SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1998
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification Number
1-14174 AGL RESOURCES INC. 58-2210952
(A Georgia Corporation)
303 PEACHTREE STREET, NE
ATLANTA, GEORGIA 30308
404-584-9470
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes |X| No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of March 31, 1998.
Common Stock, $5.00 Par Value
Shares Outstanding at March 31, 1998 ...........................56,988,417
<PAGE>
AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended March 31, 1998
Table of Contents
Item Page
Number Number
PART I -- FINANCIAL INFORMATION
1 Financial Statements
Condensed Consolidated Income Statements 3
Condensed Consolidated Balance Sheets 4
Condensed Consolidated Statements of Cash Flows 6
Notes to Condensed Consolidated Financial Statements 7
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 14
PART II -- OTHER INFORMATION
1 Legal Proceedings 23
4 Submission of Matters to a Vote of Security Holders 23
5 Other Information 23
6 Exhibits and Reports on Form 8-K 28
SIGNATURES 29
<PAGE>
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS
FOR THE THREE MONTHS, SIX MONTHS, AND TWELVE MONTHS ENDED
MARCH 31, 1998 AND 1997
(MILLIONS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<CAPTION>
Three Months Six Months Twelve Months
--------------------------------------------------------------------------
1998 1997 1998 1997 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 483.9 $ 496.7 $ 886.2 $ 876.3 $1,297.5 $1,292.2
Cost of Gas 309.8 315.7 566.9 546.8 786.6 772.9
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Margin 174.1 181.0 319.3 329.5 510.9 519.3
- ---------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
Other Operating Expenses 90.8 92.0 183.6 180.3 352.8 344.7
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Income 83.3 89.0 135.7 149.2 158.1 174.6
- ---------------------------------------------------------------------------------------------------------------------------------
Other Income 2.9 3.7 8.1 6.1 12.3 10.9
- ---------------------------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes 86.2 92.7 143.8 155.3 170.4 185.5
- ---------------------------------------------------------------------------------------------------------------------------------
Interest Expense and Preferred Stock Dividends
Interest expense 14.1 13.7 28.2 27.3 53.1 51.2
Dividends on preferred stock of subsidiaries 1.2 1.1 3.6 2.2 7.6 4.4
- ---------------------------------------------------------------------------------------------------------------------------------
Total interest expense and preferred stock
dividends 15.3 14.8 31.8 29.5 60.7 55.6
- ---------------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 70.9 77.9 112.0 125.8 109.7 129.9
- ---------------------------------------------------------------------------------------------------------------------------------
Income Taxes 25.8 28.9 41.2 47.2 40.8 49.8
- ---------------------------------------------------------------------------------------------------------------------------------
Net Income $ 45.1 $ 49.0 $ 70.8 $ 78.6 $ 68.9 $ 80.1
=================================================================================================================================
Basic Earnings Per Share of Common Stock $ 0.79 $ 0.88 $ 1.25 $ 1.41 $ 1.22 $ 1.44
Diluted Earnings Per Share of Common Stock $ 0.79 $ 0.87 $ 1.24 $ 1.40 $ 1.22 $ 1.44
Cash Dividends Paid Per Share of Common Stock $ 0.27 $ 0.27 $ 0.54 $ 0.54 $ 1.08 $ 1.07
</TABLE>
See notes to condensed consolidated financial statements.
<PAGE>
<TABLE>
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
<CAPTION>
(Unaudited)
March 31, September 30,
---------------------- ------------
ASSETS 1998 1997 1997
- ------------------------------------------------------------------------------------------------------------------------
Current Assets
<S> <C> <C> <C>
Cash and cash equivalents $ - $ 8.7 $ 4.8
Receivables (less allowance for uncollectible accounts
of $7.5 at March 31, 1998, $7.3 at March 31,
1997, and $2.6 at September 30, 1997) 204.5 219.4 93.9
Inventories
Natural gas stored underground 29.2 35.5 151.8
Liquefied natural gas 14.7 12.3 17.5
Materials and supplies 6.8 7.6 8.2
Other 5.0 1.7 6.0
Deferred purchased gas adjustment 17.9 19.3 8.5
Other 1.2 9.2 2.0
------------------------------------------------------------------------------------------------------------------------
Total current assets 279.3 313.7 292.7
- ------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment
Utility plant 2,109.9 2,011.5 2,069.1
Less: accumulated depreciation 673.5 627.2 648.8
- ------------------------------------------------------------------------------------------------------------------------
Utility plant - net 1,436.4 1,384.3 1,420.3
- ------------------------------------------------------------------------------------------------------------------------
Nonutility property 113.3 97.7 105.8
- ------------------------------------------------------------------------------------------------------------------------
Less: accumulated depreciation 32.1 27.9 29.5
- ------------------------------------------------------------------------------------------------------------------------
Nonutility property - net 81.2 69.8 76.3
- -----------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment - net 1,517.6 1,454.1 1,496.6
- ------------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
- ------------------------------------------------------------------------------------------------------------------------
Unrecovered environmental response costs 69.7 40.9 55.0
Investment in joint ventures 38.0 32.5 32.7
Unrecovered Integrated Resource Plan costs 1.0 7.7 2.0
Other 38.9 43.0 46.0
- ------------------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 147.6 124.1 135.7
- ------------------------------------------------------------------------------------------------------------------------
Total Assets $ 1,944.5 $ 1,891.9 $ 1,925.0
========================================================================================================================
<FN>
See notes to condensed consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
<CAPTION>
(Unaudited)
March 31, September 30,
---------------------------- -------------
LIABILITIES AND CAPITALIZATION 1998 1997 1997
- ------------------------------------------------------------------------------------------------------------------------
Current Liabilities
<S> <C> <C> <C>
Accounts payable-trade $ 69.5 $ 58.6 $ 65.1
Short-term debt 4.4 113.0 29.5
Redemption requirements on preferred stock 0.3 44.5
Customer deposits 31.9 29.9 29.2
Interest 28.7 27.1 29.6
Taxes 39.7 38.9 19.1
Other 35.6 40.1 26.4
- ------------------------------------------------------------------------------------------------------------------------
Total current liabilities 209.8 307.9 243.4
- ------------------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes 191.7 169.6 191.7
- ------------------------------------------------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs 47.0 31.3 37.3
Accrued postretirement benefits costs 34.5 35.7 34.3
Deferred credits 58.4 60.3 61.9
- ------------------------------------------------------------------------------------------------------------------------
Total long-term liabilities 139.9 127.3 133.5
- ------------------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 660.0 584.5 660.0
Subsidiary obligated mandatorily redeemable
preferred securities 74.3 74.3
Preferred stock of subsidiary, cumulative $100 par or
stated value, shares issued and outstanding of
0.6 at March 31, 1997 58.5
Common stock, $5 par value, shares issued and
outstanding of 57.0 at March 31, 1998, 56.1 at 668.8 644.1 622.1
March 31, 1997, and 56.6 at September 30, 1997
- ------------------------------------------------------------------------------------------------------------------------
Total capitalization 1,403.1 1,287.1 1,356.4
- ------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 1,944.5 $ 1,891.9 $ 1,925.0
========================================================================================================================
<FN>
See notes to condensed consolidated financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
AGL RESOURCES INC. AND SUBISIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS AND TWELVE MONTHS ENDED MARCH 31, 1998 AND 1997
(MILLIONS)
(UNAUDITED)
<CAPTION>
Six Months Twelve Months
------------------------------ --------------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash Flows from Operating Activities
Net income $ 70.8 $ 78.6 $ 68.9 $ 80.1
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization 36.9 34.9 72.0 69.1
Deferred income taxes (2.1) 2.1 14.3 24.4
Other 0.1 0.6 (0.3) (0.2)
Changes in certain assets and liabilities 46.2 (7.7) 37.6 (48.2)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flow from operating
activities 151.9 108.5 192.5 125.2
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses 0.3 0.6 1.4 1.4
Sale of preferred securities, net of expenses 74.3
Sale of long-term debt 30.0 75.5 30.0
Short-term borrowings, net (25.1) (39.0) (108.6) 46.5
Redemptions and purchase fund requirements
of preferred securities (44.5) (59.2)
Dividends paid on common stock (27.2) (25.1) (51.0) (49.8)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flow from financing
activities (96.5) (33.5) (67.6) 28.1
- --------------------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures (48.1) (61.9) (109.7) (136.1)
Non-utility capital expenditures (7.9) (14.8) (16.7) (15.6)
Cost of removal, net of salvage (0.9) 0.4 (2.9) (0.4)
Cash received from joint ventures 0.3 1.3 0.3 4.1
Investment in joint ventures (3.6) (4.6) (1.1)
- --------------------------------------------------------------------------------------------------------------------------------
Net cash flow from investing
activities (60.2) (75.0) (133.6) (149.1)
- --------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and
cash equivalents (4.8) - (8.7) 4.2
Cash and cash equivalents
at beginning of period 4.8 8.7 8.7 4.5
- --------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents
at end of period $ - $ 8.7 $ - $ 8.7
================================================================================================================================
Cash Paid During the Year for
Interest $ 29.1 $ 26.1 $ 51.8 $ 49.8
Income taxes $ 18.6 $ 18.4 $ 28.5 $ 25.0
<FN>
See notes to condensed consolidated financial statements.
</FN>
</TABLE>
<PAGE>
AGL RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Principles of Consolidation
AGL Resources Inc. (AGL Resources), a Georgia corporation, is the
holding company for Atlanta Gas Light Company (AGL), AGL's wholly owned
natural gas utility subsidiary, Chattanooga Gas Company (Chattanooga), and
several nonutility subsidiaries. AGL comprises substantially all of AGL
Resources' assets, revenues, and earnings. The consolidated financial
statements of AGL Resources include the financial statements of AGL,
Chattanooga, and the nonutility subsidiaries as though AGL Resources had
existed in all periods shown. Intercompany balances and transactions have
been eliminated.
2. Subsidiaries
Unless noted specifically or otherwise required by the context,
references to AGL Resources include AGL, AGL Interstate Pipeline Company
(AGL Interstate Pipeline), AGL Peaking Services, Inc. (AGL Peaking
Services), and AGL Resources' nonutility subsidiaries. AGL Resources
engages in natural gas distribution through AGL and AGL's wholly owned
subsidiary, Chattanooga. AGL is a public utility that distributes and
transports natural gas in Georgia and Tennessee and is subject to
regulation by the Georgia Public Service Commission (Georgia Commission)
and the Tennessee Regulatory Authority (TRA), with respect to its rates for
service, maintenance of its accounting records, and various other matters.
The consolidated financial statements are prepared in accordance with
generally accepted accounting principles, which give appropriate
recognition to the rate-making and accounting practices and policies of the
Georgia Commission and the TRA.
AGL Resources engages in nonutility business activities through its
wholly owned subsidiaries, AGL Energy Services, Inc. (AGL Energy Services),
a gas supply services company; AGL Investments, Inc. (AGL Investments), a
subsidiary established to develop and manage certain nonutility businesses;
Atlanta Gas Light Services (formerly The Energy Spring, Inc.), a retail
energy marketing company; and AGL Resources Service Company. AGL Energy
Services has one nonutility subsidiary, Georgia Gas Company. AGL
Investments has six wholly owned nonutility subsidiaries: AGL Propane, Inc.
(formerly known as Georgia Gas Service Company) (AGL Propane); AGL Consumer
Services, Inc.; AGL Gas Marketing, Inc.; AGL Power Services, Inc.; AGL
Energy Wise Services, Inc. and Trustees Investments, Inc.
3. Interim Financial Statements
In the opinion of management, the unaudited condensed consolidated
financial statements included herein reflect all normal recurring accruals
necessary for a fair statement of the results of the interim periods
reflected. Certain information and footnote disclosure normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been omitted from these condensed consolidated
financial statements pursuant to applicable rules and regulations of the
Securities and Exchange Commission. These financial statements should be
read in conjunction with the financial statements and the notes thereto
included in the annual reports on Form 10-K of AGL Resources for the fiscal
years ended September 30, 1997, and September 30, 1996. Certain 1997
amounts have been reclassified for comparability with 1998 amounts.
4. Earnings
AGL Resources' principal business is the distribution of natural gas
to customers in central, northwest, northeast and southeast Georgia and the
Chattanooga, Tennessee area through its natural gas distribution
<PAGE>
subsidiary, AGL. Since consumption of natural gas is dependent to a large
extent on weather, the majority of AGL Resources' income is realized during
the winter months. Earnings for three-month and six-month periods are not
indicative of the earnings for a twelve-month period.
5. Environmental Matters - AGL
AGL has identified nine sites in Georgia where it currently owns all
or part of a manufactured gas plant (MGP) site. In addition, AGL has
identified three other sites in Georgia which AGL does not own, but that
may have been associated with the operation of MGPs by AGL or its
predecessors.
Those sites are potentially subject to a variety of regulatory
programs. AGL's response to MGP sites in Georgia is proceeding under two
state regulatory programs: the Georgia Hazardous Waste Management Act
(HWMA) and the Hazardous Site Response Act (HSRA). AGL is planning to
undertake some degree of response action, under one or both of those
programs, at most of the Georgia sites.
AGL also has identified three sites in Florida which may have been
associated with AGL or its predecessors. AGL does not own any of the former
MGP sites in Florida. At one site, AGL has entered into an Administrative
Order of Consent along with four other potentially responsible parties to
further investigate this site. At another site, AGL has received a "Special
Notice Letter" from the U. S. Environmental Protection Agency (EPA), and is
negotiating the scope of a response with both EPA and the current owner.
AGL has estimated the investigation and remediation expenses likely
to be associated with the former MGP sites. First, AGL has identified
several sites where it has concluded that no significant response actions
are reasonably likely in the foreseeable future and therefore has not made
any cost projections for these sites. Second, since response cost
liabilities are often spread among potentially responsible parties, AGL's
ultimate liability will, in some cases, be limited to AGL's equitable share
of such expenses under the circumstances. Therefore, where reasonably
possible, AGL has attempted to estimate the range of AGL's equitable share,
given current cost sharing arrangements, combined with AGL's current
knowledge of relevant facts, including the current methods of equitable
apportionment and the solvency of potential contributors. Where such an
estimation was not reasonably possible, AGL has estimated a range of
expenses without adjustment for AGL's equitable share. Finally, AGL has,
with the assistance of outside consultants, prepared estimates of the range
of future investigation and remediation costs for those sites where further
action appears likely.
Applying these concepts to those sites where some future action
presently appears reasonably possible, AGL currently estimates that the
future cost to AGL of investigating and remediating the former MGP sites
could be as low as $47 million or as high as $81.3 million. That range does
not include other expenses, such as unasserted property damage claims, for
which AGL may be held liable, but for which neither the existence nor the
amount of such liabilities can be reasonably forecast. Within the stated
range of $47 million to $81.3 million, no amount within the range can be
identified reliably as a better estimate than any other estimate.
Therefore, a liability at the low end of that range has been recorded in
the financial statements.
AGL has two means of recovering the expenses associated with the
former MGP sites. First, the Georgia Commission has approved the recovery
by AGL of Environmental Response Costs, as defined, pursuant to an
Environmental Response Cost Recovery Rider (ERCRR). For purposes of the
ERCRR, Environmental Response Costs include investigation, testing,
remediation and litigation costs and expenses or other liabilities relating
to or arising from MGP sites. A regulatory asset in the amount of $69.7
million has been recorded in the financial statements to reflect the
recovery of those costs through the ERCRR.
<PAGE>
In connection with the ERCRR, the staff of the Georgia Commission has
undertaken a financial and management process audit related to the MGP
sites, cleanup activities at the sites, and environmental response costs
that have been incurred for purposes of the ERCRR. The Georgia Commission
conducted hearings on April 16 and 17, 1998 to consider three issues
relating to the ERCRR. Specifically, the Georgia Commission considered
whether the term "Environmental Response Costs" should include punitive
damages, whether AGL should be required to provide an annual accounting for
revenue recovered from customers through the ERCRR, and whether a schedule
should be established for site remediation. Additional hearings relating to
these issues are expected to be scheduled in the near future.
Second, AGL intends to seek recovery of appropriate costs from its
insurers and other potentially responsible parties. During the twelve month
period ended March 31, 1998, AGL recovered $4.5 million from its insurance
carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGL recognized other income of $1.4 million and
established regulatory liabilities for the remainder of the recoveries.
On February 10, 1995, a class action lawsuit captioned Trinity
Christian Methodist Episcopal Church, et al. v. Atlanta Gas Light Company,
No. 95-RCCV-93, was filed in the Superior Court of Richmond County,
Georgia, seeking to recover for damage to property owned by persons
adjacent to and near the former MGP site in Augusta, Georgia. On December
13, 1996, the parties reached a preliminary settlement, which was approved
by the Court on April 15, 1997. Pursuant to the settlement, there is a
claims process before an umpire to determine either the full fair market
value of properties tendered to AGL or the diminution in fair market value
of properties not tendered to AGL. Settlements were paid to 188 property
owners in the class totaling approximately $2.9 million, including legal
fees and expenses of the plaintiffs. One settlement of approximately
$64,000, including attorney's fees, is pending reconsideration. AGL filed
motions to vacate six settlements totaling approximately $4.3 million.
Orders were entered denying the motions to vacate. AGL filed notices of
appeal with the Georgia Court of Appeals seeking to reverse the denial of
the motions to vacate. On March 25, 1998, the Georgia Court of Appeals
affirmed the ruling of the lower court. Pursuant to the Court of Appeals
decision, six settlements totaling $4.9 million, including attorney's fees
and post judgement interest, have been paid; and are recoverable pursuant
to the terms of the ERCRR.
6. Competition - AGL
Alternative Fuels and Competitive Pricing. AGL competes to supply
natural gas to interruptible customers who are capable of switching to
alternative fuels, including propane, fuel and waste oils, electricity and,
in some cases, combustible wood by-products. AGL also competes to supply
gas to interruptible customers who might seek to bypass its distribution
system.
AGL can price distribution services to interruptible customers four
ways. First, multiple rates are established under the rate schedules of
AGL's tariff approved by the Georgia Commission. If an existing tariff rate
does not produce a price competitive with a customer's relevant competitive
alternative, three alternate pricing mechanisms exist: Negotiated
Contracts, Interruptible Transportation and Sales Maintenance (ITSM)
discounts and Special Contracts.
On February 17, 1995, the Georgia Commission approved a settlement
that permits AGL to negotiate contracts with customers who have the option
of bypassing AGL's facilities (Bypass Customers) to receive natural gas
from other suppliers. The bypass avoidance contracts (Negotiated Contracts)
can be renewable, provided the initial term does not exceed five years,
unless a longer term specifically is authorized by the Georgia Commission.
The rate provided by the Negotiated Contract may be lower than AGL's filed
rate, but
<PAGE>
not less than AGL's marginal cost of service to the potential Bypass
Customer. Service pursuant to a Negotiated Contract may commence without
Georgia Commission action, after a copy of the contract is filed with the
Georgia Commission. Negotiated Contracts may be rejected by the Georgia
Commission within 90 days of filing; absent such action, however, the
Negotiated Contracts remain in effect.
The settlement also provides for a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or the effective date of
new rates for AGL resulting from a general rate case. Under the recovery
mechanism, AGL is allowed to recover from other customers 75% of the
difference between (a) the nongas cost revenue that was received from the
potential Bypass Customer during the most recent twelve-month period and
(b) the nongas cost revenue that is calculated to be received from the
lower Negotiated Contract rate applied to the same volumetric level.
Concerning the remaining 25% of the difference, AGL is allowed to retain
44% of firm customers' share of capacity release revenues in excess of $5
million until AGL is made whole for discounts from Negotiated Contracts.
In addition to Negotiated Contracts, which are designed to serve
existing and potential Bypass Customers, AGL's ITSM Rider continues to
permit discounts for short-term transactions to compete with alternative
fuels. Revenue shortfalls, if any, from interruptible customers as measured
by the test-year interruptible revenues determined by the Georgia
Commission in AGL's 1993 rate case, will continue to be recovered under the
ITSM Rider.
The settlement approved by the Georgia Commission also provides that
AGL may file contracts (Special Contracts) for Georgia Commission approval
if the service cannot be provided through the ITSM Rider, existing rate
schedules, or Negotiated Contract procedures. A Special Contract, for
example, could involve AGL providing a long-term service contract to
compete with alternative fuels where physical bypass is not the relevant
competition.
Pursuant to the approved settlement, AGL has filed and is providing
service pursuant to 56 Negotiated Contracts. Additionally, AGL is providing
service pursuant to seven Special Contracts.
On February 17, 1998, the Georgia Commission nullified two negotiated
contracts and one special contract based on its interpretation of a
provision of the Natural Gas Competition and Deregulation Act (Georgia Gas
Act) that would preclude the Georgia Commission from approving any such
contracts on or after the date AGL filed its notice of election to be
subject to the act. (See Atlanta Gas Light Company-Unbundling and Rate
Filing.) In an administrative session on May 5, 1998, however, the Georgia
Commission reversed its earlier decision to nullify those contracts.
Further, the Georgia Commission authorized AGL to enter into future special
and negotiated contracts provided the initial term of any such contract
does not exceed three years. All such future contracts, however, must
include market out provisions. A written order reflecting the Georgia
Commission's decision in the above is pending.
On November 27, 1996, the TRA approved an experimental rule allowing
Chattanooga to negotiate contracts with large commercial and industrial
customers who have long-term competitive options, including bypass. The
experimental rule provides that before any such customer is allowed a
discounted rate, both the large customer and Chattanooga must petition the
TRA for approval of the rates set forth in the contract. On October 7,
1997, the TRA denied petitions filed by Chattanooga and four large
customers for discounted rates pursuant to the experimental rule upon a
finding that customer bypass was not imminent. On January 14, 1998,
however, the FERC issued an order authorizing the bypass of Chattanooga by
Southern Natural Gas Company (Southern) to serve an interruptible customer.
AGL is continuing to negotiate with the customer to determine whether a
compromise can be reached to retain the customer, and Southern has not yet
constructed
<PAGE>
the facilities necessary to complete the bypass. Management does not expect
the order issued by the FERC to have a material adverse effect on the
consolidated financial statements of AGL Resources.
Atlanta Gas Light Company - Unbundling and Rate Filing. The Georgia
Gas Act was signed into law on April 14, 1997. The act provides a legal
framework for comprehensive deregulation of many aspects of the natural gas
business in Georgia.
On November 26, 1997, AGL filed with the Georgia Commission notice of
its election to be subject to this new law and to establish separate rates
for unbundled services. AGL filed contemporaneously an application with the
Georgia Commission to have its distribution rates, charges, classifications
and services regulated pursuant to performance-based regulation. The filing
requests an increase in revenues of $18.6 million annually. The requested
increase includes the costs to support changes in AGL's business systems to
ensure reliable service to customers and that the systems are in place to
serve new gas suppliers in the competitive marketplace.
Within seven months from the date of such filing, the Georgia
Commission must issue an order approving the plan as filed or with
modification. Retail marketing companies, including AGL affiliates, may
then file with the Georgia Commission separate certificate of authority
applications to sell natural gas to firm customers connected to AGL's
delivery system. It is currently anticipated that marketers who become
certificated by the Georgia Commission may begin offering natural gas sales
services to customers of AGL by November 1998.
The Georgia Gas Act provides a transition period leading to a
condition of effective competition in all natural gas markets. AGL, as an
electing distribution company, will unbundle all services to its natural
gas customers, allocate firm delivery capacity to certificated marketers
selling the gas commodity and create a secondary market for interruptible
transportation capacity. Certificated marketers, including nonutility
affiliates of AGL, will compete to sell natural gas to all customers at
market-based prices. AGL will continue to provide intrastate delivery of
gas to end users through its existing system, subject to continued rate
regulation by the Georgia Commission. As a result of the election to be
subject to the Georgia Gas Act, it is expected that the purchased gas
adjustment provisions included in AGL's rate schedules will be discontinued
during fiscal 1999. The November 26, 1997 filing contains a provision to
true-up any over-recovery or under-recovery that may exist at the time such
purchased gas adjustment provisions are discontinued. Accordingly, AGL will
no longer defer any over-recoveries or under-recoveries of gas costs when
the purchased gas adjustment provisions are discontinued. In addition, the
Georgia Commission will continue to regulate safety, access and quality of
service pursuant to an alternative form of regulation.
The Georgia Gas 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 AGL's system. The act imposes on
marketers an obligation to serve with a corresponding universal service
fund that provides a funding mechanism for uncollectible accounts and
enables AGL to expand its facilities and serve the public interest.
Hearings in this proceeding began on March 9, 1998, and are scheduled
to continue for the weeks of April 28, 1998 and May 18, 1998. A decision by
the Georgia Commission is expected in June 1998.
Pursuant to the Georgia Gas Act, the Georgia Commission issued rules
and regulations on December 30, 1997, for certification of marketers and
assignment of firm customers to marketers for customers who ultimately do
not select a marketer after competition is fully developed. Additionally,
the Georgia Commission issued a Notice of Inquiry to address certain
aspects of random assignment of customers and marketer certification not
fully resolved in the rulemakings.
<PAGE>
7. Earnings Per Share
In February 1997 the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 128, "Earnings Per Share"
(SFAS 128), which establishes standards for computing and presenting
earnings per share.
AGL Resources adopted SFAS 128 in October 1997.
Earnings per share are based on the weighted average number of common
and common stock equivalent shares outstanding. The average number of
common shares used in the calculation of basic earnings per share and the
weighted average number of shares and common stock equivalent shares used
in the calculation of diluted earnings per share for the three-month,
six-month and twelve-month periods ended March 31, 1998 and 1997, were as
follows (in millions):
Basic Diluted
Three-months ended
March 31, 1998 56.9 57.0
March 31, 1997 56.0 56.0
Six-months ended
March 31, 1998 56.8 56.9
March 31, 1997 55.9 56.0
Twelve-months ended
March 31, 1998 56.6 56.7
March 31, 1997 55.7 55.8
The only common stock equivalent shares are those related to stock
options outstanding during the respective years whose exercise price was
less than the average market price of the common shares for the respective
periods. Additional options to purchase common stock were outstanding, 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.
8. Accounting Developments
During its July 1997 meeting, the Financial Accounting Standards
Board's 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, Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), should be discontinued for that segment. The state
of Georgia has enacted legislation, the Georgia Gas Act, that allows for
the deregulation of the merchant function and unbundling of certain
ancillary services of local gas distribution companies. AGL has filed its
election to become an electing distribution company. The rates to transport
natural gas through the intrastate pipe system of the local gas
distribution company will be regulated by the Georgia Commission. Since
AGL's regulatory assets and liabilities associated with its gas
distribution activities continue to be regulated, AGL has determined that
the continued application of SFAS 71 related to those distribution
activities remains appropriate. See Part II, Item 5 - "Other Information,
State Regulatory Matters" in this Form 10-Q.
In June 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 130, "Reporting
Comprehensive Income" (SFAS 130) and Statement of Financial Accounting
Standard No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS 131). AGL
<PAGE>
Resources will adopt SFAS 130 and SFAS 131 in fiscal year 1999. SFAS 130
establishes standards for the reporting and displaying of comprehensive
income and its components (revenues, expenses, gains, and losses) in a full
set of general-purpose financial statements. SFAS 131 establishes standards
for the way that public business enterprises report information about
operating segments in annual financial statements and requires that those
enterprises report selected information about operating segments in interim
financial reports issued to shareholders.
Management does not expect these new pronouncements to have a
significant impact on the presentation of AGL Resources' consolidated
financial statements.
During November 1997, the EITF published Issue No. 97-13 "Accounting
for Costs Incurred in Connection with a Consulting Contract or an Internal
Project That Combines Business Process Reengineering and Information
Technology Transformation." Issue No. 97-13 addresses costs which have been
incurred by organizations related to advances in computer technologies.
Some of the costs which have been incurred include consulting fees paid for
business process reengineering and information technology transformation.
The EITF concluded that these costs should be expensed as incurred rather
than capitalized. The EITF requires items previously capitalized to be
written off during the quarter which includes November 20, 1997. The
impacts of applying the effects of this consensus were not significant to
the financial results for the six-month period ended March 31, 1998.
9. Year 2000
AGL Resources uses several computer application programs written over
many years using two-digit year fields to define the applicable year,
rather than four-digit year fields. Programs that are time-sensitive may
recognize a date using "00" as the year 1900 rather than the year 2000.
That misinterpretation of the year could result in incorrect computation or
computer shutdown.
With the assistance of an independent consultant, AGL Resources has
identified the systems that could be affected by the year 2000 issue and
has developed a plan to resolve the issue. The plan provides for, among
other things, the replacement or modification of existing data processing
systems as necessary. Implementation of the plan has begun, and the cost
estimates associated with the implementation are not expected to
significantly impact AGL Resources' consolidated financial statements.
Management believes that with the appropriate modification, AGL
Resources will be able to operate its time-sensitive business systems
through the turn of the century.
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<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
Forward Looking Statements
The Private Securities Litigation Reform Act of 1995 provides for the
use of cautionary statements accompanying forward-looking statements.
Disclosures provided contain forward-looking statements concerning, among
other things, deregulation, restructuring and environmental remediation.
Important factors that could cause actual results to differ
materially from those in the forward-looking statements include, but are
not limited to, the following: changes in price and demand for natural gas
and related products; uncertainty as to state and federal legislative and
regulatory issues; the effects of competition, particularly in markets
where prices and providers historically have been regulated; changes in
accounting policies and practices; uncertainty with regard to environmental
issues, and competitive issues in general.
Results of Operations
Three-Month Periods Ended March 31, 1998 and 1997
Explained below are the major factors that had a significant effect
on results of operations for the three-month period ended March 31, 1998,
compared with the same period in 1997.
Operating revenues decreased 2.6% for the three-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to (1)
a decrease in the cost of gas supply recovered from customers under the
purchased gas provisions of AGL's rate schedules, as explained in the
following paragraph, (2) decreased consumption patterns attributable to
AGL's firm-service customers that are not related to weather conditions (3)
decreased expenses pursuant to an Integrated Resource Plan (IRP) which are
recovered through an IRP Cost Recovery Rider approved by the Georgia
Commission and (4) a shift by certain interruptible customers from
interruptible sales to transportation service. Operating revenues are less
when gas is transported for a customer than when it is sold to that
customer. The utility's transportation rate generates the same operating
margin as the applicable sales rate schedule for interruptible sales of
gas; therefore, earnings are not affected.
AGL balances the cost of gas with revenues collected from customers
under the purchased gas provisions of its rate schedules. Under-recoveries
or over-recoveries of AGL's gas costs are deferred and recorded as current
assets or liabilities, thereby eliminating the effect that recovery of gas
costs would otherwise have on net income. Cost of gas decreased 1.9% for
the three-month period ended March 31, 1998, compared with the same period
in 1997 primarily due to (1) a decrease in the cost of gas purchased for
utility system supply and (2) decreased volumes of gas sold as a result of
a shift by certain interruptible customers from interruptible sales to
transportation service.
Operating margin decreased 3.8% for the three-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to (1)
decreased consumption patterns attributable to AGL's firm-service customers
that are not related to weather conditions and (2) decreased expenses
pursuant to an IRP which are recovered through an IRP Cost Recovery Rider.
That decrease in operating margin was offset partly by margins resulting
from propane operations acquired in February and June, 1997. Weather
normalization adjustment riders (WNARs), approved by the Georgia Commission
and the TRA, stabilized operating margin at the level which would occur
with normal weather for the three-month periods ended March 31, 1998 and
<PAGE>
1997. As a result of the WNARs, weather conditions experienced do not have
a significant impact on the comparability of operating margin.
Operating expenses decreased 1.3% for the three-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
decreased expenses pursuant to an IRP Cost Recovery Rider. AGL balances IRP
expenses which are included in operating expenses with revenues collected
under the rider, thereby eliminating the effect that recovery of IRP
expenses would otherwise have on net income. That decrease in operating
expenses was offset partly by (1) increased distribution maintenance
expenses and (2) increased depreciation expense recorded as a result of
increased depreciable property.
Other income decreased $0.8 million for the three-month period ended
March 31, 1998, compared with the same period in 1997 primarily due a
decrease in certain carrying costs recovered from utility customers. Those
decreased carrying costs are attributable to a decrease in underrecovered
deferred purchased gas costs and decreased expenses pursuant to an IRP.
Interest expense increased $0.4 million for the three-month period
ended March 31, 1998, compared with the same period in 1997 primarily due
to increased amounts of long-term debt outstanding during the period. The
increase in interest expense was offset partly by decreased amounts of
short-term debt outstanding.
Income taxes decreased $3.1 million for the three-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
decreased taxable income.
Net income for the three-month period ended March 31, 1998, was $45.1
million, compared with net income of $49.0 million for the same period in
1997. Basic and diluted earnings per share of common stock were $0.79 for
the three-month period ended March 31, 1998, compared with basic earnings
per share of $0.88 and diluted earnings per share of $0.87 for the same
period in 1997. The decreases in net income and earnings per share were
primarily due to (1) decreased operating margin and (2) decreased other
income.
Six-Month Periods Ended March 31, 1998 and 1997
Explained below are the major factors that had a significant effect
on results of operations for the six-month period ended March 31, 1998,
compared with the same period in 1997.
Operating revenues increased 1.1% for the six-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to (1)
increased operating revenues attributable to a nonutility retail marketing
company formed in June 1996 and propane operations acquired in February and
June, 1997, (2) an increase in the cost of gas supply recovered from
customers under the purchased gas provisions of AGL's rate schedules, as
explained in the following paragraph, as a result of increased volumes of
gas sold due to weather that was 37.9% colder than during the same period
in 1997, and (3) growth in the number of customers served. The increase in
operating revenues was offset substantially by a shift by certain
interruptible customers from interruptible sales to transportation service.
Operating revenues are less when gas is transported for a customer than
when it is sold to that customer. The utility's transportation rate
generates the same operating margin as the applicable sales rate schedule
for interruptible sales of gas; therefore, earnings are not affected. Also
offsetting significantly the increase in operating revenues were (1)
decreased consumption patterns attributable to AGL's firm service customers
that are not related to weather conditions and (2) decreased expenses
pursuant to an IRP which are recovered through an IRP Cost Recovery Rider.
AGL balances the cost of gas with revenues collected from customers
under the purchased gas provisions of its rate schedules. Under-recoveries
or over-recoveries of AGL's gas costs are deferred and recorded as
<PAGE>
current assets or liabilities, thereby eliminating the effect that recovery
of gas costs would otherwise have on net income. Cost of gas increased 3.7%
for the six-month period ended March 31, 1998, compared with the same
period in 1997 primarily due to (1) increased volumes of gas sold as a
result of weather that was 37.9% colder than during the same period in 1997
and (2) increased cost of gas attributable to a nonutility retail marketing
company formed in June 1996 and propane operations acquired in February and
June, 1997. The increase in cost of gas was offset substantially by
decreased volumes of gas sold as a result of a shift by certain
interruptible customers from interruptible sales to transportation service.
Operating margin decreased 3.1% for the six-month period ended March
31, 1998, compared with the same period in 1997 primarily due to (1)
decreased consumption patterns attributable to AGL's firm-service customers
that are not related to weather conditions and (2) decreased expenses
pursuant to an IRP which are recovered through an IRP Cost Recovery Rider.
The decrease in operating margin was offset partly by margins resulting
from propane operations acquired in February and June, 1997. WNARs,
approved by the Georgia Commission and the TRA, stabilized operating margin
at the level which would occur with normal weather for the six-month
periods ended March 31, 1998 and 1997. As a result of the WNARs, weather
conditions experienced do not have a significant impact on the
comparability of operating margin.
Operating expenses increased 1.8% for the six-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to (1)
increased distribution maintenance expenses and (2) operating expenses of
propane operations acquired during February and June, 1997. The increase in
operating expenses was offset partly by decreased expenses pursuant to an
IRP Cost Recovery Rider. AGL balances IRP expenses which are included in
operating expenses with revenues collected under the rider, thereby
eliminating the effect that recovery of IRP expenses would otherwise have
on net income.
Other income increased $2.0 million for the six-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
increased income from a gas marketing joint venture.
Interest expense increased 3.3% for the six-month period ended March
31, 1998, compared with the same period in 1997 primarily due to increased
amounts of long-term debt outstanding during the period. The increase in
interest expense was offset partly by decreased amounts of short-term debt
outstanding.
Dividends on preferred stock of subsidiaries increased $1.4 million
for the six-month period ended March 31, 1998, compared with the same
period in 1997 primarily due to dividend requirements related to the
issuance of $75 million principal amount of Capital Securities in June 1997
as more fully described below within the caption "Financial Condition."
Income taxes decreased $6.0 million for the six-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
decreased taxable income.
Net income for the six-month period ended March 31, 1998, was $70.8
million, compared with net income of $78.6 million for the same period in
1997. Basic earnings per share was $1.25 for the six-month period ended
March 31, 1998, compared with $1.41 for the same period in 1997. Diluted
earnings per share was $1.24 for the six-month period ended March 31, 1998,
compared with $1.40 for the same period in 1997. The decreases in net
income and earnings per share were primarily due to (1) decreased operating
margin, (2) increased operating expenses and (3) increased preferred
dividend requirements. The decreases in net income and earnings per share
were offset partly by increased other income.
<PAGE>
Twelve-Month Periods Ended March 31, 1998 and 1997
Explained below are the major factors that had a significant effect
on results of operations for the twelve-month period ended March 31, 1998,
compared with the same period in 1997.
Operating revenues increased 0.4% for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
increased operating revenues attributable to (1) a nonutility retail
marketing company formed in June 1996 and (2) propane operations acquired
in February and June, 1997. The increase in operating revenues was offset
substantially by (1) decreased expenses pursuant to an IRP which are
recovered through an IRP Cost Recovery Rider and (2) a shift by certain
interruptible customers from interruptible sales to transportation service.
Operating revenues are less when gas is transported for a customer than
when it is sold to that customer. The utility's transportation rate
generates the same operating margin as the applicable sales rate schedule
for interruptible sales of gas; therefore, earnings are not affected.
Cost of gas increased 1.8% for the twelve-month period ended March
31, 1998, compared with the same period in 1997 primarily due to increased
cost of gas attributable to a nonutility retail marketing company formed in
June 1996 and propane operations acquired in February and June, 1997. The
increase in cost of gas was offset substantially by decreased volumes of
gas sold as a result of a shift by certain interruptible customers from
interruptible sales to transportation service.
Operating margin decreased 1.6% for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to (1)
decreased consumption patterns attributable to AGL's firm-service customers
that are not related to weather conditions and (2) decreased expenses
pursuant to an IRP which are recovered through an IRP Cost Recovery Rider.
The decrease in operating margin was offset partly by an increase in
operating margin attributable to (1) a nonutility gas supply services
company formed in July 1996 and (2) propane operations acquired in February
and June, 1997. WNARs, approved by the Georgia Commission and the TRA,
stabilized operating margin at the level which would occur with normal
weather for the twelve-month periods ended March 31, 1998 and 1997. As a
result of the WNARs, weather conditions experienced do not have a
significant impact on the comparability of operating margin.
Operating expenses increased 2.3% for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
increased (1) distribution maintenance expense, (2) maintenance of general
plant and (3) depreciation expense recorded as a result of increased
depreciable property. The increase in operating expenses was offset partly
by decreased expenses pursuant to an IRP Cost Recovery Rider. AGL balances
IRP expenses which are included in operating expenses with revenues
collected under the rider, thereby eliminating the effect that recovery of
IRP expenses would otherwise have on net income.
Other income increased $1.4 million for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
increased income from a gas marketing joint venture.
Interest expense increased 3.7% for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
increased amounts of long-term debt outstanding during the period. The
increase in interest expense was offset partly by decreased amounts of
short-term debt outstanding.
Dividends on preferred stock of subsidiaries increased $3.2 million
for the twelve-month period ended March 31, 1998, compared with the same
period in 1997 primarily due to dividend requirements related to the
issuance of $75 million principal amount of Capital Securities in June 1997
as more fully described below within the caption "Financial Condition."
<PAGE>
Income taxes decreased $9.0 million for the twelve-month period ended
March 31, 1998, compared with the same period in 1997 primarily due to
decreased taxable income.
Net income for the twelve-month period ended March 31, 1998, was
$68.9 million, compared with net income of $80.1 million for the same
period in 1997. Basic and diluted earnings per share of common stock was
$1.22 for the twelve-month period ended March 31, 1998, compared with basic
and diluted earnings per share of $1.44 for the same period in 1997. The
decreases in net income and earnings per share were primarily due to (1)
decreased operating margin, (2) increased operating expenses and (3)
increased interest expense and preferred dividend requirements. The
decreases in net income and earnings per share were offset partly by
increased other income.
Financial Condition
AGL Resources' primary gas utility business is highly seasonal in
nature and typically shows a substantial increase in accounts receivable
from customers from September 30 to March 31 as a result of colder weather.
The utility also uses gas stored underground and liquefied natural gas to
serve its customers during periods of colder weather. As a result, accounts
receivable increased $110.6 million and inventory of gas stored underground
and liquefied natural gas decreased $125.4 million during the six-month
period ended March 31, 1998. Accounts receivable decreased $14.9 million
from March 31,1997 to March 31, 1998, primarily due to decreased operating
revenues. Inventory of gas stored underground decreased $ 6.3 million from
March 31, 1997 to March 31, 1998 primarily due to increased volumes of gas
withdrawn from storage as a result of weather that was 41.1% colder during
the twelve-month period ended March 31, 1998, compared with the same period
in 1997.
The gas purchasing practices of AGL are subject to review by the
Georgia Commission under legislation enacted by the Georgia General
Assembly (Gas Supply Plan Legislation). The Gas Supply Plan Legislation
establishes procedures for review and approval, in advance, of gas supply
plans for gas utilities and gas cost adjustment factors applicable to firm
service customers of gas utilities. Pursuant to AGL's approved Gas Supply
Plan for fiscal year 1998, gas supply purchases are being recovered under
the purchased gas provisions of AGL's rate schedules. The plan also allows
recovery from the customers of AGL of Federal Energy Regulatory
Commission's (FERC) Order No. 636 transition costs that are currently being
charged by AGL's pipeline suppliers.
Based on filings with the FERC by its pipeline suppliers, AGL
currently estimates that its total portion of transition costs associated
with the FERC's Order No. 636 from all of its pipeline suppliers will be
approximately $104.8 million. Approximately $95.6 million of such costs has
been incurred by AGL as of March 31, 1998, and is being recovered from its
customers under the purchased gas provisions of AGL's rate schedules.
AGL's Gas Supply Plan for fiscal year 1998 includes limited gas
supply hedging activities. AGL is authorized to enter into an expanded
program to hedge up to one half of its estimated monthly winter wellhead
purchases and establish a price for those purchases at an amount other than
the beginning of the month index price to create an additional element of
diversification and price stability. The financial results of all hedging
activities are passed through to firm service customers under the purchased
gas provisions of AGL's rate schedules. Accordingly, there is no earnings
impact as a result of the hedging program.
As noted above, AGL recovers the cost of gas under the purchased gas
provisions of its rate schedules. AGL was in an under-recovery position of
$8.5 million as of September 30, 1997, an under-recovery position of $19.3
million as of March 31, 1997, and an under-recovery position of $17.9
million as of March 31, 1998.
<PAGE>
Under the provisions of the utility's rate schedules, any under-recoveries
or over-recoveries of purchased gas costs are included in current assets or
liabilities and have no effect on net income. See Note 6 to Notes to
Condensed Consolidated Financial Statements in this Form 10-Q.
The expenditures for plant and other property totaled $56 million for
the six-month and $126.4 million for the twelve-month periods ended March
31, 1998, respectively.
AGL has accrued liabilities of $47 million as of March 31, 1998,
$31.3 million as of March 31, 1997, and $37.3 million as of September 30,
1997, for estimated future expenditures covering investigation and
remediation of MGP sites which are expected to be made over a period of
several years. The Georgia Commission has approved the recovery by AGL of
Environmental Response Costs pursuant to the ERCRR. In connection with the
ERCRR, the staff of the Georgia Commission has undertaken a financial and
management process audit related to the MGP sites, cleanup activities at
the sites and environmental response costs that have been incurred for
purposes of the ERCRR.
The Georgia Commission conducted hearings on April 16 and 17, 1998 to
consider three issues relating to the ERCRR. Specifically, the Georgia
Commission considered whether the term "Environmental Response Costs"
should include punitive damages, whether AGL should be required to provide
an annual accounting for revenue recovered from customers through the
ERCRR, and whether a schedule should be established for site remediation.
Additional hearings relating to this issue are expected to be scheduled in
the near future. See Note 5 to Notes to Condensed Consolidated Financial
Statements in this Form 10-Q.
In June 1997, AGL Capital Trust, a Delaware business trust (the
Trust), of which AGL Resources owns all of the common voting securities,
issued and sold to certain initial investors $75 million in principal
amount of 8.17% Capital Securities (liquidation amount $1,000 per Capital
Security), the proceeds of which were used to purchase from AGL Resources
8.17% Junior Subordinated Deferrable Interest Debentures due June 1, 2037.
The Capital Securities are subject to mandatory redemption upon repayment
of the Junior Subordinated Debentures on the stated maturity date of June
1, 2037, upon the earlier occurrence of certain events or upon the optional
prepayment by AGL Resources on or after June 1, 2007. AGL Resources has
fully and unconditionally guaranteed all of the Trust's obligations with
respect to the Capital Securities. Net proceeds to AGL Resources from the
sale of the Junior Subordinated Debentures of $74.3 million was used to
repay short-term debt, to redeem certain of AGL's outstanding issues of
preferred stock and for other corporate purposes.
On August 15, 1997, AGL redeemed its 4.5% Cumulative Preferred Stock,
4.72% Cumulative Preferred Stock, 5% Cumulative Preferred Stock, 7.84%
Cumulative Preferred Stock, and 8.32% Cumulative Preferred Stock at the
call price in effect for each issue for an aggregate principal amount of
$14.7 million. Those issues of preferred stock have been retired in full.
On December 1, 1997, AGL redeemed its 7.70% depositary preferred shares at
the redemption price of $100 per share for an aggregate principal amount of
$44.5 million.
Long-term debt outstanding increased $75.5 million during the
twelve-month period ended March 31, 1998, as a result of the issuance in
July 1997 by AGL of the remaining $75.5 million of $300 million aggregate
principal amount of Medium-Term Notes Series C. Net proceeds from the
issuance of Medium-Term Notes were used to fund capital expenditures, to
repay short-term debt and for other corporate purposes.
Short-term debt decreased $25.1 million for the six-month period
ended March 31, 1998 primarily due to net cash flow from operating
activities. Short-term debt decreased $108.6 million for the twelve-month
period ended March 31, 1998 primarily due to the issuance of Capital
Securities and long-term debt.
<PAGE>
On February 17, 1995, the Georgia Commission approved a settlement
that permits AGL to negotiate contracts with customers who have the option
of bypassing AGL's facilities (Bypass Customers) to receive natural gas
from other suppliers. The bypass avoidance contracts (Negotiated Contracts)
can be renewable, provided the initial term does not exceed five years,
unless a longer term specifically is authorized by the Georgia Commission.
The rate provided by the Negotiated Contract may be lower than AGL's filed
rate, but not less than AGL's marginal cost of service to the potential
Bypass Customer. Service pursuant to a Negotiated Contract may commence
without Georgia Commission action, after a copy of the contract is filed
with the Georgia Commission. Negotiated Contracts may be rejected by the
Georgia Commission within 90 days of filing; absent such action, however,
the Negotiated Contracts remain in effect. The settlement also provides for
a bypass loss recovery mechanism to operate until the earlier of September
30, 1998, or the effective date of new rates for AGL resulting from a
general rate case.
In addition to Negotiated Contracts, which are designed to serve
existing and potential Bypass Customers, AGL's ITSM Rider continues to
permit discounts for short-term transactions to compete with alternative
fuels. The settlement approved by the Georgia Commission also provides that
AGL may file contracts (Special Contracts) for Georgia Commission approval
if the service cannot be provided through the ITSM Rider, existing rate
schedules, or Negotiated Contract procedures. Pursuant to the approved
settlement, AGL has filed and is providing service pursuant to 56
Negotiated Contracts. Additionally, AGL is providing service pursuant to
seven Special Contracts. See Note 6 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
On November 27, 1996, the TRA approved an experimental rule allowing
Chattanooga to negotiate contracts with large commercial or industrial
customers who have long-term competitive options, including bypass. The
experimental rule provides that before any such customer is allowed a
discounted rate, both the large customer and Chattanooga must petition the
TRA for approval of the rates set forth in the contract. On October 7,
1997, the TRA denied petitions filed by Chattanooga and four large
customers for discounted rates pursuant to the experimental rule upon a
finding that customer bypass was not imminent. On January 14, 1998,
however, the FERC issued an order authorizing the bypass of Chattanooga by
Southern to serve an interruptible customer. AGL is continuing to negotiate
with the customer to determine whether a compromise can be reached to
retain the customer, and Southern has not yet constructed the facilities
necessary to complete the bypass. Management does not expect the order
issued by the FERC to have a material adverse effect on the consolidated
financial statements of AGL Resources.
The Georgia Gas Act was signed into law on April 14, 1997. The act
provides a legal framework for comprehensive deregulation of many aspects
of the natural gas business in Georgia. On November 26, 1997, AGL filed
with the Georgia Commission notice of its election to be subject to this
new law and to establish separate rates for unbundled services. AGL filed
contemporaneously an application with the Georgia Commission to have its
distribution rates, charges, classifications and services regulated
pursuant to performance-based regulation. The filing requests an increase
in revenues of $18.6 million annually. The requested increase includes the
costs to support changes in AGL's business systems to ensure reliable
service to customers and that the systems are in place to serve new gas
suppliers in the competitive marketplace. The Georgia Gas Act provides a
transition period leading to a condition of effective competition in all
natural gas markets. See Note 6 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
On May 1, 1997, Chattanooga filed a rate proceeding with the TRA
seeking an increase in revenues of $4.4 million annually. Revenues from the
rate increase will be used to improve and expand Chattanooga's natural gas
distribution system; to recover increased operation, maintenance and tax
expenses; and to provide a reasonable return to investors. Under the TRA's
rules and regulations, the effective date of the requested new rates was
suspended until November 1, 1997. Hearings in the rate proceeding were
scheduled to begin on
<PAGE>
October 13, 1997. On October 3, 1997, all parties to the proceeding filed a
motion with the TRA requesting that the hearings be continued and that the
suspended effective date for new rates be extended to afford an opportunity
to pursue settlement discussions. On October 7, 1997, the TRA granted the
motion. The hearings in this proceeding were convened February 9-13, 1998.
On March 13, 1998, Chattanooga filed a post-hearing brief reasserting the
basis of requested new rates. A decision in this rate case by the TRA
currently is pending.
AGL cannot predict the outcome of those state regulatory proceedings
nor determine the ultimate effect, if any, such proceedings may have on
AGL.
Year 2000
AGL Resources uses several computer application programs written over
many years using two-digit year fields to define the applicable year,
rather than four-digit year fields. Programs that are time-sensitive may
recognize a date using "00" as the year 1900 rather than the year 2000.
That misinterpretation of the year could result in incorrect computation or
computer shutdown.
With the assistance of an independent consultant, AGL Resources has
identified the systems that could be affected by the year 2000 issue and
has developed a plan to resolve the issue. The plan provides for, among
other things, the replacement or modification of existing data processing
systems as necessary. Implementation of the plan has begun and the cost
estimates associated with the implementation of the plan are not expected
to significantly impact AGL Resources' consolidated financial statements.
Management believes that with the appropriate modification, AGL
Resources will be able to operate its time-sensitive business systems
through the turn of the century.
Accounting Developments
In February 1997 the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 128, "Earnings Per Share,"
(SFAS 128), which establishes standards for computing and presenting
earnings per share. AGL Resources adopted SFAS 128 in October 1997. See
Note 7 in Notes to Condensed Consolidated Financial Statements in this Form
10-Q.
During its July 1997 meeting, the Financial Accounting Standard
Board's 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, Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71), should be discontinued for that segment. The state
of Georgia has enacted legislation, the Georgia Gas Act, that allows for
the deregulation of the merchant function and unbundling of certain
ancillary services of local gas distribution companies. AGL has filed its
election to become an electing distribution company. The rates to transport
natural gas through the intrastate pipe system of the local gas
distribution company will be regulated by the Georgia Commission. Since
AGL's regulatory assets and liabilities associated with its gas
distribution activities continue to be regulated, AGL has determined that
the continued application of SFAS 71 related to those distribution
activities remains appropriate.
In June 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 130, "Reporting
Comprehensive Income" (SFAS 130) and Statement of Financial Accounting
Standard No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS 131). AGL Resources will adopt SFAS 130 and SFAS 131 in
fiscal year 1999. SFAS 130 establishes standards for the reporting and
displaying of comprehensive income and its components (revenues, expenses,
gains, and losses)
<PAGE>
in a full set of general-purpose financial statements. SFAS 131 establishes
standards for the way that public business enterprises report information
about operating segments in annual financial statements and requires that
those enterprises report selected information about operating segments in
interim financial reports issued to shareholders.
Management does not expect these new pronouncements to have a
significant impact on the presentation of AGL Resources' consolidated
financial statements.
During November 1997, the EITF published Issue No. 97-13 "Accounting
for Costs Incurred in Connection with a Consulting Contract or an Internal
Project That Combines Business Process Reengineering and Information
Technology Transformation." Issue No. 97-13 addresses costs which have been
incurred by organizations related to advances in computer technologies.
Some of the costs which have been incurred include consulting fees paid for
business process reengineering and information technology transformation.
The EITF concluded that these costs should be expensed as incurred rather
than capitalized. The EITF requires items previously capitalized to be
written off during the quarter which includes November 20, 1997. The
impacts of applying the effects of this consensus were not significant to
the financial results for the six-month period ended March 31, 1998.
(The remainder of this page was intentionally left blank.)
<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, 1997, and should be read in conjunction therewith.
ITEM 1. LEGAL PROCEEDINGS
See Item 5.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Annual Meeting of Shareholders was held on February 6, 1998 (the
"Annual Meeting"). "Broker non-votes" were not considered in determining
whether a quorum existed for purposes of the Annual Meeting. At the Annual
Meeting the shareholders elected the following four nominees for director
to hold office until the Annual Meeting of Shareholders in the year 2001,
as set forth in AGL Resources' Proxy Statement. The number of votes "for"
each nominee and the number of votes "withheld" with respect to each
nominee is as follows:
For Withheld
---------------- --------------
1. D. Raymond Riddle 49,044,962 831,183
2. Dr. Betty L. Siegel 48,779,344 1,096,801
3. Ben J. Tarbutton, Jr. 49,065,586 810,559
4. Felker W. Ward, Jr. 48,847,341 1,028,804
Directors whose term of office continued after the Annual Meeting are:
Frank Barron, Jr., W. Waldo Bradley, Otis A. Brumby, Jr., L.L. Gellerstedt,
III, David R. Jones, Albert G. Norman, Jr. and Charles McKenzie Taylor. In
addition, Walter M. Higgins was elected as a director by the Board of
Directors on February 6, 1998, and L.L. Gellerstedt, III tendered his
resignation as a director effective May 1, 1998.
ITEM 5. OTHER INFORMATION
Federal Regulatory Matters
FERC Order 636 Transition Costs Settlement Agreements. Based on
filings with the FERC by its pipeline suppliers, AGL currently estimates
that its total portion of transition costs associated with the FERC's Order
No. 636 from all of its pipeline suppliers will be approximately $104.8
million. Approximately $95.6 million of such costs has been incurred by AGL
as of March 31, 1998, and is being recovered from its customers under the
purchased gas provisions of AGL's rate schedules.
FERC Rate Proceedings. AGL participates in various rate proceedings
before the FERC involving applications for rate changes filed by its
pipeline suppliers. These proceedings typically involve numerous issues
concerning the pipeline's cost of service, allocation of costs to different
services, and rate design. A variety of cost allocation and rate design
proposals typically are advanced by the pipeline's customers, making it
impossible to forecast the precise effect of any given rate change filing
on AGL's operations. AGL is authorized to recover the costs paid to its
pipeline suppliers from its customers through the purchased gas provisions
of its rate schedules. To the extent that these cases have not been
settled, as described below, the rates filed in these proceedings have been
accepted, and made effective subject to refund and the outcome of the FERC
proceedings.
<PAGE>
Transco. On March 24, 1998, a FERC administrative law judge issued
an initial decision which, among other things, rejected the proposal by
Transco and other parties to roll into Transco's system rates the costs of
certain expansion facilities. AGL opposed Transco's proposed roll-in
methodology, which would have increased substantially the rates AGL pays
for a bundled storage and transportation service provided by Transco. The
initial decision is subject to the filing of exceptions by Transco and
other parties, and therefore is not yet final.
ANR Pipeline. On February 13, 1998, the FERC issued an order
approving ANR's proposed settlement of its current rate case, which will
provide AGL with reductions of approximately $3 million in rates,
prospectively, as well as rate refunds. The FERC's order approving the
settlement is final.
AGL cannot predict the outcome of those federal proceedings nor
determine the ultimate effect, if any, such proceedings may have on AGL.
State Regulatory Matters
Atlanta Gas Light Company - Unbundling and Rate Filing. The Georgia
Gas Act was signed into law on April 14, 1997. The act provides a legal
framework for comprehensive deregulation of many aspects of the natural gas
business in Georgia.
On November 26, 1997, AGL filed with the Georgia Commission notice of
its election to be subject to this new law and to establish separate rates
for unbundled services. AGL filed contemporaneously an application with the
Georgia Commission to have its distribution rates, charges, classifications
and services regulated pursuant to performance-based regulation. The filing
requests an increase in revenues of $18.6 million annually. The requested
increase includes the costs to support changes in AGL's business systems to
ensure reliable service to customers and that the systems are in place to
serve new gas suppliers in the competitive marketplace.
Within seven months from the date of such filing, the Georgia
Commission must issue an order approving the plan as filed or with
modification. Retail marketing companies, including AGL affiliates, may
then file with the Georgia Commission separate certificate of authority
applications to sell natural gas to firm customers connected to AGL's
delivery system. It is currently anticipated that marketers who become
certificated by the Georgia Commission may begin offering natural gas sales
services to customers of AGL by November 1998.
The Georgia Gas Act provides a transition period leading to a
condition of effective competition in all natural gas markets. AGL, as an
electing distribution company, will unbundle all services to its natural
gas customers, allocate firm delivery capacity to certificated marketers
selling the gas commodity and create a secondary market for interruptible
transportation capacity. Certificated marketers, including nonutility
affiliates of AGL, will compete to sell natural gas to all customers at
market-based prices. AGL will continue to provide intrastate delivery of
gas to end users through its existing system, subject to continued rate
regulation by the Georgia Commission. As a result of the election to be
subject to the Georgia Gas Act, it is expected that the purchased gas
adjustment provisions included in AGL's rate schedules will be discontinued
during fiscal 1999. The November 26, 1997, filing contains a provision to
true-up any over-recovery or under-recovery that may exist at the time such
purchased gas adjustment provisions are discontinued. Accordingly, AGL will
no longer defer any over-recoveries or under-recoveries of gas costs when
the purchased gas adjustment provisions are discontinued. In addition, the
Georgia Commission will continue to regulate safety, access and quality of
service pursuant to an alternative form of regulation.
<PAGE>
The Georgia Gas Act provides marketing standards and rules of
business practice designed to ensure the benefits of a competitive natural
gas market are available to all customers on AGL's system. The act imposes
on marketers an obligation to serve with a corresponding universal service
fund that provides a funding mechanism for uncollectible accounts and
enables AGL to expand its facilities and serve the public interest.
Hearings in this proceeding began on March 9, 1998, and are scheduled
to continue the weeks of April 28, 1998 and May 18, 1998. A decision by the
Georgia Commission is expected in June 1998.
Pursuant to the Georgia Gas Act, the Georgia Commission issued rules
and regulations on December 30, 1997, for certification of marketers and
assignment of firm customers to marketers for customers who ultimately do
not select a marketer after competition is fully developed. Additionally,
the Georgia Commission issued a Notice of Inquiry to address certain
aspects of random assignment of customers and marketer certification not
fully resolved in the rulemakings.
AGL supported the regulatory initiatives provided for by the Georgia
Gas Act for several reasons. AGL currently makes no profit on the purchase
and sale of gas because actual gas procurement costs are passed through to
customers under the purchased gas provisions of AGL's rate schedules.
Earnings are provided through revenues received for intrastate
transportation of the commodity. Consequently, allowing AGL to cease its
sales service function and the associated sales obligation would not affect
AGL's ability to earn a return on its distribution system investment.
Allowing gas to be sold to all customers by numerous retail marketing
companies, including nonutility subsidiaries of AGL Resources, would
provide new business opportunities.
Atlanta Gas Light Company - Other. On January 8, 1998, the Georgia
Commission issued a Procedural and Scheduling Order to establish a schedule
for certain hearings and pre-hearings in connection with alleged pipeline
safety violations. Hearings in this proceeding had been scheduled for March
31 and April 1, 1998. The Georgia Commission now has granted a stay of the
Procedural Schedule to allow the Georgia Commission and AGL to engage in
discussions to determine whether the issues presented in the proceeding can
be resolved between the parties by compromise and settlement. The stay will
continue for the duration of the settlement discussions between the
parties.
Chattanooga Gas Company - Rate Filing. On May 1, 1997, Chattanooga
filed a rate proceeding with the TRA seeking an increase in revenues of
$4.4 million annually. Revenues from the rate increase would be used to
improve and expand Chattanooga's natural gas distribution system; to
recover increased operation, maintenance and tax expenses; and, to provide
a reasonable return to investors. Under the TRA's rules and regulations,
the effective date of the requested new rates was suspended until November
1, 1997. Hearings in the rate proceeding were scheduled to begin on October
13, 1997. On October 3, 1997, all parties to the proceeding filed a motion
with the TRA requesting that the hearings be continued and that the
suspended effective date for new rates be extended to afford an opportunity
to pursue settlement discussions. On October 7, 1997, the TRA granted the
motion. The hearings in this proceeding were convened February 9-13, 1998.
On March 13, 1998, Chattanooga filed a post-hearing brief reasserting the
basis of requested new rates. A decision in this rate case by the TRA
currently is pending.
AGL cannot predict the outcome of those state regulatory proceedings
nor determine the ultimate effect, if any, such proceeding may have on AGL.
<PAGE>
Environmental Matters
AGL has identified nine sites in Georgia where it currently owns all
or part of an MGP site. In addition, AGL has identified three other sites
in Georgia which AGL does not own, but that may have been associated with
the operation of MGPs by AGL or its predecessors.
Those sites are potentially subject to a variety of regulatory
programs. AGL's response to MGP sites in Georgia is proceeding under two
state regulatory programs, HWMA and HSRA, as previously defined in Note 5
to Notes to Condensed Consolidated Financial Statements in this Form 10-Q.
AGL is planning to undertake some degree of response action, under one or
both of those programs, at most of the Georgia sites.
AGL also has identified three sites in Florida which may have been
associated with AGL or its predecessors. AGL does not own any of the former
MGP sites in Florida. At one site, AGL has entered into an Administrative
Order of Consent along with four other potentially responsible parties to
further investigate this site. At another site, AGL has received a "Special
Notice Letter" from the EPA, and is negotiating the scope of a response
with both EPA and the current owner.
AGL has estimated the investigation and remediation expenses likely
to be associated with the former MGP sites. First, AGL has identified
several sites where it has concluded that no significant response actions
are reasonably likely in the foreseeable future and therefore has not made
any cost projections for these sites. Second, since response cost
liabilities are often spread among potentially responsible parties, AGL's
ultimate liability will, in some cases, be limited to AGL's equitable share
of such expenses under the circumstances. Therefore, where reasonably
possible, AGL has attempted to estimate the range of AGL's equitable share,
given current cost sharing arrangements, combined with AGL's current
knowledge of relevant facts, including the current methods of equitable
apportionment and the solvency of potential contributors. Where such an
estimation was not reasonably possible, AGL has estimated a range of
expenses without adjustment for AGL's equitable share. Finally, AGL has,
with the assistance of outside consultants, prepared estimates of the range
of future investigation and remediation costs for those sites where further
action appears likely.
Applying these concepts to those sites where some future action
presently appears reasonably possible, AGL currently estimates that the
future cost to AGL of investigating and remediating the former MGP sites
could be as low as $47 million or as high as $81.3 million. That range does
not include other expenses, such as unasserted property damage claims, for
which AGL may be held liable, but for which neither the existence nor the
amount of such liabilities can be reasonably forecast. Within the stated
range of $47 million to $81.3 million, no amount within the range can be
identified reliably as a better estimate than any other estimate.
Therefore, a liability at the low end of that range has been recorded in
the financial statements.
AGL has two means of recovering the expenses associated with the
former MGP sites. First, the Georgia Commission has approved the recovery
by AGL of Environmental Response Costs, as defined, pursuant to an ERCRR.
For purposes of the ERCRR, Environmental Response Costs include
investigation, testing, remediation and litigation costs and expenses or
other liabilities relating to or arising from MGP sites. A regulatory asset
in the amount of $69.7 million has been recorded in the financial
statements to reflect the recovery of those costs through the ERCRR.
In connection with the ERCRR, the staff of the Georgia Commission has
undertaken a financial and management process audit related to the MGP
sites, cleanup activities at the sites, and environmental response costs
that have been incurred for purposes of the ERCRR. The Georgia Commission
conducted hearings on April 16 and 17, 1998 to consider three issues
relating to the ERCRR. Specifically, the Georgia Commission considered
whether the term "Environmental Response Costs" should include punitive
damages, whether AGL
<PAGE>
should be required to provide an annual accounting for revenue recovered
from customers through the ERCRR, and whether a schedule should be
established for site remediation. Additional hearings relating to these
issues are expected to be scheduled in the near future.
Second, AGL intends to seek recovery of appropriate costs from its
insurers and other potentially responsible parties. During the twelve month
period ended March 31, 1998, AGL recovered $4.5 million from its insurance
carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGL recognized other income of $1.4 million and
established regulatory liabilities for the remainder of the recoveries.
On February 10, 1995, a class action lawsuit captioned Trinity
Christian Methodist Episcopal Church, et al. v. Atlanta Gas Light Company,
No. 95-RCCV-93, was filed in the Superior Court of Richmond County,
Georgia, seeking to recover for damage to property owned by persons
adjacent to and near the former MGP site in Augusta, Georgia. On December
13, 1996, the parties reached a preliminary settlement, which was approved
by the Court on April 15, 1997. Pursuant to the settlement, there is a
claims process before an umpire to determine either the full fair market
value of properties tendered to AGL or the diminution in fair market value
of properties not tendered to AGL. Settlements were paid to 188 property
owners in the class totaling approximately $2.9 million, including legal
fees and expenses of the plaintiffs. One settlement of approximately
$64,000, including attorney's fees, is pending reconsideration. AGL filed
motions to vacate six settlements totaling approximately $4.3 million.
Orders were entered denying the motions to vacate. AGL filed notices of
appeal with the Georgia Court of Appeals seeking to reverse the denial of
the motions to vacate. On March 25, 1998, the Georgia Court of Appeals
affirmed the ruling of the lower court. Pursuant to the Court of Appeals
decision, six settlements totaling $4.9 million, including attorney's fees
and post judgement interest, have been paid; and are recoverable pursuant
to the terms of the ERCRR.
Other Legal Proceedings
With regard to other legal proceedings, AGL Resources is a party, as
both plaintiff and defendant, to a number of other suits, claims and
counterclaims on an ongoing basis. Management believes that the outcome of
all litigation in which it is involved will not have a material adverse
effect on the consolidated financial statements of AGL Resources.
Joint Ventures
On December 1, 1997, AGL Resources, through its subsidiary AGL
Interstate Pipeline, entered into a joint venture with a subsidiary of
Transcontinental Gas Pipe Line Corporation (Transco) Transcumberland
Pipeline Company, known as Cumberland Pipeline Company (Cumberland), to
provide interstate pipeline services to customers in Georgia and Tennessee.
The transaction is subject to various regulatory approvals. Initially, the
135-mile Cumberland pipeline will include existing pipeline infrastructure
owned by the two companies extending from Walton County, Georgia, to
Catoosa County, Georgia. Projected to enter service by November 1, 2000,
Cumberland will be positioned to serve AGL, Chattanooga and other markets
throughout the eastern Tennessee Valley, northwest Georgia and northeast
Alabama. Affiliates of Transco and AGL Resources each will own 50% of
Cumberland, and an affiliate of Transco will serve as operator. The
companies announced an open season from March 30, 1998 to May 29, 1998 for
subscriptions for capacity on Cumberland, and the project will be submitted
to the FERC for approval during fiscal year 1998.
On December 15, 1997, AGL Resources, through its subsidiary AGL
Peaking Services, and Southern, a subsidiary of Sonat Inc., entered into an
agreement to jointly construct, own and operate a new liquefied natural gas
peaking facility, Etowah LNG (Etowah), in Polk County, Georgia. The
transaction is subject to regulatory
<PAGE>
approvals. AGL Peaking Service and Southern each will own 50 percent of
Etowah, the operations of which will be subject to jurisdiction of the
FERC.
The proposed plant will connect directly into AGL's and Southern's
pipelines. Etowah will provide natural gas storage and peaking services to
AGL and other southeastern customers. The new facility will cost
approximately $90 million, with 2.5 billion-cubic-feet of natural gas
storage capacity and 300 million-cubic-feet per day of vaporization
capacity. Affiliates of AGL Resources will manage the construction of the
facility and operate it. Southern will provide administrative services.
The companies held an open season from December 1, 1997 to January
30, 1998 for Etowah subscriptions for peaking services, and subscriptions
for 71% of the total firm peak service capacity were received. A
certificate application was filed by the companies with the FERC on April
20, 1998. Subject to receiving timely FERC approval, construction will
begin in early 1999 in order to provide peaking services during the
2001-2002 winter heating season.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
10.1 Executive Compensation Plans and Arrangements.
10.1.a Sixth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit 10.1.b, AGL Resources Form
10-K for the fiscal year ended September 30, 1997).
10.2 Amendment to Service Agreement between Transcontinental Gas
Pipe Line Corporation and Atlanta Gas Light Company dated
December 15, 1997 (Exhibit 10.3, AGL Resources Form 10-K for
the fiscal year ended September 30, 1997).
10.3 Service Agreement between Transcontinental Gas Pipe Line
Corporation and Atlanta Gas Light Company dated January 14,
1998.
27.1 Financial Data Schedule.
27.2 Finacial Data Schedules (Restated)
(b) Reports on Form 8-K.
None.
<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 5/15/98 /s/ J. Michael Riley
J. Michael Riley
Senior Vice President and Chief Financial Officer
(Principal Accounting and Financial Officer)
SIXTH AMENDMENT TO THE
AGL RESOURCES INC. LONG-TERM
STOCK INCENTIVE PLAN OF 1990
This Sixth Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (the "Plan") is made and entered into as of this 6th day
of February 1998, by AGL Resources Inc. (the "Company").
W I T N E S S E T H:
WHEREAS, the Company sponsors the Plan to provide incentive and to
encourage proprietary interest in the Company by its key employees, officers and
inside directors; and
WHEREAS, the Company has determined that it would be in the best
interest of the Company, its employees and the employees of its subsidiaries to
amend the Plan to provide for the extension of certain exercise periods for
options and to change the definition of fair market value; and
WHEREAS, Section 10 of the Plan provides that the Company may amend the
Plan at any time; and
WHEREAS, at its meeting on February 6, 1998, the Board of Directors of
the Company adopted a resolution authorizing the amendment of the Plan;
NOW, THEREFORE, BE IT RESOLVED, that the Plan hereby is amended as
follows:
1.
Subsection 5(c)(ii) of the Plan shall be amended, effective as of March
1, 1998, by deleting that subsection in its entirety and substituting in lieu
thereof the following subsection:
"(ii) The fair market value of the Common Stock on any
particular date shall be the closing sale price per share of the Common
Stock on the New York Stock Exchange (or other established exchange on
which the Common Stock is listed) on the trading day preceding that
particular date. If, for any reason, the fair market value per share of
Common Stock cannot be ascertained or is unavailable for a particular
date, the fair market value of the Common Stock shall be determined as
of the nearest preceding date on which such fair market value can be
ascertained pursuant to the terms hereof."
2.
Subsection 5(j)(ii) of the Plan shall be amended, effective as of
January 1, 1998, by deleting that subsection in its entirety and substituting in
lieu thereof the following subsection:
<PAGE>
"(ii) Upon an Optionee's retirement with the Company's consent
or upon the termination of an Optionee's employment due to disability,
such disability as affirmed by the Committee in its sole discretion,
any Option or unexercised portion thereof granted to him which is
otherwise exercisable shall terminate on and shall not be exercisable
after 12 months from the date of the Optionee's retirement with the
consent of the Company or after 3 months from the date of the
Optionee's termination due to disability. Effective as of January 1,
1998, upon an Optionee's retirement with the Company's consent, the
Committee, in its sole discretion, may extend the exercise period for
an Option or unexercised portion thereof granted to the Optionee which
is otherwise exercisable through the end of the term of that Option.
Further, upon an Optionee's retirement with the Company's consent, any
ISO or unexercised portion thereof which remains unexercised on the
date three months after the date on which such Optionee ceases to be an
employee of the Company and any Subsidiary shall convert to a Non-ISO
through the end of the term of that Option. Notwithstanding the above,
the Committee may provide in the Option Agreement that such Option or
any unexercised portion thereof shall terminate sooner. An Option shall
be exercisable in accordance with its terms and only for the number of
shares exercisable on the date such Optionee's employment ceases."
3.
Section 7 of the Plan shall be amended, effective as of March 1, 1998,
by adding the following subsection (h) to the end thereof:
"(h) Fair Market Value. For purposes of this Section 7, the fair
market value on any particular date of the Common Stock
underlying an award shall be determined pursuant to the terms of
Section 5(c) of the Plan."
4.
Except as specifically set forth herein, the terms of the Plan shall
remain in full force and effect.
IN WITNESS WHEREOF, the Company has caused this Sixth Amendment to the
Plan to be executed by its duly authorized officer as of the date first above
written.
AGL RESOURCES INC.
By: /s/ Robert L. Goocher
Robert L. Goocher
Executive Vice President
S2.508341
AMENDMENT OF SERVICE AGREEMENT
THIS AMENDMENT ("Amendment") is entered into this 15th day of December
1997, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware
corporation, hereinafter to as `Seller", first part, and ATLANTA GAS LIGHT
COMPANY, hereinafter referred to as "Buyer", second party.
WITNESSETH:
WHEREAS, Seller and Buyer entered into that certain Service Agreement,
dated August 16, 1974, under Seller's Rate Schedule LG-A ("Service Agreement")
pursuant to which Seller provides liquefied natural gas storage service for
Buyer up to a total volume of 207,610 Mcf of natural gas which is Buyer's
Liquefaction Capacity Volume; and
WHEREAS, Seller and Buyer now desire to renew and extend the primary
term of the Service Agreement.
NOW THEREFORE, Seller and Buyer hereby agree to renew and amend the
Service Agreement as follows:
1. Article IV of the Service Agreement is hereby deleted in its entirety
and replaced by the following:
"ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of November 1, 1974, and shall
remain in force and effect until 8:00 a.m. Eastern Standard Time
October 31, 2002 1, and thereafter until terminated by Seller or Buyer
upon at least one hundred eighty (180) days prior written notice and
subject to the receipt of necessary authorizations; provided, however,
this agreement shall terminate immediately and, subject to the receipt
of necessary authorizations, Seller may discontinue service hereunder
if (a) Buyer, in Seller's reasonable judgement fails to demonstrate
creditworthiness, 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."
2. As herein amended, the Service Agreement is hereby renewed in full
force and effect pursuant to the terms thereof.
3. This Amendment shall be effective as of the date first above written.
____________________________
1 The parties hereto mutually acknowledge that the term of this agreement
is the result of a negotiated compromise between Buyer and Seller and shall not
be relied upon by either party as precedent for any future contract term
negotiation for this or any other service provided by Seller. Further, the term
of this agreement shall not be raised by either party in any proceeding before
the FERC as having established any precedent whatsoever to the length of contra
terms.
<PAGE>
LG-A Amendment
Page 2
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE ATLANTA GAS LIGHT COMPANY
CORPORATION ("Seller") ("Buyer")
By: /s/ Frank J. Ferazzi By: /s/ Thomas H. Benson
-------------------------- ------------------------------
Frank J. Ferazzi
Vice President Title ___________________________
Customer Service
Contract # ___________
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
ATLANTA GAS LIGHT COMPANY
Dated
January 14, 1998
<PAGE>
SERVICE AGREEMENT
THIS AGREEMENT entered into this 14th day of January, 1998, by and
between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation,
hereinafter referred to as "Seller," first party, and ATLANTA GAS LIGHT COMPANY,
hereinafter referred to as "Buyer," second party,
WITNESSETH
WHEREAS, Seller has filed an application with the Federal Energy
Regulatory Commission in Docket No. CP97-331 for a certificate of public
convenience and necessity authorizing Seller's 1998 Cherokee Expansion Project
(referred to as the "Cherokee Expansion"); and
WHEREAS, the Cherokee Expansion will add 87,070 Dt per day (at 1035 Btu
per standard cubic foot) of incremental firm transportation capacity on Seller's
mainline system by a proposed in-service date of November 1, 1998: and
WHEREAS, Buyer has requested firm transportation service under the
Cherokee Expansion and has executed with Seller a Precedent Agreement, dated
February 28, 1997, for such service; and
WHEREAS, Seller is willing to provide the requested firm transportation
for Buyer under the Cherokee Expansion pursuant to the terms of this Service
Agreement and the Precedent Agreement.
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 85,000 Dt per day at 1035 Btu per
standard cubic foot (but in no event to exceed 82,125.6 Mcf per day,
irrespective of the actual heat content of the gas).
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.
2
<PAGE>
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
delivered by Buyer shall not exceed the maximum operating pressure(s) of
Seller's pipeline system at such point(s) of receipt. In the event the maximum
operating pressure(s) of Seller's pipeline system, at the point(s) of receipt
hereunder, is from time to time increased or decreased, then the maximum
allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to
Seller at the point(s) of receipt shall be correspondingly increased or
decreased upon written notification of Seller to Buyer. The point(s) of receipt
for natural gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas
transported hereunder at the following point(s) of delivery and at a
pressure(s)of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of the later of November 1, 1998
or the date Seller's facilities necessary to provide service to Buyer under the
Cherokee Expansion have been constructed and are ready for service, and shall
remain in force and effect until 10:00 a.m. Eastern Standard Time November 1,
2013 and year to year thereafter until terminated by Seller or Buyer upon at
least one (1) year 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, 1989 revised Stipulation and Agreement in
Docket Nos. RP88-68 et. al., (a) pregranted abandonment under Section 284.221(d)
of the Commission's Regulations shall not apply to any long term conversions
from firm sales service to transportation service under Seller's Rate Schedule
FT and (b) Seller shall not exercise its right to terminate this service
agreement as it applies to transportation service resulting from conversions
from firm sales service so long as Buyer is willing to pay rates no less
favorable than Seller is otherwise able to collect from third parties for such
service.
3
<PAGE>
SERVICE AGREEMENT (CONTINUED)
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 this service agreement.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers
or causes to be delivered to Seller shall include the quantity of gas retained
by Seller for applicable compressor fuel, line loss make-up (and injection fuel
under Seller's Rate Schedule GSS, if applicable) in providing the transportation
service hereunder, which quantity may be changed from time to time and which
will be specified in the currently effective Sheet No. 44 of Volume No. 1 of
this Tariff which relates to service under this agreement and which is
incorporated herein.
3. In addition to the applicable charges for firm transportation
service pursuant to Section 3 of Seller's Rate Schedule FT, Buyer shall
reimburse Seller for any and all filing fees incurred as a result of Buyer's
request for service under Seller's Rate Schedule FT, to the extent such fees are
imposed upon Seller by the Federal Energy Regulatory Commission or any successor
governmental authority having jurisdiction.
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date
hereof the following contract(s) between the parties hereto:
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 or
different character.
3. The interpretation and performance of this agreement shall be in
accordance with the laws of the State of Texas, without recourse to the law
governing conflict of laws, and to all present and future valid laws with
respect to the subject matter, including present and future orders, rules and
regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of
the parties hereto and their respective successors and assigns.
4
<PAGE>
SERVICE AGREEMENT (CONTINUED)
5. Notices to either party shall be in writing and shall be considered
as duly delivered when mailed to the other party at the following address:
(a) If to Seller:
Transcontinental Gas Pipe Line Corporation
P.O. Box 1396
Houston, Texas, 77251-1396
Attention: Director - Customer Services
(b) If to Buyer:
Atlanta Gas Light Company
P.O.Box 4569
Atlanta, Georgia 30302-4569
Attention: Eileen Stanek
Such addresses may be changed from time to time by mailing appropriate notice
thereof to the other party by certified or registered mail.
IN WITHNESS WHEREOF, the parties hereto have caused this agreement to
be signed by their respective officers or representatives thereunto duly
authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Seller)
By: /s/ Frank J. Ferazzi
Frank J. Ferazzi
Vice President - Customer Services
ATLANTA GAS LIGHT COMPANY
(Buyer)
By: /s/ Thomas H. Benson
5
<PAGE>
EXHIBIT A
Maximum Daily Quantity
Point(s) of Receipt at each Receipt Pt. (Dt/d) 1
Point of interconnection between Transco's mainline 85,000
and Mobile Bay Lateral at milepost 784.66 in Choctaw
County, Alabama
__________________________
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.
<PAGE>
EXHIBIT B
Maximum Daily Quantity
Point(s) of Delivery and Pressure 2 at each Delivery Pt. (Dt/d) 3
Suwanee Delivery Point in Gwinnett County, Georgia 85,000
___________________________
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 points, as such DPE's are set
forth in Transco's FERC Gas Tariff, as amended from time to time.
<PAGE>
EXHIBIT C
Specification of Negotiated Rate and Term
Not Applicable
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
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