UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended December 31, 1998
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification Number
1-14174 AGL RESOURCES INC. 58-2210952
(A Georgia Corporation)
303 PEACHTREE STREET, NE
ATLANTA, GEORGIA 30308
404-584-9470
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 the number of shares outstanding of each of the issuer's classes of
common stock, as of December 31, 1998.
Common Stock, $5.00 Par Value
Shares Outstanding at December 31, 1998 ............................57,524,148
AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended December 31, 1998
Table of Contents
Item Page
Number Number
PART I -- FINANCIAL INFORMATION
1 Financial Statements
Condensed Consolidated Income Statements 3
Condensed Consolidated Balance Sheets 4
Condensed Consolidated Statements of Cash Flows 6
Notes to Condensed Consolidated Financial Statements 7
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 11
3 Quantitative and Qualitative Disclosure About Market Risk 25
PART II -- OTHER INFORMATION
1 Legal Proceedings 26
5 Other Information 26
6 Exhibits and Reports on Form 8-K 26
SIGNATURES 27
Page 2 of 27 Pages
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS
FOR THE THREE MONTHS ENDED
DECEMBER 31, 1998 AND 1997
(MILLIONS, EXCEPT PER SHARE DATA)
(UNAUDITED)
1998 1997
Operating Revenues $ 323.9 $ 399.1
Cost of Gas 187.0 254.0
-----------------------------------------
Operating Margin 136.9 145.1
Other Operating Expenses 89.2 92.7
-----------------------------------------
Operating Income 47.7 52.4
Other Income (Loss) (7.9) 5.2
-----------------------------------------
Income Before Interest and Income Taxes 39.8 57.6
Interest Expense and Preferred Stock Dividends
Interest expense 14.2 14.1
Dividends on preferred stock of subsidiaries 1.5 2.4
-----------------------------------------
Total interest expense and preferred stock dividends 15.7 16.5
-----------------------------------------
Income Before Income Taxes 24.1 41.1
Income Taxes 8.2 15.4
=========================================
Net Income $ 15.9 $ 25.7
=========================================
Earnings per Common Share
Basic $ 0.28 $ 0.45
Diluted $ 0.28 $ 0.45
Weighted Average Number of Common Shares Outstanding
Basic 57.4 56.7
Diluted 57.7 56.8
Cash Dividends Paid Per Share of Common Stock $ 0.27 $ 0.27
<FN>
See notes to condensed consolidated financial statements.
</FN>
Page 3 of 27 Pages
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
December 31, September 30,
---------------------------------------------------
ASSETS 1998 1997 1998
- ------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ - $ 7.9 $ 0.9
Receivables (less allowance for uncollectible accounts
of $4.9 at December 31, 1998, $5.0 at December 31,
1997, and $4.1 at September 30, 1998) 214.6 223.9 121.7
Inventories
Natural gas stored underground 106.4 109.3 138.1
Liquefied natural gas 16.0 17.7 17.7
Other 12.5 13.0 14.6
Deferred purchased gas adjustment 3.3 33.1 3.5
Other 2.0 1.9 1.9
- ------------------------------------------------------------------------------------------------------------------------
Total current assets 354.8 406.8 298.4
- ------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Utility plant 2,150.2 2,091.3 2,133.5
Less: accumulated depreciation 694.6 661.4 680.9
- ------------------------------------------------------------------------------------------------------------------------
Utility plant - net 1,455.6 1,429.9 1,452.6
- ------------------------------------------------------------------------------------------------------------------------
Nonutility property 114.0 108.7 105.6
Less: accumulated depreciation 27.1 30.9 24.6
- ------------------------------------------------------------------------------------------------------------------------
Nonutility property - net 86.9 77.8 81.0
- ------------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment - net 1,542.5 1,507.7 1,533.6
- ------------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental response costs 76.9 53.7 77.6
Investments in joint ventures 41.8 39.5 46.7
Other 32.3 42.9 29.0
- ------------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 151.0 136.1 153.3
========================================================================================================================
Total Assets $ 2,048.3 $ 2,050.6 $ 1,985.3
========================================================================================================================
<FN>
See notes to condensed consolidated financial statements.
</FN>
Page 4 of 27 Pages
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
December 31, September 30,
---------------------------------------------------
------------------------------- -----------------
LIABILITIES AND CAPITALIZATION 1998 1997 1998
- ------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------
Current Liabilities
Accounts payable $ 71.0 $ 93.7 $ 48.4
Short-term debt 113.0 150.5 76.5
Customer deposits 31.7 31.6 30.5
Accrued interest 21.6 20.4 32.8
Taxes 11.1 30.3 10.1
Deferred purchased gas adjustment 8.4 12.4
Other 52.8 32.9 42.8
- ------------------------------------------------------------------------------------------------------------------------
Total current liabilities 309.6 359.4 253.5
- ------------------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes 207.0 188.6 203.0
- ------------------------------------------------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs 47.0 37.3 47.0
Accrued postretirement benefits costs 33.9 35.1 33.4
Deferred credits 54.3 59.7 57.8
Other 3.7 0.4 2.1
- ------------------------------------------------------------------------------------------------------------------------
Total long-term liabilities 138.9 132.5 140.3
- ------------------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 660.0 660.0 660.0
Subsidiary obligated mandatorily redeemable
preferred securities 74.3 74.3 74.3
Common stock, $5 par value, shares issued and
outstanding of 57.5 at December 31, 1998, 56.8 at
December 31, 1997, and 57.3 at September 30, 1998 658.5 635.8 654.2
- ------------------------------------------------------------------------------------------------------------------------
Total capitalization 1,392.8 1,370.1 1,388.5
========================================================================================================================
Total Liabilities and Capitalization $ 2,048.3 $ 2,050.6 $ 1,985.3
========================================================================================================================
<FN>
See notes to condensed consolidated financial statements.
</FN>
Page 5 of 27 Pages
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED DECEMBER 31, 1998 AND 1997
(MILLIONS OF DOLLARS)
(UNAUDITED)
Three Months
-----------------------------
-----------------------------
1998 1997
- ----------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 15.9 $ 25.7
Adjustments to reconcile net income to net
cash flow from operating activities
Depreciation and amortization 21.0 18.4
Deferred income taxes 4.0 (1.3)
Other (0.3) (0.3)
Changes in certain assets and liabilities (37.6) (72.4)
- ----------------------------------------------------------------------------------------------------------
Net cash flow from operating
activities 3.0 (29.9)
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Short-term borrowings, net 36.5 121.0
Sale of common stock, net of expenses 1.3 0.7
Redemption of preferred securities (44.5)
Dividends paid on common stock (12.9) (13.0)
- ----------------------------------------------------------------------------------------------------------
Net cash flow from financing
activities 24.9 64.2
- ----------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures (25.5) (25.2)
Non-utility property expenditures (3.9) (2.5)
Investment in joint ventures (3.0)
Cash received from joint ventures 0.3
Other 0.6 (0.8)
- ----------------------------------------------------------------------------------------------------------
Net cash flow from investing
activities (28.8) (31.2)
- ----------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash
and cash equivalents (0.9) 3.1
Cash and cash equivalents at
beginning of period 0.9 4.8
- ----------------------------------------------------------------------------------------------------------
Cash and cash equivalents at
end of period $ - $ 7.9
==========================================================================================================
Cash paid during the period for
Interest $ 25.5 $ 23.6
Income taxes $ 0.1 $ 1.4
<FN>
See notes to condensed consolidated financial statements.
</FN>
Page 6 of 27 Pages
AGL RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. General
AGL Resources Inc. is the holding company for Atlanta Gas Light
Company and its wholly owned subsidiary, Chattanooga Gas Company
which are local natural gas distribution utilities. Additionally,
AGL Resources Inc. owns several nonutility subsidiaries and has
interests in several nonutility joint ventures. We collectively
refer to AGL Resources Inc. and its subsidiaries as "AGL Resources."
We refer to Atlanta Gas Light Company as "AGLC."
In the opinion of management, the unaudited consolidated financial
statements included herein reflect all normal recurring adjustments
necessary for a fair statement of the results of the interim periods
reflected. These interim financial statements and notes are condensed
as permitted by the instructions to Form 10-Q, and should be read in
conjunction with the financial statements and the notes included in the
annual report on Form 10-K of AGL Resources for the fiscal year ended
September 30, 1998. Due to the seasonal nature of AGL Resources'
business, the results of operations for a three-month period are not
necessarily indicative of results of operations for a twelve-month
period.
We make estimates and assumptions when preparing financial statements
under generally accepted accounting principles. Those estimates and
assumptions affect various matters, including :
- reported amounts of assets and liabilities in our Condensed
Consolidated Balance Sheets as of the dates of the financial
statements;
- disclosure of contingent assets and liabilities as of the
dates of the financial statements; and
- reported amounts of revenues and expenses in our Condensed
Consolidated Income Statements 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.
Certain amounts in financial statements of prior years have been
reclassified to conform to the presentation of the current year.
2. Impact of New Regulatory Rate Structure and Deregulation
Due to changes in the regulatory rate structure and the enactment of
Georgia's Natural Gas Competition and Deregulation Act (the
Deregulation Act), AGLC has begun 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 revenues and expenses
will not follow the same pattern as they have historically.
Page 7 of 27 Pages
2. Impact of New Regulatory Rate Structure and Deregulation (Continued)
New Regulatory Rate Structure
Beginning July 1, 1998, AGLC's charges for delivery service to utility
customers in Georgia have been based on a straight fixed variable (SFV)
rate design. Under SFV rates, fixed delivery service costs (as opposed
to gas commodity sales costs discussed below) are recovered evenly
throughout the year consistent with the way those costs are incurred.
The effect of the rate structure is to levelize throughout the year the
revenues collected by AGLC for gas delivery services. Prior to July 1,
1998, rates to provide delivery service were based principally on the
amount of gas customers used. Therefore, delivery 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. Consequently, substantial changes
to the quarterly results of operations are expected when compared to
the historical quarterly results due to the transition to this new
regulatory approach.
Deregulation
Pursuant to the Deregulation Act, regulated rates for natural gas
commodity sales service to AGLC customers (as opposed to delivery
service rates discussed above) ended on October 6, 1998. In the
deregulated environment, AGLC intended to price deregulated gas sales
in a manner that, at a minimum, would have allowed it to recover its
annual gas costs.
On January 5, 1999, the GPSC issued a Procedural and Scheduling Order
for the purpose of hearing evidence to consider whether unregulated
prices charged by AGLC for gas sales services subsequent to October 6,
1998 were constrained by market forces. The GPSC initiated the
proceeding in response to numerous complaints from customers who
received gas sales service from AGLC in November and December 1998.
Those complaints stemmed primarily from the effects of record warm
weather on November and December bills that, in many cases, reflected
higher fixed costs associated with gas sales and lower gas usage than
historical comparisons.
AGLC's gas sales rates were designed to enable the Company to recover
its fixed costs associated with gas sales from the customers for whom
the costs were incurred. AGLC intended to bill much of those fixed
costs during the winter, when consumption is typically higher, and
fewer of those fixed costs in the summer, when consumption is typically
lower. Under normal weather conditions, this billing approach would
have produced monthly bills in amounts similar to bills of
corresponding months in recent years. However, unseasonably warm
weather resulted in fixed costs comprising a higher percentage of
customers' bills due to lower gas usage by many customers in November
and December.
On January 26, 1999, AGLC entered into a joint stipulation with the
GPSC to resolve certain gas sales service issues. Among other
requirements in the stipulation, the Company has implemented a new rate
structure for gas sales, beginning with February 1999 bills, that more
closely reflects customers' actual gas usage which includes a demand
charge for fixed costs associated with gas sales that is entirely
volumetric. The new rate structure for gas sales service is intended to
ensure AGLC's recovery of its purchased gas costs incurred from October
6, 1998 to September 30, 1999 as accurately as possible without
creating any significant income or loss. The joint stipulation
agreement provides for a true-up of gas costs and revenues for fiscal
1999 for any amounts over or under a relatively small adjustable dead
band. To the extent that such overage or underage exceeds the
applicable dead band, AGLC will either refund to or collect from its
customers the applicable overage or underage that exists on September
30, 1999.
Page 8 of 27 Pages
2. Impact of New Regulatory Rate Structure and Deregulation (Continued)
As part of the joint stipulation, AGLC also agreed to issue checks to
customers or credits to customer bills in the total amount of
approximately $14.7 million to lessen the effects of the Company's
earlier rate methodology. Of that amount, $8.2 million will be refunded
to AGLC customers based on the over-collection of gas costs during
fiscal 1998 before deregulation began and as reported in our balance
sheet as of December 31, 1998. The remaining $6.5 million will be
allocated during the second quarter to certain AGLC customers who were
most adversely affected by the change in AGLC's rate structure for gas
sales service.
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 Deregulation 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
deliver 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 for regulatory
assets and liabilities related to AGLC's delivery services.
Pursuant to the Deregulation Act, regulated rates ended on October 6,
1998 for natural gas commodity sales to AGLC customers. Consequently,
SFAS 71 was discontinued as it relates to natural gas commodity sales
on October 6, 1998. In accordance with the EITF consensus, the
following represents the utility's operating revenues, cost of gas and
operating margin between regulated and non-regulated operations for the
three months ended December 31, 1998 (in millions):
Operating Revenues
Nonregulated $ 173.8
Regulated 143.4
============
Total Utility $ 317.2
============
Cost of Sales
Nonregulated $ 172.7
Regulated 12.2
============
Total Utility $ 184.9
============
Operating Margins
Nonregulated $ 1.1
Regulated 131.2
============
Total Utility $ 132.3
============
Page 9 of 27 Pages
3. Earnings Per Share and Equity
Basic earnings per share excludes dilution and is computed by dividing
income available to common stockholders by the weighted average number
of common shares outstanding for the period. Diluted earnings per share
reflects the potential dilution that could occur when common stock
equivalents are added to common shares outstanding. AGL Resources' only
common stock equivalents are stock options whose exercise price was
less than the average market price of the common shares for the
respective periods. Additional options to purchase 22,252 and 509,189
shares of common stock were outstanding as of December 31, 1998 and
1997, respectively, but were not included in the computation of diluted
earnings per share because the exercise price of those options was
greater than the average market price of the common shares for the
respective periods.
During the three months ended December 31, 1998, we issued 211,379
shares of common stock 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 $3.7 million.
4. Change in Inventory Costing Method
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 assignment of certain pipeline services that AGLC
has under contract. AGLC will assign 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, the GPSC has approved AGLC's tariff provisions 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. In
management's opinion, the weighted-average inventory costing method
provides for a better matching of costs and revenue from the sale of
gas.
Because AGLC recovered all of its gas costs through a PGA mechanism
until October 6, 1998, there is no cumulative effect resulting from the
change in the inventory costing method.
5. Comprehensive Income
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No.130, "Reporting Comprehensive
Income" (SFAS 130) which establishes standards for the reporting and
display of comprehensive income and its components in the financial
statements. SFAS 130 is effective for fiscal years beginning after
December 15, 1997 and was adopted by AGL Resources in October 1998.
Comprehensive income includes net income and other comprehensive
income. SFAS 130 presently identifies only the following items as
components of other comprehensive income:
- foreign currency translation adjustment;
- minimum pension liability adjustment; and
- unrealized gains and losses on certain investments in debt and
equity securities classified as available-for-sale securities.
Because AGL Resources does not have any components of other
comprehensive income for any of the periods presented, there is no
difference between net income and comprehensive income and the adoption
of SFAS No. 130 has no impact on AGL Resources' consolidated financial
statements.
Page 10 of 27 Pages
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Forward-Looking Statements
Portions of the information contained in this Form 10-Q, particularly
in the Management's Discussion and Analysis of Results of Operations
and Financial Condition, 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 we intend that such
forward-looking statements be subject to the safe harbors created
thereby. Although we believe that our expectations are based on
reasonable assumptions, we can give no assurance that such expectations
will be achieved.
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;
- the impact of changes in state and federal legislation and
regulation on both the gas and electric industries;
- the effects and uncertanties of deregulation and competition,
particularly in markets where prices and providers historically
have been regulated;
- changes in accounting policies and practices; - interest rate
fluctuations and financial market condition; - uncertainties about
environmental issues; and - other factors discussed in the following
section: Year 2000
Readiness Disclosure - Forward-Looking Statements.
Nature of Our Business
AGL Resources Inc. is 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;
- AGL Energy Services, Inc., (AGLE) a gas supply services company;
and
- several nonutility subsidiaries.
AGLC conducts our primary business: the distribution of natural gas in
Georgia, including Atlanta, Athens, Augusta, Brunswick, Macon, Rome,
Savannah, and Valdosta. Chattanooga distributes natural gas in the
Chattanooga and Cleveland areas of Tennessee. The Georgia Public
Service Commission (GPSC) regulates AGLC, and the Tennessee Regulatory
Authority (TRA) regulates Chattanooga. AGLE is a nonregulated company
that buys and sells the natural gas which is supplied to AGLC's
customers during the transition period to full competition in Georgia.
AGLC comprises substantially all of AGL Resources' assets, revenues,
and earnings. When we discuss the operations and activities of AGLC,
AGLE, and Chattanooga, we refer to them, collectively, as the
"utility."
Page 11 of 27 Pages
AGL Resources also owns or has an interest in the following nonutility
businesses:
- AGL Interstate Pipeline Company, which owns a 50% interest in
Cumberland Pipeline Company; Cumberland Pipeline Company was
formed for the purpose of providing interstate pipeline services
to customers in Georgia and Tennessee;
- 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;
- SouthStar Energy Services LLC (SouthStar), a joint venture among
a subsidiary of AGL Resources and subsidiaries of Dynegy, Inc.
and Peidmont Natural Gas Company. 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 began marketing naturalgas
to all customers in Georgia during the first quarter of fiscal
1999;
- 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 Company, L.P. (Sonat Marketing); Sonat Marketing
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.
Results of Operations
In this section we compare the results of our operations for the
three-month periods ended December 31, 1998 and 1997.
Operating Margin Analysis
(Dollars in Millions)
Three Months Ended
12/31/98 12/31/97 Increase/(Decrease)
---------- ---------- ----------------------
Operating Revenues
Utility $ 317.2 $ 377.6 $ (60.4) (16.0%)
Non Utility 6.7 21.5 (14.8) (68.8%)
========== ========== ============
Total $ 323.9 $ 399.1 $ (75.2) (18.8%)
========== ========== ============
Cost of Sales
Utility $ 184.9 $ 236.6 $ (51.7) (21.9%)
Non Utility 2.1 17.4 (15.3) (87.9%)
========== ========== ============
Total $ 187.0 $ 254.0 $ (67.0) (26.4%)
========== ========== ============
Operating Margins
Utility $ 132.3 $ 141.0 $ (8.7) (6.2%)
Non Utility 4.6 4.1 0.5 12.2%
========== ========== ============
Total $ 136.9 $ 145.1 $ (8.2) (5.7%)
========== ========== ============
Page 12 of 27 Pages
Operating Revenues
Our operating revenues for the three months ended December 31, 1998
decreased to $323.9 million from $399.1 million for the same period
last year, a decrease of 18.8%.
Utility. Utility revenues decreased to $317.2 million for the three
months ended December 31, 1998 from $377.6 million for the same period
last year. The decrease of $60.4 million in utility revenues was
primarily due to the following factors:
- The utility's cost of gas decreased by $51.7 million. (See
discussion of the utility cost of sales below regarding the
effect of warmer weather and migration of customers to
marketers). Prior to deregulation, AGLC passed the actualcost of
gas through to its customers on a dollar for dollar basis under
the PGA mechanism contained in its rate schedule. Now that the
sale of gas by AGLC has been deregulated, AGLC intends to
continue to recover only its actual gas costs from its customers
within the parameters of the joint stipulation agreement of
January 26, 1999. The reduction in gas costs therefore results\
in a corresponding reduction in revenue.
- The utility's base revenue decreased by $4.8 million when
compared to last year primarily due to the new SFV rate
structure for AGLC delivery service that became effective
July 1, 1998. (See Note 2 to the Condensed Consolidated
Financial Statements)
- The Integrated Resource Plan (IRP) was phased out during fiscal
1998 and did not exist during the first quarter of fiscal year
1999, resulting in a $3.6 million decrease in revenue associated
with the plan. AGLC passed through to its customers, on a dollar
for dollar basis, IRP expenses incurred, which were included in
operating expenses. Therefore, the phase out of IRP had no effect
on net income .
Nonutility. Nonutility operating revenues decreased to $6.7 million for
the three months ended December 31, 1998 from $21.5 million for the
same period last year. The decrease of $14.8 million in nonutility
revenues was primarily due to the formation of SouthStar in July 1998.
Prior to the formation of SouthStar (including the first quarter of
fiscal year 1998) we had a wholly owned subsidiary which was engaged in
this same business. Upon the formation of SouthStar, the customers and
operations of this business unit became the customers and operations of
SouthStar. Since the formation of the joint venture, the results of our
interest in SouthStar have been accounted for under the equity method
and our portion of their results of operations is contained in Other
Income for the three months ended December 31, 1998.
Cost of Sales
Our cost of sales decreased to $187.0 million for the three months
ended December 31, 1998 from $254.0 million for the same period last
year, a decrease of 26.4%.
Utility. The utility's cost of sales decreased to $184.9 million for
the three months ended December 31, 1998 from $236.6 million for the
same period last year. The decrease of $51.7 million in the utility's
cost of sales was primarily due to the following factors:
- The utility sold less gas to its customers due to weather that was
44% warmer for the three months ended December 31, 1998 as compared
with the same period last year. This resulted in less volume of gas
sold as compared with last year.
- Beginning November 1, 1998, customers began to switch from AGLC to
certificated marketers for gas purchases. As a result, AGLC sold less
gas.
Page 13 of 27 Pages
Nonutility. Nonutility cost of sales decreased to $2.1 million for the
three months ended December 31, 1998 from $17.4 million for the same
period last year. The decrease of $15.3 million was primarily due to
the formation of SouthStar as described above under nonutility
operating revenues.
Operating Margin
Our operating margin decreased to $136.9 million for the three months
ended December 31, 1998 from $145.1 million for the same period last
year, a decrease of 5.7%.
Utility. The utility's operating margin decreased to $132.3 million for
the three months ended December 31, 1998 from $141.0 million for the
same period last year. The decrease of $8.7 million was primarily due
to the following factors as mentioned above under utility operating
revenues:
- The utility's base revenue decreased by $4.8 million when compared
with the same period last year primarily due to the new SFV rate
structure for AGLC delivery service that became effective on July
1, 1998.
- A $3.6 million decrease in revenue associated with the phase-out
of the IRP.
Nonutility. Operating margin for the nonutility business increased by
$0.5 million to $4.6 million for the three months ended December 31,
1998 as compared with $4.1 million for the same period last year. This
increase is primarily attributable to Utilipro, our customer care
subsidiary which was acquired during the first quarter of fiscal 1998.
Other Operating Expenses
Other operating expenses decreased slightly to $89.2 million for the
three months ended December 31, 1998 compared to $92.7 million for the
same period last year. The components of other operating expenses are
as follows (dollars in millions):
Three Months Ended
12/31/98 12/31/97 (Increase/(Decrease)
-------- -------- -------------------
Operations $53.1 $58.6 $(5.5) $(9.4%)
Maintenance 9.0 9.3 (0.3) (3.2%)
Depreciation &
Amortization 20.2 17.7 2.5 14.1%
Taxes Other than Income
Taxes 6.9 7.1 (0.2) (2.8%)
-------- -------- --------
Total $89.2 $92.7 $(3.5) (3.8%)
======== ======== ========
Operations expenses decreased primarily due to the phase out of the IRP
during fiscal 1998 which resulted in $3.6 million less expense than the
same period last year. AGLC passed through to its customers, on a
dollar for dollar basis, IRP expenses incurred. Therefore, the phase
out of IRP had no effect on net income .
Depreciation and amortization expenses increased primarily due to
increased depreciable property and increased depreciation rates for
AGLC ordered by the GPSC.
Page 14 of 27 Pages
Other Income/(Loss)
Other losses totaled $7.9 million for the three months ended December
31, 1998 compared with other income of $5.2 million for the same period
last year. The decrease in other income of $13.1 million is primarily
due to:
- Our portion of the loss recorded by Sonat Marketing, a joint
venture in which we own a 35% interest. The loss by Sonat
Marketing was the result of a combination of significantly warmer
weather than last year and charges recorded in December 1998
associated with changes in certain accounting estimates. We
recorded a pre-tax loss related to our interest in Sonat of
approximately $6.5 million for the three months ended December 31,
1998 as compared with pre-tax income of approximately $3.3 million
for the same period last year.
- Our portion of SouthStar's loss was approximately $1.4 million for
the three months ended December 31, 1998. SouthStar was not formed
until July 1998, therefore there was no income or loss for this
joint venture for the three months ended December 31, 1997.
Income Taxes
Income taxes decreased to $8.2 million for the three months ended
December 31, 1998 from $15.4 million for the same period last year. The
effective tax rate (income tax expense expressed as a percentage of
pretax income) for the three months ended December 31, 1998 was 34.0%
as compared to 37.5% for the same period last year. The reduction in
the effective income tax rate is primarily due to a reduction in tax
expense resulting from our Leveraged Employee Stock Ownership Plan.
Preferred Stock of Subsidiaries
Dividends on preferred stock decreased to $1.5 million for the three
months ended December 31, 1998 compared to $2.4 million for the same
period last year. This decrease is due to the redemption of $44.5
million of 7.70% preferred stock of AGLC on December 1, 1997.
Financial Condition
Our utility business is seasonal in nature which typically results in a
substantial increase in accounts receivable from customers from
September 30 to December 31 as a result of higher billings during
colder weather. The utility also uses gas stored underground to serve
its customers during periods of colder weather resulting in a
substantial decrease in gas inventories when comparing September 30
with December 31. Consequently, accounts receivable increased $92.9
million and inventory of gas stored underground decreased $31.7 million
during the quarter ended December 31, 1998. Accounts payable increased
$22.6 million during the quarter ended December 31, 1998, primarily due
to an increase in accounts payable to gas suppliers.
Our deferred PGA asset was $3.3 million as of December 31, 1998
compared to $33.1 million as of December 31, 1997. The PGA mechanism
and regulated rates ended on October 6, 1998 for natural gas commodity
sales to AGLC customers. Beginning in October 1998, AGLC priced
deregulated gas sales in a manner that more closely matched gas costs
and revenues. The deferred PGA asset that remains as of December 31,
1998 relates to Chattanooga.
We generally meet our liquidity requirements through our operating cash
flow and the issuance of short-term debt. We also use short-term debt
to meet our seasonal working capital requirements and to temporarily
fund capital expenditures. Lines of credit with various banks provide
for direct borrowings and are subject to annual renewal. Availability
under the current lines of credit varies from $230 million in the
summer to $260 million for peak winter financing.
Page 15 of 27 Pages
Short-term debt increased $36.5 million to $113.0 million as of
December 31, 1998, from $76.5 million as of September 30, 1998, to meet
our normal seasonal working capital requirements for the three months
ended December 31, 1998. Short-term debt decreased $37.5 when comparing
December 31, 1998 to December 31, 1997 due to less borrowing needs
during the first quarter of this year as compared to last year. We
generated operating cash flow of $3.0 million for the three months
ended December 31, 1998 as compared to $(29.9) million for the same
period last year. This increase in operating cash flow is primarily due
to the decrease in our deferred PGA asset as a result of AGLC designing
its prices for deregulated gas sales in a manner that more closely
matched gas costs and revenues for the three months ended December 31,
1998.
We believe available credit will be sufficient to meet our working
capital needs both on a short and a long-term basis. However, our
capital needs depend on many factors and we may seek additional
financing through debt or equity offerings in the private or public
markets at any time.
Capital Expenditures
Capital expenditures for construction of distribution facilities,
purchase of equipment, and other general improvements were $29.4
million for the three-month period ended December 31, 1998. Typically,
we provide funding for capital expenditures through a combination of
internal sources and the issuance of short-term debt.
Common Stock
During the three months ended December 31, 1998, we issued 211,379
shares of common stock 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 $3.7 million.
Ratios
As of December 31, 1998, our capitalization ratios consisted of:
- 47.4% long-term debt;
- 5.3% preferred securities; and
- 47.3% common equity.
State Regulatory Activity
Deregulation
The 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 and 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 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.
Page 16 of 27 Pages
Going forward, AGLC intends to price 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 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.
The 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.
As of December 31, 1998, more than 168,000 residential and small
commercial customers had elected to purchase natural gas services from
one of the 11 active approved marketers in Georgia. As of February 5,
1999, more than 367,000 residential and small commercial customers had
elected to purchase natural gas services from those same marketers.
Commodity Sales Service Rate Issues
Pursuant to the Deregulation Act, regulated rates for natural gas
commodity sales service to AGLC customers (as opposed to delivery
service rates discussed above) ended on October 6, 1998. In the
deregulated environment, AGLC intended to price deregulated gas sales
in a manner that, at a minimum, would have allowed it to recover its
annual gas costs.
On January 5, 1999, the GPSC issued a Procedural and Scheduling Order
for the purpose of hearing evidence to consider whether unregulated
prices charged by AGLC for gas sales services subsequent to October 6,
1998 were constrained by market forces. The GPSC initiated the
proceeding in response to numerous complaints from customers who
received gas sales service from AGLC in November and December 1998.
Those complaints stemmed primarily from the effects of record warm
weather on November and December bills that, in many cases, reflected
higher fixed costs associated with gas sales and lower gas usage than
historical comparisons.
AGLC's gas sales rates were designed to enable the Company to recover
its fixed costs associated with gas sales from the customers for whom
the costs were incurred. AGLC intended to bill much of those fixed
costs during the winter, when consumption is typically higher, and
fewer of those fixed costs in the summer, when consumption is typically
lower. Under normal weather conditions, this billing approach would
have produced monthly bills in amounts similar to bills of
corresponding months in recent years. However, unseasonably warm
weather resulted in fixed costs comprising a higher percentage of
customers' bills due to lower gas usage by many customers in November
and December.
Page 17 of 27 Pages
On January 26, 1999, AGLC entered into a joint stipulation with the
GPSC to resolve certain gas sales service issues. Among other
requirements in the stipulation, the Company has implemented a new rate
structure for gas sales, beginning with February 1999 bills, that more
closely reflects customers' actual gas usage which includes a demand
charge for fixed costs associated with gas sales that is entirely
volumetric. The new rate structure for gas sales service is intended to
ensure AGLC's recovery of its purchased gas costs incurred from October
6, 1998 to September 30, 1999 as accurately as possible without
creating any significant income or loss. The joint stipulation
agreement provides for a true-up of gas costs and revenues for fiscal
1999 for any amounts over or under a relatively small adjustable dead
band. To the extent that such overage or underage exceeds the
applicable dead band, AGLC will either refund to or collect from its
customers the applicable overage or underage that exists on September
30, 1999.
As part of the joint stipulation, AGLC also agreed to issue checks to
customers or credits to customer bills in the total amount of
approximately $14.7 million to lessen the effects of the Company's
earlier rate methodology. Of that amount, $8.2 million will be refunded
to AGLC customers based on the over-collection of gas costs during
fiscal 1998 before deregulation began and as reported in our balance
sheet as of December 31, 1998. The remaining $6.5 million will be
allocated during the second quarter to certain AGLC customers who were
most adversely affected by the change in AGLC's rate structure for gas
sales service.
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 mechanism of
AGLC's rate schedules. Accordingly, the hedging program did not affect
our earnings.
During the first quarter of fiscal 1999, AGLC entered into certain
hedge agreements that will continue until the end of February 1999.
However, as part of the joint stipulation with the GPSC entered into in
January 1999 to resolve certain gas sales service issues, AGLC will not
participate in hedging activities for the remainder of the fiscal year
and all costs incurred for the fixed-price option agreements prior to
the date of the joint stipulation will be included in gas costs which
will be recovered from AGLC's customers.
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.
During the three months ended December 31, 1998, AGLC spent
approximately $5.4 million related to the pipeline replacement program.
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 below in the section entitled "Environmental
Matters".
Page 18 of 27 Pages
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 second way
we can recover costs is by exercising the legal rights we believe we
have to recover a share of our costs from other potentially responsible
parties - typically former owners or operators of the MGP sites.
Previously we also recovered costs by exercising legal rights we
believed we had to recover a share of our costs from various insurance
companies. We settled our final insurance company claim in January
1999.
Federal Regulatory Activity
Information related to federal regulatory activity is contained in our
Form 10-K for the year ended September 30, 1998 under the caption
"Federal Regulatory Matters".
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 is 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.
We currently estimate that our total future cost of investigating and
cleaning up our MGP sites is between $47.0 million and $81.3 million.
Within that range, we cannot identify a single number as the "best"
estimate. We therefore have recorded the lower value, or $47.0 million,
as a liability as of December 31, 1998. We are in the process of
reviewing our estimates of the cost of investigation and clean up of
our MGP sites. We believe that the estimates will increase. At the
present time, however, we do not have sufficient information to
estimate the magnitude of that increase with a reasonable degree of
certainty.
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. On December 3,
1997, the GPSC issued a Rule Nisi ordering AGLC to show cause why the
GPSC should not take certain actions with respect to the rider.
Following hearings, the GPSC Staff and AGLC entered into a settlement
agreement on December 3, 1998, resolving the outstanding issues in the
Rule Nisi. On January 6, 1999, the GPSC issued an order approving the
settlement. The settlement is not expected to have a material effect on
the recovery of costs under the rider.
Page 19 of 27 Pages
The second way we can recover costs is by exercising the legal rights
we believe we have to recover a share of our costs from other
potentially responsible parties - typically former owners or operators
of the MGP sites. Previously we also recovered costs by exercising
legal rights we believed we had to recover a share of our costs from
various insurance companies. We have been actively pursuing those
recoveries. We settled our final insurance company claim in January
1999. For the quarter ended December 31, 1998, we recovered $4.3
million from other potentially responsible parties and insurance
companies. As required by the rider, we retained $2.2 million of that
amount, and we credited the balance to our customers.
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 a schedule that management
believes will achieve Year 2000 readiness.
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
- key business partners (customers and suppliers).
Page 20 of 27 Pages
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. Sonat Power Services, L.P., and Sonat Marketing, 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
SouthStar, and of Utilipro, Inc., a recently acquired subsidiary. With
respect to SouthStar, we have completed the assessment phase and are
beginning remediation planning. Management expects SouthStar's business
and operations to achieve Year 2000 readiness. The Year 2000 initiative
recently commenced with respect to Utilipro, Inc., and management
expects 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;
- nine systems are in testing to verify Year 2000
readiness;
- three systems, including one critical system, are in
remediation for purposes of correcting noncompliant Year 2000
code;
- three systems have been eliminated;
- five systems have been replaced, and
- 30 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 April 30, 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.
Page 21 of 27 Pages
We expect to complete remediation planning for critical non-IT assets
by March 15, 1999. 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. That group of customers includes customers
whom we consider key business partners as well as other selected
customers. To date, we have not received responses from most of those
customers. Our first step in the process of following up with those key
customers who did not respond by January 1, 1999, was to categorize
those customers based on the amount of gas used and the revenue
generated by each of them. We have completed the categorizing process
and are about to begin following up by fax or telephone with key
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 December 31, 1998, our cumulative expenses in
connection with our Year 2000 assessment, remediation planning, and
plan implementation processes were approximately $ 3.8 million. Through
December 31, 1998, we had spent an additional $7.4 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 have capitalized 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. It does not
include costs associated with employees of other departments such as
Legal and Internal Audit, and of other business units, who are
involved, on a limited basis, in the Year 2000 initiative. Nor does the
estimate include our potential share of Year 2000 costs that may be
incurred by partnerships and joint ventures, other than Southstar, in
which we participate. 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
Page 22 of 27 Pages
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 December 31, 1998, AGLC
had deferred total costs of approximately $2 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 finalizing 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 analyses; and - reviewing
experts' views of factors likely to contribute to such a
scenario.
To date, we have identified our core business processes. We have also
completed the majority of our Year 2000 business impact analyses for
the core business processes. We are in the process of finalizing our
contingency planning assumptions, including our most reasonably likely
worst case scenarios.
Although we are finalizing our most reasonably likely worst case
scenarios and our contingency planning assumptions, the contingency
planning process and the process of refining our most reasonably likely
worst case scenarios will be ongoing processes, requiring continuing
development and modification 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.
Page 23 of 27 Pages
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 24 of 27 Pages
ITEM 3. 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.
Interest Rate Risk
AGL Resources' exposure to market risk related to changes in interest
rates relates primarily to its borrowing activities. A hypothetical 10%
increase or decrease in interest rates related to AGL Resources
variable rate debt ($113.0 million as of December 31, 1998) would not
have a material effect on our results of operations or financial
condition over the next year. The fair value of AGL Resources'
long-term debt and capital securities are also affected by changes in
interest rates. The carrying value of AGL Resources' long-term debt and
capital securities has been the same for the past two years. A
hypothetical 10% increase or decrease in interest rates would not have
a material effect on the estimated fair value of our long-term debt or
capital securities. Additionally, the fair value of our long-term debt
and capital securities has not materially changed since September 30,
1998.
Page 25 of 27 Pages
PART II -- OTHER INFORMATION
"Part II -- Other Information" is intended to supplement information
contained in the Annual Report on Form 10-K for the fiscal year ended
September 30, 1998, and should be read in conjunction therewith.
ITEM 1. LEGAL PROCEEDINGS
With regard to legal proceedings, AGL Resources is a party, as both
plaintiff and defendant, to a number of 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 5. OTHER INFORMATION
Information related to State Regulatory Activity, Federal Regulatory
Activity, and Environmental matters is contained in Item 2 of Part I under
the caption "Management's Discussion and Analysis of Results of Operations
and Financial Condition."
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
3 Bylaws, as amended and restated on January 15, 1999.
10.1 Seventh Amendment to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990.
10.2 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 (Exhibits 10.30; 10.32 and 10.33,
respectively, AGL Resources Inc. Form 10-K for the
fiscal year ended September 30, 1998).
18 Independent Auditor's preferability letter concerning a
change in accounting method.
27 Financial Data Schedule.
(b) Reports on Form 8-K.
There were no reports on Form 8-K filed during the quarterly
period ended December 31, 1998.
Page 26 of 27 Pages
SIGNATURES
Pursuant to the requirements 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.
AGL Resources Inc.
(Registrant)
Date February 15, 1999 /s/ J Michael Riley
J. Michael Riley
Senior Vice President and Chief Financial
Officer
(Principal Accounting and Financial Officer)
Page 27 of 27 Pages