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 MARCH 31, 1999
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 March 31, 1999.
Common Stock, $5.00 Par Value
Shares Outstanding at March 31, 1999 ................................57,683,727
<PAGE>
AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended March 31, 1999
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 14
3 Quantitative and Qualitative Disclosure About Market Risk 37
PART II -- OTHER INFORMATION
1 Legal Proceedings 38
4 Submission of Matters to a Vote of Security Holders 38
5 Other Information 38
6 Exhibits and Reports on Form 8-K 39
SIGNATURES 40
Page 2 of 40 Pages
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PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS
FOR THE THREE MONTHS AND SIX MONTHS ENDED
MARCH 31, 1999 AND 1998
(MILLIONS, EXCEPT PER SHARE DATA)
(UNAUDITED)
Three Months Six Months
1999 1998 1999 1998
------------------- -----------------
Operating Revenues $ 375.1 $ 479.7 $ 699.0 $ 878.8
Cost of Gas 232.0 305.7 419.0 559.7
- -------------------------------------------------------------------------------
Operating Margin 143.1 174.0 280.0 319.1
Other Operating Expenses 90.7 90.7 179.9 183.4
- -------------------------------------------------------------------------------
Operating Income 52.4 83.3 100.1 135.7
Other Income (Loss) (0.2) 2.9 (8.1) 8.1
- -------------------------------------------------------------------------------
Income Before Interest and
Income Taxes 52.2 86.2 92.0 143.8
Interest Expense and Preferred
Stock Dividends
Interest expense 13.6 14.1 27.8 28.2
Dividends on preferred stock
of subsidiaries 1.6 1.2 3.1 3.6
- -------------------------------------------------------------------------------
Total interest expense and
preferred stock dividends 15.2 15.3 30.9 31.8
- -------------------------------------------------------------------------------
Income Before Income Taxes 37.0 70.9 61.1 112.0
Income Taxes 12.8 25.8 21.0 41.2
- -------------------------------------------------------------------------------
Net Income $ 24.2 $ 45.1 $ 40.1 $ 70.8
===============================================================================
Earnings per Common Share
Basic $ 0.42 $ 0.79 $ 0.70 $ 1.25
Diluted $ 0.42 $ 0.79 $ 0.70 $ 1.24
Weighted Average Number of Common
Shares Outstanding
Basic 57.6 56.9 57.5 56.8
Diluted 57.6 57.0 57.7 56.9
Cash Dividends Paid Per Share of
Common Stock $ 0.27 $ 0.27 $ 0.54 $ 0.54
See notes to condensed consolidated financial statements.
Page 3 of 40 Pages
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
March 31, September 30,
----------------------- -------------
ASSETS 1999 1998 1998
- --------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ 6.9 $ - $ 0.9
Receivables (less allowance for
uncollectible accounts of $6.9
at March 31, 1999, $7.5 at
March 31, 1998, and $4.1 at
September 30, 1998) 186.7 202.1 121.7
Inventories
Natural gas stored underground 45.8 29.2 138.1
Liquefied natural gas 9.7 14.7 17.7
Other 12.4 11.8 14.6
Deferred purchased gas adjustment - 18.1 3.5
Other 1.3 1.2 1.9
- --------------------------------------------------------------------------------
Total current assets 262.8 277.1 298.4
- --------------------------------------------------------------------------------
Property, Plant and Equipment
Utility plant 2,174.0 2,109.9 2,133.5
Less: accumulated depreciation 708.5 673.5 680.9
- --------------------------------------------------------------------------------
Utility plant - net 1,465.5 1,436.4 1,452.6
- --------------------------------------------------------------------------------
Nonutility property 119.3 111.4 105.6
Less: accumulated depreciation 29.9 32.2 24.6
- --------------------------------------------------------------------------------
Nonutility property - net 89.4 79.2 81.0
- --------------------------------------------------------------------------------
Total property, plant and
equipment - net 1,554.9 1,515.6 1,533.6
- --------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental
response costs 141.2 69.7 77.6
Investments in joint ventures 38.1 43.2 46.7
Other 33.9 40.8 29.0
- --------------------------------------------------------------------------------
Total deferred debits
and other assets 213.2 153.7 153.3
- --------------------------------------------------------------------------------
Total Assets $2,030.9 $1,946.4 $ 1,985.3
================================================================================
See notes to condensed consolidated financial statements.
Page 4 of 40 Pages
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
March 31, September 30,
--------------------- -------------
LIABILITIES AND CAPITALIZATION 1999 1998 1998
- --------------------------------------------------------------------------------
Current Liabilities
Accounts payable $ 43.3 $ 69.5 $ 48.4
Short-term debt 1.5 4.4 76.5
Customer deposits 24.3 31.9 30.5
Accrued interest 30.0 28.7 32.8
Taxes 9.2 39.7 10.1
Deferred purchased gas adjustment 2.4 0.2 12.4
Gas cost credits 36.4 - -
Other 77.8 35.6 42.8
- --------------------------------------------------------------------------------
Total current liabilities 224.9 210.0 253.5
- --------------------------------------------------------------------------------
Accumulated Deferred Income Taxes 207.3 191.7 203.0
- --------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs 104.3 47.0 47.0
Accrued postretirement benefits costs 34.8 34.5 33.4
Deferred credits 53.5 59.7 57.8
Other 1.6 0.5 2.1
- --------------------------------------------------------------------------------
Total long-term liabilities 194.2 141.7 140.3
- --------------------------------------------------------------------------------
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 57.7 at
March 31, 1999, 57.0 at March 31,
1998, and 57.3 at Sept. 30, 1998 670.2 668.7 654.2
- --------------------------------------------------------------------------------
Total capitalization 1,404.5 1,403.0 1,388.5
- --------------------------------------------------------------------------------
Total Liabilities and Capitalization $2,030.9 $1,946.4 $ 1,985.3
================================================================================
See notes to condensed consolidated financial statements.
Page 5 of 40 Pages
<PAGE>
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED MARCH 31, 1999 AND 1998
(MILLIONS)
(UNAUDITED)
Six Months
-----------------------
1999 1998
- --------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 40.1 $ 70.8
Adjustments to reconcile net income to net
cash flow from operating activities
Depreciation and amortization 41.4 36.9
Deferred income taxes 4.3 (2.1)
Other (0.7) 0.1
Changes in certain assets and liabilities 80.7 46.2
- --------------------------------------------------------------------------------
Net cash flow from operating
activities 165.8 151.9
- --------------------------------------------------------------------------------
Cash Flows from Financing Activities
Short-term borrowings, net (75.0) (25.1)
Sale of common stock, net of expenses 1.9 0.3
Redemption of preferred securities - (44.5)
Dividends paid on common stock (26.0) (27.2)
- --------------------------------------------------------------------------------
Net cash flow from financing
activities (99.1) (96.5)
- --------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures (52.4) (48.1)
Non-utility property expenditures (9.4) (7.9)
Investment in joint ventures - (3.6)
Cash received from joint ventures - 0.3
Other 1.1 (0.9)
- --------------------------------------------------------------------------------
Net cash flow from investing
activities (60.7) (60.2)
- --------------------------------------------------------------------------------
Net increase (decrease) in cash
and cash equivalents 6.0 (4.8)
Cash and cash equivalents at
beginning of period 0.9 4.8
- --------------------------------------------------------------------------------
Cash and cash equivalents at
end of period $ 6.9 $ -
================================================================================
Cash paid during the period for
Interest $ 31.0 $ 29.1
Income taxes $ 11.8 $ 18.6
See notes to condensed consolidated financial statements.
Page 6 of 40 Pages
<PAGE>
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 both natural gas
local distribution utilities. Additionally, AGL Resources Inc. owns several
non-utility subsidiaries and has interests in several non-utility joint
ventures. We collectively refer to AGL Resources Inc. and its subsidiaries as
"AGL Resources" or the "Company." 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 the three-month and six-month
periods 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 reported 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 legislation
in Georgia, AGLC will fully unbundle, or separate, the various components of its
services to its customers effective October 1, 1999. Beginning on that date,
AGLC will continue to provide delivery service to utility customers in Georgia,
but will exit the natural gas sales service function. As a result, numerous
changes have occurred with respect to the delivery and sales 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 40 Pages
<PAGE>
2. IMPACT OF NEW REGULATORY RATE STRUCTURE AND DEREGULATION (CONTINUED)
REGULATORY RATE STRUCTURE FOR DELIVERY SERVICE
Since 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 service.
Prior to July 1, 1998, rates to provide delivery service were based principally
on the amount of gas customers used. Therefore, revenue from delivery rates was
typically lower in the summer when customers used less gas, and higher in the
winter when customers used more gas. Beginning July 1, 1998, AGLC began
collecting such revenue 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.
Although there is a shift of utility delivery service revenues among quarters,
under the new rate design, the utility's annual delivery service revenue stream
remains the same.
RATE STRUCTURE FOR SALES SERVICE
Pursuant to legislation in Georgia, regulated rates for natural gas 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 Georgia Public Service Commission (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 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 it 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 agreement with the
GPSC to resolve certain gas sales service issues. Among other requirements in
the stipulation, AGLC has implemented a new rate structure for gas sales,
beginning with February 1999 bills, that more closely reflects customers' actual
gas usage and 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 revenues from gas sales to gas costs during fiscal 1999 for any
profit or loss outside of a specified range. The allowed maximum profit is $1.0
million and the maximum risk of loss is $3.25 million. As of March 31, 1999, the
Company has received revenues in excess of costs of $37.4 million. As of
Page 8 of 40 Pages
<PAGE>
2. IMPACT OF NEW REGULATORY RATE STRUCTURE AND DEREGULATION (CONTINUED)
March 31, 1999, the Company has recognized profits of $1.0 million and has
recorded a liability of $36.4 million under the caption "Gas cost credits" on
the Condensed Consolidated Balance Sheet.
As part of the joint stipulation agreement, AGLC also agreed to issue checks to
customers or credits to customer bills in the total amount of approximately
$14.8 million to lessen the effects of the Company's earlier rate methodology.
Of that amount, $8.1 million was refunded to AGLC customers based on the
over-collection of gas costs during fiscal 1998 before deregulation began and
was recorded on our balance sheet as of December 31, 1998. The remaining $6.7
million was 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 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.
Page 9 of 40 Pages
<PAGE>
2. IMPACT OF NEW REGULATORY RATE STRUCTURE AND DEREGULATION (CONTINUED)
Pursuant to legislation in Georgia, 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 and six months ended March 31, 1999 (in
millions):
3 Months 6 Months
Ended Ended
3/31/99 3/31/99
-------- --------
Operating Revenues
Nonregulated $ 220.1 $ 393.9
Regulated ... 144.6 288.0
-------- --------
Total Utility $ 364.7 $ 681.9
======== ========
Cost of Gas
Nonregulated $ 213.5 $ 386.2
Regulated ... 15.0 27.2
-------- --------
Total Utility $ 228.5 $ 413.4
======== ========
Operating Margins
Nonregulated $ 6.6 $ 7.7
Regulated ... 129.6 260.8
-------- --------
Total Utility $ 136.2 $ 268.5
======== ========
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
2,199,643 and 30,321 shares of common stock were outstanding as of March 31,
1999 and 1998, 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 and six months ended March 31, 1999, we issued 160,254
and 371,633 shares of common stock, respectively, 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 $3.2 million and $6.9 million for the three-month and
six-month periods ended March 31, 1999, respectively.
Page 10 of 40 Pages
<PAGE>
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 Purchase Gas Adjustment
(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 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 130 had no impact on AGL
Resources' consolidated financial statements.
6. JOINT VENTURES
In August 1995, the Company, through a subsidiary, invested $32.6 million for a
35% ownership interest in Sonat Marketing Company, L.P. (Sonat Marketing), a
joint venture with a subsidiary of Sonat Inc. (Sonat). Under the joint venture
agreement with Sonat, the Company has the right to require Sonat to repurchase
its 35% interest in Sonat Marketing at a price equal to the greater of (i) the
fair market value of the 35% interest or (ii) $32 million, plus interest (not to
exceed $5 million) at a nominal rate, less the amount of certain distributions
made by the joint venture to the Company.
Page 11 of 40 Pages
<PAGE>
6. JOINT VENTURES (CONTINUED)
The Company also owns a 35% interest in Sonat Power Marketing, L.P., another
joint venture with Sonat. Pursuant to the Sonat Power Marketing joint venture
agreement, Sonat has the right to purchase the Company's entire interest in
Sonat Power Marketing in the event the Company exercises its right to require
Sonat to purchase its interest in Sonat Marketing. If Sonat exercises this
right, it is required to pay the Company the fair market value of its interest
in Sonat Power Marketing.
The Company has exercised its right to require Sonat to purchase its 35%
interest in Sonat Marketing. Additionally, Sonat has exercised its right to
require the Company to sell its 35% interest in Sonat Power Marketing.
7. 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 (EPD) 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 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 the above process, we currently estimate that our total future cost of
investigating and cleaning up our MGP sites is between $104.3 million and $150.1
million. That range does not include other potential expenses, such as
unasserted property damage claims or legal expenses for which we may be held
liable but for which neither the existence nor the amount of such liabilities
can be reasonably forecast. Within that range, we cannot identify any single
number as a "better" estimate of our likely future costs. Consequently, we have
recorded the lower end of the range, or $104.3 million, as a liability as of
March 31, 1999. We do not believe that any single number within the range
constitutes a "better" estimate because our actual future investigation and
cleanup costs will be affected by a number of contingencies that cannot be
quantified at this time. The cost estimate has increased from the estimate as of
December 31, 1998, primarily due to (i) more complete information, obtained from
actual on-site clean-up experience and from further investigation at various
sites, concerning the amount of contamination present at various sites and (ii)
increased experience with EPD and, as a result of such experience, enhanced
knowledge of the types of clean-up EPD is likely to find acceptable at each of
the sites.
Page 12 of 40 Pages
<PAGE>
7. ENVIRONMENTAL MATTERS (CONTINUED)
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.
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. We have been
actively pursuing those recoveries. There were no material recoveries during the
quarter ended March 31, 1999.
Page 13 of 40 Pages
<PAGE>
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 uncertainties 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 conditions;
- 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 natural gas local
distribution utilities;
- AGL Energy Services, Inc., (AGLE) a gas supply services company; and
Several non-utility 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 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 14 of 40 Pages
<PAGE>
AGL Resources (AGLR) also owns or has an interest in the following non-utility
businesses:
- SouthStar Energy Services LLC (SouthStar), a joint venture among a
subsidiary of AGL Resources and subsidiaries of Dynegy, Inc. and Piedmont
Natural Gas Company. SouthStar markets natural gas, propane, fuel oil,
electricity, and related services to industrial, commercial, and
residential customers in Georgia and the Southeast. SouthStar began
marketing natural gas to all customers in Georgia during the first quarter
of fiscal 1999;
- AGL Investments, Inc., which was established to develop and manage certain
non-utility 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 (For information regarding the current
status of this joint venture interest, see Note 6, Joint Ventures, to
the Condensed Consolidated Financial Statements);
- 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 (For information regarding the current status of this
joint venture interest, see Note 6, Joint Ventures, to the Condensed
Consolidated Financial Statements);
- 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;
- Utilipro, Inc., which engages in the sale of integrated customer care
solutions to energy marketers;
- 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; and,
- AGL Interstate Pipeline Company, which owns a 50% interest in Cumberland
Pipeline Company; Cumberland Pipeline Company was formed for the purpose of
owning a new interstate pipeline, known as the Cumberland Pipeline Project,
which was intended to provide interstate pipeline services to customers in
Georgia and Tennessee. In April 1999, AGLC reached a decision not to
proceed with the conversion of certain parts of its distribution system
into the Cumberland Pipeline Project. As a result, the Cumberland Pipeline
Project is not expected to proceed in the foreseeable future.
Page 15 of 40 Pages
<PAGE>
RESULTS OF OPERATIONS
THREE-MONTH PERIODS ENDED MARCH 31, 1999 AND 1998
In this section we compare the results of our operations for the three-month
periods ended March 31, 1999 and 1998.
OPERATING MARGIN ANALYSIS
(Dollars in Millions)
THREE MONTHS ENDED
3/31/99 3/31/98 Increase/(Decrease)
-------- -------- ----------------------
Operating Revenues
Utility .............. $ 364.7 $ 457.7 $ (93.0) (20.3%)
Non-utility .......... 10.4 22.0 (11.6) (52.7%)
-------- -------- --------- -------
Total ................ $ 375.1 $ 479.7 $ (104.6) (21.8%)
======== ======== ========= =======
Cost of Gas
Utility .............. $ 228.5 $ 290.0 $ (61.5) (21.2%)
Non-utility .......... 3.5 15.7 (12.2) (77.7%)
-------- -------- --------- -------
Total ................ $ 232.0 $ 305.7 $ (73.7) (24.1%)
======== ======== ========= =======
Operating Margins
Utility .............. $ 136.2 $ 167.7 $ (31.5) (18.8%)
Non-utility .......... 6.9 6.3 0.6 9.5%
-------- -------- --------- -------
Total ................ $ 143.1 $ 174.0 $ (30.9) (17.8%)
======== ======== ========= =======
OPERATING REVENUES
Our operating revenues for the three months ended March 31, 1999 decreased to
$375.1 million from $479.7 million for the same period last year, a decrease of
21.8%.
UTILITY. Utility revenues decreased to $364.7 million for the three months ended
March 31, 1999 from $457.7 million for the same period last year. The decrease
of $93.0 million in utility revenues was primarily due to the following factors:
- A decline in the utility's sales service revenues and a comparable decline
in the utility's recovery of gas costs of $51.7 million (See discussion on
the utility's cost of gas below regarding the effects of warmer weather and
the migration of customers to marketer's.) AGLC recovers only its actual
gas costs from its customers within the parameters of the January 26, 1999
joint stipulation agreement with the GPSC. The reduction in gas costs
therefore results in a corresponding reduction in revenue, but does not
affect net income.
- A decline in the utility's delivery service revenue of $27.5 million when
compared to last year was primarily due to the new SFV rate structure for
AGLC delivery service that became effective July 1, 1998. (See Note 2,
Impact of New Regulatory Rate Structure and Deregulation, to the Condensed
Consolidated Financial Statements.)
- The January 26, 1999 joint stipulation agreement with the GPSC required
AGLC to issue checks to customers or credits to customer bills in the
amount of $14.8 million. Of that amount, $8.1 million was related to the
over-collection of gas costs during fiscal year 1998 before deregulation
began and
Page 16 of 40 pages
<PAGE>
was recorded on our balance sheet as of December 31, 1998. The remaining
$6.7 million was allocated during the second quarter to certain AGLC
customers and recorded as a decrease in revenue.
- The Integrated Resource Plan (IRP) was phased out during fiscal 1998 and
did not exist in the second quarter of fiscal year 1999, resulting in a
$1.7 million decrease in revenue associated with the plan. Previously, 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.
NON-UTILITY. Non-utility operating revenues decreased to $10.4 million for the
three months ended March 31, 1999 from $22.0 million for the same period last
year. The decrease of $11.6 million in non-utility revenues was primarily due to
the formation of the SouthStar joint venture in July 1998. Prior to the
formation of SouthStar (including the second quarter of fiscal year 1998), we
had a wholly owned subsidiary, which was engaged in the same business. Upon the
formation of SouthStar, the customers and operations of the former subsidiary
became the customers and operations of SouthStar. The results of the former
subsidiary were reported on a consolidated basis and, in contrast, the results
of our joint venture interest in SouthStar are accounted for under the equity
method. Our portion of SouthStar's results of operations is contained in Other
Income/(Loss) on the Condensed Consolidated Income Statement for the three
months ended March 31, 1999.
COST OF GAS
Our cost of gas decreased to $232.0 million for the three months ended March 31,
1999 from $305.7 million for the same period last year, a decrease of 24.1%.
UTILITY. The utility's cost of gas decreased to $228.5 million for the three
months ended March 31, 1999 from $290.0 million for the same period last year.
The decrease of $61.5 million in the utility's cost of gas was primarily due to
the following factors:
- Beginning November 1, 1998, customers began to switch from AGLC to
certificated marketers for gas purchases. As of March 31, 1999,
approximately 600,000 customers (41% of AGLC's total customers) had
switched from AGLC. As a result, AGLC sold less gas.
- The utility sold less gas to its customers due to weather that was 10%
warmer for the three months ended March 31, 1999 as compared with the same
period last year. This resulted in less volume of gas sold as compared with
last year.
NON-UTILITY. Non-utility cost of gas decreased to $3.5 million for the three
months ended March 31, 1999 from $15.7 million for the same period last year.
The decrease of $12.2 million was primarily due to the change from consolidation
to the equity method for SouthStar as described above under non-utility
operating revenues.
Page 17 of 40 Pages
<PAGE>
OPERATING MARGIN
Our operating margin decreased to $143.1 million for the three months ended
March 31, 1999 from $174.0 million for the same period last year, a decrease of
17.8%.
The utility's operating margin decreased to $136.2 million for the three months
ended March 31, 1999 from $167.7 million for the same period last year. The
decrease of $31.5 million was due primarily to the following factors as
mentioned above under utility operating revenues:
- The utility's delivery service revenue decreased by $27.5 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.
- The pace at which AGLC customers have switched to certificated marketers
for gas purchases. As of March 31, 1999, approximately 600,000 customers
(41% of AGLC's total customers) had switched from AGLC. As customers switch
to marketers, AGLC no longer bills those customers for ancillary services
and transition costs. As a result, operating margin decreased approximately
$2.4 million.
- A $1.7 million decrease in revenue associated with the phase-out of the
IRP.
OTHER OPERATING EXPENSES
Overall, other operating expenses remained the same for the three months ended
March 31, 1999 as compared with the same period last year. The components of
other operating expenses are as follows (dollars in millions):
THREE MONTHS ENDED
3/31/99 3/31/98 Increase/(Decrease)
------- ------- ------------------
Operations
Utility ....................... $ 40.4 $ 38.1 $ 2.3 6.0%
Non-utility ................... 14.1 17.4 (3.3) (19.0%)
------- ------- ------- -------
Total ......................... $ 54.5 $ 55.5 $ (1.0) (1.8%)
======= ======= ======= =======
Maintenance
Utility ....................... $ 7.1 $ 8.2 $ (1.1) (13.4%)
Non-utility ................... 2.0 1.6 0.4 25.0%
------- ------- ------- -------
Total ......................... $ 9.1 $ 9.8 $ (0.7) (7.1%)
======= ======= ======= =======
Depreciation & Amortization
Utility ....................... $ 16.9 $ 15.9 $ 1.0 6.3%
Non-utility ................... 2.8 1.9 0.9 47.4%
------- ------- ------- -------
Total ......................... $ 19.7 $ 17.8 $ 1.9 10.7%
======= ======= ======= =======
Taxes Other Than Income Taxes
Utility ....................... $ 6.5 $ 6.6 $ (0.1) (1.5%)
Non-utility ................... 0.9 1.0 (0.1) (10.0%)
------- ------- ------- -------
Total ......................... $ 7.4 $ 7.6 $ (0.2) (2.6%)
======= ======= ======= =======
Total Other Operating Expenses
Utility ....................... $ 70.9 $ 68.8 $ 2.1 3.1%
Non-utility ................... 19.8 21.9 (2.1) (9.6%)
------- ------- ------- -------
Total ......................... $ 90.7 $ 90.7 $ (0.0) (0.0%)
======= ======= ======= =======
Page 18 of 40 Pages
<PAGE>
UTILITY. Utility operation expenses increased $2.3 million as compared with the
same period last year primarily due to increased demand for customer service
associated with the more rapid than expected pace of customer migration.
Additionally, utility depreciation and amortization expenses increased primarily
due to increased depreciable property and increased depreciation rates for AGLC
ordered by the GPSC.
NON-UTILITY. Non-utility operation expenses decreased by approximately $3.3
million due to the change from consolidation to the equity method for SouthStar
as discussed above under non-utility operating revenue.
OTHER INCOME/(LOSS)
Other losses totaled $0.2 million for the three months ended March 31, 1999
compared with other income of $2.9 million for the same period last year. The
decrease in other income of $3.1 million is primarily due to:
- Our portion of the loss for Sonat Marketing, a joint venture in which we
own a 35% interest. We incurred a pre-tax loss related to our interest in
Sonat Marketing of approximately $2.0 million for the three months ended
March 31, 1999 versus $1.0 million in income for the same period in 1998.
- Our portion of SouthStar's loss was approximately $1.9 million for the
three months ended March 31, 1999. SouthStar was not formed until July
1998, and there was no income or loss for this joint venture for the three
months ended March 31, 1998.
- PGA carrying costs decreased $1.1 million due to the deregulation of the
PGA for the three months ended March 31, 1999 compared with the same period
last year.
- Our portion of the income for Sonat Power Marketing, a joint venture in
which we own a 35% interest. We had pre-tax income related to our interest
in Sonat Power Marketing of approximately $3.0 million for the three months
ended March 31, 1999 as compared to $0.5 million in income for the same
period last year.
INCOME TAXES
Income taxes decreased to $12.8 million for the three months ended March 31,
1999 from $25.8 million for the same period last year. The decrease in income
taxes of $13.0 million was due primarily to the decrease in income before income
taxes 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 March 31,
1999 was 34.6% as compared to 36.4% for the same period last year. The decrease
in the effective tax rate was due primarily to a reduction in tax reserves
related to the favorable resolution of certain outstanding tax issues.
Page 19 of 40 Pages
<PAGE>
SIX-MONTH PERIODS ENDED MARCH 31, 1999 AND 1998
In this section we compare the results of our operations for the six-month
periods ended March 31, 1999 and 1998.
OPERATING MARGIN ANALYSIS
(Dollars in Millions)
SIX MONTHS ENDED
3/31/99 3/31/98 Increase/(Decrease)
-------- -------- ----------------------
Operating Revenues
Utility .............. $ 681.9 $ 835.3 $ (153.4) (18.4%)
Non-utility .......... 17.1 43.5 (26.4) (60.7%)
-------- -------- --------- --------
Total ................ $ 699.0 $ 878.8 $ (179.8) (20.5%)
======== ======== ========= ========
Cost of gas
Utility .............. $ 413.4 $ 526.6 $ (113.2) (21.5%)
Non-utility .......... 5.6 33.1 (27.5) (83.1%)
-------- -------- --------- --------
Total ................ $ 419.0 $ 559.7 $ (140.7) (25.1%)
======== ======== ========= ========
Operating Margins
Utility .............. $ 268.5 $ 308.7 $ (40.2) (13.0%)
Non-utility .......... 11.5 10.4 1.1 10.6%
-------- -------- --------- --------
Total ................ $ 280.0 $ 319.1 $ (39.1) (12.3%)
======== ======== ========= ========
OPERATING REVENUES
Our operating revenues for the six months ended March 31, 1999 decreased to
$699.0 million from $878.8 million for the same period last year, a decrease of
20.5%.
UTILITY. Utility revenues decreased to $681.9 million for the six months ended
March 31, 1999 from $835.3 million for the same period last year. The decrease
of $153.4 million in utility revenues was primarily due to the following
factors:
- A decline in the utility's sales service revenues and a comparable decline
in the utility's recovery of gas costs of $104.9 million. (See discussion
on the utility's cost of gas below regarding the effects of warmer weather
and the migration of customers to marketer's.) AGLC recovers only its
actual gas costs from its customers within the parameters of the January
26, 1999 joint stipulation agreement with the GPSC. The reduction in gas
costs therefore results in a corresponding reduction in revenue, but does
not affect net income.
- A decline in the utility's delivery service revenue of $40.4 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, Impact of
New Regulatory Rate Structure and Deregulation, to the Condensed
Consolidated Financial Statements.)
Page 20 of 40 Pages
<PAGE>
- The January 26, 1999 joint stipulation agreement with the GPSC required
AGLC to issue checks to customers or credits to customer bills in the
amount of $14.8 million. Of that amount, $8.1 million was related to the
over-collection of gas costs during fiscal year 1998 before deregulation
began and was recorded on our balance sheet as of December 31, 1998. The
remaining $6.7 million was allocated during the second quarter to certain
AGLC customers and recorded as a decrease in revenue.
- The IRP was phased out during fiscal 1998 and did not exist in the first
six months of fiscal year 1999, resulting in a $5.3 million decrease in
revenue associated with the plan. Previously, 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.
NON-UTILITY. Non-utility operating revenues decreased to $17.1 million for the
six months ended March 31, 1999 from $43.5 million for the same period last
year. The decrease of $26.4 million in non-utility revenues was primarily due to
the formation of the SouthStar joint venture in July 1998. Prior to the
formation of SouthStar (including the six months ended March 31, 1998), we had a
wholly owned subsidiary that was engaged in the same business. Upon the
formation of SouthStar, the customers and operations of the former subsidiary
became the customers and operations of SouthStar. The results of the former
subsidiary were reported on a consolidated basis and, in contrast, the results
of our joint venture interest in SouthStar are accounted for under the equity
method. Our portion of SouthStar's results of operations is contained in Other
Income/(Loss) on the Condensed Consolidated Income Statement for the six months
ended March 31, 1999.
COST OF GAS
Our cost of gas decreased to $419.0 million for the six months ended March 31,
1999 from $559.7 million for the same period last year, a decrease of 25.1%.
UTILITY. The utility's cost of gas decreased to $413.4 million for the six
months ended March 31, 1999 from $526.6 million for the same period last year.
The decrease of $113.2 million in the utility's cost of gas was primarily due to
the following factors:
- Beginning November 1, 1998, customers began to switch from AGLC to
certificated marketers for gas purchases. As of March 31, 1999,
approximately 600,000 customers (41% of AGLC's total customers) had
switched from AGLC. As a result, AGLC sold less gas.
- The utility sold less gas to its customers due to weather that was 26%
warmer for the six months ended March 31, 1999 as compared with the same
period last year. This resulted in less volume of gas sold as compared with
last year.
NON-UTILITY. Non-utility cost of gas decreased to $5.6 million for the six
months ended March 31, 1999 from $33.1 million for the same period last year.
The decrease of $27.5 million was primarily due to the change from consolidation
to the equity method for SouthStar as described above under non-utility
operating revenues.
Page 21 of 40 Pages
<PAGE>
OPERATING MARGIN
Our operating margin decreased to $280.0 million for the six months ended March
31, 1999 from $319.1 million for the same period last year, a decrease of 12.3%.
The utility's operating margin decreased to $268.5 million for the three months
ended March 31, 1999 from $308.7 million for the same period last year. The
decrease of $40.2 million was due primarily to the following factors as
mentioned above under utility operating revenues:
- The utility's delivery service revenue decreased by $40.4 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 $5.3 million decrease in revenue associated with the phase-out of the
IRP.
OTHER OPERATING EXPENSES
Other operating expenses decreased slightly to $179.9 million for the six months
ended March 31, 1999 compared to $183.4 million for the same period last year, a
decrease of 1.9%. The components of other operating expenses are as follows
(dollars in millions):
SIX MONTHS ENDED
3/31/99 3/31/98 Increase/(Decrease)
-------- -------- ------------------
Operations
Utility ..................... $ 76.4 $ 79.6 $ (3.2) (4.0%)
Non-utility ................. 31.2 34.5 (3.3) (9.6%)
-------- -------- ------- -------
Total ....................... $ 107.6 $ 114.1 $ (6.5) (5.7%)
======== ======== ======= =======
Maintenance
Utility ..................... $ 14.1 $ 16.1 $ (2.0) (12.4%)
Non-utility ................. 4.0 3.0 1.0 33.3%
-------- -------- ------- -------
Total ....................... $ 18.1 $ 19.1 $ (1.0) (5.2%)
======== ======== ======= =======
Depreciation & Amortization
Utility ..................... $ 33.7 $ 31.7 $ 2.0 6.3%
Non-utility ................. 6.2 3.8 2.4 63.2%
-------- -------- ------- -------
Total ....................... $ 39.9 $ 35.5 $ 4.4 12.4%
======== ======== ======= =======
Taxes Other Than Income Taxes
Utility ..................... $ 12.7 $ 13.1 $ (0.4) (3.1%)
Non-utility ................. 1.6 1.6 0.0 0.0%
-------- -------- ------- -------
Total ....................... $ 14.3 $ 14.7 $ (0.4) (2.7%)
======== ======== ======= =======
Total Other Operating Expenses
Utility ..................... $ 136.9 $ 140.5 $ (3.6) (2.6%)
Non-utility ................. 43.0 42.9 0.1 0.2%
-------- -------- ------- -------
Total ....................... $ 179.9 $ 183.4 $ (3.5) (1.9%)
======== ======== ======= =======
Page 22 of 40 Pages
<PAGE>
UTILITY. Utility operations expenses decreased primarily due to the phase out of
the IRP during fiscal 1998 that resulted in a $5.3 million decrease. Utility
depreciation and amortization expenses increased primarily due to increased
depreciable property and increased depreciation rates for AGLC ordered by the
GPSC.
NON-UTILITY. Non-utility operations expenses decreased primarily due to the
change from consolidation to the equity method for SouthStar as discussed above
under non-utility operating revenue. Non-utility depreciation and amortization
expenses increased primarily due to increased depreciable property.
OTHER INCOME/(LOSS)
Other losses totaled $8.1 million for the six months ended March 31, 1999
compared with other income of $8.1 million for the same period last year. The
decrease in other income of $16.2 million is primarily due to:
- Our portion of the loss for 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 throughout 1999 associated with changes in certain accounting
estimates. We recorded a pre-tax loss related to our interest in Sonat
Marketing of approximately $7.9 million for the six months ended March 31,
1999 as compared with pre-tax income of approximately $4.6 million for the
same period last year.
- PGA carrying costs decreased by $3.5 million due to the deregulation of the
PGA for the six months ended March 31, 1999 compared with the same period
last year.
- Our portion of SouthStar's loss was approximately $3.3 million for the six
months ended March 31, 1999. Since SouthStar was not formed until July
1998, and there was no income or loss for this joint venture for the six
months ended March 31, 1998.
- Our portion of the income for Sonat Power Marketing, a joint venture in
which we own a 35% interest. There was greater income in 1999 as compared
to 1998 due to an overall favorable trend towards profitability. We
recorded pre-tax income related to our interest in Sonat Power Marketing of
approximately $2.7 million for the six months ended March 31, 1999 as
compared with a pre-tax loss of approximately $1.0 million for the same
period last year.
INCOME TAXES
Income taxes decreased to $21.0 million for the six months ended March 31, 1999
from $41.2 million for the same period last year. The decrease in income taxes
of $20.2 million was due primarily to the decrease in income before income taxes
for the same period last year. The effective tax rate (income tax expense
expressed as a percentage of pretax income) for the six months ended March 31,
1999 was 34.4% as compared to 36.8% for the same period last year. The decrease
in the effective tax rate was due primarily to a reduction in tax reserves
related to the favorable resolution of certain outstanding tax issues.
Page 23 of 40 Pages
<PAGE>
FINANCIAL CONDITION
Historically, our utility business was seasonal in nature and resulted in a
substantial increase in accounts receivable from customers from September 30 to
March 31 due to higher billings during colder weather. The utility used natural
gas stored underground to serve its customers during periods of colder weather
resulting in a substantial decrease in gas inventories when comparing March 31
with September 30. Although the seasonality of both expenses and revenues will
diminish as end-use customers select or are assigned to marketers and the
utility exits the sales service function, some level of seasonality will be
observed until AGLC is no longer providing sales service. (See Note 2, Impact of
New Regulatory Rate Structure and Deregulation, to the Condensed Consolidated
Financial Statements.)
Consequently, accounts receivable increased $65.0 million and inventory of
natural gas stored underground decreased $92.3 million during the six months
ended March 31, 1999. Natural gas stored underground decreased during the
six-month period ended March 31, 1999 primarily due to the seasonality of our
business and the assignment of natural gas inventories to marketers in
accordance with deregulation.
AGLC's deferred PGA asset was $0 as of March 31, 1999 compared to a deferred PGA
liability of $12.4 million as of September 30, 1998 and a deferred PGA asset of
$18.1 million as of March 31, 1998. The changes were due primarily to the
termination of the PGA mechanism and the elimination of regulated rates for
natural gas commodity sales to Georgia customers on October 6, 1998.
The pace at which customers are switching from AGLC to marketers has far
exceeded original expectations, particularly now that all customers must be
assigned to marketers no later than October 1, 1999. Additionally, the
regulatory mechanism that governs the shedding of costs associated with the
provision of ancillary services by AGLC is not functioning as was intended.
Specifically, there is a disparity between the rate at which AGLC is actually
able to shed costs and the rate at which AGLC is assumed, for regulatory
purposes, to be shedding costs. AGLC is closely monitoring the effect of both
the acceleration of the assignment of customers to marketers and the
imperfection in the regulatory mechanism on its financial condition and results
of operations. AGLC is pursuing solutions aggressively, including shedding cost
as quickly as possible consistent with prudent business practices, and
evaluating regulatory alternatives for additional revenue generation.
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.
Short-term debt decreased $75.0 million to $1.5 million as of March 31, 1999
from $76.5 million as of September 30, 1998. Typically, we borrow and repay the
loans within a month. We generated operating cash flow of $165.8 million for the
six months ended March 31, 1999 as compared to $151.9 million for the same
period last year. This increase in operating cash flow is primarily due to the
decrease in natural gas stored underground as well as the increase in gas cost
credits.
We believe available credit will be sufficient to meet our working capital needs
both on a short and 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.
Page 24 of 40 Pages
<PAGE>
CAPITAL EXPENDITURES
Capital expenditures for construction of distribution facilities, purchase of
equipment, and other general improvements were $61.8 million for the six-month
period ended March 31, 1999 as compared to $56.0 million for the six month
period ended March 31, 1998. The increase of $5.8 million is directly related to
the capital expenditures incurred for the accelerated pipeline replacement plan.
(See discussion of AGLC Pipeline Safety under State Regulatory Activity.)
Typically, we provide funding for capital expenditures through a combination of
internal sources and the issuance of short-term debt.
COMMON STOCK
During the six months ended March 31, 1999, we issued 371,633 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 $6.9 million.
TERMINATION OF LESOP
We have terminated our Leveraged Employee Stock Ownership Plan (LESOP) and will
distribute the value of participants' LESOP account balances as of June 15,
1999. At the election of the participants, we will distribute the value of each
account in one of three forms:
- Direct rollover into the Retirement Savings Plus Plan (401(k) plan) or into
another tax-qualified retirement plan;
- Lump sum payment in the form of a certificate for shares of AGL Resources
common stock; or
- Lump sum cash payment based on the market value of AGL Resources common
stock at the close of business on June 14, 1999.
We will repurchase in cash from the LESOP trustee all shares in the accounts of
participants who elect to receive a lump sum cash payment. The total cash
repurchase price is not expected to exceed approximately $27.5 million. We will
fund these cash repurchases with working capital or short-term borrowings.
RATIOS
As of March 31, 1999, our capitalization ratios consisted of:
- 47.0% long-term debt;
- 5.3% preferred securities; and
- 47.7% common equity.
GAS COST CREDITS
AGLR has $36.4 million in gas cost credits as of March 31, 1999 as compared to a
$0 balance on September 30, 1998 and March 31, 1998. (See Note 2, Impact of New
Regulatory Rate Structure and Deregulation, to the Condensed Consolidated
Financial Statements.)
Page 25 of 40 Pages
<PAGE>
SALE OF JOINT VENTURE INTERESTS
We have exercised our right to require Sonat Inc. (Sonat) to repurchase our 35%
interest in Sonat Marketing. At a minimum, we expect to receive a price for this
interest that is no less than $32 million, plus simple interest (not to exceed
$5 million) at an annual rate of 3.5% from the date of our initial investment,
less the amount of certain distributions made by the joint venture to us since
the formation of the joint venture.
Following our notice to Sonat that we were exercising our right to sell our
interest in Sonat Marketing, we received notice that Sonat is exercising its
right to purchase our 35% interest in Sonat Power Marketing. Under the terms of
the Sonat Power Marketing joint venture agreement, Sonat is required to
repurchase this interest for its fair market value.
STATE REGULATORY ACTIVITY
DEREGULATION
The Deregulation Act enacted in April 1997 provides for deregulation 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 in Georgia; 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, are competing 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 continues to regulate
delivery rates, safety, access to AGLC's system, and quality of service for all
aspects of delivery service.
On April 8, 1999, a new law was enacted giving the GPSC the authority to speed
up the process for the assignment of all remaining AGLC customers to gas
marketers beginning August 11, 1999. The GPSC issued an order on May 3, 1999,
setting forth a 100 day period for customers to choose a marketer. Customers who
do not choose a marketer by August 11, 1999 will be randomly assigned to a
marketer under the rules issued by the GPSC.
Marketers will be assigned customers in proportion to their respective market
share as of August 11, 1999 and begin serving those customers on October 1,
1999. AGLC will then exit the gas sales business and be responsible only for
delivery service for residential and commercial customers.
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
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. To date, seventeen marketers have been
certificated by the
Page 26 of 40 Pages
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STATE REGULATORY ACTIVITY (CONTINUED)
GPSC to serve end-use customers in Georgia. Two marketers have requested to exit
the Georgia market and those applications are pending approval. Additionally,
three marketers have submitted applications for certification which are pending
approval.
As of March 31, 1999, more than 600,000 residential and small commercial
customers had elected to purchase natural gas services from one of the 11 active
approved marketers in Georgia. As of May 1, 1999, more than 726,000 residential
and small commercial customers had elected to purchase natural gas services from
those same marketers.
SALES SERVICE RATE ISSUES
Pursuant to the Deregulation Act, regulated rates for natural gas sales service
to AGLC's Georgia customers (as opposed to delivery service rates discussed
above - see Note 2, Impact of New Regulatory Rate Structure and Deregulation, to
the Condensed Consolidated Financial Statements) 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 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 implemented a new rate structure for gas sales,
beginning with February 1999 bills, that more closely reflected customers'
actual gas usage and included a demand charge for fixed costs associated with
gas sales that was entirely volumetric. The new rate structure for gas sales
service was 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 revenues from gas sales to gas costs during fiscal
1999 for any profit or loss on gas sales outside of a specified range. The
allowed maximum profit is $1.0 million and the maximum risk of loss is $3.25
million. As of March 31, 1999, the Company has received revenues in excess of
costs of $37.4 million. As of March 31, 1999, the Company has recognized profits
of $1.0 million and has recorded a regulatory liability of $36.4 million under
the caption "Gas cost credits" on the Condensed Consolidated Balance Sheet.
As part of the joint stipulation agreement, AGLC issued checks to customers or
credits to customer bills in the total amount of $14.8 million to lessen the
effects of the Company's earlier rate methodology. Of that amount, $8.1 million
was refunded to AGLC customers based on the over-collection of gas costs during
fiscal 1998 before deregulation began and was recorded on our balance sheet as
of December 31, 1998. The remaining $6.7 million was 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 when regulated rates ended on
October 6, 1998.
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 mechanism of
AGLC's rate schedules. Accordingly, the hedging program did not affect our
earnings.
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STATE REGULATORY ACTIVITY (CONTINUED)
During the first quarter of fiscal 1999, AGLC entered into certain hedge
agreements that continued until the end of February 1999. However, as part of
the joint stipulation agreement 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
agreement have been included in gas costs which are 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 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 six month period ended March
31, 1999, AGLC spent approximately $16.7 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."
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 the low end of the
range of our estimated 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. We have been actively
pursuing those recoveries. There were no material recoveries during the quarter
ended March 31, 1999.
FEDERAL REGULATORY ACTIVITY
FERC ORDER 636: TRANSITION COSTS SETTLEMENT AGREEMENTS. As contained in our Form
10-K for the year ended September 30, 1998 under the caption "Federal Regulatory
Matters," the FERC has required the utility, as well as other interstate
pipeline customers, to pay transition costs associated with the separation of
its 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 $105.3
million. As of March 31, 1999, approximately $99.7 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.
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.
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FEDERAL REGULATORY ACTIVITY (CONTINUED)
Under the Southern settlement, the utility's share of Southern's transition
costs is approximately $87.1 million, of which the utility had incurred $86.4
million as of March 31, 1999. Under the Tennessee settlement, the utility's
share of Tennessee's transition costs is approximately $14.7, of which the
utility had incurred approximately $10.0 million as of March 31, 1999.
FERC RATE PROCEEDINGS. On April 16, 1999, the FERC issued an order addressing
Transcontinental Gas Pipe Line Company's (Transco's) proposal to include in its
general system rates the costs of certain pipeline facilities that currently are
recovered only from the customers that actually receive service through those
facilities. A FERC administrative law judge previously issued an initial
decision rejecting Transco's proposal. The FERC reversed the initial decision
and authorized Transco to include the additional costs in its general system
rates to be charged in the future, but required further proceedings to determine
the manner in which certain costs are to be allocated to Transco's customers.
AGLC is actively participating in these proceedings. The FERC's order is subject
to possible requests for rehearing by parties objecting to the order, and
therefore is not yet final.
On March 30, 1999, a FERC administrative law judge issued an initial decision
reducing the rate of return underlying the rates charged by Transco since May 1,
1997. The initial decision is subject to review by the FERC, and therefore is
not yet final.
SOUTHCOAST. On April 29, 1999, Transco filed an application with the FERC to
construct certain facilities in Alabama and Georgia in order to provide service
to several customers beginning November 1, 2000. AGLC has signed an agreement to
purchase 61,160 Dth/day of service through the proposed facilities if the FERC
authorizes their construction. Transco'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.
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 (EPD) 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 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.
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ENVIRONMENTAL MATTERS (CONTINUED)
Using the above process, we currently estimate that our total future cost of
investigating and cleaning up our MGP sites is between $104.3 million and $150.1
million. That range does not include other potential expenses, such as
unasserted property damage claims or legal expenses for which we may be held
liable but for which neither the existence nor the amount of such liabilities
can be reasonably forecast. Within that range, we cannot identify any single
number as a "better" estimate of our likely future costs. Consequently, we have
recorded the lower end of the range, or $104.3 million, as a liability as of
March 31, 1999. We do not believe that any single number within the range
constitutes a "better" estimate because our actual future investigation and
cleanup costs will be affected by a number of contingencies that cannot be
quantified at this time. The cost estimate has increased from the estimate as of
December 31, 1998, primarily due to (i) more complete information, obtained from
actual on-site clean-up experience and from further investigation at various
sites, concerning the amount of contamination present at various sites and (ii)
increased experience with EPD and, as a result of such experience, enhanced
knowledge of the types of clean-up EPD is likely to find acceptable at each of
the sites.
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.
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. We have been
actively pursuing those recoveries. There were no material recoveries during the
quarter ended March 31, 1999.
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
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
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 information technology (IT) applications,
infrastructure and non-information technology (non-IT) applications, as each of
those terms is defined below, and 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, suppliers and manufacturers 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) applications - Computer software
maintained by our Information Systems (IS) Department;
- Infrastructure and non-information technology (non-IT) applications -
Computer hardware, such as our mainframe and PC's, microprocessors
embedded in equipment, and software maintained by business units other
than our IS Department; and
- Key business partners (customers, suppliers and manufacturers).
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
Marketing, L.P. and Sonat Marketing Company, L.P. 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.)
Set forth below 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,
remediation planning and plan implementation phases. All of SouthStar's critical
assets are Year 2000 ready. Our
Page 31 of 40 Pages
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
assessment of the readiness of SouthStar's key business partners is underway.
We've obtained information or responses from a majority of SouthStar's key
suppliers. We are in the process of assessing and following up on the responses
from certain of SouthStar's critical suppliers. We plan to contact key customers
of SouthStar with respect to their Year 2000 readiness. We are in the process of
preparing contingency plans for SouthStar. Management expects SouthStar's
business and operations to achieve Year 2000 readiness. With respect to
Utilipro, Inc., the Year 2000 initiative recently commenced. We have completed
the project plan for the Utilipro Year 2000 initiative. We expect to complete
the assessment phase by June 30, 1999. Management expects Utilipro's business
and operations to achieve Year 2000 readiness.
IT APPLICATIONS
Assessment of, and remediation planning for, IT applications is complete and
implementation is underway. During the assessment phase, we completed the
assessment of our 80 IT applications. We deem 13 of those 80 applications to be
critical applications. The results of our Year 2000 initiative with respect to
IT applications indicate that, to date:
- 46 applications now are ready for Year 2000, including all critical
applications;
- Two applications are in testing to verify Year 2000 readiness;
- Four applications are in remediation for purposes of correcting
noncompliant Year 2000 code;
- Eight applications have been eliminated;
- Eight applications have been replaced; and
- 12 applications are scheduled for either testing, replacement, remediation,
or elimination in the future.
Remediation completion schedules for achieving Year 2000 readiness of
noncritical IT applications are expected to extend through September 1999.
INFRASTRUCTURE AND NON-IT APPLICATIONS
Assessment of infrastructure and non-IT applications is complete. Our
infrastructure and non-IT application assessment process involved the following:
- Identifying business processes;
- Identifying the assets that comprise the infrastructure and non-IT
applications category, and defining the business process or processes to
which such assets relate;
- Identifying the mission criticality of each such asset and business
process; and
- Documenting in a tracking database the existence, and the
mission-criticality, of each such asset and business process.
Remediation planning for critical infrastructure and non-IT applications also
has been completed. We expect to complete implementation of our remediation
plans for critical infrastructure and non-IT applications by no later than June
30 1999, with the following two exceptions. With respect to both, operational
changes unrelated to Year 2000 will impact the schedule for achieving their Year
2000 readiness. The critical infrastructure and non-IT applications referred to
are our mainframe computer and certain infrastructure and non-IT applications at
three of our four liquefied natural gas (LNG) plants.
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
- Mainframe - We plan to outsource the operation of our mainframe functions
in order to increase operating capacity and efficiency. We plan to complete
the Year 2000 readiness testing of the outsourced system by September 30,
1999.
- LNG Plants - The infrastructure and non-IT applications of one of our four
plants will be Year 2000 ready by June 30, 1999. In an effort to increase
operating efficiency, we are in the process of centralizing the integrated
control systems of three of our LNG plants. We expect to complete the
centralization by September 30, 1999. Completion of the centralization will
also result in the Year 2000 readiness of infrastructure and non-IT
applications at these three LNG plants.
KEY BUSINESS PARTNERS
We are contacting key business partners, including suppliers, manufacturers and
customers to evaluate their Year 2000 readiness plans and status of readiness.
We have contacted over 2000 suppliers and manufacturers by letter. This group
includes suppliers and manufacturers that we consider key business partners as
well as other selected suppliers and manufacturers. However, to date, we have
not received responses from the majority of suppliers and manufacturers we
contacted. We have begun following up by telephone with those key suppliers from
whom we have not yet received responses. To date, we have completed follow-up
with 100% of those suppliers that we consider to be critical suppliers. We have
begun follow-up with critical manufacturers.
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 that 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 have begun following up
with critical 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
March 31, 1999, our cumulative expenses in connection with our Year 2000
assessment, remediation planning, and plan implementation processes were
approximately $4.7 million. Through March 31, 1999, we had spent an additional
$8.7 million for the replacement of our financial 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 financial and human resources information systems.
We have capitalized the costs of
Page 33 of 40 Pages
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
our new financial and human resources information systems, in accordance with
our accounting policies and with generally accepted accounting principles.
We expect to spend approximately $6.2 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 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 March 31, 1999, AGLC had
deferred total costs of approximately $2.6 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 recently finalized our most reasonably likely worst case Year 2000 scenarios.
These scenarios contemplate intermittent disruptions of important goods and
services that we obtain from third parties at some locations. We do not expect
these disruptions to be long-term nor do we expect the disruptions to materially
impact our operations as a whole. However, the extent of such disruptions is
uncertain and if the extent or longevity of the disruptions exceed our
assumptions, they could have a material adverse impact on our business, results
of operations, or financial condition.
Although we have finalized our most reasonably likely worst case scenarios, the
process of refining our most reasonably likely worst case scenarios will be an
ongoing process. We expect to continue to develop and modify our most reasonably
likely worst case scenarios as we obtain additional information regarding (a)
our internal systems and equipment during the implementation phase of our Year
2000 initiative as well as during independent validation and verification of the
Year 2000 readiness of such systems and equipment, and (b) the status, and the
impact on us, of the Year 2000 readiness of others.
BUSINESS CONTINUITY AND CONTINGENCY PLANNING
We have completed the initial drafts of our 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. Our most reasonably
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
likely worst case scenarios as described above 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.
We expect to continue 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, refine and test our contingency plans, as needed, to
reflect system and business changes as they evolve.
CLEAN MANAGEMENT
Clean management describes the process of:
- Identifying our means of acquiring assets and of developing or modifying
systems;
- Verifying the Year 2000 readiness of assets prior to purchase; and
- Assuring that system modifications and new systems are Year 2000 ready at
the time of development or acquisition.
We are using the clean management process on an on-going basis. Clean management
applies to both IT applications and to infrastructure and non-IT applications
and to key business partner relationships. We expect to obtain additional or
updated information about the Year 2000 readiness of assets and key business
partners through the clean management process. We will address any additional
Year 2000 issues discovered as a result of the clean management process.
VALIDATION AND VERIFICATION
Our Year 2000 initiative includes validation and verification of assets by us,
by third parties or by both. We expect validation and verification efforts,
whether internal or independent, to result in the discovery of additional Year
2000 issues and we will address those issues as they arise. We expect the
validation and verification process to continue throughout 1999 and into the
Year 2000.
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,
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YEAR 2000 READINESS DISCLOSURE (CONTINUED)
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.
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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 ($1.5
million as of March 31, 1999) 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. 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 37 of 40 Pages
<PAGE>
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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Annual Meeting of Shareholders was held on February 5, 1999 (the "Annual
Meeting"). "Broker non-votes" were not considered in determining whether a
quorum existed for purposes of the Annual Meeting. At the Annual Meeting, the
shareholders :
(a) Elected the following two nominees for director to hold office until
the Annual Meeting of Shareholders in the year 2002, as set forth in
AGL Resources' Proxy Statement. The number of votes "for" each nominee
and the number of votes "withheld" with respect to each nominee was as
follows:
NOMINEE FOR WITHHELD
Frank Barron, Jr. 50,006,983 574,721
Walter M. Higgins 50,049,657 532,047
Directors whose term of office continued after the Annual Meeting are:
Otis A. Brumby, Jr., David R. Jones, Wyck A. Knox, Jr., Albert G.
Norman, Jr., D. Raymond Riddle, Betty L. Siegel, Ben J. Tarbutton, Jr.
and Felker W. Ward, Jr.
(b) Approved and adopted the AGL Resources Inc. Long-Term Incentive Plan
(1999).
FOR AGAINST
33,317,579 5,515,551
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."
Page 38 of 40 Pages
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
27 Financial Data Schedule.
(B) REPORTS ON FORM 8-K.
There were no reports on Form 8-K filed during the quarterly period
ended March 31, 1999.
Page 39 of 40 Pages
<PAGE>
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 May 17, 1999 /s/ J. Michael Riley
J. Michael Riley
Senior Vice President and Chief Financial Officer
(Principal Accounting and Financial Officer)
Page 40 of 40 Pages
<PAGE>
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