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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 March 31, 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 March 31, 1995.
Common Stock, $5.00 Par Value
Shares Outstanding at March 31, 1995 . . . . . . . . 25,744,226
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ATLANTA GAS LIGHT COMPANY
Quarterly Report on Form 10-Q
For the Quarter Ended March 31, 1995
Table of Contents
Item Page
Number PART I FINANCIAL INFORMATION Number
1 Financial Statements
Condensed Consolidated Income Statements (Unaudited) for
the Three Months, Six Months and Twelve Months Ended
March 31, 1995 and 1994 3
Condensed Consolidated Balance Sheets (Unaudited) at
March 31, 1995, March 31, 1994 and September 30, 1994 4
Condensed Consolidated Statements of Cash Flows (Unaudited)
for the Six Months and Twelve Months Ended
March 31, 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
4 Submission of Matters to a Vote of Security Holders 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, SIX MONTHS AND TWELVE MONTHS ENDED
MARCH 31, 1995 AND 1994
(MILLIONS, EXCEPT PER SHARE DATA)
Three Months Six Months Twelve Months
1995 1994 1995 1994 1995 1994
Operating Revenues . . . .$448.2 $500.2 $777.0 $862.1 $1,114.8 $1,210.1
Cost of Gas. . . . . . . . 269.9 328.5 458.0 558.2 636.6 755.3
Operating Margin . . . . 178.3 171.7 319.0 303.9 478.2 454.8
Other Operating Expenses:
Operating Expenses . . . .88.0 84.9 169.5 165.4 325.3 311.0
Restructuring Costs. . . .23.0 67.5 67.5
Total Other Operating Expenses
111.0 84.9 237.0 165.4 392.8 311.0
Income Taxes . . . . . . . .18.4 26.3 19.0 40.1 13.2 34.2
Operating Income . . . . .48.9 60.5 63.0 98.4 72.2 109.6
Other Income:
Other Income and Deductions.
1.0 2.6 2.4 4.2 3.4 8.2
Income Taxes . . . . . . .(0.4) (0.9) (0.9) (1.7) (1.2) (3.2)
Other Income - Net . . . . 0.6 1.7 1.5 2.5 2.2 5.0
Income Before Interest Charges
49.5 62.2 64.5 100.9 74.4 114.6
Interest Charges . . . . . .12.2 11.8 25.4 24.2 48.8 47.6
Net Income . . . . . . . . .37.3 50.4 39.1 76.7 25.6 67.0
Dividends on Preferred Stock 1.1 1.1 2.2 2.2 4.5 4.4
Earnings Applicable to Common Stock.
$36.2 $49.3 $36.9 $74.5 $21.1 $62.6
Earnings Per Share of Common Stock . .
$1.41 $1.97 $1.44 $2.98 $0.83 $2.52
Cash Dividends Paid Per Share of
Common Stock . . . . . . $0.52 $0.52 $1.04 $1.04 $2.08 $2.08
Average Number of Common Shares
Outstanding (Millions) . .25.7 25.1 25.6 25.0 25.4 24.9
See notes to condensed consolidated financial statements.
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ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(MILLIONS)
March 31, September 30,
1995 1994 1994
ASSETS
Utility Plant. . . . . . . . . . . . $1,872.7 $1,784.9 $1,833.2
Less Accumulated Depreciation. . . . 571.5 534.8 553.6
Utility Plant - Net. . . . . . . 1,301.2 1,250.1 1,279.6
Other Property and Investments (less
accumulated depreciation) . . . . . 18.6 17.8 17.8
Current Assets:
Cash and Cash Equivalents . . . . . 36.2 8.0 3.3
Receivables (less allowance for
uncollectible accounts of $7.2 at
March 31, 1995, $6.9 at March 31, 1994
and $2.8 at September 30, 1994) . 185.6 215.6 79.3
Inventories:
Natural Gas Stored Underground . 22.5 40.0 144.5
Liquefied Natural Gas. . . . . . 11.5 11.3 17.8
Liquefied Petroleum Gas. . . . . 1.6 3.0 3.6
Merchandise. . . . . . . . . . . 2.6 3.9 4.4
Materials and Supplies . . . . . 8.5 9.2 9.1
Other . . . . . . . . . . . . . . . 7.8 7.7 9.1
Total Current Assets . . . . . . 276.3 298.7 271.1
Deferred Debits and Other Assets:
Unrecovered Environmental Response Costs. .
34.2 24.5 30.5
Unrecovered Integrated Resource Plan Costs.
12.5 2.9 11.4
Other . . . . . . . . . . . . . . . 20.5 38.2 32.5
Total Deferred Debits and Other Assets .
67.2 65.6 74.4
Total. . . . . . . . . . . . . $1,663.3 $1,632.2 $ 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)
March 31, September 30,
1995 1994 1994
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock, $5 Par Value, Shares Issued and
Outstanding of 25.7 at March 31, 1995,
25.1 at March 31, 1994 and 25.4 at
September 30, 1994. . . . . . . . $128.7 $125.6 $127.1
Premium on Capital Stock. . . . . . . 249.9 232.7 241.3
Earnings Reinvested . . . . . . . . . 160.4 192.1 150.1
Total Common Stock Equity. . . . . 539.0 550.4 518.5
Preferred Stock, Cumulative $100 Par or Stated
Value, Shares Issued and Outstanding of 0.6
at March 31, 1995, March 31, 1994 and
September 30, 1994. . . . . . . . . 58.5 58.7 58.5
Long-Term Debt. . . . . . . . . . . . 554.5 554.5 554.5
Total Capitalization . . . . . . 1,152.0 1,163.6 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 . . . . . . . . . . . 95.4
Accounts Payable. . . . . . . . . . . 50.8 67.3 57.6
Deferred Purchased Gas Adjustment . . 67.6 52.5 20.1
Customer Deposits . . . . . . . . . . 30.1 26.3 26.8
Taxes . . . . . . . . . . . . . . . . 22.6 35.0 14.0
Accrued Pension Costs . . . . . . . . 25.1
Accrued Postretirement Benefits Costs .30.8 3.9 3.6
Other . . . . . . . . . . . . . . . . 59.9 55.2 53.1
Total Current Liabilities. . . . . 287.2 255.5 285.9
Accrued Environmental Response Costs . . 28.6 18.8 24.3
Deferred Credits . . . . . . . . . . . . 71.9 62.3 66.6
Accumulated Deferred Income Taxes. . . . 123.6 132.0 134.6
Total. . . . . . . . . . . . . .$1,663.3 $1,632.2 $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 SIX MONTHS AND TWELVE MONTHS ENDED MARCH 31, 1995 AND 1994
(MILLIONS)
Six Months Twelve Months
1995 1994 1995 1994
Cash Flows from Operating Activities:
Net Income. . . . . . . . . . . . $39.1 $76.7 $25.6 $67.0
Adjustments to Reconcile Net Income to Net
Cash Flow from Operating Activities:
Non-Cash Restructuring Costs . 66.6 66.6
Depreciation and Amortization .31.5 29.9 60.8 61.0
Deferred Income Taxes . . . . (11.0) 5.4 (2.8) 21.0
Non-Cash Compensation Expense . 4.2 4.1 8.3 7.9
Other . . . . . . . . . . . . (1.3) (0.9) (2.3) (2.2)
129.1 115.2 156.2 154.7
Changes in Certain Assets and
Liabilities. . . . . . . . . .90.7 36.3 44.8 (11.0)
Net Cash Flow from Operating
Activities . . . . . . . . 219.8 151.5 201.0 143.7
Cash Flows from Financing Activities:
Short-Term Borrowings, Net . . . (95.4) (131.4) (10.0)
Redemptions, Purchase Fund and Sinking
Fund Requirements of Preferred
Stock and Long-Term Debt. . . . (15.0) (125.7) (15.0) (178.0)
Sale of Common Stock, Net of Expenses. . .
1.0 1.3 2.1 2.7
Sale of Long-Term Debt . . . . . . 194.5 206.8
Dividends. . . . . . . . . . . . (23.8) (23.6) (47.6) (47.1)
Net Cash Flow from Financing
Activities . . . . . . . .(133.2) (84.9) (60.5) (25.6)
Cash Flows from Investing Activities:
Utility Plant Expenditures . . . (53.5) (63.8) (111.7) (127.7)
Non-Utility Capital Expenditures .(0.9) (0.1) (0.9) (0.7)
Cost of Property Removal, Net of Salvage .
0.7 2.0 0.3 1.2
Net Cash Flow from Investing
Activities . . . . . . . . (53.7) (61.9) (112.3) (127.2)
Net Increase (Decrease) in Cash
and Cash Equivalents . . . .32.9 4.7 28.2 (9.1)
Cash and Cash Equivalents at
Beginning of Period. . . . . 3.3 3.3 8.0 17.1
Cash and Cash Equivalents at
End of Period. . . . . . . $36.2 $8.0 $36.2 $8.0
Cash Paid During the Period for:
Interest . . . . . . . . . . . . $25.5 $22.9 $47.3 $43.5
Income Taxes . . . . . . . . . . $20.7 $12.4 $26.3 $17.9
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 six-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 has completed its assessment activities at the Griffin site,
has developed a proposed CAP for this site, and has submitted the CAP to
EPD for review. 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 recent 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 parcel. 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 has also 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 revised its estimate of investigation and remediation
expenses 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.
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. As a result of the ERCRR, AGL expects that
it will be able to recover all of its Environmental Response Costs. 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.
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.
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
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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 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.
In addition to Negotiated Contracts, which are designed to serve
existing and potential physical 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 the
interruptible customers 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, five Negotiated
Contracts. Additionally, the Georgia Commission has approved Special
Contracts with two 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.
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.
Restructuring will combine offices and create centralized call centers,
as well as a network of locations where customers can pay their bills
throughout the Company's service area. In accordance with the plan's
initial objective, the number of employees of the Company has been
reduced by more than 600 through attrition and voluntary retirement and
severance programs. The Company will implement remaining portions of
the plan during the remainder of fiscal 1995.
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In accordance with current accounting standards, the Company has
recorded restructuring costs of $35.6 million (after income taxes)
related to the early retirement and severance programs, and $5.8 million
(after income taxes) related to office closings and costs to exit the
Company's appliance merchandising and real estate investment operations.
As of March 31, 1995, approximately $67.5 million, or $41.4 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 will be in a
range of $67.5 million to $70 million or $41.4 million to $43 million
after income taxes. Those costs will be offset within three years with
lower operating costs.
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Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Results of Operations
Three-Month Periods Ended March 31, 1995 and 1994
Explained below are the major factors that had a significant effect
on results of operations for the three-month period ended March 31,
1995, compared with the same period for 1994.
Operating revenues decreased 10.4% for the three-month period ended
March 31, 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 8% 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 17.8% for the three-month period ended March
31, 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 8%
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 3.8% for the three-month period ended
March 31, 1995, compared with the same period in 1994. The increase in
operating margin was primarily due to the increase of approximately
37,000 in the number of customers served.
Operating expenses increased 3.7% for the three-month period ended
March 31, 1995, compared with the same period in 1994 primarily due to
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
2.1% primarily due to (1) decreased labor costs as a result of the
Company's restructuring plan and (2) decreased uncollectible accounts
expenses as a result of the decrease in operating revenues. Total other
operating expenses increased primarily due to restructuring costs of $23
million. See Note 7 to Notes to Condensed Consolidated Financial
Statements in this Form 10-Q.
Other income decreased $1.1 million for the three-month period ended
March 31, 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 3.4% for the three-month period ended
March 31, 1995, compared with the same period in 1994. The increase was
primarily due to increased interest rates on short-term debt.
Income taxes decreased $8.4 million for the three-month period ended
March 31, 1995, compared with the same period in 1994 primarily due to
decreased taxable income.
Net income for the three-month period ended March 31, 1995, was
$37.3 million, compared with net income of $50.4 million for the same
period in 1994. Earnings per share of common stock were $1.41 for the
three-month period ended March 31, 1995, compared with earnings per
share of $1.97 for the same period in 1994. The decreases in net income
and earnings per share were primarily due to restructuring costs of $23
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 increased operating margin resulting
from the increase of approximately 37,000 in the number of customers
served.
<PAGE>
Six-Month Periods Ended March 31, 1995 and 1994
Explained below are the major factors that had a significant effect on
results of operations for the six-month period ended March 31, 1995,
compared with the same period for 1994.
Operating revenues decreased 9.9% for the six-month period ended
March 31, 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 19% 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% for the six-month period ended
March 31, 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 19% 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% for the six-month period ended
March 31, 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 2.5% for the six-month period ended
March 31, 1995, compared with the same period in 1994 primarily due to
an increase of $7.8 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 2.2% primarily due to (1) decreased
labor costs as a result of the Company's restructuring plan and (2)
decreased uncollectible accounts expenses as a result of the decrease in
operating revenues. Total other operating expenses increased primarily
due to restructuring costs of $67.5 million. See Note 7 to Notes to
Condensed Consolidated Financial Statements in this Form 10-Q.
Other income decreased $1 million for the six-month period ended
March 31, 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 5% for the six-month period ended
March 31, 1995, compared with the same period in 1994. The increase was
primarily due to increased interest rates on short-term debt.
Income taxes decreased $21.9 million for the six-month period ended
March 31, 1995, compared with the same period in 1994 primarily due to
decreased taxable income.
Net income for the six-month period ended March 31, 1995, was $39.1
million, compared with net income of $76.7 million for the same period
in 1994. Earnings per share of common stock were $1.44 for the
six-month period ended March 31, 1995, compared with earnings per share
of $2.98 for the same period in 1994. The decreases in net income and
earnings per share were primarily due to restructuring costs of $67.5
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 increased operating margin resulting
from the increase of approximately 37,000 in the number of customers
served.
<PAGE>
Twelve-Month Periods Ended March 31, 1995 and 1994
Explained below are the major factors that had a significant effect
on results of operations for the twelve-month period ended March 31,
1995, compared with the same period for 1994.
Operating revenues decreased 7.9% for the twelve-month period ended
March 31, 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 22% warmer than the same period in 1994. The decrease in
operating revenues was partly offset by (1) an increase of approximately
37,000 in the number of customers served and (2) a change in the mix of
volumes of gas sold and transported to interruptible customers.
Although margins are not affected, operating revenues are greater when
gas is sold to customers than when gas is transported to customers.
Cost of gas decreased 15.7% for the twelve-month period ended
March 31, 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 and (2) decreased volumes of gas sold to firm service
customers as a result of weather that was 22% 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 5.1% for the twelve-month period ended
March 31, 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 4.6% for the twelve-month period ended
March 31, 1995, compared with the same period in 1994 primarily due to
an increase of $10.2 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. The remainder of
the increase in operating expenses was primarily due to (1) increased
postretirement benefits other than pensions and (2) increased outside
services employed. Total other operating expenses increased primarily
due to (1) the increase in operating expenses and (2) restructuring
costs of $67.5 million. See Note 7 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
Other income decreased $2.8 million for the twelve-month period
ended March 31, 1995, compared with the same period in 1994 primarily
due to (1) decreased income from propane operations as a result of
warmer weather and (2) decreased interest income associated with income
tax refunds related to prior years.
Interest charges increased $1.2 million for the twelve-month period
ended March 31, 1995, compared with the same period in 1994. The
increase was primarily due to increased interest rates on short-term
debt.
Income taxes decreased $23 million for the twelve-month period
ended March 31, 1995, compared with the same period in 1994 primarily
due to decreased taxable income.
Net income for the twelve-month period ended March 31, 1995, was
$25.6 million, compared with net income of $67 million for the same
period in 1994. Earnings per share of common stock were $.83 for the
twelve-month period ended March 31, 1995, compared with earnings per
share of $2.52 for the same period in 1994. The decreases in net income
and earnings per share were primarily due to restructuring costs of
$67.5 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 increased operating margin resulting
from the increase of approximately 37,000 in the number of customers
served.
<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 March 31 as a result of colder weather. The Company
also uses gas stored underground and liquefied natural gas to serve its
customers during periods of colder weather. As a result, accounts
receivable increased $106.3 million and inventory of gas stored
underground and liquefied natural gas decreased $128.3 million during
the six months ended March 31, 1995. Accounts receivable decreased $30
million from March 31, 1994 to March 31, 1995 primarily due to decreased
operating revenues. Accounts payable decreased $16.5 million from March
31, 1994 to March 31, 1995 primarily due to a $14.6 million decrease in
accounts payable to pipeline suppliers.
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 $79.6 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 new 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. On August 1, 1994, AGL filed its gas supply plan for
fiscal year 1995, and on September 15, 1994, the Georgia Commission
approved the plan. Pursuant to AGL's approved plan, gas supply purchases
may be recovered under the purchased gas provisions of AGL's rate
schedules, and 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. 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 rate schedules. The Company
was in an over recovery position of $52.5 million at March 31, 1994, and
$67.6 million at March 31, 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.
Cash and cash equivalents increased $32.9 million and $28.2 million
for the six-month and twelve-month periods ended March 31, 1995
primarily due to net cash flow from operating activities.
The expenditures for plant and other property totaled $54.4 million
and $112.6 million for the six-month and twelve-month periods ended
March 31, 1995, respectively.
The Company had accrued liabilities of $28.6 million at March 31,
1995 compared with $18.8 million at March 31, 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. As a result of the ERCRR, the Company expects
that it will be able to recover all of its Environmental Response Costs.
See Note 3 to Notes to Condensed Consolidated Financial Statements and
Part II, Item 5, "Other Information, " "Environmental Matters" of this
Form 10-Q.
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
<PAGE>
Contract may begin without additional Georgia Commission action, once a
copy of the contract is filed with the Georgia Commission. The Georgia
Commission may reject a Negotiated Contract within 60 days of filing;
absent such action by the Georgia Commission, the Negotiated Contracts
are fully effective.
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.
Long-term debt due within one year decreased $15 million for the
six-month and twelve-month periods ended March 31, 1995 due to the
maturity of $15 million of Medium-Term Notes in January, 1995.
Short-term debt outstanding decreased $95.4 million from September
30, 1994 to March 31, 1995 primarily due to net cash flow from
operating activities.
Accrued postretirement benefits costs increased $26.9 million from
March 31, 1994 to March 31, 1995 and $27.2 million from September 30,
1994 to March 31, 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 $25.1 million from March 31, 1994
and September 30, 1994 to March 31, 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 will be in a
range of $67.5 million to $70 million or $41.4 million to $43 million
after income taxes. Those costs will be offset within three years with
lower operating costs.
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.
Item 4. Submission of Matters to a Vote of Security Holders
a) The Annual Meeting of shareholders of the Company was held on
February 3, 1995.
b) All nominees for director listed in the Company's Proxy
Statement were elected without opposition for a one-year term. The
number of votes "for" each nominee and the number of votes "withheld"
with respect to each nominee is as follows:
For Withheld
1. Frank Barron, Jr. 21,903,458 385,787
2. W. Waldo Bradley 21,852,208 437,037
3. Otis A. Brumby, Jr. 21,858,605 430,640
4. L. L. Gellerstedt, Jr. 21,864,694 424,551
5. David R. Jones 21,858,674 430,571
6. Kenneth D. Lewis 21,875,888 413,357
7. Albert G. Norman, Jr. 21,873,304 415,941
8. D. Raymond Riddle 21,856,069 433,176
9. Dr. Betty L. Siegel 21,846,851 442,394
10. Ben J. Tarbutton, Jr. 21,878,986 410,259
11. Charles McKenzie Taylor 21,866,250 422,995
12. Felker W. Ward, Jr. 21,867,524 421,721
<PAGE>
c) Other matters voted upon at the meeting and the number of
affirmative and negative votes and abstentions with respect to each
matter include:
(1) A proposal to adopt the Atlanta Gas Light Company
Nonqualified Savings Plan.
Affirmative Negative Abstentions
20,026,714 1,376,463 886,068
(78%) (5%) (4%)
d) No other matters were voted upon at the Annual Meeting.
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 $79.6 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 concern 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 $68
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 February 28, 1995, Southern made an additional filing to recover
approximately $5.2 million in GSR costs and approximately $7.1 million
in other transition costs. On March 30, 1995, the FERC accepted
Southern's filing, 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.
<PAGE>
TENNESSEE GSR Cost Recovery Proceeding. Tennessee Gas Pipeline
Company (Tennessee) has continued to make quarterly GSR cost recovery
filings with the FERC. On March 30, 1995, Tennessee filed with the FERC
to recover an additional $21.8 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 $7.4 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.
SOUTH GEORGIA On February 9, 1995, an administrative law judge issued
an initial decision in South Georgia Natural Gas Company's (South
Georgia) rate case that South Georgia's interruptible transportation
(IT) rate should be based on a load factor of 100% on a prospective
basis. AGL supported the 100% load factor IT rate at the hearing in
this proceeding. South Georgia and the Georgia Industrial Group have
filed exceptions to the initial decision with the FERC, and AGL has
responded to the exceptions and supported the initial decision. The
FERC has not yet acted on the exceptions.
TENNESSEE On December 30, 1994, Tennessee filed a new general
rate case seeking an increase in revenues of approximately $117.9
million annually, and reflecting numerous modifications to its tariff.
On January 11, 1995, the Company protested the filing on various grounds
and requested that the FERC set Tennessee's filing for hearing. On
January 25, 1995, the FERC issued an order accepting Tennessee's filing,
subject to refund, and set a hearing date. The Company is actively
participating in the hearing procedures.
TRANSCO On March 1, 1995, Transcontinental Gas Pipe Line
Corporation (Transco) filed a new general rate case to recover
approximately $132 million in additional revenues, and to reflect
numerous modifications to its tariff. On March 10, 1995, AGL protested
the filing on various grounds and requested that the FERC set Transco's
filing for hearing. On March 31, 1995, the FERC issued an order
accepting Transco's filing, subject to refund, and set a hearing date.
AGL is actively participating in the hearing procedures.
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. 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 17 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
<PAGE>
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 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 the revenue that would
have been received from full rates and the revenues that are actually
received from the lower rates resulting from Negotiated Contracts. 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 physical 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 the
interruptible customers 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, five Negotiated
Contracts. Additionally, as discussed below, the Georgia Commission has
approved Special Contracts with two additional customers.
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 the discounts.
The Georgia Commission approved the 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.
On May 1, 1995, Chattanooga Gas Company (Chattanooga) made a rate
filing 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 rate increase will be used by Chattanooga to improve and expand
its distribution system and to recover increased operation, maintenance,
and tax expenses.
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.
<PAGE>
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 U. S. Environmental Protection Agency. 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.
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 has completed its assessment activities at the Griffin site,
has developed a proposed CAP for this site, and has submitted the CAP to
EPD for review. 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 recent 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 has also 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).
<PAGE>
The Company has revised its estimate of investigation and
remediation expenses 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.
As a result of the ERCRR, the Company expects that it will be able
to recover all of its Environmental Response Costs. See Note 3 to Notes
to Condensed Consolidated Financial Statements in this Form 10-Q.
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, and the expiration of applicable waiting
periods.
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10(a) - Firm Storage (FS) Agreement, dated November 1,
1994, between the Company and ANR Storage
Company.
10(b) - Firm Storage (FS) Agreement, dated November 1,
1994, between the Company and ANR Storage
Company.
10(c) - Firm Transportation Agreement, dated March 1,
1995, between the Company and Southern Natural
Gas Company amending Service Agreement #902470
under Rate Schedule FT (Exhibit 10(hh), Form
10-K for the fiscal year ended September 30,
1994.)
10(d) - Firm Transportation Agreement, dated March 1,
1995, between the Company and Southern Natural
Gas Company amending Service Agreement #904480
under Rate Schedule FT (Exhibit 10(jj), 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 May 15, 1995 /s/ Robert L. Goocher
Robert L. Goocher
Executive Vice President
Business Support
(Principal Financial Officer)
Date May 15, 1995 /s/ J. Michael Riley
J. Michael Riley
Vice President - Finance and Accounting
(Principal Accounting Officer)
<PAGE>
EXHIBIT 10a
SERVICE AGREEMENT
THIS AGREEMENT entered into as of the 1st day of November, 1994, by and
between ANR Storage Company, a Michigan Corporation, hereinafter referred to
as "Seller," and Atlanta Gas Light Company, hereinafter referred to as
"Customer."
W I T N E S S E T H
WHEREAS, Customer has requested Seller to store Gas on its behalf; and
WHEREAS, Seller has sufficient capacity available to provide the Storage
Service for Customer on the terms specified herein;
NOW, THEREFORE, Seller and Customer agree as follows:
ARTICLE I
STORAGE SERVICE
1. Seller's service hereunder shall be subject to receipt of all requisite
regulatory authorizations from the Federal Energy Regulatory Commission
("Commission"), or any successor regulatory authority, and any other
necessary governmental authorizations, in a manner and form acceptable to
Seller.
2. Subject to the terms and provisions of this Agreement, Customer may on
any Day deliver or cause to be delivered to Seller, Gas up to the Maximum
Daily Injection Quantity plus Seller's Injection Use for Storage of up to
the Maximum Storage Quantity, and at Customer's request on any Day Seller
agrees to tender Equivalent Quantities of Gas to or for the account of
Customer, on a firm basis, up to the Maximum Daily Withdrawal Quantity,
reduced by Seller's Withdrawal Use.
3. Seller may, if requested by Customer, inject or withdraw from storage
daily quantities in excess of the Maximum Daily Injection Quantity or
Maximum Daily Withdrawal Quantity specified in Paragraph 2, above, if it can
do so without adverse effect on Seller's operations or its ability to meet
its higher priority obligations.
<PAGE>
SERVICE AGREEMENT
(Continued)
ARTICLE II
POINT OF INJECTION AND POINT OF WITHDRAWAL
1. Customer shall deliver or cause to be delivered Gas hereunder at the
Point of Injection.
2. Seller shall tender to or for the account of Customer, Equivalent
Quantities of Gas stored hereunder, at the Point of Withdrawal.
ARTICLE III
TERM OF AGREEMENT
1. This Agreement shall be effective as of the date first above written and
shall remain in effect for a primary term commencing November 1, 1994 and
ending March 31, 2003.
ARTICLE IV
RATE SCHEDULE AND CHARGES
1. Each Month, Customer shall pay Seller for the service hereunder, an
amount determined in accordance with Seller's Rate Schedule FS and the
applicable provisions of the General Terms and Conditions of Seller's
F.E.R.C. Gas Tariff, Original Volume No. 1, as filed with the Commission.
Such Rate Schedule and General Terms and Conditions are incorporated by
reference and made a part hereof. Section VI & VII of Exhibit A hereto sets
forth the applicable information as follows, which shall be utilized for
transactions hereunder:
(a) Rates and Charges
(b) Additional charges which are applicable
<PAGE>
SERVICE AGREEMENT
(Continued)
Exhibit A to this Agreement shall specify the Rates and Charges and
Additional charges which are applicable. When the level of any Rates and
Charges or Additional charges is changed pursuant to Commission authorization
or direction, Seller may unilaterally effect an amendment to Exhibit A to
reflect such change(s) by so specifying in a written communication to
Customer.
2. It is further agreed that Seller may seek authorization from the
Commission and/or other appropriate body for such changes to any rate(s) and
terms and conditions set forth herein, in Rate Schedule FS or in the General
Terms and Conditions of Seller's Original Volume No. 1 FERC Gas Tariff, as
may be found necessary to assure Seller just and reasonable rates. Nothing
herein contained shall be construed to deny Customer any rights it may have
under the Natural Gas Act, as amended, including the right to participate
fully in rate proceedings by intervention or otherwise to contest Seller's
filing in whole or in part.
3. Further Agreement:
a) Customer's Reservation Rates shall be as follows:
Deliverability - Monthly $2.35820
Capacity - Monthly $0.02406
These rates will remain in effect through the term of this Service Agreement
or until the rates set forth in Seller's Rate Schedule FS are changed, at
which time Customer's rates will change to become the same as the new
maximum rates under the then effective Rate Schedule FS.
<PAGE>
SERVICE AGREEMENT
(Continued)
EXHIBIT "A"
to Agreement between
ANR Storage Company (Seller)
and
Atlanta Gas Light Company (Customer)
Dated November 1, 1994
I. STORAGE DEMAND INJECTION QUANTITY (dth) 44,231
II. STORAGE DEMAND WITHDRAWAL QUANTITY (dth) 115,001
III. MAXIMUM STORAGE QUANTITY (dth) 5,750,050
IV. POINT OF INJECTION - Point of interconnection between the pipeline
systems of Great Lakes Gas Transmission
Limited Partnership and Seller in Frederic
Township, Crawford County, Michigan.
V. POINT OF WITHDRAWAL - Point of interconnection between the
pipeline systems of Great Lakes Gas
Transmission Limited Partnership and
Seller in Frederic Township, Crawford County,
Michigan.
VI. RATES AND CHARGES - Maximum Rates as set forth on Sheet No. 5 of
Original Volume No. 1 unless otherwise agreed
to.
VII. ADDITIONAL CHARGES - pursuant to Section 5 of Rate Schedule FS.
<PAGE>
SERVICE AGREEMENT
(Continued)
ARTICLE V
NOTICE
1. Except as may be otherwise provided, any notice, request, demand,
statement or bill provided for in this Agreement or any notice which a party
may desire to give the other shall be in writing and mailed by regular mail,
effective as of the postmark date, to the post office address of the party
intended to receive the same, as the case may be, as follows:
Seller: ANR Storage Company
500 Renaissance Center
Detroit, Michigan 48243
Attention: Marketing Department
Customer: Atlanta Gas Light Company
303 Peachtree Street N.E.
Atlanta, Georgia 30308-3249
Attention: Stephen Gunther - General Correspondence
Attention: Gas Supply Dept. - Billing
ARTICLE VI
INCORPORATION BY REFERENCE
The provisions of Rate Schedule FS and the General Terms and Conditions of
Seller's FERC Gas Tariff, Original Volume No. 1, are specifically
incorporated herein by reference and made a part hereof.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective Officers or Representatives thereunto duly
authorized.
ANR Storage Company
By /s/ Michael A. Mujadin
Its Executive Vice President
Atlanta Gas Light Company
By /s/ Stephen J. Gunther
Its Vice President
<PAGE>
EXHIBIT 10b
SERVICE AGREEMENT
THIS AGREEMENT entered into as of the 1st day of November, 1994, by and
between ANR Storage Company, a Michigan Corporation, hereinafter referred to
as "Seller," and Atlanta Gas Light Company, hereinafter referred to as
"Customer."
W I T N E S S E T H
WHEREAS, Customer has requested Seller to store Gas on its behalf; and
WHEREAS, Seller has sufficient capacity available to provide the Storage
Service for Customer on the terms specified herein;
NOW, THEREFORE, Seller and Customer agree as follows:
ARTICLE I
STORAGE SERVICE
1. Seller's service hereunder shall be subject to receipt of all requisite
regulatory authorizations from the Federal Energy Regulatory Commission
("Commission"), or any successor regulatory authority, and any other
necessary governmental authorizations, in a manner and form acceptable to
Seller.
2. Subject to the terms and provisions of this Agreement, Customer may on
any Day deliver or cause to be delivered to Seller, Gas up to the Maximum
Daily Injection Quantity plus Seller's Injection Use for Storage of up to
the Maximum Storage Quantity, and at Customer's request on any Day Seller
agrees to tender Equivalent Quantities of Gas to or for the account of
Customer, on a firm basis, up to the Maximum Daily Withdrawal Quantity,
reduced by Seller's Withdrawal Use.
3. Seller may, if requested by Customer, inject or withdraw from storage
daily quantities in excess of the Maximum Daily Injection Quantity or
Maximum Daily Withdrawal Quantity specified in Paragraph 2, above, if it can
do so without adverse effect on Seller's operations or its ability to meet
its higher priority obligations.
<PAGE>
SERVICE AGREEMENT
(Continued)
ARTICLE II
POINT OF INJECTION AND POINT OF WITHDRAWAL
1. Customer shall deliver or cause to be delivered Gas hereunder at the
Point of Injection.
2. Seller shall tender to or for the account of Customer, Equivalent
Quantities of Gas stored hereunder, at the Point of Withdrawal.
ARTICLE III
TERM OF AGREEMENT
1. This Agreement shall be effective as of the date first above written and
shall remain in effect for a primary term commencing November 1, 1994 and
ending March 31, 2003.
ARTICLE IV
RATE SCHEDULE AND CHARGES
1. Each Month, Customer shall pay Seller for the service hereunder, an
amount determined in accordance with Seller's Rate Schedule FS and the
applicable provisions of the General Terms and Conditions of Seller's
F.E.R.C. Gas Tariff, Original Volume No. 1, as filed with the Commission.
Such Rate Schedule and General Terms and Conditions are incorporated by
reference and made a part hereof. Section VI & VII of Exhibit A hereto sets
forth the applicable information as follows, which shall be utilized for
transactions hereunder:
(a) Rates and Charges
(b) Additional charges which are applicable
<PAGE>
SERVICE AGREEMENT
(Continued)
Exhibit A to this Agreement shall specify the Rates and Charges and
Additional charges which are applicable. When the level of any Rates and
Charges or Additional charges is changed pursuant to Commission authorization
or direction, Seller may unilaterally effect an amendment to Exhibit A to
reflect such change(s) by so specifying in a written communication to
Customer.
2. It is further agreed that Seller may seek authorization from the
Commission and/or other appropriate body for such changes to any rate(s) and
terms and conditions set forth herein, in Rate Schedule FS or in the General
Terms and Conditions of Seller's Original Volume No. 1 FERC Gas Tariff, as
may be found necessary to assure Seller just and reasonable rates. Nothing
herein contained shall be construed to deny Customer any rights it may have
under the Natural Gas Act, as amended, including the right to participate
fully in rate proceedings by intervention or otherwise to contest Seller's
filing in whole or in part.
3. Further Agreement:
a) Customer's Reservation Rates shall be as follows:
Deliverability - Monthly $2.35820
Capacity - Monthly $0.02406
These rates will remain in effect through the term of this Service Agreement
or until the rates set forth in Seller's Rate Schedule FS are changed, at
which time Customer's rates will change to become the same as the new maximum
rates under the then effective Rate Schedule FS.
<PAGE>
SERVICE AGREEMENT
(Continued)
EXHIBIT "A"
to Agreement between
ANR Storage Company (Seller)
and
Atlanta Gas Light Company (Customer)
Dated November 1, 1994
I. STORAGE DEMAND INJECTION QUANTITY (dth) 43,448
II. STORAGE DEMAND WITHDRAWAL QUANTITY (dth) 56,483
III. MAXIMUM STORAGE QUANTITY (dth) 5,648,279
IV. POINT OF INJECTION - Point of interconnection between the pipeline
systems of Great Lakes Gas Transmission Limited
Partnership and Seller in Frederic Township,
Crawford County, Michigan.
V. POINT OF WITHDRAWAL - Point of interconnection between the
pipeline systems of Great Lakes Gas
Transmission Limited Partnership and Seller in
Frederic Township, Crawford County, Michigan.
VI. RATES AND CHARGES - Maximum Rates as set forth on Sheet No. 5 of
Original Volume No. 1 unless otherwise agreed
to.
VII. ADDITIONAL CHARGES - pursuant to Section 5 of Rate Schedule FS.
<PAGE>
SERVICE AGREEMENT
(Continued)
ARTICLE V
NOTICE
1. Except as may be otherwise provided, any notice, request, demand,
statement or bill provided for in this Agreement or any notice which a party
may desire to give the other shall be in writing and mailed by regular mail,
effective as of the postmark date, to the post office address of the party
intended to receive the same, as the case may be, as follows:
Seller: ANR Storage Company
500 Renaissance Center
Detroit, Michigan 48243
Attention: Marketing Department
Customer: Atlanta Gas Light Company
303 Peachtree Street N.E.
Atlanta, Georgia 30308-3249
Attention: Stephen Gunther - General Correspondence
Attention: Gas Supply Dept. - Billing
ARTICLE VI
INCORPORATION BY REFERENCE
The provisions of Rate Schedule FS and the General Terms and Conditions of
Seller's FERC Gas Tariff, Original Volume No. 1, are specifically
incorporated herein by reference and made a part hereof.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their respective Officers or Representatives thereunto duly
authorized.
ANR Storage Company
By /s/ Michael A. Mujadin
Its Executive Vice President
Atlanta Gas Light Company
By /s/ Stephen J. Gunther
Its Vice President
<PAGE>
EXHIBIT 10c
AMENDATORY AGREEMENT
This Amendment is entered into this 1st day of March, 1995, between SOUTHERN
NATURAL GAS COMPANY ("Company") and ATLANTA GAS LIGHT COMPANY ("Shipper").
W I T N E S S E T H:
WHEREAS, Company and Shipper are parties to a firm transportation agreement
dated September 1, 1994, (#902470) for 100,000 Mcf per day ("September FT
Agreement"), a firm transportation agreement dated November 1, 1994,
(#904460) for 259,812 Mcf per day ("November FT Agreement"), a firm
transportation-no notice agreement dated November 1, 1994, (#904461) for
406,222 Mcf per day ("FT-NN Agreement"), and a contract storage service
agreement dated November 1, 1994, (#S20150) for 20,117,674 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, Company has agreed to discount
Shipper's rates and charges under the September FT Agreement and Shipper has
agreed to extend the primary terms of the September FT Agreement, the
November 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 September FT Agreement, FT-NN Agreement and 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
2. Section 4.1 of the November 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 114,905 Mcf per day of Transportation Demand, and June 30, 2007 for 1,000
Mcf per day of Transportation Demand, and shall continue and remain in force
and effect for successive terms of one year each after the end of each
primary term for the specified volume, unless and until cancelled with
respect to the associated volume by either party giving 180 days written
notice to the other party prior to the end of the specified primary term or
any yearly extension thereof; and (b) February 28, 1998, for 143,907 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. The current Exhibit E to the September FT Agreement shall be deleted in
its entirety and the 1st Revised Exhibit E attached hereto effective March
1, 1995, shall be substituted therefor.
4. 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 its terms, then either party may
give prior written notice to the other party to (a) reinstate the primary
term and Exhibit E which were in effect under the September FT Agreement
prior to the date of this Amendment, and (b) amend Section 4.1 of the
November FT Agreement, the FT-NN Agreement, and the 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 Article
XV of the Stipulation.
<PAGE>
Amendatory Agreement
5. 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.
6. Except as provided herein, the September FT Agreement, the November FT
Agreement, the FT-NN Agreement and the CSS Agreement shall remain in full
force and effect as written.
7. 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/ Joel Anderson
___________________________ ___________________________
Title: Secretary Title: Vice President
_________________________ _________________________
ATTEST: ATLANTA GAS LIGHT COMPANY
By: /s/ Melanie M. Platt By: /s/ Stephen J. Gunther
___________________________ ___________________________
Title: Corporate Secretary Title: Vice President
_________________________ _________________________
<PAGE>
Service Agreement No. 902470
FIRST REVISED
EXHIBIT E
DISCOUNT INFORMATION
Discounted Rates:
(1) The Reservation Charge under this Agreement shall be $10.50/Mcf;
(2) The applicable GSR Cost Surcharge and GSR Volumetric Surcharge shall be
capped at 50% each;
(3) All other surcharges shall be assessed at full rate under this
Agreement.
Discounted Rate Effective from 3/1/95 to 2/28/98,
subject to the termination provisions of the Amendatory Agreement between
the parties dated March 1, 1995, pursuant to which this revised Exhibit E
was established.
/s/ Stephen J. Gunther /s/ Joel Anderson
_________________________ ____________________________
ATLANTA GAS LIGHT COMPANY SOUTHERN NATURAL GAS COMPANY
<PAGE>
EXHIBIT 10d
AMENDATORY AGREEMENT
This Amendment is entered into this 1st day of March, 1995, between SOUTHERN
NATURAL GAS COMPANY ("Company") and ATLANTA GAS LIGHT 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, (#904480) for 5,173 Mcf per day ("FT Agreement"), a
firm transportation-no notice agreement dated November 1, 1994, (#904481)
for 6,764 Mcf per day ("FT-NN Agreement"), and a contract storage service
agreement dated November 1, 1994, (#S20140) for 334,997 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 Agreement, FT-NN Agreement and 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.
2. 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
<PAGE>
Amendatory Agreement
the other party that it wishes to amend Section 4.1 of the FT Agreement,
the FT-NN Agreement and the CSS Agreement to provide that the respective
primary terms under such agreements 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 Article XV of the Stipulation.
3. 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.
4. Except as provided herein, the FT Agreement, the FT-NN Agreement and the
CSS Agreement shall remain in full force and effect as written.
5. 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/ Joel Anderson
Title: Secretary Title: Vice President
ATTEST: ATLANTA GAS LIGHT COMPANY
By: /s/ Melanie M. Platt By: /s/ Stephen J. Gunther
Title: Corporate Secretary Title: Vice President
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> SEP-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> MAR-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1301
<OTHER-PROPERTY-AND-INVEST> 19
<TOTAL-CURRENT-ASSETS> 276
<TOTAL-DEFERRED-CHARGES> 65
<OTHER-ASSETS> 2
<TOTAL-ASSETS> 1663
<COMMON> 129
<CAPITAL-SURPLUS-PAID-IN> 250
<RETAINED-EARNINGS> 160
<TOTAL-COMMON-STOCKHOLDERS-EQ> 539
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> 511
<TOT-CAPITALIZATION-AND-LIAB> 1663
<GROSS-OPERATING-REVENUE> 777
<INCOME-TAX-EXPENSE> 19
<OTHER-OPERATING-EXPENSES> 237
<TOTAL-OPERATING-EXPENSES> 714
<OPERATING-INCOME-LOSS> 63
<OTHER-INCOME-NET> 2
<INCOME-BEFORE-INTEREST-EXPEN> 65
<TOTAL-INTEREST-EXPENSE> 25
<NET-INCOME> 39
2
<EARNINGS-AVAILABLE-FOR-COMM> 37
<COMMON-STOCK-DIVIDENDS> 27
<TOTAL-INTEREST-ON-BONDS> 22
<CASH-FLOW-OPERATIONS> 220
<EPS-PRIMARY> 1.44
<EPS-DILUTED> 1.44
</TABLE>
