- - Sonat Marketing Company, L.P.;
- - Etowah LNG;
- - SouthStar Energy Services LLC; and
- - Cumberland Pipeline Company.
Utility Revenues
We record utility revenues in our Statements of Consolidated Income when we
provide service to customers. Those revenues include estimated amounts
for gas delivered, but not yet billed. Revenues from our utility
business are based on rates approved by the GPSC and the TRA.
On July 1, 1998, AGLC began billing customers under a new rate structure
that recovers nongas costs evenly throughout the year consistent with the way
the costs are incurred. (See Note 2 in Notes to Consolidated Financial
Statements.)
The GPSC authorized a weather normalization adjustment
rider (WNAR), which was in effect during fiscal 1996, fiscal 1997, and
the first nine months of fiscal 1998. In addition, the TRA has
authorized a WNAR. They are designed to offset the impact
of unusually cold or warm weather on customer billings and operating margin. On
June 30, 1998, the WNAR for AGLC was discontinued, since the rate design
mandated by the Georgia Natural Gas Competition and Deregulation Act (the Act)
eliminates the effect of weather-related volumetric variances on nongas cost
revenue collections. The WNAR for Chattanooga remains in effect.
Some industrial and commercial customers purchase gas directly from gas
producers and marketers. The GPSC and the TRA have approved programs in which
transportation charges are billed on those purchases.
Gas Costs
The utility incurs costs for the natural gas that it purchases and resells to
customers. The utility charged its customers for the natural gas they consumed
using purchased gas adjustment (PGA) mechanisms set by the GPSC and the TRA.
Under the PGA, the utility deferred (included as a current asset or liability in
the Consolidated Balance Sheets and excluded from the Statements of Consolidated
Income) the difference between the utility's actual cost of gas and what it
collected from customers in a given period. Then, the utility either billed or
refunded its customers the deferred amount. The GPSC's order acknowledges that
under the Act, AGLC's PGA will be deregulated when at least five nonaffiliated
marketers are authorized to serve an area of Georgia. The GPSC issued more than
five such authorizations on October 6, 1998. Consequently, AGLC will no longer
defer any over-recoveries or under-recoveries of gas costs, and will refund to
customers any over-recovery that existed when the PGA mechanism was deregulated
on October 6, 1998.
Risk Management
AGLCs Gas Supply Plan for fiscal 1998 included limited gas supply hedging
activities. AGLC was authorized to begin an expanded program to hedge up to
one-half its estimated monthly winter wellhead purchases and to establish a
price for those purchases at an amount other than the beginning-of-the-month
index price. Such a program creates an additional element of diversification and
price stability. The financial results of all hedging activities were passed
through to residential and small commercial customers under the PGA provisions
of AGLC's rate schedules. Accordingly, the hedging program did not affect our
earnings.
Consistent with fiscal 1998, AGLC's Gas Supply Plan for fiscal 1999 will
include limited gas supply hedging activities. In conjunction with deregulation,
the fiscal 1999 hedging results will not pass through to residential and small
commercial customers through a regulated PGA mechanism. Accordingly, in fiscal
1999, the hedging program may affect earnings.
Beginning in November 1998, AGLC began to make public the price at which
it sells gas. AGLC also began a fixed-price option program to minimize the risk
of loss incurred as a result of gas volume and price volatility after the price
has been published. Each month before publishing the sales price, AGLC will
determine whether to enter into a fixed-price option agreement for the
respective month. In the event AGLC enters into such an agreement,it will pay a
monthly option premium based on the potential need for incremental wellhead
purchases. Such premium will fix AGLC's maximum gas purchase cost for
incremental wellhead purchases at the agreements fixed price. Accordingly, in
the event actual gas prices on any day during the month exceed the agreement's
fixed price for the month, the option reimburses AGLC the difference in excess
of the fixed price. If the actual gas price on any day during the month is less
than the fixed price, AGLC pays the lesser price. The anticipated results of
fixed-price option agreements will be to limit the effect of gas price
volatility on earnings.
Income Taxes
We must report some of our assets and liabilities differently for financial
accounting purposes than we do for income tax purposes. The tax effects
of the differences in those items are reported as deferred income tax assets
or liabilities in our Consolidated Balance Sheets. Investment tax credits
associated with our utility have been deferred and are being amortized as
credits to income in accordance with regulatory treatment over the estimated
lives of the related properties. We reduce income tax expense in our
Statements of Consolidated Income for the investment tax credits and other
tax credits associated with our nonutility subsidiaries.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
(SFAS 121) requires us to review long-lived assets and certain intangibles
for impairment when events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Any impairment losses are
reported in the period in which the recognition criteria are first applied
based on the fair value of the asset. In accordance with SFAS 121, AGL
Resources has evaluated its long-lived assets for financial impairment. As
a result of this review, AGL Resources recorded charges totaling $13.9
million to other operating expenses during the fourth quarter of 1998. Those
charges included:
- - a $10.8 million expense related to the impairment of certain assets no
longer useful primarily due to changes in our information systems strategy;
and
- - a $3.1 million expense due to a decision by management not to seek recovery
for certain deferred expenses.
Utility Plant and Depreciation
Utility Plant Utility plant is the term we use to describe our utility
business property and equipment that is in use, being held for future use,
and under construction. We report our utility plant at its original cost,
which includes:
- - material and labor;
- - contractor costs;
- - construction overhead costs (where applicable); and
- - an allowance for funds used during construction (described later in this
note).
We charge retired or otherwise-disposed-of utility plant to accumulated
depreciation.
Depreciation Expense We compute depreciation by applying composite,
straight-line rates (approved by the GPSC and TRA) to the average investment
in classes of depreciable utility property. The composite straight-line
depreciation rate was approximately 3.2% for depreciable utility and nonutility
property excluding transportation equipment during fiscal years 1998, 1997,
and 1996. Transportation equipment is depreciated on a straight-line basis over
a period of five to ten years.
Allowance for Funds Used During Construction (AFUDC) We finance construction
projects with borrowed funds and equity funds. The GPSC allows us to record
the cost of those funds as part of the cost of construction projects
on our Consolidated Balance Sheets. We do that through the AFUDC in our
Statements of Consolidated Income. We calculate the AFUDC using a rate
authorized by the GPSC. Beginning July 1, 1998, the GPSC authorized a rate
of 9.11% for AFUDC. For the nine months ended June 30, 1998, and for
fiscal 1997 and fiscal 1996, the authorized AFUDC rate was 9.32%.
Statement of Cash Flows
For reporting our cash flows, we define cash equivalents as highly liquid
investments that mature in three months or less.
Noncash investing and financing transactions include the following:
- - the issuance of common stock for ResourcesDirect, a stock purchase and
dividend reinvestment plan; the Retirement Savings Plus Plan; the Long-Term
Stock Incentive Plan; the Nonqualified Savings Plan; and the Non-Employee
Directors Equity Compensation Plan of $12.0 million in fiscal 1998, $12.5
million in fiscal 1997, and $12.3 million in fiscal 1996; and
- - the issuance of 200,000 shares of AGL Resources common stock in the amount
of $3.9 million for the acquisition of propane operations in June 1997.
During fiscal 1998 AGL Resources recorded noncash charges of $13.9 million
related to the impairment of certain long-lived assets.
Earnings per Common Share
Earnings per common share for all periods have been computed under the
provisions of a new accounting standard, Statement of Financial Accounting
Standards No.128, "Earnings Per Share," which was adopted October 1, 1997, and
calls for the restatement of all periods presented on a comparable basis. The
following weighted average common share and common share equivalent amounts
were used for the calculation of basic and diluted earnings per common
share. The common share equivalents relate to stock options under stock
compensation plans.
______________________________________________________________
Weighted Average Weighted Average Number
Number of Common Shares and
of Common Shares Common Share Equivalents
Fiscal Year (Basic Shares) (Diluted Shares)
- -----------------------------------------------------------------------------
1998 57.0 million 57.1 million
- -----------------------------------------------------------------------------
1997 56.1 million 56.2 million
- -----------------------------------------------------------------------------
1996 55.3 million 55.4 million
_____________________________________________________________________________
Use of Accounting Estimates
We make estimates and assumptions when preparing financial statements under
generally accepted accounting principles. Those estimates and assumptions
affect various matters:
- - reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements;
- - disclosure of contingent assets and liabilities at the dates of the
financial statements; and
- - reported amounts of revenues and expenses in our Statements of
Consolidated Income during the reporting periods.
Those estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. Consequently, actual amounts could differ from our estimates.
Other
Gas inventories are stated at cost principally on a first-in, first-out method.
Materials and supplies inventories are stated at lower of average cost or
market.
Consistent with the rate treatment prescribed by the GPSC and the TRA, vacation
pay and short-term disability benefits for the utility are expensed as those
benefits are paid.
We have reclassified certain prior year amounts for comparative purposes. Those
reclassifications did not affect consolidated net income for the years
presented.
Recently Issued Accounting Pronouncements
In June 1997 the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 130, "Reporting Comprehensive Income"
(SFAS 130) and Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information"
(SFAS 131).
- - SFAS 130 establishes standards for reporting and displaying comprehensive
income and its components (revenues, expenses, gains, and losses) in a full
set of general-purpose financial statements.
- - SFAS 131 establishes standards for the way public companies report
information about operating segments in annual financial statements. It also
requires those companies to report selected information about operating
segments in interim financial reports issued to shareholders.
We will adopt SFAS 130 and SFAS 131 in fiscal 1999.
In June 1998 the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133). SFAS 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. We will adopt
SFAS 133 in fiscal 2000.
In March 1998 the American Institute of Certified Public Accountants
issued Statement of Position 98-1 (SOP 98-1), "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." SOP 98-1 provides
guidance on accounting for the costs of computer software developed or
obtained for internal use. We will adopt SOP 98-1 in fiscal 2000.
We do not expect those new pronouncements to have a material effect on
our consolidated financial statements.
Note 2. Impact of Deregulation
Under Georgias Natural Gas Competition and Deregulation Act (the Act), AGLC
elected to unbundle, or separate, the various components of its services to its
customers. As a result, numerous changes have occurred with respect to the
services being offered by AGLC and with respect to the manner in which AGLC
prices and accounts for those services. Consequently, AGLC's future
expenses and revenues will not follow the same pattern as they have
historically.
Pursuant to the Act, regulated rates ended on October 6, 1998, for natural gas
commodity sales to AGLC customers. Consequently, AGLC will no longer defer
any over-recoveries or under-recoveries of gas costs and will refund to
customers the over-recovery that existed when the purchased gas adjustment
provisions were deregulated.
Going forward, AGLC intends to design its prices for deregulated gas sales
in a manner that, at a minimum, will allow it to recover its annual gas costs.
Accordingly, substantial changes to future quarterly statements of income
are expected from this new regulatory approach. AGLC intends to recover all
its gas costs through the prices it will establish such that on an annual
basis it recovers, at a minimum, the actual costs of acquiring gas supplies
for sales services.
As part of the GPSC's rate case ruling, AGLC began billing customers on
Therefore, total distribution rates were typically lower in the summer when
customers used less gas, and higher in the winter when customers used more gas.
Going forward, AGLC will collect such rates evenly throughout the year
regardless of volumetric summer and winter differences in gas usage.
In addition, there are other AGLC revenues that reflect costs associated
with services deemed ancillary to distribution service that will change as
customers select a marketer for sales service. For example, as customers choose
a marketer, the associated revenues to AGLC for billing, billing inquiries,
payment collection, payment processing, and possibly meter reading will
decrease if those services are provided by the marketer. The regulatory
provisions provide for a reduction in the revenues associated with those
services as AGLC has the opportunity to avoid such future costs.
Consequently, those provisions will reduce some of the regulated revenue and
associated expenses for AGLC.
Note 3. Income Taxes
Income Tax Expense
We have two categories of income taxes in our Statements of Consolidated Income:
current and deferred. Our current income tax expense consists of regular tax
less applicable tax credits. Our deferred income tax expense generally is
equal to the changes in the deferred income tax liability during the year.
Investment Tax Credits
We have deferred investment tax credits associated with our utility as a
regulatory liability in our Consolidated Balance Sheets. (See Note 4 in Notes
to Consolidated Financial Statements.) Those investment tax credits are
being amortized as credits to income in accordance with regulatory treatment
over the estimated life of the related properties. We reduce income tax
expense in our Statements of Consolidated Income for the investment tax credits
and other tax credits associated with our nonutility subsidiaries.
Deferred Income Tax Assets and Liabilities
We must report some of our assets and liabilities differently for financial
accounting purposes than we do for income tax purposes. The tax effects of the
differences in those items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect. Because of
the regulated nature of the utility's business, a regulatory tax liability has
been recorded in accordance with Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes." The regulatory tax liability is being
amortized over approximately 30 years. (See Note 4 in Notes to Consolidated
Financial Statements.)
Components of income tax expense shown in the Statements of Consolidated Income
are as follows:
___________________________________
Millions of dollars 1998 1997 1996
- ----------------------------------------------------------------------
Included in expenses:
Current income taxes
Federal $25.3 $24.2 $20.3
State 3.6 5.5 3.0
Deferred income taxes
Federal 9.7 16.7 21.6
State 1.6 1.8 4.1
Amortization of investment
tax credits (1.4) (1.4) (1.5)
- ----------------------------------------------------------------------
Total $38.8 $46.8 $47.5
______________________________________________________________________
Reconciliation between the statutory federal income tax rate and the effective
rate is as follows:
_________________________
Millions of dollars 1998
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $41.8 35.0
State income tax, net of federal
income tax benefit 3.5 2.9
Amortization of investment tax credits (1.4) (1.2)
Adjustment of prior year's income taxes (2.3) (1.9)
Other - net (2.8) (2.3)
- ----------------------------------------------------------------------
Total income tax expense $38.8 32.5
______________________________________________________________________
_________________________
Millions of dollars 1997
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $43.2 35.0
State income tax, net of federal
income tax benefit 4.5 3.7
Amortization of investment tax credits (1.4) (1.1)
Other - net .5 .4
- ----------------------------------------------------------------------
Total income tax expense $46.8 38.0
______________________________________________________________________
_________________________
Millions of dollars 1996
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $43.1 35.0
State income tax, net of federal
income tax benefit 4.3 3.5
Amortization of investment tax credits (1.5) (1.2)
Other - net 1.6 1.3
- ----------------------------------------------------------------------
Total income tax expense $47.5 38.6
______________________________________________________________________
Components that give rise to the net deferred income tax liability as of
September 30 are as follows:
____________________
Millions of dollars 1998 1997
- ----------------------------------------------------------------------
Deferred tax liabilities:
Property - accelerated depreciation and
other property-related items $221.9 $206.8
Other 19.1 18.5
- ----------------------------------------------------------------------
Total deferred tax liabilities 241.0 225.3
- ----------------------------------------------------------------------
Deferred tax assets:
Deferred investment tax credits $ 10.0 $ 10.6
Other 28.0 23.0
- ----------------------------------------------------------------------
Total deferred tax assets 38.0 33.6
- ----------------------------------------------------------------------
Net deferred tax liability $203.0 $191.7
______________________________________________________________________
Note 4. Regulatory Assets and Liabilities
As discussed in Note 1, the GPSC and the TRA regulate our utility business. We
generally use the same accounting policies and practices nonregulated
companies use for financial reporting under generally accepted accounting
principles. However, sometimes the GPSC and the TRA order an accounting
treatment different from that used by nonregulated companies to determine
the rates we charge our customers. When that happens, we must defer certain
utility expenses and income in our Consolidated Balance Sheets as
regulatory assets and liabilities. We then record them in our Statements
of Consolidated Income (using amortization) when we include them in the
rates we charge our customers.
We have recorded regulatory assets and liabilities in our Consolidated
Balance Sheets in accordance with Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71).
In July 1997, the Emerging Issues Task Force (EITF) concluded that once
legislation is passed to deregulate a segment of a utility and that legislation
includes sufficient detail for the enterprise to determine how the transition
plan will affect that segment, SFAS 71 should be discontinued for that segment
of the utility. The EITF consensus permits assets and liabilities of a
deregulated segment to be retained if they are recoverable through a segment
that remains regulated.
Georgia has enacted legislation, the Act, which allows deregulation of
natural gas sales and the separation of some ancillary services of local
natural gas distribution companies. However, the rates local gas distribution
companies charge to transport natural gas through their intrastate pipe
system will continue to be regulated by the GPSC. Therefore, we have
concluded that the continued application of SFAS 71 remains appropriate. The
remaining regulatory liability associated with the deregulated gas function
will be refunded.
We summarize our regulatory assets and liabilities in the following
table (in millions):
_________________________
At September 30, 1998 1997
- ----------------------------------------------------------------------
Assets:
Unrecovered environmental response costs $77.6 $55.0
Unrecovered postretirement benefits costs 9.3 10.0
Deferred purchased gas adjustment 8.5
Other 7.9 4.2
- ---------------------------------------------------------------------
Total $94.8 $77.7
- ---------------------------------------------------------------------
Liabilities:
Unamortized investment tax credit $25.8 $27.3
Deferred purchased gas adjustment 8.9
Regulatory tax liability 17.3 18.3
Environmental response cost recoveries
from third parties - customer portion 9.5 10.1
Environmental response cost recoveries
from third parties - deferred company
portion 4.8 6.1
Other 2.2 3.7
- ----------------------------------------------------------------------
Total $68.5 $65.5
______________________________________________________________________
Note 5. Employee Benefit Plans and Stock-Based Compensation Plans
Substantially all AGL Resources employees are eligible to participate in the
company's employee benefit plans.
Pension Benefits
AGL Resources sponsors a defined benefit retirement plan for its employees.
A defined benefit plan specifies the amount of benefits an eligible plan
participant eventually will receive using information about the participant.
We generally calculate the benefits under that plan based on age, years of
service, and pay. Our employees do not contribute to that plan.
Sometimes we amend the plan retroactively. Retroactive plan amendments require
us to recalculate benefits related to participants' past service. We amortize
the change in the benefit costs from those plan amendments on a straight-line
basis over the average remaining service period of active employees. We fund
the plan by contributing annually the amount required by applicable regulations
and recommended by our actuary. We calculate the amount of funding using an
actuarial method called the projected unit credit cost method. The plan's assets
consist primarily of marketable securities, corporate obligations, U.S.
government obligations, insurance contracts, mutual funds, and cash
equivalents.
AGL Resources has an excess benefit plan that is unfunded and provides
supplemental benefits to some officers after retirement. In September 1994
we established a voluntary early retirement plan for some AGL Resources
officers that is unfunded and provides supplemental pension benefits to
participants who elected early retirement. The annual expense and accumulated
benefits of such plans are not significant.
We show the components of total net pension cost in the following table:
______________________________________
Millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------
Service cost $ 4.6 $ 4.0 $ 4.0
Interest cost 16.6 16.2 15.8
Actual return on assets (32.0) (30.6) (19.3)
Net amortization and deferral 16.2 16.9 6.3
- ----------------------------------------------------------------------------
Net periodic pension cost $ 5.4 $ 6.5 $ 6.8
- ----------------------------------------------------------------------------
Actuarial assumptions used include:
Discount rate 7.5% 7.5% 7.8%
Rate of increase in compensation
levels 4.5% 4.5% 4.5%
Expected long-term rate of return
on assets 8.3% 8.3% 8.3%
____________________________________________________________________________
We show the funded status of the plan in the following table:
____________________
Millions of dollars 1998 1997
- ---------------------------------------------------------------------------
Actuarial present value of benefit obligations
Vested benefit obligation $ 202.1 $ 187.2
- ---------------------------------------------------------------------------
Accumulated benefit obligation $ 206.2 $ 190.5
- ---------------------------------------------------------------------------
Projected benefit obligation $(242.8) $(223.8)
Plan assets at fair value 229.5 212.1
- ---------------------------------------------------------------------------
Plan assets less than projected benefit
obligation (13.3) (11.7)
Unrecognized net loss 11.0 15.1
Remaining unrecognized net assets at date
of initial adoption (3.0) (3.7)
Unrecognized prior service cost 3.1 3.5
- ---------------------------------------------------------------------------
Prepaid (accrued) pension costs $ (2.2) $ 3.2
___________________________________________________________________________
Employee Savings Plan Benefits
AGL Resources also sponsors the Retirement Savings Plus Plan, a defined
contribution benefit plan. In a defined contribution benefit plan, the benefits
a participant ultimately receives come from regular contributions to a
participant account. Under the Retirement Savings Plus Plan, we made matching
contributions to participant accounts in the following amounts:
- - $3.5 million in fiscal 1998;
- - $3.3 million in fiscal 1997; and
- - $3.2 million in fiscal 1996.
AGL Resources' Nonqualified Savings Plan, an unfunded, nonqualified plan
similar to the defined contribution savings plan described above, was
established on July 1, 1995. The Nonqualified Savings Plan provides an
opportunity for eligible employees to contribute for retirement savings. Our
contributions to the Nonqualified Savings Plan during fiscal years 1998, 1997,
and 1996 were not significant.
Employee Stock Ownership Benefits
AGL Resources' Leveraged Employee Stock Ownership Plan (LESOP) provides eligible
employees with another source of retirement income, while enabling them to be
AGL Resources shareholders.
In January 1988 we purchased 2 million shares of common stock for $11.75 per
share with the proceeds of a loan secured by the common stock. We did not
guarantee the repayment of the loan. The loan was repaid from regular cash
dividends on our common stock paid to the LESOP and from contributions to the
LESOP, as approved by our Board of Directors. Repayment of the loan was
completed December 31, 1997. Contributions to the LESOP were as follows:
- - $.2 million for fiscal 1998;
- - $.9 million for fiscal 1997; and
- - $.7 million for fiscal 1996.
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans,
which cover nearly all employees if they reach retirement age while working for
AGL Resources. We generally calculate the benefits under those plans based on
age and years of service.
Some retirees contribute a portion of health care plan costs. Retirees do not
contribute toward the cost of the life insurance plan.
Effective October 1, 1993, we adopted Statement of Financial Accounting
Standards No. 106, "Employer's Accounting for Postretirement Benefits Other Than
Pensions," which requires accrual of postretirement benefits other than pensions
during the years an employee provides service. In 1993 the GPSC approved a
five-year phase-in that defers a portion of other postretirement benefits
expense for future recovery. A regulatory asset has been recorded for that
amount. In 1993 the TRA approved the recovery of other postretirement benefits
expense that is funded through an external trust.
We show the components of net periodic postretirement benefits costs in the
following table:
___________________________________
Millions of dollars 1998 1997 1996
- ---------------------------------------------------------------------------
Service cost $ .9 $ .8 $ .8
Interest cost 7.6 8.0 8.8
Actual return on assets (1.5) (1.0) (.6)
Amortization of transition obligation 3.6 3.8 4.2
- ---------------------------------------------------------------------------
Net postretirement benefits costs $ 10.6 $ 11.6 $ 13.2
___________________________________________________________________________
Net periodic postretirement benefits costs were recovered from utility
customers as follows:
- - $11.3 million in fiscal 1998;
- - $11.3 million in fiscal 1997; and
- - $10.7 million in fiscal 1996.
The difference between our total net postretirement benefits costs and the
associated costs recovered from our utility customers of $.3 million in 1997
and $2.5 million in fiscal 1996 was deferred for future recovery through
amortization and recognized as regulatory assets in the financial statements
consistent with regulatory decisions. The $.7 million difference in fiscal
1998 represents the amortization of the regulatory asset.
The following schedule sets forth the plan's funded status as of September 30,
1998 and 1997:
___________________________
Millions of dollars 1998 1997
- ------------------------------------------------------------------------
Retirees $ 81.5 $ 82.2
Fully eligible active plan participants 7.1 6.4
Other active plan participants 16.2 14.8
- ------------------------------------------------------------------------
Total accumulated postretirement benefit
obligation 104.8 103.4
Plan assets at fair value 23.6 17.9
- ------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan assets 81.2 85.5
Unrecognized transition obligation (61.3) (65.5)
Unrecognized gain 13.5 14.3
- ------------------------------------------------------------------------
Accrued postretirement benefits costs $ 33.4 $ 34.3
________________________________________________________________________
Assumptions For purposes of measuring the accumulated postretirement benefit
obligation, the assumed health care inflation rate for pre-Medicare eligibility
is as follows:
- - 10.0% in 1998, decreasing .5% per year to 6.0% in the year 2006, decreasing
.25% to 5.75% in 2007, and decreasing .5% to 5.25% in 2008.
The assumed health care inflation rate for post-Medicare eligibility is as
follows:
- - 8.5% in 1998, decreasing .5% per year to 5.5% in the year 2004, decreasing
.25% to 5.25% in 2005, and decreasing .25% to 5.0% in 2006.
Increasing the assumed health care inflation rate by 1% would increase the
accumulated postretirement benefit obligation by approximately $4.2 million as
of September 30, 1998, and increase the accrued postretirement benefits cost by
approximately $.3 million for fiscal 1998.
The assumed discount rate used in determining the postretirement benefit
obligation was as follows:
- - 7.0% in 1998;
- - 7.5% in 1997; and
- - 7.75% in 1996.
Stock-Based Compensation Plans
AGL Resources' Long-Term Stock Incentive Plan (LTSIP) provides for grants of
restricted stock awards, incentive and nonqualified stock options, and stock
appreciation rights to key employees. The LTSIP currently authorizes issuance of
up to 3.2 million shares of our common stock. In addition, we maintain AGL
Resources' Non-Employee Directors Equity Compensation Plan (Directors Plan) in
which all non-employee directors participate. The Directors Plan currently
authorizes the issuance of up to 200,000 shares of common stock. Key employees
and non-employee directors realize value from option grants only to the extent
that the fair market value of the common stock of AGL Resources on the date of
exercise of the option exceeds the fair market value of the common stock on the
date of grant.
LTSIP Stock Awards
Stock awards generally are subject to some vesting restrictions. We recognize
compensation expense for those stock awards over the related vesting periods.
We awarded shares of stock to key employees in the following amounts:
- - 41,424 shares in fiscal 1998;
- - 31,863 shares in fiscal 1997; and
- - 7,249 shares in fiscal 1996.
At the date of the award, the weighted average fair value of the
shares was as follows:
- - $19.890 in fiscal 1998;
- - $20.125 in fiscal 1997; and
- - $19.758 in fiscal 1996.
LTSIP Incentive and Nonqualified Stock Options
Incentive and nonqualified stock options are granted at the fair market value
on the date of grant. The vesting of incentive options is subject to a
statutory limitation of $100,000 per year under Section 422A of the Internal
Revenue Code. Otherwise, nonqualified options become fully exercisable six
months after the date of grant and generally expire 10 years after that date.
A summary of activity related to grants of incentive and nonqualified stock
options follows:
_________________________________________
Number of Weighted Average
Options Excercise Price
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1995 849,160 $ 17.18
Granted 299,340 19.40
Exercised (109,980) 17.24
Forfeited (27,176) 19.49
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1996 1,011,344 $ 17.77
- -----------------------------------------------------------------------
Granted 510,119 $ 20.17
Exercised (104,520) 16.70
Forfeited (28,169) 19.76
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1997 1,388,774 $ 18.69
- -----------------------------------------------------------------------
Granted 810,572 19.90
Exercised (68,684) 16.95
Forfeited (51,867) 20.11
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1998 2,078,795 $ 19.19
_______________________________________________________________________
Information about outstanding and exercisable options as of September 30, 1998,
follows:
<TABLE>
_____________________________________________________ _________________________________
Options Outstanding Options Exercisable
_____________________________________________________ _________________________________
<CAPTION>
Weighted Average
Remaining Weighted Weighted
Contractual Life Average Average
Range of Exercise Prices Number of Options (in years) Exercise Price Number of Options Exercise Price
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$13.75 to $17.44 299,730 4.8 $15.88 299,730 $15.88
$18.13 to $19.81 815,138 6.9 $19.23 755,138 $19.26
$20.00 to $22.06 963,927 8.2 $20.18 953,713 $20.16
- ------------------------------------------------------------------------------------------------------------------------------
$13.75 to $22.06 2,078,795 7.2 $19.19 2,008,581 $19.18
______________________________________________________________________________________________________________________________
</TABLE>
A summary of outstanding options that are fully exercisable follows:
___________________________________
Number of Weighted Average
Options Exercise Price
- -----------------------------------------------------------------------
Exercisable - September 30, 1996 1,006,166 $17.76
Exercisable - September 30, 1997 1,384,125 $18.69
Exercisable - September 30, 1998 2,008,581 $19.18
_______________________________________________________________________
We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for our stock
option plans. Accordingly, no compensation expense has been recognized in
connection with our LTSIP option grants. If we had determined compensation
expense for the issuance of options based on the fair value method described
in SFAS No. 123, "Accounting for Stock-Based Compensation," our net income and
earnings per share would have been reduced to the pro forma amounts presented
below:
___________________________________________
For the years ended Sept. 30, 1998 1997 1996
- -------------------------------------------------------------------------------
Net income-as reported (millions) $80.6 $76.6 $75.6
Net income-pro forma (millions) $79.4 $75.6 $75.2
Basic earnings per share-as reported $1.41 $1.37 $1.37
Basic earnings per share-pro forma $1.39 $1.35 $1.36
Diluted earnings per share-as reported $1.41 $1.36 $1.36
Diluted earnings per share-pro forma $1.39 $1.35 $1.36
_______________________________________________________________________________
In accordance with the fair value method of determining compensation expense,
the weighted average grant date fair value per share of options granted was as
follows:
- - $2.55 in fiscal 1998;
- - $2.93 in fiscal 1997; and
- - $2.34 in fiscal 1996.
We used the Black-Scholes pricing model to estimate the fair value of each
option granted with the following weighted average assumptions:
__________________________________
For the years ended Sept. 30, 1998 1997 1996
- ---------------------------------------------------------------------
Expected life (years) 7 7 7
Interest rate 5.5% 6.3% 5.5%
Volatility 17.8% 17.1% 16.5%
Dividend yield 5.5% 5.3% 5.4%
_____________________________________________________________________
Non-Employee Directors Equity Compensation Plan (Directors Plan)
Under the Directors Plan, each non-employee director receives an annual grant
of:
- - a stock award equal to the fair market value of the $16,000 annual retainer,
which is payable to each director; and
- - a nonqualified stock option to purchase the same number of shares of common
stock as the annual stock award.
Nonqualified stock options are granted at the fair market market value on the
date of grant. Options generally expire 10 years after the date of grant.
Non-employee directors were granted options to purchase an aggregate of the
following:
- - 7,980 shares in fiscal 1998;
- - 7,960 shares in fiscal 1997; and
- - 9,306 shares in fiscal 1996.
Note 6. Common Stock
Shareholder Rights Plan
On March 6, 1996, AGL Resources' Board of Directors adopted a Shareholder Rights
Plan. The plan contains provisions to protect AGL Resources' shareholders in the
event of unsolicited offers to acquire AGL Resources or other takeover bids and
practices that could impair the ability of the Board of Directors to represent
shareholders' interests fully. As required by the Shareholder Rights Plan, the
Board of Directors declared a dividend of one preferred share purchase right (a
"Right") for each outstanding share of AGL Resources' common stock, with
distribution made to shareholders of record on March 22, 1996.
The Rights, which will expire March 6, 2006, initially will be
represented by, and traded together with, AGL Resources common stock. The Rights
are not currently exercisable and do not become exercisable unless some
triggering events occur. One of the triggering events is the acquisition of 10%
or more of AGL Resources' common stock by a person or group of affiliated or
associated persons. Unless previously redeemed, upon the occurrence of one of
the specified triggering events, each Right will entitle its holder to purchase
one one-hundredth of a share of Class A Junior Participating Preferred Stock at
a purchase price of $60. Each preferred share will have 100 votes, voting
together with the common stock. Because of the nature of the preferred shares'
dividend, liquidation and voting rights, one one-hundredth of a share of
preferred stock is intended to have the value, rights, and preferences of one
share of common stock. As of September 30, 1998, 1 million shares of Class A
Junior Participating Preferred Stock were reserved for issuance under that plan.
Stock Split
On November 3, 1995, the Board of Directors declared a two-for-one stock split
of the common stock effected in the form of a 100% stock dividend to
shareholders of record on November 17, 1995, and payable on December 1, 1995.
All references to number of shares and to per share amounts have been restated
retroactively to reflect the stock dividend.
Other
AGL Resources issued the following:
- - 739,380 shares of its common stock in fiscal 1998;
- - 753,866 shares of its common stock in fiscal 1997; and
- - 792,919 shares of its common stock in fiscal 1996
under ResourcesDirect, a stock purchase and dividend reinvestment plan; the
Retirement Savings Plus Plan; the Long-Term Stock Incentive Plan; the
Nonqualified Savings Plan; and the Non-Employee Directors Equity Compensation
Plan.
As of September 30, 1998, 7,295,993 shares of common stock were reserved
for issuance pursuant to ResourcesDirect, the Retirement Savings Plus Plan, the
Long-Term Stock Incentive Plan, the Nonqualified Savings Plan, and the
Non-Employee Directors Equity Compensation Plan.
Note 7. Preferred Stock
Subsidiary Obligated Mandatorily Redeemable Preferred Securities
(Capital Securities)
In June 1997 we established AGL Capital Trust (the Trust), a Delaware business
trust, and we own all the common voting securities. The Trust issued and sold
$75 million principal amount of 8.17% Capital Securities (liquidation amount
$1,000 per Capital Security) to certain initial investors. The Trust used the
proceeds to purchase 8.17% Junior Sub-ordinated Deferrable Interest Debentures,
which are due June 1, 2037, from AGL Resources.
The Capital Securities are subject to mandatory redemption at the time
of the repayment of the Junior Subordinated Debentures on June 1, 2037, or the
optional prepayment by AGL Resources after May 31, 2007.
We fully and unconditionally guarantee all the Trust's obligations for the
Capital Securities. We used the net proceeds of approximately $74 million
from the sale of the Junior Subordinated Debentures to repay short-term debt,
to redeem some of AGLC's outstanding issues of preferred stock, and for
other corporate purposes.
Other Preferred Securities
As of September 30, 1998, AGL Resources had 10 million shares of
authorized, but unissued, Class A Junior Participating Preferred Stock,
no par value; and 10 million shares of authorized, but unissued,
preferred stock, no par value. As of September 30, 1998, AGLC had 10
million shares of authorized, but unissued, preferred stock, no par
value.
On August 15, 1997, AGLC redeemed the following
- - 4.5% Cumulative Preferred Stock;
- - 4.72% Cumulative Preferred Stock;
- - 5% Cumulative Preferred Stock;
- - 7.84% Cumulative Preferred Stock; and
- - 8.32% Cumulative Preferred Stock.
Those issues of preferred stock were redeemed at the call price in effect for
each issue, for a total of $14.7 million. They have been retired in full.
On December 1, 1997, AGLC redeemed its 7.70% Series depositary preferred
stock at the redemption price of $100 per share. That issue of preferred stock
has been retired in full.
Note 8. Long-Term Debt
Long-term debt matures more than one year from the date of the financial
statements. Medium-term notes Series A, Series B, and Series C were issued
under an Indenture dated December 1, 1989. The notes are unsecured and rank on
parity with all other unsecured indebtedness. During 1997 the remaining $105.5
million in principal amount of such notes was issued, with maturity dates
ranging from 20 to 30 years and with interest rates ranging from 6.55% to 7.3%.
Net proceeds from the issuance of medium-term notes were used to fund capital
expenditures, repay short-term debt, and for other corporate purposes. The
annual maturities of long-term debt for the five-year period ending September
30, 2003, are as follows:
- - $50 million in fiscal 2000;
- - $20 million in fiscal 2001;
- - $45 million in fiscal 2002; and
- - $48 million in fiscal 2003.
The outstanding long-term debt as of September 30 is as follows:
________________________
Millions of dollars 1998 1997
- -----------------------------------------------------------
Medium-term notes
Series A(1) $ 60.0 $ 60.0
Series B(2) 300.0 300.0
Series C(3) 300.0 300.0
- -----------------------------------------------------------
Total $660.0 $660.0
___________________________________________________________
(1) Interest rates from 8.90% to 9.10% with maturity dates from 2000 to 2021.
(2) Interest rates from 7.15% to 8.70% with maturity dates from 2000 to 2023.
(3) Interest rates from 5.90% to 7.30% with maturity dates from 2004 to 2027.
Note 9. Short-Term Debt
Short-term debt matures within one year from the date of the financial
statements. Lines of credit with various banks provide for direct borrowings
and are subject to annual renewal. The current lines of credit vary throughout
the year from $240 million in the summer months to $290 million for peak
winter financing. Certain of the lines are on a commitment-fee basis. As of
September 30, 1998, $165 million was available on lines of credit.
__________________________________
Millions of dollars 1998 1997 1996
- --------------------------------------------------------------------------
Maximum amounts of short-term debt
outstanding at any month end
during the year $ 149.0 $ 189.0 $ 156.3
- --------------------------------------------------------------------------
Weighted average interest rates
Short-term debt outstanding at end
of year 5.8% 5.9% 5.7%
__________________________________________________________________________
Note 10. Commitments and Contingencies
Agreements for Firm Pipeline and Storage Capacity
In connection with its utility business, AGL Resources has agreements for firm
pipeline and storage capacity that expire at various dates through 2014. The
aggregate amount of required payments under such agreements totals
approximately $1.3 billion, with annual required payments of $221 million in
fiscal 1999, $221 million in fiscal 2000, $203 million in fiscal 2001,
$181 million in fiscal 2002, and $77 million in fiscal 2003. Total payments
of fixed charges under all agreements were $220 million in fiscal 1998,
$215 million in fiscal 1997, and $225 million in fiscal 1996. The purchased
gas adjustment provisions of the utilitys rate schedules have permitted
the recovery of these gas costs from customers. As a result of the Act, AGLC's
rights to capacity under the purchase agreements will be assigned to
certificated marketers as they acquire firm customers. Marketers will be
responsible for payment of the fixed charges associated with the assignments.
FERC Order 636: Transition Costs Settlement Agreements
The utility purchases natural gas transportation and storage services from
interstate pipeline companies, and the Federal Energy Regulatory Commission
(FERC) regulates those services and the rates the interstate pipeline companies
charge it. During the past decade, the FERC has transformed dramatically the
natural gas industry through a series of generic orders promoting competition in
the industry. As part of that transformation, the interstate pipelines that
serve the utility have been required to -
- - unbundle, or separate, their transportation and gas supply services, and
- - provide a separate transportation service on a nondiscriminatory basis for
the gas that is supplied by numerous gas producers or other third parties.
The FERC is considering further revisions to its rules, including the
following:
- - its policies governing secondary market transactions; and
- - revisions that would permit pipelines and their customers to establish
individually negotiated terms and conditions of service that depart
from generally applicable pipeline tariff rules.
The utility cannot predict whether those changes will be adopted or how they
potentially might affect it.
The FERC has required the utility, as well as other interstate pipeline
customers, to pay transition costs associated with the separation of the
suppliers' transportation and gas supply services. Based on its pipeline
suppliers' filings with the FERC, the utility estimates the total portion of its
transition costs from all its pipeline suppliers will be approximately $106.2
million. As of September 30, 1998, approximately $97.8 million of those costs
has been incurred and is being recovered from the utility's customers under the
purchased gas provisions of its rate schedules. Going forward, AGLC will
recover the majority of the remaining costs through its gas sales. A small
portion of the costs will be recovered from certificated marketers as
part of the assignment process under its unbundling plan.
The largest portion of the transition costs the utility must pay consists of
gas supply realignment costs that Southern Natural Gas Company (Southern)
and Tennessee Gas Pipeline Company (Tennessee) bill the utility. The utility
and other parties have entered restructuring settlements with Southern and
Tennessee that resolve all transition cost issues for those pipelines.
Under the Southern settlement, the utility's share of Southern's transition
costs is about $88 million, of which the utility incurred $84.5 million as of
September 30, 1998. Under the Tennessee settlement, the utility's share of
Tennessee's transition costs is about $14.7 million, of which the utility
incurred $10 million as of September 30, 1998.
Collective Bargaining Agreements
On September 30, 1998, AGL Resources and its subsidiaries had 2,791 employees.
Of that total, approximately 702 employees are covered under collective
bargaining agreements. Those agreements provided for a $500 lump sum payment
to each bargaining unit employee in 1998. Based on current pay levels,
it is anticipated that the majority of bargaining unit employees will not
receive any base pay increases until 1999. The collective bargaining
agreements expire in 2000 and 2001.
Rental Expense
Total rental expense for property and equipment was as follows:
- - $7.7 million in fiscal 1998;
- - $6.5 million in fiscal 1997; and
- - $7 million in fiscal 1996.
Minimum annual rentals under noncancelable operating leases are as follows:
- - fiscal 1999 - $8.9 million;
- - fiscal 2000 - $8.6 million;
- - fiscal 2001 - $8.8 million;
- - fiscal 2002 - $8.6 million;
- - fiscal 2003 - $6.1 million; and
- - thereafter - $6.5 million.
On October 14, 1998, AGL Resources entered into an arrangement to sublease
certain corporate office space, the term of which will begin on December 1,
1998, and will expire on January 3, 2003. The original lease is an operating
lease. Annual sublease rental receipts are as follows:
- - fiscal 1999 - $.9 million;
- - fiscal 2000 - $1.5 million;
- - fiscal 2001 - $1.5 million;
- - fiscal 2002 - $1.5 million; and
- - fiscal 2003 - $.4 million.
Litigation
We are involved in litigation arising in the normal course of business. (See
Note 12 in Notes to Consolidated Financial Statements regarding Environmental
Matters.) We believe the ultimate resolution of that litigation will not
have a material adverse effect on the consolidated financial statements.
Note 11. Suppliers' Refunds
The utility has received refunds from its interstate natural gas suppliers.
Those refunds are a result of FERC orders that adjust the price of various
pipeline services purchased by the utility from suppliers in prior periods.
Under purchased gas provisions of rate schedules approved by the TRA,
Chattanooga credits the refunds to customers. Under purchased gas provisions of
rate schedules approved by the GPSC, AGLC credited the refunds to customers
until June 30, 1998. Beginning July 1, 1998, and thereafter, the Act requires
AGLC to credit refunds from interstate natural gas suppliers to a universal
service fund. The universal service fund provides a method to fund the recovery
of marketers' uncollectible accounts, and it enables AGLC to expand its
facilities to serve the public interest.
Note 12. Environmental Matters
Before natural gas was available in the Southeast in the early 1930s, AGLC
manufactured gas from coal and other materials. Those manufacturing operations
were known as "manufactured gas plants," or "MGPs." Because of recent
environmental concerns, we are required to investigate possible contamination at
those plants and, if necessary, clean them up.
Through the years AGLC has been associated with twelve MGP sites in
Georgia and three in Florida. Based on investigations to date, we believe that
some cleanup will be likely at most of the sites. In Georgia, the state
Environmental Protection Division supervises the investigation and cleanup of
MGP sites. In Florida, the U.S. Environmental Protection Agency has that
responsibility.
For each of those sites, we estimated our share of the likely costs of
investigation and cleanup. We used the following process to do the estimates:
First, we eliminated the sites where we believe no cleanup or further
investigation is likely to be necessary. Second, we estimated the likely
future cost of investigation and cleanup at each of the remaining sites.
Third, for some sites, we estimated our likely "share" of the costs.
We developed our estimate based on any agreements for cost sharing we have,
the legal principles for sharing costs, our evaluation of other entities'
ability to pay, and other similar factors.
Using that process, we believe our total future cost of investigating and
cleaning up our MGP sites is between $47 million and $81.3 million. Within
the range of $47 million to $81.3 million, we cannot identify a single number
as the "best" estimate. Therefore, we have recorded the lower value, or $47
million, as a liability as of September 30, 1998. As of September 30, 1997,
the liability which we had recorded was $37.3 million. During the year the
liability increased $25.7 million. After making payments of $16.0 million,
related to legal fees and technical support, the net increase in the
liability was $9.7 million. The increase in the liability was based on
revised estimates, which resulted in a corresponding increase in the
unrecovered environmental response cost asset.
We have two ways of recovering investigation and cleanup costs. First,
the GPSC has approved an "Environmental Response Cost Recovery Rider." It allows
us to recover our costs of investigation, testing, cleanup, and litigation.
Because of that rider, we have recorded an asset in the same amount as our
investigation and cleanup liability. The GPSC, however, is conducting hearings
about three aspects of the rider. Depending on how the GPSC rules, our
recoveries under the rider could be affected. If the GPSC were to limit
significantly our recovery under the rider, the results could be material.
The second way we could recover costs is by exercising the legal rights
we believe we have to recover a share of our costs from other corporations and
from insurance companies. We have been actively pursuing those recoveries. In
fiscal 1998, we recovered $1.9 million. As required by the rider, we retained
$.9 million of that amount, and we credited the balance to our customers.
Note 13. Fair Value of Financial Instruments
In the following table, we show the carrying amounts and fair values of
financial instruments included in our Consolidated Balance Sheets as of
September 30, 1998, and 1997.
Carrying Estimated
Millions of dollars Amount Fair Value
1998
Long-term debt including
current portion $660.0 $714.6
Capital Securities 74.3 81.5
1997
Long-term debt including
current portion $660.0 $687.0
Capital Securities 74.3 76.3
The estimated fair values are determined based on the following:
* Long-term debt - interest rates that are currently available for issuance of
debt with similar terms and remaining maturities.
* Capital securities - quoted market price and dividend rates for preferred
stock with similar terms.
Considerable judgment is required to develop the fair value estimates;
therefore, the values are not necessarily indicative of the amounts that could
be realized in a current market exchange. The fair value estimates are based on
information available to management as of September 30, 1998. Management is not
aware of any subsequent factors that would affect significantly the estimated
fair value amounts.
Note 14. Joint Ventures and Nonutility Acquisitions
SouthStar Energy Services LLC
In July 1998, AGL Resources formed a venture known as SouthStar Energy Services
LLC (SouthStar). SouthStar was established to sell natural gas, propane, fuel
oil, electricity, and related services to industrial, commercial, and
residential customers in Georgia and the Southeast. SouthStar is a joint venture
among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a subsidiary of
Dynegy, Inc., and Piedmont Energy Company, a subsidiary of Piedmont Natural Gas
Company. SouthStar filed for certification as a retail marketer with the GPSC on
July 15, 1998, and was approved on October 6, 1998. SouthStar operates in
Georgia under the name "Georgia Natural Gas Services."
Etowah LNG
On December 15, 1997, AGL Resources, through its subsidiary AGL Peaking
Services, and Southern Natural Gas Company, a subsidiary of Sonat Inc., signed
an agreement to construct, own, and operate a new liquefied natural gas peaking
facility, Etowah LNG (Etowah). AGL Peaking Services and Southern each will own
50% of Etowah, the operations of which will be subject to jurisdiction of the
FERC. Etowah is located in Polk County, Georgia.
The proposed plant will connect AGLC's and Southern's pipelines directly.
Etowah will provide natural gas storage and peaking services to AGLC and
other southeastern customers. The new facility will cost approximately
$90 million and will have 2.5 billion cubic feet of natural gas storage
capacity and 300 million cubic feet per day of vaporization capacity.
AGL Resources' affiliates will manage the construction of the facility
and operate it. Southern will provide administrative services.
The companies filed a certificate application with the FERC on April 20,
1998. Subject to receiving timely FERC approval, construction is expected to
begin in early 1999 in order to provide peaking services during the 2001-2002
winter heating season.
Etowah has received subscriptions for peaking services for 71% of its
firm peak-service capacity. The majority of such capacity has been subscribed
for by AGLC pursuant to an agreement between AGLC and Etowah LNG Company LLC.
Under this agreement, AGLC may, until February 15, 1999, terminate its
subscription for capacity if, among other things, it determines that as a result
of GPSC actions or inactions, the subscription for such capacity is not in
AGLC's best interests. Termination by AGLC of its capacity subscription would
not have a material effect on our consolidated financial statements.
Cumberland Pipeline Company
On December 1, 1997, AGL Resources, through its subsidiary AGL Interstate
Pipeline, entered a joint venture with Transcumberland Pipeline Company, a
subsidiary of Transcontinental Gas Pipe Line Corporation (Transco). The joint
venture, Cumberland Pipeline Company (Cumberland), will provide interstate
pipeline services to customers in Georgia and Tennessee.
Initially, the 135-mile pipeline will include existing pipeline
infrastructure owned by the two companies extending from Walton County, Georgia,
to Catoosa County, Georgia. The pipeline is projected to enter service by
November 1, 2000; Cumberland will be positioned to serve AGLC, Chattanooga, and
other markets throughout the eastern Tennessee Valley, northwest Georgia, and
northeast Alabama. Transco and AGL Resources affiliates each will own 50% of
Cumberland, and a Transco affiliate will serve as operator. The companies
announced an open season from March 30, 1998, to May 29, 1998, for nonbinding
subscriptions for capacity on Cumberland, and the project will be submitted to
the FERC for approval during fiscal 1999.
Service from Cumberland was included in the five-year forecast filed
with AGLCs 1999 Gas Supply Plan at the GPSC. In that proceeding, the GPSC
granted a request by East Tennessee Natural Gas Company (East Tennessee) to
establish a separate proceeding to examine AGLC's plans to replace service from
East Tennessee with service from Cumberland. The separate proceeding provides
for two rounds of comments by interested parties, to be filed with the GPSC in
December 1998 and January 1999. Although the GPSC decision may affect
AGLC's plans to contract for service from Cumberland, AGLC cannot predict the
outcome of that proceeding.
Sonat Marketing Company, L.P.
During August 1995 AGLC signed an agreement with Sonat Inc. to form the joint
venture, Sonat Marketing Company, L.P. (Sonat Marketing). Sonat Marketing offers
natural gas sales, transportation, risk management, and storage services in key
natural gas producing and consuming areas of the United States.
AGLC invested $32.6 million for a 35% ownership interest in Sonat
Marketing, which was transferred to AGL Gas Marketing, Inc., a wholly owned
subsidiary of AGL Investments, during the third quarter of fiscal 1996. AGL Gas
Marketing, Inc.'s 35% investment is being accounted for under the equity method.
The excess of the purchase price over the estimated fair value of the net
tangible assets of approximately $23 million has been allocated to intangible
assets consisting of customer lists and goodwill. Those assets are being
amortized over 10 and 35 years, respectively.
AGL Investments has rights through August 2000 to sell its interest in
Sonat Marketing to Sonat Inc. at a predetermined fixed price, as defined, or for
fair market value at any time.
Sonat Power Marketing, L.P.
AGL Power Services, Inc., a wholly owned subsidiary of AGL Investments, holds a
35% interest in Sonat Power Marketing, L.P., which provides power marketing and
all related services in key market areas throughout the United States. During
fiscal 1996, AGL Power Services, Inc. invested approximately $1 million in
exchange for a 35% ownership interest in the partnership.
Regional Propane Operations
During fiscal 1997 AGL Investments acquired regional propane operations in
northern Alabama, northern Georgia, and eastern Tennessee for approximately
$17.7 million. Those acquisitions are accounted for following the purchase
method of accounting. The excess of the purchase price over the estimated fair
value of the net tangible assets of approximately $5.8 million has been
allocated to goodwill and is being amortized over 40 years.
Note 15. Related Party Transactions
AGL Resources purchased gas totaling $208.2 million in fiscal 1998, $287.9
million in fiscal 1997, and $247.5 million in fiscal 1996 from Sonat Marketing
and its affiliates. AGL Resources had outstanding obligations payable to Sonat
Marketing of $27.4 million as of September 30, 1998, and $32.6 million as
of September 30, 1997.
AGL Resources sold gas totaling $1.9 million in fiscal 1998 to
SouthStar. AGL Resources recognized revenue of $.5 million on services provided
to SouthStar during fiscal 1998. AGL Resources had $2.5 million in accounts
receivable from SouthStar as of September 30, 1998. AGL Resources' purchases
from SouthStar in fiscal 1998 were immaterial.
Note 16. Quarterly Financial Data (Unaudited)
The increase in operating revenues and net income in the quarter ended September
30, 1998, is primarily due to a new rate structure, which recovers nongas costs
evenly throughout the year consistent with the way the costs are incurred. That
rate structure for AGLC's gas distribution service was effective July 1, 1998.
The increase was offset partly by higher operating expenses resulting
principally from noncash, nonrecurring charges of $13.9 million
associated with the impairment of certain assets no longer useful
primarily due to changes in our information systems strategy. (See Note
1 in Notes to Consolidated Financial Statements.) During the quarter ended
September 30, 1998, we reduced our income tax liability for prior years by
$2.3 million.
Quarterly financial data for fiscal 1998 and fiscal 1997 are summarized as
follows:
Millions of dollars,
except per share data Operating Operating
Quarter Ended Revenues Income
1998
December 31, 1997 $402.3 $52.4
March 31, 1998 483.9 83.3
June 30, 1998 247.0 8.8
September 30, 1998 205.4 23.1
1997
December 31, 1996 $379.6 $60.2
March 31, 1997 496.7 89.0
June 30, 1997 216.7 15.1
September 30, 1997 194.6 7.2
Basic Diluted
Earnings Earnings
Net (Loss)Per (Loss) Per
Income Common Common
Quarter Ended (Loss)(a) Share(a) Share(a)
1998
December 31, 1997 $25.7 $.45 $.45
March 31, 1998 45.1 .79 .79
June 30, 1998 (1.2) (.02) (.02)
September 30, 1998 11.0 .19 .19
1997
December 31, 1996 $29.6 $.53 $.53
March 31, 1997 49.0 .88 .87
June 30, 1997 1.4 .03 .03
September 30, 1997 (3.4) (.06) (.06)
(a) The wide variance in quarterly earnings results from the highly seasonal
nature of AGL Resources' primary business.
Basic and diluted earnings per common share are calculated based on the weighted
average number of common shares outstanding and common share equivalents during
the quarter. Those totals differ from the basic and diluted earnings per share,
as shown on the Statements of Consolidated Income, which are based on the
weighted average number of common shares outstanding and common share
equivalents for the entire year.
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors of AGL Resources Inc.:
We have audited the accompanying consolidated balance sheets of AGL Resources
Inc. and subsidiaries as of September 30, 1998 and 1997, and the related
statements of consolidated income, common stock equity, and cash flows for each
of the three years in the period ended September 30, 1998. These financial
statements are the responsibility of AGL Resource's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of AGL Resources Inc. and subsidiaries
as of September 30, 1998 and 1997, and the results of its operations and its
cash flows for each of the three years in the period ended September 30, 1998,
in conformity with generally accepted accounting principles.
DELOITTE AND TOUCHE LLP
Atlanta, Georgia
November 2, 1998
Management's Responsibility for Financial Reporting
The consolidated financial statements and related information are the
responsibility of management. The financial statements have been prepared in
conformity with generally accepted accounting principles appropriate in the
circumstances. The financial information contained elsewhere in this Annual
Report is consistent with that in the financial statements.
AGL Resources maintains a system of internal accounting controls designed to
provide reasonable assurance that assets are safeguarded from loss and that
transactions are executed and recorded in accordance with established
procedures. The concept of reasonable assurance is based on the recognition that
the cost of maintaining a system of internal accounting controls should not
exceed related benefits. The system of internal accounting controls is
supported by written policies and guidelines.
The financial statements have been audited by Deloitte & Touche LLP, independent
auditors. Their audits were made in accordance with generally
accepted auditing standards, as indicated in the Independent Auditors' Report,
and included a review of the system of internal accounting controls and tests of
transactions to the extent they considered necessary to carry out their
responsibilities.
The Board of Directors pursues its responsibility for reported financial
information through its Audit Committee. The Audit Committee meets
periodically with management and the independent auditors to assure that they
are carrying out their responsibilities and to discuss internal accounting
controls, auditing and financial reporting matters.
Walter M. Higgins J. Michael Riley
President and Senior Vice President and
Chief Executive Officer Chief Financial Officer
November 2, 1998 November 2, 1998
<PAGE>
<TABLE>
Selected Financial Data
For the years ended September 30,
-------------------------------------------------------------------------------
<CAPTION>
In millions, except per share amounts 1998 1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Income Statement Data
Operating revenues $ 1,338.6 $ 1,287.6 $ 1,228.6 $ 1,068.5 $ 1,199.9 $ 1,130.3
Cost of sales 796.0 766.5 725.5 574.1 736.8 701.0
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Operating margin 542.6 521.1 503.1 494.4 463.1 429.3
- -----------------------------------------------------------------------------------------------------------------------------------
Other operating expenses
Operation 238.1 226.2 221.8 215.5 207.0 187.6
Restructuring costs 70.3
Maintenance 38.4 30.8 29.5 30.4 32.8 30.9
Depreciation 71.1 66.6 63.3 59.0 55.4 58.8
Taxes other than income taxes 27.4 26.0 25.0 25.7 26.0 23.9
- -----------------------------------------------------------------------------------------------------------------------------------
Total other operating expenses 375.0 349.6 339.6 400.9 321.2 301.2
- -----------------------------------------------------------------------------------------------------------------------------------
Operating income 167.6 171.5 163.5 93.5 141.9 128.1
- -----------------------------------------------------------------------------------------------------------------------------------
Other income 12.9 10.3 13.1 1.5 5.2 6.6
- -----------------------------------------------------------------------------------------------------------------------------------
Interest expense and
preferred stock dividends 61.1 58.4 53.5 51.9 52.1 51.0
- -----------------------------------------------------------------------------------------------------------------------------------
Income before income taxes 119.4 123.4 123.1 43.1 95.0 83.7
- -----------------------------------------------------------------------------------------------------------------------------------
Income taxes 38.8 46.8 47.5 16.7 36.3 30.5
- -----------------------------------------------------------------------------------------------------------------------------------
Net income 80.6 76.6 75.6 26.4 58.7 53.2
Common dividends paid 61.5 60.5 58.6 54.2 52.2 51.1
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Earnings reinvested $ 19.1 $ 16.1 $ 17.0 $ (27.8) $ 6.5 $ 2.1
- -----------------------------------------------------------------------------------------------------------------------------------
Common Stock Data (1)
Weighted average shares outstanding - basic 57.0 56.1 55.3 52.4 50.2 49.2
Weighted average shares outstanding - diluted 57.1 56.2 55.4 52.5 50.3 49.2
Earnings per share - basic $ 1.41 $ 1.37 $ 1.37 $ 0.50 $ 1.17 $ 1.08
Earnings per share - diluted $ 1.41 $ 1.36 $ 1.36 $ 0.50 $ 1.17 $ 1.08
Dividends paid per share $ 1.08 $ 1.08 $ 1.06 $ 1.04 $ 1.04 $ 1.04
Dividend payout ratio 76.6% 78.8% 77.4% 208.0% 88.9% 96.3%
Book value per share (2) $ 11.42 $ 10.99 $ 10.56 $ 10.15 $ 10.20 $ 9.90
Market value per share (3) $ 19.38 $ 18.94 $ 19.13 $ 19.31 $ 15.31 $ 18.81
- -----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data (2)
Total assets $ 1,981.8 $ 1,925.5 $ 1,823.1 $ 1,674.6 $ 1,642.9 $ 1,533.0
Long-term liabilities
Accrued environmental response costs $ 47.0 $ 37.3 $ 30.4 $ 28.6 $ 24.3 $ 19.6
Accrued pension costs $ 2.2 $ 4.9 $ 10.3
Accrued postretirement benefits costs $ 33.4 $ 34.3 $ 36.2 $ 30.1 $ 3.6
Deferred credits $ 57.8 $ 62.4 $ 60.9 $ 65.6 $ 66.6 $ 42.3
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt
(including current portion) $ 660.0 $ 660.0 $ 554.5 $ 554.5 $ 569.5 $ 500.7
Preferred stock
(including current portion)
Preferred stock of subsidiary 44.5 58.8 58.8 58.8 59.0
Subsidiary obligated mandatorily
redeemable preferred securities 74.3 74.3
Common equity 654.1 622.1 588.3 557.3 518.5 492.0
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
Total $ 1,388.4 $ 1,400.9 $ 1,201.6 $ 1,170.6 $ 1,146.8 $ 1,051.7
- -----------------------------------------------------------------------------------------------------------------------------------
Financial Ratios (2)
Capitalization
Long-term debt 47.5% 47.1% 46.1% 47.4% 49.6% 47.6%
Preferred stock of subsidiary 3.2 4.9 5.0 5.2 5.6
Subsidiary obligated mandatorily
redeemable preferred securities 5.4 5.3
Common equity 47.1 44.4 49.0 47.6 45.2 46.8
- -----------------------------------------------------------------------------------------------------------------------------------
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Return on average common equity 12.6% 12.7% 13.2% 4.9% 11.6% 11.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Ratio of earnings to: (4)
Interest charges 3.30 3.46 3.58 1.99 3.08 2.86
Interest charges and
preferred stock dividends 2.94 3.10 3.28 1.83 2.82 2.63
Combined fixed charges and
preferred stock dividends (5) 2.77 2.90 3.08 1.75 2.66 2.49
- -----------------------------------------------------------------------------------------------------------------------------------
<FN>
(1) Adjusted for two-for-one stock splits paid in the form of 100% stock
dividends on December 1, 1995. (2) Year-end.
(3) September 30 closing market price.
(4) Interest charges exclude the debt portion of allowance for funds used during
construction.
(5) Fixed charges consist of interest on short- and long-term debt, other
interest and the estimated interest component of rentals.
</FN>
</TABLE>
<PAGE>
<TABLE>
Gas Sales and Statistics
- ----------------------------------------------------------------------------------------------------------------------
For the years ended September 30,
--------------------------------------------------------------------
<CAPTION>
1998 1997 1996 1995 1994 1993
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues (Millions of Dollars)
Sales of natural gas
Residential $ 775.9 $ 728.5 $ 708.8 $ 610.6 $ 700.7 $ 658.2
Commercial 294.1 290.9 288.8 243.2 285.8 268.1
Industrial 152.6 148.0 178.8 169.4 172.1 154.2
Transportation revenues 34.8 28.5 21.5 23.9 22.6 33.8
Miscellaneous revenues 21.4 20.2 19.7 15.9 18.7 16.0
- ----------------------------------------------------------------------------------------------------------------------
Total utility operating revenues 1,278.8 1,216.1 1,217.6 1,063.0 1,199.9 1,130.3
- ----------------------------------------------------------------------------------------------------------------------
Other operating revenues 59.8 71.5 11.0 5.5
- ----------------------------------------------------------------------------------------------------------------------
Total operating revenues $ 1,338.6 $ 1,287.6 $ 1,228.6 $ 1,068.5 $ 1,199.9 $ 1,130.3
- ----------------------------------------------------------------------------------------------------------------------
Utility Throughput
Therms sold (Millions)
Residential 1,084.9 986.1 1,165.4 916.8 1,003.1 1,001.4
Commercial 467.8 455.5 538.2 454.0 478.9 478.5
Industrial 438.1 344.9 449.6 526.0 424.8 388.7
Therms transported 1,310.6 1,014.5 738.7 722.8 697.4 795.6
- ----------------------------------------------------------------------------------------------------------------------
Total utility throughput 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
- ----------------------------------------------------------------------------------------------------------------------
Average Utility Customers (Thousands)
Residential 1,351.5 1,319.0 1,289.4 1,250.4 1,215.2 1,182.7
Commercial 107.4 104.5 102.5 100.0 98.0 95.7
Industrial 2.6 2.7 2.6 2.6 2.5 2.5
- ----------------------------------------------------------------------------------------------------------------------
Total 1,461.5 1,426.2 1,394.5 1,353.0 1,315.7 1,280.9
- ----------------------------------------------------------------------------------------------------------------------
Sales, Per Average Residential
Utility Customer
Gas sold (Therms) 803 748 904 733 825 847
Revenue $574.10 $552.00 $550.00 $488.32 $576.61 $556.52
Revenue per therm (cents) 71.5 73.9 60.8 66.6 69.9 65.7
Degree Days - Atlanta Area
30-year normal 2,991 2,991 2,991 2,991 2,991 3,021
Actual 3,078 2,402 3,191 2,121 2,565 2,852
Percentage of actual to 30-year normal 102.9 80.3 106.7 70.9 85.8 94.4
Gas Account (Millions of Therms)
Natural gas purchased 1,459.1 1,323.4 1,632.9 1,406.9 1,453.6 1,629.9
Natural gas withdrawn from storage 604.7 472.4 596.0 520.7 500.3 276.4
Natural gas transported 1,310.8 1,014.5 738.7 722.8 697.4 795.6
- ----------------------------------------------------------------------------------------------------------------------
Total send-out 3,374.6 2,810.3 2,967.6 2,650.4 2,651.3 2,701.9
Less
Unaccounted for 66.2 1.3 60.4 20.4 37.2 29.0
Company use 7.0 8.0 15.3 10.4 9.9 8.7
- ----------------------------------------------------------------------------------------------------------------------
Sold and transported
to utility customers 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
- ----------------------------------------------------------------------------------------------------------------------
Cost of Gas (Millions of Dollars)
Natural gas purchased $ 558.8 $ 532.5 $ 547.1 $ 389.4 $ 550.1 $ 595.7
Natural gas withdrawn from storage 203.7 175.7 171.6 182.4 186.7 105.3
- ----------------------------------------------------------------------------------------------------------------------
Cost of gas - utility operations 762.5 708.2 718.7 571.8 736.8 701.0
- ----------------------------------------------------------------------------------------------------------------------
Cost of gas - other 33.5 58.3 6.8 2.3
- ----------------------------------------------------------------------------------------------------------------------
Total cost of gas $ 796.0 $ 766.5 $ 725.5 $ 574.1 $ 736.8 $ 701.0
- ----------------------------------------------------------------------------------------------------------------------
Utility Plant - End of Year
(Millions of Dollars)
Gross plant $ 2,133.5 $ 2,069.1 $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6
Net plant $ 1,452.6 $ 1,420.3 $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9
Gross plant investment per utility
customer (Thousands of Dollars) $ 1.5 $ 1.5 $ 1.4 $ 1.4 $ 1.4 $ 1.4
Capital Expenditures (Millions of Dollars) $ 118.2 $ 147.7 $ 132.5 $ 121.7 $ 122.5 $ 122.2
Gas Mains - Miles of 3" Equivalent 30,753 30,261 29,045 28,520 27,972 27,390
Employees - Average 3,024 2,986 2,942 3,249 3,764 3,764
Average Btu Content of Natural Gas 1,028 1,024 1,024 1,027 1,032 1,027
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
Subsidiaries of AGL Resources Inc. *
Following is a listing of the first tier subsidiaries and their related
second tier subsidiaries:
Name of Subsidiary Jurisdiction of incorporation
AGL Energy Services, Inc. Georgia
Georgia Gas Company Georgia
AGL Interstate Pipeline Company Georgia
AGL Investments, Inc. Georgia
AGL Gas Marketing, Inc. Georgia
AGL Power Services, Inc. Georgia
AGL Propane, Inc. Georgia
Trustees Investments, Inc. Georgia
Utilipro, Inc. Georgia
AGL Peaking Services, Inc. Georgia
AGL Resources Service Company Georgia
Atlanta Gas Light Company Georgia
Chattanooga Gas Company Tennessee
Atlanta Gas Light Services, Inc. Georgia
* The names of certain subsidiaries have been omitted because, considered
in the aggregate as a single subsidiary, they would not constitute a
significant subsidiary.
Exhibit 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-31674, 33-50301, 33-62155, 333-01519, 333-02353, 333-26961 and 333-26963
on Form S-8 and Registration Statement No. 333-22867 on Form S-3 of our
reports dated November 2, 1998 appearing and incorporated by reference in
this Annual Report on Form 10-K of AGL Resources Inc. for the year ended
September 30, 1998.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
December 23, 1998
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<TOTAL-NET-UTILITY-PLANT> 1,453
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<EARNINGS-AVAILABLE-FOR-COMM> 81
<COMMON-STOCK-DIVIDENDS> 62
<TOTAL-INTEREST-ON-BONDS> 50
<CASH-FLOW-OPERATIONS> 178
<EPS-PRIMARY> 1.41
<EPS-DILUTED> 1.41
</TABLE>
