SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 1997
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification Number
1-9905 ATLANTA GAS LIGHT COMPANY 58-0145925
(A Georgia Corporation)
303 PEACHTREE STREET, NE
ATLANTA, GEORGIA 30308
404-584-4000
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months and (2) has been subject to such filing requirements for
the past 90 days. Yes x No
Indicate the number of shares outstanding of each of the issuer's classes of
common stock.
As of June 30, 1997, 55,352,415 shares of Common Stock, $5.00 Par Value, were
outstanding, all of which are owned by AGL Resources Inc.
<PAGE>
ATLANTA GAS LIGHT COMPANY
Quarterly Report on Form 10-Q
For the Quarter Ended June 30, 1997
Table of Contents
Item Page
Number Number
PART I -- FINANCIAL INFORMATION
1 Financial Statements
Condensed Consolidated Income Statements 3
Condensed Consolidated Balance Sheets 4
Condensed Consolidated Statements of Cash Flows 6
Notes to Condensed Consolidated Financial Statements 7
2 Management's Discussion and Analysis of Results of
Operations and Financial Condition 12
PART II -- OTHER INFORMATION
1 Legal Proceedings 19
5 Other Information 19
6 Exhibits and Reports on Form 8-K 24
SIGNATURES 25
Page 2 of 25 Pages
<PAGE>
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED INCOME STATEMENTS (UNAUDITED)
FOR THE THREE MONTHS, NINE MONTHS AND TWELVE MONTHS ENDED
JUNE 30, 1997 AND 1996
(MILLIONS)
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
-----------------------------------------------------------------
1997 1996 1997 1996 1997 1996
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues ................ $ 206.4 $ 240.5 $ 1,041.8 $ 1,048.1 $ 1,211.3 $ 1,156.6
Cost of Gas ....................... 109.0 140.6 622.2 637.4 703.5 666.4
- --------------------------------------------------------------------------------------------------------
Operating Margin .................. 97.4 99.9 419.6 410.7 507.8 490.2
- --------------------------------------------------------------------------------------------------------
Other Operating Expenses .......... 84.8 81.2 259.1 253.2 339.4 335.1
Income Taxes ...................... 0.4 2.2 45.2 44.5 44.2 40.4
- --------------------------------------------------------------------------------------------------------
Operating Income .................. 12.2 16.5 115.3 113.0 124.2 114.7
- --------------------------------------------------------------------------------------------------------
Other Income
Other income and deductions . 2.2 0.6 6.9 8.9 10.6 8.3
Income taxes ................ (0.9) (0.4) (2.6) (3.4) (4.0) (3.2)
- --------------------------------------------------------------------------------------------------------
Total other income-net .. 1.3 0.2 4.3 5.5 6.6 5.1
- --------------------------------------------------------------------------------------------------------
Income Before Interest Charges .... 13.5 16.7 119.6 118.5 130.8 119.8
Interest Charges .................. 12.4 11.7 39.8 36.9 52.0 47.9
- --------------------------------------------------------------------------------------------------------
Net Income ........................ 1.1 5.0 79.8 81.6 78.8 71.9
- --------------------------------------------------------------------------------------------------------
Dividends on Preferred Stock ...... 1.1 1.1 3.3 3.3 4.4 4.4
- --------------------------------------------------------------------------------------------------------
Earnings Available for Common Stock $ 0.0 $ 3.9 $ 76.5 $ 78.3 $ 74.4 $ 67.5
========================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
Page 3 of 25 Pages
<PAGE>
ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS)
<TABLE>
<CAPTION>
September
June 30, 30,
---------------------- ---------
1997 1996 1996
ASSETS (Unaudited)
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Utility Plant ....................................... $ 2,041.5 $ 1,999.2 $ 1,969.0
Less accumulated depreciation ................. 638.7 619.3 607.8
- ----------------------------------------------------------------------------------------
Utility plant-net ......................... 1,402.8 1,379.9 1,361.2
- ----------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents ..................... 0.8 1.3 7.9
Receivables (less allowance for uncollectible
accounts of $4.7 at June 30, 1997, $3.1
at June 30, 1996, and $2.7 at September
30, 1996) ................................. 112.7 130.1 91.3
Inventories
Natural gas stored underground ............ 95.4 72.7 144.0
Liquefied natural gas ..................... 15.1 9.7 16.8
Materials and supplies .................... 7.4 8.1 7.9
Other ..................................... 0.3 0.1
Deferred purchased gas adjustment ............. 9.0 4.7
Other ......................................... 7.3 10.1 10.3
- ----------------------------------------------------------------------------------------
Total current assets ...................... 247.7 232.3 283.0
- ----------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental response costs ...... 44.4 36.0 38.0
Unrecovered integrated resource plan costs .... 4.5 9.5 10.0
Receivable from AGL Resources - prepaid pension 3.1
Other ......................................... 36.5 34.4 36.0
- ----------------------------------------------------------------------------------------
Total deferred debits and other assets .... 88.5 79.9 84.0
- ----------------------------------------------------------------------------------------
Total Assets ........................................ $ 1,739.0 $ 1,692.1 $ 1,728.2
========================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
Page 4 of 25 Pages
<PAGE>
ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(MILLIONS, EXCEPT PAR VALUE DATA)
<TABLE>
<CAPTION>
September
June 30, 30,
--------------------- ---------
1997 1996 1996
CAPITALIZATION AND LIABILITIES (Unaudited)
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Capitalization
Common stock, $5 par value, shares issued and
outstanding of 55.4 at June 30, 1997, June 30, 1996,
and September 30, 1996 ............................. $ 276.8 $ 276.8 $ 276.8
Premium on capital stock ............................... 166.2 166.2 166.2
Earnings reinvested .................................... 86.0 110.9 59.7
- -------------------------------------------------------------------------------------------------
Total common stock equity .......................... 529.0 553.9 502.7
- -------------------------------------------------------------------------------------------------
Preferred stock, cumulative $100 par or stated value,
shares issued and outstanding of 0.6 at June 30,
1997, June 30, 1996, and September 30, 1996 ........ 44.5 58.5 58.5
Long-term debt ......................................... 584.5 554.5 554.5
- -------------------------------------------------------------------------------------------------
Total capitalization ............................... 1,158.0 1,166.9 1,115.7
- -------------------------------------------------------------------------------------------------
Current Liabilities
Redemption requirements on preferred stock ............. 14.3 0.3 0.3
Short-term debt ........................................ 33.5 71.9 152.0
Accounts payable-trade ................................. 60.9 68.5 72.7
Payable to associated companies ........................ 57.2 1.9 2.7
Deferred purchased gas adjustment ...................... 3.4
Customer deposits ...................................... 29.1 27.8 27.8
Interest ............................................... 18.9 17.6 25.7
Taxes .................................................. 32.1 25.8 16.0
Other .................................................. 26.1 27.6 26.6
- -------------------------------------------------------------------------------------------------
Total current liabilities .......................... 272.1 244.8 323.8
- -------------------------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs ................... 31.3 28.6 30.4
Payable to AGL Resources - accrued pension costs ....... 4.9 4.9
Payable to AGL Resources - accrued postretirement
benefits costs ..................................... 36.7 34.7 36.2
Deferred credits ....................................... 60.4 62.6 60.9
- -------------------------------------------------------------------------------------------------
Total long-term liabilities ........................ 128.4 130.8 132.4
- -------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes ............................ 180.5 149.6 156.3
- -------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities ......................... $ 1,739.0 $ 1,692.1 $ 1,728.2
=================================================================================================
</TABLE>
See notes to condensed consolidated financial statements.
Page 5 of 25 Pages
<PAGE>
ATLANTA GAS LIGHT COMPANY AND SUBISIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
FOR THE NINE MONTHS AND TWELVE MONTHS ENDED JUNE 30, 1997 AND 1996
(MILLIONS)
<TABLE>
<CAPTION>
Nine Months Twelve Months
------------------ ------------------
1997 1996 1997 1996
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Cash Flows from Operating Activities
Net income .................................. $ 79.8 $ 81.6 $ 78.8 $ 71.9
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization ........... 48.1 49.3 64.2 64.5
Deferred income taxes ................... 10.2 10.8 24.5 19.3
Noncash compensation expense ............ 2.1 2.4
Noncash restructuring costs ............. 1.0
Other ................................... (1.8) (1.7) (2.5) (2.2)
Changes in certain assets and liabilities ... 88.8 (33.1) 43.4 (92.0)
- --------------------------------------------------------------------------------------------
Net cash flow from operating activities 225.1 109.0 208.4 64.9
- --------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses ....... 1.0 1.3
Short-term borrowings, net .................. (118.5) 20.9 (38.4) 71.9
Sale of long-term debt ...................... 30.0 30.0
Common stock dividends paid to parent ....... (45.3) (39.1) (60.0) (50.9)
Preferred stock dividends ................... (3.3) (3.3) (4.4) (4.4)
- --------------------------------------------------------------------------------------------
Net cash flow from financing activities (137.1) (20.5) (72.8) 17.9
- --------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures .................. (94.5) (91.3) (135.3) (129.4)
Investment in joint venture ................. (32.6)
Nonutility capital expenditures ............. 1.1 1.6
Cost of removal, net of salvage ............. (0.6) (0.7) (0.8) 0.5
- --------------------------------------------------------------------------------------------
Net cash flow from investing activities (95.1) (90.9) (136.1) (159.9)
- --------------------------------------------------------------------------------------------
Net decrease in cash and cash
equivalents ......................... (7.1) (2.4) (0.5) (77.1)
Cash and cash equivalents at
beginning of year ................... 7.9 3.7 1.3 78.4
- --------------------------------------------------------------------------------------------
Cash and cash equivalents at
end of year ......................... $ 0.8 $ 1.3 $ 0.8 $ 1.3
============================================================================================
Supplemental Information
Cash paid during the period for
Interest ................................ $ 46.9 $ 44.9 $ 51.2 $ 49.0
Income taxes ............................ $ 19.1 $ 13.3 $ 23.7 $ 18.2
</TABLE>
See notes to condensed consolidated financial statements.
Page 6 of 25 Pages
<PAGE>
ATLANTA GAS LIGHT COMPANY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Implementation of Holding Company Reorganization
On March 6, 1996, following shareholder approval, Atlanta Gas Light
Company (AGLC) completed a corporate restructuring in which a new company,
AGL Resources Inc. (AGL Resources), became the holding company for AGLC,
AGLC's wholly owned natural gas utility subsidiary, Chattanooga Gas Company
(Chattanooga), and AGLC's nonregulated subsidiaries. The consolidated
financial statements of AGLC include the financial statements of AGLC and
Chattanooga and unless noted specifically or otherwise required by the
context, references to AGLC include the operations and activities of AGLC
and Chattanooga.
During fiscal 1996 ownership of AGLC's nonregulated business, Georgia
Gas Company (natural gas production activities), was transferred to AGL
Energy Services, Inc. (AGL Energy Services). Ownership of AGLC's other
nonregulated businesses, Georgia Gas Service Company (propane sales) and
Trustees Investments, Inc. (real estate holdings), was transferred to AGL
Investments, Inc. (AGL Investments). AGLC's interest in Sonat Marketing
Company L.P. was transferred to AGL Gas Marketing, Inc., a wholly owned
subsidiary of AGL Investments. The transfer of AGLC's nonregulated
businesses to those subsidiaries of AGL Resources was effected through a
noncash dividend of $45.9 million during fiscal 1996.
AGL Resources Service Company (Service Company) was formed during
fiscal 1996 to provide corporate support services to AGLC, AGL Resources
and its other subsidiaries. The transfer of related assets and accumulated
deferred income tax liabilities from AGLC to Service Company and other
nonregulated subsidiaries of AGL Resources was effected through noncash
dividends of $34.3 million during the fourth quarter of fiscal 1996 and
$4.8 million during the first quarter of fiscal 1997. As a result of those
noncash dividends, utility plant-net decreased by $48.4 million and
accumulated deferred income tax decreased by $9.3 million. Expenses of
Service Company are allocated to AGLC, AGL Resources and its other
subsidiaries.
2. Interim Financial Statements
In the opinion of management, the unaudited condensed consolidated
financial statements included herein reflect all normal recurring accruals
necessary for a fair statement of the results of the interim periods
reflected. Certain information and footnote disclosure normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been omitted from these condensed consolidated
financial statements pursuant to applicable rules and regulations of the
Securities and Exchange Commission. These financial statements should be
read in conjunction with the financial statements and the notes thereto
included in the annual reports on Form 10-K of AGLC for the fiscal years
ended September 30, 1996 and 1995. Certain 1996 amounts have been
reclassified for comparability with 1997 amounts.
3. Earnings
Since consumption of natural gas is dependent to a large extent on
weather, the majority of AGLC's income is realized during the winter
months. Earnings for three-month and nine-month periods are not indicative
of the earnings for a twelve-month period.
On October 3, 1995, AGLC implemented revised firm service rates
pursuant to an order on rehearing of the rate design issues of AGLC's 1993
rate case that was issued by the Georgia Public Service Commission
Page 7 of 25 Pages
<PAGE>
(Georgia Commission) on September 25, 1995. Although neutral with respect
to total annual margins, the new rates shift margins from heating months
(November - March) into non-heating months, thereby affecting the
comparisons of earnings for the twelve-month periods ended June 30, 1997
and 1996.
4. Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all
or part of a manufactured gas plant (MGP) site. In addition, AGLC has
identified three other sites in Georgia which AGLC does not now own, but
which may have been associated with the operation of MGPs by AGLC or its
predecessors. There are also three sites in Florida which have been
investigated by environmental authorities in connection with which AGLC may
be contacted as a potentially responsible party. In that regard, AGLC has
learned that the U. S. Environmental Protection Agency (EPA) has conducted
an Expanded Site Investigation at the former MGP site in Sanford, Florida
and has concluded that MGP impacts are present in a nearby lake. The
consequences of this finding have not been determined.
AGLC's response to MGP sites in Georgia is proceeding under two state
regulatory programs. First, AGLC has entered into consent orders with the
Georgia Environmental Protection Division (EPD) with respect to four sites:
Augusta, Griffin, Savannah and Valdosta. Under these consent orders, AGLC
is obligated to investigate and, if necessary, remediate environmental
impacts at the sites. AGLC has completed soil remediation at the Griffin
site and expects to monitor groundwater for three to six years. Assessment
activities are being conducted at Augusta and have been completed at
Savannah. Those assessment activities are expected to be completed
principally during fiscal 1997. In addition, AGLC has completed removal of
the gas storage holder at the Augusta site.
Second, AGLC's response to all Georgia sites is proceeding under
Georgia's Hazardous Site Response Act (HSRA). AGLC submitted to EPD formal
notifications relating to all of its nine owned MGP sites, and EPD had
listed seven of those sites (Athens, Augusta, Brunswick, Griffin, Savannah,
Valdosta and Waycross) on the Hazardous Site Inventory (HSI). EPD has not
listed the Macon site on the HSI at this time. EPD also has listed the Rome
site, which AGLC has acquired, on the HSI. Under the HSRA regulations, EPD
has determined the four sites subject to consent orders require corrective
action; EPD also has determined the Athens site requires corrective action
and will determine whether corrective action is required at the three
remaining sites (Brunswick, Rome and Waycross) in due course. In that
respect, however, AGLC has submitted to EPD Compliance Status Reports
(CSRs) for the Brunswick and Rome MGP sites, and AGLC has concluded that
some degree of response action is likely to be required at those sites.
AGLC has estimated that, under the most favorable circumstances
reasonably possible, the future cost to AGLC of investigating and
remediating the former MGP sites could be as low as $31.3 million.
Alternatively, AGLC has estimated that, under reasonably possible
unfavorable circumstances, the future cost to AGLC of investigating and
remediating the former MGP sites could be as high as $117.3 million. Those
estimates have been adjusted from the September 30, 1996 estimates to
reflect settlements of property damage claims at certain sites. AGLC cannot
at this time determine the range of costs that may be associated with
investigation and cleanup of the lake near the Sanford MGP site, which
costs may be material. Accordingly, the foregoing estimated range now
excludes those costs and reflects only AGLC's current estimate of the range
of costs for which cost recovery claims against AGLC are reasonably likely.
In addition, those costs do not include other expenses, such as property
damage claims and natural resource damage claims, for which AGLC may
ultimately be held liable, but for which neither the existence nor the
amount of such liabilities can be reasonably forecast. Within the stated
range of $31.3 million to $117.3 million, no amount within the range can be
reliably
Page 8 of 25 Pages
<PAGE>
identified as a better estimate than any other estimate. Therefore, a
liability at the low end of this range and a corresponding regulatory asset
have been recorded on the financial statements.
AGLC has two means of recovering the expenses associated with the
former MGP sites. First, the Georgia Commission has approved the recovery
by AGLC of Environmental Response Costs, as defined, pursuant to an
Environmental Response Cost Recovery Rider (ERCRR). For purposes of the
ERCRR, Environmental Response Costs include investigation, testing,
remediation and litigation costs and expenses or other liabilities relating
to or arising from MGP sites. In connection with the ERCRR, the staff of
the Georgia Commission conducted a financial and management process audit
related to the MGP sites, cleanup activities at the sites and environmental
response costs that have been incurred for purposes of the ERCRR. On
October 10, 1996, the Georgia Commission issued an order to prohibit funds
collected through the ERCRR from being used for the payment of any damage
award, including punitive damages, as a result of any litigation associated
with any of the MGP sites in which AGLC is involved. AGLC is currently
pursuing judicial review of the October 10, 1996 order.
Second, AGLC is seeking recovery of appropriate costs from its
insurers and other potentially responsible parties. With respect to its
insurers, AGLC filed a declaratory judgment action against 23 of its
insurance companies in 1991. After the trial court entered a judgment
adverse to AGLC and AGLC appealed that ruling, the Eleventh Circuit Court
of Appeals held that the case did not present a case or controversy when
filed, and the case was remanded with instructions to dismiss. Since the
Eleventh Circuit's decision, AGLC has settled with, or is close to
settlement with, most of the major insurers. AGLC has not determined what
actions it will take with respect to non-settling insurers.
5. Competition
AGLC competes to supply natural gas to interruptible customers who are
capable of switching to alternative fuels, including propane, fuel and
waste oils, electricity and, in some cases, combustible wood by-products.
AGLC also competes to supply gas to interruptible customers who might seek
to bypass its distribution system.
AGLC can price distribution services to interruptible customers four
ways. First, multiple rates are established under the rate schedules of
AGLC's tariff approved by the Georgia Commission. If an existing tariff
rate does not produce a price competitive with a customer's relevant
competitive alternative, three alternate pricing mechanisms exist:
Negotiated Contracts, Interruptible Transportation and Sales Maintenance
(ITSM) discounts, and Special Contracts.
On February 17, 1995, the Georgia Commission approved a settlement
that permits AGLC to negotiate contracts with customers who have the option
of bypassing AGLC's facilities (Bypass Customers) to receive natural gas
from other suppliers. The bypass avoidance contracts (Negotiated Contracts)
can be renewable, provided the initial term does not exceed five years,
unless a longer term specifically is authorized by the Georgia Commission.
The rate provided by the Negotiated Contract may be lower than AGLC's filed
rate, but not less than AGLC's marginal cost of service to the potential
Bypass Customer. Service pursuant to a Negotiated Contract may commence
without Georgia Commission action, after a copy of the contract is filed
with the Georgia Commission. Negotiated Contracts may be rejected by the
Georgia Commission within 90 days of filing; absent such action, however,
the Negotiated Contracts remain in effect. None of the Negotiated Contracts
filed to date with the Georgia Commission have been rejected.
Page 9 of 25 Pages
<PAGE>
The settlement also provides for a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or the effective date of
new rates for AGLC resulting from a general rate case. Under the recovery
mechanism, AGLC is allowed to recover from other customers 75% of the
difference between (a) the nongas cost revenue that was received from the
potential Bypass Customer during the most recent 12-month period and (b)
the nongas cost revenue that is calculated to be received from the lower
Negotiated Contract rate applied to the same volumetric level. Concerning
the remaining 25% of the difference, AGLC is allowed to retain a 44% share
of capacity release revenues in excess of $5 million until AGLC is made
whole for discounts from Negotiated Contracts. To the extent there are
additional capacity release revenues, AGLC is allowed to retain 15% of such
amounts.
In addition to Negotiated Contracts, which are designed to serve
existing and potential Bypass Customers, AGLC's ITSM Rider continues to
permit discounts for short-term transactions to compete with alternative
fuels. Revenue shortfalls, if any, from interruptible customers as measured
by the test-year interruptible revenues determined by the Georgia
Commission in AGLC's 1993 rate case will continue to be recovered under the
ITSM Rider.
The settlement approved by the Georgia Commission also provides that
AGLC may file contracts (Special Contracts) for Georgia Commission approval
if the service cannot be provided through the ITSM Rider, existing rate
schedules, or Negotiated Contract procedures. A Special Contract, for
example, could involve AGLC providing a long-term service contract to
compete with alternative fuels where physical bypass is not the relevant
competition.
Pursuant to the approved settlement, AGLC has filed and is providing
service pursuant to 50 Negotiated Contracts. Additionally, the Georgia
Commission has approved Special Contracts between AGLC and seven
interruptible customers.
On November 27, 1996, the Tennessee Regulatory Authority (TRA)
approved a settlement that permits Chattanooga to negotiate contracts with
large commercial or industrial customers who are capable of bypassing
Chattanooga's distribution system. The settlement provides for approval on
an experimental basis, with the Tennessee Regulatory Authority (TRA) to
review the measure two years from the approval date. The pricing terms
provided in any such contract may be neither less than Chattanooga's
marginal cost of providing service nor greater than the filed tariff rate
generally applicable to such service. Chattanooga can recover 50% of the
difference between the contract rate and the applicable tariff rate through
the balancing account of the purchased gas adjustment provisions of
Chattanooga's rate schedules. Pursuant to the approved settlement,
Chattanooga has entered into four negotiated contracts which are currently
under review by the TRA.
The 1997 session of the Georgia General Assembly passed legislation
which provides a legal framework for comprehensive deregulation of many
aspects of the natural gas business in Georgia. Senate Bill 215, the
Natural Gas Competition and Deregulation Act, which became law on April 14,
1997, if implemented by AGLC with respect to its system, would result in
the application of an alternative form of regulation, such as performance
based regulation, to AGLC. Pursuant to a separate election, AGLC, as an
electing distribution company, could choose to exit the merchant function
and fully unbundle its system.
Senate Bill 215 provides for a transition period leading to a
condition of effective competition in the natural gas markets. An electing
distribution company would unbundle all services to its natural gas
customers, assign firm delivery capacity to certificated marketers selling
the gas commodity and create a secondary transportation market for
interruptible transportation capacity. Marketers, including unregulated
affiliates of AGLC, would compete to sell natural gas to all customers at
market-based prices. AGLC would continue to provide intrastate
transportation of the gas to end users through its existing system, subject
to
Page 10 of 25 Pages
<PAGE>
continued rate regulation by the Georgia Commission. In addition, the
Georgia Commission would continue to regulate safety, access, and quality
of service pursuant to an alternative form of regulation.
The law provides for marketer standards and rules of business practice
to ensure that the benefits of a competitive natural gas market are
available to all customers on the AGLC system. It imposes an obligation to
serve on marketers with a corresponding universal service fund which can
also facilitate the extension of AGLC facilities in order to serve the
public interest.
In order to implement the new law, the Georgia Commission must
undertake and complete several rulemakings by December 31, 1997. As the
process of considering and adopting these rules progresses, the extent of
and schedule for actions under the legislation by AGLC will evolve further.
Currently, in accordance with Statement of Financial Accounting
Standard No. 71, "Accounting for the Effects of Certain Types of
Regulation," (SFAS 71), AGLC has recorded regulatory assets and liabilities
which represent regulator-approved deferrals resulting from the ratemaking
process. Recently, the staff of the Securities and Exchange Commission has
questioned the continued applicability of SFAS 71 to portions of the
business of three California utilities, as a result of legislation recently
enacted in California. The Emerging Issues Task Force (EITF) held
discussions of this issue at its July 1997 meeting. The EITF concluded that
once legislation is passed to deregulate a segment of a utility and that
legislation includes sufficient detail for the enterprise to determine how
the transition plan will affect that segment, SFAS 71 should be
discontinued for that segment of the utility. The state of Georgia has
enacted legislation (Senate Bill 215) which allows deregulation of the
merchant function and unbundling of certain ancillary services of local gas
distribution companies. Each local gas company within the state may elect
to be subject to Senate Bill 215 or continue to be regulated in the
traditional manner. Under either scenario, the rates to transport natural
gas through the intrastate pipe system of the local gas distribution
company will be regulated by the Georgia Commission. Since the activities
associated with AGLC's SFAS 71 regulatory assets and liabilities continue
to be regulated, AGLC has concluded that the continued application of SFAS
71 remains appropriate.
On May 1, 1997, Chattanooga filed a rate proceeding with the TRA
seeking an increase in revenues of $4.4 million annually. Revenues from the
rate increase will be used to improve and expand Chattanooga's natural gas
distribution system, to recover increased operation, maintenance and tax
expenses, and to provide a reasonable return to investors. Under the TRA's
rules and regulations, the effective date of the requested new rates has
been suspended until November 1, 1997. A schedule for hearings has not yet
been established by the TRA.
6. Accounting Developments
In June 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 130, "Reporting
Comprehensive Income" (SFAS 130) and Statement of Financial Accounting
Standard No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS 131). AGLC will adopt SFAS 130 and SFAS 131 in fiscal
year 1999. SFAS 130 establishes standards for reporting and displaying of
comprehensive income and its components (revenues, expenses, gains, and
losses) in a full set of general-purpose financial statements. SFAS 131
establishes standards for the way that public business enterprises report
information about operating segments in annual financial statements and
requires that those enterprises report selected information about operating
segments in interim financial reports issued to shareholders. Management
does not expect SFAS 130 or SFAS 131 to have a significant impact on the
presentation of AGLC's consolidated financial statements.
Page 11 of 25 Pages
<PAGE>
Item 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
On March 6, 1996, Atlanta Gas Light Company (AGLC) completed a corporate
restructuring in which a new company, AGL Resources Inc. (AGL Resources) became
the holding company for AGLC and its subsidiaries. During calendar 1996,
ownership of AGLC's nonregulated businesses was transferred to AGL Resources and
its various subsidiaries. Unless noted specifically or otherwise required by the
context, references to AGLC include the operations and activities of AGLC and
Chattanooga. The following discussion and analysis reflects events affecting
AGLC's results of operations and financial condition and factors expected to
impact its future operations. See Note 1 in Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
Forward Looking Statements
The Private Securities Litigation Reform Act of 1995 provides for the use
of cautionary statements accompanying forward looking statements. Management's
Discussion and Analysis of Results of Operations and Financial Condition
includes forward looking statements concerning, among other things, estimated
costs of environmental remediation, deregulation and restructuring costs. The
future results for AGLC generally may be affected by many factors, among which
are uncertainty as to the regulatory issues, both state and federal, and
uncertainty with regard to environmental issues and competitive issues in
general.
Results of Operations
Three-Month Periods Ended June 30, 1997 and 1996
Explained below are the major factors that had a significant effect on
results of operations for the three-month period ended June 30, 1997, compared
with the same period in 1996.
Operating revenues decreased 14.2% for the three-month period ended June
30, 1997, compared with the same period in 1996 primarily due to decreased
volumes of gas sold as a result of a shift by certain interruptible customers
from interruptible sales to transportation service. Operating revenues are less
when gas is transported for a customer than when it is sold to that customer.
AGLC's transportation rate generates the same operating margin as the applicable
sales rate schedule for interruptible sales of gas; therefore, net income is not
affected.
AGLC balances the cost of gas with revenues collected from customers under
the purchased gas provisions of its rate schedules. Underrecoveries or
overrecoveries 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. Cost of gas decreased 22.5% during the three-month
period ended June 30, 1997, compared with the same period in 1996. The decrease
in the cost of AGLC's gas supply was primarily due to decreased volumes of gas
sold principally as a result of a shift by certain interruptible customers from
interruptible sales to transportation service.
Operating margin decreased 2.5% for the three-month period ended June 30,
1997, compared with the same period in 1996 primarily due to decreased volumes
of gas sold and transported.
Operating expenses increased 4.4% for the three-month period ended June
30, 1997, compared with the same period in 1996 primarily due to increased (1)
labor and labor-related expenses and (2) uncollectible accounts
Page 12 of 25 Pages
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expense. The increase in operating expenses was offset partly by decreased (1)
maintenance of general plant and (2) outside services employed.
Other income increased $1.1 million for the three-month period ended June
30, 1997, compared with the same period in 1996 primarily due to (1) the
recovery from customers of carrying costs not included in base rates related to
storage gas inventories and (2) the recovery from customers of carrying costs
attributable to an increase in underrecovered deferred purchased gas costs.
Income taxes decreased $1.3 million for the three-month period ended June
30, 1997, compared with the same period in 1996 primarily due to decreased
taxable income.
Interest charges increased $0.7 million for the three-month period ended
June 30, 1997, compared with the same period in 1996 primarily due to increased
amounts of long-term and short-term debt outstanding during the period.
Earnings available for common stock for the three-month period ended June
30, 1997, was $0, compared with $3.9 million for the same period in 1996. The
decrease in earnings available for common stock was primarily due to (1)
decreased operating margin and (2) increased other operating expenses. The
decrease in earnings available for common stock was offset partly by increased
other income.
Nine-Month Periods Ended June 30, 1997 and 1996
Explained below are the major factors that had a significant effect on
results of operations for the nine-month period ended June 30, 1997, compared
with the same period in 1996.
Operating revenues decreased $6.3 million for the nine-month period ended
June 30, 1997, compared with the same period in 1996 primarily due to (1)
decreased volumes of gas sold as a result of weather that was 24.7% warmer than
during the same period in 1996 and (2) a shift by certain interruptible
customers from interruptible sales to transportation service. Operating revenues
are less when gas is transported for a customer than when it is sold to that
customer. AGLC's transportation rate generates the same operating margin as the
applicable sales rate schedule for interruptible sales of gas; therefore, net
income is not affected. The decrease in operating revenues was offset partly by
growth in the number of customers served.
AGLC balances the cost of gas with revenues collected from customers under
the purchased gas provisions of its rate schedules. Underrecoveries or
overrecoveries 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. Cost of gas decreased 2.4% during the nine-month
period ended June 30, 1997, compared with the same period in 1996. The decrease
in the cost of AGLC's gas supply was primarily due to (1) decreased volumes of
gas sold as a result of weather that was 24.7% warmer than during the same
period in 1996 and (2) a shift by certain interruptible customers from
interruptible sales to transportation service.
Operating margin increased 2.2% for the nine-month period ended June 30,
1997, compared with the same period in 1996 primarily due to growth in the
number of customers served. WNARs approved by the Georgia Commission and the TRA
stabilized margin at the level which would occur with normal weather for the
nine-month periods ended June 30, 1997 and 1996. As a result of the WNARs,
weather conditions experienced do not have a significant impact on the
comparability of operating margin.
Operating expenses increased 2.3% for the nine-month period ended June 30,
1997, compared with the same period in 1996 primarily due to increased (1)
uncollectible accounts expense, (2) ad valorem taxes and (3) injuries
Page 13 of 25 Pages
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and damages expenses. The increase in operating expenses was offset partly by
decreased outside services employed.
Other income decreased $1.2 million for the nine-month period ended June
30, 1997, compared with the same period in 1996 primarily due to nonregulated
subsidiary income of $3.7 million recorded during the nine-month period ended
June 30, 1996. Those nonregulated subsidiaries were transferred to AGL Resources
and its subsidiaries subsequent to March 1996 (see Note 1 to Notes to Condensed
Consolidated Financial Statements in this Form 10-Q). The decrease in other
income was offset partly by (1) the recovery from customers of carrying costs
not included in base rates related to storage gas inventories, (2) the recovery
from customers of carrying costs attributable to an increase in underrecovered
deferred purchased gas costs and (3) recoveries of environmental response costs
from insurance carriers and third parties.
Income taxes decreased $0.1 million for the nine-month period ended June
30, 1997, compared with the same period in 1996 primarily due to decreased
taxable income.
Interest charges increased $2.9 million for the nine-month period ended
June 30, 1997, compared with the same period in 1996 primarily due to increased
amounts of short-term and long-term debt outstanding during the period.
Earnings available for common stock for the nine-month period ended June
30, 1997, was $76.5 million, compared with $78.3 million for the same period in
1996. The decrease in earnings available for common stock was primarily due to
(1) increased operating expenses, (2) increased interest charges and (3)
decreased other income. The decrease in earnings available for common stock was
offset partly by growth in the number of customers served.
Twelve-Month Periods Ended June 30, 1997 and 1996
Explained below are the major factors that had a significant effect on
results of operations for the twelve-month period ended June 30, 1997, compared
with the same period in 1996.
Operating revenues increased 4.7% for the twelve-month period ended June
30, 1997, compared with the same period in 1996 primarily due to (1) an increase
in the cost of the gas supply recovered from customers under the purchased gas
provisions of AGLC's rate schedules, as explained in the following paragraph and
(2) growth in the number of customers served. The increase in operating revenues
was offset partly by (1) decreased volumes of gas sold as a result of weather
that was 25.2% warmer than during the same period in 1996 and (2) a shift by
certain interruptible customers from interruptible sales to transportation
service. Operating revenues are less when gas is transported for a customer than
when it is sold to that customer. AGLC's transportation rate generates the same
operating margin as the applicable sales rate schedule for interruptible sales
of gas; therefore, net income is not affected.
AGLC balances the cost of gas with revenues collected from customers under
the purchased gas provisions of its rate schedules. Underrecoveries or
overrecoveries 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. Cost of gas increased 5.6% during the twelve-month
period ended June 30, 1997, compared with the same period in 1996. The increase
in the cost of AGLC's gas supply was primarily due to an increase in the cost of
gas purchased for system supply. The increase in cost of gas was offset partly
by (1) decreased volumes of gas sold as a result of weather that was 25.2%
warmer than during the same period in 1996 and (2) a shift by certain
interruptible customers from interruptible sales to transportation service.
Page 14 of 25 Pages
<PAGE>
Operating margin increased 3.6% for the twelve-month period ended June 30,
1997, compared with the same period in 1996 primarily due to (1) revised firm
services rates, effective October 3, 1995, which shift margins from heating
months into non-heating months (see Note 3 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q) and (2) growth in the number of
customers served. WNARs approved by the Georgia Commission and the TRA
stabilized margin at the level which would occur with normal weather for the
twelve-month periods ended June 30, 1997 and 1996. As a result of the WNARs,
weather conditions experienced do not have a significant impact on the
comparability of operating margin.
Operating expenses increased 1.3% for the twelve-month period ended June
30, 1997, compared with the same period in 1996 primarily due to increased (1)
uncollectible accounts expense, (2) expenses related to AGLC's IRP which are
recovered through an IRP Cost Recovery Rider approved by the Georgia Commission,
(3) injuries and damages expense and (4) franchise expenses which are recovered
through a Franchise Recovery Rider approved by the Georgia Commission. AGLC
balances IRP and franchise expenses which are included in operating expenses
with revenues collected under the riders, thereby eliminating the effect that
recovery of IRP and franchise expenses would otherwise have on net income.
Operating expenses excluding IRP and franchise expenses increased $2.4 million,
or 0.8%. The increase in operating expenses was offset partly by decreased
outside services employed.
Other income increased $1.5 million for the twelve-month period ended June
30, 1997, compared with the same period in 1996 primarily due to (1) the
recovery from customers of carrying costs attributable to an increase in
underrecovered deferred purchased gas costs, (2) recoveries of environmental
response costs from insurance carriers and third parties and (3) the recovery
from customers of carrying costs not included in base rates related to storage
gas inventories. The increase in other income was offset partly by nonregulated
subsidiary income of $3.7 million recorded during the twelve-month period ended
June 30, 1996. Those nonregulated subsidiaries were transferred to AGL Resources
and its subsidiaries subsequent to March 1996 (see Note 1 to Notes to Condensed
Consolidated Financial Statements in this Form 10-Q).
Income taxes increased $4.6 million for the twelve-month period ended June
30, 1997, compared with the same period in 1996 primarily due to increased
taxable income.
Interest charges increased $4.1 million for the twelve-month period ended
June 30, 1997, compared with the same period in 1996 primarily due to increased
amounts of short-term and long-term debt outstanding during the period.
Earnings available for common stock for the twelve-month period ended June
30, 1997, was $74.4 million, compared with $67.5 million for the same period in
1996. The increase in earnings available for common stock was primarily due to
(1) increased operating margin and (2) increased other income. The increase in
earnings available for common stock was offset partly by (1) increased operating
expenses and (2) increased interest expense.
Financial Condition
AGLC's business is highly seasonal in nature and typically shows a
substantial increase in accounts receivable from customers from September 30 to
June 30 as a result of colder weather. AGLC also uses gas stored underground and
liquefied natural gas to serve its customers during periods of colder weather.
As a result, accounts receivable increased $21.4 million and inventory of gas
stored underground and liquefied natural gas decreased $50.3 million during the
nine-month period ended June 30, 1997. Accounts payable decreased $11.8 million
during the nine-month period ended June 30, 1997, primarily due to a $7 million
decrease in accounts payable to gas suppliers.
Page 15 of 25 Pages
<PAGE>
Accounts receivable decreased $17.4 million from June 30, 1996 to June 30,
1997, primarily due to decreased operating revenues. Inventory of gas stored
underground and liquefied natural gas increased $28.1 million from June 30, 1996
to June 30, 1997, primarily due to decreased volumes of gas withdrawn from
storage as a result of weather that was 25.2% warmer during the twelve-month
period ended June 30, 1997, compared with the same period in 1996. Accounts
payable decreased $7.6 million from June 30, 1996 to June 30, 1997, primarily
due to a $5.8 million decrease in accounts payable to gas suppliers.
The purchasing practices of AGLC are subject to review by the Georgia
Commission under legislation enacted by the Georgia General Assembly (Gas Supply
Plan Legislation). The Gas Supply Plan Legislation establishes procedures for
review and approval, in advance, of gas supply plans for gas utilities and gas
cost adjustment factors applicable to firm service customers of gas utilities.
Pursuant to AGLC's approved Gas Supply Plan for fiscal year 1997, gas supply
purchases are being recovered under the purchased gas provisions of AGLC's rate
schedules. The plan also allows recovery from the customers of AGLC of Federal
Energy Regulatory Commission (FERC) Order No. 636 transition costs that are
currently being charged by AGLC's pipeline suppliers. See Part II, Item 5,
"Other Information - Federal Regulatory Matters - Order No. 636," in this Form
10-Q.
AGLC currently estimates that its portion of transition costs resulting
from the FERC Order No. 636 restructuring proceedings from all of its pipeline
suppliers, that have been filed to be recovered to date, could be as high as
approximately $105 million. This estimate assumes that the restructuring
settlement of Southern Natural Gas Company (Southern) approved by FERC is not
overturned on judicial review and that FERC does not alter its GSR recovery
policies on rehearing of its Order No. 636-C. Although some filings by AGLC's
pipeline suppliers have been finally approved by FERC, other such filings are
pending final FERC approval, and the transition costs are being collected
subject to refund. Approximately $90.4 million of such costs have been incurred
by AGLC as of June 30, 1997, recovery of which is provided under the purchased
gas provisions of AGLC's rate schedules. For further discussion of the effects
of FERC Order No. 636 on AGLC, see Part II, Item 5, "Other Information - Federal
Regulatory Matters" of this Form 10-Q.
On August 1, 1997, AGLC filed its Gas Supply Plan for the twelve-month
period beginning October 1, 1997, which consists of gas supply, transportation
and storage options designed to provide reliable service to firm customers at
the best cost. The proposed plan is similar to the plan currently in effect. The
Georgia Commission may approve the entire supply portfolio contained in the
proposed 1998 Gas Supply Plan, modify the proposed plan or adopt a plan of its
own. A Georgia Commission decision is scheduled for September 12, 1997. Since
the passage of Gas Supply Plan Legislation, the Georgia Commission has
consistently approved AGLC's proposed supply portfolio.
Additionally, the proposed 1998 Gas Supply Plan contains a gas supply
incentive mechanism for off-system sales that is consistent with the incentive
mechanism in Senate Bill 215 (the Natural Gas Competition and Deregulation Act)
and an expanded hedging program. Under the plan, firm service customers and
shareholders would share revenues in excess of the costs of the sale and the
actual cost of the sale would be passed through to firm service customers under
the purchased gas adjustment provisions (PGA) of AGLC's rate schedules. The
financial results of all hedging activities are passed through to firm service
customers under the PGA and, accordingly, there is no impact on net income as a
result of the hedging program.
As noted above, AGLC recovers the cost of gas under the purchased gas
provisions of its rate schedules. AGLC was in an underrecovery position of $9
million as of June 30, 1997, an overrecovery position of $3.4 million as of June
30, 1996, and an underrecovery position of $4.7 million as of September 30,
1996. Under the provisions of AGLC's rate schedules, any underrecoveries of gas
costs are included in current assets and have no effect on net income.
Page 16 of 25 Pages
<PAGE>
Cash and cash equivalents decreased $7.1 million and $0.5 million for the
nine-month and twelve-month periods ended June 30, 1997, primarily to offset
other working capital requirements.
The expenditures for plant and other property totaled $94.5 million and
$135.3 million for the nine-month and twelve-month periods ended June 30, 1997.
Service Company was formed during fiscal 1996 to provide corporate support
services to AGLC, AGL Resources and its other subsidiaries. The transfer of
related assets and accumulated deferred income tax liabilities from AGLC to
Service Company and other nonregulated subsidiaries was effected through noncash
dividends of $34.3 million during the fourth quarter of fiscal 1996 and $4.8
million during the first quarter of fiscal 1997. As a result of those noncash
dividends, utility plant-net decreased by $48.4 million and accumulated deferred
income tax decreased by $9.3 million. Expenses of Service Company are allocated
to AGL Resources and its subsidiaries.
AGLC has accrued liabilities of $31.3 million as of June 30, 1997, $28.6
million as of June 30, 1996, and $30.4 million as of September 30, 1996, for
estimated future expenditures covering investigation and remediation of MGP
sites which are expected to be made over a period of several years. The Georgia
Commission has approved the recovery by AGLC of Environmental Response Costs, as
defined in Note 4 to Notes to Condensed Consolidated Financial Statements in
this Form 10-Q, pursuant to the ERCRR. In connection with the ERCRR, the staff
of the Georgia Commission conducted a financial and management process audit
related to the MGP sites, cleanup activities at the sites and environmental
response costs that have been incurred for purposes of the ERCRR. On October 10,
1996, the Georgia Commission issued an order to prohibit funds collected through
the ERCRR from being used for the payment of any damage award, including
punitive damages, as a result of any litigation associated with any of the MGP
sites in which AGLC is involved. AGLC is currently pursuing judicial review of
the October 10, 1996, order. See Note 4 to Notes to Condensed Consolidated
Financial Statements in this Form 10-Q.
In July 1997, AGLC called for the redemption on August 15, 1997, of its
4.5% Cumulative Preferred Stock, 4.72% Cumulative Preferred Stock, 5% Cumulative
Preferred Stock, 7.84% Cumulative Preferred Stock, and 8.32% Cumulative
Preferred Stock at the current call price in effect for each issue. Accordingly,
a current liability associated with those redemptions of $14.3 million is
recorded in the financial statements.
Long-term debt outstanding increased $30 million during the nine-month and
twelve-month periods ended June 30, 1997, as a result of the issuance by AGLC of
$30 million in principal amount of Medium-Term Notes, Series C in November 1996.
The notes were issued under a registration statement filed with the Securities
and Exchange Commission in September 1993 covering the periodic offer and sale
of up to $300 million in principal amount of Medium-Term Notes, Series C. As of
June 30, 1997, AGLC had issued $224.5 million in principal amount of Medium-Term
Notes Series C, with maturity dates ranging from ten to 30 years and with
interest rates ranging from 5.9% to 7.2%. Net proceeds from the issuance of
Medium-Term Notes were used to fund capital expenditures, to repay short-term
debt and for other corporate purposes. During July 1997, the remaining $75.5
million principal amount of Medium Term Notes Series C were issued, with
maturity dates ranging from 20 to 30 years and with interest rates ranging from
7.2% to 7.3%. Net proceeds from that issue will be used to repay short-term debt
and for other corporate purposes.
Short-term debt decreased $118.5 million and $38.4 million for the
nine-month and twelve-month periods ended June 30, 1997, respectively, primarily
due to the issuance of long-term debt and the use of proceeds from external
financing activities of AGL Resources to repay short-term debt.
On February 17, 1995, the Georgia Commission approved a settlement that
permits AGLC to negotiate contracts with customers who have the option of
bypassing AGLC's facilities (Bypass Customers) to receive
Page 17 of 25 Pages
<PAGE>
natural gas from other suppliers. The bypass avoidance contracts (Negotiated
Contracts) can be renewable, provided the initial term does not exceed five
years, unless a longer term specifically is authorized by the Georgia
Commission. The rate provided by the Negotiated Contract may be lower than
AGLC's filed rate, but not less than AGLC's marginal cost of service to the
potential Bypass Customer. Service pursuant to a Negotiated Contract may
commence without Georgia Commission action, after a copy of the contract is
filed with the Georgia Commission. Negotiated Contracts may be rejected by the
Georgia Commission within 90 days of filing; absent such action, however, the
Negotiated Contracts remain in effect. None of the Negotiated Contracts filed to
date with the Georgia Commission have been rejected.
The settlement also provides for a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or the effective date of new
rates for AGLC resulting from a general rate case. See Note 5 to Notes to
Condensed Consolidated Financial Statements in this Form 10-Q.
On November 27, 1996, the TRA approved a settlement that permits
Chattanooga to negotiate contracts with large commercial or industrial customers
who are capable of bypassing Chattanooga's distribution system. The settlement
provides for approval on an experimental basis, with the TRA to review the
measure two years from the approval date. The pricing terms provided in any such
contract may be neither less than Chattanooga's marginal cost of providing
service nor greater than the filed tariff rate generally applicable to such
service. Chattanooga can recover 50% of the difference between the contract rate
and the applicable tariff rate through the balancing account of the purchased
gas adjustment provisions of Chattanooga's rate schedules.
The 1997 session of the Georgia General Assembly enacted legislation which
provides a legal framework for comprehensive deregulation of many aspects of the
natural gas business in Georgia. Senate Bill 215, the Natural Gas Competition
and Deregulation Act, which became law on April 14, 1997, if implemented by AGLC
with respect to its system, would result in the application of an alternative
form of regulation, such as performance based regulation, to AGLC. Pursuant to a
separate election, AGLC, as an electing distribution company, could choose to
exit the merchant function and fully unbundle its system. See Note 5 to Notes to
Condensed Consolidated Financial Statements in this Form 10-Q.
On May 1, 1997, Chattanooga filed a rate proceeding with the TRA seeking
an increase in revenues of $4.4 million annually. Revenues from the rate
increase will be used to improve and expand Chattanooga's natural gas
distribution system, to recover increased operation, maintenance and tax
expenses, and to provide a reasonable return to investors. Under the TRA's rules
and regulations, the effective date of the requested new rates has been
suspended until November 1, 1997. A schedule for hearings has not yet been
established by the TRA.
Accounting Developments
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standard No. 130, "Reporting Comprehensive Income" (SFAS
130) and Statement of Financial Accounting Standard No. 131, "Disclosures about
Segments of an Enterprise and Related Information" (SFAS 131). AGLC will adopt
SFAS 130 and SFAS 131 in fiscal year 1999. SFAS 130 establishes standards for
reporting and displaying of comprehensive income and its components (revenues,
expenses, gains, and losses) in a full set of general-purpose financial
statements. SFAS 131 establishes standards for the way that public business
enterprises report information about operating segments in annual financial
statements and requires that those enterprises report selected information about
operating segments in interim financial reports issued to shareholders.
Management does not expect SFAS 130 or SFAS 131 to have a significant impact on
the presentation of AGLC's consolidated financial statements.
Page 18 of 25 Pages
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PART II -- OTHER INFORMATION
"Part II -- Other Information" is intended to supplement information
contained in the Annual Report on Form 10-K for the fiscal year ended September
30, 1996 and should be read in conjunction therewith.
Item 1. Legal Proceedings
See Item 5.
Item 5. Other Information
Federal Regulatory Matters
Order No. 636
On May 12, 1997, the United States Supreme Court denied petitions for
certiorari filed by AGLC and others challenging the ruling of the United States
Court of Appeals for the District of Columbia Circuit in United Distribution
Cos. v. FERC that FERC has authority over capacity release by local distribution
companies.
AGLC currently estimates that its portion of transition costs (which
include unrecovered gas costs, GSR costs and various stranded costs resulting
from unbundling of interstate pipeline sales service) from all of its pipeline
suppliers filed with the FERC to date to be recovered could be as high as
approximately $105.1 million. AGLC's estimate is based on the most recent
estimates of transition costs filed by its pipeline suppliers with the FERC, and
assumes that the restructuring settlement agreement of Southern approved by FERC
is not overturned on judicial review and that FERC does not alter its GSR
recovery policies on rehearing of its Order 636-C. Although some filings by
AGLC's pipeline suppliers have been finally approved by FERC, other such filings
are pending final FERC approval. Approximately $90.4 million of transition costs
have been incurred by AGLC as of June 30, 1997, and are being recovered from
customers under the purchased gas provisions of AGLC's rate schedules. Details
concerning the status of the Order No. 636 restructuring proceedings involving
the pipelines that serve AGLC directly are set forth below.
SOUTHERN GSR Cost Recovery Proceeding. Southern continues to make quarterly and
monthly transition cost filings to recover costs from contesting parties to the
settlement, and the FERC has ordered that such costs may be recovered by
Southern, subject to the outcome of a hearing for contesting parties. However,
since AGLC is a consenting party, its GSR and other transition cost charges are
in accordance with Southern's restructuring settlement. Assuming the FERC's
approval of the settlement is upheld on judicial review, AGLC's share of
Southern's transition costs is estimated to be $86.9 million. This estimate
would not be affected by the remand of Order No. 636, unless FERC's approval of
the settlement is not upheld on judicial review. As of June 30, 1997, $78
million of such costs have already been incurred by AGLC.
TENNESSEE GSR Cost Recovery Proceeding. FERC's April 16, 1997 order approving
the restructuring settlement between Tennessee Gas Pipeline Company (Tennessee)
and its customers became final when no party sought rehearing within the
statutory period. As a consequence, Tennessee's recovery of GSR costs from AGLC
is now pursuant to the settlement. AGLC's estimated liability for GSR costs as a
result of the settlement is approximately $13 million. As of June 30, 1997, $6.9
million of such costs have already been incurred by AGLC.
Page 19 of 25 Pages
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FERC Rate Proceedings
TRANSCO The consolidated hearing to address the proposal of Transcontinental Gas
Pipe Line Corporation (Transco) to roll into its general system rates the costs
associated with the Leidy Line and Southern expansion facilities has concluded,
and the matter currently is pending briefing by the parties and an initial
decision by the administrative law judge. AGLC has submitted testimony in
Transco's current rate case to advocate the creation of a balancing charge on
Transco's system.
Arcadian
On May 20, 1997, the United States Court of Appeals for the Eleventh
Circuit issued an order consolidating the various appeals filed by AGLC and
others of the FERC's orders in Arcadian Corp. v. Southern Natural Gas Co. and
ruling that those appeals are no longer being held in abeyance. The consolidated
cases are now pending briefing and decision.
AGLC cannot predict the outcome of these federal proceedings nor can it
determine the ultimate effect, if any, such proceedings may have on AGLC.
State Regulatory Matters
The 1997 session of the Georgia General Assembly enacted legislation which
provides a legal framework for comprehensive deregulation of many aspects of the
natural gas business in Georgia. Senate Bill 215, the Natural Gas Competition
and Deregulation Act, which became law on April 14, 1997, if implemented by AGLC
with respect to its system, would result in the application of an alternative
form of regulation, such as performance based regulation, to AGLC. Pursuant to a
separate election, AGLC, as an electing distribution company, could choose to
exit the merchant function and fully unbundle its system.
Senate Bill 215 provides for a transition period leading to a condition of
effective competition in the natural gas markets. An electing distribution
company would unbundle all services to its natural gas customers, assign firm
delivery capacity to certificated marketers selling the gas commodity and create
a secondary transportation market for interruptible transportation capacity.
Marketers, including unregulated affiliates of AGLC, would compete to sell
natural gas to all customers at market-based prices. AGLC would continue to
provide intrastate transportation of the gas to end users through its existing
system, subject to continued rate regulation by the Georgia Commission. In
addition, the Georgia Commission would continue to regulate safety, access, and
quality of service pursuant to an alternative form of regulation.
The law provides for marketer standards and rules of business practice to
ensure that the benefits of a competitive natural gas market are available to
all customers on the AGLC system. It imposes an obligation to serve on marketers
with a corresponding universal service fund which can also facilitate the
extension of AGLC facilities in order to serve the public interest.
In order to implement the new law, the Georgia Commission must undertake
and complete several rulemakings by December 31, 1997. As the process of
considering and adopting these rules progresses, the extent of and schedule for
actions under the legislation by AGLC will evolve further.
On May 21, 1996, the Georgia Commission adopted a Policy Statement
following its November 20, 1995, Notice of Inquiry concerning changes in state
regulatory guidelines to respond to trends toward increased competition in
natural gas markets. Among other things, the Policy Statement sets up a
distinction between competitive and natural monopoly services; favors
performance-based regulation in lieu of traditional
Page 20 of 25 Pages
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cost-of-service regulation; calls for unbundling interruptible service; directs
the Georgia Commission's staff to develop standards of conduct for utilities and
their marketing affiliates; and invites pilot programs for unbundling services
to residential and small business customers.
Consistent with specific goals in the Georgia Commission's Policy
Statement, AGLC filed on June 10, 1996, the Natural Gas Service Provider
Selection Plan (the Plan), a comprehensive plan for serving interruptible
markets. The Plan proposes further unbundling of services to provide large
customers more service options and the ability to purchase only those services
they require. Proposed tariff changes would allow AGLC to cease its sales
service function and the associated sales obligation for large customers;
implement delivery-only service for large customers on a firm and interruptible
basis; and provide pooling services to marketers. The Plan also includes
proposed standards of conduct for utilities and utility marketing affiliates.
The Georgia Commission granted AGLC's Motion for Continuance on January 30,
1997, moving the Georgia Commission to suspend the proceeding after a showing
that all parties of record had expressed an interest in pursuing settlement
discussions in lieu of rebuttal hearings. On August 5, 1997, AGLC notified the
Georgia Commission that the settlement discussions had concluded without
reaching a settlement. Pursuant to the Georgia Commission's order dated January
30, 1997, granting AGLC's motion to suspend the proceeding, the new statutory
deadline for a decision by the Georgia Commission on the Plan is September 19,
1997. A schedule for rebuttal testimony and briefs has not yet been established
by the Georgia Commission.
AGLC supports both the Plan under consideration by the Georgia Commission
and the new regulatory model contemplated by Senate Bill 215. AGLC currently
makes no profit on the purchase and sale of gas because actual gas costs are
passed through to customers under the purchased gas provisions of AGLC's rate
schedules. Earnings are provided through revenues received for intrastate
transportation of the commodity. Consequently, allowing AGLC to cease its sales
service function and the associated sales obligation would not adversely affect
AGLC's ability to earn a return on its distribution system investment. Gas will
be sold to all customers by numerous marketers, including nonregulated
subsidiaries of AGL Resources.
On July 22, 1996, Chattanooga filed a plan with the TRA that permits
Chattanooga to negotiate contracts with customers in Tennessee who have
long-term competitive options, including bypass. On November 27, 1996, the TRA
approved a settlement that permits Chattanooga to negotiate contracts with large
commercial or industrial customers who are capable of bypassing Chattanooga's
distribution system. The settlement provides for approval on an experimental
basis, with the TRA to review the measure two years from the approval date. The
pricing terms provided in any such contract may be neither less than
Chattanooga's marginal cost of providing service nor greater than the filed
tariff rate generally applicable to such service. Chattanooga can recover 50% of
the difference between the contract rate and the applicable tariff rate through
the balancing account of the purchased gas adjustment provisions of
Chattanooga's rate schedules.
On May 1, 1997, Chattanooga filed a rate proceeding with the TRA seeking
an increase in revenues of $4.4 million annually. Revenues from the rate
increase will be used to improve and expand Chattanooga's natural gas
distribution system, to recover increased operation, maintenance and tax
expenses, and to provide a reasonable return to investors. Under the TRA's rules
and regulations, the effective date of the requested new rates has been
suspended until November 1, 1997. A schedule for hearings has not yet been
established by the TRA.
See Note 5 to Notes to Condensed Consolidated Financial Statements in this
Form 10-Q for a discussion of state regulatory matters relating to competition.
Page 21 of 25 Pages
<PAGE>
Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all or
part of an MGP site. In addition, AGLC has identified three other sites in
Georgia which AGLC does not now own, but which may have been associated with the
operation of MGPs by AGLC or its predecessors. There are also three sites in
Florida which have been investigated by environmental authorities in connection
with which AGLC may be contacted as a potentially responsible party. In that
regard, AGLC has learned that the EPA has conducted an Expanded Site
Investigation at the former MGP site in Sanford, Florida and has concluded that
MGP impacts are present in a nearby lake. The consequences of this finding have
not been determined.
AGLC's response to MGP sites in Georgia is proceeding under two state
regulatory programs. First, AGLC has entered into consent orders with the EPD
with respect to four sites: Augusta, Griffin, Savannah and Valdosta. Under these
consent orders, AGLC is obligated to investigate and, if necessary, remediate
environmental impacts at the sites. AGLC has completed soil remediation at the
Griffin site and expects to monitor groundwater for three to six years.
Assessment activities are being conducted at Augusta and have been completed at
Savannah. Those assessment activities are expected to be completed principally
during fiscal 1997. In addition, AGLC has completed removal of the gas storage
holder at the Augusta site.
Second, AGLC's response to all Georgia sites is proceeding under Georgia's
HSRA. AGLC submitted to EPD formal notifications relating to all of its nine
owned MGP sites, and EPD had listed seven of those sites (Athens, Augusta,
Brunswick, Griffin, Savannah, Valdosta and Waycross) on the HSI. EPD has not
listed the Macon site on the HSI at this time. EPD also has listed the Rome
site, which AGLC has acquired, on the HSI. Under the HSRA regulations, EPD has
determined the four sites subject to consent orders require corrective action;
EPD also has determined the Athens site requires corrective action and will
determine whether corrective action is required at the three remaining sites
(Brunswick, Rome and Waycross) in due course. In that respect, however, AGLC has
submitted to EPD CSRs for the Brunswick and Rome MGP sites, and AGLC has
concluded that some degree of response action is likely to be required at those
sites.
AGLC has estimated that, under the most favorable circumstances reasonably
possible, the future cost to AGLC of investigating and remediating the former
MGP sites could be as low as $31.3 million. Alternatively, AGLC has estimated
that, under reasonably possible unfavorable circumstances, the future cost to
AGLC of investigating and remediating the former MGP sites could be as high as
$117.3 million. Those estimates have been adjusted from the September 30, 1996
estimates to reflect settlements of property damage claims at certain sites.
AGLC cannot at this time determine the range of costs that may be associated
with investigation and cleanup of the lake near the Sanford MGP site, which
costs may be material. Accordingly, the foregoing estimated range now excludes
those costs and reflects only AGLC's current estimate of the range of costs for
which cost recovery claims against AGLC are reasonably likely. In addition,
those costs do not include other expenses, such as property damage claims and
natural resource damage claims, for which AGLC may ultimately be held liable,
but for which neither the existence nor the amount of such liabilities can be
reasonably forecast. Within the stated range of $31.3 million to $117.3 million,
no amount within the range can be reliably identified as a better estimate than
any other estimate. Therefore, a liability at the low end of this range and a
corresponding regulatory asset have been recorded on the financial statements.
AGLC has two means of recovering the expenses associated with the former
MGP sites. First, the Georgia Commission has approved the recovery by AGLC of
Environmental Response Costs, as defined, pursuant to AGLC's ERCRR. For purposes
of the ERCRR, Environmental Response Costs include investigation, testing,
remediation and litigation costs and expenses or other liabilities relating to
or arising from MGP sites. In connection with the ERCRR, the staff of the
Georgia Commission conducted a financial and management process audit related to
the MGP sites, cleanup activities at the sites and environmental
Page 22 of 25 Pages
<PAGE>
response costs that have been incurred for purposes of the ERCRR. On October 10,
1996, the Georgia Commission issued an order to prohibit funds collected through
the ERCRR from being used for the payment of any damage award, including
punitive damages, as a result of any litigation associated with any of the MGP
sites in which AGLC is involved. AGLC is currently pursuing judicial review of
the October 10, 1996, order.
Second, AGLC is seeking recovery of appropriate costs from its insurers
and other potentially responsible parties. See Note 4 to Notes to Condensed
Consolidated Financial Statements in this Form 10-Q.
Other Legal Proceedings
On February 10, 1995, a class action lawsuit captioned Trinity Christian
Methodist Episcopal Church, et al. v. Atlanta Gas Light Company, No. 95-RCCV-93,
was filed in the Superior Court of Richmond County, Georgia seeking to recover
for damage to property owned by persons adjacent to and nearby the former
manufactured gas plant site in Augusta, Georgia. On December 13, 1996, the
parties reached a preliminary settlement, which was finally approved by the
Court on April 15, 1997. Pursuant to the settlement, there is a claims process
before an umpire to determine either the full fair market value of properties
tendered to AGLC or the diminution in fair market value of properties not
tendered to AGLC. Thus far, awards have been made to fifty-four (54) property
owners in the class totaling approximately $5.7 million, including legal fees
and expenses of the plaintiffs. There are approximately eighty-four (84) awards
yet to be made. AGLC has filed motions to vacate six awards totaling
approximately $4.4 million. An order was entered on July 8, 1997, denying the
motion to vacate. AGLC has filed a notice of appeal to the Georgia Court of
Appeals seeking to reverse the denial of the motion to vacate.
With regard to other legal proceedings, AGLC is a party, as both plaintiff
and defendant, to a number of other suits, claims and counterclaims on an
ongoing basis. Management believes that the outcome of all litigation in which
it is involved will not have a material adverse effect on the consolidated
financial statements of AGLC.
(The remainder of this page was intentionally left blank.)
Page 23 of 25 Pages
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
10.1 - Letter Agreement amending FT-A Contract No. 4235,
dated May 20, 1997, between Atlanta Gas Light Company
and East Tennessee Natural Gas Company.
10.2 - Amendatory Agreement dated April 21, 1997, between
Atlanta Gas Light Company and Southern Natural Gas
Company, amending Exhibits 10.28, 10.29, 10.31 and
10.34, Form 10-K for the fiscal year ended September
30, 1996.
10.3 - Amendatory Agreement dated April 21, 1997, between
Chattanooga Gas Company and Southern Natural Gas
Company, amending Exhibit 10.37, Form 10-K for the
fiscal year ended September 30, 1996.
10.4 - Amendatory Agreement dated April 21, 1997, between
Chattanooga Gas Company and Southern Natural Gas
Company, amending Exhibit 10.35, Form 10-K for the
fiscal year ended September 30, 1996.
10.5 - Amendatory Agreement dated April 21, 1997, between
Chattanooga Gas Company and Southern Natural Gas
Company, amending Exhibit 10.36, Form 10-K for the
fiscal year ended September 30, 1996.
10.6 - Letter Agreement dated April 21, 1997, between
Atlanta Gas Light Company and Southern Natural Gas
Company.
27 - Financial Data Schedule.
(b) Reports on Form 8-K.
None.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Atlanta Gas Light Company
(Registrant)
Date August 14, 1997 /s/ David R. Jones
David R. Jones
Chief Executive Officer
Date August 14, 1997 /s/ J. Michael Riley
J. Michael Riley
Vice President and Chief Financial Officer
(Principal Accounting and Financial Officer)
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000008154
<NAME> ATLANTA GAS LIGHT COMPANY
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> SEP-30-1997
<PERIOD-START> OCT-01-1996
<PERIOD-END> JUN-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,403
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 248
<TOTAL-DEFERRED-CHARGES> 73
<OTHER-ASSETS> 15
<TOTAL-ASSETS> 1,739
<COMMON> 277
<CAPITAL-SURPLUS-PAID-IN> 166
<RETAINED-EARNINGS> 86
<TOTAL-COMMON-STOCKHOLDERS-EQ> 529
45
<LONG-TERM-DEBT-NET> 585
<SHORT-TERM-NOTES> 33
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
14
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 533
<TOT-CAPITALIZATION-AND-LIAB> 1,739
<GROSS-OPERATING-REVENUE> 1,042
<INCOME-TAX-EXPENSE> 48
<OTHER-OPERATING-EXPENSES> 259
<TOTAL-OPERATING-EXPENSES> 881
<OPERATING-INCOME-LOSS> 115
<OTHER-INCOME-NET> 5
<INCOME-BEFORE-INTEREST-EXPEN> 120
<TOTAL-INTEREST-EXPENSE> 40
<NET-INCOME> 80
3
<EARNINGS-AVAILABLE-FOR-COMM> 77
<COMMON-STOCK-DIVIDENDS> 45
<TOTAL-INTEREST-ON-BONDS> 32
<CASH-FLOW-OPERATIONS> 225
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
</TABLE>
Exhibit 10.1
[LETTERHEAD OF EL PASO ENERGY APPEARS HERE]
May 20,1997
Ms. Eileen G. Stanek
Atlanta Gas Light Company
303 Peachtree St., N.E.
Atlanta, GA 30308
RE: Firm Transportation Contract Restructuring
ETNG FT-A Contract No. 4235
Whereas Atlanta Gas Light (AGL) has requested that East Tennessee
Natural Gas Company (ETNG) permit it to reduce the Contract Transportation
Quantity (TQ) of Contract Number 4235 (FN1), and
Whereas ETNG has determined that such reduction in Transportation
Quantity will enable ETNG to reduce the required mainline facilities associated
with ETNG's recent open season expansion and subsequent Certificate of Public
Convenience and Necessity issued by the Federal Energy Regulatory Commission
(FERC) in Docket CP96-696-000,
Therefore, ETNG hereby agrees to amend FT-A Contract Number 4235, and
AGL agrees to such amendment, to reflect a reduction in the TQ by 2,700 Dth/d to
a total TQ of 61,160 Dth/d with such reduction applied to the primary receipt
point at Nora's Dickenson County Receiving (meter number 759315) and the primary
delivery point at Atlanta (meter number 759014). The 2,700 Dth/d reduction in
AGL's TQ under Contract No. 4235 shall commence and be effective on the date
that service commences for shippers under ETNG's open season expansion which
utilizes the 2,700 Dth/d of capacity being permanently relinquished by AGL. ETNG
anticipates that service to the open season expansion shippers will commence on
or about November 1, 1997. However, any delay in the commencement of service to
open season expansion shippers will result in a corresponding delay in the
permanent relinquishment of capacity.
Please have the appropriate representative execute both copies on
behalf of AGL and return to the undersigned. Upon receipt, ETNG will return one
fully executed original to your attention for your files. Signed originals must
be returned to the undersigned on or before seven (7) days from the date of this
letter, or this agreement may be nullified.
Sincerely,
/s/ William E. Wickman
William E. Wickman
EAST TENNESSEE NATURAL GAS ATLANTA GAS LIGHT
By: Signature not legible By: /s/ Thomas H. Benson
Title: AGENT AND ATTORNEY-IN-FACT Title: Executive Vice President
& Chief Operating Officer
Date: 6/2/97 Date: 5/3/97
(FN1)
AGL has not executed an agreement for service under ETNG's Rate Schedule FT-A.
For purposes of this agreement, the term "FT-A Contract Number 4235" refers to
ETNG's obligation to provide firm transportation service, and AGL's obligation
to purchase such service, pursuant to the orders of the Federal Energy
Regulatory Commission in East Tennessee's Order No. 636 restructuring
proceeding. East Tennessee Natural Gas Co., 65 FERC 61,356 (1993); 67 FERC
61,196 (1994).
Exhibit 10.2
Amendatory Agreement
This Amendment is entered into this 21St day of April, 1997, between
SOUTHERN NATURAL GAS COMPANY ("Company") and ATLANTA GAS LIGHT COMPANY
("Shipper").
RECITALS:
1 Company and Shipper are parties to a firm transportation agreement dated
September 1, 1994 (#902470) for 100,000 Mcf per day, as amended March 1, 1995
and August 23, 1996 (the "September FT Agreement"), a firm transportation
agreement dated November 1, 1994 (#904460), as amended March 1, 1995, June 1,
1995, and August 23, 1996, for 253,812 Mcf per day (the "November FT
Agreement"), a no-notice firm transportation agreement dated November 1, 1994
(#904460), as amended March 1, 1995 and August 23, 1996, for 406,222 Mcf per day
(the "FT-NN Agreement"), and a contract storage service agreement dated November
1, 1994 as amended March 1, 1995 and August 23, 1996, (#S20150) for 20,117,674
Mcf (the "CSS Agreement");
2. Shipper has notified Company that it desires to extend the term of the
September FT Agreement, the November FT Agreement, the FT-NN Agreement, and the
CSS Agreement as provided below.
AGREEMENTS:
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 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 August 31, 2002,
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 365 days prior to the end of the
primary term or any subsequent yearly extension.
<PAGE>
2. The Second Revised Exhibit E to the September FT Agreement shall be
deleted in its entirety and the Third Revised Exhibit E attached hereto shall be
substituted therefor.
3. The First Revised Exhibit B to the November FT Agreement and the FT-NN
Agreement shall each be deleted in its entirety and the Second Revised Exhibit B
attached hereto shall be substituted therefor.
4. 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 fun force and
effect for a primary term through the following
dates: (a) April 30, 2007, for 108,905 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 canceled 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; (b) August 31, 2003, for 21,139 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 365 days prior to the end of the primary term
or subsequent yearly extension; and (c) August 31,
2002, for 122,768 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 365 days
prior to the end of the primary term or subsequent
yearly extension.
- 2 -
<PAGE>
5. Section 4. 1 of the FT-NN 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) August 3l, 2003, for 24,133 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 365 days prior to the end of the primary term
or subsequent yearly extension; and (b) August 31,
2002, for 382,089 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 365 days
prior to the end of the primary term or subsequent
yearly extension.
6. Section 4.1 of the CSS 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) August 3l, 2003, for 1,195,179 Mcf per
day of Maximum Storage Quantity 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 365 days prior to the end of the
primary term or subsequent yearly extension; and
(b) August 31, 2002, for 18,922,495 Mcf per day of
Maximum Storage Quantity and shall continue and
remain in force and effect for successive terms of
one year each thereafter if the parties mutually
agree
-3 -
<PAGE>
in writing to each such yearly extension at least
365 days prior to the end of the primary term or
subsequent yearly extension.
7. This Amendatory Agreement is subject to a condition subsequent that the
FERC issue an order approving Company's certificate application and facilities
design in its upcoming expansion filing in Docket No. CP97- to provide
additional firm service to customers in eastern Tennessee and elsewhere in Zones
2 and 3 (the "ET Phase II Application"). If the FERC either (i) does not issue
an order approving the ET Phase II Application by June 1, 1999, or (ii) approves
the ET Phase II Application but modifies the ET Phase II facilities design, in
the ET Phase II certificate proceeding or in any other proceeding, in a manner
that is unacceptable to Company or Shipper, then either Company or Shipper may
terminate this Amendatory Agreement upon 30 days written prior notice to the
other party, to be given no later than 30 days after the occurrence of such
event described in (i) or (ii). If such termination occurs before March 1, 1999,
the terms of the Amendatory Agreement between Company and Shipper dated August
23, 1996 shall continue to apply as provided therein. If such termination occurs
after March 1, 1999, but before August 31, 2002, the terms of such August 23,
1996 Amendatory Agreement shall continue to apply as provided therein and all of
the service agreements described in such Amendatory Agreement with terms ending
on March 1, 1999, or March 1, 2000, and the discounted reservation rate under
the September FT Agreement, shall be extended through the later of (a) February
28, 2000, or (b) a date six months after the termination of this Amendatory
Agreement pursuant to this paragraph 7.
8. 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.
9. 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/ James J. Cleary By: /s/ James E. Moylan, Jr.
Title: Vice President Title: President
-4-
<PAGE>
ATTEST: ATLANTA GAS LIGHT COMPANY
By: /s/ Charlie J. Lail By: /s/ Thomas H. Benson
Title: Sr. V.P. Title: Executive Vice President
and Chief Operating Officer
- 5 -
<PAGE>
Service Agreement No. 902470
THIRD REVISED
EXHIBIT E
DISCOUNT INFORMATION
Discounted Rates:
(1) The Reservation Charge under this Agreement shall be the
lesser of (i) $10.50/Mcf ($10.284/dt effective January 1,
1997), or (ii) the maximum lawful applicable reservation
charge as approved by the FERC and in effect from time to
time;
(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 through 8/31/2002
/s/ Thomas H. Benson /s/ James E. Moylan, Jr.
ATLANTA GAS LIGHT COMPANY SOUTHERN NATURAL GAS COMPANY
<PAGE>
Exhibit B
Second Revised Exhibit B
Page No. 1 of 5
Effective Date 1997/05/01
ATLANTA GAS LIGHT COMPANY
The legal description of the Delivery Points listed below are more particularly
set forth in the Company's Delivery Point catalogs, a copy of which can be
requested from Company or accessed through SoNet, Company's electronic computer
system. Pages I through 3 of this exhibit reflect Maximum Daily Delivery
Quantities for FT Service Agreement No. 904460 and FT-NN Service Agreement No.
904461.
<TABLE>
<CAPTION>
Delivery Delivery MDDQ Meter Capability Cont.
Point Point in Daily Hourly Press.
Description Code MCF (Mcf/d) (Mcf/h) (psig) Notes
- ----------- ---- --- ------- ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Atlanta Area 683600 255,814 A
Fulton Ind'ial 910800 48,000 2,000 Line
East Point 911000 20,000 1,000 Line 200# - 335#
So. Atlanta #1 911300 137,000 8,200 290
Sewell Road 911400 270,000 14,000 Line < 335#, B
So. Atlanta #2 911600 172,000 7,165 Line
Marietta 912200 50,000 3,000 Reg 300# - 500#, F
Hampton 913000 4,200 252 290
AGL Farm Taps 907000
Chatsworth 907600 2,127 Line
Catoosa County 907800 258 300
Ringgold 908000 3,814 275
Macon Area 911500 53,916 A
North Macon 915400 50,000 3,000 Line
East Macon 915500 27,500 1,700 Line
West Macon 915600 14,400 864 Line
Macon-Mville #l 915800 89,395 5,360 Line D
Macon-Mville #2 915900 60,000 3,600 Line D
Jeffersonville 918200 2,110 126 Line >400#
Savannah Area 911800 69,327 A
Savannah #1 934600 30,000 1,800 125
Savannah #2 934700 46,500 2,790 Line >300#
Savannah #3 934800 6,000 250 150
Savannah #4 934900 28,800 1,200 Line >400#
Plant McIntosh 935000 69,327 8,703 Line >400#
Griffin 913400 18,750 290
Forsyth 917200 2,073 Line
</TABLE>
<PAGE>
Exhibit B
Second Revised Exhibit B
Page No. 2 of 5
Effective Date 1997/05/01
ATLANTA GAS LIGHT COMPANY
The legal description of the Delivery Points listed below are more particularly
set forth in the Company's Delivery Point catalogs, a copy of which can be
requested from Company or accessed through SoNet, Company's electronic computer
system. Pages I through 3 of this exhibit reflect Maximum Daily Delivery
Quantities for FT Service Agreement No. 904460 and FT-NN Service Agreement No.
904461.
<TABLE>
<CAPTION>
Delivery Delivery MDDQ Meter Capability Cont.
Point Point in Daily Hourly Press.
Description Code MCF (Mcf/d) (Mcf/h) (psig) Notes
- ----------- ---- --- ------- ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Zebulon 917400 555 Line
Thomaston 917600 7,406 150
Barnesville 917800 3,567 250
Jackson 918000 2,385 Reg 400# - 600#
Danville 918400 350 400
Dexter 918600 410 400
AGL-Laurens Co. 918700 46,817 Line >700#,E
Warrenton 930600 4,429 325
Blythe 931600 160 300
Sandersville 932500 6,430 Line >700#
S'field-Guyton 934200 850 Reg 380# - 400#
Rome Area 940013 29,971 A
Rome #1 904200 13,300 800 Line >450#
Rome #2 904300 20,000 1,100 260
Rome #3 904400 11,000 540 Line >400#
Shannon 906200 1,300 70 150 C
Augusta Area 940016 69,381 A
Augusta #1 932000 53,140 3,188 400
Augusta #2 932100 35,000 1,500 Line
Augusta #3 932200 18,333 1,100 500
Augusta #4 932300 19,200 800 Line
New-Yat-Dal Area 940018 47,162 A
Villa Rica 909400 1,875 113 150
Dallas #2 909800 9,600 400 300
Yates Junction 910100 20,400 850 Line
Newnan Junction 910200 8,500 492 Line
Douglasville 910400 10,800 450 Line >250#
</TABLE>
<PAGE>
Exhibit B
Second Revised Exhibit B
Page No. 3 of 5
Effective Date 1997/05/01
ATLANTA GAS LIGHT COMPANY
The legal description of the Delivery Points listed below are more particularly
set forth in the Company's Delivery Point catalogs, a copy of which can be
requested from Company or accessed through SoNet, Company's electronic computer
system. Pages I through 3 of this exhibit reflect Maximum Daily Delivery
Quantities for FT Service Agreement No. 904460 and FT-NN Service Agreement No.
904461.
<TABLE>
<CAPTION>
Delivery Delivery MDDQ Meter Capability Cont.
Point Point in Daily Hourly Press.
Description Code MCF (Mcf/d) (Mcf/h) (psig) Notes
- ----------- ---- --- ------- ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Calhoun Area 940019 4,552 A
Calhoun #1 907200 9,640 578 230
Calhoun #2 907300 9,640 402 Line >350#
Ctown-Rmart Area 940020 10,321 A
Cedartown 903600 7,300 430 250
Rockmart 903800 7,800 470 250
Car'llton Area 940026 19,209 A
Bowden 902800 1,560 65 300
Bremen 903000 5,544 231 300
Carrollton 909000 16,152 673 310
Temple 909200 1,200 50 150
GRAND TOTAL 660,034
</TABLE>
Atlanta Gas Light Company Southern Natural Gas Company
By: /s/ Thomas H. Benson By: /s/ James J. Cleary
Vice President
Date: 5/6/97 Date: 5/1/97
<PAGE>
Exhibit B
Second Revised Exhibit B
Page No. 4 of 5
Effective Date 1997/05/01
ATLANTA GAS LIGHT COMPANY
The legal description of the Delivery Points listed below are more particularly
set forth in the Company's Delivery Point catalogs, a copy of which can be
requested from Company or accessed through SoNet, Company's electronic computer
system. Page 4 of this exhibit reflects Maximum Daily Delivery Quantities for FT
Service Agreement No. 902470.
<TABLE>
<CAPTION>
Delivery Delivery MDDQ Meter Capability Cont.
Point Point in Daily Hourly Press.
Description Code MCF (Mcf/d) (Mcf/h) (psig) Notes
- ----------- ---- --- ------- ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Atlanta Area 683600 100,000 A
Fulton lnd'ial 910800 48,000 2,000 Line
East Point 911000 20,000 1,000 Line 200# - 335#
So. Atlanta #1 911300 137,000 8,200 290
Sewell Road 911400 270,000 14,000 Line < 335#, B
So. Atlanta #2 911600 172,000 7,165 Line
Marietta 912200 50,000 3,000 Reg 300# - 500#, F
Hampton 913000 4,200 252 290
GRAND TOTAL 100,000
</TABLE>
Atlanta Gas Light Company Southern Natural Gas Company
By: /s/ Thomas H. Benson By: James J. Cleary
Vice President
Date: 5/6/97 Date: 5/1/97
<PAGE>
Exhibit B
First Revised Exhibit B
Page No. 5 of 5
Effective Date 1998/11/01
Atlanta Gas Light Company
Service Agreement Nos. 904460, 904461 and 902470
(A) Company's obligation to deliver gas at each measurement station
comprising this Delivery Point is limited to the delivery capacity of
Company's facilities (at the measurement station and of the upstream
pipelines serving said station) as it exists from time to time.
(B) At a delivery pressure of 300 PSIG, the maximum hourly rate will be
12,000 Mcf; and the maximum daily rate 258,470 Mcf.
(C) Maximum hourly rate to be 80 Mcf upon the installation of additional
meter (after notification by purchaser) when required increased load.
(D) In accordance with ordering Paragraph (B) of the Commission's Order
issued December 27, 1973, in Docket No. CP74-7, combined deliveries
through the Macon-Milledgeville No. 1 and No. 2 Meter Stations for any
calendar year may not exceed 20,047,991 Mcf.
(E) The maximum hourly volume under Section 10.2 of the General Terms and
Conditions of Company's FERC Gas Tariff shall be the lesser of 6% of the
MDDQ or 2,200 Mcf/h.
(F) Notwithstanding the provisions of Note A to this Exhibit B, once the
facilities proposed in Company's phase II expansion filing to serve
customers in East Tennessee in Docket No. CP97-____ are placed in service,
Company's obligation will be to provide delivery capacity to the Marietta
Delivery Point of 4,000 Mcf of gas per hour on a steady state basis within
AGL's firm transportation capacity of 355,814 Mcf/d for the Atlanta Area.
The maximum hourly volume for the Atlanta Area Delivery Point under
Section 10.2 of the General Terms and conditions of Company's FERC Gas
Tariff shall be 6% of Shipper's total MDDQ for the Atlanta Area Delivery
Point.
Exhibit 10.3
AMENDATORY AGREEMENT
This Amendment is entered into this 21st day of April, 1997, between
SOUTHERN NATURAL GAS COMPANY ("Company") and CHATTANOOGA GAS COMPANY
("Shipper").
WITNESSETH:
WHEREAS, Company and Shipper are parties to a contract storage service
agreement dated November 1, 1994, (#S20130) as amended March 1, 1995, and July
26, 1996, under Company's Rate Schedule CSS ("Agreement") for 695,871 Mcf
(maximum storage quantity) for a primary term through February 28, 2000; and
WHEREAS, Company and Shipper have had discussions regarding an
extension of the primary term under the Agreement as more specifically provided
for herein;
NOW, THEREFORE, in consideration of the premises and the mutual
benefits and covenants contained herein, the parties agree as follows:
1. Section 4.1 of the CSS Agreement shall be deleted in its entirety
and the following Section 4.1 substituted therefor:
"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 August
31, 2003, 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 365 days prior to the end of the primary
term or any subsequent yearly extension."
2. Except as provided herein, the Agreement shall remain in full force
and effect as written.
3. 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 mater hereof.
4. This Amendment shall be binding on the parties' respective
successors and assigns.
<PAGE>
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/ James J. Cleary By: /s/ James E. Moylan, Jr.
Title: Vice President Title: President
ATTEST: CHATTANOOGA GAS COMPANY
By: /s/ Melanie M. Platt By: /s/ Harrison F. Thompson
Title: V.P. & Corp. Secy. Title: President
- 2 -
Exhibit 10.4
AMENDATORY AGREEMENT
This Amendment is entered into this 21st day of April, 1997, between
SOUTHERN NATURAL GAS COMPANY ("Company") and CHATTANOOGA GAS COMPANY
("Shipper").
WITNESSETH:
WHEREAS, Company and Shipper are parties to a firm transportation
agreement dated November 1, 1994, (#904470) as amended March 1, 1995, and July
26, 1996, under Company's Rate Schedule FT ("Agreement") for an aggregate
quantity of 7,949 Mcf per day of Transportation Demand for separately stated
terms; and
WHEREAS, Company and Shipper have had discussions regarding an
extension of the primary term for a portion of the Transportation Demand under
the Agreement as more specifically provided for herein;
NOW, THEREFORE, in consideration of the premises and the mutual
benefits and covenants contained herein, the parties agree as follows:
1. Section 4.1 of the FT Agreement shall be deleted in its entirety
and the following Section 4. 1 substituted therefor:
"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 primary terms through the following dates: (a)
April 30, 2007, for 3,300 Mcf per day of Transportation Demand, and
shall continue and remain in force and effect for successive terms of
one year each thereafter, unless and until canceled by either party
giving 180 days written notice to the other party prior to the end of
the primary term or any yearly extension thereof, and (b) August 31,
2003, for 4,649 Mcf per day of Transportation Demand, and shall
continue and remain in force and effect for successive terms of one
year each thereafter if the parties' mutually agree in writing to each
such yearly extension at least 365 days prior to the end of the primary
term or subsequent yearly extension."
2. Except as provided herein, the Agreement shall remain in full force
and effect as written.
<PAGE>
3. 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 mater hereof.
4. This Amendment shall be binding on the parties' respective
successors and assigns.
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/ James J. Cleary By: /s/ James E. Moylan, Jr.
Title: Vice President Title: President
ATTEST: CHATTANOOGA GAS COMPANY
By: /s/ Melanie M. Platt By: /s/ Harrison F. Thompson
Title: V. P. and Corp. Secy Title: President
- 2 -
Exhibit 10.5
AMENDATORY AGREEMENT
This Amendment is entered into this 21st day of April, 1997, between
SOUTHERN NATURAL GAS COMPANY ("Company") and CHATTANOOGA GAS COMPANY
("Shipper").
WITNESSETH:
WHEREAS, Company and Shipper are parties to a firm transportation-no
notice agreement dated November 1, 1994, (#904471) as amended March 1, 1995, and
July 26, 1996, under Company's Rate Schedule FT-NN ("Agreement") for 14,051 Mcf
per day of Transportation Demand for a primary term through February 28, 2000;
and
WHEREAS, Company and Shipper have had discussions regarding an
extension of the primary term under the Agreement as more specifically provided
for herein;
NOW, THEREFORE, in consideration of the premises and the mutual
benefits and covenants contained herein, the parties agree as follows:
1. Section 4.1 of the FT-NN Agreement shall be deleted in its entirety
and the following Section 4.1 substituted therefor:
"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 August
31, 2003, 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 365 days prior to the end of the primary
term or any subsequent yearly extension."
2. Except as provided herein, the Agreement shall remain in full force
and effect as written.
3. 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 mater hereof.
4. This Amendment shall be binding on the parties' respective
successors and assigns.
<PAGE>
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/ James J. Cleary By: /s/ James E. Moylan, Jr.
Title: Vice President Title: President
ATTEST: CHATTANOOGA GAS COMPANY
By: /s/ Melanie M. Platt By: /s/ Harrison F. Thompson
Title: V. P. and Corp. Secy. Title: President
- 2 -
Exhibit 10.6
[LETTERHEAD OF SOUTHERN NATURAL GAS COMPANY APPEARS HERE]
SOUTHERN NATURAL GAS
April 21, 1997
Mr. Stephen J. Gunther
President
AGL Energy Services, Inc.
Post Office Box 4569
Atlanta, Georgia 30302-4569
Dear Steve:
This letter is to clarify Southern's position on various
items that we have recently discussed regarding service
levels to Atlanta Gas Light Company ("AGL") as a result of
Southern's upcoming expansion filing of approximately 65,000
Mcf/d to serve customers in East Tennessee and elsewhere in
Zones 3 and 2 (the "ET Phase II Filing"). To this end,
Southern confirms the following items:
1. Southern will design its facilities for the ET
Phase II Filing in a manner that will enable
Southern to provide deliveries to AGL's Marietta
meter station of 4,000 Mcf of gas per hour on a
steady state basis at a pressure of not less than
300 psig once such facilities are placed in
service. Such deliveries would be within AGL's firm
transportation capacity of 355,814 Mcf/d for the
Atlanta Area, as described in Exhibit B to AGL's
Service Agreement Nos. 904460, 904461, and 902470.
2. The facilities in the ET Phase II Filing will be
designed to enable Southern to provide
approximately 65,000 Mcf/d of additional firm
service to Zones 2 and 3. Based on its TGNET gas
flow model, Southern expects that the level of IT
service to delivery points in Zone 3 will be as set
forth in the attached schedule upon installation of
the facilities in the ET Phase II filing. While
this reflects Southern's best estimate, based on
our gas flow model, of the expected level of IT
services that will be available to Zone 3 with the
installation
<PAGE>
[LETTERHEAD OF SOUTHERN NATURAL GAS COMPANY APPEARS HERE]
Mr. Stephen J. Gunter
April 21, 1997
Page 2
of the ET Phase II facilities, the actual level of
IT service to delivery points in Zone 3 will depend
upon a number of factors including, among other
things, the physical gas flows, future gas loads,
future expansion facilities, and the IT allocation
method utilized. Under the IT allocation method
currently utilized, the IT loss in the Atlanta Area
due to the ET Phase II expansion would be a
pro-rata share of the IT loss in Zone 3 (based on
the Atlanta group's IT allocation per such method
compared to the total IT allocated to Zone 3 under
such method). Southern acknowledges that neither it
nor AGL has agreed by this letter to maintain the
current IT allocation method in the future.
3. Southern clarifies its position that as long as AGL
retains at least 760,000 Mcf/d of long-term FT and
FT-NN contracts,
a. Southern will propose in its East Tennessee
Phase II Filing, and in future pipeline
expansions, a facilities design that preserves
the ability of AGL to shift up to 53,916 Mcf/d
of firm capacity on a preferred interruptible
("B-1") basis from AGL's Macon Area delivery
point to AGL's Atlanta Area delivery points.
b. Southern will defend such design(s) in its East
Tennessee Phase II Filing, and in future
pipeline expansions, if challenged at FERC, and
will oppose efforts by FERC Staff and/or other
intervenors to modify or alter the design of
such facilities in a manner that would reduce
or eliminate AGL's ability to shift up to
53,916 Mcf/d on a B-1 basis from the Macon Area
delivery point to AGL's Atlanta Area delivery
points.
If in the future AGL reduces its level of FT and
FT-NN contracts pursuant to Southern's initiation
of the right of first refusal procedures ("ROFR")
prior to September 1, 2002, as provided in Section
20 of Southern's tariff, the 760,000 Mcf/d
threshold described above will be reduced by the
amount of capacity relinquished by AGL as a result
of such ROFR
<PAGE>
[LETTERHEAD OF SOUTHERN NATURAL GAS COMPANY APPEARS HERE]
Mr. Stephen J. Gunter
April 21, 1997
Page 3
procedure(s), but not to exceed a reduction of
30,000 Mcf/d in the aggregate.
This provision does not apply to the ROFR
procedures initiated in connection with the ET
Phase II Filing. However, it is intended to allow
AGL some latitude with respect to its level of FT
and FT-NN in the future, while maintaining
Southern's agreement to propose and defend facility
designs in the ET Phase II Filing, and in future
pipeline expansions, which preserve the ability of
AGL to shift up to 53,916 Mcf/d of firm capacity on
a preferred interruptible ("B-1") basis from its
Macon Area delivery point to its Atlanta Area
delivery point.
If AGL has any questions about any of the above clarification
items or disagrees with any of them please advise us as soon
as possible.
Very truly yours,
SOUTHERN NATURAL GAS COMPANY
By: /s/ James J. Cleary
James J. Cleary
