<PAGE>
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 December 31, 1994
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 December 31, 1994.
Common Stock, $5.00 Par Value
Shares Outstanding at December 31, 1994. . . . . . . . . . . 25,600,552
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ATLANTA GAS LIGHT COMPANY
Quarterly Report on Form 10-Q
For the Quarter Ended December 31, 1994
Table of Contents
Item Page
Number PART I FINANCIAL INFORMATION Number
1 Financial Statements
Condensed Consolidated Income Statements (Unaudited)
for the Three Months and Twelve Months Ended
December 31, 1994 and 1993 3
Condensed Consolidated Balance Sheets (Unaudited) at
December 31, 1994, December 31, 1993 and
September 30, 1994 4
Condensed Consolidated Statements of Cash Flows
(Unaudited) for the Three Months and Twelve
Months Ended December 31, 1994 and 1993 6
Notes to Condensed Consolidated Financial Statements
(Unaudited) 7
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 10
PART II OTHER INFORMATION
1 Legal Proceedings 14
5 Other Information 14
6 Exhibits and Reports on Form 8-K 18
SIGNATURES 19
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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 AND TWELVE MONTHS ENDED DECEMBER 31, 1994 AND 1993
(MILLIONS, EXCEPT PER SHARE DATA)
Three Months Twelve Months
-------------- ------------------
1994 1993 1994 1993
------ ------ -------- --------
Operating Revenues $328.8 $361.9 $1,166.8 $1,158.1
Cost of Gas 188.1 229.7 695.2 718.4
------ ------ -------- --------
Operating Margin 140.7 132.2 471.6 439.7
------ ------ -------- --------
Other Operating Expenses:
Operating Expenses 81.5 80.5 322.2 305.0
Restructuring Costs 44.5 44.5
------ ------ ------- --------
Total Other Operating Expenses 126.0 80.5 366.7 305.0
Income Taxes 0.6 13.8 21.1 30.5
------ ------ ------- -------
Operating Income 14.1 37.9 83.8 104.2
------ ------ ------- -------
Other Income:
Other Income and Deductions 1.4 1.6 5.0 7.9
Income Taxes (0.5) (0.8) (1.7) (3.0)
------ ------ ------- -------
Other Income - Net 0.9 0.8 3.3 4.9
------ ------ ------- -------
Income Before Interest Charges 15.0 38.7 87.1 109.1
Interest Charges 13.2 12.4 48.4 47.4
------ ------ ------- -------
Net Income 1.8 26.3 38.7 61.7
Dividends on Preferred Stock 1.1 1.1 4.5 4.5
------ ------ ------- -------
Earnings Applicable to Common
Stock $ 0.7 $ 25.2 $ 34.2 $ 57.2
====== ====== ======= =======
Earnings Per Share of Common Stock $ 0.03 $ 1.01 $ 1.35 $ 2.32
Cash Dividends Paid Per Share of
Common Stock $ 0.52 $ 0.52 $ 2.08 $ 2.08
Average Number of Common Shares
Outstanding (Millions) 25.5 24.9 25.3 24.7
See notes to condensed consolidated financial statements.
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ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(MILLIONS)
December 31, September 30,
----------------- -------------
1994 1993 1994
-------- -------- --------
ASSETS
Utility Plant $1,847.5 $1,764.2 $1,833.2
Less Accumulated Depreciation 559.0 532.4 553.6
-------- -------- --------
Utility Plant - Net 1,288.5 1,231.8 1,279.6
-------- -------- --------
Other Property and Investments (less
accumulated depreciation) 18.7 17.9 17.8
-------- -------- --------
Current Assets:
Cash and Cash Equivalents 4.2 4.3 3.3
Receivables (less allowance for
uncollectible accounts of $5.0 at
December 31, 1994, $4.1 at December 31,
1993 and $2.8 at September 30, 1994) 187.5 231.0 79.3
Inventories:
Natural Gas Stored Underground 103.9 108.7 144.5
Liquefied Natural Gas 17.5 18.8 17.8
Liquefied Petroleum Gas 3.3 4.1 3.6
Merchandise 3.2 3.2 4.4
Materials and Supplies 9.3 9.1 9.1
Other 8.4 2.1 9.1
-------- -------- --------
Total Current Assets 337.3 381.3 271.1
-------- -------- --------
Deferred Debits and Other Assets:
Unrecovered Environmental Response Costs 29.4 24.6 30.5
Unrecovered Integrated Resource Plan Costs 12.8 0.7 11.4
Other 26.8 35.1 32.5
-------- -------- --------
Total Deferred Debits and Other Assets 69.0 60.4 74.4
-------- -------- --------
Total $1,713.5 $1,691.4 $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)
December 31, September 30,
--------------- -------------
1994 1993 1994
------- ------- --------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock, $5 Par Value, Shares Issued and
Outstanding of 25.6 at December 31, 1994, 25.0
at December 31, 1993 and 25.4 at September 30,
1994 $ 128.0 $ 124.9 $ 127.1
Premium on Capital Stock 245.8 228.5 241.3
Earnings Reinvested 137.5 155.9 150.1
-------- ------- --------
Total Common Stock Equity 511.3 509.3 518.5
Preferred Stock, Cumulative $100 Par or Stated
Value, Shares Issued and Outstanding of 0.6 at
December 31, 1994, December 31, 1993 and
September 30, 1994 58.5 58.7 58.5
Long-Term Debt 554.5 509.8 554.5
------- ------- -------
Total Capitalization 1,124.3 1,077.8 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 148.6 229.5 95.4
Accounts Payable 51.7 81.4 57.6
Deferred Purchased Gas Adjustment 33.3 5.2 20.1
Customer Deposits 29.6 25.3 26.8
Taxes 14.4 24.9 14.0
Accrued Pension Costs 20.2
Accrued Postretirement Benefits Costs 23.0 2.3 3.6
Other 41.4 32.7 53.1
------- ------- --------
Total Current Liabilities 377.5 401.6 285.9
------- ------- --------
Accrued Environmental Response Costs 24.1 19.1 24.3
------- ------- --------
Deferred Credits 66.1 63.3 66.6
------- ------- --------
Accumulated Deferred Income Taxes 121.5 129.6 134.6
------- ------- --------
Total $1,713.5$1,691.4 $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 THREE MONTHS AND TWELVE MONTHS ENDED DECEMBER 31, 1994 AND 1993
(MILLIONS)
Three Months Twelve Months
--------------- ---------------
1994 1993 1994 1993
------ ------ ------ -------
Cash Flows from Operating Activities:
Net Income $ 1.8 $ 26.3 $ 38.7 $ 61.7
Adjustments to Reconcile Net Income to Net
Cash Flow from Operating Activities:
Restructuring Costs 44.5 44.5
Depreciation and Amortization 15.7 15.0 59.9 61.7
Deferred Income Taxes (13.1) 3.1 (2.6) 21.4
Non-Cash Compensation Expense 2.4 2.1 8.5 8.2
Other (0.9) (0.4) (2.4) (2.2)
------ ------ ------ -------
50.4 46.1 146.6 150.8
Changes in Certain Assets and
Liabilities (65.9) (112.4) 37.0 (105.2)
------ ------- ------- ------
Net Cash Flow from Operating
Activities (15.5) (66.3) 183.6 45.6
------- ------- ------- ------
Cash Flows from Financing Activities:
Short-Term Borrowings, Net 53.2 98.1 (80.9) 94.0
Redemptions, Purchase Fund and
Sinking Fund Requirements of Preferred
Stock and Long-Term Debt (125.7) (178.0)
Sale of Common Stock, Net of Expenses 0.5 0.7 2.2 2.7
Sale of Long-Term Debt 134.8 59.7 207.3
Sale of Preferred Stock, Net of Expenses
Dividends (11.9) (11.8) (47.5) (47.0)
-------- ------- ------- ------
Net Cash Flow from Financing
Activities 41.8 96.1 (66.5) 79.0
-------- ------- ------- ------
Cash Flows from Investing Activities:
Utility Plant Expenditures (25.7) (28.5) (119.3) (121.1)
Non-Utility Capital Expenditures (0.9) (1.0) (0.6)
Cost of Property Removal, Net of Salvage1.2 (0.3) 3.1 (1.5)
------- ------- ------- ------
Net Cash Flow from Investing
Activities (25.4) (28.8) (117.2) (123.2)
------- ------- ------- ------
Net Increase (Decrease) in Cash
and Cash Equivalents 0.9 1.0 (0.1) 1.4
Cash and Cash Equivalents
at Beginning of Period 3.3 3.3 4.3 2.9
------- ------- ------- ------
Cash and Cash Equivalents
at End of Period $ 4.2 $ 4.3 $ 4.2 $ 4.3
======= ======= ======= ======
Cash Paid during the Period for:
Interest $ 20.8 $ 18.5 $ 53.4 $ 44.7
Income Taxes $ 8.3 $ 0.0 $ 26.3 $ 16.9
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 1993 amounts
have been restated or reclassified for comparability with 1994 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 a three-month period are not indicative of the
earnings for a twelve-month period.
3. AGL has identified eight 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, Macon, Rome, Savannah, Valdosta and Waycross.
In addition, AGL has identified four 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), Macon
and Griffin. 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 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/SI's for each site. 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 at Augusta, Savannah and Athens to be completed in 1995.
On March 22, 1994 AGL submitted to the EPD, under newly enacted
regulations issued by EPD under the Georgia Hazardous Site Response Act
(HSRA), formal notifications pertaining to MGP site conditions at seven
of the owned MGP sites: Athens, Augusta, Brunswick, Macon, Savannah,
Valdosta and Waycross. 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 on Georgia's
"Hazardous Site Inventory." EPD has also listed the Rome MGP site with
which AGL has been associated and which is the subject of pending
litigation. EPD will determine whether corrective action is required at
any or all of these sites.
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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 each 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 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 and purchase
natural gas directly from interstate pipelines or municipal gas
authorities.
Certain interruptible customers have indicated they may seek to bypass
AGL. The Company estimates that operating margin from AGL's
interruptible customers could be reduced by as much as approximately $26
million per year, depending upon the ultimate number of customers that
seek and are granted bypass. If any interruptible customers seek and are
granted authority to bypass AGL, AGL intends to recover those lost
revenues through the Interruptible Transportation and Sales
Maintenance (ITSM) Rider. The authority to recover revenues lost as a
result of bypass through this tariff mechanism has been challenged
recently in proceedings before the Georgia Commission. AGL believes
such authority is provided in its current tariff. However, management
is unable to predict the outcome of the proceedings pending before the
Georgia Commission.
On October 19, 1994, the Georgia Commission issued a scheduling order
for an investigation of AGL Bypass and Other Issues. The proceeding is
designed to provide information to the Georgia Commission regarding
alternatives to respond to bypass and to assess the economics of
bypass. Hearings were conducted during the months of November and
December 1994. The matter is pending before the Georgia Commission.
To further address competition and the threat of bypass, AGL will
negotiate special contracts with customers on an individual basis,
subject to Georgia Commission approval. On September 28, 1994, AGL and
DSM Chemicals of North America, Inc. (DSM) filed a contract with the
Georgia Commission designed to avoid bypass by DSM. On November 15,
1994, the Georgia Commission approved the special contract. Under the
terms of the contract, the Company may offset the discount with certain
gas supply benefits. As a result, the Company expects no operating margin
loss under the lower contract rates.
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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 (Tennessee
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 organization.
Restructuring will include combining offices and creating centralized
call centers and a network of locations where customers can pay their
bills throughout the Company's service area. The plan should ultimately
reduce the number of employees of the Company by approximately 600,
which will be accomplished by attrition, early retirement and other
severance programs. Portions of the plan have been implemented, with
the remainder to be implemented over the next one to two years.
During the quarter ended December 31, 1994, 354 eligible employees
accepted the Company's Special Voluntary Retirement Plan (SVRP) offer.
In accordance with current accounting standards, the Company recorded
restructuring costs of $44.5 million or $28.4 million after income taxes.
In addition, 85 eligible employees accepted the SVRP after December 31,
1994 but prior to the January 3, 1995 deadline. Additional restructuring
costs of $10.0 million or $6.4 million after income taxes related to
those 85 employees will be recorded during the quarter ending March 31,
1995 along with certain other restructuring costs.
As a result of the restructuring, the Company expects significant
reductions in future annual operating expenses. Such reductions should
enable the Company to be more competitive in its markets in the future.
The Company estimates total costs of the restructuring plan, including
the SVRP, will be in a range of $58 to $61 million or $37 to $39 million
after income taxes. The Company expects to offset those costs in the
following two to 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-Months Ended December 31, 1994 Compared With 1993
Explained below are the major factors that had a significant effect
on results of operations for the three-month period ended December 31,
1994, compared with the same period for 1993.
Operating revenues decreased 9.2% for the three-month period ended
December 31, 1994, compared with 1993 due primarily 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 as a result
of weather that was 32% warmer than the same period in 1993. The decrease
in operating revenues was partly offset by (1) increased consumption by
firm service customers and (2) growth in the number of customers served.
Cost of gas decreased 18.1% for the three-month period ended
December 31, 1994, compared with 1993 due primarily 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 as a
result of weather that was 32% warmer than the same period in 1993. The
Company balances the cost of gas with revenues collected under the
purchased gas provisions of the Company's rate schedules. Under or over
recoveries of gas costs are deferred and recorded as current assets or
liabilities, thereby eliminating the effect that recovery of gas costs
would otherwise have on net income.
Operating margin increased 6.4% for the three-month period ended
December 31, 1994, compared with 1993. The increase in operating margin
was due primarily to (1) increased consumption by firm service customers
and (2) growth in the number of customers served.
Operating expenses increased 1.2% for the three-month period ended
December 31, 1994, compared with 1993 due primarily to increased
depreciation expense as a result of increased property subject to
depreciation. Total other operating expenses increased due primarily to
(1) restructuring costs of $44.5 million (see Note 7 to Condensed
Consolidated Financial Statements in this Form 10-Q) and (2) increased
depreciation expense.
Interest charges increased 6.5% for the three-month period ended
December 31, 1994, compared with 1993. The increase was due primarily to
increased interest rates on short-term debt.
Income taxes decreased $13.5 million for the three-month period
ended December 31, 1994, compared with 1993 due primarily to decreased
taxable income.
Net income for the three-month period ended December 31, 1994, was
$1.8 million, compared with net income of $26.3 million in 1993. Earnings
per share of common stock were $.03 for the three-month period ended
December 31, 1994, compared with earnings per share of $1.01 in 1993. The
decreases in net income and earnings per share were due to
restructuring costs of
$44.5 million (see Note 7 to Condensed Consolidated Financial Statements in
this Form 10-Q). The decrease in net income and earnings per share were
partly offset by increased operating margin resulting from (1) increased
consumption by firm service customers and (2) growth in the number of
customers served.
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Twelve-Months Ended December 31, 1994 Compared With 1993
Explained below are the major factors that had a significant effect
on results of operations for the twelve-month period ended December 31,
1994, compared with the same period for 1993.
Operating revenues increased 0.8% for the twelve-month period ended
December 31, 1994, compared with the same period for 1993 due primarily to
(1) increased consumption by firm service customers, (2) growth in the
number of customers served, (3) a change in the mix of volumes of gas sold
and transported to interruptible customers and (4) rate increases granted
by the Georgia Commission effective October 1, 1993 and the Tennessee
Commission effective February 1, 1994. The increase in operating revenues
was partly offset by (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 as a result of weather that
was 21% warmer than the same period in 1993. Although margins are not
affected, operating revenues are greater when gas is sold to customers than
when gas is transported for customers.
Cost of gas decreased 3.2% for the twelve-month period ended
December 31, 1994, compared with the same period for 1993 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 as a result of weather that was 21% warmer than the same period in
1993. 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 7.3% for the twelve-month period ended
December 31, 1994, compared with 1993. The increase in operating margin
was due primarily to (1) increased consumption by firm service customers
and (2) growth in the number of customers served.
Operating expenses increased 5.6% for the twelve-month period ended
December 31, 1994, compared with the same period for 1993 due primarily to
(1) increased postretirement benefits other than pensions, (see Note 5 to
Condensed Consolidated Financial Statements), (2) increased outside
services employed and (3) increased costs for labor.
Total other operating expenses increased due primarily to (1)
restructuring costs of $44.5 million (see Note 7 to Condensed Consolidated
Financial Statements in this Form 10-Q), (2) increased postretirement
benefits other than pensions, (3) increased outside services employed and
(4) increased costs for labor.
Other income for the twelve-month period ended December 31, 1994,
decreased $1.6 million from 1993 due primarily to a decrease in interest
income associated with income tax refunds related to prior years.
Interest charges increased 2.1% for the twelve-month period ended
December 31, 1994, compared with 1993. The increase was due primarily to
increased (1) interest rates on short-term debt and (2) amounts of
short-term debt outstanding.
Income taxes decreased $10.7 million for the twelve-month period
ended December 31, 1994, compared with 1993 due primarily to decreased
taxable income.
Net income for the twelve months ended December 31, 1994, was $38.7
million, compared with net income of $61.7 million in 1993. Earnings per
share of common stock were $1.35 for the twelve months ended December 31,
1994, compared with $2.32 in 1993. The decreases in net income and
<PAGE>
earnings per share were due to
restructuring costs of $44.5 million (see Note 7 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 (1) increased consumption by firm service customers and (2)
growth in the number of customers served.
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 December 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 $108.2 million and inventory of gas stored underground
and liquefied natural gas decreased $40.9 million during the three months
ended December 31, 1994. Accounts receivable decreased $43.5 million from
December 31, 1993 to December 31, 1994 due primarily to decreased operating
revenues as a result of weather that was 32% warmer during the three months
ended December 31, 1994 compared with 1993. Accounts payable decreased
$29.7 million from December 31, 1993 to December 31, 1994 due primarily to
a $21.4 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 $107 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 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 "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 $5.2 million at December 31, 1993, and
$33.3 million at December 31, 1994 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.
The expenditures for plant and other property totaled $26.6 million
and $120.3 million for the three-month and twelve-month periods ended
December 31, 1994, respectively.
The Company had accrued liabilities of $24.1 million at December
31, 1994 compared with $19.1 million at December 31, 1993 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 Condensed
Consolidated Financial Statements, commencing October 1, 1992,
<PAGE>
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 Part II,
Item 5 of this Form 10-Q.
Certain interruptible customers have indicated they may seek to
bypass AGL. The Company estimates that operating margin from AGL's
interruptible customers could be reduced by as much as approximately $26
million per year, depending upon the ultimate number of customers that seek
and are granted bypass. If any additional customers seek and are granted
authority to bypass AGL, AGL intends to recover those lost revenues through
the Interruptible Transportation and Sales Maintenance (ITSM) Rider. The
authority to recover revenues lost as a result of bypass through this
tariff mechanism has been challenged recently in proceedings before the
Georgia Commission. AGL believes such authority is provided in its
current tariff. However, management is unable to predict the outcome of
the proceedings pending before the Georgia Commission.
As of December 31, 1994, the Company had issued $194.5 million
principal amount of Medium- Term Notes Series C, with maturity dates
ranging from 10 to 30 years and with interest rates ranging from 5.9% to
7.2%. The notes are issued under an Indenture dated as of December 1,
1989, as supplemented and modified, and are unsecured and rank on a parity
with all other unsecured indebtedness of the Company. Net proceeds from the
notes were used to repay short-term debt, to refund the remaining $125
million principal balance of the Company's only outstanding series of First
Mortgage Bonds and for other corporate purposes. As a result, long-term
debt outstanding increased $44.7 million from December 31, 1993 to December
31, 1994.
Short-term debt outstanding increased $53.2 million from September
30, 1994 to December 31, 1994 primarily to meet increased working capital
requirements. Short-term debt outstanding decreased $80.9 million from
December 31, 1993 to December 31, 1994 due primarily to net cash flow from
operating activities and the repayment of short-term debt from the proceeds
of the issuance of Medium-Term Notes, Series C.
Accrued postretirement benefits costs increased $20.7 million from
December 31, 1993 to December 31, 1994 and $19.4 million from September 30,
1994 to December 31, 1994. The increase was due primarily to restructuring
costs resulting from the Company's Special Voluntary Retirement Plan (SVRP)
in the quarter ended December 31, 1994 (see Note 7 to Condensed
Consolidated Financial Statements in this Form 10-Q).
Accrued pension costs increased $20.2 million for the three-and
twelve-month periods ended December 31, 1994. The increase was due
primarily to restructuring costs resulting from the Company's SVRP in the
quarter ended December 31, 1994 (see Note 7 to Condensed Consolidated
Financial Statements in this Form 10-Q).
<PAGE>
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 5. Other Information
Federal Regulatory Matters
Order 636
The Company currently estimates that its portion of transition
costs from all of its pipeline suppliers that have been filed with the
Federal Energy Regulatory Commission (FERC) to date to be recovered (which
include unrecovered gas costs, gas supply realignment (GSR) costs and
various stranded costs resulting from unbundling of interstate pipeline
sales service), could be as high as approximately $107 million. The
Company's estimate is based on the most recent estimates of transition
costs filed by its pipeline suppliers with the FERC. Such filings by the
Company's pipeline suppliers are pending final 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 current status of various Order 636 restructuring
proceedings involving the pipelines that serve the Company directly are set
forth below.
SOUTHERN GSR Cost Recovery Proceeding. Southern Natural Gas Company
(Southern) made several quarterly GSR cost recovery filings with the FERC
during the fiscal year ended September 30, 1994. In addition, Southern has
filed on a monthly basis since the implementation of Order 636 to revise
its GSR billing determinants. On November 30, 1994, Southern filed with
the FERC to recover an additional $16.6 million in GSR costs of which the
Company's liability is estimated at $3.8 million. On December 30, 1994, the
FERC rejected certain costs contained in Southern's November 30, 1994 filing
which are associated with Southern's Mississippi Canyon gas supply
facilities, but otherwise accepted Southern's filing and consolidated it
with Southern's other GSR recovery filings for hearing purposes.
The Company has challenged Southern's methodology for allocating
GSR costs to the Company, and is actively challenging the eligibility and
prudence of the GSR costs Southern has sought to recover. The Company's
estimated liability for GSR costs as a result of Southern's filings is
approximately $72.8 million, subject to possible reduction based upon the
hearing FERC established to investigate Southern's costs. The Company's
estimated liability also is subject to change based upon possible revisions
to Southern's allocation methodology and cost recovery mechanism.
However, the Company has reached an agreement in principle with Southern
that if implemented would resolve the
pending rate and restructuring proceedings and all transition
costs involving Southern. The agreement, if approved, will result in an
annual decrease in rates to the Company's customers of approximately $35
million. In addition, it would reduce the Company's overall liability for
GSR costs by approximately $30 million. The total estimated GSR liability
owed to Southern under the agreement will be satisfied essentially with
previously collected GSR costs and refunds that otherwise would have been
due the Company. The agreement is subject to the negotiation of definitive
documents and FERC approval.
<PAGE>
TENNESSEE GSR Cost Recovery Proceeding. Tennessee Gas Pipeline
Company (Tennessee) made several quarterly GSR cost recovery filings with
the FERC during the fiscal year ended September 30, 1994. On December 15,
1994, Tennessee filed with the FERC to recover an additional $21.5 million
in GSR costs. The Company's estimated liability for GSR costs as a result
of Tennessee's filings is approximately $7.0 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.
Other Cost Recovery Proceedings. On November 30, 1994, Tennessee
filed with FERC to recover $21.2 million in annual stranded upstream
transportation costs. The Company protested Tennessee's additional cost filing
on the ground that Tennessee had not removed certain merchant-related
costs associated with stranded upstream transportation arrangements as directed
by FERC. The Company's estimated liability for these costs is $0.5 million.
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 commenced on January 10, 1995. An agreement in principle
has been reached with Southern which, if approved, would include the
resolution of this rate proceeding. (See "Federal Regulatory Matters - Order
636 - Southern.")
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. The FERC has not yet acted upon Tennessee's
filing.
TRANSCO On December 23, 1994, the United States Court of Appeals for the
District of Columbia Circuit issued an order remanding to the FERC its rulings
regarding the rate of return on equity of Transcontinental Gas Pipe Line
Corporation (Transco) in its pending rate proceeding. This issue had been
carved out by the FERC for expedited resolution. A group of intervenors
challenged the rate of return set by the FERC on the grounds that FERC
inappropriately employed a hypothetical capital structure and set
the rate of return too high.
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
Economic Development Policy
On September 19, 1993, the Georgia Public Service Commission
(Georgia Commission) initiated an
investigation of Economic Development Incentive Policies of the utilities
under its jurisdiction. On November 3, 1994, the Georgia Commission issued
a final order establishing guidelines for utility economic development
incentives which are designed to provide incentives to industrial customers
to locate or expand facilities in Georgia. On December 19, 1994,
AGL filed its proposed economic development incentive
program in compliance with the Georgia Commission's order. As filed, the
AGL Economic Development Policy is designed to promote economic development
within the context of its
<PAGE>
approved Integrated Resource Plan (IRP) by providing cost-effective job
creation incentive payments and investment incentive payments to industrial
customers where such payments provide positive benefits both to AGL and its
new and existing industrial customers. The proposal is pending before the
Georgia Commission.
Integrated Resource Plan
The IRP, which was approved by the Georgia Commission on August 11,
1993, consists of eight Demand Side Management (DSM) programs that are
designed to provide the Company's residential, commercial, and industrial
customers with incentives to use natural gas in a more efficient manner.
The programs were implemented by the Company between October 1993 and
November 1994 and currently are available to AGL's customers. The eight DSM
programs are the Menu of Services Program, the Energy Wise New Home
Program, the Energy Wise Existing Home Program, the Energy Wise Equipment
Enhancement Program, the Energy Wise Natural Gas Vehicle Program, the
Energy Wise Special Needs Program, the Energy Wise Gas Heat Pump Program
and the Energy Wise Customized Commercial and Industrial Program.
Bypass and Other Issues
On October 19, 1994, the Georgia Commission issued a scheduling
order for an Investigation of AGL Bypass and Other Issues. The proceeding
is designed to provide information to the Georgia Commission regarding
alternatives to respond to bypass and to assess the economics of bypass.
Hearings were conducted during the months of November and December 1994.
The matter is pending before the Georgia Commission.
The Company has begun to address competition in interruptible energy
markets through special contracts. On September 28, 1994, AGL and DSM
Chemicals North America, Inc. (DSM) filed a contract with the Georgia
Commission designed to avoid bypass by DSM. On November 15, 1994, the
Georgia Commission approved the special contract. Under the terms of the
contract, the Company may offset the discount with certain gas supply
benefits. As a result, the Company expects no operating margin loss
under the lower contract rates.
The Company cannot predict the outcome of pending state proceedings
nor can it determine the ultimate effect, if any, such proceedings may have
on the Company.
Environmental Matters
In June 1990, the Company was contacted by attorneys for Florida
Public Utilities Company (FPUC) in connection with a former manufactured
gas plant (MGP) site in Sanford, Florida. Thereafter, FPUC received a
"Warning Notice" from the Florida Department of Environmental Regulation
(FDER) demanding that FPUC enter into a consent order to investigate the
Sanford site. Preliminary investigation results indicate some
environmental impacts at this site. In addition, limited investigations of
the surrounding area indicate potential environmental impacts off-site. On
January 31, 1992, FPUC filed suit against the Company, two other
corporations, and the City of Sanford, under the federal Comprehensive
Environmental Response Compensation and Liability Act, and an equivalent
state statute, alleging the Company is a former "owner," to obtain
contribution from the company and others for all costs incurred and for a
declaratory judgment that all defendants are jointly and severally liable
for future response costs. On May 15, 1992, the Court administratively
terminated the case for one year while the parties, pursuant to an
agreement, attempt to determine the nature and extent of impacts at the
Sanford MGP site. By letter dated September 11, 1992, FPUC responded to
the "Warning Notice" issued by FDER and proposed to conduct a joint
investigation of the site under FDER
<PAGE>
supervision, without the entry of any formal order. By letter dated
September 23, 1992, FDER rejected this proposal. Pursuant to an agreement
among the parties to fund the conduct of further studies, an administrative
termination of the case was reinstituted and will expire on December 31,
1994. On February 3, 1994, the parties submitted a 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.
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 eight sites in Georgia where it currently owns
all or part of an MGP site. These sites are located in Athens, Augusta,
Brunswick, Macon, Rome, Savannah, Valdosta and Waycross. In addition, AGL
has identified four 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), Macon and Griffin.
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 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/SI's for each site. 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 newly enacted
regulations issued by EPD under the Georgia Hazardous Site Response Act
(HSRA), formal notifications pertaining to MGP site conditions at seven of
the owned MGP sites: Athens, Augusta, Brunswick, Macon, Savannah, Valdosta
and Waycross. 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 on Georgia's "Hazardous Site
Inventory." EPD has also listed the Rome MGP site with which AGL has been
associated and which is the subject of pending litigation. EPD will
determine whether corrective action is required at any or all of these
sites.
As of December 31, 1994, the Company had expended approximately
$14.7 million for Environmental Response Costs. Under potentially
applicable requirements, the total environmental response costs, including
estimated costs of the cleanup of the MGP sites, could be as high as
approximately $214 million or as low as approximately $39 million.
However, HSRA may change the basis on which this range
is calculated. At the present time no amount within this range can be
identified as a better estimate than any other estimate. Therefore, the
minimum expected liability
<PAGE>
less amounts paid and a corresponding regulatory asset have been recorded
in the financial statements. The Company is not able to quantify the
effects of HSRA at this time.
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
Condensed Consolidated Financial Statements.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Item 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 February 13, 1995 /s/ David R. Jones
--------------------- ----------------------------
David R. Jones
President and
Chief Executive Officer
(Principal Executive Officer)
Date February 13, 1995 /s/ Robert L. Goocher
---------------------- ----------------------------
Robert L. Goocher
Executive Vice President
(Principal Financial Officer)
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