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 June 30, 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)
817 West Peachtree Street, N.E.
Suite 1000
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 June 30, 1999.
Common Stock, $5.00 Par Value
Shares Outstanding at June 30, 1999..................................56,911,802
<PAGE>
AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended June 30, 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 38
PART II -- OTHER INFORMATION
1 Legal Proceedings 39
4 Submission of Matters to a Vote of Security Holders 39
5 Other Information 39
6 Exhibits and Reports on Form 8-K 40
SIGNATURES 41
Page 2 of 41 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 NINE MONTHS ENDED
JUNE 30, 1999 AND 1998
(MILLIONS, EXCEPT PER SHARE DATA)
(UNAUDITED)
Three Months Nine Months
1999 1998 1999 1998
---------- ---------- ---------- -----------
Operating Revenues .............. $ 185.9 $ 246.4 $ 884.9 $ 1,125.2
Cost of Gas ..................... 61.4 150.1 480.4 709.8
---------- ---------- ---------- -----------
Operating Margin .............. 124.5 96.3 404.5 415.4
Other Operating Expenses ........ 95.0 87.4 274.9 270.8
---------- ---------- ---------- -----------
Operating Income .............. 29.5 8.9 129.6 144.6
Other Income (Loss) ............. (5.6) 0.7 (13.7) 8.8
---------- ---------- ---------- -----------
Income Before Interest and
Income Taxes ................. 23.9 9.6 115.9 153.4
Interest Expense and Preferred
Stock Dividends
Interest expense .............. 12.9 13.1 40.7 41.3
Dividends on preferred stock
of subsidiaries .............. 1.5 1.6 4.6 5.2
---------- ---------- ---------- -----------
Total interest expense and
preferred stock dividends ... 14.4 14.7 45.3 46.5
---------- ---------- ---------- -----------
Income Before Income Taxes .... 9.5 (5.1) 70.6 106.9
Income Taxes .................... 2.3 (3.9) 23.3 37.3
---------- ---------- ---------- -----------
Net Income .................... $ 7.2 $ (1.2) $ 47.3 $ 69.6
========== ========== ========== ===========
Earnings (Loss) per Common Share
Basic ......................... $ 0.12 $ (0.02) $ 0.82 $ 1.22
Diluted ....................... $ 0.12 $ (0.02) $ 0.82 $ 1.22
Weighted Average Number of Common
Shares Outstanding
Basic ......................... 57.4 57.1 57.5 56.9
Diluted ....................... 57.5 57.2 57.6 57.0
Cash Dividends Paid Per Share of
Common Stock .................. $ 0.27 $ 0.27 $ 0.81 $ 0.81
See notes to condensed consolidated financial statements.
Page 3 of 41 Pages
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
June 30, September 30,
-------------------- --------------
ASSETS 1999 1998 1998
- --------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents ........ $ 14.0 $ 9.5 $ 0.9
Receivables (less allowance
for uncollectible accounts
of $2.4 at June 30, 1999,
$5.7 at June 30, 1998, and
$4.1 at September 30, 1998) .. 100.1 136.1 121.7
Inventories
Natural gas stored underground 57.4 84.5 138.1
Liquefied natural gas ........ 8.9 16.6 17.7
Other ........................ 11.8 12.4 14.6
Investment in joint ventures ..... 28.9 - -
Deferred purchased gas adjustment - - 3.5
Other ............................ 2.8 2.3 1.9
- --------------------------------------------------------------------------------
Total current assets ......... 223.9 261.4 298.4
- --------------------------------------------------------------------------------
Property, Plant and Equipment
Utility plant .................... 2,212.0 2,129.3 2,133.5
Less: accumulated depreciation ... 720.6 683.4 680.9
- --------------------------------------------------------------------------------
Utility plant - net .......... 1,491.4 1,445.9 1,452.6
- --------------------------------------------------------------------------------
Nonutility property .............. 111.0 118.6 105.6
Less: accumulated depreciation ... 32.3 33.1 24.6
- --------------------------------------------------------------------------------
Nonutility property - net .... 78.7 85.5 81.0
- --------------------------------------------------------------------------------
Total property, plant and
equipment - net ............. 1,570.1 1,531.4 1,533.6
- --------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental
response costs .................. 145.0 73.0 77.6
Investments in joint ventures .... 4.0 40.2 46.7
Other ............................ 33.9 30.5 29.0
- --------------------------------------------------------------------------------
Total deferred debits
and other assets ............ 182.9 143.7 153.3
- --------------------------------------------------------------------------------
Total Assets ........................... $ 1,976.9 $ 1,936.5 $ 1,985.3
================================================================================
See notes to condensed consolidated financial statements.
Page 4 of 41 Pages
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
(Unaudited)
June 30, September 30,
----------------- ------------
LIABILITIES AND CAPITALIZATION 1999 1998 1998
- --------------------------------------------------------------------------------
Current Liabilities
Accounts payable .................... $ 39.7 $ 77.3 $ 48.4
Short-term debt ..................... 1.5 10.4 76.5
Customer deposits ................... 15.2 30.9 30.5
Accrued interest .................... 18.8 19.3 32.8
Taxes ............................... 2.7 25.3 10.1
Deferred purchased gas
adjustment ......................... 0.5 12.0 12.4
Gas cost credits .................... 41.7 -- --
Current portion of long-term debt ... 50.0 -- --
Other ............................... 59.8 27.4 42.8
- --------------------------------------------------------------------------------
Total current liabilities ....... 229.9 202.6 253.5
- --------------------------------------------------------------------------------
Accumulated Deferred Income Taxes ......... 219.0 198.6 203.0
- --------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response
costs .............................. 102.4 47.0 47.0
Accrued postretirement benefits
costs .............................. 34.7 37.4 33.4
Deferred credits .................... 53.9 58.8 57.8
Other ............................... 5.1 2.3 2.1
- --------------------------------------------------------------------------------
Total long-term liabilities ..... 196.1 145.5 140.3
- --------------------------------------------------------------------------------
Capitalization
Long-term debt ...................... 610.0 660.0 660.0
Subsidiary obligated mandatorily
redeemable preferred securities ... 74.3 74.3 74.3
Common stock, $5 par value, shares
issued of 57.8 at June 30, 1999,
57.2 at June 30, 1998,
and 57.3 at September 30, 1998 .. 664.7 655.5 654.2
Less: Shares held in treasury,
at cost
0.9 shares at June 30, 1999 . (17.1) -- --
- --------------------------------------------------------------------------------
Total capitalization ............ 1,331.9 1,389.8 1,388.5
- --------------------------------------------------------------------------------
Total Liabilities and Capitalization ...... $ 1,976.9 $ 1,936.5 $ 1,985.3
================================================================================
See notes to condensed consolidated financial statements.
Page 5 of 41 Pages
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED JUNE 30, 1999 AND 1998
(MILLIONS)
(UNAUDITED)
Nine Months
---------------------
1999 1998
- --------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income ..................................... $ 47.3 $ 69.6
Adjustments to reconcile net income to net
cash flow from operating activities
Depreciation and amortization ............ 62.0 54.1
Deferred income taxes .................... 16.0 3.9
Other .................................... (1.0) 0.1
Changes in certain assets and liabilities ...... 65.8 69.8
- --------------------------------------------------------------------------------
Net cash flow from operating
activities .......................... 190.1 197.5
- --------------------------------------------------------------------------------
Cash Flows from Financing Activities
Short-term borrowings, net ..................... (25.0) (19.1)
Sale of common stock, net of expenses .......... 2.4 0.4
Redemption of preferred securities ............. -- (44.5)
Purchase of treasury shares .................... (17.1) --
Dividends paid on common stock ................. (39.3) (40.4)
- --------------------------------------------------------------------------------
Net cash flow from financing
activities .......................... (79.0) (103.6)
- --------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures ..................... (82.4) (72.3)
Non-utility property expenditures .............. (14.4) (13.2)
Investment in joint ventures ................... (4.4) (4.3)
Cash received from joint ventures .............. 1.8 2.0
Other .......................................... 1.4 (1.4)
- --------------------------------------------------------------------------------
Net cash flow from investing
activities .......................... (98.0) (89.2)
- --------------------------------------------------------------------------------
Net increase in cash and
cash equivalents .................... 13.1 4.7
Cash and cash equivalents at
beginning of period ................. 0.9 4.8
- --------------------------------------------------------------------------------
Cash and cash equivalents at
end of period ....................... $ 14.0 $ 9.5
================================================================================
Cash paid during the period for
Interest ....................................... $ 59.5 $ 51.6
Income taxes ................................... $ 13.0 $ 20.2
Page 6 of 41 Pages
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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 condensed 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 nine-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 Georgia 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 41 Pages
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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 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. On July 1, 1998, AGLC began collecting such revenue
throughout the year regardless of differences in the volume of gas used during
the summer and winter. 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 rate structure and 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
revenues should remain relatively consistent with prior years.
Rate Structure for Sales Service
- --------------------------------
Pursuant to legislation enacted 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 than normal 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 than normal 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 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 for any
profit or loss outside of a specified range during fiscal 1999.
Page 8 of 41 Pages
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2. Impact of New Regulatory Rate Structure and Deregulation (Continued)
The allowed maximum profit is $1.0 million and the maximum risk of loss is $3.25
million. As of June 30, 1999, the Company has received revenues for the period
beginning October 6, 1998 in excess of costs of $42.7 million. Through June 30,
1999, the Company has recognized profits of $1.0 million and has recorded a
liability of $41.7 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. Of that amount, $8.1 million was related to the over-collection
of gas costs during fiscal 1998 before deregulation began and was previously
recorded as a liability. The remaining $6.7 million was allocated during the
second quarter to certain AGLC customers and recorded as a decrease in revenue.
Regulatory Accounting
- ---------------------
AGLC has recorded regulatory assets and liabilities on the 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.
(The remainder of this page was intentionally left blank.)
Page 9 of 41 Pages
<PAGE>
2. Impact of New Regulatory Rate Structure and Deregulation (Continued)
Pursuant to legislation enacted in Georgia, regulated rates for natural gas
commodity sales to AGLC customers ended on October 6, 1998. 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 nine months ended June 30, 1999
(in millions):
3 Months 9 Months
Ended Ended
6/30/99 6/30/99
-------- --------
Operating Revenues
Nonregulated $ 55.3 $ 449.2
Regulated ... 125.4 413.4
-------- --------
Total Utility $ 180.7 $ 862.6
======== ========
Cost of Gas
Nonregulated $ 54.1 $ 440.3
Regulated ... 6.2 33.4
-------- --------
Total Utility $ 60.3 $ 473.7
======== ========
Operating Margins
Nonregulated $ 1.2 $ 8.9
Regulated ... 119.2 380.0
-------- --------
Total Utility $ 120.4 $ 388.9
======== ========
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
2,324,024 and 50,151 shares of common stock were outstanding as of June 30, 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 nine months ended June 30, 1999, we issued 149,725
and 521,358 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 $3.0 million and $9.9 million for the three-month and
nine-month periods ended June 30, 1999, respectively.
During the quarter ended June 30, 1999, the Company purchased 868,688 shares of
its common stock in connection with the termination of the Leveraged Employee
Stock Ownership Plan (LESOP). The shares were purchased at $18.50 per share, and
are held by AGL Resources as treasury shares.
Page 10 of 41 Pages
<PAGE>
4. Change in Inventory Costing Method
In Georgia's new competitive environment, certificated marketing companies,
including AGLC's marketing affiliate, Georgia Natural Gas Services, 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 to certificated marketing companies 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 Purchased 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.
(The remainder of this page was intentionally left blank.)
Page 11 of 41 Pages
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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). In June 1996, the
Company, through a subsidiary, invested $1.0 million for a 35% ownership
interest in Sonat Power Marketing, L.P. (Sonat Power Marketing), another joint
venture with a subsidiary of Sonat.
On July 29, 1999, the Company and Sonat entered into an agreement pursuant to
which Sonat agreed to purchase the Company's interest in Sonat Marketing for
$40.0 million and its interest in Sonat Power Marketing for $25.0 million. Under
the terms of the agreement, upon the completion of each transaction, the
applicable joint venture agreement will be amended to provide that the Company
will not be allocated any gain or loss from the joint venture for any period
subsequent to June 30, 1999. The sale of the Company's interest in Sonat
Marketing was completed on August 12, 1999. Completion of the sale of the
Company's interest in Sonat Power Marketing is subject to, among other things,
approval of the Federal Energy Regulatory Commission under Section 203 of the
Federal Power Act. The Company expects the sale of its interest in Sonat Power
Marketing to close by the end of 1999.
7. Environmental Matters
Before natural gas was widely available in the Southeast, AGLC manufactured gas
from coal and other fuels. Those manufacturing operations were known as
"manufactured gas plants," or "MGPs" which AGLC ceased operating in the 1950s.
Because of recent environmental concerns, we are required to investigate
possible environmental contamination at those plants and, if necessary, clean up
any contamination.
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 have estimated our share of the likely costs of
investigation and cleanup. We used the following process for 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 $102.4 million and $148.2
million. That range does not include other potential expenses, such as
unasserted property damage or personal injury 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 $102.4 million, as
a liability and a corresponding regulatory asset as of June 30, 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.
Page 12 of 41 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 a regulatory asset in the same amount as our
investigation and cleanup liability.
The second way we can recover costs is by exercising the legal rights we believe
we have to recover a share of our costs from other potentially responsible
parties - typically former owners or operators of the MGP sites. We have been
actively pursuing those recoveries. There were no material recoveries during the
quarter ended June 30, 1999.
(The remainder of this page was intentionally left blank.)
Page 13 of 41 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
deregulation 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." Additionally, the utility's operations
expenses include costs allocated from AGL Resources.
Page 14 of 41 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., (Utilipro) which engages in the sale of integrated
customer care solutions and billing services 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.
(The remainder of this page was intentionally left blank.)
Page 15 of 41 Pages
<PAGE>
Results of Operations
Three-Month Periods Ended June 30, 1999 and 1998
- ------------------------------------------------
In this section we compare the results of our operations for the three-month
periods ended June 30, 1999 and 1998.
Operating Margin Analysis
- -------------------------
(Dollars in Millions)
Three Months Ended
-------------------
6/30/99 6/30/98 Increase/(Decrease)
-------- -------- ------------------
Operating Revenues
Utility ..... $ 180.7 $ 237.4 $ (56.7) (23.9%)
Non-utility . 5.2 9.0 (3.8) (42.2%)
-------- -------- ------- -------
Total ....... $ 185.9 $ 246.4 $ (60.5) (24.6%)
======== ======== ======= =======
Cost of Gas
Utility ..... $ 60.3 $ 141.8 $ (81.5) (57.5%)
Non-utility . 1.1 8.3 (7.2) (86.7%)
-------- -------- ------- -------
Total ....... $ 61.4 $ 150.1 $ (88.7) (59.1%)
======== ======== ======= =======
Operating Margins
Utility ..... $ 120.4 $ 95.6 $ 24.8 25.9%
Non-utility . 4.1 0.7 3.4 485.7%
-------- -------- ------- -------
Total ....... $ 124.5 $ 96.3 $ 28.2 29.3%
======== ======== ======= =======
Operating Revenues
- ------------------
Our operating revenues for the three months ended June 30, 1999 decreased to
$185.9 million from $246.4 million for the same period last year, a decrease of
24.6%.
Utility.
Utility revenues decreased to $180.7 million for the three months ended June 30,
1999 from $237.4 million for the same period last year. The decrease of $56.7
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 $81.5 million (See discussion of
the utility's cost of gas below regarding the migration of customers to
marketers.) 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.
- An increase in the utility's delivery service revenue of $24.0 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.)
- TheIntegrated Resource Plan (IRP) was phased out during fiscal 1998 and did
not exist in the third quarter of fiscal year 1999, resulting in a $1.0
million decrease in revenue associated with IRP. 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.
Page 16 of 41 Pages
<PAGE>
Non-utility.
Non-utility operating revenues decreased to $5.2 million for the three months
ended June 30, 1999 from $9.0 million for the same period last year. The net
decrease of $3.8 million was primarily due to the following factors:
- A decrease in revenues attributable to the formation of the SouthStar joint
venture in July 1998. Prior to the formation of SouthStar (including the
third 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. 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 June 30, 1999.
- Increased revenues from a subsidiary of the Company, Utilipro, which
engages in the sale of integrated customer care solutions to energy
marketers. As of June 30, 1998, Utilipro had been in business for only six
months. Utilipro has been a fast growing start up company that has had an
increase in both revenues and expenses over the past year.
Cost of Gas
- -----------
Our cost of gas decreased to $61.4 million for the three months ended June 30,
1999 from $150.1 million for the same period last year, a decrease of 59.1%.
Utility.
The utility's cost of gas decreased to $60.3 million for the three months ended
June 30, 1999 from $141.8 million for the same period last year. The decrease of
$81.5 million in the utility's cost of gas was primarily due to customer
migration to marketers. Beginning November 1, 1998, customers began to switch
from AGLC to certificated marketers for gas purchases. As of June 30, 1999,
approximately 881,000 customers (approximately 60% of AGLC's total customers)
had switched from AGLC to a certificated marketer. As a result, AGLC sold less
gas.
Non-utility.
Non-utility cost of gas decreased to $1.1 million for the three months ended
June 30, 1999 from $8.3 million for the same period last year. The decrease of
$7.2 million was primarily due to the change from consolidation to the equity
method for SouthStar as described above. (See Operating Revenue - Non-utility.)
Operating Margin
- ----------------
Our operating margin increased to $124.5 million for the three months ended June
30, 1999 from $96.3 million for the same period last year, an increase of 29.3%.
Utility.
The utility's operating margin increased to $120.4 million for the three months
ended June 30, 1999 from $95.6 million for the same period last year. The
increase of $24.8 million was due primarily to the following factors as
mentioned above under Operating Revenues - Utility:
- The utility's delivery service revenue increased by $24.0 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 June 30, 1999, approximately 881,000 customers
(approximately 60% 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 $5.5 million.
- A $1.0 million decrease in revenue associated with the phase-out of the
IRP.
Page 17 of 41 Pages
<PAGE>
Non-utility.
Non-utility operating margin increased to $4.1 million for the three months
ended June 30, 1999 from $0.7 million for the same period last year, an increase
of 485.7%. The increase is primarily due to a subsidiary of the Company,
Utilipro, which engages in the sale of integrated customer care solutions to
energy marketers. As of June 30, 1998, Utilipro had been in business for only
six months. Utilipro has been a fast growing start up company that has had an
increase in both revenues and expenses over the past year. Because it is a
service company, expenses related to Utilipro are included in other operating
expenses. As a result, there is an increase in operating revenue without a
similar increase in cost of gas, explaining the increase in operating margin for
the three months ended June 30, 1999 as compared with the same period last year.
Other Operating Expenses
- ------------------------
Other operating expenses increased to $95.0 million for the three months ended
June 30, 1999 from $87.4 million for the same period last year, an increase of
8.7%. The components of other operating expenses are as follows (dollars in
millions):
Three Months Ended
------------------
6/30/99 6/30/98 Increase/(Decrease)
------- ------- -----------------
Operations
Utility ................. $ 58.0 $ 54.4 $ 3.6 6.6%
Non-utility ............. 0.8 1.3 (0.5) (38.5%)
------- ------- ------- -------
Total ................... $ 58.8 $ 55.7 $ 3.1 5.6%
======= ======= ======= =======
Maintenance
Utility ................. $ 7.8 $ 7.5 $ 0.3 4.0%
Non-utility ............. 1.9 1.3 0.6 46.2%
------- ------- ------- -------
Total ................... $ 9.7 $ 8.8 $ 0.9 10.2%
======= ======= ======= =======
Depreciation & Amortization
Utility ................. $ 17.2 $ 14.7 $ 2.5 17.0%
Non-utility ............. 2.7 1.5 1.2 80.0%
------- ------- ------- -------
Total ................... $ 19.9 $ 16.2 $ 3.7 22.8%
======= ======= ======= =======
Taxes Other Than Income Taxes
Utility ................. $ 5.8 $ 5.9 $ (0.1) (1.7%)
Non-utility ............. 0.8 0.8 (0.0) (0.0%)
------- ------- ------- -------
Total ................... $ 6.6 $ 6.7 $ (0.1) (1.5%)
======= ======= ======= =======
Total Other Operating Expenses
Utility ................. $ 88.8 $ 82.5 $ 6.3 7.6%
Non-utility ............. 6.2 4.9 1.3 26.5%
------- ------- ------- -------
Total ................... $ 95.0 $ 87.4 $ 7.6 8.7%
======= ======= ======= =======
Utility.
- --------
Utility operations expenses increased $3.6 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.
Page 18 of 41 Pages
<PAGE>
Non-utility.
- ------------
Non-utility operations expenses decreased by approximately $0.5 million as
compared with the same period last year primarily due to a decrease in
operations expenses for SouthStar due to the change from consolidation to the
equity method as described above. (See Operating Revenues -Non-utility.) The
decrease was offset by increased operations expenses for Utilipro resulting from
increased demand for services as discussed above. (See Operating Margin -
Non-utility.) Non-utility depreciation and amortization increased primarily due
to increased depreciable property and increased depreciation rates for AGLR's
data processing equipment as ordered by the GPSC.
Other Income/(Loss)
- -------------------
Other losses totaled $5.6 million for the three months ended June 30, 1999
compared with other income of $0.7 million for the same period last year. The
decrease in other income of $6.3 million is primarily due to:
- Our portion of SouthStar's net start-up costs was approximately $5.1
million for the three months ended June 30, 1999. Those start-up costs are
associated with establishing market share in Georgia's deregulated natural
gas market. Since SouthStar was not formed until July 1998, there was no
income or loss for this joint venture for the three months ended June 30,
1998.
- 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 by Sonat Marketing throughout 1999 associated with changes in
certain accounting estimates. We recorded a pre-tax loss related to our
interest in Sonat Marketing of approximately $0.2 million for the three
months ended June 30, 1999, a decrease of $1.3 million as compared with
pre-tax income of approximately $1.1 million for the same period last year.
(See Note 6, Joint Ventures, to the Condensed Consolidated Financial
Statements.)
Income Taxes
- ------------
Income tax expense increased to $2.3 million for the three months ended June 30,
1999 from an income tax benefit of $3.9 million for the same period last year.
The increase in income taxes of $6.2 million was due primarily to the increase
in income before income taxes compared to the same period last year. The
effective tax rate (income tax expense expressed as a percentage of pretax
income) for the three months ended June 30, 1999 was 24.2% as compared to 76.5%
for the same period last year. The decrease in the effective tax rate was due
primarily to a reduction in certain tax reserves related to the favorable
resolution of certain outstanding tax issues during the three months ended June
30, 1999 and tax benefits associated with the contribution of certain assets to
a private charitable foundation during the three months ended June 30, 1998.
(The remainder of this page was intentionally left blank.)
Page 19 of 41 Pages
<PAGE>
Nine-Month Periods Ended June 30, 1999 and 1998
- -----------------------------------------------
In this section we compare the results of our operations for the nine-month
periods ended June 30, 1999 and 1998.
Nine months Ended
----------------------
6/30/99 6/30/98 Increase/(Decrease)
-------- ---------- --------------------
Operating Revenues
Utility ..... $ 862.6 $ 1,072.7 $ (210.1) (19.6%)
Non-utility . 22.3 52.5 (30.2) (57.5%)
-------- ---------- --------- -------
Total ....... $ 884.9 $ 1,125.2 $ (240.3) (21.4%)
======== ========== ========= =======
Cost of gas
Utility ..... $ 473.7 $ 668.4 $ (194.7) (29.1%)
Non-utility . 6.7 41.4 (34.7) (83.8%)
-------- ---------- --------- -------
Total ....... $ 480.4 $ 709.8 $ (229.4) (32.3%)
======== ========== ========= =======
Operating Margins
Utility ..... $ 388.9 $ 404.3 $ (15.4) (3.8%)
Non-utility . 15.6 11.1 4.5 40.5%
-------- ---------- --------- -------
Total ....... $ 404.5 $ 415.4 $ (10.9) (2.6%)
======== ========== ========= =======
Operating Revenues
- ------------------
Our operating revenues for the nine months ended June 30, 1999 decreased to
$884.9 million from $1,125.2 million for the same period last year, a decrease
of 21.4%.
Utility.
Utility revenues decreased to $862.6 million for the nine months ended June 30,
1999 from $1,072.7 million for the same period last year. The decrease of $210.1
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 $194.7 million. (See discussion
of the utility's cost of gas below regarding the effects of warmer weather
and the migration of customers to marketers.) 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 $16.9 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.)
- 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 previously recorded as a liability. 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
nine months of fiscal 1999, resulting in a $6.3 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.
Page 20 of 41 Pages
<PAGE>
Non-utility.
Non-utility operating revenues decreased to $22.3 million for the nine months
ended June 30, 1999 from $52.5 million for the same period last year. The
decrease of $30.2 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 nine months ended June 30, 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 nine months ended June
30, 1999.
Cost of Gas
- -----------
Our cost of gas decreased to $480.4 million for the nine months ended June 30,
1999 from $709.8 million for the same period last year, a decrease of 32.3%.
Utility.
The utility's cost of gas decreased to $473.7 million for the nine months ended
June 30, 1999 from $668.4 million for the same period last year. The decrease of
$194.7 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 June 30, 1999,
approximately 881,000 customers (approximately 60% 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 27.3%
warmer for the nine months ended June 30, 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 $6.7 million for the nine months ended June
30, 1999 from $41.4 million for the same period last year. The decrease of $34.7
million was primarily due to the change from consolidation to the equity method
for SouthStar as described above. (See Operating Revenues - Non-utility.)
Operating Margin
- ----------------
Our operating margin decreased to $404.5 million for the nine months ended June
30, 1999 from $415.4 million for the same period last year, a decrease of 2.6%.
Utility.
The utility's operating margin decreased to $388.9 million for the nine months
ended June 30, 1999 from $404.3 million for the same period last year. The
decrease of $15.4 million was due primarily to the following factors as
mentioned above under Operating Revenues - Utility:
- The utility's delivery service revenue decreased by $16.9 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 $6.3 million decrease in revenue associated with the phase-out of the
IRP.
Page 21 of 41 Pages
<PAGE>
Non-utility.
Non-utility operating margin increased to $15.6 million for the nine months
ended June 30, 1999 from $11.1 million for the same period last year, an
increase of 40.5%. The increase is primarily due to Utilipro, Inc., which
engages in the sale of integrated customer care solutions and billing services
to energy marketers. At the end of the third quarter in 1998, Utilipro had been
in business for only six months. Utilipro has been a fast growing start up
company that has had an increase in both revenues and expenses over the past
year. Because it is a service company, expenses related to Utilipro are included
in other operating expenses. As a result, there is an increase in operating
revenue without a similar increase in cost of gas, explaining the increase in
operating margin for the nine months ended June 30, 1999 as compared with the
same period last year.
Other Operating Expenses
- ------------------------
Other operating expenses increased to $274.9 million for the nine months ended
June 30, 1999 compared to $270.8 million for the same period last year, an
increase of 1.5%. The components of other operating expenses are as follows
(dollars in millions):
Nine months Ended
--------------------
6/30/99 6/30/98 Increase/(Decrease)
--------- -------- -------------------
Operations
Utility ................. $ 168.9 $ 168.3 $ 0.6 0.4%
Non-utility ............. (2.5) 1.5 (4.0) (266.7%)
--------- -------- ------- --------
Total ................... $ 166.4 $ 169.8 $ (3.4) (2.0%)
========= ======== ======= ========
Maintenance
Utility .................. $ 21.9 $ 23.6 $ (1.7) (7.2%)
Non-utility .............. 5.9 4.3 1.6 37.2%
--------- -------- ------- --------
Total .................... $ 27.8 $ 27.9 $ (0.1) (0.4%)
========= ======== ======= ========
Depreciation & Amortization
Utility ................. $ 50.9 $ 46.4 $ 4.5 9.7%
Non-utility ............. 8.9 5.3 3.6 67.9%
--------- -------- ------- --------
Total ................... $ 59.8 $ 51.7 $ 8.1 15.7%
========= ======== ======= ========
Taxes Other Than Income Taxes
Utility ................. $ 18.5 $ 19.0 $ (0.5) (2.6%)
Non-utility ............. 2.4 2.4 0.0 0.0%
--------- -------- ------- --------
Total ................... $ 20.9 $ 21.4 $ (0.5) (2.3%)
========= ======== ======= ========
Total Other Operating Expenses
Utility ................. $ 260.2 $ 257.3 $ 2.9 1.1%
Non-utility ............. 14.7 13.5 1.2 8.9%
--------- -------- ------- --------
Total ................... $ 274.9 $ 270.8 $ 4.1 1.5%
========= ======== ======= ========
Utility.
Utility operations expenses increased primarily due to the increased demand for
customer services caused by the more rapid than expected pace of customer
migration. Utility depreciation and amortization expenses increased primarily
due to increased depreciable property and increased depreciation rates for AGLC
ordered by the GPSC.
Page 22 of 41 Pages
<PAGE>
Non-utility.
Non-utility operations expenses decreased primarily due to a decrease in
operation expenses for SouthStar resulting from the change from consolidation to
the equity method as described above under non-utility operating revenues. This
decrease was offset by Utilipro's increase in operation expenses of $5.5 million
to $6.4 million for the nine months ended June 30, 1999 from $0.9 million for
the same period last year. This increase was due to increased demand for
services provided by Utilipro as discussed above. (See Operating Margin
- -Non-utility.) Non-utility depreciation and amortization expenses increased
primarily due to increased depreciable property and increased depreciation rates
for AGLR's data processing equipment ordered by the GPSC.
Other Income/(Loss)
- -------------------
Other losses totaled $13.7 million for the nine months ended June 30, 1999
compared with other income of $8.8 million for the same period last year. The
decrease in other income of $22.5 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 by Sonat Marketing throughout 1999 associated with changes in
certain accounting estimates. We recorded a pre-tax loss related to our
interest in Sonat Marketing of approximately $8.1 million for the nine
months ended June 30, 1999, a decrease of $13.8 million as compared with
pre-tax income of approximately $5.7 million for the same period last year.
(See Note 6, Joint Ventures, to the Condensed Consolidated Financial
Statements.)
- Our portion of SouthStar's net start-up costs was approximately $8.4
million for the nine months ended June 30, 1999. Those start-up costs are
associated with establishing market share in Georgia's deregulated natural
gas market. Since SouthStar was not formed until July 1998, there was no
income or loss for this joint venture for the nine months ended June 30,
1998.
Income Taxes
- ------------
Income taxes decreased to $23.3 million for the nine months ended June 30, 1999
from $37.3 million for the same period last year. The decrease in income taxes
of $14.0 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 nine months ended June 30,
1999 was 33.0% as compared to 34.9% for the same period last year. The decrease
in the effective tax rate was due primarily to a reduction in certain tax
reserves related to the favorable resolution of certain outstanding tax issues.
(The remainder of this page was intentionally left blank.)
Page 23 of 41 Pages
<PAGE>
Financial Condition
Seasonality of Business
- -----------------------
Historically, the utility business was seasonal in nature and resulted in a
substantial increase in accounts receivable from customers from September 30 to
June 30 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 June 30
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.)
Accounts receivable decreased $21.6 million and inventory of natural gas stored
underground decreased $80.7 million during the nine months ended June 30, 1999.
Accounts receivable decreased primarily due to the assignment of the Company's
end-use customers to marketers. The assignment causes accounts receivable to
decrease because the Company no longer bills the gas cost component. Similarly,
natural gas stored underground decreased during the nine-month period ended June
30, 1999 primarily due to the assignment of natural gas inventories to marketers
in accordance with deregulation.
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 June 30, 1999 from
$76.5 million as of September 30, 1998. Typically, we borrow and repay the loans
within a month. The decrease in short-term debt is primarily due to the
assignment of natural gas inventories to marketers in accordance with
deregulation. We are less reliant on the use of short-term debt because we are
no longer building those inventories. We generated operating cash flow of $190.1
million for the nine months ended June 30, 1999 as compared to $197.5 million
for the same period last year.
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.
Transition to Competition
- -------------------------
The regulatory framework under which AGLC is unbundling its gas sales and
delivery service assumes that AGLC's costs associated with providing customer
service decrease each time a customer switches to a marketer for gas sales
service, and that such costs are eliminated at the time the switch is made. This
framework therefore reduces the per customer revenue collected by AGLC in the
month following the transfer by a customer to a marketer. However, AGLC's
experience has been that a significant portion of the costs associated with
customer service activities cannot be eliminated immediately after a customer
switch is made as is assumed by the regulatory framework. Rather, there is a
period of up to several months during which AGLC continues to incur these
customer service expenses, which include, for example, remittance processing and
collection services. As a result, a disparity now exists between the rate at
which AGLC is actually reducing costs and the rate at which AGLC is assumed for
regulatory purposes to be reducing costs. This disparity has been exacerbated by
the rapid pace at which customers have switched to marketers.
Page 24 of 41 Pages
<PAGE>
The accelerated pace of customer migration to marketers also has required AGLC
to incur additional customer service expense, not originally projected, in order
to maintain an adequate level of customer service during the transition to
competition. In particular, beginning in October 1998, and continuing each month
thereafter, the number of calls handled by AGLC's customer call centers has
significantly exceeded the number of calls handled by the call centers during
the same months of the preceding year. This increase in call center volumes has
required AGLC to increase its customer service representative staff and increase
other call center related expenses rather than reduce them, despite the fact
that at June 30, 1999, AGLC had approximately 60% fewer gas sales service
customers than it did at June 30, 1998.
The transition to competition will be complete on September 30, 1999. Absent
some change in the regulatory framework, effective October 1, 1999, AGLC's
annual revenues associated with providing delivery service will be reduced by
approximately $43 million, and associated costs likely will not be reduced by
the same amount, resulting in an adverse effect on net income. The impact of the
revenue and cost imbalance related to the transition to competition will
continue into fiscal year 2000.
AGLC is pursuing solutions to this revenue and cost imbalance aggressively,
including reducing or eliminating costs as quickly as possible consistent with
prudent business practices and increasing employee productivity at customer call
centers. AGLC also is pursuing regulatory alternatives for additional cost
recovery. The Deregulation Act authorizes an electing distribution company, like
AGLC, to recover prudently incurred costs that are "stranded" as a result of the
transition to competition. On June 25, 1999, AGLC filed a request with the GPSC
for an accounting order which, if approved, would allow AGLC to defer transition
costs for future consideration by the GPSC. The Company cannot predict the
outcome of this or any other regulatory filing.
Capital Expenditures
- --------------------
Capital expenditures for construction of distribution facilities, purchase of
equipment, and other general improvements were $96.8 million for the nine-month
period ended June 30, 1999 as compared to $85.5 million for the nine month
period ended June 30, 1998. The increase of $11.3 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 nine months ended June 30, 1999, we issued 521,358 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 $9.9 million.
Termination of LESOP
- --------------------
We terminated our Leveraged Employee Stock Ownership Plan (LESOP) and
distributed the value of participants' LESOP account balances as of June 15,
1999. At the election of the participants, we distributed 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, which was $18.50 per
share.
Page 25 of 41 Pages
<PAGE>
During the quarter ended June 30, 1999, 868,688 LESOP shares were repurchased in
cash by the Company from the LESOP trustee in a non-brokered transaction at a
purchase price of $18.50 per share, and are held by AGL Resources as treasury
shares.
Ratios
- ------
As of June 30, 1999, our capitalization ratios consisted of:
- 47.8% long-term debt;
- 5.4% preferred securities; and
- 46.8% common equity.
Gas Cost Credits
- ----------------
For the nine months ended June 30, 1999, the Company has received revenues in
excess of purchased gas costs of $42.7 million. In accordance with the January
26, 1999 joint stipulation agreement entered into with the GPSC, we have
recognized profits of $1.0 million and have recorded a liability of $41.7
million under the caption "Gas Cost Credits." (See Note 2, Impact of New
Regulatory Rate Structure and Deregulation, to the Condensed Consolidated
Financial Statements.)
Sale of Joint Venture Interests
On July 29, 1999, the Company and Sonat entered into an agreement pursuant to
which Sonat agreed to purchase the Company's interest in Sonat Marketing for
$40.0 million and its interest in Sonat Power Marketing for $25.0 million. Under
the terms of the agreement, upon the completion of each transaction, the
applicable joint venture agreement will be amended to provide that the Company
will not be allocated any gain or loss from the joint venture for any period
subsequent to June 30, 1999. The sale of the Company's interest in Sonat
Marketing was completed on August 12, 1999. Completion of the sale of the
Company's interest in Sonat Power Marketing is subject to, among other things,
approval of the Federal Energy Regulatory Commission under Section 203 of the
Federal Power Act. The Company expects the sale of its interest in Sonat Power
Marketing to close by the end of 1999.
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 is unbundling, or separating, all services
to its natural gas customers in Georgia; allocating delivery capacity to
approved marketers who sell the gas commodity to residential and small
commercial users; and creating 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.
Page 26 of 41 Pages
<PAGE>
State Regulatory Activity (Continued)
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. Effective November 1, 1998, marketers began selling
natural gas services at market prices to Georgia customers.
As of June 30, 1999, more than 881,000 residential and small commercial
customers had elected to purchase natural gas services from certificated
marketers in Georgia. As of August 10, 1999, more than 1.1 million residential
and small commercial customers had elected to purchase natural gas services from
those same marketers, an increase of approximately 219,000 customers, or 25%,
since June 30, 1999. On June 25, 1999, AGLC filed a request with the GPSC for an
accounting order which, if approved, would allow AGLC to defer transition costs
for future consideration by the GPSC. The Company cannot predict the outcome of
this or any other regulatory filing. (See discussion above under Financial
Condition - Transition to Competition.)
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.
Page 27 of 41 Pages
<PAGE>
State Regulatory Activity (Continued)
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 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 June
30, 1999, the Company has received revenues in excess of costs of $42.7 million.
As of June 30, 1999, the Company has recognized profits of $1.0 million and has
recorded a regulatory liability of $41.7 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 the opportunity for an additional element of
diversification and price stability. The financial results of all hedging
activities were passed through to residential and small commercial customers
under the PGA mechanism of AGLC's rate schedules. Accordingly, the hedging
program did not affect our earnings.
During the first quarter of fiscal 1999, AGLC entered into certain hedge
agreements that 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 nine month period ended June
30, 1999, AGLC spent approximately $34.2 million related to the pipeline
replacement program.
Page 28 of 41 Pages
<PAGE>
State Regulatory Activity (Continued)
Environmental
- -------------
Before natural gas was widely available in the Southeast, AGLC manufactured gas
from coal and other fuels. Those manufacturing operations were known as
"manufactured gas plants", or "MGPs" which AGLC ceased operating in the 1950s.
Because of recent environmental concerns, we are required to investigate
possible contamination at those plants and, if necessary, clean up any
contamination. Additional information relating to environmental matters and
disclosures is contained below in the section entitled "Environmental Matters"
and above in Note 7, Environmental Matters, to the Condensed Consolidated
Financial Statements.
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 a regulatory asset in the same amount as our
investigation and cleanup liability. The second way we can recover costs is by
exercising the legal rights we believe we have to recover a share of our costs
from other potentially responsible parties - typically former owners or
operators of the MGP sites. We have been actively pursuing those recoveries.
There were no material recoveries during the quarter ended June 30, 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 $105.5 million. As of June 30, 1999, approximately $100.5 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.
Under the Southern settlement, the utility's share of Southern's transition
costs is approximately $87.3 million, of which the utility had incurred $87.1
million as of June 30, 1999. Under the Tennessee settlement, the utility's share
of Tennessee's transition costs was approximately $14.7 million, all of which
had been incurred by the utility as of June 30, 1999.
FERC Rate Proceedings.
- ----------------------
The parties have sought a rehearing of the FERC's April 16, 1999 order allowing
Transcontinental Gas Pipe Line Corporation (Transco) 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, and therefore the order is not yet final.
SouthCoast.
- -----------
Several parties have filed protests to Transco's April 29, 1999 application to
construct facilities to provide service to several customers, including AGLC,
beginning November 1, 2000. The protestors challenge the need for the proposed
facilities, as well as Transco's proposal to roll the costs of the facilities
into its general system rates. Transco's application is pending before the FERC.
Page 29 of 41 Pages
<PAGE>
Federal Regulatory Activity (Continued)
Waiver Request.
- ---------------
On July 31, 1998, the FERC granted to AGLC certain waivers and a limited
jurisdiction blanket certificate to enable AGLC to make certain interstate
pipeline services available to marketers pursuant to the requirements of
Georgia's Natural Gas Competition and Deregulation Act. The authorizations
granted in the July 31 order are due to expire October 31, 1999.
On June 22, 1999, AGLC filed with the FERC a request for extension of the FERC
authorizations through the earlier of March 31, 2003, or the time that the
affected interstate pipeline services either expire or become directly
assignable to marketers. The FERC has granted the request; however, the
extension is only for 17 months subsequent to October 31, 1999. Therefore, the
extension will expire on March 31, 2001.
Environmental Matters
Before natural gas was widely available in the Southeast, AGLC manufactured gas
from coal and other fuels. Those manufacturing operations were known as
"manufactured gas plants", or "MGP's" which AGLC ceased operating in the 1950s.
Because of recent environmental concerns, we are required to investigate
possible environmental contamination at those plants and, if necessary, clean up
any contamination.
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 have estimated our share of the likely costs of
investigation and cleanup. We used the following process for 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 $102.4 million and $148.2
million. That range does not include other potential expenses, such as
unasserted property damage or personal injury 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 $102.4 million, as
a liability and a corresponding regulatory asset as of June 30, 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.
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 a regulatory asset in the same amount as our
investigation and cleanup liability.
Page 30 of 41 Pages
<PAGE>
Environmental Matters (Continued)
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 June 30, 1999.
(The remainder of this page was intentionally left blank.)
Page 31 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure
The widespread use by governments and businesses, including us, of computer
software that relies on two digits, rather than four digits, to define the
applicable year may cause computers, computer-controlled systems, and equipment
with embedded software to malfunction or incorrectly process data as we approach
and enter the year 2000.
Our Year 2000 Readiness Initiative
- ----------------------------------
In view of the potential adverse impact of the "Year 2000" issue on our
business, operations, and financial condition, we have established a
cross-functional team to coordinate, and to report to management on a regular
basis about, our assessment, remediation planning, and plan implementation
processes directed to Year 2000. We also have engaged independent consultants to
assist us in the assessment, remediation, planning, and implementation phases of
our Year 2000 initiative. Our Year 2000 initiative is proceeding on a schedule
that management believes will achieve Year 2000 readiness.
The mission of our Year 2000 initiative is to define and provide a continuing
process for assessment, remediation planning, and plan implementation to achieve
a level of readiness that will meet the challenges presented to us by the Year
2000 in a timely manner. Achieving Year 2000 readiness does not mean correcting
every Year 2000 limitation. Achieving Year 2000 readiness does mean that
critical systems, critical electronic assets, and relationships with key
business partners have been evaluated and are expected to be suitable for
continued use into and beyond the Year 2000, and that contingency plans are in
place.
Our Year 2000 readiness initiative involves a three-phase process. The
initiative is a continuing process with all phases of the initiative progressing
concurrently with respect to 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.
Page 32 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure (Continued)
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 are addressing the Year 2000 readiness of those
joint ventures using the same processes we are using 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. 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 assessment of the
readiness of SouthStar's two joint venture partners is underway. We have
obtained information or responses from a majority of SouthStar's key suppliers.
We are in the process of assessing and following up on responses from certain of
SouthStar's critical suppliers. We are in the process of contacting certain key
customers of SouthStar with respect to their Year 2000 readiness. We have
completed the preparation and review of contingency plans for SouthStar.
Management expects SouthStar's business and operations to achieve Year 2000
readiness. With respect to Utilipro, the Year 2000 initiative commenced in
January of 1999. We have completed the project plan and assessment phase for the
Utilipro Year 2000 initiative. We have completed the remediation planning phase
for Utilipro. Utilipro has engaged independent consultants to assist with its
Year 2000 initiative. The mission and processes of the Year 2000 initiative of
Utilipro are essentially identical to those of the AGL Resources' Year 2000
initiative. 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 81 IT applications. We deem 14 of those 81 applications to be
critical applications. The results of our Year 2000 initiative with respect to
IT applications indicate that, to date:
- 53 applications now are ready for Year 2000, including all critical
applications;
- One application is in remediation for purposes of correcting noncompliant
Year 2000 code;
- Nine applications have been eliminated;
- Nine applications have been replaced; and
- Nine applications are scheduled for 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:
Page 33 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure (Continued)
- 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 have completed implementation of our remediation plans
for critical infrastructure and non-IT applications, 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.
- Mainframe - Last quarter we reported that we plan to outsource the
operation of our mainframe functions in order to increase operating
capacity and efficiency. However, recently we have decided not to outsource
until after January 1, 2000. We plan to install additional mainframe
capacity for the months prior to outsourcing. The vendor of the new
mainframe hardware represents that the hardware is Year 2000 ready. We plan
to complete the Year 2000 readiness testing of the mainframe system
software by September 30, 1999.
- LNG Plants - The infrastructure and non-IT applications of one of our four
plants is Year 2000 ready. In an effort to increase operating efficiency,
we are in the process of centralizing the integrated control systems of our
three other 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. We have received responses
from the majority of suppliers and manufacturers we contacted. To date, we have
completed follow-up with 100% of those suppliers that we consider to be critical
suppliers. We plan to continue to update our assessment of the readiness of
critical suppliers during the remainder of 1999. 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. We have begun following up with critical customers and expect
to continue to follow-up as needed throughout the remainder of 1999. In light of
deregulation, the expected focus of our follow-up effort will be on our gas
marketer customers. We also plan to use industry analysts' predictions to
forecast the most reasonably likely worst case scenario with respect to any
potential revenue impact related to customers.
Page 34 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure (Continued)
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
certain 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
June 30, 1999, our cumulative expenses in connection with our Year 2000
assessment, remediation planning, and plan implementation processes were
approximately $5.4 million. Of this total, $2.3 million was spent in fiscal
years 1997 and 1998. Through June 30, 1999, we had spent an additional $8
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 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. In addition, we expect to spend $0.3 million for the
Year 2000 initiative in fiscal year 2000. These estimates include costs
associated with the use of outside consultants as well as hardware and software
costs. They also include 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 and Utilipro, 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 which would normally be
expensed in accordance with generally accepted accounting principles and that
are attributable to AGLC. Going forward, we estimate that approximately 92% of
our Year 2000 costs will be attributable to AGLC. At June 30, 1999, AGLC had
deferred total costs of approximately $3.7 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.
Page 35 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure (Continued)
Risks of Year 2000 Issues
- -------------------------
We recently finalized our most reasonably likely and worst case Year 2000
estimates. These estimates 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 and worst case estimates,
the process of refining our most reasonably likely and worst case estimates will
be an ongoing process. We expect to continue to develop and modify our most
reasonably likely and worst case estimates 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 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. Our contingency planning effort focused on our potential internal
risks as well as potential risks associated with our suppliers and customers.
Our most reasonably 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 have completed initial testing of our contingency plans. During the remainder
of calendar year 1999, we plan to update, refine and further 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.
Page 36 of 41 Pages
<PAGE>
Year 2000 Readiness Disclosure (Continued)
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, 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 actual results to differ materially from
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.
(The remainder of this page was intentionally left blank.)
Page 37 of 41 Pages
<PAGE>
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 June 30, 1999) would not have a material effect on our results of
operations or financial condition over the next 12 months. 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.
(The remainder of this page was intentionally left blank.)
Page 38 of 41 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
None.
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."
(The remainder of this page was intentionally left blank.)
Page 39 of 41 Pages
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 Executive Compensation Plans and Arrangements
10.1.a Early Retirement Agreement in substantially the form entered
into between AGL Resources Inc. and two of its executive
officers.
10.2 Precedent Agreement between Transcontinental Gas Pipe Line
Corporation and Atlanta Gas Light Company for Firm
Transportation Service on the proposed SouthCoast Expansion
Project.
27 Financial Data Schedule.
(b) Reports on Form 8-K.
On July 30, 1999, AGL Resources filed a Current Report on Form 8-K
dated July 29, 1999, containing : "Item 7 - Exhibits"; Exhibit 99 -
Form of Press Release, dated July 29, 1999.
(The remainder of this page was intentionally left blank.)
Page 40 of 41 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 August 13, 1999 /s/ J. Michael Riley
J. Michael Riley
Senior Vice President
and Chief Financial Officer
(Principal Accounting and
Financial Officer)
Page 41 of 41 Pages
<PAGE>
Exhibit Index
10.1.a Early Retirement Agreement in substantially the form entered
into between AGL Resources Inc. and
two of its executive officers.
10.2 Precedent Agreement between Transcontinental Gas Pipe Line
Corporation and Atlanta Gas Light Company for Firm
Transportation Service on the proposed SouthCoast Expansion
Project.
27 Financial Data Schedule.
EARLY RETIREMENT AGREEMENT
This Early Retirement Agreement will confirm the agreement made by and
between __________________________ (herein called "Employee") and AGL RESOURCES
INC. (which, with its affiliates, is herein called "the Company").
The Employee has been employed by the Company for many years and has
provided valuable and loyal service throughout those years. This Early
Retirement Agreement has been offered to the Employee for a period of 45 days
for his consideration. After consultation with his family, legal and financial
counselors, the Employee has determined to terminate his employment with the
Company in exchange for certain early retirement benefits. In consideration of
the mutual benefits to each party, the parties agree as follows:
1. DATE OF EARLY RETIREMENT. The Employee will retire and cease to be an
employee of the Company effective as of _____________ ____, 1999 (the
"Retirement Date"). The Employee's base salary will continue through
_________________ _____, 1999.
2. RETIREMENT BENEFITS. In addition to the retirement benefits to which
the Employee would be entitled based upon his employment through his
Retirement Date, the Employee shall receive the following as additional
consideration, which the Employee acknowledges is significant and
substantial:
(a) AGL Resources Inc. Retirement Plan. On the Retirement Date,
the Employee shall cease to accrue years of service under the
Retirement Plan. He will become eligible to commence receiving
benefit payments under the Retirement Plan in accordance with
the terms of the Retirement Plan.
(b) Supplemental Retirement Benefit. From the Effective Date of
this Agreement until the Employee reaches age 55, the Employee
shall receive a monthly supplement payable from the Company's
general assets, in an amount equal to: (i) the monthly amount
the Employee would be entitled to under the Retirement Plan,
plus (ii) the difference between the amount in (i) and the
amount his monthly benefit would have been under the
Retirement Plan if he had five (5) additional years of age
and five (5) additional Years of Eligibility Service (as
defined in the Retirement Plan). Upon the Employee's
attaining age 55, the monthly supplement will be reduced by
the amount to which the Employee would be entitled under the
Retirement Plan. The payment of this supplemental retirement
benefit will be made in the same form and for the same
duration as selected by the Employee for his benefit under
the Retirement Plan.
(c) Social Security Bridge Payments. The Employee shall also
receive a monthly Social Security bridge payment, payable from
the Company's general assets, in the amount of One Thousand
Three Hundred Dollars ($1,300.00), through and including the
month in which the Employee attains age 62.
(d) Death Benefits. To the extent the form selected by the
Employee for his benefit under the Retirement Plan and the
Supplemental Retirement Benefit provides a survivor benefit,
that benefit will be so paid. If the Employee should die prior
to attainment of age 62, the Social Security bridge payments
shall cease as of the month of death.
<PAGE>
3. WELFARE AND OTHER BENEFITS. Unless otherwise specified below, upon the
Retirement Date, the Employee shall cease to participate in the
Company's employee benefit plans, pursuant to the terms and conditions
of the plan documents.
(a) Retiree Medical and Dental Insurance Coverage.
* If the Employee would have completed 25 years of service with the
Company and/or its Affiliates upon his attainment of age 62 - The
Employee and his dependents that are under age 65 shall receive
coverage under the Company's group retiree medical and dental
plans until the Employee and his spouse (if applicable) each
reach age 65. The cost of the Employee's coverage will be paid by
the Company (or its affiliate that last employed the Employee).
The Employee shall pay premiums for the cost of coverage for his
dependents under the age of 65 at the same rate as other Company
retirees pay for dependent coverage. However, the Company
reserves the right to amend or terminate such group medical and
dental plans at its discretion and reserves the right to change,
increase or decrease the amount of the retiree premiums for this
coverage. The Employee shall, however, continue to be treated
as any other retiree with regard to the coverages and the amounts
of premiums charged for the coverages.
* If the Employee would not have completed 25 years of service with
the Company and/or its Affiliates upon his attainment of
age 62 - The Employee and his dependents shall receive coverage
under the Company's group retiree medical and dental plans. The
Employee shall pay the full cost of his coverage (without any
Company subsidy), and he shall pay premiums for the cost of
coverage for his dependents under the age of 65 at the same rate
as other Company retirees pay for dependent coverage until
the Employee and his spouse (if applicable) each reach age 65.
However, the Company reserves the right to amend or terminate
such group medical and dental plans at its discretion and
reserves the right to change, increase or decrease the amount of
the retiree premiums for this coverage. The Employee shall be
treated as any other Company retiree with regard to the coverages
and the amounts of premiums charged for the coverages.
Upon the Employee's attainment of age 65, coverage under the
Company's plans will coordinate with Medicare, with Medicare
as the primary payor. If the Employee becomes employed by
another employer and becomes covered under that employer's
group health insurance coverage, then that employer's group
health insurance coverage shall be primary (or secondary if he
is then eligible for Medicare), and the Company's retiree
medical/dental coverage shall pay only after those coverages.
(b) Basic Life Insurance. The Company shall continue to pay the
premiums for the Employee's basic life insurance coverage of
$10,000 under the Company's Group Life Insurance Plan, until
the death of the Employee.
(c) GRIP Life Insurance. The Company shall continue to pay the
Employee's premium for coverage under the GRIP plan until the
policy is paid in full (at the later of the date the policy
has been in effect for ten years or the Employee reaches age
65, whichever is later). These premium payments will continue
to be treated as taxable income to the Employee.
(d) Accidental Death & Dismemberment. Coverage under the Company's AD&D
policies shall cease upon the Retirement Date.
(e) Dependent Life Insurance. Coverage on the life of any
dependent of the Employee under the Company's policies and
plans shall cease on the Retirement Date.
(f) Short-Term Disability and Long-Term Disability Insurance.
Coverage under the Company's Short-Term Disability Plan and
Long-Term Disability Plan shall cease upon the Retirement
Date.
(g) Flexible Benefits Plan. The Employee's coverage under the
Company's Flexible Benefits Plan shall cease on the Retirement
Date.
(h) Employee Allowance Fund. The Employee shall continue to
participate in the Employee Allowance Fund for the remainder
of 1999 without proration. The Employee shall reimburse the
Company for any expenses incurred by the Employee in excess of
his Employee Allowance for the year.
(i) Automobile Allowance. If the Employee is leasing an automobile
through the Employee Allowance Fund on the Retirement Date,
the Employee shall be permitted to choose to: (1) assume the
lease on the Retirement Date, (2) return the automobile to the
Company on the Retirement Date, or (3) continue the lease
through the end of 1999 and then either assume the lease or
return the automobile to the Company.
(j) AGL Resources Inc. Retirement Saving Plus Plan and
Nonqualified Savings Plan. Upon the Retirement Date, the
Employee shall cease to participate in the RSP and the NSP. As
soon as practicable after the Retirement Date, the Employee's
total account in the RSP will be payable to him. The
Employee's NSP account will be payable to him after the end of
1999.
(k) AGL Resources Inc. Leveraged Employee Stock Ownership Plan.
The Company has terminated the LESOP. The Employee shall be
eligible to receive a distribution of his account in the LESOP
at the same time as all other accounts in the LESOP are
distributed.
(l) Survivor Support and Survivor Income Plan. The Employee's
coverage under the Company's Survivor Support and Survivor
Income Plan shall cease as of the Retirement Date.
(m) Outplacement Services. The Employee shall be entitled to
certain career transition services, such as planning job
search strategies, evaluating personal strengths and
weaknesses, resume preparation and training in interview
techniques, for a period of up to 12 months through a provider
selected by the Company.
(n) Stock Options and Restricted Stock. The Company shall request
that the Committee administering the Company's Long-Term Stock
Incentive Plan of 1990 extend the operation of the Employee's
outstanding stock options so that vesting may continue to
occur, and once vested, the options shall continue to be
exercisable, until the full term of the option or the
Employee's attaining age 62, whichever is the first to occur.
Any outstanding incentive stock options shall convert to
nonqualified stock options on the date three months following
the Retirement Date. Any outstanding shares of restricted
stock granted to the Employee which are unvested on the
Retirement Date shall be forfeited.
(o) Unused Earned Vacation. As soon as practicable following the
Retirement Date, the Company shall pay the Employee, in a lump
sum, an amount equal to his unused 1999 vacation entitlement.
4. RESTRICTIVE COVENANTS. For and in consideration for the payment and
benefits provided to the Employee under this Early Retirement
Agreement, the Employee agrees to the terms of the following:
(a) Covenant Not to Compete. The Employee covenants and agrees that,
during a period beginning on the Retirement Date and ending one
(1) year thereafter, he will not directly or indirectly, on his
own behalf or on behalf of any person or entity, compete with the
Company by performing activities or duties substantially
similar or related to the functions, activities or duties
performed by the Employee for the Company for any business entity
engaged in direct competition with the Company. A business entity
shall be considered to be "in direct competition" with the Company
if it is engaged in producing, manufacturing, distributing,
marketing, selling, servicing or repairing products similar to
products produced, manufactured, distributed, marketed, sold,
serviced or repaired by the Company, including (but not limited
to) any type of production and distribution of any energy source,
whether by cultivation of natural resources or by technology.
This restriction shall apply only to a restricted territory
within a 100-mile radius of any locations, sites or facilities
in which the Company (including its affiliates) maintains
offices, operations or service contracts or has provided services
during the 12-month period immediately preceding the Retirement
Date.
(b) Nondisclosure and Confidentiality. The Employee acknowledges and
agrees that during the term of his employment, he has had access
to trade secrets and other confidential information unique to
the business of the Company and that the disclosure or
unauthorized use of such trade secrets or confidential information
by the Employee would injure the Company's business. Therefore,
the Employee agrees that he will not, at any time during which he
is receiving any benefits hereunder, use, reveal or divulge any
trade secrets or any other confidential information which, while
not trade secrets or information unique to the Company's business,
is highly confidential and constitutes a valuable asset of the
Company by reason of the material investment of the Company's time
and money in the production of such information. The Employee
agrees that he will not use, reveal or divulge any general
confidential or customer-related information.
(c) Nonsolicitation. Due to the Employee's extensive knowledge of
the specifics of the Company's business, and its customers and
clients, the Employee agrees that during the period he is
receiving payments hereunder, he will not, without the prior
written consent of the Company, either directly or indirectly, on
his own behalf or in the service or on behalf of others, solicit,
divert or appropriate, or attempt to solicit, divert or
appropriate, to any business that competes with the Company's
business any person or entity who transacted business with the
Company during the year preceding the Retirement Date. This
provision shall be specific to any and all persons or entities
with whom the Employee has (i) had direct contact, (ii) been a
party to marketing or sales strategies with regard to, or (iii)
been privy to marketing or sales strategies with regard to such
persons or entities. For purposes of this provision, the
Company's business shall include any and all aspects of producing,
manufacturing, distributing, marketing, selling, servicing or
repairing products similar to products produced, manufactured,
distributed, marketed, sold, serviced or repaired by the Company
and/or any of its affiliates, including (but not limited to) any
type of production and distribution of any energy source,
whether by cultivation of natural resources or by technology.
The Employee agrees that during the period he is receiving
payments and benefits hereunder, he will not, either directly
or indirectly, on his own behalf or in the service or on
behalf of others solicit, divert or hire away, or attempt to
solicit, divert or hire away to any business that competes
with Company's business any person employed by the Company, or
any person employed by the Company at any time during the
period beginning one (1) year prior to the Retirement Date.
5. COOPERATION AFTER RETIREMENT DATE. The Employee agrees to cooperate
fully with the Company during the period that benefits are provided
hereunder and to reasonably assist the Company thereafter on all
matters relating to his employment and the conduct of business,
including any litigation, claim or suit in which the Company deems
that the Employee's cooperation is needed. The Employee also agrees
that during the period that benefits are provided hereunder, the
Employee will make himself available on reasonable notice to furnish
reasonable transition services in the nature of a consultant to the
Company regarding any issues arising from the Employee's employment
and the conduct of business prior to the Retirement Date,
including but not limited to any litigation matters involving the
Company as a party or witness and as to which the Employee possesses
knowledge or information which is relevant to the litigation. The
Company agree to reimburse the Employee for all reasonable
"out-of-pocket" expenses related to provision of the services
referenced in this Paragraph, provided the Employee receives advance
approval of such expenses by the Company's Chief Employee Officer
and provides the Company with receipts and invoices for all such
expenses in accordance with the general expense reimbursement policy.
6. GENERAL RELEASE. The Employee agrees, for himself, his spouse,
heirs, executor or administrator, assigns, insurers, attorneys
and other persons or entities acting or purporting to act on his
behalf, to irrevocably and unconditionally release, acquit and
forever discharge the Company, its affiliates, subsidiaries,
directors, officers, employees, shareholders, partners, agents,
representatives, predecessors, successors, assigns, insurers,
attorneys, benefit plans sponsored by the Company and said plans'
fiduciaries, agents and trustees, from any and all actions, cause of
action, suits, claims, obligations, liabilities, debts, demands,
contentions, damages, judgments, levies and executions of any kind,
whether in law or in equity, known or unknown, which the Employee
has, has had, or may in the future claim to have against the Company
by reason of, arising out of, related to, or resulting from
Employee's employment with the Company or the termination thereof.
This release specifically includes without limitation any claims
arising in tort or contract, any claim based on wrongful discharge,
any claim based on breach of contract, any claim arising under federal,
state or local law prohibiting race, sex, age, religion, national
origin, handicap, disability or other forms of discrimination, any
claim arising under federal, state or local law concerning
employment practices, and any claim relating to compensation or
benefits. This specifically includes, without limitation, any
claim which the Employee has or has had under Title VII of the Civil
Rights Act of 1964, as amended, the Age Discrimination in
Employment Act, as amended, the Americans with Disabilities Act,
as amended, and the Employee Retirement Income Security Act of
1974, as amended. Notwithstanding the provisions of Section XII
hereof, it is understood and agreed that the waiver of benefits and
claims contained in Section XII does not include a waiver of the
right to payment of any vested, nonforfeitable benefits to which
the Employee or a beneficiary of the Employee may be entitled under
the terms and provisions of any employee benefit plan of the Company
which have accrued as of the Retirement Date, and does not include a
waiver of the right to benefits and payment of consideration to which
the Employee may be entitled under this Agreement. The Employee
acknowledges that he is only entitled to the additional benefits
and compensation set forth in this Agreement, and that all other
claims for any other benefits or compensation are hereby waived,
except those expressly stated in the preceding sentence.
7. PENALTIES. In addition to any legal or equitable remedies available to
the Company, including injunctive relief, the Employee agrees and
acknowledges that if he violates any provision of this Early Retirement
Agreement, the Company may immediately cease any and all payments and
benefits payable to the Employee hereunder.
8. REVOCATION PERIOD. For a period of seven (7) days following execution
of this Early Retirement Agreement, the Employee may revoke this Early
Retirement Agreement by sending written notice of revocation by
Certified Mail (return receipt requested) within that period to:
AGL Resources Inc.
303 Peachtree Street
Suite 400
Atlanta, GA 30308
Attn: General Counsel
9. GOVERNING LAW. This Early Retirement Agreement shall be construed in
accordance with, and governed by, the laws of the State of Georgia,
except to the extent that the laws of the United States shall otherwise
apply.
10. ENTIRE AGREEMENT. This Agreement constitutes the entire agreement
between the parties with respect to the subject matter hereof and
supercedes all prior and contemporaneous oral and written agreements
and discussions.
11. EFFECTIVE DATE. For purposes of this Agreement, the "Effective Date" of
this Agreement shall be the date on which this Agreement becomes
effective, which shall be the date which is exactly eight (8) days
following the Execution Date, unless this Agreement has been revoked by
the Employee prior to such date in accordance with the provisions of
this Agreement. The Execution Date shall mean that date on which this
Agreement is executed by the parties.
IN WITNESS WHEREOF, the undersigned have executed this Agreement on the
__________ day of _______________________, 1999.
EMPLOYEE:
-----------------------------------
COMPANY:
AGL RESOURCES INC.
BY:_______________________________
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
PRECEDENT AGREEMENT
THIS PRECEDENT AGREEMENT ("Precedent Agreement") is entered into this
28th day of April 1999, by and between TRANSCONTINENTAL GAS PIPE LINE
CORPORATION ("Transco"), a Delaware corporation, and ATLANTA GAS LIGHT COMPANY
("Shipper). Transco and Shipper are sometimes referred to individually as
"Party" and jointly as "Parties".
WITNESSETH:
WHEREAS, Transco conducted an open season from July 22, 1998 through
August 24, 1998, during which it accepted requests for firm transportation
service to be made available under its SouthCoast Expansion Project
("SouthCoast"); and
WHEREAS, Shipper desires firm transportation service under SouthCoast
for 61,160 dekatherms of gas per day ("dt/d") from the primary receipt point(s)
specified in Exhibit A hereto to the primary delivery point(s) specified in
Exhibit B hereto; and
WHEREAS, subject to the terms and conditions of this Agreement, Transco
is willing to provide such firm transportation service for Shipper under
SouthCoast pursuant to the terms of this Precedent Agreement and the Service
Agreement (as hereinafter defined) commencing as soon as all rights and
regulatory approvals are received and accepted by Transco and all of the
necessary facilities are constructed and ready for service, as further set forth
herein below.
NOW THEREFORE, in consideration of the mutual covenants herein assumed,
Transco and Shipper hereby agree as follows:
<PAGE>
1. Rights and Approvals. Following the execution by Transco and Shipper of this
Precedent Agreement, Transco shall seek such contract rights, property rights,
financing arrangements and regulatory approvals, including, without limitation,
the requisite authorizations from the FERC ("FERC Authorizations"), including
rates based on a rolled-in cost of service, as may be necessary to provide firm
transportation service for Shipper of 61,160 dt/d from point(s) of receipt set
forth in Exhibit A hereto to point(s) of delivery set forth in Exhibit B hereto.
Transco reserves the right to file and prosecute applications for any required
authorizations, any supplements or amendments thereto (including the right at
any time to withdraw any application for required authorizations or not to
accept such authorizations), and, if necessary, court review, in such manner as
it deems to be in its best interest.
Shipper agrees to use its good faith efforts to cooperate with and
support Transco in obtaining the necessary regulatory approvals for SouthCoast
and to provide Transco with any necessary information reasonably requested in
order to obtain the regulatory approvals and financing arrangements for
SouthCoast. In that regard, (i) Shipper shall file with the FERC in support of
Transco's FERC application(s) for NGA Section 7(c) certificate authorization of
SouthCoast, (ii) Shipper shall not oppose any filing made with the FERC (whether
made by Transco or another party) to roll into Transco's systemwide cost of
service (a) the costs of SouthCoast, (b) the costs of the incrementally priced
projects approved by the FERC in Docket Nos. CP96-16, CP97-328, and CP97-331,
and/or (c) the costs of the incrementally priced projects for which rolled-in
rate treatment has been sought in Docket Nos. RP97-71 and RP95-197 (which
include, without limitation, the incrementally priced projects approved by the
FERC in Docket Nos. CP88-92, CP88-760, CP89-6, CP89-7, CP89-710, CP90-687,
CP94-68, and CP94-109), provided, however, that the foregoing shall not
constitute a waiver of Shipper's right to oppose cost allocation and rate design
for rolled-in rate treatment of the incrementally priced projects referred to in
the foregoing clauses (b) and (c), and (iii) to the extent that the FERC
determines that information relating to Shipper's gas supply arrangements or
markets is required from Transco, Shipper shall provide Transco with such
information in a timely manner to enable Transco to respond within the time
required by the FERC. To the extent that such information is considered
confidential, proprietary or privileged by Shipper, Transco and Shipper shall
negotiate in good faith acceptable protective arrangements. 2. Service
Agreement. Within thirty (30) days (or within such shorter time frame as may be
required for timely commencement of construction of SouthCoast) after Transco's
receipt and acceptance of the FERC Authorizations in a form and substance
satisfactory to Transco in its sole opinion, as reasonably determined, Transco
and Shipper shall execute and deliver a service agreement under Transco's Rate
Schedule FT ("Service Agreement") substantially in the form attached as Exhibit
C hereto; provided, however, that neither Party shall be obligated to execute
the Service Agreement if the FERC Authorizations adversely impact the character
of service and/or the receipt and delivery points agreed to in this Precedent
Agreement; provided, further, that the Parties shall not be obligated to execute
the Service Agreement if this Precedent Agreement shall have been previously
terminated in accordance with Paragraph 5 below. The Service Agreement shall
provide for the firm transportation by Transco for Shipper of 61,160 dt/d from
point(s) of receipt set forth in Exhibit A hereto to point(s) of delivery set
forth in Exhibit B hereto. Notwithstanding the Parties' execution of the Service
Agreement, Transco's obligation to provide firm transportation service to
Shipper is expressly made subject to Transco's receipt and acceptance of any
remaining necessary contract rights, property rights, financing arrangements and
regulatory approvals in a form and substance satisfactory to Transco, as
reasonably determined in its sole opinion, and Transco's completion of
construction and placement into service of Transco's facilities necessary to
provide service to Shipper under SouthCoast. 3. Rates. For the firm
transportation service under the Service Agreement, Shipper shall pay the
maximum reservation rate and all applicable commodity charges, reservation and
commodity surcharges and fuel applicable under Transco's Rate Schedule FT for
SouthCoast firm transportation service unless otherwise agreed to by the
Parties. 4. Service and Reservation Charge Commencement; Term of Service. The
firm transportation service for Shipper under SouthCoast and Shipper's
obligation to pay Transco reservation charges for such service shall commence on
the later of: (i) November 1, 2000; or (ii) the date on which Transco's
facilities necessary to provide firm service to Shipper under SouthCoast have
been constructed and are ready for service as reasonably determined in Transco's
sole opinion. Such firm transportation service shall continue for a primary term
of fifteen (15) years from the date that the firm transportation service
commences, and year-to-year thereafter subject to termination after such primary
term by either Party upon one (1) year prior written notice to the other Party.
5. Termination of Agreements. If the FERC has not issued a preliminary
determination on non-environmental issues by May 1, 2000 or if Transco has not
received and accepted the necessary FERC Authorizations on or before November 1,
2000, then at any time thereafter until Transco receives and accepts such FERC
Authorizations, either Party shall have the right to terminate this Precedent
Agreement and Service Agreement by giving thirty (30) days advance written
notice to the other Party; provided, however, that such termination shall not be
effective if during the 30-day period Transco receives and accepts the necessary
FERC Authorizations. Further, if as a result of orders or actions taken by the
Georgia Public Service Commission ("PSC"), Shipper concludes, in Shipper's sole
opinion, as reasonably determined, that Shipper's ability to include the firm
transportation service from the SouthCoast Expansion project in its array of
capacity supply contracts is at unreasonable risk, then Shipper may terminate
this Precedent Agreement by giving twenty-four (24) hours advance written notice
to Transco: provided that such right to terminate must be exercised on or before
September 1, 1999 or such right shall be waived. Additionally, if Transco has
not commenced the firm transportation service contemplated herein to Shipper on
or before November 1, 2001, either Party shall have the right to terminate this
Precedent Agreement and the Service Agreement by giving twenty-four (24) hours
advance written notice to the other Party; provided that such right must be
exercised on or before November 15, 2001, or else such right shall be waived.
Termination of this Precedent Agreement and/or the Service Agreement in
accordance with the terms of this Paragraph 5 shall be without liability for
costs or expenses to the terminating Party or its partners, shareholders,
officers, employees or agents. 6. Construction. After both Parties' execution of
the Service Agreement pursuant to Paragraph 2 above and Transco's receipt and
acceptance of all other necessary contract rights, property rights, financing
arrangements and regulatory approvals in a form and substance satisfactory to
Transco, as reasonably determined in its sole opinion, Transco shall proceed
with the construction of the SouthCoast facilities so as to begin firm
transportation service for Shipper by a proposed in-service date of November 1,
2000. If Transco is unable to complete such construction and place such
facilities into operation by such proposed in-service despite its exercise of
due diligence, Transco shall provide notice thereof to Shipper, with such notice
including the revised projected in-service date unless Shipper has exercised its
right to terminate in accordance with Paragraph 5 above, and shall continue to
proceed with due diligence to complete such construction, place such facilities
in operation and commence service for Shipper at the earliest practicable date
thereafter. Transco shall not be liable in any manner to Shipper, nor shall this
Precedent Agreement or the Service Agreement be subject to termination, except
as provided in Paragraph 5 above, if despite Transco's exercise of due
diligence, Transco is unable to complete the construction of such facilities and
commence firm transportation service contemplated herein by the proposed
in-service date. 7. Prepayment Refund. Transco and Shipper agree that the
$10,000 prepayment submitted by Shipper during the open season for SouthCoast
plus any interest that accrues on the prepayment amount (any interest on the
prepayment amount calculated hereunder shall be at the interest rate set forth
in the billing and payment provisions of the General Terms and Conditions of
Transco' FERC Gas Tariff) prior to the in-service date of the project will be
applied to Shipper's reservation charges due for the first month of firm
transportation service under the project. In the event that service commences on
a date other than the first day of the month, the reservation charge will be
prorated and the prepayment plus accrued interest will be applied to such
prorated reservation charge. In the event that Shipper terminates this Precedent
Agreement pursuant to Paragraph 5 above, Transco shall refund Shipper's
prepayment plus accrued interest. 8. Remedies. Shipper recognizes that Transco
will be required to incur material expenses to construct SouthCoast facilities
by a proposed in-service date of November 1, 2000. In the event that Shipper
fails to perform its obligations under this Precedent Agreement or terminates
this Precedent Agreement in a manner inconsistent with Paragraph 5 above,
Transco shall have the right to retain Shipper's prepayment (plus accrued
interest) made in accordance with Shipper's request for firm transportation
service under SouthCoast and to seek any other legal remedies available to
Transco, provided that any such legal remedy which is a monetary remedy shall be
reduced by an amount equal to the prepayment (plus accrued interest) retained by
Transco. 9. Notices Notices under this Precedent Agreement shall be in writing
and shall be addressed as follows:
If to Shipper:
Vice President, Gas Services
Atlanta Gas Light Company
1219 Caroline Street, NE
Atlanta, GA 30307
Fax: 404/584-3499
Email: [email protected]
If to Transco:
Transcontinental Gas Pipe Line Corporation
2800 Post Oak Boulevard
P.O. Box 1396
Houston, Texas 77251-1396
Attention: Vice President, Customer Service and Rates
Fax: 713/215-2549
Notices may be given by hand, electronic transmission, mail or courier. Notices
shall by deemed given upon the date the notice is sent. Either Party may change
its address or telecopy number for notices hereunder by providing written notice
of such change to the other Party. 10. Assignment. This Precedent Agreement
shall be binding upon, and shall inure to the benefit of, the parties hereto and
their respective successors, whether successors shall succeed to the business
and operation of the parties by share purchase, share exchange, merger,
consolidation or otherwise. 11. Governing Law. This Precedent Agreement and any
actions, claims, demands or settlements hereunder shall be governed by and
construed in accordance with the laws of the State of Texas, excluding, however,
any conflicts of law, rules or principles which might require the application of
the laws of another jurisdiction. 12. Third Persons. Except as expressly
provided in this Precedent Agreement, nothing herein expressed or implied is
intended or shall be construed to confer upon or to give any person not a Party
hereto any rights, remedies or obligations under or by reason of this Precedent
Agreement. 13. Laws and Regulatory Bodies. This Precedent Agreement and the
obligations of the Parties hereunder are subject to all applicable laws, rules,
orders and regulations of governmental authorities having jurisdiction and, in
the event of conflict, such laws, rules, orders and regulations of governmental
authorities having jurisdiction shall control. 14. Captions. The titles to each
of the paragraphs in this Precedent Agreement are included for convenience of
reference only and shall have no effect on, or be deemed as part of the text of,
this Precedent Agreement. 15. Severablity. Any provision of this Precedent
Agreement that is prohibited or unenforceable in any jurisdiction shall, as to
that jurisdiction, be ineffective to the extent of that prohibition or
unenforceablity without invalidating the remaining provisions hereof or
affecting the validity or enforceability of that provision in any other
jurisdiction. 16. Waiver. No waiver by either Party of any default by the other
Party in the performance of any provision, condition or requirement herein shall
be deemed to be a waiver of, or in any manner release the other Party from,
performance of any other provision, condition or requirement herein, nor shall
such waiver be deemed to be a waiver of, or in any manner release the other
Party from, future performance of the same provision, condition or requirement.
Any delay or omission of either Party to exercise any right hereunder shall not
impair the exercise of any such right, or any like right, accruing to it
thereafter. 17. Further Assurances. Each Party agrees to execute and deliver all
such other and additional instruments and documents and to do such other acts as
may be reasonably necessary to effectuate the terms and provisions of this
Precedent Agreement. 18. Joint Preparation. The terms, conditions and provisions
of this Precedent Agreement shall be considered as prepared through the joint
efforts of the Parties and shall not be construed against either Party as a
result of the preparation or drafting thereof.
IN WITNESS WHEREOF, duly authorized representatives of the Parties have executed
this Precedent Agreement as of the date first above written.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
By /s/ Frank J. Ferazzi
Frank J. Ferazzi
Vice President
Customer Service and Rates
ATLANTA GAS LIGHT COMPANY
B /s/ James W. Scabareti
James W. Scabareti
Vice President, Gas Services
<PAGE>
EXHIBIT A
Receipt Point(s) Maximum Daily Quantity at
Each Receipt Point1 (dt/d)
Point of Interconnection between
Transco's mainline and Mobile Bay 61,160
Lateral at milepost 784.66 in Choctaw
County, Alabama
<PAGE>
Exhibit B
Delivery Point(s) Maximum Daily Quantity at Each
Suwanee Delivery Point in Gwinnett Delivery Point (dt/d)
County , Georgia
61,160
<PAGE>
Exhibit C
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
Buyer
<PAGE>
SERVICE AGREEMENT
THIS AGREEMENT entered into this ____ day of ___________, 19___, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware Corporation,
hereinafter referred to as "Seller," first party, and _______________,
hereinafter referred to as "Buyer," second party,
WITNESSETH
WHEREAS.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Seller's
Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to
Seller gas for transportation and Seller agrees to receive, transport
and redeliver natural gas to Buyer or for the account of Buyer, on a
firm basis, a Transportation Contract Quantity ("TCQ") of ______ dt per
day (at Seller's system BTU as of the date of this Agreement and as
provided in Section 23(b) of the General Terms and Conditions of
Seller's FERC Gas Tariff) per day.
2. Transportation service rendered hereunder shall not be subject to
curtailment or interruption except as provided in Section 11 of the
General Terms and Conditions of Seller's FERC Gas Tariff.
Article II
Point(s) of Receipt
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt
hereunder at a pressure sufficient to allow the gas to enter Seller's pipeline
system at the varying pressures that may exist in such system from time to time;
provided, however, the pressure of the gas delivered or caused to be in the
event the maximum operating pressure(s) of Seller's pipeline system, at the
point(s) of receipt hereunder, is from timeto time increased or decreased, then
the maximum allowable pressure(s) of the gas delivered or caused to be delivered
by Buyer to Seller at the point(s) of receipt shall be correspondingly increased
or decreased upon written notification of Seller to Buyer. The point(s) of
receipt for natural gas received for transportation pursuant to this agreement
shall be:
See Exhibit A, attached hereto, for point(s) of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas transported
hereunder at the following point(s) of delivery and at a pressure(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of _____ __, 19__ and shall remain
in force and effect until 9:00 a.m. Central Clock Time _____ __, 20__ and year
to year thereafter until terminated by Seller or Buyer upon at least one (1)
years' written notice; provided, however, this agreement shall terminate
immediately and, subject to the receipt of necessary authorizations, if any,
Seller may discontinue service hereunder if (a) Buyer, in Seller's reasonable
judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide
adequate security in accordance with Section 32 of the General Terms and
Conditions of Seller's Volume No. 1 Tariff. As set forth in Section 8 of Article
II of Seller's August 7, 1998 revised Stipulation and Agreement in Docket No.
RP88-68 et. al., (a) pregranted abandonment under Section 284.221 (d) of the
Commission's Regulations shall not apply to any long term conversions from firm
sales service to transportation service under Seller's Rate Schedule FT and (b)
Seller shall not exercise its right to terminate this service agreement as it
applies to transportation service resulting from conversions from firm sales
service so long as Buyer is willing to pay rates no less favorable than Seller
is otherwise able to collect from third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder
in accordance with Seller's Rate Schedule FT and the applicable provisions of
the General Terms and Conditions of Seller's FERC Gas Tariff as filed with the
Federal Energy Regulatory Commission, and as the same may be legally amended or
superseded from time to time. Such Rate Schedule and General Terms and
Conditions are by this reference made a part hereof. In the event Buyer and
Seller mutually agree to a negotiated rate and specified term for service
hereunder, provisions governing such negotiated rate (including surcharges) and
term shall be set forth on Exhibit C to the service agreement.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers
or causes to be delivered to Seller shall include the quantity of gas retained
by Seller for applicable compressor fuel, line loss make-up (and injection fuel
under Seller's Rate Schedule GSS, if applicable) in providing the transportation
hereunder, which quantity may be changed from time to time and which will be
specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff
which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation
service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall
reimburse Seller for any and all filing fees incurred as a result of Buyer's
request for Service under Seller's Rate Schedule FT, to the extent such fees are
imposed upon Seller by the Federal Energy Regulatory Commission or any successor
governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date
hereof the following contract(s) between parties hereto: None.
2. No waiver by either party of any one or more defaults by the other
in the performance of any provisions of this agreement shall operate or be
construed as a waiver of any future default or defaults, whether of a like of
different character.
3. The interpretation and performance of this agreement shall be in
accordance with the laws of the State of Texas, without recourse to the law
governing conflicts of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of
the parties' hereto and there respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered
as duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
2800 Post Oak Boulevard (77056)
P.O. Box 1396
Houston, Texas, 77251-1396
Attention:
(b) If to Buyer
Such addresses may be changed from time to time by mailing appropriate
notice thereof to the other party by certified or registered mail.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be
signed by their respective officers or representatives thereunto duly
authorized.
<PAGE>
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Seller)
By:_________________________________________
Name:
Title:
(Buyer)
By:_________________________________________
Name:
Title:
<PAGE>
Exhibit A
Point(s) of Receipt Maximum Daily Quantity
at Each Receipt Pt. (dt/d)1
<PAGE>
Exhibit B
Point(s) of Delivery and Pressures2 Maximum Daily Quantity
at Each Delivery Pt. (Dt/d)3
<PAGE>
Exhibit C
Specifications of Negotiated Rate and Term
- --------
1 These quantities do not include the additional quantities of gas to
be retained by Transco for compressor fuel and line loss make-up.
Therefore, Shipper shall also deliver or cause to be delivered at the
receipt points such additional quantities of gas to be retained by
Transco for compressor fuel and line loss make-up. 1 These quantities
do not include the additional quantities of gas to be retained by
Seller for compressor fuel and line loss make-up. Therefore, Buyer
shall also deliver or cause to be delivered at the receipt points such
additional quantities of gas in kind to be retained by Seller for
compressor fuel and line loss make-up.
2 Pressure(s) shall not be less than fifty (50) pounds per square inch
gauge or at such other pressures as may be agreed upon in the
day-to-day operations of Buyer and Seller.
3 Deliveries to or for the account of Shipper at the delivery point(s)
shall be subject to the limits of the Delivery Point Entitlements
("DPE's") of the entities receiving the gas at the delivery point(s),
as such DPE's are set forth in Transco's FERC Gas Tariff, as amended
from time to time.
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0001004155
<NAME> AGL RESOURCES INC.
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,491
<OTHER-PROPERTY-AND-INVEST> 79
<TOTAL-CURRENT-ASSETS> 224
<TOTAL-DEFERRED-CHARGES> 183
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,977
<COMMON> 272
<CAPITAL-SURPLUS-PAID-IN> 200
<RETAINED-EARNINGS> 175
<TOTAL-COMMON-STOCKHOLDERS-EQ> 647
74
0
<LONG-TERM-DEBT-NET> 610
<SHORT-TERM-NOTES> 2
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 50
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 594
<TOT-CAPITALIZATION-AND-LIAB> 1,977
<GROSS-OPERATING-REVENUE> 885
<INCOME-TAX-EXPENSE> 23
<OTHER-OPERATING-EXPENSES> 275
<TOTAL-OPERATING-EXPENSES> 778
<OPERATING-INCOME-LOSS> 107
<OTHER-INCOME-NET> (14)
<INCOME-BEFORE-INTEREST-EXPEN> 93
<TOTAL-INTEREST-EXPENSE> 41
<NET-INCOME> 52
5
<EARNINGS-AVAILABLE-FOR-COMM> 47
<COMMON-STOCK-DIVIDENDS> 47
<TOTAL-INTEREST-ON-BONDS> 37
<CASH-FLOW-OPERATIONS> 190
<EPS-BASIC> 0.82
<EPS-DILUTED> 0.82
</TABLE>
