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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 1995
Commission file number 1-9905
ATLANTA GAS LIGHT COMPANY
(Exact name of registrant as specified in its charter)
GEORGIA 58-0145925
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
303 PEACHTREE STREET, NE 30308
ATLANTA, GEORGIA (Zip Code)
(Address of principal executive offices)
(404) 584-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of June 30, 1995.
Common Stock, $5.00 Par Value
Shares Outstanding at June 30, 1995. . . . . . . . . . . . . . . .27,375,405
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ATLANTA GAS LIGHT COMPANY
Quarterly Report on Form 10-Q
For the Quarter Ended June 30, 1995
Table of Contents
Item Page
Number PART I FINANCIAL INFORMATION Number
1 Financial Statements
Condensed Consolidated Income Statements (Unaudited) for
the Three Months, Nine Months and Twelve Months Ended
June 30, 1995 and 1994 3
Condensed Consolidated Balance Sheets (Unaudited) at
June 30, 1995, June 30, 1994 and September 30, 1994 4
Condensed Consolidated Statements of Cash Flows (Unaudited)
for the Nine Months and Twelve Months Ended
June 30, 1995 and 1994 6
Notes to Condensed Consolidated Financial Statements
(Unaudited) 7
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 11
PART II OTHER INFORMATION
1 Legal Proceedings 15
5 Other Information 16
6 Exhibits and Reports on Form 8-K 21
SIGNATURES 22
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PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS (UNAUDITED)
FOR THE THREE MONTHS, NINE MONTHS AND TWELVE MONTHS ENDED
JUNE 30, 1995 AND 1994
(MILLIONS, EXCEPT PER SHARE DATA)
Three Months Nine Months Twelve Months
1995 1994 1995 1994 1995 1994
Operating Revenues . . .$177.5 $191.2 $954.5 $1,053.3 $1,101.1 $1,203.6
Cost of Gas. . . . . . . 84.8 106.0 542.8 664.2 615.4 745.6
Operating Margin . . 92.7 85.2 411.7 389.1 485.7 458.0
Other Operating Expenses:
Operating Expenses . 77.7 78.0 247.2 243.4 325.0 315.0
Restructuring Costs . 1.7 69.2 69.2
Total Other Operating Expenses. .
79.4 78.0 316.4 243.4 394.2 315.0
Income Taxes . . . . . . 1.1 (0.4) 20.1 39.7 14.7 34.9
Operating Income. . . 12.2 7.6 75.2 106.0 76.8 108.1
Other Income:
Other Income and Deductions . .
0.3 0.4 2.7 4.6 3.3 8.2
Income Taxes. . . . . (0.1) (0.9) (1.8) (1.1) (3.1)
Other Income - Net. . 0.3 0.3 1.8 2.8 2.2 5.1
Income Before Interest Charges . .
12.5 7.9 77.0 108.8 79.0 113.2
Interest Charges . . . . 11.1 11.7 36.5 35.9 48.2 47.7
Net Income (Loss). . . . 1.4 (3.8) 40.5 72.9 30.8 65.5
Dividends on Preferred Stock . .
1.1 1.1 3.3 3.3 4.5 4.4
Earnings (Loss) Applicable to
Common Stock . . . . $0.3 $(4.9) $37.2 $69.6 $26.3 $61.1
Earnings (Loss) Per Share of
Common Stock. . . . . $0.01 $(0.19) $1.44 $2.78 $1.02 $2.45
Cash Dividends Paid Per Share of
Common Stock. . . . . $0.52 $0.52 $1.56 $1.56 $2.08 $2.08
Average Number of Common Shares
Outstanding (Millions) 26.3 25.2 25.8 25.1 25.7 25.0
See notes to condensed consolidated financial statements.
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ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(MILLIONS)
June 30, September 30,
1995 1994 1994
ASSETS
Utility Plant. . . . . . . . . . . $1,890.2 $1,810.0 $1,833.2
Less Accumulated Depreciation. . . 575.4 545.5 553.6
Utility Plant - Net. . . . . . . 1,314.8 1,264.5 1,279.6
Other Property and Investments (less
accumulated depreciation) . . . . 18.6 17.9 17.8
Current Assets:
Cash and Cash Equivalents . . . . 78.4 3.4 3.3
Receivables (less allowance for
uncollectible accounts of $5.9 at
June 30, 1995, $3.9 at June 30, 1994
and $2.8 at September 30, 1994) 102.0 100.7 79.3
Inventories:
Natural Gas Stored Underground 64.1 96.1 144.5
Liquefied Natural Gas. . . . . 12.4 14.9 17.8
Liquefied Petroleum Gas. . . . 1.6 3.4 3.6
Merchandise. . . . . . . . . . 1.3 4.0 4.4
Materials and Supplies . . . . 9.2 10.0 9.1
Other . . . . . . . . . . . . . . 9.5 8.8 9.1
Total Current Assets. . . . . 278.5 241.3 271.1
Deferred Debits and Other Assets:
Unrecovered Environmental Response Costs . .
34.7 24.5 30.5
Unrecovered Integrated Resource Plan Costs. .
11.2 6.6 11.4
Other . . . . . . . . . . . . . . 23.3 37.8 32.5
Total Deferred Debits and Other Assets. .
69.2 68.9 74.4
Total. . . . . . . . . . . $1,681.1 $1,592.6 $1,642.9
See notes to condensed consolidated financial statements.
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ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(MILLIONS)
June 30, September 30,
1995 1994 1994
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock, $5 Par Value, Shares Issued and
Outstanding of 27.4 at June 30, 1995,
25.3 at June 30, 1994 and 25.4 at
September 30, 1994 . . . . . . . . $136.9 $126.3 $127.1
Premium on Capital Stock . . . . . . 295.0 236.9 241.3
Earnings Reinvested . . . . . . . . 147.3 174.2 150.1
Total Common Stock Equity . . . . 579.2 537.4 518.5
Preferred Stock, Cumulative $100 Par or Stated
Value, Shares Issued and Outstanding of 0.6
at June 30, 1995, June 30, 1994 and
September 30, 1994 . . . . . . . 58.5 58.6 58.5
Long-Term Debt . . . . . . . . . . . 554.5 554.5 554.5
Total Capitalization. . . . . . . 1,192.2 1,150.5 1,131.5
Current Liabilities:
Redemption Requirements on Preferred Stock . .
0.3 0.3 0.3
Long-Term Debt Due Within One Year . 15.0 15.0
Short-Term Debt. . . . . . . . . . . 18.0 95.4
Accounts Payable . . . . . . . . . . 55.5 51.7 57.6
Deferred Purchased Gas Adjustment. . 62.4 49.3 20.1
Customer Deposits. . . . . . . . . . 29.3 26.1 26.8
Taxes. . . . . . . . . . . . . . . . 18.9 16.4 14.0
Accrued Pension Costs. . . . . . . . 12.9
Accrued Postretirement Benefits Costs 32.3 6.2 3.6
Other. . . . . . . . . . . . . . . . 44.8 39.3 53.1
Total Current Liabilities . . . . 256.4 222.3 285.9
Accrued Environmental Response Costs . 28.6 18.6 24.3
Deferred Credits . . . . . . . . . . . 73.6 61.8 66.6
Accumulated Deferred Income Taxes. . . 130.3 139.4 134.6
Total . . . . . . . . . . . .$1,681.1 $1,592.6 $1,642.9
See notes to condensed consolidated financial statements.
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ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE NINE MONTHS AND TWELVE MONTHS ENDED JUNE 30, 1995 AND 1994
(MILLIONS)
Nine Months Twelve Months
1995 1994 1995 1994
Cash Flows from Operating Activities:
Net Income. . . . . . . . . . . . $40.5 $72.9 $30.8 $65.5
Adjustments to Reconcile Net Income to Net
Cash Flow from Operating Activities:
Non-Cash Restructuring Costs . 54.4 54.4
Depreciation and Amortization. 47.3 45.1 61.4 60.7
Deferred Income Taxes. . . . . (4.3) 12.9 (3.6) 26.1
Non-Cash Compensation Expense. 5.9 6.0 8.1 8.0
Other. . . . . . . . . . . . . (1.9) (1.3) (2.5) (1.9)
141.9 135.6 148.6 158.4
Changes in Certain Assets and
Liabilities. . . . . . . . . . 112.2 34.0 68.6 (43.0)
Net Cash Flow from Operating
Activities. . . . . . . . . 254.1 169.6 217.2 115.4
Cash Flows from Financing Activities:
Short-Term Borrowings, Net . . . (95.4) (113.4) (18.0) 18.0
Redemptions and Purchase Fund
Requirements of Preferred
Stock and Long-Term Debt . . . (15.0) (125.7) (15.0) (173.3)
Sale of Common Stock, Net of Expenses. .
50.1 1.8 50.7 2.6
Sale of Long-Term Debt . . . . . 194.5 194.5
Dividends. . . . . . . . . . . . (35.8) (35.4) (47.8) (47.2)
Net Cash Flow from Financing
Activities . . . . . . . . . (96.1) (78.2) (30.1) (5.4)
Cash Flows from Investing Activities:
Utility Plant Expenditures. . . . (82.7) (92.9) (111.8) (129.8)
Non-Utility Capital Expenditures. (0.9) (0.1) (0.9) (0.6)
Cost of Property Removal, Net of Salvage. .
0.7 1.7 0.6 1.2
Net Cash Flow from Investing
Activities . . . . . . . . . (82.9) (91.3) (112.1) (129.2)
Net Increase (Decrease) in Cash
and Cash Equivalents . . . . 75.1 0.1 75.0 (19.2)
Cash and Cash Equivalents at
Beginning of Period. . . . . 3.3 3.3 3.4 22.6
Cash and Cash Equivalents at
End of Period. . . . . . . . $78.4 $3.4 $78.4 $3.4
Cash Paid During the Period for:
Interest . . . . . . . . . . . . $44.3 $40.4 $48.6 $46.4
Income Taxes. . . . . . . . . . . $23.7 $17.7 $24.0 $20.7
See notes to condensed consolidated financial statements.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Unless noted specifically or otherwise required by the context,
reference to the "Company" includes Atlanta Gas Light Company (AGL) and its
wholly owned subsidiaries Chattanooga Gas Company (Chattanooga), Georgia Gas
Company, Georgia Gas Service Company, Georgia Energy Company, and Trustees
Investments, Inc. The information contained in these condensed consolidated
financial statements and notes is unaudited, but reflects all normal
recurring accruals, which are, in the opinion of management, 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 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 the Company for the fiscal
years ended September 30, 1994 and 1993. Certain 1994 amounts have been
restated or reclassified for comparability with 1995 amounts.
2. Since sales of natural gas are dependent to a large extent on weather,
the majority of the Company's income is realized during the winter months.
Earnings for three and nine-month periods are not indicative of the earnings
for a twelve-month period.
3. AGL has identified nine sites in Georgia where it currently owns all or
part of a manufactured gas plant (MGP) site. These sites are located in
Athens, Augusta, Brunswick, Griffin, Macon, Rome, Savannah, Valdosta and
Waycross. In addition, AGL has identified three other sites in Georgia
which AGL does not now own, but which may have been associated with the
operation of MGPs by AGL or its predecessors. These sites are located in
Atlanta (2) and Macon. A Preliminary Assessment (PA) has been conducted at
each of these sites and a subsequent Site Investigation (SI) was conducted
at ten of the twelve sites (all but the two Atlanta sites). Results from
these investigations reveal environmental impacts at and near nine sites
(all but the two Atlanta sites and second Macon site).
AGL has entered into consent orders with the Georgia Environmental
Protection Division (EPD) with respect to four sites (Augusta, Griffin,
Savannah and Valdosta) pursuant to which AGL is obligated to investigate and
clean-up, if necessary, these sites. The Company has submitted to EPD the
PA/SIs for each of these four sites. In addition, PAs were submitted to EPD
for the other eight sites. The Company, in response to a request by EPD,
also has submitted the SI for Athens. For the four sites subject to EPD
orders, the orders require the Company, if necessary, to conduct additional
investigations sufficient to develop a Corrective Action Plan (CAP), which
will provide a proposal for cleanup of groundwater, surface water, and soil
at and near each consent order site. When completed, the CAP will be
submitted to EPD for review and approval. Within 180 days of approval of
the CAP by EPD, AGL must complete installation of all remedial structures
called for in the CAP. The Company developed a proposed CAP for the Griffin
site, and submitted the CAP to EPD for review. EPD has requested that the
Company provide additional data on the Griffin site prior to EPD approving
the CAP. The Company expects to provide these data before the end of 1995.
Additional assessment activities are now underway at Augusta and Savannah. In
addition, further studies are underway at the Athens site. AGL expects these
activities in Augusta, Savannah and Athens to be completed in 1995.
On March 22, 1994 AGL submitted to the EPD, under regulations issued by EPD
under the Georgia Hazardous Site Response Act (HSRA), formal notifications
pertaining to MGP site conditions at seven of the eight then owned MGP sites:
Athens, Augusta, Brunswick, Macon, Savannah, Valdosta and Waycross. On
November 4, 1994, the Company submitted a notification for the newly acquired
portion of the Griffin site. EPD has completed its initial review of these
submissions, has eliminated one site (Macon) from further consideration at
this time, and has listed the seven remaining sites (Athens, Augusta,
Brunswick, Griffin, Savannah, Valdosta and Waycross) on Georgia's "Hazardous
Site Inventory" (HSI). EPD also has listed the Rome MGP site with which AGL
has been associated and which is the subject of pending litigation. Under the
HSRA regulations, the sites subject to Consent Orders (Augusta, Griffin,
Savannah and Valdosta) are presumed to require corrective action. EPD will
determine whether corrective action is required at any or all of the
remaining four sites (Athens, Brunswick, Rome and Waycross).
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The Company has estimated the investigation and remediation expenses likely
to be associated with the former MGP sites. First, for some sites, the
Company has determined that its liability, if any, for future investigation
and cleanup expenses is likely to arise from claims by potentially
responsible parties, or equivalent proceedings by the government, for
contribution and/or cost recovery. Under such circumstances, although the
Company may be jointly and severally liable for all investigation and
cleanup expenses, the probable amount of the Company's ultimate liability is
likely to be limited to the Company's equitable share of such expenses under
the circumstances. Accordingly, the Company has adjusted the range of
future investigation and cleanup expenses for these sites by estimating,
where possible, the range of reasonably possible values for the Company's
share of such expenses, given the current methods of equitable apportionment
and the Company's knowledge of relevant facts, including the solvency of
potential contributors and likely disputes over appropriate shares. In all
other cases where such values were not reasonably estimable, the Company has
simply continued to use a range of expenses without adjustment for the
Company's equitable share. Second, the issuance of regulations under HSRA
and the listing of MGP sites on the HSI has altered the basis upon which the
Company has projected future investigation and remediation costs associated
with the former MGP sites in Georgia. Under a thorough analysis of these
and other current potentially applicable requirements, the Company has
estimated that, under the most favorable reasonably possible circumstances,
the future cost of investigating and remediating the former MGP sites could
be as low as $28.6 million. Alternatively, the Company has estimated that,
under the least favorable reasonably possible circumstances, the future cost
of investigating and remediating the former MGP sites could be as high as
$109 million. The Company cannot estimate at this time the amount of any
other future expenses or liabilities, or the impact on these estimates of
future environmental regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the range can be
identified as a better estimate than any other estimate. Therefore, the low
end of this range and a corresponding regulatory asset have been recorded in
the financial statements.
With regard to other legal proceedings related to the former MGP sites, the
Company is or expects to be a party to claims or counterclaims on an ongoing
basis. Among such matters, the Company intends to continue to pursue
aggressively insurance coverage and contribution from potentially
responsible parties. Management currently believes that the outcome of MGP
related litigation in which the Company is involved will not have a material
adverse effect on the financial condition and results of operations of the
Company.
The Georgia Public Service Commission (Georgia Commission) has approved the
recovery by AGL of Environmental Response Costs, as defined below, pursuant
to an Environmental Response Cost Recovery Rider (ERCRR) effective October
1, 1992. 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.
The ERCRR authorized AGL to recover from its ratepayers Environmental
Response Costs that it may incur in succeeding twelve-month periods ending
June 30th, net of working capital benefits resulting from deferred income
taxes, amortized over a 60-month recovery period beginning each October 1.
The carrying costs to AGL of such Environmental Response Costs during the
period of amortization are subject to recovery from any amounts that may be
received from insurance carriers and from former owners and operators of MGP
sites. Any amounts received from such sources are shared equally by AGL and
its ratepayers. AGL records its portion as income to offset unrecovered
carrying costs.
In connection with the ERCRR, the staff of the Georgia Commission has
undertaken a financial and management process audit related to the MGP sites,
clean up activities at the sites and Environmental Response Costs which have
been incurred for purposes of the ERCRR. At the present time, the potential
impact or result of such audit cannot be determined.
See Part I, Item 2 and Part II, Item 5, "Other Information," "Environmental
Matters," of this Form 10-Q for additional information regarding
environmental response activities associated with MGP sites.
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4. The Company competes to supply natural gas to interruptible customers
which are capable of switching to alternative fuels, including fuel oil,
coal, propane, electricity and, in some cases, combustible wood by-
products. The Company also competes to supply gas to interruptible
customers that might otherwise seek to bypass the Company's distribution
system.
On February 17, 1995, the Georgia Commission approved a settlement that
authorizes the Company to negotiate contracts with customers that have the
option of bypassing the Company's facilities and receiving natural gas from
other suppliers. The bypass avoidance contracts (Negotiated Contracts) can
be renewable, provided that the initial term does not exceed five years,
unless a longer term is specifically 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 begin
without additional Georgia Commission action, once a copy of the contract is
filed with the Georgia Commission. The Georgia Commission's original order
approving the settlement provided that a Negotiated Contract may be rejected
by the Georgia Commission within 60 days of filing; absent such action, the
Negotiated Contracts are fully effective. The Georgia Commission
subsequently amended its order to extend to at least 90 days the time for
review and possible disapproval. None of the Negotiated Contracts filed with
the Georgia Commission have been rejected.
The settlement also provides for a bypass loss recovery mechanism to operate
until the earlier of September 30, 1998, or until 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 non-gas cost revenue that was received from the
potential Bypass Customer during the most recent twelve month period and (b)
the non-gas cost revenue that is calculated to be received from the lower
Negotiated Contract rate applied to the same volumetric level. With respect
to the remaining 25% of the difference, AGL is allowed to retain a 44% share
of capacity release revenues in excess of $5 million until AGL is made whole
for discounts from Negotiated Contracts. To the extent that there are
additional capacity release revenues, AGL is allowed to retain 15% of such
amounts.
In addition to Negotiated Contracts, which are designed to serve existing and
potential Bypass Customers, the Company's Interruptible Transportation and
Sales Maintenance (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 the Company's 1993 rate case
will continue to be recovered by the ITSM Rider through the Fiscal Year End
Balancing Adjustment mechanism.
The settlement approved by the Georgia Commission also provides that the
Company may continue to file contracts (Special Contracts) for Georgia
Commission approval if the service cannot be provided through ITSM, existing
rate schedules, or the Negotiated Contract procedures. An example of an
application for a Special Contract would be to provide for a long-term
service contract to compete with alternative fuels where physical bypass was
not the relevant competition.
Since the Georgia Commission's order approving the settlement, the Company
has filed, and is providing service pursuant to, nine Negotiated Contracts.
Additionally, the Georgia Commission has approved Special Contracts with
three industrial customers. See Part II, Item 5, "Other Information,"
"State Regulatory Matters" for additional information concerning the
Company's Negotiated Contracts and Special Contracts.
5. The Company adopted Statement of Financial Accounting Standards No. 106
"Employers' Accounting for Postretirement Benefits Other than Pensions"
(SFAS 106), effective October 1, 1993. This statement requires accrual of
postretirement benefits during the years an employee provides services.
Previously the costs of these benefits, which include health care and life
insurance benefits, were recorded using the pay- as-you-go method.
In its September 29, 1993 rate case decision, the Georgia Commission
approved a phase-in of SFAS 106 expense that defers a portion of fiscal 1994
and fiscal 1995 SFAS 106 expense for future recovery. The Company records a
regulatory asset for the deferred portion of SFAS 106 expense. On June 14,
1993, the Tennessee Public Service Commission issued an order resulting from
a generic docket that approved the recovery of SFAS 106 expense that is
funded through an external trust.
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6. The Company adopted Statement of Financial Accounting Standards No. 109
"Accounting for Income Taxes" (SFAS 109), effective October 1, 1993. Under
this method, deferred tax balances are measured at the tax rates that will
apply during the period the taxes become payable and are adjusted whenever
new rates are enacted. Due to the regulated nature of the Company's utility
business, the principal effect of the adoption of SFAS 109 was to record a
regulatory liability. There was no significant effect on net income or the
consolidated balance sheet as a result of the adoption of SFAS 109.
7. In November 1994, the Company announced a corporate restructuring plan in
response to the increased challenges of competition and the federal and
state regulatory environments in which the Company operates. The
restructuring plan provides for reengineering the Company's business
processes and streamlining the Company's statewide field organizations. As
a result of restructuring, the Company has combined offices and established
centralized call centers, as well as a network of locations where customers
can pay their bills throughout the Company's service area. One of the plan
objectives is to reduce the Company's employee level by more than 600
through attrition, voluntary retirement and severance programs. The Company
will implement remaining portions of the plan during the fourth quarter of
fiscal 1995.
In accordance with current accounting standards, the Company has recorded
restructuring costs of $36.8 million (after income taxes) related to the
early retirement and severance programs, and $5.6 million (after income
taxes) related to office closings and costs to exit the Company's appliance
merchandising and real estate investment operations. As of June 30, 1995,
approximately $69.2 million, or $42.4 million after income taxes, had been
recorded in connection with the Company's corporate restructuring plan.
As a result of the restructuring, the Company expects considerable
reductions in future annual operating expenses. Those reductions should
enable the Company to be more competitive in its markets in the future. The
Company estimates total costs of the restructuring plan could increase
slightly to approximately $70 million or approximately $43 million after
income taxes. Those costs will be offset within three years with lower
operating costs.
8. On June 16, 1995, the Company issued and sold approximately 1.5 million
shares of its common stock, par value $5.00 per share, at a price of $33.625
per share, in an underwritten public offering. Net proceeds of $48.7 million
from the sale of common stock will be used to finance the Company's capital
expenditure program and for other corporate purposes.
9. On April 28, 1995, the Company executed a letter of intent with Sonat,
Inc. (Sonat) regarding the purchase of an interest in Sonat Marketing
Company, which letter evidenced the mutual intentions of the Company and
Sonat to jointly own an entity that will acquire the business of Sonat
Marketing Company, a wholly-owned subsidiary of Sonat. The jointly owned
entity in succeeding to the business of Sonat Marketing Company will
continue to engage in the business of offering natural gas sales,
transportation, risk management and storage services to natural gas users in
key natural gas producing and consuming areas of the United States.
The agreement contemplates the Company will contribute $32 million in cash
for a 35% ownership interest in the marketing entity. It is contemplated
that employees of Sonat Marketing will be subject to confidentiality
agreements, precluding such employees from communicating any market or
pricing information that is not publicly available. In addition, the
Company has certain rights for a period of five (5) years to sell its
interest to Sonat under a formula price and has certain rights to sell its
interest to Sonat for Fair Market Value, as defined, at any time. The
letter of intent is subject to a number of conditions, including the
negotiation and execution of a mutually acceptable definitive agreement
regarding the transaction and obtaining all required consents and approvals,
including governmental approvals. On May 4, 1995, the Company filed a
Notification with the Federal Trade Commission (FTC) and the Justice
Department pursuant to the Hart-Scott-Rodino Antitrust Improvements Act. On
June 1, 1995, the Company received an early termination notice with respect
to the applicable waiting period from the FTC.
<PAGE>
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Three-Month Periods Ended June 30, 1995 and 1994
Explained below are the major factors that had a significant effect on
results of operations for the three-month period ended June 30, 1995,
compared with the same period in 1994.
Operating revenues decreased 7.2% for the three-month period ended June 30,
1995, compared with the same period in 1994 primarily due to a decrease in
the amount recovered from customers under the purchased gas provisions of
the Company's rate schedules for the cost of gas supply, as explained in the
following paragraph. The decrease in operating revenues was partly offset by
an increase of approximately 35,000 in the number of customers served.
Cost of gas decreased 20% for the three-month period ended June 30, 1995,
compared with the same period in 1994 primarily due to a decrease in the
amount recovered from customers under the purchased gas provisions of the
Company's rate schedules. The Company balances the cost of gas with
revenues collected under the purchased gas provisions of the Company's rate
schedules. Under or over recoveries of 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.
Operating margin increased 8.8% for the three-month period ended June 30,
1995, compared with the same period in 1994 primarily due to the increase of
approximately 35,000 in the number of customers served.
Operating expenses decreased $0.3 million for the three-month period ended
June 30, 1995, compared with the same period in 1994. Operating expenses for
the three-month period ended June 30, 1995 included an increase of $4.9
million in expenses related to the Company's Integrated Resource Plan (IRP)
which are recovered through an IRP Cost Recovery Rider approved by the
Georgia Commission. The Company balances IRP expenses with revenues
collected under the rider, thereby eliminating the effect that recovery of
IRP expenses would otherwise have on net income. Operating expenses
excluding IRP expenses decreased 6.7% primarily due to decreased labor costs
as a result of the Company's restructuring plan. Total other operating
expenses increased primarily due to restructuring costs of $1.7 million.
See Note 7 to Notes to Condensed Consolidated Financial Statements in this
Form 10-Q.
Interest charges decreased 5.1% for the three-month period ended June 30,
1995, compared with the same period in 1994 primarily due to (1) decreased
long-term debt outstanding and (2) decreased interest expense associated
with income tax deficiencies related to prior years.
Income taxes increased $1.4 million for the three-month period ended June
30, 1995, compared with the same period in 1994 primarily due to increased
taxable income.
Net income for the three-month period ended June 30, 1995, was $1.4 million,
compared with net loss of $3.8 million for the same period in 1994. Earnings
per share of common stock was $.01 for the three-month period ended June 30,
1995, compared with loss per share of $.19 for the same period in 1994. The
increases in net income and earnings per share were primarily due to (1)
decreased operating expenses as a result of the Company's restructuring plan
and (2) increased operating margin as a result of an increase of
approximately 35,000 in the number of customers served. The increases in net
income and earnings per share were partly offset by restructuring costs of
$1.7 million. See Note 7 to Notes to Condensed Consolidated Financial
Statements in this Form 10-Q.
<PAGE>
Nine-Month Periods Ended June 30, 1995 and 1994
Explained below are the major factors that had a significant effect on
results of operations for the nine-month period ended June 30, 1995,
compared with the same period in 1994.
Operating revenues decreased 9.4% for the nine-month period ended June 30,
1995, compared with the same period in 1994 primarily due to (1) a decrease
in the amount recovered from customers under the purchased gas provisions of
the Company's rate schedules for the cost of gas supply, as explained in the
following paragraph and (2) decreased volumes of gas sold to firm service
customers as a result of weather that was 18% warmer than the same period in
1994. The decrease in operating revenues was partly offset by an increase
of approximately 37,000 in the number of customers served.
Cost of gas decreased 18.3% for the nine-month period ended June 30, 1995,
compared with the same period in 1994 primarily due to (1) a decrease in the
amount recovered from customers under the purchased gas provisions of the
Company's rate schedules and (2) decreased volumes of gas sold to firm
service customers as a result of weather that was 18% warmer than the same
period in 1994. The Company balances the cost of gas with revenues
collected under the purchased gas provisions of the Company's rate
schedules. Under or over recoveries of 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.
Operating margin increased 5.8% for the nine-month period ended June 30,
1995, compared with the same period in 1994 primarily due to an increase of
approximately 37,000 in the number of customers served.
Operating expenses increased 1.6% for the nine-month period ended June 30,
1995, compared with the same period in 1994 primarily due to an increase of
$12.6 million in expenses related to the Company's IRP which are recovered
through an IRP Cost Recovery Rider approved by the Georgia Commission. The
Company balances IRP expenses with revenues collected under the rider,
thereby eliminating the effect that recovery of IRP expenses would otherwise
have on net income. Operating expenses excluding IRP expenses decreased 3.6%
primarily due to decreased labor costs as a result of the Company's
restructuring plan. Total other operating expenses increased primarily due to
restructuring costs of $69.2 million. See Note 7 to Notes to Condensed
Consolidated Financial Statements in this Form 10-Q.
Other income decreased $1 million for the nine-month period ended June 30,
1995, compared with the same period in 1994 primarily due to decreased
income from propane operations as a result of warmer weather.
Interest charges increased 1.7% for the nine-month period ended June 30,
1995, compared with the same period in 1994 primarily due to increased
interest rates on short-term debt.
Income taxes decreased $20.5 million for the nine-month period ended June
30, 1995, compared with the same period in 1994 primarily due to decreased
taxable income.
Net income for the nine-month period ended June 30, 1995, was $40.5 million,
compared with net income of $72.9 million for the same period in 1994.
Earnings per share of common stock were $1.44 for the nine-month period
ended June 30, 1995, compared with earnings per share of $2.78 for the same
period in 1994. The decreases in net income and earnings per share were
primarily due to restructuring costs of $69.2 million. See Note 7 to Notes
to Condensed Consolidated Financial Statements in this Form 10-Q. The
decreases in net income and earnings per share were partly offset by (1)
decreased labor costs as a result of the Company's restructuring plan and
(2) increased operating margin as a result of an increase of approximately
37,000 in the number of customers served.
<PAGE>
Twelve-Month Periods Ended June 30, 1995 and 1994
Explained below are the major factors that had a significant effect on
results of operations for the twelve-month period ended June 30, 1995,
compared with the same period in 1994.
Operating revenues decreased 8.5% for the twelve-month period ended June 30,
1995, compared with the same period in 1994 primarily due to (1) a decrease
in the amount recovered from customers under the purchased gas provisions of
the Company's rate schedules for the cost of gas supply, as explained in the
following paragraph and (2) decreased volumes of gas sold to firm service
customers as a result of weather that was 18% warmer than the same period in
1994. The decrease in operating revenues was partly offset by an increase
of approximately 37,000 in the number of customers served.
Cost of gas decreased 17.5% for the twelve-month period ended June 30, 1995,
compared with the same period in 1994 primarily due to (1) a decrease in the
amount recovered from customers under the purchased gas provisions of the
Company's rate schedules and (2) decreased volumes of gas sold to firm
service customers as a result of weather that was 18% warmer than the same
period in 1994. The Company balances the cost of gas with revenues
collected under the purchased gas provisions of the Company's rate
schedules. Under or over recoveries of 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.
Operating margin increased 6.1% for the twelve-month period ended June 30,
1995, compared with the same period in 1994 primarily due to the increase of
approximately 37,000 in the number of customers served.
Operating expenses increased 3.2% for the twelve-month period ended June 30,
1995, compared with the same period in 1994 primarily due to an increase of
$14.2 million in expenses related to the Company's IRP which are recovered
through an IRP Cost Recovery Rider approved by the Georgia Commission. The
Company balances IRP expenses with revenues collected under the rider,
thereby eliminating the effect that recovery of IRP expenses would otherwise
have on net income. Operating expenses excluding IRP expenses decreased 1.3%
for the twelve-month period ended June 30, 1995, compared with the same
period in 1994 primarily due to decreased labor costs as a result of the
Company's restructuring plan. Taxes - other than income increased $1.2
million primarily due to increased ad valorem taxes. Total other operating
expenses increased primarily due to restructuring costs of $69.2 million.
See Note 7 to Notes to Condensed Consolidated Financial Statements in this
Form 10-Q.
Other income decreased $2.9 million for the twelve-month period ended June
30, 1995, compared with the same period in 1994 primarily due to decreased
income from propane operations as a result of warmer weather.
Interest charges increased 1.1% for the twelve-month period ended June 30,
1995, compared with the same period in 1994 primarily due to increased
interest rates on short-term debt.
Income taxes decreased $22.2 million for the twelve-month period ended June
30, 1995, compared with the same period in 1994 primarily due to decreased
taxable income.
Net income for the twelve-month period ended June 30, 1995, was $30.8
million, compared with net income of $65.5 million for the same period in
1994. Earnings per share of common stock were $1.02 for the twelve-month
period ended June 30, 1995, compared with earnings per share of $2.45 for
the same period in 1994. The decreases in net income and earnings per share
were primarily due to restructuring costs of $69.2 million. See Note 7 to
Notes to Condensed Consolidated Financial Statements in this Form 10-Q. The
decreases in net income and earnings per share were partly offset by (1)
increased operating margin as a result of an increase of approximately
37,000 in the number of customers served and (2) decreased labor costs as a
result of the Company's restructuring plan.
<PAGE>
Financial Condition
The Company's business is highly seasonal in nature and typically shows a
substantial increase in accounts receivable from customers from September 30
to June 30 as a result of colder weather. The Company also uses gas stored
underground and liquefied natural gas to serve its customers during periods
of cold weather. As a result, accounts receivable increased $22.7 million
and inventory of gas stored underground and liquefied natural gas decreased
$85.8 million during the nine months ended June 30, 1995. Inventory of gas
stored underground and liquefied natural gas decreased $34.5 million from
June 30, 1994 to June 30, 1995 primarily due to (1) decreased volumes of gas
injected into storage and (2) a decrease in the cost of gas injected into
storage. The Company anticipates that it will fill its underground storage
facilities during the months of July through October, 1995 in order to meet
the demand for natural gas during the 1995-1996 heating season.
The Company currently estimates that its portion of transition costs
resulting from FERC Order 636 restructuring proceedings from all of its
pipeline suppliers, that have been filed to be recovered to date, could be
as high as approximately $85.9 million. The Company's estimate is based on
the most recent estimates of transition costs filed by its pipeline
suppliers with FERC. Such filings by the Company's pipeline suppliers are
pending final FERC approval.
Prior to the implementation of Order 636, the cost of bundled pipeline sales
service was reviewed and approved by FERC. Because of diminished review by
FERC following the implementation of Order 636, local distribution companies
such as the Company may face greater accountability and risks from their
purchasing practices for gas supply, transportation and storage services.
The purchasing practices of AGL are subject to review by the Georgia
Commission under legislation enacted by the Georgia General Assembly.
The legislation establishes procedures for review and approval 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 1995, 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 Order 636 transition costs that are
currently being charged by the Company's pipeline suppliers. On August 1,
1995, the Company filed with the Georgia Commission its Gas Supply Plan for
fiscal year 1996. Hearings on the Company's 1996 Gas Supply Plan have been
scheduled for September 6, 7, and 8, 1995. A plan must be approved by the
Georgia Commission on or before September 15, 1995. For further discussion
of the effects of FERC Order 636 on the Company, see Part II, Item 5, "Other
Information," "Federal Regulatory Matters" of this Form 10-Q.
As noted above, the Company recovers the cost of gas under the purchased gas
provisions of the Company's rates schedules. The Company was in an over
recovery position of $49.3 million at June 30, 1994, and $62.4 million at
June 30, 1995 with respect to the purchased gas provisions. Under the
provisions of the Company's rate schedules, any under or over recoveries of
gas costs are included in current assets or liabilities and have no effect
on net income. On July 21, 1995, the Company filed a proposal with the
Georgia Commission to refund approximately $38.5 million in over recovered
gas costs to its customers. See Part II, Item 5, "Other Information,"
"State Regulatory Matters" of this Form 10-Q for additional information
concerning refunds of over recovered gas costs.
Cash and cash equivalents increased $75.1 million and $75 million for the
nine-month and twelve-month periods ended June 30, 1995, respectively,
primarily due to net cash flow from operating activities and the issuance
and sale of approximately 1.5 million shares of common stock as discussed
below.
The expenditures for plant and other property totaled $83.6 million and
$112.7 million for the nine-month and twelve-month periods ended June 30,
1995, respectively.
The Company had accrued liabilities of $28.6 million at June 30, 1995
compared with $18.6 million at June 30, 1994 and $24.3 million at September
30, 1994 for future expenditures which are expected to be made over a period
of several years in connection with or related to MGP sites. The Georgia
Commission has approved the recovery by the Company of Environmental Response
Costs, as defined in Note 3 to Notes to Condensed Consolidated Financial
Statements, commencing October 1, 1992, pursuant to the ERCRR. The staff of
the Georgia Commission has undertaken a financial and management process
audit related to the MGP sites, clean up activities at the sites of the ERCRR
and Environmental Response Costs incurred for purposes of the ERCRR. At the
present time, the potential impact or result of such audit cannot be
determined. See Note 3 to Notes to Condensed Consolidated Financial
Statements and Part II, Item 5, "Other Information," "Environmental Matters"
of this Form 10-Q.
<PAGE>
On June 16, 1995, the Company issued and sold approximately 1.5 million
shares of its common stock, par value $5.00 per share, at a price of $33.625
per share, in an underwritten public offering. Net proceeds of $48.7
million from the sale of common stock will be used to finance the Company's
capital expenditure program and for other corporate purposes.
Long-term debt due within one year decreased $15 million for the nine-month
and twelve-month periods ended June 30, 1995 due to the maturity of $15
million of Medium-Term Notes in January, 1995.
Short-term debt decreased $95.4 million and $18.0 million for the nine-month
and twelve-month periods ended June 30, 1995, respectively, primarily due to
net cash flow from operating activities.
Accrued postretirement benefits costs increased $26.1 million from June 30,
1994 to June 30, 1995 and $28.7 million from September 30, 1994 to June 30,
1995. The increase was primarily due to restructuring costs resulting from
the Company's Special Voluntary Retirement Plan (SVRP). See Note 7 to Notes
to Condensed Consolidated Financial Statements in this Form 10-Q.
Accrued pension costs increased $12.9 million from June 30, 1994 and
September 30, 1994 to June 30, 1995. The increase was primarily due to
restructuring costs resulting from the Company's SVRP. See Note 7 to Notes
to Condensed Consolidated Financial Statements in this Form 10-Q.
As a result of the restructuring, the Company expects considerable
reductions in future annual operating expenses. Those reductions should
enable the Company to be more competitive in its markets in the future. The
Company estimates total costs of the restructuring plan could increase
slightly to approximately $70 million or approximately $43 million after
income taxes. Those costs will be offset within three years with lower
operating costs.
On February 17, 1995, the Georgia Commission approved a settlement that
authorizes the Company to negotiate contracts with customers that have the
option of bypassing the Company's facilities and receiving natural gas from
other suppliers. The bypass avoidance contracts (Negotiated Contracts) can
be renewable, provided that the initial term does not exceed five years,
unless a longer term is specifically 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 begin
without additional Georgia Commission action, once a copy of the contract is
filed with the Georgia Commission. The Georgia Commission's original order
approving the settlement provided that a Negotiated Contract may be rejected
by the Georgia Commission within 60 days of filing; absent such action, the
Negotiated Contracts are fully effective. The Georgia Commission
subsequently amended its order to extend to at least 90 days the time for
review and possible disapproval. None of the Negotiated Contracts filed
with the Georgia Commission have been rejected.
The Georgia Commission also approved a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or until the effective date
of new rates for AGL resulting from a general rate case. See Part II, Item
5, "Other Information," "State Regulatory Matters" for additional
information concerning the bypass loss recovery mechanism.
PART II -- OTHER INFORMATION
Part II -- Other Information is intended to supplement information
contained in the Company's Annual Report on Form 10-K for the fiscal year
ended September 30, 1994 and should be read in conjunction therewith.
Item 1. Legal Proceedings
See Item 5.
<PAGE>
Item 5. Other Information
Federal Regulatory Matters
Order No. 636
The Company currently estimates that its portion of transition costs (which
include unrecovered gas costs, gas supply realignment (GSR) costs and
various stranded costs resulting from unbundling of interstate pipeline
sales service) from all of its pipeline suppliers filed with the Federal
Energy Regulatory Commission (FERC) to date to be recovered could be as high
as approximately $85.9 million. The Company's estimate is based on the most
recent estimates of transition costs filed by its pipeline suppliers with
the FERC and assumes Southern Natural Gas Company's (Southern) restructuring
settlement agreement, as described below, is approved. Such filings by the
Company's pipeline suppliers are pending final FERC approval. Transition
costs billed to the Company are being recovered from customers under the
purchased gas provisions of the Company's rate schedules. Details
concerning the status of the Order No. 636 restructuring proceedings
involving the pipelines that serve the Company directly are set forth below.
SOUTHERN Restructuring Settlement. The Company has entered
into a settlement agreement with Southern and other customers to resolve
virtually all pending Southern proceedings before the FERC and the courts.
The settlement would, if approved by the FERC, resolve Southern's pending
general rate proceedings, which relates to Southern's rates charged from
January 1, 1991 through the present. The settlement also provides for rate
reductions and refund offsets against GSR costs and would resolve Southern's
Order No. 636 transition cost proceedings and provide for revisions to
Southern's tariff. Southern submitted the settlement agreement to the FERC
on March 15, 1995. In addition, in conjunction with the settlement,
Southern has filed for authority to construct certain facilities to improve
service to AGL and has filed for authority to abandon by sale to AGL a
portion of the Brunswick lateral. The FERC has not yet acted on the
proposed settlement agreement or the related filings, but has allowed
Southern to implement the reduced rates on an interim basis for supporting
parties. Although there is substantial support for the settlement, some
customers of Southern have filed comments in opposition to the settlement.
Assuming the settlement agreement is approved, the Company's portion of
Southern's transition costs is estimated to be approximately $73.8 million.
Southern and its customers have suspended litigation of the matters covered
by the settlement, pending action by the FERC on the settlement.
GSR Cost Recovery Proceeding. Southern has continued to
make quarterly GSR cost recovery filings with the FERC, and has filed on a
monthly basis since the implementation of Order No. 636 to revise its GSR
surcharges based on changes in billing determinants. On May 31, 1995,
Southern made additional filings to recover $1.7 million in GSR costs and
approximately $10.1 million in other transition costs. On June 30, 1995,
the FERC accepted Southern's filings, subject to the outcome of Southern's
restructuring settlement. Southern will continue to make quarterly and
monthly transition cost filings. Pending approval of the restructuring
settlement, however, GSR charges to the Company will be in accordance with
the interim settlement rates. The Company has actively challenged the
eligibility and prudence of the GSR costs Southern has sought to recover.
TENNESSEE GSR Cost Recovery Proceeding. Tennessee Gas Pipeline
Company (Tennessee) has continued to make quarterly GSR cost recovery
filings with the FERC. On June 30, 1995, Tennessee filed with the FERC to
recover an additional $22.5 million in GSR costs. The Company protested
this filing, but the FERC has not yet acted upon Tennessee's filing. The
Company's estimated liability for GSR costs as a result of Tennessee's
filings is approximately $7.9 million, subject to possible reduction based
upon the hearing FERC established to investigate Tennessee's costs. The
Company is actively participating in Tennessee's GSR cost recovery
proceeding.
FERC Rate Proceedings
SOUTHERN Southern's current rate proceeding involves rates from May 1,
1993 forward, and also involves undue discrimination claims raised by the
Company against Southern. These claims arise out of a settlement between
Southern and Arcadian Corporation (Arcadian) related to the bypass of the
Company's system, and certain discounted transportation arrangements entered
into between Southern and Arcadian as part of the settlement. The hearing
in this rate proceeding concluded on February 7, 1995; the proceeding is
suspended pending action by the FERC on the settlement agreement noted
above.
<PAGE>
TENNESSEE On June 30, 1995, Tennessee moved to implement, effective July 1,
1995, the rate increase it filed for on December 30, 1994. The filing
reflects certain reductions by the FERC from the $117.9 million rate
increase originally sought by Tennessee, as well as a voluntary 5%
reduction. The FERC has not yet acted on Tennessee's motion.
On July 24, 1995, a FERC administrative law judge (ALJ) issued an initial
decision addressing the rates to be charged by Tennessee on a prospective
basis. Among other matters, the ALJ approved Tennessee's proposal to
decrease the load factor used to calculate its interruptible transportation
rates from 125% to 100%. The Company supported a further reduction, to 50%.
The ALJ also rejected challenges by the Company and others to Tennessee's
"straight-fixed-variable-to-the-wellhead" design for firm transportation
rates. The ALJ's decision is subject to the filing of exceptions by the
parties, and thus is not yet final.
TRANSCO On July 19, 1995, a FERC ALJ rejected Transcontinental Gas
Pipeline Corporation's (Transco) proposed "firm-to-the-wellhead" rate
structure for firm transportation rates which would, if approved, shift
approximately $60 million in production area fixed costs into firm
transportation rates. In addition, the ALJ determined that Transco's
existing production area rate design is unjust and unreasonable, and adopted
a production area rate design proposal offered by another intervenor in the
proceeding. The ALJ's decision is subject to the filing of exceptions by
the parties, and thus is not yet final. AGL opposed the "firm-to-the-
wellhead" rate design, but did not oppose Transco's existing production area
rates.
The Company cannot predict the outcome of these federal proceedings nor can
it determine the ultimate effect, if any, such proceedings may have on the
Company.
State Regulatory Matters
Bypass and Other Competitive Issues
On October 19, 1994, the Georgia Public Service Commission (Georgia
Commission) issued a scheduling order for an Investigation of AGL Bypass and
Other Issues, designated as Docket No. 5392-U. The proceeding was designed
to provide information to the Georgia Commission regarding alternatives to
respond to bypass and to assess the economics of bypass. Hearings in this
docket were conducted in November and December 1994.
On February 17, 1995, the Georgia Commission approved a settlement that
authorizes the Company to negotiate contracts with customers that have the
option of bypassing the Company's facilities and receiving natural gas from
other suppliers (Bypass Customers). The settlement was agreed to by all
parties to this docket, except for the Consumers' Utility Counsel (CUC),
which has requested that the Georgia Commission reverse its February 1995
approval of the settlement. The CUC's petition to the Georgia Commission
for rehearing and reconsideration was denied by the Georgia Commission on
February 21, 1995, and no petition for judicial review was filed within the
time allowed under Georgia law.
The bypass avoidance contracts (Negotiated Contracts) can be renewable,
provided that the initial term does not exceed five years, unless a longer
term is specifically 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 begin without
additional Georgia Commission action, once a copy of the contract is filed
with the Georgia Commission. A Negotiated Contract may be rejected by the
Georgia Commission within 60 days of filing; absent such action, the
Negotiated Contracts are fully effective. The Georgia Commission
subsequently amended its order to extend to at least 90 days the time for
review and possible disapproval. None of the Negotiated Contracts filed
with the Georgia Commission have been rejected.
The Georgia Commission also approved a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or until the effective date
of new rates for AGL resulting from a general rate case. See Note 4 to
Notes to Condensed Consolidated Financial Statements in this Form 10-Q for
additional information concerning the bypass loss recovery mechanism.
<PAGE>
In addition to Negotiated Contracts, which are designed to serve existing
and potential Bypass Customers, the Company's Interruptible Transportation
and Sales Maintenance (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 the
Company's 1993 rate case will continue to be recovered by the ITSM Rider
through the Fiscal Year End Balancing Adjustment mechanism.
The settlement approved by the Georgia Commission also provides that AGL may
continue to file contracts (Special Contracts) for Georgia Commission
approval if the service cannot be provided through ITSM, existing rate
schedules, or the Negotiated Contract procedures. An example of an
application for a Special Contract would be to provide for a long-term
service contract to compete with alternative fuels where physical bypass was
not the relevant competition.
Since the Georgia Commission's order approving the settlement, AGL has
filed, and is providing service pursuant to, nine Negotiated Contracts.
Additionally, the Georgia Commission has approved Special Contracts with
three additional customers. One of the Special Contracts involves a five
year agreement pursuant to which the Company is providing natural gas as a
fuel for electric power generation for facilities owned by Savannah Electric
Power Company and Georgia Power Company.
On January 18, 1995, AGL filed with the Georgia Commission a request to
approve a Special Contract with Georgia-Pacific Corporation designed to
provide long-term service in competition with fuel oil. Although the
Special Contract rate is lower than the rate schedule that would otherwise
be applicable, because there are significant additional volumes, there is no
revenue shortfall resulting from these discounts. The Georgia Commission
approved this Special Contract on March 2, 1995.
On March 16, 1995, the Company proposed for Georgia Commission consideration
two Special Contracts with the Metropolitan Atlanta Rapid Transit Authority
(MARTA) to provide for the construction of a refueling facility as well as
for the acquisition of, and service to, natural gas fueled transit buses.
Under the contracts, MARTA agreed to purchase at least 200 natural gas buses
over the next five years. The Company agreed to contribute up to $2.55
million to the cost of refueling facilities, and to contribute approximately
28% ($2.9 million) of the purchase cost difference between diesel and
natural gas buses. On April 18, 1995, the Georgia Commission voted
unanimously to grant the regulatory authority required to proceed with the
MARTA Special Contracts. Specifically, the Georgia Commission voted to
approve the contract terms as the terms of service applicable to MARTA, to
approve the contract rates, and approve an accounting order to defer for
subsequent recovery the $2.9 million bus purchase incentives. The Georgia
Commission's accounting order was issued on June 19, 1995.
On May 1, 1995, Chattanooga Gas Company (Chattanooga) filed a rate
proceeding with the Tennessee Public Service Commission seeking an increase
in revenues of $5.2 million annually. Among other things, the filing seeks
to implement a new financing and marketing program for natural gas heating
and cooling systems and natural gas water heaters. Revenues from the
proposed rate increase will be used by Chattanooga to improve and expand its
distribution system and to recover increased operation, maintenance, and tax
expenses. Hearings have been scheduled for September 1995 and a decision is
expected on October 17, 1995, with new rates to be effective November 1,
1995.
On July 21, 1995, the Company filed with the Georgia Commission a request to
approve a refund of $38.5 million of the revenues collected through the
Purchased Gas Adjustment (PGA) Rider since October 1994. The PGA Rider is
intended to recover the actual expenses associated with purchasing and
delivering natural gas supplies for firm sales customers. Because the PGA
Rider recovers actual expenses and contains true-up provisions, the
Company's earnings are not affected by this proposed refund. The Company
has proposed that the refunds be reflected on customers' September 1995
bills. If approved as filed, the average refund, based on actual
consumption during the four months in which the PGA Rider collected more
revenue than required to cover the gas cost expenses, will be approximately
$22 for residential customers, approximately $100 for small commercial
customers, approximately $765 for small industrial customers, approximately
$2,587 for large commercial customers, and approximately $2,257 for large
industrial customers.
<PAGE>
On August 1, 1995, the Company filed with the Georgia Commission its Gas
Supply Plan for fiscal year 1996. Pursuant to Georgia law, each
investor-owned local natural gas distribution company is required to file
on or before August 1 of each year, a proposed gas supply plan for the
following year, as well as a proposed gas cost recovery factor to be used in
the same time period. Natural gas companies are allowed to recover from
their customers the costs associated with implementing gas supply plans
which are approved by the Georgia Commission. Hearings on the Company's
1996 Gas Supply Plan have been scheduled for September 6, 7 and 8, 1995. A
plan must be approved by the Georgia Commission on or before September 15,
1995.
The Company cannot predict the outcome of pending state proceedings nor can
it determine the ultimate effect, if any, such proceedings may have on the
Company.
Environmental Matters
In June 1990, the Company was contacted by attorneys for Florida Public
Utilities Company (FPUC) in connection with a former manufactured gas plant
(MGP) site in Sanford, Florida. Thereafter, FPUC received a "Warning
Notice" from the Florida Department of Environmental Regulation (FDER)
demanding that FPUC enter into a consent order to investigate the Sanford
site. Preliminary investigation results indicate some environmental impacts
at this site. In addition, limited investigations of the surrounding area
indicate potential environmental impacts off-site. On January 31, 1992,
FPUC filed suit against the Company, two other corporations, and the City of
Sanford, under the federal Comprehensive Environmental Response,
Compensation, and Liability Act, and an equivalent state statute, alleging
the Company is a former "owner," to obtain contribution from the Company and
others for all costs incurred and for a declaratory judgment that all
defendants are jointly and severally liable for future response costs. On
February 3, 1994, the parties submitted a Contamination Assessment Report
(CAR) to the Florida Department of Environmental Protection (FDEP),
previously known as FDER. The CAR confirmed the existence of environmental
impacts at the site and off-site. On April 10, 1994, FDEP completed its
review of the CAR and submitted a preliminary scoring of the site to Region
IV of the United States Environmental Protection Agency (EPA). FDEP
concluded that further study is necessary in some areas because the site did
not exceed the listing threshold under one set of assumptions but did exceed
that threshold under different assumptions. On February 17, 1995, FPUC
dismissed its lawsuit without prejudice. The EPA has requested that FPUC
conduct an Expanded Site Investigation (ESI) of the Sanford site and the
nearby area. FPUC declined and it is expected that EPA will conduct the
ESI itself.
In addition to the Sanford site noted above, there are two other sites in
Florida presently being investigated by environmental authorities in
connection with which the Company may be contacted as a potentially
responsible party. No claim has been made by any party regarding these
sites.
AGL has identified nine sites in Georgia where it currently owns all or part
of an MGP site. These sites are located in Athens, Augusta, Brunswick,
Griffin, Macon, Rome, Savannah, Valdosta and Waycross. In addition, AGL has
identified three other sites in Georgia which AGL does not now own, but
which may have been associated with the operation of MGPs by AGL or its
predecessors. These sites are located in Atlanta (2) and Macon. A
Preliminary Assessment (PA) has been conducted at each of these sites and a
subsequent Site Investigation (SI) was conducted at ten of the twelve sites
(all but the two Atlanta sites). Results from these investigations reveal
environmental impacts at and near nine sites (all but the two Atlanta sites
and the second Macon site).
AGL has entered into consent orders with the Georgia Environmental
Protection Division (EPD) with respect to four sites (Augusta, Griffin,
Savannah and Valdosta) pursuant to which AGL is obligated to investigate and
clean-up, if necessary, these sites. The Company has submitted to EPD the
PA/SIs for each of these four sites. In addition, PAs were submitted to EPD
for the other eight sites. The Company, in response to a request by EPD,
also has submitted the SI for the Athens site. For the four sites subject
to EPD orders, the orders require the Company, if necessary, to conduct
additional investigations sufficient to develop a Corrective Action Plan
(CAP), which will provide a proposal for cleanup of groundwater, surface
water, and soil at and near each consent order site. When completed, the CAP
will be submitted to EPD for review and approval. Within 180 days of
approval of the CAP by EPD, AGL must complete installation of all remedial
structures called for in the CAP. The Company developed a proposed CAP for
the Griffin site, and submitted the CAP to EPD for review. EPD
<PAGE>
has requested that the Company provide additional data on the Griffin site
prior to EPD approving the CAP. The Company expects to provide these data
prior to the end of 1995. Additional assessment activities are now underway
at Augusta and Savannah. In addition, further studies are underway at the
Athens site. AGL expects these activities in Augusta, Savannah and Athens to
be completed during 1995.
On March 22, 1994, AGL submitted to the EPD, under regulations issued by EPD
under the Georgia Hazardous Site Response Act (HSRA), formal notifications
pertaining to MGP site conditions at seven of the eight then owned MGP
sites: Athens, Augusta, Brunswick, Macon, Savannah, Valdosta and Waycross.
On November 4, 1994, the Company submitted a notification for the recently
acquired portion of the Griffin site. EPD has completed its initial review
of these submissions, has eliminated one site (Macon) from further
consideration at this time, and has listed the seven remaining sites
(Athens, Augusta, Brunswick, Griffin, Savannah, Valdosta and Waycross) on
Georgia's "Hazardous Site Inventory" (HSI). EPD also has listed the Rome
MGP site with which AGL has been associated and which is the subject of
pending litigation. Under the HSRA regulations, the sites subject to
Consent Orders (Augusta, Griffin, Savannah and Valdosta) are presumed to
require corrective action. EPD will determine whether corrective action is
required at any or all of the remaining four sites (Athens, Brunswick, Rome
and Waycross).
The Company has estimated the investigation and remediation expenses likely
to be associated with the former MGP sites. First, for some sites, the
Company has determined that its liability, if any, for future investigation
and cleanup expenses is likely to arise from claims by potentially
responsible parties, or equivalent proceedings by the government, for
contribution and/or cost recovery. Under such circumstances, although the
Company may be jointly and severally liable for all investigation and
cleanup expenses, the probable amount of the Company's ultimate liability is
likely to be limited to the Company's equitable share of such expenses under
the circumstances. Accordingly, the Company has adjusted the range of
future investigation and cleanup expenses for these sites by estimating,
where possible, the range of reasonably possible values for the Company's
share of such expenses, given the current methods of equitable apportionment
and the Company's knowledge of relevant facts, including the solvency of
potential contributors and likely disputes over appropriate shares. In all
other cases where such values were not reasonably estimable, the Company has
simply continued to use a range of expenses without adjustment for the
Company's equitable share. Second, the issuance of regulations under HSRA
and the listing of MGP sites on the HSI has altered the basis upon which the
Company has projected future investigation and remediation costs associated
with the former MGP sites in Georgia. Under a thorough analysis of these
and other current potentially applicable requirements, the Company has
estimated that, under the most favorable reasonably possible circumstances,
the future cost of investigating and remediating the former MGP sites could
be as low as $28.6 million. Alternatively, the Company has estimated that,
under the least favorable reasonably possible circumstances, the future cost
of investigating and remediating the former MGP sites could be as high as
$109 million. The Company cannot estimate at this time the amount of any
other future expenses or liabilities, or the impact on these estimates of
future environmental regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the range can be
identified as a better estimate than any other estimate. Therefore, the low
end of this range and a corresponding regulatory asset have been recorded in
the financial statements. See Note 3 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
With regard to other legal proceedings related to the former MGP sites, the
Company is or expects to be a party to claims or counterclaims on an ongoing
basis. Among such matters, the Company intends to continue to pursue
aggressively insurance coverage and contribution from potentially
responsible parties. Management currently believes that the outcome of MGP
related litigation in which the Company is involved will not have a material
adverse effect on the financial condition and results of operations of the
Company.
The Environmental Response Costs incurred by the Company are recoverable
under the terms of the Environmental Response Cost Recovery Rider (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,
clean up activities at the sites and Environmental Response Costs which have
been incurred for purposes of the ERCRR. At the present time, the potential
impact or result of such audit cannot be determined.
<PAGE>
Recent Developments
On April 28, 1995, the Company executed a letter of intent with Sonat, Inc.
(Sonat) regarding the purchase of an interest in Sonat Marketing Company,
which letter evidenced the mutual intentions of the Company and Sonat to
jointly own an entity that will acquire the business of Sonat Marketing
Company, a wholly-owned subsidiary of Sonat. The jointly owned entity in
succeeding to the business of Sonat Marketing Company will continue to
engage in the business of offering natural gas sales, transportation, risk
management and storage services to natural gas users in key natural gas
producing and consuming areas of the United States.
The agreement contemplates the Company will contribute $32 million in cash
for a 35% ownership interest in the marketing entity. It is contemplated
that employees of Sonat Marketing will be subject to confidentiality
agreements, precluding such employees from communicating any market or
pricing information that is not publicly available. In addition, the
Company has certain rights for a period of five (5) years to sell its
interest to Sonat under a formula price and has certain rights to sell its
interest to Sonat for Fair Market Value, as defined, at any time. The
letter of intent is subject to a number of conditions, including the
negotiation and execution of a mutually acceptable definitive agreement
regarding the transaction and obtaining all required consents and approvals,
including governmental approvals. On May 4, 1995, the Company filed a
Notification with the Federal Trade Commission (FTC) and the Justice
Department pursuant to the Hart-Scott-Rodino Antitrust Improvements Act. On
June 1, 1995, the Company received an early termination notice with respect
to the applicable waiting period from the FTC.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10(a) - Firm Transportation agreement, dated March 1, 1995,
between Chattanooga Gas Company and Southern Natural Gas
Company amending Service Agreements #904470 under Rate
Schedule FT (Exhibit 10(oo), Form 10-K for the fiscal
year ended September 30, 1994), #904471 under Rate
Schedule FT-NN (Exhibit 10(pp), Form 10-K for the fiscal
year ended September 30, 1994), and #S20130 under Rate
Schedule CSS (Exhibit 10(qq), Form 10-K for the fiscal
year ended September 30, 1994).
27 - Financial Data Schedule
(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.
Atlanta Gas Light Company
(Registrant)
Date August 14, 1995 /s/ Robert L. Goocher
Robert L. Goocher
Executive Vice President
Business Support
(Principal Financial Officer)
Date August 14, 1995 /s/ J. Michael Riley
J. Michael Riley
Vice President - Finance and Accounting
(Principal Accounting Officer)
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> JUN-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1315
<OTHER-PROPERTY-AND-INVEST> 19
<TOTAL-CURRENT-ASSETS> 279
<TOTAL-DEFERRED-CHARGES> 67
<OTHER-ASSETS> 2
<TOTAL-ASSETS> 1681
<COMMON> 137
<CAPITAL-SURPLUS-PAID-IN> 297
<RETAINED-EARNINGS> 146
<TOTAL-COMMON-STOCKHOLDERS-EQ> 581
56
3
<LONG-TERM-DEBT-NET> 555
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 489
<TOT-CAPITALIZATION-AND-LIAB> 1681
<GROSS-OPERATING-REVENUE> 955
<INCOME-TAX-EXPENSE> 20
<OTHER-OPERATING-EXPENSES> 316
<TOTAL-OPERATING-EXPENSES> 879
<OPERATING-INCOME-LOSS> 75
<OTHER-INCOME-NET> 2
<INCOME-BEFORE-INTEREST-EXPEN> 77
<TOTAL-INTEREST-EXPENSE> 37
<NET-INCOME> 41
3
<EARNINGS-AVAILABLE-FOR-COMM> 37
<COMMON-STOCK-DIVIDENDS> 40
<TOTAL-INTEREST-ON-BONDS> 32
<CASH-FLOW-OPERATIONS> 253
<EPS-PRIMARY> 1.44
<EPS-DILUTED> 1.44
</TABLE>
<PAGE>
Exhibit 10a
AMENDATORY AGREEMENT
This Amendment is entered into this 1st day of March, 1995, between
SOUTHERN NATURAL GAS COMPANY ("Company") and CHATTANOOGA GAS COMPANY
("Shipper").
W I T N E S S E T H :
WHEREAS, Company and Shipper are parties to a firm transportation agreement
dated November 1, 1994, (#904470) for 7,949 Mcf per day ("FT Agreement"), a
firm transportation-no notice agreement dated November 1, 1994, (#904471)
for 14,051 Mcf per day ("FT-NN Agreement"), and a contract storage service
agreement dated November 1, 1994, (#S20130) for 695,871 Mcf ("CSS
Agreement"); and
WHEREAS, Shipper has agreed to support the Stipulation and Agreement filed
by Company in Docket Nos. RP89-224, et al, on March 15, 1995
("Stipulation"); and
WHEREAS, under the terms of the Stipulation, Shipper has agreed to extend
the primary terms of the FT Agreement, the FT-NN Agreement and the CSS
Agreement, all as more specifically provided herein;
NOW THEREFORE, in consideration for the premises and the mutual promises
and covenants contained herein, the parties agree as follows:
1. Section 4.1 of the FT-NN Agreement and the CSS Agreement, respectively,
shall be deleted in their entirety and the following Section 4.1
substituted therefor in each agreement:
4.1 Subject to the provisions hereof, this Agreement shall
become effective as of the date first hereinabove
written and shall be in full force and effect for a
primary term through February 28, 1998, and shall
continue and remain in force and effect for successive
terms of one year each thereafter if the parties
mutually agree in writing to each such yearly
extension at least 60 days prior to the end of the
primary term or any subsequent yearly extension.
<PAGE>
Amendatory Agreement
Page 2
2. Section 4.1 of the FT Agreement shall be deleted in its entirety and
the following Section 4.1 substituted therefor:
4.1 Subject to the provisions hereof, this Agreement shall
become effective as of the date first hereinabove
written and shall be in full force and effect for a
primary term through the following dates: (a) April
30, 2007 for 3,300 Mcf per day of Transportation
Demand, and shall continue and remain in force and
effect for successive terms of one (1) year each
thereafter, unless and until cancelled by either party
giving 180 days written notice to the other party
prior to the end of the primary term or any yearly
extension thereof; and (b) February 28, 1998, for
4,649 Mcf per day of Transportation Demand, and shall
continue and remain in force and effect for successive
terms of one year each thereafter if the parties
mutually agree in writing to each such yearly
extension at least 60 days prior to the end of the
primary term or subsequent yearly extension.
3. This Amendment is conditioned on the Stipulation becoming effective as
provided in Article XVIII thereof and the Stipulation not otherwise being
terminated pursuant to its terms. If the Stipulation does not become
effective, or if it terminates pursuant to the terms of the Stipulation,
then either party may give prior written notice to the other party to amend
Section 4.1 of the FT Agreement, FT-NN Agreement, and CSS Agreement
to provide that the respective primary terms under such agreements which
were extended herein through February 28, 1998, shall extend through the
later of October 31, 1995, or ninety (90) days after the date that
the Stipulation terminates. Within fifteen (15) days after the Stipulation
terminates, the parties shall execute any documents necessary to effectuate
the foregoing provision. If the Stipulation becomes effective, then
within fifteen (15) days after such effective date, the parties shall
execute such other amendments to the firm transportation service agreements
provided for in paragraph 1(b) of the Article XV of the Stipulation.
4. As provided in paragraph 2(a) of Article IV of the Stipulation, this
amendment is subject to the provisions of Articles III, paragraph 4 and
XII, paragraph 5 of the Stipulation.
<PAGE>
Amendatory Agreement
Page 3
5. Except as provided herein the FT Agreement, the FT-NN Agreement and the
CSS Agreement shall remain in full force and effect as written.
6. This Amendment is subject to all applicable, valid laws, orders, rules
and regulations of any governmental entity having jurisdiction over the
parties or the subject matter hereof.
WHEREFORE, the parties have executed this Amendment through their duly
authorized representatives to be effective as of the date first written
above.
ATTEST: SOUTHERN NATURAL GAS COMPANY
By: /s/ illegible signature By: /s/ Larry E. Powell
Title: Secretary Title: Sr. Vice President
ATTEST: CHATTANOOGA GAS COMPANY
By: /s/ illegible signature By: /s/ Kenneth A. Royse
Title: Vice President Title: President
