SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1996 Commission File Number 1-9905
ATLANTA GAS LIGHT COMPANY
(Exact name of registrant as specified in its charter)
GEORGIA 58-0145925
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
303 Peachtree Street, N.E., Atlanta Georgia
30308 404-584-4000
(Address and zip code of principal (Registrant's telephone number,
executive offices) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Depositary Preferred Shares New York Stock Exchange
(Title of Class) (Name of exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock, $100 Par Value
Cumulative Preferred Stock, $100 Stated Value
(Title of Class)
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[ ]
The number of shares of Atlanta Gas Light Company Common Stock outstanding as of
November 29, 1996, was one share. All outstanding shares of Atlanta Gas Light
Company Common Stock are held by AGL Resources Inc.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of each of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
TABLE OF CONTENTS
Page
PART I
Item 1. Business............................................. 1
Item 2. Properties........................................... 13
Item 3. Legal Proceedings.................................... 13
Item 4. Submission of Matters to a Vote of Security
Holders............................................ 15
PART II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters........................ 16
Item 6. Selected Financial Data.............................. 17
Item 7. Management's Discussion and Analysis of Results
of Operations and Financial Condition.............. 18
Item 8. Financial Statements and Supplementary Data.......... 26
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................ 49
PART III
Item 10. Directors and Executive Officers of the Registrant... 50
Item 11. Executive Compensation............................... 51
Item 12. Security Ownership of Certain Beneficial Owners and
Management......................................... 56
Item 13. Certain Relationships and Related Transactions....... 58
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K ....................................... 59
Signatures ...................................................... 66
Part I
Item 1. Business
GENERAL
Atlanta Gas Light Company (AGLC) was incorporated on February 16, 1856,
by a special act of the Georgia General Assembly. On March 6, 1996, AGLC
completed a corporate restructuring in which a new company, AGL Resources Inc.
(AGL Resources) became the holding company for AGLC, a natural gas distribution
utility and its subsidiaries. During the third and fourth quarters of fiscal
1996, ownership of AGLC's nonregulated businesses was transferred to AGL
Resources and its various subsidiaries. See Note 1 in Notes to Consolidated
Financial Statements on page 32 of this Form 10-K. Unless noted specifically or
otherwise required by context, references to AGLC include the operations and
activities of AGLC and Chattanooga Gas Company, a wholly owned natural gas
utility subsidiary of AGLC (Chattanooga).
AGLC is engaged in the distribution of natural gas to customers in
central, northwest, northeast and southeast Georgia and the Chattanooga,
Tennessee area. AGLC's major service area is the ten county metropolitan Atlanta
area. Metropolitan Atlanta has an estimated population of 3 million,
constituting approximately 41% of the total population of Georgia. Approximately
66% of AGLC's customers are located in the Atlanta metropolitan area. These
customers consume 48% of the natural gas sold and transported and provide
approximately 60% of the gas revenues of AGLC. AGLC's other principal service
areas in Georgia are the Athens, Augusta, Brunswick, Macon, Rome, Savannah and
Valdosta areas. During the fiscal year ended September 30, 1996, AGLC supplied
natural gas service to an average of approximately 1.3 million customers in
Georgia including 516 centrally metered customers serving 50,098 apartment
units. AGLC provides natural gas service in 235 cities and surrounding areas in
Georgia. In addition to AGLC's service areas in Georgia, natural gas service was
supplied by Chattanooga to an average of approximately 52,000 customers in
Chattanooga and Cleveland, Tennessee, and surrounding portions of Hamilton
County and Bradley County, Tennessee during the fiscal year ended September 30,
1996. All of AGLC's natural gas service area is certificated by the Georgia
Public Service Commission (Georgia Commission) and the Tennessee Regulatory
Authority (TRA), formerly the Tennessee Public Service Commission.
The areas served by AGLC in Georgia outside the metropolitan areas
described in the preceding paragraph were for many years primarily agricultural,
with timber, poultry, cattle, cotton, tobacco, peanuts and soy beans among the
principal products. However, both industry and agriculture are currently
important to the economies of these areas. In addition to the industries that
use local natural resources such as pulpwood, clay, marble, talc and kaolin,
AGLC serves a number of nationally known organizations that operate
installations in Georgia. These operations increase substantially the
diversification of industry in AGLC's service area.
During fiscal 1996, AGLC added approximately 41,500 customers, based on
12-month average calculations, representing an increase over the prior year of
approximately 3%. Substantially all of this growth was in the residential and
small commercial service categories.
The ten largest customers of AGLC accounted for 1.9% and 1.4% of total
operating revenues and operating margin, respectively, for the fiscal year ended
September 30, 1996. For the same period, volumes of gas sold and transported to
the ten largest customers accounted for 10.6% of total volumes of gas sold and
transported.
AGLC's consolidated operating revenues during the fiscal year ended
September 30, 1996, were $1.2 billion, of which approximately 58% was derived
from residential customers, 24% from commercial customers, 15% from industrial
customers, 2% from transportation customers and 1% from other sources.
1
Through September 30, 1996, historic maximum daily sendout of natural gas
was approximately 2.15 billion cubic feet which occurred on February 4, 1996.
The mean temperature in the metropolitan Atlanta area that day was 11(degree) F.
AGLC's business is highly seasonal in nature and heavily dependent on weather
because of the substantial use of gas for heating purposes. However, AGLC has
implemented weather normalization adjustment riders. The weather normalization
adjustment riders, which were approved by the Georgia Commission and the TRA,
offset the impact that either unusually cold or unusually warm weather has on
operating margin, earnings and cash flow and are designed to stabilize operating
margin and earnings at the levels which would occur with normal weather. For the
effects of seasonal variations on quarterly earnings, see Note 14 in Notes to
Consolidated Financial Statements on page 47 of this Form 10-K.
On September 30, 1996, AGLC and its subsidiaries had 2,383 employees.
Approximately 640 employees working for AGLC are covered by provisions of
collective bargaining agreements with the General Teamsters Local Union No. 528.
The master agreement, among the Teamsters, AGLC and AGL Resources Service
Company (Service Company), provides for a $1,000 lump sum payment to each
covered employee in October 1996 and a $500 lump sum payment in September 1997
and 1998. In addition, the pay ranges for all covered positions are scheduled to
increase 3% in September 1997 and 1998 and 3.5% in 1999. Based on current pay
levels, it is anticipated that few covered employees will see any base rate
increases until 1999. That agreement expires September 17, 2000.
A five-year collective bargaining agreement among AGLC, Service Company
and the International Union of Operating Engineers, Local Union No. 474,
covering 60 employees in Savannah, Georgia, was ratified on November 14, 1996.
The contract provides for a $1,000 lump sum payment to each covered employee in
November 1996 and a $500 lump sum payment in November 1997 and 1998. In
addition, the pay ranges for all covered positions are scheduled to increase 3%
in September 1997 and 1998, 3.5% in 1999, and 3% in the year 2000. Based on
current pay levels, it is anticipated that few covered employees will see any
base rate increases until 1998. That agreement expires November 4, 2001.
Additionally, AGLC has approximately 60 employees at its Chattanooga and
Cleveland, Tennessee facilities covered by an agreement with the Utility Workers
Union of America, Local Union No. 461. A new five-year agreement with the
Utility Workers became effective October 15, 1996. The agreement provides for a
$1,000 lump sum payment to each covered employee in November 1996 and a $500
lump sum payment in October 1997 and 1998. In addition, the pay ranges for all
covered positions are scheduled to increase 3% in September 1997 and 1998, 3.5%
in 1999, and 3% in the year 2000. Based on current pay levels, it is anticipated
that few covered employees will see any base rate increases until 1998. That
agreement expires October 14, 2001.
AGLC holds franchises, permits, certificates and rights which management
believes are sufficient for the operation of its properties without any
substantial restrictions and adequate for the operation of its gas distribution
business.
FORMATION OF HOLDING COMPANY
As a result of the formation of the holding company, ownership of
nonregulated businesses was transferred from AGLC to AGL Resources and various
subsidiaries of AGL Resources. Ownership of Georgia Gas Company (natural gas
production activities) has been transferred to AGL Energy Services, Inc. (AGL
Energy Services). Ownership of Georgia Energy Company (natural gas vehicle
conversions), Georgia Gas Service Company (retail propane sales) and Trustees
Investments, Inc. (real estate holdings) has been transferred to AGL
Investments, Inc. (AGL Investments). AGLC's interest in Sonat Marketing Company
L.P. has been transferred to AGL Gas Marketing, Inc., a wholly owned subsidiary
of AGL Investments. In addition, AGL Investments has established two wholly
owned subsidiaries: AGL Power Services, Inc., which owns a 35% interest in Sonat
Power Marketing, L.P., and AGL Consumer Services, Inc., an energy-related
consumer products and services company. 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. Prior to that transfer, the
aggregate net income contributed by nonregulated subsidiaries in fiscal 1996 was
$3.7 million.
2
Service Company was formed during fiscal 1996 to provide corporate
support services to AGL Resources and its subsidiaries. The transfer of related
assets from AGLC to Service Company and other nonregulated subsidiaries was
effected through a noncash dividend of $34.3 million during the fourth quarter
of fiscal 1996. Expenses of Service Company are allocated to AGL Resources and
its subsidiaries.
NEW JOINT VENTURE
During December 1996, AGL Resources signed a letter of intent with
Transcontinental Gas Pipe Line Corporation (Transco) to form a joint venture,
which would be known as Cumberland Pipeline Company, to operate and market
interstate pipeline capacity. The transaction is subject to various corporate
and regulatory approvals.
Initially, the 135-mile Cumberland pipeline will consist of existing
pipeline infrastructure owned by the two companies. Projected to enter service
by November 1, 2000, Cumberland will provide service to AGLC, Chattanooga and
other markets throughout the eastern Tennessee Valley.
Affiliates of Transco and AGL Resources each will own 50% of the new
pipeline company, and an affiliate of Transco will serve as operator. The
project will be submitted to the Federal Energy Regulatory Commission for
approval in the fourth quarter of 1997.
The remainder of this page was intentionally left blank.
3
Gas Sales and Statistics
FOR THE YEARS ENDED SEPTEMBER 30
1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues (Millions of Dollars)
Sales of gas
Residential ................................. $ 708.8 $ 610.6 $ 700.7 $ 658.2 $ 575.7
Commercial .................................. 288.8 243.2 285.8 268.1 231.5
Industrial .................................. 178.8 169.4 172.1 154.2 140.9
Transportation revenues ....................... 21.5 23.9 22.6 33.8 36.6
Miscellaneous revenues ........................ 19.7 15.9 18.7 16.0 9.9
- ---------------------------------------------------------------------------------------------------------------------
Total utility operating revenues .............. $ 1,217.6 $ 1,063.0 $ 1,199.9 $ 1,130.3 $ 994.6
=====================================================================================================================
Utility Throughput
Therms sold (Millions)
Residential ................................ 1,165.4 916.8 1,003.1 1,001.4 915.4
Commercial ................................. 538.2 454.0 478.9 478.5 433.9
Industrial ................................. 449.6 526.0 424.8 388.7 445.0
- ---------------------------------------------------------------------------------------------------------------------
Therms transported ............................ 738.7 722.8 697.4 795.6 901.8
- ---------------------------------------------------------------------------------------------------------------------
Total utility throughput .................. 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1
=====================================================================================================================
Average Utility Customers (Thousands)
Residential ................................... 1,289.4 1,250.4 1,215.2 1,182.7 1,152.2
Commercial .................................... 102.5 100.0 98.0 95.7 93.7
Industrial .................................... 2.6 2.6 2.5 2.5 2.5
- ---------------------------------------------------------------------------------------------------------------------
Total ..................................... 1,394.5 1,353.0 1,315.7 1,280.9 1,248.4
=====================================================================================================================
Sales, Per Average Residential Customer
Gas sold (Therms) ............................. 904 733 825 847 794
Revenue (Dollars) ............................. 550.00 488.32 576.61 556.52 499.65
Revenue per therm (Cents) ..................... 60.8 66.6 69.9 65.7 62.9
Degree Days - Atlanta Area
30-year normal ................................ 2,991 2,991 2,991 3,021 3,021
Actual ........................................ 3,191 2,121 2,565 2,852 2,552
Percentage of actual to 30-year normal ........ 106.7 70.9 85.8 94.4 84.5
Gas Account (Millions of Therms)
Natural gas purchased ......................... 1,632.9 1,406.9 1,453.6 1,629.9 1,555.4
Natural gas withdrawn from storage ............ 596.0 520.7 500.3 276.4 263.3
Gas transported ............................... 738.7 722.8 697.4 795.6 901.8
- ---------------------------------------------------------------------------------------------------------------------
Total send-out ............................ 2,967.6 2,650.4 2,651.3 2,701.9 2,720.5
Less
Unaccounted for ............................. 60.4 20.4 37.2 29.0 16.2
Company use ................................. 15.3 10.4 9.9 8.7 8.2
- ---------------------------------------------------------------------------------------------------------------------
Sold and transported to utility customers . 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1
=====================================================================================================================
Cost of Gas (Millions of Dollars)
Natural gas purchased ......................... $ 547.1 $ 389.4 $ 550.1 $ 595.7 $ 487.9
Natural gas withdrawn from storage ............ 171.6 182.4 186.7 105.3 102.6
- ---------------------------------------------------------------------------------------------------------------------
Cost of gas - utility operations .............. $ 718.7 $ 571.8 $ 736.8 $ 701.0 $ 590.5
=====================================================================================================================
Utility Plant - End of Year (Millions of Dollars)
Gross plant ................................... $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6 $ 1,634.8
Net plant ..................................... $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9 $ 1,157.4
Gross plant investment per customer
(Thousands of Dollars) ...................... $ 1.4 $ 1.4 $ 1.4 $ 1.4 $ 1.3
Capital Expenditures (Millions of Dollars) ...... $ 132.5 $ 121.7 $ 122.5 $ 122.2 $ 132.9
Gas Mains - Miles of 3" Equivalent .............. 29,045 28,520 27,972 27,390 26,936
Employees - Average ............................. 2,883 3,191 3,711 3,721 3,764
Average Btu Content of Gas ...................... 1,024 1,027 1,032 1,027 1,024
=====================================================================================================================
4
GAS SUPPLY SERVICES, PRICING AND COMPETITION
General
AGLC is served directly by four interstate pipelines: Southern Natural Gas
Company (Southern), South Georgia Natural Gas Company (South Georgia),
Transcontinental Gas Pipe Line Corporation (Transco) and East Tennessee Natural
Gas Company (East Tennessee), in combination with its upstream pipeline,
Tennessee Gas Pipeline Company (Tennessee) ,the parent company and primary
source of gas for East Tennessee.
As a result of Order 636, gas purchasing decisions made by local
distribution companies (LDCs) are subject to greater review by state regulatory
commissions. However, out of the 1994 Georgia General Assembly, legislation was
enacted which provides for annual review and approval by the Georgia Commission
of AGLC's gas services portfolio on a prospective basis. On August 1, 1996, AGLC
made its annual gas supply plan filing for fiscal 1997 and on September 13,
1996, the Georgia Commission issued its order approving the mix of gas services
in the portfolio.
Additionally, AGL Energy Services was formed to provide consulting and
energy management services to AGL Resources' regulated operations and to other
nonregulated gas marketers. Through innovative management of gas supply assets
that maximize off-system sales, AGL Energy Services is expected to boost AGL
Resources' operating margins. For example, the TRA has approved a gas supply
incentive mechanism under which the net margin associated with off-system sales
is shared equally between Chattanooga and its firm customers.
Firm Pipeline Transportation and Underground Storage
The table on the following page shows the amount of firm transportation
and describes the types and amounts of underground storage that both AGLC and
Chattanooga have elected or been assigned under Order 636. The table also shows
services that were not affected by the implementation of Order 636.
The remainder of this page was intentionally left blank.
5
Production Area Supplemental
Underground Underground
Maximum Storage Storage
Firm Maximum Maximum
Transportation Withdrawal Withdrawal Expiration
Mcf/Day Mcf/Day(1) Mcf/Day(2) Date
------- ------- ------- -------
ATLANTA GAS LIGHT COMPANY
- -------------------------
Southern
Firm Transportation 1,000 June 30, 2007
Firm Transportation 604,857 February 28, 1999
Firm Transportation 45,272 February 29, 2000
Firm Transportation 110,905 April 30, 2007
CSS 382,089 February 28, 1999
CSS 24,133 February 29, 2000
ANR - 50 113,000 March 31, 2003
ANR - 100 55,500 March 31, 2003
Transco
Firm Transportation 107,600 March 31, 2010
Firm Transportation 15,000 July 1, 2005
Firm Transportation 6,222 March 17, 2008
Firm Transportation 4,500 October 31, 2009
WSS 70,588 March 31, 2010
Eminence Storage 11,263 March 31, 1997
Eminence Storage 19,034 October 31, 2013(3)
GSS 57,016 June 30, 2001(3)
GSS 67,919 March 31, 2013(3)
LSS 17,430 March 31, 1994(4)
SS-1 20,211 March 31, 2009
LGA 41,522 October 31, 1991(4)
Cove Point LNG 66,667 April 15, 1997
Other 14,493 March 31, 2001
Other 4,831 March 31, 1997
Tennessee/East Tennessee
Firm Transportation 62,000 November 1, 2000(3)
FS Storage 29,485 November 1, 2000
CNG 3,321 March 31, 2001
South Georgia
Firm Transportation 11,877 April 30, 2007
ANR - 100 708 March 31, 2003
CSS 6,764 February 28, 1998
------- ------- -------
Total 969,233 546,677 459,297
======= ======= =======
CHATTANOOGA GAS COMPANY
- -----------------------
Southern
Firm Transportation 4,649 February 28, 2000
Firm Transportation 14,051 February 28, 2000
Firm Transportation 3,300 April 30, 2007
CSS 14,051 February 28, 2000
Tennessee/East Tennessee
Firm Transportation 45,000 November 1, 2000(3)
FS Storage 20,802 November 1, 2000
CNG 2,411 March 31, 2001
------- -------
Total 67,000 37,264
======= =======
(1) Production area storage requires a complementary amount of the firm
transportation capacity identified in the first column to move storage gas
withdrawals to AGLC's service area.
(2) Supplemental underground storage withdrawals include delivery to AGLC's
service area and do not require any of the firm transportation capacity
identified in the first column. Injections into supplemental " underground
storage require incremental transportation, primarily from transportation
identified in Column 1."
(3) Expiration dates are shown for these contracts although contracts have not
yet been executed. AGLC is operating under Natural Gas Act (NGA) certificate
authority while negotiating these contracts.
(4) AGLC is operating under NGA certificate authority while negotiating these
contracts.
6
Wellhead Supply
AGLC and Chattanooga have entered into firm wellhead supply contracts of
442,973 Mcf/day and 27,427 Mcf/day, respectively, to supply their firm
transportation and underground storage requirements. AGLC anticipates entering
into additional firm wellhead supply contracts by the end of December 1996 of up
to 58,851 Mcf/day for AGLC and 6,342 Mcf/day for Chattanooga. AGLC also
purchases spot market gas as needed during the year.
Liquefied Natural Gas
To meet the demand for natural gas on the coldest days of the winter
months, AGLC must also maintain sufficient supplemental quantities of liquefied
natural gas (LNG) in its supply portfolio. AGLC's three strategically located
Georgia-based LNG plants -- north and south of Atlanta and near Macon --
currently provide a combined maximum daily supplement of 665,000 Mcf and a
combined usable storage capacity of 72 million gallons, equivalent to 6,214,921
Mcf. This combined maximum daily supplement is expected to increase to 765,000
Mcf in January 1997 with the installation of additional equipment at the LNG
plant north of Atlanta. Chattanooga's LNG plant provides a maximum daily
supplement of 90,000 Mcf and has a usable storage capacity of 13 million
gallons, equivalent to 1,207,574 Mcf.
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.
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.
7
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 approximately 50 Negotiated Contracts. Additionally, the
Georgia Commission has approved Special Contracts between AGLC and five
interruptible customers.
For additional information regarding competitive initiatives in Georgia,
see Part I, Item 1, "Business State Regulatory Matters."
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 7, 1996, the TRA
hearing officer recommended approval of 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.
FEDERAL REGULATORY MATTERS
Order 636
On July 16, 1996, the United States Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) issued its ruling in UNITED DISTRIBUTION COS. V.
FERC, concerning the appeals from Order No. 636, which mandated the unbundling
of interstate pipeline sales service and established new open access
transportation regulations. The court generally upheld the Federal Energy
Regulatory Commission's (FERC) orders against a broad array of challenges, but
remanded the orders to the FERC for reconsideration of certain issues, including
the FERC's decision to permit pipelines to pass all of their gas supply
realignment (GSR) costs through to their customers and its decision to require
interruptible transportation customers to bear 10% of GSR costs. The FERC has
not yet issued an order on remand, and thus it is not known whether the FERC
will change its GSR policies. On October 29, 1996, the D.C. Circuit rejected
requests for rehearing filed by AGLC and others, which sought reversal of the
court's ruling affirming the FERC's authority over capacity release by LDCs. The
court's order is subject to possible further proceedings before the United
States Supreme Court.
AGLC, based on filings with FERC by its pipeline suppliers, currently
estimates that its portion of transition costs, costs that previously were
recovered in the pipelines' rate for bundled sales services, from all of its
pipeline suppliers would be approximately $109.9 million. Such filings currently
are pending before FERC for final approval, and the transition costs are being
collected subject to refund. Approximately $80.6 million of such costs have been
incurred by AGLC as of September 30, 1996, and are being recovered from its
customers under the purchased gas provisions of AGLC's rate schedules.
Transition costs have not affected the total cost of gas to AGLC's customers
significantly because (1) AGLC purchases its wellhead gas supplies based on
market prices that are below the cost of gas previously embedded in the bundled
pipelines' sales service rates and (2) many elements of transition costs
previously were embedded in the rates for the pipelines' bundled sales service.
See Part I, Item 1, "State Regulatory Matters - Gas Supply Filing" in this Form
10-K for further discussion of recovery of gas costs.
Details concerning the status of the Order 636 restructuring proceedings
involving the pipelines that serve AGLC directly are set forth below.
8
SOUTHERN
Restructuring Proceeding.
AGLC has filed several petitions for review with the D. C. Circuit
concerning various aspects of Southern's restructuring. Those aspects include
favorable treatment of small customers, rate mitigation, mitigation of GSR
costs, and tying of firm storage service to firm transportation service. AGLC
has moved to withdraw those petitions for review in light of the FERC's approval
of the restructuring settlement between Southern and its customers, as discussed
below, but the court has not yet acted on AGLC's motion.
GSR Cost Recovery Proceeding.
On April 11, 1996, the FERC issued an order constituting final approval of
the settlement agreement between AGLC, Southern, and other customers which
resolves virtually all pending Southern proceedings before the FERC and the
courts. The settlement resolves Southern's pending general rate proceedings,
which relate to Southern's rates charged from January 1, 1991, through the
present. The settlement provides for rate reductions and refund offsets against
GSR costs. It also resolves Southern's Order No. 636 transition cost proceedings
and provides for revisions to Southern's tariff. The FERC's approval of the
settlement is subject to action on petitions for review filed by parties
opposing the settlement.
On April 25, 1996, the FERC issued an order accepting Southern's March
29, 1996, filing to reduce its volumetric GSR surcharge for consenting parties
to the restructuring settlement to reflect actual GSR costs incurred by Southern
through December 31, 1995. 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,
GSR and other transition cost charges to AGLC are in accordance with the
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 $85.5
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
September 30, 1996, $70.9 million of such costs have already been incurred by
AGLC.
TENNESSEE
Restructuring Proceeding.
AGLC has filed several petitions for review with the D. C. Circuit
concerning various aspects of Tennessee's restructuring. Those aspects include
favorable treatment for small customers, rate mitigation and others. AGLC also
has filed a petition for review of FERC orders concerning Tennessee's service
obligation to AGLC. AGLC's petitions for review currently are pending with the
court.
GSR Cost Recovery Proceeding.
Tennessee has made several quarterly GSR recovery filings. AGLC's estimated
liability as a result of Tennessee's prior GSR recovery filings is approximately
$16.8 million, assuming that the FERC does not change its GSR policies pursuant
to the Order No. 636 remand and subject to possible reduction based on the
hearing FERC established to investigate Tennessee's costs. AGLC is actively
participating in Tennessee's GSR cost recovery proceeding. As of September 30,
1996, $5.4 million of such costs have been incurred by AGLC.
Columbia Gas Transmission Corporation.
AGLC has filed a petition for review of a FERC order approving a settlement
between Tennessee and Columbia Gas Transmission Corporation (Columbia). The
settlement resolves issues relating to Columbia's upstream capacity on
Tennessee's system, as well as certain other matters between the two pipelines.
AGLC has sought review of the order on the ground that the FERC has failed to
ensure that Tennessee's customers will be made whole with respect to Tennessee's
agreement to permit Columbia to abandon certain contracts for capacity on
Tennessee's system.
FERC Rate Proceedings
AGLC also is participating in various rate proceedings before the FERC
involving applications for rate changes filed by its pipeline suppliers. To the
extent that these cases have not been settled, as described below, the rates
filed in these proceedings have been accepted, and made effective subject to
refund and the outcome of the FERC proceedings.
SOUTHERN
As noted above, the FERC has approved the restructuring settlement
agreement between AGLC, Southern, and other customers that resolves all issues
between AGLC and Southern for Southern's outstanding rate proceedings.
9
SOUTH GEORGIA
On December 20, 1995, the FERC issued an order upholding an initial
decision by an administrative law judge (ALJ) in South Georgia's rate case that
South Georgia's interruptible transportation (IT) rate should be based on a load
factor of 100% on a prospective basis. AGLC supported the 100% load factor IT
rate at the hearing in this proceeding. No party has sought rehearing of the
FERC's ruling, which is therefore final.
TENNESSEE
On April 5, 1996, Tennessee filed with the FERC a comprehensive settlement
to resolve all issues in its current rate case. The settlement provides for a
reduction of approximately $83 million in the cost of service underlying
Tennessee's rates in effect since July 1, 1995, and also provides for Tennessee
to share a portion of costs associated with firm capacity relinquished by its
customers. AGLC filed comments supporting the settlement. AGLC's estimated
annual reduction in cost is $2.2 million. The FERC approved the proposed
settlement on October 30, 1996, but the order approving the settlement is
pending requests for rehearing and therefore is not yet final.
On July 3, 1996, the FERC issued an order on exceptions from the rulings
of an ALJ in a prior Tennessee rate case. Among other things, the FERC's order,
which is to have prospective effect, rejects a proposal to unbundle Tennessee's
production area rates from its market area rates. AGLC supported the unbundling
proposal. The order also upholds the ALJ's ruling that Tennessee's interruptible
transportation rates should be set at the 100% load factor derivative of the
firm transportation rate. AGLC supported the 100% load factor proposal. The
order also rejects proposals to revise Tennessee's rate zone boundaries. AGLC
has opposed such proposals. The FERC's rulings may impact the rates contained in
the settlement agreement in Tennessee's FERC rate case, which was approved by
the FERC on November 1, 1996. The FERCs order approving the settlement is
pending requests for rehearing and therefore is not yet final.
TRANSCO
On June 19, 1996, Transco filed a proposed partial settlement to resolve
cost of service and throughput issues in its current rate case. The partial
settlement reserves certain cost allocation and rate design issues for hearing,
including roll-in of Transco's incrementally priced Leidy Line facilities and
Transco's use of the straight-fixed-variable rate design methodology. The
proposal provides for a reduction of approximately $58 million in the cost of
service underlying Transco's rates that have been in effect since September 1,
1995. The estimated annual reduction in costs to AGLC is $2.4 million. AGLC
filed comments in support of the proposed settlement, which was approved by the
FERC on November 1, 1996. The FERC's order approving the settlement is pending
requests for rehearing and therefore is not yet final.
On July 3, 1996, the FERC issued an order on exceptions from the rulings
of an ALJ in a prior Transco rate case. Among other things, the FERC's order,
which is to have prospective effect, rejects Transco's proposal to established a
firm-to-the-wellhead production area rate design, but permits Transco to file a
rate case to establish firm-to-the-wellhead rates if customers with entitlements
to production area capacity are permitted to determine whether they require such
capacity in an open season. AGLC opposed Transco's firm-to-the-wellhead
proposal. The order also reverses the ALJ's ruling that Transco must establish a
separate production area cost of service. AGLC had filed exceptions seeking
reversal of this aspect of the ALJ's ruling. AGLC has joined other Transco
customers in seeking rehearing of the July 3, 1996 order with respect to the
FERC's determination that Transco may file a new proposal to establish
firm-to-the-wellhead rates, and also has sought clarification that the FERC's
order does not eliminate protections against abandonment that originated in the
settlements by which AGLC and other customers agreed to convert from sales to
firm transportation service.
On November 1, 1996, Transco filed to increase its rates by approximately
$83 million over the last rates approved by the FERC. Among other things,
Transco filed its own proposal to roll into systemwide rates the costs of the
incrementally-priced Leidy Line and Southern Expansion facilities on a
prospective basis, after a hearing. AGLC filed a protest challenging the roll-in
proposal and the magnitude of the requested rate increase. On November 29, 1996,
the FERC issued an order accepting Transco's filing, subject to refund and a
hearing, and consolidated Transco's roll-in proposal with its ongoing rate case,
where a Leidy Line roll-in proposal by other parties is being litigated.
ANR PIPELINE
ANR Pipeline (ANR) provides transportation services to Southern under a
case-specific certificate issued by the FERC in 1980. Southern entered into this
transportation arrangement with ANR in order to provide Southern's customers,
including AGLC, access to storage facilities owned and operated by ANR Storage
Company. According to Southern, approximately 96% of Southern's service
entitlement on ANR is used to serve AGLC. AGLC has actively participated in the
hearing procedures established by the FERC
10
with respect to ANR's general rate proceeding, supporting a reduced
transportation rate for ANR's services to Southern. That proceeding currently is
pending for decision before an ALJ.
Miscellaneous
SECONDARY MARKETS
On July 31, 1996, the FERC issued a notice of proposed rulemaking
concerning changes to the FERC's regulations governing release of firm pipeline
capacity, as well as the sale by pipelines of interruptible transportation and
short-term firm capacity. The FERC is not proposing to eliminate the prohibition
against pricing released capacity at higher than the pipeline's maximum tariff
rate for firm service. However, the FERC has solicited applications from
pipelines and local distribution companies to participate in a pilot program in
which the prices for released firm capacity, interruptible transportation, and
short-term firm capacity are not capped. AGLC has not sought permission to
participate in the pilot program, but is monitoring the process. One of AGLC's
pipeline suppliers, Transco, sought approval to participate in the pilot
program, but the FERC rejected Transco's application.
NEGOTIATED RATES
The FERC has issued a policy statement authorizing pipelines to establish
mechanisms by which they may charge separately negotiated rates to particular
customers in lieu of their tariff rates. The FERC has required pipelines to
retain in their tariffs a "recourse rate," which must be approved by the FERC,
and which must be available to those customers that do not choose to separately
negotiate a rate with the pipeline. Of the pipelines that supply AGLC, Transco,
Tennessee, and East Tennessee have requested authority to separately negotiate
rates. The FERC has approved the applications by Transco, Tennessee, and the
application filed by East Tennessee. The FERC's policy statement has been
appealed to the D. C. Circuit, and AGLC has intervened in that proceeding.
Arcadian
The FERC has granted final approval to the settlement between Southern
and Arcadian Corporation (Arcadian); see Part I, Item 3, "Legal Proceedings."
The settlement resolves both Arcadian's FERC complaint against Southern and
Arcadian's antitrust lawsuit against Southern and AGLC. The settlement provides
for Southern to provide firm transportation service to Arcadian at a negotiated
rate for an initial term of five years ending October 31, 1998. In addition, the
settlement establishes tariff language addressing the conditions under which
Southern will address future requests for direct transportation service. AGLC
sought rehearing of the FERC's order approving the settlement but the FERC
rejected AGLC's rehearing request on November 26, 1996. AGLC had petitioned for
review of the FERC's prior orders in this proceeding in the United States Court
of Appeals for the Eleventh Circuit. AGLC's appeals have been held in abeyance
pending action by the FERC on AGLC's rehearing request. If the FERC's orders
approving the restructuring settlement between Southern, AGLC and the other
customers are upheld on appeal, it will resolve the undue discrimination issue
raised by AGLC in Southern's current rate case.
On April 22, 1996, AGLC filed to withdraw portions of its request for
rehearing of the FERC's order approving the November 12, 1993, settlement
between Arcadian and Southern. The portions of the request for rehearing that
AGLC proposes to withdraw, pursuant to the restructuring settlement with
Southern, are those that allege that Southern's discounted rates to Arcadian
constitute an anticompetitive "price squeeze" against AGLC.
AGLC cannot predict the outcome of these federal proceedings nor
determine the ultimate effect, if any, such proceedings may have on AGLC.
STATE REGULATORY MATTERS
Atlanta Gas Light Company
REGULATORY REFORM INITIATIVES
Two regulatory reform initiatives are pending in Georgia, both designed
to increase competition and reduce the role of regulation within the natural gas
industry. The first such initiative is the subject of a proceeding at the
Georgia Commission; the second initiative is before study committees of the
Georgia General Assembly.
11
With respect to the first initiative, on November 20, 1995, the Georgia
Commission issued a Natural Gas Notice of Inquiry soliciting comments on how to
introduce more competition into natural gas markets within Georgia. Following
written comments and oral presentations from numerous parties, on May 21, 1996,
the Georgia Commission adopted a Policy Statement that, among other things, sets
up a distinction between competitive and natural monopoly services; favors
performance-based regulation in lieu of traditional cost-of-service regulation;
calls for unbundling interruptible service; directs the Georgia Commission 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, on June 10, 1996, AGLC filed a comprehensive plan for serving
interruptible markets called the Natural Gas Service Provider Selection Plan
(the Plan). 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 marketing affiliates of
utilities. Hearings on the proposal began in December 1996 and are scheduled to
resume in January and February 1997. A decision is expected from the Georgia
Commission prior to March 1, 1997.
The second major initiative to increase competition and decrease the role
of regulation in Georgia is before study committees of the Georgia General
Assembly. The 1996 Georgia General Assembly considered, but delayed action on,
The Natural Gas Fair Pricing Act, which would have allowed local gas companies
to negotiate contract prices and terms for gas services with large commercial
and industrial customers absent Georgia Commission-mandated rates. The Georgia
General Assembly stated through resolutions a desire to fashion a more
comprehensive approach to deregulation and unbundling of natural gas services in
Georgia. Those resolutions, adopted during the 1996 session, created Senate and
House committees to study and recommend a comprehensive course of action by
December 31, 1996, for deregulating natural gas markets in Georgia.
The separate Senate and House study committees conducted joint meetings
during September, October and November 1996, with the goal of crafting a
comprehensive deregulation bill for the 1997 General Assembly, which convenes in
January 1997. The natural gas deregulation plan under consideration by the
committees would unbundle services to all of AGLC's natural gas customers, would
continue AGLC's role as the intrastate transporter of natural gas, would allow
AGLC to assign firm delivery capacity to certificated marketers who would sell
the gas commodity, and would create a secondary transportation market for
interruptible transportation capacity.
Although AGLC cannot predict the outcome of these two regulatory reform
initiatives, it supports both the plan under consideration by the Georgia
Commission and the plan under consideration by the Georgia General Assembly.
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 COST RECOVERY FILING
Pursuant to legislation enacted by the Georgia General Assembly, each
investor-owned local gas distribution company is required to file on or before
August 1 of each year, a proposed gas supply plan for the subsequent year, as
well as a proposed cost recovery factor to be used during the same time period.
Costs of natural gas supply, interstate transportation and storage incurred
pursuant to an approved plan may be recovered under the purchased gas provisions
of AGLC's rate schedules.
On August 1, 1996, AGLC filed its 1997 Gas Supply Plan, which consists of
gas supply, transportation and storage options designed to provide reliable
service to firm customers at the best cost. On September 13, 1996, the Georgia
Commission approved the entire supply portfolio contained in the 1997 Gas Supply
Plan.
12
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue
limited gas supply hedging activities. The 1997 hedging program has been
expanded beyond the program approved in the 1996 Gas Supply Plan. The financial
results of all hedging activities are passed through to firm service customers
under the purchased gas provisions of AGLC's rate schedules. Accordingly, there
is no earnings impact as a result of the hedging program.
Chattanooga Gas Company
RATE FILINGS
On May 1, 1995, Chattanooga filed a rate proceeding with the TRA seeking
an increase in revenues of $5.2 million annually. On September 27, 1995, a
settlement agreement was reached that provides for an annual increase in
revenues of approximately $2.5 million, effective November 1, 1995.
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Item 2. Properties
AGLC's properties consist primarily of distribution systems and related
facilities and local offices serving 230 cities and surrounding areas in the
State of Georgia and 12 cities and surrounding areas in the State of Tennessee.
As of September 30, 1996, AGLC had 25,642 miles of mains and 5,952,000 Mcf of
LNG storage capacity in three LNG plants to supplement the gas supply in very
cold weather or emergencies. Chattanooga had 1,328 miles of mains and 1,076,000
Mcf of LNG storage capacity in its one LNG plant.
At September 30, 1996, AGLC's gross utility plant amounted to
approximately $2.0 billion.
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Item 3. Legal Proceedings
The nature of AGLC's business ordinarily results in periodic regulatory
proceedings before various state and federal authorities as well as litigation
incidental to the business. For information regarding regulatory proceedings,
see the preceding sections in Part I, Item 1, "Business - Federal Regulatory
Matters" and "Business - State Regulatory Matters."
Arcadian
ARCADIAN CORPORATION V. SOUTHERN NATURAL GAS COMPANY AND ATLANTA GAS LIGHT
COMPANY, U. S. District Court for the Southern District of Georgia, Augusta
Division, Case No. CV192-006. On January 10, 1992, Arcadian, an industrial
customer of AGLC, filed a complaint against Southern and AGLC alleging violation
of the federal antitrust laws and seeking treble damages in excess of $45
million. In the complaint, Arcadian alleged that Southern and AGL conspired to
restrain trade by agreeing not to compete in the provision of direct
transportation service to end users in the areas served by AGLC. AGLC denied the
allegations of the complaint.
On November 30, 1993, a proposed settlement between Southern and
Arcadian was filed with FERC that would resolve both Arcadian's FERC complaint
against Southern and Arcadian's antitrust lawsuit against Southern and AGLC. The
settlement provided for firm and interruptible transportation service from
Southern to Arcadian at discounted rates for an initial term of five years. In
addition, the settlement establishes tariff conditions for addressing future
requests for direct transportation service. In connection with the proposed
settlement, the antitrust lawsuit has been stayed and administratively closed.
On May 12, 1994, FERC approved the settlement over AGLC's objections. AGLC has
sought rehearing of the FERC's order approving the settlement, and has
petitioned for review in the United States Court of Appeals for the Eleventh
Circuit. AGLC's appeals are currently being held in abeyance pending action by
the FERC on AGLC's rehearing request.
On April 22, 1996, AGLC filed to withdraw portions of its request for
rehearing of the FERC's order approving the November 12, 1993, settlement
between Arcadian and Southern. The arguments that AGLC proposes to withdraw,
pursuant to the restructuring settlement with Southern, are those that allege
that Southern's discounted rates to Arcadian constitute an anticompetitive
"price squeeze" against AGLC.
13
Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all or
part of a manufactured gas plant (MGP) site. These sites are located in Athens,
Augusta, Brunswick, Griffin, Macon, Rome, Savannah, Valdosta and Waycross. In
addition, AGLC has identified three other sites in Georgia which AGLC does not
now own, but that may have been associated with the operation of MGPs by AGLC or
its predecessors. These sites are located in Atlanta (2) and Macon. A
Preliminary Assessment (PA) was conducted at each of those twelve sites, and a
subsequent Site Investigation (SI) was conducted at ten sites (all but the two
Atlanta sites). Results from those investigations reveal environmental impacts
at and near nine sites (all but the two Atlanta sites and the second Macon
site).
In addition, AGLC has identified three sites in Florida which may have
been associated with AGLC or its predecessors. One of these, located in Sanford,
Florida, is now the subject of an Expanded Site Investigation (ESI) which has
been or is being conducted by the U.S. Environmental Protection Agency (EPA).
Investigations at the site by AGLC and others have indicated environmental
impacts on and near the site. In addition, the current owner of this site,
Florida Public Utilities Company (FPUC), had previously filed suit against AGLC
and others alleging that AGLC is a former "owner" and seeking to obtain a
declaratory judgment that all defendants are jointly and severally liable for
past and future costs of investigating and remediating the site. That suit has
since been dismissed by FPUC without prejudice.
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
obliged to investigate and, if necessary, remediate impacts at the site. AGLC
developed a proposed Corrective Action Plan (CAP) for the Griffin site, is now
conducting certain follow-up investigations in response to EPD's comments, and
expects to submit a revised CAP once EPD clarifies certain regulatory matters.
Assessment activities are being conducted at Augusta and Savannah. In addition,
AGLC is in the process of planning certain interim remedial measures at the
Augusta MGP site. Those measures are expected to be implemented principally
during fiscal 1997.
Second, AGLC's response to all Georgia sites is proceeding in substantial
compliance with Georgia's "Hazardous Site Response Act" (HSRA). AGLC submitted
to EPD formal notifications pertaining to all of its owned MGP sites, and EPD
had listed seven sites (Athens, Augusta, Brunswick, Griffin, Savannah, Valdosta
and Waycross) on the state's "Hazardous Site Inventory" (HSI). EPD has not
listed the Macon site on the HSI at this time. In addition, EPD has also listed
the Rome site on the HSI. Under the HSRA regulations, the four sites subject to
consent orders are presumed to require corrective action; EPD will determine
whether corrective action is required at the four remaining sites (Athens,
Brunswick, Rome and Waycross) in due course. In that respect, however, AGLC has
submitted Compliance Status Reports (CSRs) for the Athens, Brunswick and Rome
MGP sites, and AGLC has concluded that these sites do not meet applicable risk
reduction standards. Accordingly, some degree of response action is likely to be
required at those sites.
AGLC has estimated the investigation and remediation expenses likely to
be associated with the former MGP sites. First, since such liabilities are often
spread among potentially responsible parties, AGLC's ultimate liability will, in
some cases, be limited to AGLC's equitable share of such expenses under the
circumstances. Therefore, where reasonably possible, AGLC has attempted to
estimate the range of AGLC's equitable share, given AGLC's current knowledge of
relevant facts, including the current methods of equitable apportionment and the
solvency of potential contributors. Where such an estimation was not reasonably
possible, AGLC has estimated a range of expenses without adjustment for AGLC's
equitable share. Second, the regulatory structure of the cleanup requirements
under HSRA has permitted AGLC to estimate future investigation and remediation
costs for the Georgia MGP sites, assuming such costs arise under this framework.
Applying both of these concepts to those sites where some future action
presently appears reasonably possible, 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 $30.4
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 $110.8 million. If
14
additional sites were added to those for which action now appears reasonably
likely, or if substantially more stringent cleanups were required, or if site
conditions are markedly worse than those now anticipated, the costs could be
higher. In addition, those costs do not include other expenses, such as property
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 $30.4 million to $110.8 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 in 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 has undertaken a
financial and management process audit related to the MGP sites, cleanup
activities at the sites and environmental response costs that have been incurred
for purposes of the ERCRR. 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 intends to seek recovery of appropriate costs from its
insurers and other potentially responsible parties. With respect to its
insurers, in 1991, AGLC filed a declaratory judgment action against 23 of its
insurance companies. 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. During fiscal 1996 AGLC recovered $14.7 million from its
insurance carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $2.9 million and
established regulatory liabilities for the remainder of those recoveries.
Other Legal Proceedings
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.
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Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the fourth
quarter of the fiscal year covered by this report.
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15
Part II
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Item 5. Market for the Registrants' Common Equity and Related Stockholder
Matters
As of September 30, 1996, all of AGLC's common stock was beneficially
owned by AGL Resources. Accordingly, there is no established public trading
market for AGLC's common stock. Further, as of September 30, 1996, all of the
outstanding shares of AGLC common stock were owned of record by AGL Resources,
the sole shareholder of record.
The following table reflects the quarterly dividends paid per share on
AGLC's common stock for fiscal years ended September 30, 1996 and 1995. On
November 3, 1995, the Board of Directors of AGLC declared a two-for-one stock
split of the common stock effected in the form of a 100% stock dividend to
shareholders of record on November 17, 1995, and payable on December 1, 1995.
All references to per share amounts have been restated retroactively to reflect
the stock dividend.
Quarter Ended Dividends Paid Per Share
1996
September 30, 1996(a) 26.5(cent)
June 30, 1996(a) 26.5(cent)
March 31, 1996(a) 26.5(cent)
December 31, 1995 26.5(cent)
1995
September 30, 1995 26(cent)
June 30, 1995 26(cent)
March 31, 1995 26(cent)
December 31, 1994 26(cent)
(a) Amount paid to AGL Resources Inc.
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16
Item 6. Selected Financial Data
Selected financial data for AGLC for each year of the five-year period
ended September 30, 1996, is set forth as follows:
ATLANTA GAS LIGHT COMPANY
Selected Financial Data
For the years ended September 30,
------------------------------------------------------------------------
In millions, except per share amounts 1996 1995 1994 1993 1992 1991
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Income Statement Data
Operating revenues .......................... $ 1,217.6 $ 1,063.0 $ 1,199.9 $ 1,130.3 $ 994.6 $ 963.8
Cost of gas ................................. 718.7 571.8 736.8 701.0 590.5 579.9
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Operating margin ............................ 498.9 491.2 463.1 429.3 404.1 383.9
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Other operating expenses
Operation ................................ 217.7 213.5 207.0 187.6 170.7 165.2
Restructuring costs ...................... 70.3
Maintenance .............................. 29.3 30.4 32.8 30.9 29.5 28.6
Depreciation ............................. 61.6 58.5 55.4 58.8 54.9 50.2
Income taxes ............................. 43.5 16.0 34.3 28.2 25.6 26.2
Taxes other than income taxes ............ 24.9 25.6 26.0 23.9 23.2 19.2
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Total other operating expenses ....... 377.0 414.3 355.5 329.4 303.9 289.4
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Operating income ............................ 121.9 76.9 107.6 99.9 100.2 94.5
Other income - net .......................... 7.8 1.4 3.2 4.3 2.6 1.8
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Income before interest charges .............. 129.7 78.3 110.8 104.2 102.8 96.3
Interest charges ............................ 49.1 47.5 47.6 46.7 47.4 46.9
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Net Income .................................. 80.6 30.8 63.2 57.5 55.4 49.4
Dividends on preferred stock ................ 4.4 4.4 4.5 4.3 1.0 1.1
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Earnings available for common stock ......... 76.2 26.4 58.7 53.2 54.4 48.3
Common dividends paid ....................... 58.6 54.2 52.2 51.1 49.6 47.4
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Earnings reinvested ......................... $ 17.6 $ (27.8) $ 6.5 $ 2.1 $ 4.8 $ 0.9
================================================================================================================================
Balance Sheet Data(1)
Total assets ................................ $ 1,738.1 $ 1,674.6 $ 1,642.9 $ 1,533.0 $ 1,428.6 $ 1,350.3
Long-term liabilities
Take-or-pay charges payable ............... $ 5.0 $ 15.0
Accrued environmental response costs ..... $ 30.4 $ 28.6 $ 24.3 $ 19.6 $ 25.0
Accrued pension costs .................... $ 4.9 $ 10.3
Accrued postretirement benefits costs .... $ 36.2 $ 30.1 $ 3.6
Deferred Credits ......................... $ 60.9 $ 65.6 $ 66.6 $ 42.3 $ 43.8 $ 47.6
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Capitalization
Long-term debt ........................... $ 554.5 $ 554.5 $ 569.5 $ 500.7 $ 476.5 $ 458.3
Preferred stock - redeemable ............ 55.5 55.8 55.8 56.0 11.5 12.8
- nonredeemable ......... 3.0 3.0 3.0 3.0 3.0 3.0
Common equity ............................ 502.7 557.3 518.5 492.0 472.1 448.2
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Total ............................... $ 1,115.7 $ 1,170.6 $ 1,146.8 $ 1,051.7 $ 963.1 $ 922.3
================================================================================================================================
Financial Ratios(1)
Capitalization
Long-term debt ........................... 49.7% 47.4% 49.6% 47.6% 49.5% 49.7%
Preferred stock - redeemable ............ 5.0 4.8 4.9 5.3 1.2 1.4
- nonredeemable ......... 0.2 0.2 0.3 0.3 0.3 0.3
Common equity ............................ 45.1 47.6 45.2 46.8 49.0 48.6
- --------------------------------------------------------------------------------------------------------------------------------
Total ................................ 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
================================================================================================================================
Return on average common equity ............. 14.4% 4.9% 11.6% 11.0% 11.8% 11.4%
- --------------------------------------------------------------------------------------------------------------------------------
Times charges earned before income taxes(2)
Total interest ........................... 3.60 1.99 3.08 2.86 2.66 2.56
Total interest and preferred dividends ... 3.31 1.83 2.82 2.63 2.60 2.50
Fixed(3) ................................. 3.49 1.95 3.00 2.80 2.62 2.53
================================================================================================================================
(1) Year-End.
(2) Interest charges exclude the debt portion of allowance for funds used during construction.
(3) Fixed charges consist of interest on short- and long-term debt, other interest and the estimated interest component of
rentals.
17
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Item 7. 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, a natural gas distribution utility, AGLC's wholly
owned natural gas utility subsidiary, Chattanooga Gas Company (Chattanooga), and
AGLC's nonregulated subsidiaries: AGL Energy Services, Inc.; AGL Investments,
Inc.; Georgia Gas Company; Georgia Gas Service Company; Georgia Energy Company
and Trustees Investments, Inc. During the third and fourth quarters of fiscal
1996, ownership of AGLC's nonregulated businesses was transferred to AGL
Resources and its various subsidiaries. (See Note 1 in Notes to Consolidated
Financial Statements.) 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 cover events affecting AGLC's
results of operations and financial condition for each of the three years ended
September 30, 1996, and factors expected to impact future operations.
Results of Operations
Fiscal 1996 Compared with Fiscal 1995
OPERATING REVENUES
Operating revenues increased 14.5% in 1996 compared with 1995 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, (2) increased
volumes of gas sold to firm service customers as a result of weather that was
50% colder in 1996 than in 1995 and (3) an increase of approximately 41,500 in
the number of customers served.
COST OF GAS
Cost of gas increased 25.7% in 1996 compared with 1995 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 and (2) increased volumes of
gas sold to firm service customers as a result of weather that was 50% colder in
1996 than in 1995.
AGLC's cost of natural gas per therm was 32.2 cents in 1996 and 29.7
cents in 1995. Variations in the cost of purchased gas are passed through to
customers under the purchased gas provisions of AGLC's rate schedules.
Overrecoveries or underrecoveries of purchased gas costs are charged or credited
to cost of gas and are included in current assets or liabilities, thereby
eliminating the effect that recovery of gas costs otherwise would have on net
income.
OPERATING MARGIN
Operating margin increased 1.6% in 1996 compared with 1995 primarily due
to (1) recovery of increased expenses related to an Integrated Resource Plan
(IRP), which are recovered through an IRP Cost Recovery Rider approved by the
Georgia Public Service Commission (Georgia Commission), (2) a revenue increase
granted by the Tennessee Regulatory Authority (TRA), formerly the Tennessee
Public Service Commission, effective November 1, 1995, and (3) an increase of
approximately 41,500 in the number of customers served.
RESTRUCTURING COSTS
In November 1994 AGLC announced a corporate restructuring plan in
response to increased competition and changes in the federal and state
regulatory environments in which it operates. Restructuring costs of $61.4
million related to early retirement and severance programs and $8.9 million
related to office closings and costs to exit AGLC's appliance merchandising and
real estate investment operations were recorded during 1995.
There were no restructuring costs recorded in 1996.
18
During the fourth quarter of fiscal 1996, AGLC reviewed its remaining
liabilities with respect to its corporate restructuring plan. As a result, AGLC
adjusted its restructuring accruals and reduced operating expenses by $1.6
million, after income taxes. The remaining balance of restructuring liabilities
as of September 30, 1996 and 1995 was $1 million and $4.8 million, respectively.
OTHER OPERATING EXPENSES
Operation and maintenance expenses increased 1.3% in 1996 compared with
1995 primarily due to (1) an increase of $3.6 million in expenses related to an
Integrated Resource Plan (IRP) and (2) an increase of $1.2 million in franchise
expenses. IRP and franchise expenses are recovered from customers through rate
recovery riders approved by the Georgia Commission. As a result, IRP program
costs and franchise expenses do not affect net income. Operation and maintenance
expenses excluding IRP and franchise expenses decreased slightly primarily due
to decreased labor related expenses. The decrease in operation and maintenance
expenses excluding IRP and franchise expenses was offset partly by increased
uncollectible accounts expenses.
Depreciation expense increased 5.3% in 1996 compared with 1995 primarily
due to increased depreciable plant in service. The composite straight-line
depreciation rate was approximately 3.2% for utility property other than
transportation equipment during 1996 and 1995.
Income taxes increased $27.5 million in 1996 compared with 1995 primarily
due to increased taxable income.
Taxes other than income taxes decreased $0.7 million primarily due to
decreased ad valorem taxes.
OTHER INCOME
Other income increased $6.4 million in 1996 compared with 1995 primarily
due to (1) income from carrying costs on increased deferred purchased gas
undercollections and (2) recoveries of environmental response costs from
insurance carriers and third parties.
INTEREST CHARGES
Total interest charges increased $1.6 million in 1996 compared with 1995
primarily due to increased amounts of short-term debt outstanding. The increase
was offset partly by decreased amounts of long-term debt outstanding.
EARNINGS AVAILABLE FOR COMMON STOCK
Earnings available for common stock for 1996 was $76.2 million, compared
with $26.4 million in 1995. The increase in earnings available for common stock
was primarily due to (1) corporate restructuring costs of $43.1 million, after
income taxes, recorded in 1995, (2) increased other income and (3) increased
operating margin as a result of an increase of approximately 41,500 in the
number of customers served. The increase in earnings available for common stock
was offset partly by increased depreciation expense.
Results of Operations
Fiscal 1995 Compared with Fiscal 1994
OPERATING REVENUES
Operating revenues decreased 11.4% in 1995 compared with 1994 primarily
due to (1) a decrease in the cost of the gas supply recovered from customers
under the purchased gas provisions of AGLC's rate schedules and (2) decreased
volumes of gas sold to firm service customers as a result of weather that was
17% warmer in 1995 than in 1994. The decrease in operating revenues was offset
partly by an increase of approximately 37,000 in the number of customers served.
COST OF GAS
Cost of gas decreased 22.4% in 1995 compared with 1994 primarily due to
(1) a decrease in the cost of the gas supply recovered from customers under the
purchased gas provisions of AGLC's rate schedules and (2) decreased volumes of
gas sold to firm service customers as a result of weather that was 17% warmer in
1995 than in 1994.
19
AGLC's cost of natural gas per therm was 29.7 cents in 1995 and 37.7
cents in 1994. Variations in the cost of purchased gas are passed through to
customers under the purchased gas adjustment provisions of AGLC's rate
schedules.
OPERATING MARGIN
Operating margin increased 6.1% in 1995 compared with 1994 primarily due
to an increase of approximately 37,000 in the number of customers served.
RESTRUCTURING COSTS
In November 1994 AGLC announced a corporate restructuring plan in
response to increased competition and changes in the federal and state
regulatory environments in which AGLC operates.
The restructuring plan provided for reengineering AGLC's business
processes and streamlining AGLC's statewide field organizations. As a result of
restructuring, AGLC has combined offices and established centralized customer
service centers. During 1995, AGLC reduced the average number of employees by
approximately 500 through voluntary retirement and severance programs, and
attrition.
Restructuring costs of $61.4 million related to early retirement and
severance programs and $8.9 million related to office closings and costs to exit
AGLC's appliance merchandising and real estate investment operations were
recorded during 1995.
OTHER OPERATING EXPENSES
Operation and maintenance expenses increased 1.7% in 1995 compared with
1994 primarily due to an increase of $17 million in expenses related to an IRP,
which are recovered through an IRP Cost Recovery Rider approved by the Georgia
Commission. As a result, IRP program costs do not affect net income. Operation
and maintenance expenses excluding IRP expenses decreased 5.4% in 1995 compared
with 1994 primarily due to (1) decreased labor costs as a result of the
restructuring plan, (2) decreased uncollectible accounts expenses and (3)
decreased regulatory commission expenses.
Depreciation expense increased 5.6% in 1995 compared with 1994 primarily
due to increased depreciable plant in service. The composite straight-line
depreciation rate was approximately 3.2% for utility property other than
transportation equipment during 1995 and 1994.
Income taxes decreased $18.3 million in 1995 compared with 1994 primarily
due to decreased taxable income.
Taxes other than income taxes decreased $0.4 million primarily due to
decreased payroll taxes as a result of the restructuring plan. The decrease in
taxes other than income taxes was offset partly by increased ad valorem taxes.
OTHER INCOME
Other income decreased $1.8 million in 1995 compared with 1994 primarily
due to (1) decreased income from propane operations as a result of warmer
weather and (2) decreased income from merchandise operations.
INTEREST CHARGES
Total interest charges decreased $0.1 million in 1995 compared with 1994
primarily due to increased allowance for funds used during construction-debt.
Interest on long-term debt decreased $0.5 million in 1995 compared with 1994 due
to decreased amounts of long-term debt outstanding. The decreased interest
expense on long-term debt was offset by a $0.5 million increase in other
interest expenses primarily due to increased interest rates on short-term debt.
EARNINGS AVAILABLE FOR COMMON STOCK
Earnings available for common stock for 1995 was $26.4 million, compared
with $58.7 million for 1994. The decrease in earnings available for common stock
was primarily due to corporate restructuring costs of $43.1 million, after
income taxes, recorded in 1995. The decrease in earnings available for common
stock was offset partly by (1) increased operating margin as a result of an
increase of approximately 37,000 in the
20
number of customers served and (2) decreased other operating expenses as a
result of the restructuring plan. Excluding charges recorded during 1995 related
to the restructuring plan, earnings available for common stock would have been
approximately $69.5 million.
Impact of Inflation
Inflation impacts the prices AGLC must pay for labor and other goods and
services required for operation, maintenance and capital improvements. AGLC's
rate schedules include purchased gas adjustment provisions that permit the
increases in gas costs to be passed on to its customers. Increases in costs not
recovered through the purchased gas adjustment provisions and other similar rate
riders must be recovered through timely filings for rate relief.
Financial Condition
Financing
LONG-TERM DEBT
During fiscal 1994, $194.5 million in principal amount of Medium-Term
Notes, Series C, was issued, with maturity dates ranging from 10 to 30 years and
with interest rates ranging from 5.9% to 7.2%. The notes are issued under an
Indenture dated December 1, 1989, and are unsecured and rank on a parity with
all other unsecured indebtedness. Net proceeds from the notes were used to repay
short-term debt, to refund $125 million in principal amount of First Mortgage
Bonds and for other corporate purposes. Approximately $105 million in principal
amount of Medium-Term Notes, Series C, was unissued as of September 30, 1996,
and 1995.
SHORT-TERM DEBT
Because AGLC's business is highly seasonal, short-term debt is used to
meet seasonal working capital requirements. In addition, capital expenditures
are funded temporarily with short-term debt. Lines of credit with various banks
provide for direct borrowings from the banks and are subject to annual renewal.
The current lines of credit vary from $75 million in the summer months to $253
million for peak winter financing. Short-term debt increased $101 million from
the amount outstanding as of September 30, 1995, to $152 million as of September
30, 1996, primarily as a result of the increased use of short-term debt to
temporarily fund capital expenditures. For additional information concerning
short-term debt, see Note 8 in Notes to Consolidated Financial Statements.
Capital Requirements
Capital expenditures for construction of distribution facilities,
purchase of equipment and other general improvements were $132.8 million during
1996.
Capital requirements are estimated to be approximately $350 million for
the three years ending September 30, 1999. During the same period, approximately
$1.2 million will be required to fund preferred stock purchase fund obligations.
Funding for those expenditures will be provided through a combination of
internal sources and the issuance of short-term and long-term debt.
The cost of natural gas stored underground increased $32.8 million to
$144 million as of September 30, 1996, primarily due to an increase in the cost
of the gas that was injected into storage.
Ratios and Coverages
On September 30, 1996, AGLC's capitalization ratios consisted of 49.7%
long-term debt, 5.2% preferred stock and 45.1% common equity. The times interest
earned and ratio of earnings to fixed charges increased in 1996 compared with
1995 primarily due to increased earnings. The times interest earned and ratio of
earnings to fixed charges decreased in 1995 compared with 1994 primarily due to
decreased earnings.
21
The weighted average cost of long-term debt decreased from 7.7% on
September 30, 1994, to 7.6% on September 30, 1996. The decrease was due to the
redemption of $15 million in principal amount of 8.85% medium-term notes. The
weighted average cost of preferred stock was 7.5% on September 30, 1994, 1995
and 1996. The return on average common equity was 11.6% for 1994; 4.9% for 1995;
and 14.4% for 1996. Earnings available for common stock in 1995 included a
charge for restructuring of $43.1 million, after income taxes.
Regulatory Activity
ORDER 636
In 1992 the Federal Energy Regulatory Commission (FERC) issued Order 636,
which, among other things, mandated the unbundling of interstate pipeline sales
service and established certain open access transportation regulations that
became effective beginning in the 1993-1994 heating season.
In Order 636 FERC acknowledged that, without special recovery mechanisms,
certain costs that previously were recovered in the pipelines' rate for bundled
sales services no longer could be recovered by the pipelines in a restructured
environment. Those costs, referred to as transition costs, include such things
as unrecovered gas costs, gas supply realignment (GSR) costs and various
stranded costs resulting from unbundling. Accordingly, Order 636 included a
recovery mechanism that allows the pipeline companies to pass through to their
customers any prudently incurred transition costs attributable to compliance
with Order 636.
On July 16, 1996, the United States Court of Appeals for the District of
Columbia Circuit issued its ruling in United Distribution Cos. v. FERC,
concerning appeals from Order 636. The court generally upheld FERC's orders
against a broad array of challenges, but remanded the orders to FERC for
reconsideration of certain issues, including FERC's decision to permit pipelines
to pass all of their GSR costs through to their customers and its decision to
require interruptible transportation customers to bear 10% of GSR costs. FERC
has not yet issued an order on remand, and thus it is not known whether FERC
will change its GSR policies. The court's order is subject to further
proceedings before the District of Columbia Circuit, and possibly the United
States Supreme Court.
AGLC, based on filings with FERC by its pipeline suppliers, estimates
that its portion of such costs from all of its pipeline suppliers would be
approximately $109.9 million. Such filings currently are pending before FERC for
final approval, and the transition costs are being collected subject to refund.
Approximately $80.6 million of such costs have been incurred by AGLC as of
September 30, 1996, recovery of which is provided under the purchased gas
provisions of AGLC's rate schedules.
Transition costs have not affected the total cost of gas to AGLC's
customers significantly because (1) purchases of wellhead gas supplies are based
on market prices that are below the cost of gas previously embedded in the
bundled pipeline sales service rates and (2) many elements of transition costs
previously were embedded in the rates for the pipelines' bundled sales service.
REGULATORY REFORM INITIATIVES
Two regulatory reform initiatives are pending in Georgia, both designed
to increase competition and reduce the role of regulation within the natural gas
industry. The first such initiative is the subject of a proceeding at the
Georgia Commission; the second initiative is before study committees of the
Georgia General Assembly.
With respect to the first initiative, on November 20, 1995, the Georgia
Commission issued a Natural Gas Notice of Inquiry soliciting comments on how to
introduce more competition into natural gas markets within Georgia. Following
written comments and oral presentations from numerous parties, on May 21, 1996,
the Georgia Commission adopted a Policy Statement that, among other things, sets
up a distinction between competitive and natural monopoly services; favors
performance-based regulation in lieu of traditional cost-of-service regulation;
calls for unbundling interruptible service; directs the Georgia Commission 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.
22
Consistent with specific goals in the Georgia Commission's Policy
Statement, on June 10, 1996, AGLC filed a comprehensive plan for serving
interruptible markets called the Natural Gas Service Provider Selection Plan
(the Plan). 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; 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 marketing affiliates of utilities. Hearings on the
proposal have been scheduled for December 1996 and January and February 1997. A
decision is expected from the Georgia Commission prior to March 1, 1997.
The second major initiative to increase competition and decrease the role
of regulation in Georgia is before study committees of the Georgia General
Assembly. The 1996 Georgia General Assembly considered, but delayed action on,
The Natural Gas Fair Pricing Act, which would have allowed local gas companies
to negotiate contract prices and terms for gas services with large commercial
and industrial customers absent Georgia Commission-mandated rates. The Georgia
General Assembly stated through resolutions a desire to fashion a more
comprehensive approach to deregulation and unbundling of natural gas services in
Georgia. Those resolutions, adopted during the 1996 session, created Senate and
House committees to study and recommend a comprehensive course of action by
December 31, 1996, for deregulating natural gas markets in Georgia.
The separate Senate and House study committees conducted meetings during
September, October and November 1996, with the goal of crafting a comprehensive
deregulation bill for the 1997 General Assembly, which convenes in January 1997.
The natural gas deregulation plan under consideration by the committees would
unbundle services to all of AGLC's natural gas customers, would continue AGLC's
role as the intrastate transporter of natural gas, would allow AGLC to assign
firm delivery capacity to certificated marketers who would sell the gas
commodity, and would create a secondary transportation market for interruptible
transportation capacity.
Although AGLC cannot predict the outcome of these two regulatory reform
initiatives, it supports both the plan under consideration by the Georgia
Commission and the plan under consideration by the Georgia General Assembly.
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 COST RECOVERY FILING
Pursuant to legislation enacted by the Georgia General Assembly, each
investor-owned local gas distribution company is required to file on or before
August 1 of each year, a proposed gas supply plan for the subsequent year, as
well as a proposed cost recovery factor to be used during the same time period.
Costs of natural gas supply, interstate transportation and storage incurred
pursuant to an approved plan may be recovered under the purchased gas provisions
of AGLC's rate schedules.
On August 1, 1996, AGLC filed its 1997 Gas Supply Plan, which consists of
gas supply, transportation and storage options designed to provide reliable
service to firm customers at the best cost. On September 13, 1996, the Georgia
Commission approved the entire supply portfolio contained in the 1997 Gas Supply
Plan.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue
limited gas supply hedging activities. The 1997 hedging program has been
expanded beyond the program approved in the 1996 Gas Supply Plan. The financial
results of all hedging activities are passed through to firm service customers
under the purchased gas provisions of AGLC's rate schedules. Accordingly, there
is no earnings impact as a result of the hedging program.
RATE FILINGS
On May 1, 1995, Chattanooga filed a rate proceeding with the TRA seeking
an increase in revenues of $5.2 million annually. On September 27, 1995, a
settlement agreement was reached that provides for an annual increase in
revenues of approximately $2.5 million, effective November 1, 1995.
23
On August 3, 1993, Chattanooga made a rate filing with the TRA seeking an
increase in revenues of $5.7 million annually. On December 31, 1993, a
settlement agreement was reached that provided for an annual rate increase of
$3.5 million, effective February 1, 1994.
WEATHER NORMALIZATION
The Georgia Commission and the TRA have authorized weather normalization
adjustment riders (WNARs), which are designed to offset the impact that
unusually cold or warm weather has on customer billings and operating margin.
Because fiscal 1996 was colder than normal, the WNARs reduced net income and net
cash flow from operating activities to normal levels. Fiscal years 1995 and 1994
were warmer than normal, and the WNARs, therefore, increased net income and net
cash flow from operating activities to normal levels for those periods. The
WNARs decreased net income by $4.4 million in 1996, and increased net income by
$27.3 million in 1995 and $12.6 million in 1994.
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 that AGLC does not now own, but that may have been
associated with the operation of MGPs by AGLC or its predecessors. There are
three sites in Florida that have been investigated by environmental authorities
in connection with which AGLC may be contacted as a potentially responsible
party. Preliminary assessments and subsequent site investigations have revealed
environmental impacts at and near some of those sites.
Under a thorough analysis of potentially applicable requirements, AGLC
has estimated that, under the most favorable circumstances reasonably possible,
the future cost of investigating and remediating the former MGP sites, excluding
sites for which no remediation is expected or the cost of which cannot be
estimated, could be as low as $30.4 million. Alternatively, AGLC has estimated
that, under the least favorable circumstances reasonably possible, the future
cost of investigating and remediating the same former MGP sites could be as high
as $110.8 million, excluding sites for which no remediation is expected or the
cost of which cannot be estimated. AGLC cannot estimate at this time the amount
of any other future expenses or liabilities, or the impact on those estimates of
future environmental or regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the $30.4 million to $110.8
million range can be 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 in the financial statements.
The Georgia Commission has approved the recovery by AGLC of environmental
response costs, pursuant to AGLC's 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 has undertaken a financial and management
process audit related to the MGP sites, cleanup activities at the sites and
environmental response costs that have been incurred for purposes of the ERCRR.
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.
AGLC is currently a party to claims and litigation related to the former
MGP sites. During fiscal 1996 AGLC recovered $14.7 million from its insurance
carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $1.6 million, after
income taxes, and established regulatory liabilities for the remainder of those
recoveries. AGLC intends to continue to pursue insurance coverage and
contributions from potentially responsible parties.
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.
24
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.
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.
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 approximately 50 Negotiated Contracts. Additionally, the
Georgia Commission has approved Special Contracts between AGLC and five
interruptible customers.
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 7, 1996, the TRA
hearing officer recommended approval of 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.
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25
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Item 8. Financial Statements and Supplementary Data
The following financial statements of AGLC are set forth as follows:
Statements of Consolidated Income for the years ended September 30, 1996,
1995 and 1994 - page 27.
Statements of Consolidated Cash Flows for the years ended September 30,
1996, 1995 and 1994 - page 28.
Consolidated Balance Sheets as of September 30, 1996 and 1995 - pages
29-30.
Statements of Consolidated Common Stock Equity for the years ended
September 30, 1996, 1995 and 1994 - page 31.
Notes to Consolidated Financial Statements - pages 32-47.
Independent Auditors' Report - page 48.
The supplementary financial information required by Item 302 of Regulation
S-K is set forth in Note 14 in Notes to Consolidated Financial Statements
on page 47 of this Form 10-K.
26
ATLANTA GAS LIGHT COMPANY
Statements of Consolidated Income
For the years ended September 30,
------------------------------------
In millions, except per share amounts 1996 1995 1994
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Operating Revenues ...................... $ 1,217.6 $ 1,063.0 $ 1,199.9
Cost of Gas ............................. 718.7 571.8 736.8
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Operating Margin ........................ 498.9 491.2 463.1
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Other Operating Expenses
Operation ......................... 217.7 213.5 207.0
Restructuring costs ............... 70.3
Maintenance ....................... 29.3 30.4 32.8
Depreciation of utility plant other
than transportation equipment . 61.6 58.5 55.4
Income taxes ...................... 43.5 16.0 34.3
Taxes other than income taxes ..... 24.9 25.6 26.0
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Total other operating expenses 377.0 414.3 355.5
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Operating Income ........................ 121.9 76.9 107.6
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Other Income
Allowance for funds used during
construction-equity ........... 0.4 0.2 0.2
Other income and deductions ....... 12.2 1.9 5.0
Income taxes ...................... (4.8) (0.7) (2.0)
- --------------------------------------------------------------------------------
Total other income-net ........ 7.8 1.4 3.2
- --------------------------------------------------------------------------------
Income Before Interest Charges .......... 129.7 78.3 110.8
- --------------------------------------------------------------------------------
Interest Charges
Interest on long-term debt ........ 42.2 42.7 43.2
Allowance for funds used during
construction-debt ............. (0.4) (0.3) (0.2)
Other interest .................... 7.3 5.1 4.6
- --------------------------------------------------------------------------------
Total interest charges ........ 49.1 47.5 47.6
- --------------------------------------------------------------------------------
Net Income .............................. 80.6 30.8 63.2
- --------------------------------------------------------------------------------
Dividends on Preferred Stock ............ 4.4 4.4 4.5
- --------------------------------------------------------------------------------
Earnings Available for Common Stock ..... $ 76.2 $ 26.4 $ 58.7
- --------------------------------------------------------------------------------
See notes to consolidated financial statements.
27
ATLANTA GAS LIGHT COMPANY
Statements of Consolidated Cash Flows
For the years ended September 30,
----------------------------------
In millions 1996 1995 1994
- --------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income .............................. $ 80.6 $ 30.8 $ 63.2
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization ....... 65.8 62.5 59.2
Noncash restructuring costs ......... 52.9
Deferred income taxes ............... 24.3 (1.2) 13.6
Other ............................... (0.1) 3.8 6.3
- --------------------------------------------------------------------------------
170.6 148.8 142.3
Changes in assets and liabilities
Receivables ......................... (27.3) 14.6 9.4
Inventories ......................... (32.7) 43.3 (38.5)
Deferred purchased gas adjustment ... (11.0) (13.8) 20.8
Accounts payable .................... 3.1 14.7 (6.0)
Other-net ........................... (12.8) 2.4 4.7
- --------------------------------------------------------------------------------
Net cash flow from operating
activities ...................... 89.9 210.0 132.7
- --------------------------------------------------------------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses ... 1.0 50.4 2.4
Short-term borrowings, net .............. 101.0 (44.4) (36.0)
Redemptions and purchase fund
requirements of preferred stock and
long-term debt ...................... (15.0) (125.7)
Sale of long-term debt .................. 194.5
Common stock dividends paid to parent ... (53.8) (44.3) (42.9)
Preferred stock dividends ............... (4.4) (4.4) (4.5)
- --------------------------------------------------------------------------------
Net cash flow from financing ...... 43.8 (57.7) (12.2)
activities
- --------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures .............. (132.0) (120.8) (122.0)
Investment in joint venture ............. (32.6)
Nonutility capital expenditures ......... 1.1 (0.4) (0.1)
Cash received from joint venture ........ 2.4
Cost of removal, net of salvage ......... (1.0) 1.9 1.6
- --------------------------------------------------------------------------------
Net cash flow from investing ...... (129.5) (151.9) (120.5)
activities
- --------------------------------------------------------------------------------
Net increase in cash and cash
equivalents ..................... 4.2 0.4
Cash and cash equivalents at
beginning of year ............... 3.7 3.3 3.3
- --------------------------------------------------------------------------------
Cash and cash equivalents at
end of year ..................... $ 7.9 $ 3.7 $ 3.3
- --------------------------------------------------------------------------------
Supplemental Information
Cash Paid During the Year for
Interest ............................ $ 49.2 $ 48.4 $ 51.1
Income taxes ........................ $ 19.1 $ 28.6 $ 18.0
Noncash dividend paid to parent ......... $ 80.2
- --------------------------------------------------------------------------------
See notes to consolidated financial statements.
28
ATLANTA GAS LIGHT COMPANY
Consolidated Balance Sheets
Assets September 30,
---------------------------
In millions 1996 1995
- --------------------------------------------------------------------------------
Utility Plant ..................................... $ 1,969.0 $ 1,919.9
Less accumulated depreciation ................... 607.8 583.3
- --------------------------------------------------------------------------------
Utility plant-net ............................. 1,361.2 1,336.6
- --------------------------------------------------------------------------------
Other Property and Investments
(less accumulated depreciation of $2.9 in 1995) . 13.7
- --------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents ....................... 7.9 3.7
Receivables
Gas (less allowance for uncollectible accounts
of $2.1 in 1996 and $2.4 in 1995) ........... 62.4 30.3
Merchandise (less allowance for uncollectible
accounts of $.4 in 1996 and $1.9 in 1995) ... 2.5 5.3
Integrated resource plan loans (less allowance
for uncollectible accounts of $.2 in 1996 and
$.1 in 1995) ................................ 3.4 1.3
Other ......................................... 2.5 9.6
Unbilled revenues ............................... 20.5 17.5
Inventories
Natural gas stored underground ................ 144.0 111.2
Liquefied natural gas ......................... 16.8 14.3
Materials and supplies ........................ 7.9 8.0
Other ......................................... 0.1 2.6
Deferred purchased gas adjustment ............... 4.7
Other ........................................... 10.3 10.9
- --------------------------------------------------------------------------------
Total current assets .......................... 283.0 214.7
- --------------------------------------------------------------------------------
Deferred Debits and Other Assets
Investment in joint ventures .................... 32.6
Unrecovered environmental response costs ........ 38.0 34.9
Unrecovered integrated resource plan costs ...... 10.0 9.9
Unrecovered postretirement benefits costs ....... 9.7 7.2
Unamortized cost to repurchase long-term debt ... 3.5 4.9
Other ........................................... 22.8 20.1
- --------------------------------------------------------------------------------
Total deferred debits and other assets ........ 84.0 109.6
- --------------------------------------------------------------------------------
Total ......................................... $ 1,728.2 $ 1,674.6
- --------------------------------------------------------------------------------
See notes to consolidated financial statements.
29
ATLANTA GAS LIGHT COMPANY
Capitalization and Liabilities September 30,
--------------------------
In millions 1996 1995
- --------------------------------------------------------------------------------
Capitalization
Common stock equity (See accompanying statements
of consolidated common stock equity) .......... $ 502.7 $ 557.3
Cumulative preferred stock
Redeemable .................................... 55.5 55.5
Nonredeemable ................................. 3.0 3.0
Long-term debt .................................. 554.5 554.5
- --------------------------------------------------------------------------------
Total capitalization .......................... 1,115.7 1,170.3
- --------------------------------------------------------------------------------
Current Liabilities
Short-term debt ................................. 152.0 51.0
Accounts payable-trade .......................... 72.7 72.3
Payable to associated companies ................. 2.7
Take-or-pay charges payable ..................... 8.0
Customer deposits ............................... 27.8 29.5
Interest ........................................ 25.7 25.4
Other accrued liabilities ....................... 22.5 11.9
Deferred purchased gas adjustment ............... 6.3
Other ........................................... 20.4 26.5
- --------------------------------------------------------------------------------
Total current liabilities ..................... 323.8 230.9
- --------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs ............ 30.4 28.6
Payable to AGL Resources - accrued pension costs 4.9 10.3
Payable to AGL Resources - accrued postretirement
benefits costs ................................ 36.2 30.1
- --------------------------------------------------------------------------------
Total long-term liabilities ................... 71.5 69.0
- --------------------------------------------------------------------------------
Deferred Credits
Unamortized investment tax credit ............... 28.8 30.3
Regulatory tax liability ........................ 19.3 23.3
Other ........................................... 12.8 12.0
- --------------------------------------------------------------------------------
Total deferred credits ........................ 60.9 65.6
- --------------------------------------------------------------------------------
Accumulated Deferred Income Taxes ................. 156.3 138.8
- --------------------------------------------------------------------------------
Commitments and Contingencies (Notes 8 and 10)
- --------------------------------------------------------------------------------
Total ......................................... $ 1,728.2 $ 1,674.6
- --------------------------------------------------------------------------------
30
ATLANTA GAS LIGHT COMPANY
Statements of Consolidated Common Stock Equity
For the years ended September 30,
---------------------------------
In millions, except per share amounts 1996 1995 1994
- --------------------------------------------------------------------------------
Common Stock (Note 4)
$5 par value; authorized 100.0 shares;
outstanding, 55.4 in 1996, 54.9 in 1995
and 50.8 in 1994
Beginning of year ........................ $ 137.3 $ 127.1 $ 124.2
Issuance of common stock
Stock dividend ....................... 137.5
Public sale .......................... 7.5
Employees' benefit plans, dividend
reinvestment and stock purchase plan
and long-term stock incentive plan . 2.0 2.7 2.9
- --------------------------------------------------------------------------------
End of year .............................. 276.8 137.3 127.1
- --------------------------------------------------------------------------------
Premium on Capital Stock (Note 4)
Beginning of year ........................ 297.7 241.3 224.2
Issuance of common stock
Stock dividend ....................... (137.5)
Public sale .......................... 41.1
Employees' benefit plans, dividend
reinvestment and stock purchase plan
and long-term stock incentive plan . 6.0 15.3 17.1
- --------------------------------------------------------------------------------
End of year .............................. 166.2 297.7 241.3
- --------------------------------------------------------------------------------
Earnings Reinvested
Beginning of year ........................ 122.3 150.1 143.6
Net income ............................. 80.6 30.8 63.2
Cash dividends
Preferred stock ........................ (4.4) (4.4) (4.5)
Common stock
Paid to public shareholders .......... (29.2) (54.2) (52.2)
Paid to AGL Resources ................ (29.4)
Noncash dividend to parent ............. (80.2)
- --------------------------------------------------------------------------------
End of year .............................. 59.7 122.3 150.1
- --------------------------------------------------------------------------------
Total common stock equity .............. $ 502.7 $ 557.3 $ 518.5
- --------------------------------------------------------------------------------
See notes to consolidated financial statements.
31
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
PRINCIPLES OF CONSOLIDATION
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, AGLC's wholly owned natural gas
utility subsidiary, Chattanooga Gas Company (Chattanooga), and AGLC's
nonregulated subsidiaries. The holding company formation was completed upon
receipt of shareholder approval on March 6, 1996, when each share of AGLC common
stock was converted into one share of AGL Resources common stock, and AGLC
became the primary subsidiary of AGL Resources. The consolidated financial
statements of AGLC include the financial statements of AGLC and Chattanooga.
Intercompany balances and transactions between AGLC and Chattanooga have been
eliminated.
SUBSIDIARIES
AGLC is a public utility that distributes and transports natural gas in
Georgia and Tennessee and is subject to regulation by the Georgia Public Service
Commission (Georgia Commission) and the Tennessee Regulatory Authority (TRA),
formerly the Tennessee Public Service Commission, with respect to its rates for
service, maintenance of its accounting records and various other matters. The
consolidated financial statements are prepared in accordance with generally
accepted accounting principles, which give appropriate recognition to the
rate-making and accounting practices and policies of the Georgia Commission and
the TRA.
Ownership of AGLC's nonregulated business, Georgia Gas Company (natural
gas production activities), has been transferred to AGL Energy Services, Inc.
Ownership of AGLC's other nonregulated businesses, Georgia Energy Company
(natural gas vehicle conversions), Georgia Gas Service Company (retail propane
sales) and Trustees Investments, Inc. (real estate holdings), has been
transferred to AGL Investments. AGLC's interest in Sonat Marketing Company L.P.
has been 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 from AGLC to Service Company
and other nonregulated subsidiaries was effected through a noncash dividend of
$34.3 million during the fourth quarter of fiscal 1996. Expenses of Service
Company are allocated to AGL Resources and its subsidiaries.
REGULATION
The consolidated financial statements reflect regulatory actions by the
Georgia Commission and the TRA that result in the recognition of revenues and
expenses in different time periods than do enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71),
regulatory assets and liabilities are recorded and represent regulator-approved
deferrals resulting from the rate-making process. SFAS 71 assets and liabilities
recorded on September 30 consist of the following:
32
(Millions of dollars) 1996 1995
- ------------------------------------------------------------------
Assets:
Unrecovered environmental response costs .... $ 38.0 $ 34.9
Unrecovered integrated resource plan costs .. 10.0 9.9
Unrecovered postretirement benefits costs ... 9.7 7.2
Deferred purchased gas adjustment ........... 4.7
Unamortized cost to repurchase long-term debt 3.4 4.9
- ------------------------------------------------------------------
Total ......................................... $ 65.8 $ 56.9
- ------------------------------------------------------------------
Liabilities:
Unamortized investment tax credit ........... $ 28.8 $ 30.3
Regulatory tax liability .................... 19.3 23.3
Deferred purchased gas adjustment
6.3
Environmental response cost recoveries from
third parties ........................... 7.4
Environmental response cost recoveries from
third parties - customer portion ........ 4.5
Other ....................................... 3.7 15.0
- ------------------------------------------------------------------
Total ......................................... $ 63.7 $ 74.9
- ------------------------------------------------------------------
UTILITY PLANT AND DEPRECIATION
Utility plant is stated at original cost. Direct labor and material
costs of plant construction and related indirect construction costs, including
administrative, engineering and general overhead, taxes, and an allowance for
funds used during construction (AFUDC), are added to utility plant. The portion
of AFUDC attributable to equity funds is included in other income, and the
portion attributable to borrowed funds is shown as a reduction in interest
charges in the statements of consolidated income. The AFUDC rate of 9.32% for
the three-year period ended September 30, 1996, was the cost of capital approved
by the Georgia Commission in a prior rate proceeding.
The original cost of utility property retired or otherwise disposed of,
plus the cost of dismantling, less salvage, is charged to accumulated
depreciation. Maintenance, repairs and minor additions, renewals, and
betterments to property are charged to operations.
The composite straight-line depreciation rate was approximately 3.2%
for utility property other than transportation equipment for the three-year
period ended September 30, 1996. Transportation equipment is depreciated over a
period of five to 10 years.
DEFERRED PURCHASED GAS ADJUSTMENT
AGLC's rate schedules include purchased gas adjustment provisions that
permit the recovery of purchased gas costs. The purchased gas adjustment factor
is revised periodically to reflect changes in the cost of purchased gas without
formal rate proceedings. Any overrecoveries or underrecoveries of gas costs are
charged or credited to cost of gas and are included in current assets or
liabilities.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue
limited gas supply hedging activities. The 1997 hedging program has been
expanded beyond the program approved in the 1996 Gas Supply Plan. Accounting for
hedging activities is provided in accordance with Statement of Financial
Accounting Standards No. 80, "Accounting for Futures Contracts." The
33
financial results of all hedging activities are passed through to firm
service customers under the purchased gas provisions of AGLC's rate schedules.
Accordingly, there is no earnings impact as a result of the hedging program.
OPERATING REVENUES
Revenues are based on rates approved by the Georgia Commission and the
TRA. Customers' base rates may not be changed without formal approval of the
Georgia Commission or the TRA. Revenues are recognized on the accrual basis,
which includes estimated amounts for gas delivered, but not yet billed.
The Georgia Commission and the TRA have authorized weather
normalization adjustment riders. Such riders are designed to offset the impact
that unusually cold or warm weather has on operating margin.
Certain interruptible customers purchase gas directly from gas
producers and marketers. The Georgia Commission and the TRA have approved
programs whereby transportation charges are billed on those purchases.
INCOME TAXES
Deferred income taxes result from temporary differences between book
and taxable income and principally relate to depreciation.
Investment tax credits have been deferred and are being amortized by
credits to income in accordance with regulatory treatment over the estimated
lives of the related properties.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, AGLC considers all highly liquid
investments purchased with a maturity of three months or less to be cash
equivalents.
USE OF ESTIMATES
Preparing financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions.
Those estimates and assumptions affect the reported amounts of assets and
liabilities, disclosure on contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
OTHER
Gas inventories are stated at cost on a principally first-in, first-out
method. Materials and supplies inventories are stated at lower of average cost
or market.
Consistent with the rate treatment prescribed by the Georgia Commission
and the TRA, vacation pay and short-term disability benefits are expensed when
those benefits are paid.
Certain reclassifications have been made in 1995 and 1994 to conform with
the 1996 financial statement presentation.
34
2. Income Tax Expense
AGLC's income taxes are included as a part of AGL Resources'
consolidated income tax return. The information included herein relates to
AGLC's allocated portion.
Deferred tax balances are measured at the tax rates that will apply
during the period the taxes become payable and are adjusted whenever new rates
are enacted. Due to the regulated nature of AGLC's business, a regulatory
liability has been recorded in accordance with Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes." The regulatory liability is
being amortized over approximately 30 years.
Components of income tax expense shown in the consolidated income
statements are as follows:
(Millions of dollars) 1996 1995 1994
- -------------------------------------------------------------------------------
Included in operating expenses:
Current income taxes
Federal $18.1 $16.4 $19.7
State 2.6 2.5 3.1
Deferred income taxes
Federal 20.4 (1.1) 11.5
State 3.9 (0.2) 1.5
Amortization of investment tax credits (1.5) (1.6) (1.5)
- -------------------------------------------------------------------------------
Total 43.5 16.0 34.3
- -------------------------------------------------------------------------------
Included in other income:
Current income taxes
Federal 4.2 0.5 1.2
State 0.6 0.1 0.2
Deferred income taxes
Federal 0.1 0.5
State 0.1
- -------------------------------------------------------------------------------
Total 4.8 0.7 2.0
- -------------------------------------------------------------------------------
Total income tax expense $48.3 $16.7 $36.3
- -------------------------------------------------------------------------------
A reconciliation between the statutory federal income tax rate and the
effective rate is as follows:
(Millions of dollars) 1996
- --------------------------------------------------------------------
% of
Pretax
Amount Income
- --------------------------------------------------------------------
Computed tax expense $45.1 35.0
State income tax, net of federal
income tax benefit 4.4 3.3
Amortization of investment tax credits (1.5) (1.2)
Other-net 0.3 0.3
- --------------------------------------------------------------------
Total income tax expense $48.3 37.4
- --------------------------------------------------------------------
35
(Millions of dollars) 1995
- --------------------------------------------------------------------
% of
Pretax
Amount Income
- --------------------------------------------------------------------
Computed tax expense $16.6 35.0
State income tax, net of federal
income tax benefit 1.3 2.7
Amortization of investment tax credits (1.6) (3.4)
Other-net 0.4 0.8
- --------------------------------------------------------------------
Total income tax expense $16.7 35.1
- --------------------------------------------------------------------
(Millions of dollars) 1994
- --------------------------------------------------------------------
% of
Pretax
Amount Income
- --------------------------------------------------------------------
Computed tax expense $34.8 35.0
State income tax, net of federal
income tax benefit 3.2 3.2
Amortization of investment tax credits (1.5) (1.5)
Other-net (0.2) (0.2)
- --------------------------------------------------------------------
Total income tax expense $36.3 36.5
- --------------------------------------------------------------------
36
Components that give rise to the net deferred income tax liability as
of September 30 are as follows:
(Millions of dollars) 1996 1995
- --------------------------------------------------------------------------------
Deferred tax liabilities:
Property - accelerated depreciation and other
property-related items $193.4 $187.1
Other 15.2 15.8
- --------------------------------------------------------------------------------
Total deferred tax liabilities 208.6 202.9
- --------------------------------------------------------------------------------
Deferred tax assets:
Deferred investment tax credits 11.1 11.7
Alternative minimum tax 11.8 12.3
Other 29.4 40.1
- --------------------------------------------------------------------------------
Total deferred tax assets 52.3 64.1
- --------------------------------------------------------------------------------
Net deferred tax liability $156.3 $138.8
- --------------------------------------------------------------------------------
3. Corporate Restructuring
In November 1994 AGLC announced a corporate restructuring plan and
began its implementation during fiscal 1995. As a result of the restructuring,
AGLC combined offices and established centralized customer service centers.
During 1995 AGLC reduced the average number of employees by approximately 500
through voluntary retirement, severance programs and attrition. Restructuring
costs of $43.1 million, after income taxes, were recorded by AGLC during 1995.
The principal effects of the restructuring charges were to increase obligations
with respect to pension benefits and postretirement benefits other than
pensions.
During the fourth quarter of fiscal 1996, AGLC reviewed its remaining
liabilities with respect to its corporate restructuring plan. As a result, AGLC
adjusted its restructuring accruals and reduced operating expenses by $1.6
million, after income taxes. The remaining balance of restructuring liabilities
as of September 30, 1996 and 1995 was $1 million and $4.8 million, respectively.
4. Employee Benefit Plans
Effective July 1, 1996, the Board of Directors authorized the transfer
of the sponsorship of all employee benefit plans from AGLC to AGL Resources.
Substantially all employees of AGLC are eligible to participate in the AGL
Resources-sponsored benefit plans.
AGLC participates in an AGL Resources noncontributory defined benefit
retirement plan. The plan's assets consist primarily of marketable securities,
corporate obligations, U.S. government obligations, insurance contracts, real
estate investments and cash equivalents. The plan provides pension benefits that
are based on years of service and the employee's highest 36 consecutive months'
compensation out of the last 60 months worked. AGL Resources' funding policy is
to make the annual contribution required by applicable regulations and
recommended by its actuary.
AGLC participates in an AGL Resources excess benefit plan that is
unfunded and provides supplemental benefits to certain officers after
retirement. In September 1994, AGL
37
Resources established a voluntary early retirement plan for certain officers of
AGL Resources that is unfunded and provides supplemental pension benefits to
participants who elected early retirement. The annual expense and accumulated
benefits of such plans are not significant.
Net periodic pension costs for the plans include service cost, interest
cost, return on pension assets and straight-line amortization of unrecognized
initial net assets over approximately 16 years. Net periodic pension costs
allocated to AGLC include the following components:
(Millions of dollars) 1996 1995 1994
- --------------------------------------------------------------------------------
Service cost $ 4.0 $ 4.5 $ 5.5
Interest cost 15.8 14.9 13.2
Actual return on assets (19.3) (17.0) (3.3)
Net amortization and deferral 6.3 5.9 (6.2)
- --------------------------------------------------------------------------------
Net periodic pension cost $ 6.8 $ 8.3 $ 9.2
- --------------------------------------------------------------------------------
Actuarial assumptions used include:
Discount rate 7.8% 8.3% 8.3%
Rate of increase in compensation levels 4.5% 5.0% 5.0%
Expected long-term rate of return on assets 8.3% 8.3% 8.3%
- --------------------------------------------------------------------------------
The following schedule sets forth the funded status of the AGL
Resources' plan as of June 30, 1996, and 1995, and amounts recognized in the
consolidated balance sheets of AGLC as of September 30, 1996 and 1995:
(Millions of dollars) 1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of benefit obligations
Vested benefit obligation $ 180.5 $ 175.6
- --------------------------------------------------------------------------------
Accumulated benefit obligation $ 183.2 $ 178.3
- --------------------------------------------------------------------------------
Projected benefit obligation $(212.9) $(207.4)
Plan assets at fair value 181.8 163.9
- --------------------------------------------------------------------------------
Plan assets less than projected benefit obligation (31.1) (43.5)
Unrecognized net loss 26.8 34.1
Remaining unrecognized net assets at date of
initial adoption (4.5) (5.2)
Unrecognized prior service cost 3.9 4.3
- --------------------------------------------------------------------------------
Accrued pension costs $ (4.9) $ (10.3)
- --------------------------------------------------------------------------------
During 1995 a curtailment loss of $6 million and a loss associated with
incentive benefits of $25.3 million was incurred as a result of a corporate
restructuring plan (see Note 3). The effect of the curtailment loss and
incentive loss was to increase the accumulated benefit obligation and projected
benefit obligation by $25.3 million and $31.3 million, respectively.
AGLC participates in AGL Resources' Retirement Savings Plus Plan (RSP
Plan), a 401(k) plan, that provides participants a mechanism for making
contributions for retirement savings. Each participant may contribute amounts up
to 15% of eligible compensation. AGL Resources makes a contribution equal to 65%
of the participant's contribution not to exceed 3.9%
38
of the participant's compensation for the plan year. The contribution was $3.2
million for 1996, $3.3 million for 1995 and $3.4 million for 1994.
AGLC participates in AGL Resources' Nonqualified Savings Plan (NSP), an
unfunded, nonqualified plan similar to the RSP Plan, that was established on
July 1, 1995. The NSP provides an opportunity for eligible employees to make
contributions for retirement savings. AGL Resources' contributions during 1996
and 1995 to the NSP were not significant.
AGLC participates in AGL Resources' Leveraged Employee Stock Ownership
Plan (LESOP). In January 1988, in connection with the LESOP, AGL Resources
purchased 2 million shares of its common stock for $11.75 per share, with the
proceeds of a loan secured by such common stock. AGL Resources has not
guaranteed the repayment of the loan. The loan is expected to be repaid from
regular cash dividends on AGL Resources' common stock paid to the LESOP and from
contributions to the LESOP as approved by AGL Resources' Board of Directors.
Contributions to the LESOP were $0.7 million for 1996 and $0.8 million for 1995
and $0.8 million for 1994. The principal balance of the loan was $2.9 million as
of September 30, 1996, and $5.3 million as of September 30, 1995. The loan is
payable on December 31, 1997.
AGLC's officers and employees participate in AGL Resources' Long-Term
Stock Incentive Plan (LTSIP). The LTSIP provides that incentive and nonqualified
stock options, restricted stock and stock appreciation rights may be granted to
key employees of AGL Resources and its subsidiaries. The exercise price of any
shares under option must be at least equal to the fair market value on the date
of the grant. The options granted become exercisable six months after the date
of grant and generally expire 10 years after the date of grant.
In addition to providing pension benefits, AGL Resources provides
certain health care and life insurance benefits for retired employees.
Substantially all employees become eligible for those benefits if they reach
retirement age while working for AGLC.
In 1993 the Georgia Commission approved a five-year phase-in of
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106) expense that defers a
portion of SFAS 106 expense for future recovery. A regulatory asset has been
recorded for the deferred portion of SFAS 106 expense. In 1993, the TRA approved
the recovery of SFAS 106 expense that is funded through an external trust.
Net periodic postretirement benefits costs allocated to AGLC for fiscal
1996 and 1995 include the following components:
(Millions of dollars) 1996 1995 1994
- ---------------------------------------------------------------------
Service cost $0.8 $ 0.9 $ 1.0
Interest cost 8.8 7.6 6.5
Actual return on assets (0.6) (0.3)
Amortization of transition obligation 4.2 4.2 4.1
- ---------------------------------------------------------------------
Net postretirement benefits costs $13.2 $12.4 $11.6
- ---------------------------------------------------------------------
Approximately $10.7 million, $8.7 million and $8.0 million of net
periodic postretirement benefits costs for fiscal 1996, 1995 and 1994,
respectively, were recovered from
39
AGLC's customers. The remaining $2.5 million, $3.7 million and $3.6 million for
1996, 1995 and 1994, respectively, were deferred for future recovery through
amortization and recognized as a regulatory asset in the financial statements
consistent with regulatory decisions. AGL Resources has funded through an
external trust SFAS 106 expense recovered from its utility customers in excess
of the pay-as-you-go amounts.
The following schedule sets forth the funded status of the AGL
Resources plan as of September 30, 1996 and 1995:
(Millions of dollars) 1996 1995
- -------------------------------------------------------------------------------
Retirees $(85.8) $(94.1)
Fully eligible active plan participants (6.4) (9.3)
Other active plan participants (13.3) (14.5)
- -------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation (105.5) (117.9)
Plan assets at fair value 10.4 8.0
- -------------------------------------------------------------------------------
Accumulated postretirement benefit obligation
in excess of plan assets (95.1) (109.9)
Unrecognized transition obligation 69.5 73.6
Unrecognized (gain) loss (10.6) 6.2
- -------------------------------------------------------------------------------
Accrued postretirement benefits costs $(36.2) $(30.1)
- -------------------------------------------------------------------------------
During 1995 a curtailment loss of $22.9 million was incurred as a
result of a corporate restructuring (see Note 3). The assumed health care cost
trend rate used in measuring the accumulated postretirement benefit obligation
for pre-Medicare eligibility is 11% in 1996, decreasing 0.5% per year to 6% in
the year 2006 and an additional 0.25% to 5.75% in 2007. The rate for
post-Medicare eligibility is 9.5% in 1996, decreasing 0.5% per year to 5.5% in
the year 2004 and an additional 0.25% to 5.25% in 2005. Increasing the assumed
health care cost trend rate by 1% would increase the accumulated postretirement
benefit obligation as of September 30, 1996, by approximately $6 million and the
accrued postretirement benefits cost by approximately $0.5 million for fiscal
1996. The assumed discount rate used in determining the postretirement benefit
obligation was 7.75% in 1996 and 1995.
5. Common Stock
On March 6, 1996, AGLC completed a corporate restructuring in which AGL
Resources became the holding company for AGLC and its subsidiaries. The holding
company formation was completed upon receipt of shareholder approval on March 6,
1996, when each share of AGLC common stock was converted into one share of AGL
Resources common stock, and AGLC became the primary subsidiary of AGL Resources.
AGL Resources holds all shares of common stock of AGLC outstanding as of March
6, 1996.
On November 3, 1995, the Board of Directors declared a two-for-one
stock split of the common stock effected in the form of a 100% stock dividend to
shareholders of record on November 17, 1995, and payable on December 1, 1995.
AGLC recorded a decrease to premium on capital stock and an increase to common
stock of $137.5 million to transfer the amount of the par value of the stock
dividend to common stock. All references to number of shares have been restated
retroactively to reflect the stock dividend.
40
Common stock dividends declared during the first and second quarters of
fiscal 1996 were paid to AGLC's public shareholders. Dividends declared during
the third and fourth quarters of fiscal 1996 were paid to AGL Resources.
6. Preferred Stock
AGLC is required under its charter to offer to purchase or call for
redemption 4,100 shares of preferred stock for each of the five years ending
September 30, 2001. The issues are callable at the option of AGLC, in whole or
in part, upon 30 days' notice. Shares reacquired by AGLC to satisfy future
requirements and reported as if canceled were 6,715; 7,715; and 8,715, as of
September 30, 1996, 1995, and 1994, respectively.
AGLC's charter contains provisions limiting the issuance of additional
shares of preferred stock. The most restrictive of those provisions requires
gross income, as defined, for a specified 12-month period to be at least equal
to 1.5 times the sum of annualized interest requirements on outstanding
indebtedness and the dividend requirements on outstanding preferred stock,
including the preferred stock being issued. Based on earnings for fiscal 1996,
AGLC's gross income was 2.48 times the sum of its interest and preferred stock
dividend requirements.
As of September 30, 1996, AGLC had 10 million shares of authorized, but
unissued, preferred stock, no par value.
The outstanding preferred stock, net of current maturities, as of
September 30 is as follows:
(Millions of dollars) 1996 1995
- ---------------------------------------------------------------------
$100 par or stated value
(callable at option of AGLC)
Redeemable preferred stock
4.72% - Current call
price $103.00 $ 1.5 $ 1.5
7.70% - Current call
price (a) 44.5 44.5
7.84% - Current call
price
$101.96 4.6 4.6
8.32% - Current call
price
$102.08 4.9 4.9
Nonredeemable preferred stock
4.50% - Current call
price
$105.25 2.0 2.0
5.00% - Current call
price
$105.00 1.0 1.0
- ---------------------------------------------------------------------
Total $58.5 $58.5
- ---------------------------------------------------------------------
(a) Not redeemable prior to December 1, 1997. Redeemable at par thereafter.
41
The outstanding shares of preferred stock net of previously reacquired
shares and shares reacquired during the year for purchase fund requirements are
as follows:
1996 1995 1994
- -------------------------------------------------------------
4.50% Series
Outstanding 20,000 20,000 20,000
4.72% Series
Outstanding 15,285 15,285 15,285
5.00% Series
Outstanding 10,000 10,000 10,000
7.70% Series
Outstanding 445,000 445,000 445,000
7.84% Series
Outstanding 47,645 47,797 47,802
Reacquired 152 5 1,500
8.32% Series
Outstanding 49,854 50,004 50,004
Reacquired 150 215
- -------------------------------------------------------------
Total
Outstanding 587,784 588,086 588,091
Reacquired 302 5 1,715
- -------------------------------------------------------------
7. Long-Term Debt
Medium-term notes Series A, Series B and Series C were issued under an
Indenture dated December 1, 1989. The notes are unsecured and rank on a parity
with all other unsecured indebtedness. During 1994, $194.5 million in principal
amount of such notes was issued. The annual maturities of long-term debt for the
five years ending September 30, 2001, are $50 million in 2000 and $20 million in
2001.
The outstanding long-term debt, net of current maturities, as of
September 30 is as follows:
(Millions of dollars) 1996 1995
- ----------------------------------------------------------------
Medium-term notes
Series A (1) $ 60.0 $ 60.0
Series B (2) 300.0 300.0
Series C (3) 194.5 194.5
- ----------------------------------------------------------------
Total $554.5 $554.5
- ----------------------------------------------------------------
(1) Interest rates from 8.90% to 9.10% with maturity dates from 2000 to 2021.
(2) Interest rates from 7.15% to 8.70% with maturity dates from 2000 to 2023.
(3) Interest rates from 5.90% to 7.20% with maturity dates from 2004 to 2024.
8. Short-Term Debt
Lines of credit with various banks provide for direct borrowings and
are subject to annual renewal. The current lines of credit vary throughout the
year from $75 million in the
42
summer months to $253 million for peak winter financing. Certain of the lines
are on a commitment fee basis. As of September 30, 1996, $59.3 million was
available on lines of credit.
Short-term borrowings consisted of the following:
(Millions of dollars) 1996 1995 1994
- -------------------------------------------------------------------
Short-term debt outstanding
at end of year $ 152.0 $ 51.0 $ 95.4
Maximum amounts of short-term
debt outstanding at any month
end during the year 156.3 155.0 229.4
Average amounts of short-term
debt outstanding
during the year (a) 87.5 51.5 69.3
- -------------------------------------------------------------------
Weighted Average Interest Rates
1996 1995 1994
- -------------------------------------------------------------------
Short-term debt outstanding
at end of year 5.7% 5.9% 5.1%
Average amounts of short-term
debt outstanding
during the year (a) 5.8% 5.7% 3.6%
- -------------------------------------------------------------------
(a) Average amount outstanding during the year calculated based on daily
outstanding balances. Weighted average interest rate during the year calculated
based on interest expense and average amount outstanding during the year.
9. Commitments and Contingencies
AGLC has agreements for firm pipeline and storage capacity that expire
at various dates through 2012. The aggregate amount of required payments under
such agreements totals approximately $1.1 billion, with annual required payments
of $225 million in 1997, $218 million in 1998, $156 million in 1999, $107
million in 2000 and $78 million in 2001. Total payments of fixed charges under
all agreements were $225 million in 1996, $230 million in 1995 and $232 million
in 1994. The purchased gas adjustment provisions of AGLC's rate schedules permit
the recovery of gas costs from customers.
In 1992 the Federal Energy Regulatory Commission (FERC) issued Order
636, which, among other things, mandated the unbundling of interstate pipeline
sales service and established certain open access transportation regulations
that became effective beginning in the 1993-1994 heating season. Order 636
permits AGLC's pipeline suppliers to pass through any prudently incurred
transition costs, such as unrecovered gas costs, gas supply realignment costs
and stranded costs. AGLC estimates its portion of such costs from all of its
pipeline suppliers would approximate $109.9 million based on filings with FERC
by the pipeline suppliers. Approximately $80.6 million of such costs have been
incurred by AGLC as of September 30, 1996, recovery of which is provided under
the purchased gas provisions of AGLC's rate schedules.
43
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue
limited gas supply hedging activities. The 1997 hedging program has been
expanded beyond the program approved in the 1996 Gas Supply Plan. The financial
results of all hedging activities are passed through to firm service customers
under the purchased gas provisions of AGLC's rate schedules. Accordingly, there
is no earnings impact as a result of the hedging program. Contracts outstanding
as of September 30, 1996, and during the year then ended, were not significant.
As of September 30, 1996, approximately 32% of AGLC's labor force was
covered by collective bargaining agreements. A collective bargaining agreement
with the General Teamsters Local Union No. 528 expired on September 15, 1996. A
new, four-year contract was finalized on October 13, 1996. In addition, a new,
five-year agreement with the Utility Workers' Union of America, Local Union No.
461, became effective October 15, 1996.
Total rental expense for property and equipment was $3 million in 1996,
$6.3 million in 1995 and $6.5 million in 1994. Minimum annual rentals under
noncancelable operating leases are as follows: 1997 - $3 million; 1998 - $3.1
million; 1999 - $3.1 million; 2000 - $3.3 million; 2001 - $3.4 million; and
thereafter - $6.3 million.
AGLC is involved in litigation arising in the normal course of business
(see Note 11 regarding Environmental Matters). Management believes that the
ultimate resolution of such litigation will not have a material adverse effect
on the consolidated financial statements.
10. Customers' and Suppliers' Refunds
Pursuant to orders of FERC, AGLC has received refunds from its
interstate natural gas suppliers. Those refunds are a result of FERC orders
adjusting the price of various pipeline services purchased by AGLC from its
suppliers in prior periods. AGLC passes the refunds on to its customers under
purchased gas provisions of rate schedules approved by the Georgia Commission
and the TRA.
On August 23, 1995, the Georgia Commission approved a $38.5 million
plus interest refund of deferred purchased gas costs. The refund resulted from
the overrecovery of gas costs through the purchased gas provisions of AGLC's
rate schedules. The refund was credited to customers' bills in September 1995.
On September 7, 1994, the Georgia Commission approved a $13.5 million
refund of deferred purchased gas costs. The refund resulted from the
overrecovery of gas costs through the purchased gas provisions of AGLC's rate
schedules. The refund was credited to customers' bills in September 1994.
11. 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 that AGLC does not now own, but that may have been
associated with the operation of MGPs by AGLC or its predecessors. There are
three sites in Florida that have been investigated by environmental authorities
in connection with which AGLC may be contacted as a potentially
44
responsible party. Preliminary assessments and subsequent site investigations
have revealed environmental impacts at and near some of those sites.
Under a thorough analysis of potentially applicable requirements, AGLC
has estimated that, under the most favorable circumstances reasonably possible,
the future cost of investigating and remediating the former MGP sites, excluding
sites for which no remediation is expected or the cost of which cannot be
estimated, could be as low as $30.4 million. Alternatively, AGLC has estimated
that, under the least favorable circumstances reasonably possible, the future
cost of investigating and remediating the same former MGP sites could be as high
as $110.8 million, excluding sites for which no remediation is expected or the
cost of which cannot be estimated. AGLC cannot estimate at this time the amount
of any other future expenses or liabilities, or the impact on those estimates of
future environmental or regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the $30.4 million to $110.8
million range can be 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 in the financial statements.
The Georgia Commission has approved the recovery by AGLC of
environmental response costs, pursuant to AGLC's 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 has undertaken a financial and
management process audit related to the MGP sites, cleanup activities at the
sites and environmental response costs that have been incurred for purposes of
the ERCRR. 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.
AGLC is currently a party to claims and litigation related to the
former MGP sites. During fiscal 1996 AGLC recovered $14.7 million from its
insurance carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $1.6 million, after
income taxes, and established regulatory liabilities for the remainder of those
recoveries. AGLC intends to continue to pursue insurance coverage and
contributions from potentially responsible parties.
12. Fair Value of Financial Instruments
AGLC has estimated the fair value of its financial instruments, the
carrying value of which differed from fair value using available market
information and appropriate valuation methodologies. Considerable judgment is
required in developing the estimates of fair value presented herein and,
therefore, the values are not necessarily indicative of the amounts that could
be realized in a current market exchange.
The carrying amount and the estimated fair value of such financial
instruments as of September 30, 1996 and 1995, consist of the following:
45
Carrying Estimated
(Millions of dollars) Amount Fair Value
- ------------------------------------------------------------------------------
1996
Long-term debt including current portion $554.5 $566.6
Redeemable cumulative preferred stock of AGLC,
including current portion 55.8 56.9
- ------------------------------------------------------------------------------
1995
Long-term debt including current portion $554.5 $571.5
Redeemable cumulative preferred stock of AGLC,
including current portion 55.8 56.6
- ------------------------------------------------------------------------------
The estimated fair values are determined based on the following:
Long-term debt - interest rates that are currently available for issuance of
debt with similar terms and remaining maturities.
Redeemable cumulative preferred stock - quoted market price and dividend rates
for preferred stock with similar terms.
The fair value estimates presented herein are based on information available to
management as of September 30, 1996, and 1995. Management is not aware of any
subsequent factors that would affect the estimated fair value amounts
significantly.
13. Related Parties
During August 1995 AGLC signed an agreement with Sonat Inc. (Sonat) to
form a joint venture to acquire the business of Sonat Marketing Company, a
wholly owned subsidiary of Sonat. AGLC invested $32.6 million for a 35%
ownership interest in Sonat Marketing. AGLC's 35% investment is being accounted
for under the equity method. The excess of the purchase price over the estimated
fair value of the net tangible assets of approximately $23 million has been
allocated to intangible assets consisting of customer lists and goodwill, which
is being amortized over 10 and 35 years, respectively. During the third quarter
of fiscal 1996 AGLC's interest in Sonat Marketing was dividended to AGL
Investments.
During fiscal 1996 and September 1995, AGLC purchased gas totaling
$247.5 million and $23.7 million, respectively, from Sonat Marketing and its
affiliates. As of September 30, 1996, and 1995, AGLC had outstanding obligations
payable to Sonat Marketing of $18.8 million and $23.7 million, respectively.
Accounts receivable and accounts payable balances as of September 30,
1996, resulting from related party transactions are as follows:
(Millions of dollars) 1996
- ------------------------------------------------------------------
Payable to AGL Resources -- short-term $ (4.7)
Payable to AGL Resources -- long-term (41.1)
Receivable from nonregulated subsidiaries 2.0
- ------------------------------------------------------------------
Total payable to associated companies $(43.8)
- ------------------------------------------------------------------
46
14. Quarterly Financial Data (Unaudited)
Quarterly financial data for fiscal 1996 and 1995 are summarized as
follows:
(Millions) Operating Operating Net Income
Quarter Ended Revenues Income (Loss)
- --------------------------------------------------------------------------------
1996
December 31, 1995 $328.8 $42.0 $30.2
March 31, 1996 478.8 54.5 46.4
June 30, 1996 240.5 16.5 5.0
September 30, 1996(a) 169.5 8.9 (1.0)
- --------------------------------------------------------------------------------
1995(b)
December 31, 1994 $328.8 $14.1 $ 1.8
March 31, 1995 448.2 48.9 37.3
June 30, 1995 177.5 12.2 1.4
September 30, 1995(c) 108.5 1.7 (9.7)
- --------------------------------------------------------------------------------
(a) During the fourth quarter of fiscal 1996, AGLC increased net income by $1.6
million as a result of a review of remaining liabilities in connection with a
corporate restructuring plan. (See Note 3).
In addition, net income was increased during the fourth quarter of fiscal 1996
by $1.6 million in connection with recoveries from insurers in accordance with
provisions of an environmental response cost recovery rider. (See Note 11).
(b) Quarterly operating income (loss) for 1995 includes the effects of charges
for restructuring costs as follows: $44.5 million for the quarter ended December
31, 1994; $23.0 million for the quarter ended March 31, 1995; $1.7 million for
the quarter ended June 30, 1995; and $1.1 million for the quarter ended
September 30, 1995.
Quarterly net income (loss) for 1995 includes the effects of charges for
restructuring costs as follows: $28.4 million for the quarter ended December 31,
1994; $13.0 million for the quarter ended March 31, 1995; $1.1 million for the
quarter ended June 30, 1995; and $0.6 million for the quarter ended September
30, 1995.
The wide variance in quarterly earnings results from the highly seasonal nature
of AGLC's business.
(c) During the fourth quarter of fiscal 1995, AGLC recorded a refund to its
customers of $38.5 million plus interest. (See Note 10).
47
Independent Auditors' Report
Shareholder and Board of Directors of Atlanta Gas Light Company:
We have audited the accompanying consolidated balance sheets of Atlanta Gas
Light Company and subsidiaries as of September 30, 1996 and 1995 and the related
statements of consolidated income, common stock equity, and cash flows for each
of the three years in the period ended September 30, 1996. Our audits also
included the financial statement schedule listed in the Index at Item 14. These
financial statements and financial statement schedule are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Atlanta Gas Light Company and subsidiaries
as of September 30, 1996 and 1995 and the results of its operations and its cash
flows for each of the three years in the period ended September 30, 1996, in
conformity with generally accepted accounting principles. Also, in our opinion,
such financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
November 5, 1996
48
- --------------------------------------------------------------------------------
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
- --------------------------------------------------------------------------------
The remainder of this page was intentionally left blank.
49
Part III
- --------------------------------------------------------------------------------
Item 10. Directors and Executive Officers of the Registrants
Set forth below is certain information regarding AGLC's executive officers
and directors (two of whom are employees of AGLC), including their ages, as of
September 30, 1996, their principal occupations (which have continued for at
least the past five years unless otherwise noted), the year in which each was
elected and any directorships held by them in other public companies.
DAVID R. JONES, age 59, is President and Chief Executive Officer of AGLC
(since 1988) and President and Chief Executive Officer and director of AGL
Resources and Service Company (since January 1996 and August 1996,
respectively); director of the Federal Reserve Bank of Atlanta. Mr. Jones has
been a director of AGLC since 1985.
THOMAS H. BENSON, age 51, Chief Operating Officer of AGLC and Executive
Vice President of AGL Resources since August 1996, Executive Vice President
Customer Operations of AGLC from 1994 until 1996 and Senior Vice President
Operations and Engineering of AGLC from 1988 until 1994. Mr. Benson has been a
director of AGLC since 1996.
CHARLIE J. LAIL, age 57, Senior Vice President Operations Improvement of
AGLC since 1994, Senior Vice President Divisions of AGLC from 1992 until 1994,
Vice President Divisions of AGLC from 1991 until 1992 and Vice President and
Northeast Georgia Division manager of AGLC from 1988 until 1991.
MICHAEL D. HUTCHINS, age 45, Vice President Operations and Engineering of
AGLC since 1994, Vice President Engineering of AGLC from 1989 until 1994.
CHARLES W. BASS, age 49, Executive Vice President and Chief Operating
Officer of AGL Resources since August 1996, Executive Vice President Market
Service and Development of AGLC from 1994 until 1996 and Senior Vice President
Governmental and Regulatory Affairs of AGLC from 1988 until 1994. Mr. Bass has
been a director of AGLC since 1996.
MELANIE M. PLATT, age 42, Corporate Secretary of AGLC since February 1995,
Corporate Secretary of AGL Resources and Service Company (since January 1996 and
August 1996, respectively), previously associated with the law firm of Long,
Aldridge & Norman, LLP, general counsel for AGLC, from 1985 until December 1994.
Ms. Platt has been a director of AGLC since 1996.
The By-Laws of AGLC provide that the Board of Directors shall consist of
such number of directors as shall be fixed from time to time exclusively
pursuant to a resolution adopted by the Board. The Board of Directors has
established four directorships and has proposed that AGL Resources, as sole
shareholder, elect as directors the four present directors named above to serve
until the next succeeding Annual Meeting or until their respective successors
have been duly elected. Each nominee presently is a director of AGLC and has
consented to serve as a director if elected.
50
Section 16(a) Beneficial Ownership Reporting Compliance
AGLC is required to identify any director, executive officer or person who
owns more than ten percent of any class of Preferred Stock of AGLC registered
pursuant to Section 12 of the Securities Exchange Act of 1934 (Exchange Act) or
any interest in any such class of Preferred Stock of AGLC who failed to timely
file with the Securities Exchange Commission (Commission) a required report
under Section 16(a) of the Exchange Act. Section 16(a) and regulations of the
Commission thereunder require executive officers and directors and persons who
own more than ten percent of any such class of Preferred Stock of AGLC or any
interest in any such class of Preferred Stock of AGLC, as well as certain
affiliates of such persons, to file initial reports of ownership and changes in
ownership of such securities with the Commission and the New York Stock
Exchange. Executive officers, directors and persons owning more than ten percent
of any such class of Preferred Stock of AGLC or any interest in any such class
of Preferred Stock of AGLC are required by regulation of the Commission to
furnish AGLC with copies of all Section 16(a) forms that they file. Based solely
on its review of the copies of such forms received by it and written
representations that no other reports were required for those persons, AGLC
believes that, during the fiscal year ended September 30, 1996, all applicable
filing requirements were complied with.
- --------------------------------------------------------------------------------
Item 11. Executive Compensation
Table 1 summarizes by various categories, for the fiscal years ended
September 30, 1996, 1995 and 1994, the total compensation paid to or accrued for
the President and Chief Executive Officer of AGLC and each other executive
officer of AGLC whose salary and bonus for the fiscal year ended September 30,
1996 exceeded $100,000 (collectively referred to as the "named executive
officers").
TABLE 1: SUMMARY COMPENSATION TABLE
Annual Compensation
Long-Term
Compensation
Other
Fiscal Year Annual Securities All Other
Name and Ended Compen- Underlying Compensa-
Principal Position September 30 Salary($)(1) Bonus ($)(2) sation($)(3) Options(#)(4) tion($)(5)
- ------------------ ------------ ------------ ------------- ------------ ------------- ----------
David R. Jones 1996 $474,923 $160,800 - 37,161 $46,080
President and 1995 444,423 230,000 $11,750 43,126 33,293
Chief Executive Officer 1994 409,981 53,950 26,500 33,536 28,181
Thomas H. Benson 1996 248,885 83,600 - 20,129 17,497
Chief Operating Officer 1995 214,362 67,500 - 24,510 24,510
1994 176,375 23,205 - 14,424 11,636
Charlie J. Lail 1996 147,565 49,245 - 7,587 13,146
Senior Vice President 1995 145,962 44,100 - 11,980 12,554
1994 141,742 18,720 - 11,636 11,947
Michael D. Hutchins 1996 132,162 44,570 - 12,276 8,698
Vice President 1995 107,327 33,600 - 7,000 5,135
1994 96,894 10,342 - 5,306 3,015
51
(1) Includes before-tax contributions for the indicated fiscal years made
to the AGL Resources Inc. Retirement Savings Plus Plan (RSP Plan) and
the AGL Resources Inc. Nonqualified Savings Plan (NSP).
(2) For fiscal 1996, 1995 and 1994, reflects cash bonus earned pursuant to
the Variable Compensation Plan (formerly the Short-Term Incentive
Plan) by each of the named executive officers other than Mr. Jones.
For fiscal 1996, reflects for Mr. Jones a cash bonus earned. For
fiscal 1995 and 1994, reflects for Mr. Jones a cash bonus and a bonus
award of restricted stock which is not subject to any vesting
restrictions. The dollar value of the restricted stock awards is based
on the number of shares of restricted stock multiplied by the fair
market value per share on the date of issuance.
(3) Includes for Mr. Jones director's fees of $11,750 and $26,500 paid
during fiscal 1995 and 1994, respectively. Effective January 1, 1995,
Mr. Jones no longer receives any compensation for his services as a
director or as a member of a standing committee of the Board. (See
"Director Compensation" below.)
(4) Options to purchase common stock of AGL Resources Inc.; includes
grants of reload options pursuant to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990 (LTSIP).
(5) All Other Compensation paid during fiscal 1996 includes the following:
(i) contributions to the AGL Resources Inc. Leveraged Employee Stock
Ownership Plan: Mr. Jones - $1,829; Mr. Benson - $1,829; Mr. Lail -
$1,789; and Mr. Hutchins - $1,347; (ii) contributions to the RSP Plan:
Mr. Jones - $4,275; Mr. Benson - $5,297; Mr. Lail - $5,733; and Mr.
Hutchins - $5,088; (iii) contributions to the NSP: Mr. Jones -
$13,586; Mr. Benson - $3,671; Mr. Lail - $0; and Mr. Hutchins - $0;
and (iv) premiums paid for life insurance policies, any proceeds of
which are payable to the respective beneficiaries designated by the
named officers: Mr. Jones - $26,390; Mr. Benson - $6,700; Mr. Lail -
$5,624; and Mr. Hutchins - $2,263.
Change in Control Employment Agreements
During fiscal 1996, the Board of Directors of AGL Resources approved an
Employment Continuity Program in which each of the named executive officers
participates on one of three tier levels. The purpose of the program is to
retain key management personnel and assure continued productivity of such
personnel in the event of a change in control of AGL Resources.
For purposes of the program, a "change in control" will be deemed to have
occurred in connection with any of the following events: (i) the acquisition by
a person or group of persons of 10% or more of the voting securities of AGL
Resources; (ii) approval by the shareholders of a merger, business combination,
or sale of 50% or more of AGL Resources' assets, the result of which is that
less than 80% of the voting securities of the resulting corporation is owned by
the former shareholders of AGL Resources; or (iii) the failure, during any
period of two years, of incumbent directors to constitute at least a majority of
the Board of Directors of AGL Resources.
Generally, no benefits are provided under the program for any type of
termination prior to the occurrence of a change in control, or for terminations
following a change in control due to death, disability, voluntary termination
(other than the Chief Executive Officer) or any termination for "cause," which
includes failure to perform duties and responsibilities and fraud or dishonesty.
Upon becoming operational, and depending on the tier level of participation
and on the timing of employment termination, the program provides a severance
benefit of between one and three years of base salary and annual incentive
compensation to participants whose employment is involuntarily terminated within
twelve months following the occurrence of a change in control.
Other benefits provided include the payout of a pro rata bonus for the
portion of the year in which the termination occurs, full vesting of all
long-term incentives, a lump-sum payment of between one and three years of age
and service credits under AGL Resources' pension plan, full vesting and funding
of nonqualified retirement and deferral plan benefits, a one to three year
continuation of healthcare benefits and life insurance, and outplacement
assistance. The Chief Executive Officer and the Executive Vice Presidents of AGL
Resources also will receive payments of legal fees (up to a maximum dollar
limit) in connection with the enforcement of payouts under the program.
For all participants, total severance benefits are limited to the maximum
benefit allowable without triggering excise taxes.
52
Option Grants
Table 2 sets forth information regarding the number and terms of options to
purchase shares of AGL Resources common stock granted to the named executive
officers during the fiscal year ended September 30, 1996. In addition, in
accordance with the rules and regulations of the Commission, set forth is the
present value of each option granted, calculated using the Black-Scholes option
pricing model.
TABLE 2: OPTION GRANTS IN LAST FISCAL YEAR
Number of % of Total
Securities Options
Underlying Granted to Exercise or
Options Employees in Base Price Grant Date
Name Granted(#)(1) Fiscal Year ($/Sh)(2) Expiration Date Present Value($)(3)
David R. Jones 37,161 12.41% $19.375 2/2/06 $90,673
Thomas H. Benson 20,129 6.72 19.375 2/2/06 49,115
Charlie J. Lail 7,587 * 19.375 2/2/06 18,512
Michael D. Hutchins 870 * 19.750 4/24/02 1,957
1,180 * 19.750 2/3/05 2,808
7,329 * 19.375 2/2/06 17,883
2,897 * 20.500 2/3/05 11,211
- ------------------
* Less than 1%.
(1) Options were granted to each of the named executive officers pursuant
to the LTSIP and became fully exercisable six months after the date of
grant. Options are subject to early termination upon the occurrence of
certain events related to termination of employment. Further, Reload
Options (as hereinafter defined) were granted to Mr. Hutchins to
purchase the following number of shares: 870 shares on November 6,
1995; 1,180 shares on November 6, 1995; and 2,897 shares on August 16,
1996.
(2) The exercise price of options may be paid in cash, by delivery of
already owned shares of Common Stock of AGL Resources or by any other
method approved by the Nominating and Compensation Committee, which
administers the LTSIP. To the extent that the exercise price of an
option is paid with shares of common stock of AGL Resources, a "Reload
Option" will be granted to the optionee. A Reload Option is an option
granted for the same number of shares as is exchanged in payment of
the exercise price and is subject to all of the same terms and
conditions as the original option except for the exercise price which
is determined on the basis of the fair market value of the common
stock of AGL Resources on the date the Reload Option is granted. One
or more successive Reload Options may be granted to an optionee who
pays for the exercise of a Reload Option with shares of common stock
of AGL Resources.
(3) The "Grant Date Present Value" is calculated using the Black-Scholes
Warrant Valuation Call Option Model, assuming a constant dividend
yield. This model assumes no dilution effects and includes the
following assumptions for the options granted to the named executive
officers: expected volatility - 16.15% (14.55%, 14.55% and 21.33% with
respect to Mr. Hutchins' Reload Options for 870, 1,180 and 2,897
shares, respectively); annual risk free rate of return (represents the
monthly average yield on ten year Treasury notes during the month of
the grant) - 5.81% (5.80%, 5.90% and 6.58% with respect to Mr.
Hutchins' Reload Options for 870, 1,180 and 2,897 shares,
respectively); annual dividend yield - 5.47% (5.37%, 5.37% and 5.17%
with respect to Mr. Hutchins' Reload Options for 870, 1,180 and 2,897
shares, respectively). The model also assumes an exercise period for
options granted of ten years; provided, however, with respect to Mr.
Hutchins' Reload Options to purchase 870, 1,180 and 2,897 shares of
common stock, an exercise period of approximately 78 months, 111
months and 111 months, respectively, was assumed.
53
Option Exercises
Table 3 sets forth option exercises to purchase shares of AGL Resources
Inc. common stock by the named executive officers during the fiscal year ended
September 30, 1996, including the aggregate value of gains on the date of
exercise. The table also sets forth (i) the number of shares covered by options
(both exercisable and unexercisable) as of September 30, 1996 and (ii) the
respective values for "in-the-money" options, which represent the positive
spread between the exercise price of existing options and the fair market value
of AGL Resources' Common Stock at September 30, 1996.
TABLE 3: AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND
FISCAL YEAR END OPTION VALUES
Exercises During Year Fiscal Year End
--------------------- ---------------
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money Options
Shares Acquired Value Options at Fiscal Year End(#) at Fiscal Year End($)(1)
Name on Exercise(#) Realized($) Exercisable Unexercisable Exercisable Unexercisable
- ---- -------------- ----------- ----------- ------------- ----------- -------------
David R. Jones - - 138,695 - $272,288 -
Thomas H. Benson - - 65,055 - 74,888 -
Charlie J. Lail - - 41,439 - 46,872 -
Michael D. Hutchins 6,250 26,290 23,799 2,897 12,913 -
(1) Certain exercisable options held by the named executive officers were
not "in-the-money" at September 30, 1996.
54
Retirement Plan
Table 4 reflects the estimated annual lifetime benefits calculated on a
straight-life annuity basis and payable under the terms of the AGL Resources
Inc. Retirement Plan (the "Retirement Plan") and the AGL Resources Inc. Excess
Benefit Plan (the "Excess Benefit Plan") (as described below), as currently in
effect, to persons in specified compensation and years of service
classifications upon retirement at age 65. Benefit amounts as reflected in the
table are subject to reductions for a portion of Social Security benefits.
TABLE 4: PENSION PLAN TABLE
3 Year Years of Service
Average ------------------------------------------------------------------------
Earnings 20 25 30 35 40 45
- -------- -- -- -- -- -- --
$100,000 $33,333 $41,667 $50,000 $57,500 $65,000 $72,500
150,000 50,000 62,500 75,000 86,250 97,500 108,750
200,000 66,667 83,333 100,000 115,000 130,000 145,000
250,000 83,333 104,167 125,000 143,750 162,500 181,250
300,000 100,000 125,000 150,000 172,500 195,000 217,500
350,000 116,667 145,833 175,000 201,250 227,500 253,750
400,000 133,333 166,667 200,000 230,000 260,000 290,000
450,000 150,000 187,500 225,000 258,750 292,500 326,250
500,000 166,667 208,333 250,000 287,500 325,000 362,500
The Retirement Plan is a qualified defined benefit pension plan which
covers all employees of AGL Resources and its participating affiliate companies
(except leased employees) who have satisfied certain standards as to hours of
service, who have attained age 21 and who have been employed for one year.
Benefits under the Retirement Plan are based upon length of service, with
varying provisions for employees who are terminated or take early, normal or
deferred retirement. A participant's benefits also vary depending upon the
participant's earnings for the three consecutive years of highest compensation
during his or her final 60 months of employment.
The compensation covered by the Retirement Plan includes generally the
base rate of earnings actually paid to a participant (up to dollar limits
imposed by the Internal Revenue Service). This amount of compensation does not
include the bonuses or director's fees that are included in the above Summary
Compensation Table. The Retirement Plan also provides, subject to certain
conditions, for the payment of vested benefits of a deceased employee to his or
her spouse during such spouse's lifetime.
AGL Resources makes contributions to the Retirement Plan to fund the
benefits which accrue thereunder. Annual contribution amounts are determined
actuarially. Participant contributions are not permitted.
In addition, AGL Resources maintains an Excess Benefit Plan for its
employees, the purpose of which is to restore pension benefits to employees who
are prevented from receiving their total accrued benefits under the Retirement
Plan because of the maximum benefit limitations imposed on qualified retirement
plans by Sections 415 and 401(a)(17) of the Internal Revenue Code of 1986, as
amended (the "Code"). The Excess Benefit Plan is not funded, but benefit
payments are made directly by AGL Resources. Benefits under the Excess Benefit
Plan are payable in the same form and according to the same general terms and
conditions as benefits under the Retirement Plan. All employees who participate
in the Retirement Plan whose benefits are limited by the provisions of the Code
will receive restoration of benefits under the Excess Benefit Plan.
55
The amounts shown in the Summary Compensation Table above do not
include AGL Resources's contributions in connection with the Retirement Plan or
the Excess Benefit Plan for the named executive officers. Such amounts are not
and cannot be readily separated or individually calculated. AGL Resources made a
contribution of approximately $13.4 million to the Retirement Plan for the plan
year ended June 30, 1996.
As of the plan year ended June 30, 1996, Messrs. Jones, Benson, Lail
and Hutchins had 36, 26, 32 and 23 years of service, respectively.
The Retirement Plan and the Excess Benefit Plan are administered by or
are under the direction of the Retirement Plan Administrative Committee
appointed by the Board of Directors. Wachovia Bank of North Carolina, N.A.,
serves as Trustee to the Retirement Plan. The Retirement Plan must be amended to
bring it into compliance with recent changes in federal law.
Director Compensation
Any director who is an officer or employee of AGLC or AGL Resources does
not receive any compensation for his or her services as a director or as a
member of a standing committee of the Board. Each of the directors of AGLC is an
officer of AGLC and/or AGL Resources.
- --------------------------------------------------------------------------------
Item 12. Security Ownership of Certain Beneficial Owners and Management
As of September 30, 1996, all of the outstanding shares of common stock of
AGLC are beneficially owned by AGL Resources. Accordingly, as of September 30,
1996, AGL Resources is the beneficial owner of more than 5% of the AGLC common
stock.
The following table sets forth certain information as of September 30,
1996 regarding the ownership of AGL Resources common stock by each director and
director nominee, by each executive officer named in the Summary Compensation
Table (collectively, the "named executive officers") who is not a director and
by all directors and executive officers as a group, based on data furnished to
AGLC.
56
Name and Relationship of Beneficial Owner to Number of Shares of Common
AGLC Stock Owned Beneficially
(Percent of Class)(1)
David R. Jones
President, Chief Executive Officer and Director 223,715 (*)(2)(3)(4)(5)
Thomas H. Benson
Chief Operating Officer and Director 94,359 (*)(2)(3)(4)(5)
Charlie J. Lail
Senior Vice President 62,897 (*)(2)(3)(4)(5)
Michael D. Hutchins
Vice President 33,444 (*)(2)(3)(4)(5)
Charles W. Bass
Director 103,301 (*)(2)(3)(4)(5)
Melanie M. Platt
Director 6,629 (*)(2)(3)(4)(5)
All executive officers and directors as a group
(6 persons) 524,345 (1%)(2)(3)(4)(5)
- ---------------------------
(*) Less than one percent.
(1) As of September 30, 1996, no individual director or executive officer
of AGLC owned beneficially 1% or more of the outstanding common stock
of AGL Resources or any class of Preferred Stock of AGLC or any
interest in any class of Preferred Stock of AGLC. Beneficial ownership
as reported herein has been determined in accordance with regulations
of the Commission and includes shares of common stock which may be
acquired within 60 days upon the exercise of outstanding stock
options. Except as otherwise indicated in footnote (4) below, all
executive officers, directors and director nominees have sole voting
and investment power with respect to the shares shown.
(2) Includes shares held for the accounts of the above-named persons and
the above-referenced group as participants in the LESOP and RSP Plan
as follows: Mr. Jones - 30,747 shares; Mr. Benson - 16,222 shares; Mr.
Lail - 13,028 shares; Mr. Hutchins - 5,154 shares; Mr. Bass - 15,415
shares; Ms. Platt - 118 shares; and the above-referenced group -80,684
shares.
(3) Includes shares which may be acquired by the above-named persons and
the above-referenced group upon the exercise of stock options as
follows: Mr. Jones - 138,695 shares; Mr. Benson - 65,055 shares; Mr.
Lail - 41,439 shares; Mr. Hutchins - 23,799 shares; Mr. Bass - 77,963
shares; Ms. Platt - 5,600 shares; and the above- referenced group -
352,551 shares.
(4) With regard to Mr. Jones, the shares shown include 51,648 shares for
which he shares voting and investment power and 1,322 shares which are
held of record by the spouse of Mr. Jones as to which he disclaims
beneficial ownership; with regard to Mr. Benson, the shares shown
include 13,082 shares for which he shares voting and investment power;
with regard to Mr. Lail, the shares shown include 3,054 shares for
which he shares voting and investment power; with regard to Mr.
Hutchins, the shares shown include 3,671 shares for which he shares
voting and investment power; with regard to Mr. Bass, the shares shown
include 3,683 shares for which he shares voting and investment power;
with regard to Ms. Platt, the shares shown include 911 shares for
which she shares voting and investment power; and with regard to the
group, the shares shown include 76,049 shares held with shared voting
and investment power and 1,322 shares held of record by certain
spouses of members
57
of the above-referenced group as to which the respective members
of the group disclaim beneficial ownership.
(5) Excludes shares held by the Trust of the NSP for the benefit of the
above-named persons and the above-referenced group as follows: Mr.
Jones - 2,252 shares; Mr. Benson - 849 shares; Mr. Lail - 892 shares;
Mr. Hutchins - -0- shares; Mr. Bass - 577 shares; Ms. Platt - -0-
shares; and the above-referenced group - 4,570 shares. As determined
in accordance with regulations of the Commission, such shares are not
deemed to be beneficially owned and, accordingly, are excluded from
the shares of common stock shown in the table above. (See footnotes
(1) and (5) to "Table 1: Summary Compensation Table" above.)
- --------------------------------------------------------------------------------
Item 13. Certain Relationships and Related Transactions
Compensation Committee Interlocks and Insider Participation
Prior to the formation of the AGL Resources holding company in March 1996,
the AGLC Nominating and Compensation Committee was composed of Messrs. Bradley,
Brumby, Norman, Tarbutton and Taylor, none of whom is an officer or employee of
AGLC. Mr. Norman is a partner in the law firm of Long, Aldridge & Norman, LLP,
General Counsel to AGLC and AGL Resources. For the fiscal year ended September
30, 1996, AGLC and AGL Resources paid to Long, Aldridge & Norman, LLP
approximately $3.6 million for legal services to AGL Resources, AGLC and their
subsidiaries.
58
Part IV
- --------------------------------------------------------------------------------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Documents Filed as Part of This Report:
1. Financial Statements
Included under Item 8 are the following financial statements:
Statements of Consolidated Income for the Years Ended September
30, 1996, 1995 and 1994.
Statements of Consolidated Cash Flows for the Years Ended
September 30, 1996, 1995 and 1994.
Consolidated Balance Sheets as of September 30, 1996 and 1995.
Statements of Consolidated Common Stock Equity for the Years
Ended September 30, 1996, 1995 and 1994.
Notes to Consolidated Financial Statements.
Independent Auditors' Report.
2. Supplemental Consolidated Financial Schedules for Each of
the Three Years in the Period Ended September 30, 1996:
II. - Valuation and Qualifying Account--Allowance for
Uncollectible Accounts.
Schedules other than those referred to above are omitted and are
not applicable or not required, or the required information is
shown in the financial statements or notes thereto.
3. Exhibits
Where an exhibit is filed by incorporation by reference to a
previously filed registration statement or report, such
registration statement or report is identified in parentheses.
Exhibits indicated by an asterisk are provided in electronic
format only.
3.1* - Charter of the Company, as amended through February 22, 1993.
3.2 - Articles of Merger of the Company and AGL Merger Co. filed
March 6, 1996, with the Secretary of State of the State of
Georgia.
3.3 - Articles of Amendment to the Articles of Incorporation
(Charter) of the Company filed on October 3, 1996, with the
Secretary of State of the State of Georgia.
3.4 - By-Laws of the Company, as amended through November 17, 1995
(Exhibit 3(e), Atlanta Gas Light Company Form 10-K for the fiscal
year ended September 30, 1995).
59
4.1 - Indenture, dated as of December 1, 1989, between Atlanta Gas
Light Company and Bankers Trust Company, as Trustee (Exhibit
4(a), Registration No. 33-32274).
4.2 - First Supplemental Indenture, dated as of March 16, 1992,
between Atlanta Gas Light Company and NationsBank of Georgia,
National Association, as Successor Trustee, (Exhibit 4(a),
Registration No. 33-46419).
10.1 - Executive Compensation Plans and Arrangements;
10.1.a - Executive Severance Pay Plan of AGL Resources Inc. (Exhibit
10.1.a, AGL Resources Inc. Form 10-K for the fiscal year ended
September 30, 1996).
10.1.b - AGL Resources Inc. Long-Term Stock Incentive Plan of 1990
(Exhibit 10(ii), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1991).
10.1.c - First Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit B to the Atlanta Gas Light
Company Proxy Statement for the Annual Meeting of Shareholders
held February 5, 1993).
10.1.d - Third Amendment to the AGL Resources Inc. Long-Term Stock
Incentive Plan of 1990 (Exhibit C to the Proxy Statement and
Prospectus filed as a part of Amendment No. 1 to Registration
Statement on Form S-4, No. 33-99826).
10.1.e - AGL Resources Inc. Nonqualified Savings Plan (Exhibit 10(a),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.2 - Service Agreement under Rate Schedule GSS dated April 13, 1972,
between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 5(c), Registration No. 2-48297).
10.3 - Service Agreement under Rate Schedule LG-A, effective August
16, 1974, between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 5(d), Registration No. 2-58971).
10.4 - Storage Transportation Agreement, dated June 1, 1979, between
the Company and Southern Natural Gas Company, (Exhibit 5(n),
Registration No. 2-65487).
10.5 - Letter of Intent dated September 18, 1987, between the Company
and Jupiter Industries, Inc. relating to the purchase by the
Company of the assets of the Chattanooga Gas Company Division of
Jupiter Industries, Inc. (Exhibit 10(p), Form 10-K for the fiscal
year ended September 30, 1987).
10.6 - Agreement for the Purchase of Assets dated April 5, 1988,
between the Company and Jupiter Industries, Inc., (Exhibit 10(q),
Form 10-K for the fiscal year ended September 30, 1988).
10.7 - 100 Day Storage Service Agreement, dated June 1, 1979, between
the Company and South Georgia Natural Gas Company, (Exhibit
10(r), Form 10-K for the fiscal year ended September 30, 1989).
60
10.8 - Service Agreement under Rate Schedule LSS, dated October 31,
1984, between the Company and Transcontinental Gas Pipe Line
Corporation, (Exhibit 10(s), Form 10-K for the fiscal year ended
September 30, 1989).
10.9 - Storage Transportation Agreement, dated June 1, 1979, between
the Company and South Georgia Natural Gas Company, (Exhibit
10(v), Form 10-K for the fiscal year ended September 30, 1990).
10.10- Firm Seasonal Transportation Agreement, dated June 29, 1990,
between the Company and Transcontinental Gas Pipe Line
Corporation, (Exhibit 10(bb), Form 10-K for the fiscal year ended
September 30, 1990).
10.11- Service Agreement under Rate Schedule WSS, dated June 1, 1990,
between the Company and Transcontinental Gas Pipe Line
Corporation, (Exhibit 10(cc), Form 10-K for the fiscal year ended
September 30, 1990).
10.12- Limited-Term Transportation Agreement Contract # A970 dated
April 1, 1988, between the Company and CNG Transmission
Corporation, (Exhibit 10(bb), Form 10-K for the fiscal year ended
September 30, 1991).
10.13- Service Agreement System Contract #.2271 under Rate Schedule
FT, dated August 1, 1991, between the Company and
Transcontinental Gas Pipe Line Corporation, (Exhibit 10(dd), Form
10-K for the fiscal year ended September 30, 1991).
10.14- Service Agreement System Contract #.4984 dated August 1, 1991,
between the Company and Transcontinental Gas Pipe Line
Corporation, (Exhibit 10(ee), Form 10-K for the fiscal year ended
September 30, 1991).
10.15- Service Agreement Contract #830810 under Rate Schedule FT,
dated March 1, 1992, between the Company and South Georgia
Natural Gas Company (Exhibit 10(aa), Form 10-K for the fiscal
year ended September 30, 1992).
10.16- Firm Gas Transportation Contract #3699 under Rate Schedule FT,
dated February 1, 1992, between the Company and Transcontinental
Gas Pipe Line Corporation (Exhibit 10(dd), Form 10-K for the
fiscal year ended September 30, 1992).
10.17- Firm Gas Transportation Agreement under Rate Schedule FT-1,
dated July 1, 1992, between the Company and East Tennessee
Natural Gas Company (Exhibit 10(ff), Form 10-K for the fiscal
year ended September 30, 1992).
10.18- Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated October 25, 1993, between the
Company and CNG Transmission Corporation (Exhibit 10(y), Form
10-K for the fiscal year ended September 30, 1993).
10.19- Service Agreement Applicable to the Storage of Natural Gas
under Rate Schedule GSS, dated September, 1993, between
Chattanooga Gas Company and CNG Transmission Corporation (Exhibit
10(z), Form 10-K for the fiscal year ended September 30, 1993).
61
10.20- Firm Seasonal Transportation Agreement, dated February 1,
1992, between the Company and Transcontinental Gas Pipe Line
Corporation amending Exhibit 10(bb), Form 10-K for the fiscal
year ended September 30, 1990 (Exhibit 10(cc), Form 10-K for the
fiscal year ended September 30, 1993).
10.21- Service Agreement under Rate Schedule SS-1, dated April 1,
1988, between the Company and Transcontinental Gas Pipe Line
Corporation (Exhibit 10(z), Form 10-K for the fiscal year ended
September 30, 1994).
10.22- Firm Gas Transportation Agreement #5049 under Rate Schedule
FT-A, dated November 1, 1993, between the Company and Tennessee
Gas Pipeline Company (Exhibit 10(aa), Form 10-K for the fiscal
year ended September 30, 1994).
10.23- Firm Gas Transportation Agreement #5051 under Rate Schedule
FT-A, dated November 1, 1993, between Chattanooga Gas Company and
Tennessee Gas Pipeline Company (Exhibit 10(bb), Form 10-K for the
fiscal year ended September 30, 1994).
10.24- Gas Storage Contract #3998 under Rate Schedule FS, dated
November 1, 1993, between the Company and Tennessee Gas Pipeline
Company (Exhibit 10(cc), Form 10-K for the fiscal year ended
September 30, 1994).
10.25- Gas Storage Contract #3999 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and Tennessee
Gas Pipeline Company (Exhibit 10(dd), Form 10-K for the fiscal
year ended September 30, 1994).
10.26- Gas Storage Contract #3923 under Rate Schedule FS, dated
November 1, 1993, between the Company and Tennessee Gas Pipeline
Company (Exhibit 10(ee), Form 10-K for the fiscal year ended
September 30, 1994).
10.27- Gas Storage Contract #3947 under Rate Schedule FS, dated
November 1, 1993, between Chattanooga Gas Company and Tennessee
Gas Pipeline Company (Exhibit 10(ff), Form 10-K for the fiscal
year ended September 30, 1994).
10.28- Service Agreement #902470 under Rate Schedule FT, dated
September 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(hh), Form 10-K for the fiscal year ended
September 30, 1994).
10.29- Service Agreement #904460 under Rate Schedule FT, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(ii), Form 10-K for the fiscal year ended
September 30, 1994).
10.30- Service Agreement #904480 under Rate Schedule FT, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(jj), Form 10-K for the fiscal year ended
September 30, 1994).
10.31- Service Agreement #904461 under Rate Schedule FT-NN, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(kk), Form 10-K for the fiscal year ended
September 30, 1994).
62
10.32- Service Agreement #904481 under Rate Schedule FT-NN, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(ll), Form 10-K for the fiscal year ended
September 30, 1994).
10.33- Service Agreement #S20140 under Rate Schedule CSS, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(mm), Form 10-K for the fiscal year ended
September 30, 1994).
10.34- Service Agreement #S20150 under Rate Schedule CSS, dated
November 1, 1994, between the Company and Southern Natural Gas
Company (Exhibit 10(nn), Form 10-K for the fiscal year ended
September 30, 1994).
10.35- Service Agreement #904470 under Rate Schedule FT, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(oo), Form 10-K for the fiscal
year ended September 30, 1994).
10.36- Service Agreement #904471 under Rate Schedule FT-NN, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(pp), Form 10-K for the fiscal
year ended September 30, 1994).
10.37- Service Agreement #S20130 under Rate Schedule CSS, dated
November 1, 1994, between Chattanooga Gas Company and Southern
Natural Gas Company (Exhibit 10(qq), Form 10-K for the fiscal
year ended September 30, 1994).
10.38- Firm Storage (FS) Agreement, dated November 1, 1994, between
the Company and ANR Storage Company (Exhibit 10(a), Form 10-Q for
the quarter ended March 31, 1996).
10.39- Firm Storage (FS) Agreement, dated November 1, 1994, between
the Company and ANR Storage Company (Exhibit 10(b), Form 10-Q for
the quarter ended March 31, 1996).
10.40- Firm Transportation Agreement, dated March 1, 1996, between
the Company and Southern Natural Gas Company amending Exhibits
10(jj), 10(ll) and 10(mm), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(c), Form 10-Q for the quarter
ended March 31, 1996).
10.41- Firm Transportation Agreement, dated March 1, 1996, between
the Company and Southern Natural Gas Company amending Exhibits
10(hh), 10(ii), 10(kk) and 10(nn), Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(d), Form 10-Q for the
quarter ended March 31, 1996).
10.42- Firm Transportation Agreement, dated March 1, 1996, between
Chattanooga Gas Company and Southern Natural Gas Company amending
Exhibits 10(oo), 10(pp) and 10(qq), Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(a), Form 10-Q for the
quarter ended June 30, 1996).
63
10.43- Firm Transportation Agreement, dated June 1, 1996, between the
Company and Southern Natural Gas Company amending Exhibit 10(ii),
Form 10-K for the fiscal year ended September 30, 1994 (Exhibit
10(tt), Form 10-K for the fiscal year ended September 30, 1995).
10.44- Firm Storage Agreement, effective December 1, 1994, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(uu), Form 10-K for the fiscal year
ended September 30, 1995).
10.45- Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(ff), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(vv), Form 10-K for the fiscal year
ended September 30, 1995).
10.46- Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(dd), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(ww), Form 10-K for the fiscal year
ended September 30, 1995).
10.47- Firm Transportation Agreement, dated September 26, 1994,
between The Company and South Georgia Natural Gas Company
amending Exhibit 10(s), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(xx), Form 10-K for the fiscal year
ended September 30, 1995).
10.48- Firm Storage Agreement, effective July 1, 1996, between The
Company and Tennessee Gas Pipeline Company amending Exhibit
10(ee), Form 10- K for the fiscal year ended September 30, 1994
(Exhibit 10(yy), Form 10- K for the fiscal year ended September
30, 1995).
10.49- Firm Storage Agreement, effective July 1, 1996, between The
Company and Tennessee Gas Pipeline Company amending Exhibit
10(cc), Form 10- K for the fiscal year ended September 30, 1994
(Exhibit 10(zz), Form 10- K for the fiscal year ended September
30, 1995).
10.50- Firm Storage Agreement, effective January 1, 1996, between the
Company and Tennessee Gas Pipeline Company amending Exhibit 10(z)
and replacing Exhibit 10(u), Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(a), Form 10-Q for the quarter
ended December 31, 1995).
10.51- Firm Storage Agreement, effective January 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline Company
amending Exhibit 10(aa) and replacing Exhibit 10(dd), Form 10-K
for the fiscal year ended September 30, 1995 (Exhibit 10(b), Form
10-Q for the quarter ended December 31, 1995).
10.52- Gas Sales Agreement between Seller and Atlanta Gas Light
Company, as Buyer (Exhibit 10(a), Form 10-Q for the quarter ended
March 31, 1995).
64
10.53- FPS-1 Service Agreement, dated July 9, 1996, between Atlanta
Gas Light Company and Cove Point LNG Limited Partnership (Exhibit
10(a), Form 10-Q for the quarter ended June 30, 1996).
10.54- Amendment to FS Agreement, dated September 13, 1994, between
Atlanta Gas Light Company and Transcontinental Gas Pipe Line
Corporation.
10.55- Amendment to Letter Agreement, dated July 13, 1994, among and
between Southern Natural Gas Company, Atlanta Gas Light Company
and Chattanooga Gas Company.
10.56- Three-party agreement between ANR Storage Company, Atlanta Gas
Light Company and Southern Natural Gas Company, effective
November 1, 1994.
10.57- Displacement Service Agreement, effective December 15, 1996,
between Washington Gas Light Company and Atlanta Gas Light
Company.
10.58- Amendment to Firm Storage Agreement, effective July 26, 1996,
between Chattanooga Gas Company and Southern Natural Gas Company
amending Exhibit 10(jj) , Form 10-K for the fiscal year ended
September 30, 1995.
10.59- Amendatory Agreement, effective August 23, 1996, between
Southern Natural Gas Company and Atlanta Gas Light Company
amending Exhibits 10(ee), 10(ff), 10(hh) and 10(kk), Form 10-K
for the fiscal year ended September 30, 1995.
21 - Subsidiaries of the Registrant.
23 - Independent Auditors' Consent.
24 - Powers of Attorney (included with Signature Page hereto).
27 - Financial Data Schedule.
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the year ended
September 30, 1996.
65
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, on November 1, 1996.
ATLANTA GAS LIGHT COMPANY
By: /s/ David R. Jones
David R. Jones
President and Chief Executive Officer
POWERS OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints David R. Jones and J. Michael Riley, and
each of them, his or her true and lawful attorneys-in-fact and agents, with full
power of substitution and resubstitution, for him or her and in his or her name,
place and stead, in any and all capacities, to sign the Annual Report on Form
10-K for the fiscal year ended September 30, 1996 and any and all amendments to
such Annual Report, and to file the same, with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
granting unto said attorneys-in-fact and agents, and each of them, full power
and authority to do and perform each and every act and thing requisite or
necessary to be done, as fully to all intents and purposes as he or she might or
could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents or any of them, or their or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated as of November 1, 1996.
Signatures Title
/s/ David R. Jones
David R. Jones President and Chief Executive Officer
(Principal Executive Officer) and Director
/s/ J. Michael Riley
J. Michael Riley Vice President and Chief Financial
Officer
(Principal Accounting and Financial
Officer)
66
/s/ Charles W. Bass
Charles W. Bass Director
/s/ Thomas H. Benson
Thomas H. Benson Director
/s/ Melanie M. Platt
Melanie M. Platt Director
*By /s/ J. Michael Riley
J. Michael Riley,
as Attorney-in-Fact
67
SCHEDULE II
ATLANTA GAS LIGHT COMPANY
VALUATION AND QUALIFYING ACCOUNT
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1996, 1995 AND 1994
(IN MILLIONS)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Balance, beginning of year ............. $ 4.4 $ 2.8 $ 1.9
Additions:
Provisions charged to income ......... 4.6 5.3 7.5
Recovery of accounts
previously written off
as uncollectible ................... 8.6 6.6 7.1
------- ------- -------
Total ............................ 17.6 14.7 16.5
Deduction:
Accounts written off
as uncollectible ................... 14.9 10.3 13.7
------- ------- -------
Balance, end of year ................... $ 2.7 $ 4.4 $ 2.8
======= ======= =======
68
INDEX TO EXHIBITS
Exhibit
Number Description
3.1* - Charter of the Company, as amended through February 22,
1993.
3.2 - Articles of Merger of the Company and AGL Merger Co.
filed March 6, 1996, with the Secretary of State of the
State of Georgia.
3.3 - Articles of Amendment to the Articles of Incorporation
(Charter) of the Company filed on October 3, 1996, with
the Secretary of State of the State of Georgia.
3.4 - By-Laws of the Company, as amended through November 17,
1995 (Exhibit 3(e), Atlanta Gas Light Company Form 10-K
for the fiscal year ended September 30, 1995).
4.1 - Indenture, dated as of December 1, 1989, between
Atlanta Gas Light Company and Bankers Trust Company, as
Trustee (Exhibit 4(a), Registration No. 33-32274).
4.2 - First Supplemental Indenture, dated as of March 16,
1992, between Atlanta Gas Light Company and NationsBank
of Georgia, National Association, as Successor Trustee,
(Exhibit 4(a), Registration No. 33-46419).
10.1 - Executive Compensation Plans and Arrangements;
10.1.a - Executive Severance Pay Plan of AGL Resources Inc.
(Exhibit 10.1.a, AGL Resources Inc. Form 10-K for the
fiscal year ended September 30, 1996).
10.1.b - AGL Resources Inc. Long-Term Stock Incentive Plan of
1990 (Exhibit 10(ii), Atlanta Gas Light Company Form
10-K for the fiscal year ended September 30, 1991).
10.1.c - First Amendment to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990 (Exhibit B to the Atlanta
Gas Light Company Proxy Statement for the Annual
Meeting of Shareholders held February 5, 1993).
Exhibit
Number Description
10.1.d - Third Amendment to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990 (Exhibit C to the Proxy
Statement and Prospectus filed as a part of Amendment
No. 1 to Registration Statement on Form S-4, No.
33-99826).
10.1.e - AGL Resources Inc. Nonqualified Savings Plan (Exhibit
10(a), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1995).
10.2 - Service Agreement under Rate Schedule GSS dated April
13, 1972, between the Company and Transcontinental Gas
Pipe Line Corporation (Exhibit 5(c), Registration No.
2-48297).
10.3 - Service Agreement under Rate Schedule LG-A, effective
August 16, 1974, between the Company and
Transcontinental Gas Pipe Line Corporation (Exhibit
5(d), Registration No. 2-58971).
10.4 - Storage Transportation Agreement, dated June 1, 1979,
between the Company and Southern Natural Gas Company,
(Exhibit 5(n), Registration No. 2-65487).
10.5 - Letter of Intent dated September 18, 1987, between the
Company and Jupiter Industries, Inc. relating to the
purchase by the Company of the assets of the
Chattanooga Gas Company Division of Jupiter Industries,
Inc. (Exhibit 10(p), Form 10-K for the fiscal year
ended September 30, 1987).
10.6 - Agreement for the Purchase of Assets dated April 5,
1988, between the Company and Jupiter Industries, Inc.,
(Exhibit 10(q), Form 10-K for the fiscal year ended
September 30, 1988).
10.7 - 100 Day Storage Service Agreement, dated June 1, 1979,
between the Company and South Georgia Natural Gas
Company, (Exhibit 10(r), Form 10-K for the fiscal year
ended September 30, 1989).
10.8 - Service Agreement under Rate Schedule LSS, dated
October 31, 1984, between the Company and
Transcontinental Gas Pipe Line Corporation, (Exhibit
10(s), Form 10-K for the fiscal year ended September
30, 1989).
Exhibit
Number Description
10.9 - Storage Transportation Agreement, dated June 1, 1979,
between the Company and South Georgia Natural Gas
Company, (Exhibit 10(v), Form 10-K for the fiscal year
ended September 30, 1990).
10.10 - Firm Seasonal Transportation Agreement, dated June 29,
1990, between the Company and Transcontinental Gas Pipe
Line Corporation, (Exhibit 10(bb), Form 10-K for the
fiscal year ended September 30, 1990).
10.11 - Service Agreement under Rate Schedule WSS, dated June
1, 1990, between the Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(cc), Form 10-K for
the fiscal year ended September 30, 1990).
10.12 - Limited-Term Transportation Agreement Contract # A970
dated April 1, 1988, between the Company and CNG
Transmission Corporation, (Exhibit 10(bb), Form 10-K
for the fiscal year ended September 30, 1991).
10.13 - Service Agreement System Contract #.2271 under Rate
Schedule FT, dated August 1, 1991, between the Company
and Transcontinental Gas Pipe Line Corporation,
(Exhibit 10(dd), Form 10-K for the fiscal year ended
September 30, 1991).
10.14 - Service Agreement System Contract #.4984 dated August
1, 1991, between the Company and Transcontinental Gas
Pipe Line Corporation, (Exhibit 10(ee), Form 10-K for
the fiscal year ended September 30, 1991).
10.15 - Service Agreement Contract #830810 under Rate Schedule
FT, dated March 1, 1992, between the Company and South
Georgia Natural Gas Company (Exhibit 10(aa), Form 10-K
for the fiscal year ended September 30, 1992).
10.16 - Firm Gas Transportation Contract #3699 under Rate
Schedule FT, dated February 1, 1992, between the
Company and Transcontinental Gas Pipe Line Corporation
(Exhibit 10(dd), Form 10-K for the fiscal year ended
September 30, 1992).
Exhibit
Number Description
10.17 - Firm Gas Transportation Agreement under Rate Schedule
FT-1, dated July 1, 1992, between the Company and East
Tennessee Natural Gas Company (Exhibit 10(ff), Form
10-K for the fiscal year ended September 30, 1992).
10.18 - Service Agreement Applicable to the Storage of Natural
Gas under Rate Schedule GSS, dated October 25, 1993,
between the Company and CNG Transmission Corporation
(Exhibit 10(y), Form 10-K for the fiscal year ended
September 30, 1993).
10.19 - Service Agreement Applicable to the Storage of Natural
Gas under Rate Schedule GSS, dated September, 1993,
between Chattanooga Gas Company and CNG Transmission
Corporation (Exhibit 10(z), Form 10-K for the fiscal
year ended September 30, 1993).
10.20 - Firm Seasonal Transportation Agreement, dated February
1, 1992, between the Company and Transcontinental Gas
Pipe Line Corporation amending Exhibit 10(bb), Form
10-K for the fiscal year ended September 30, 1990
(Exhibit 10(cc), Form 10-K for the fiscal year ended
September 30, 1993).
10.21 - Service Agreement under Rate Schedule SS-1, dated April
1, 1988, between the Company and Transcontinental Gas
Pipe Line Corporation (Exhibit 10(z), Form 10-K for the
fiscal year ended September 30, 1994).
10.22 - Firm Gas Transportation Agreement #5049 under Rate
Schedule FT-A, dated November 1, 1993, between the
Company and Tennessee Gas Pipeline Company (Exhibit
10(aa), Form 10-K for the fiscal year ended September
30, 1994).
10.23 - Firm Gas Transportation Agreement #5051 under Rate
Schedule FT-A, dated November 1, 1993, between
Chattanooga Gas Company and Tennessee Gas Pipeline
Company (Exhibit 10(bb), Form 10-K for the fiscal year
ended September 30, 1994).
10.24 - Gas Storage Contract #3998 under Rate Schedule FS,
dated November 1, 1993, between the Company and
Tennessee Gas Pipeline Company (Exhibit 10(cc), Form
10-K for the fiscal year ended September 30, 1994).
Exhibit
Number Description
10.25 - Gas Storage Contract #3999 under Rate Schedule FS,
dated November 1, 1993, between Chattanooga Gas Company
and Tennessee Gas Pipeline Company (Exhibit 10(dd),
Form 10- K for the fiscal year ended September 30,
1994).
10.26 - Gas Storage Contract #3923 under Rate Schedule FS,
dated November 1, 1993, between the Company and
Tennessee Gas Pipeline Company (Exhibit 10(ee), Form
10-K for the fiscal year ended September 30, 1994).
10.27 - Gas Storage Contract #3947 under Rate Schedule FS,
dated November 1, 1993, between Chattanooga Gas Company
and Tennessee Gas Pipeline Company (Exhibit 10(ff),
Form 10-K for the fiscal year ended September 30,
1994).
10.28 - Service Agreement #902470 under Rate Schedule FT, dated
September 1, 1994, between the Company and Southern
Natural Gas Company (Exhibit 10(hh), Form 10-K for the
fiscal year ended September 30, 1994).
10.29 - Service Agreement #904460 under Rate Schedule FT, dated
November 1, 1994, between the Company and Southern
Natural Gas Company (Exhibit 10(ii), Form 10-K for the
fiscal year ended September 30, 1994).
10.30 - Service Agreement #904480 under Rate Schedule FT, dated
November 1, 1994, between the Company and Southern
Natural Gas Company (Exhibit 10(jj), Form 10-K for the
fiscal year ended September 30, 1994).
10.31 - Service Agreement #904461 under Rate Schedule FT-NN,
dated November 1, 1994, between the Company and
Southern Natural Gas Company (Exhibit 10(kk), Form 10-K
for the fiscal year ended September 30, 1994).
10.32 - Service Agreement #904481 under Rate Schedule FT-NN,
dated November 1, 1994, between the Company and
Southern Natural Gas Company (Exhibit 10(ll), Form 10-K
for the fiscal year ended September 30, 1994).
10.33 - Service Agreement #S20140 under Rate Schedule CSS,
dated November 1, 1994, between the Company and
Southern Natural Gas Company (Exhibit 10(mm), Form 10-K
for the fiscal year ended September 30, 1994).
Exhibit
Number Description
10.34 - Service Agreement #S20150 under Rate Schedule CSS,
dated November 1, 1994, between the Company and
Southern Natural Gas Company (Exhibit 10(nn), Form 10-K
for the fiscal year ended September 30, 1994).
10.35 - Service Agreement #904470 under Rate Schedule FT, dated
November 1, 1994, between Chattanooga Gas Company and
Southern Natural Gas Company (Exhibit 10(oo), Form 10-K
for the fiscal year ended September 30, 1994).
10.36 - Service Agreement #904471 under Rate Schedule FT-NN,
dated November 1, 1994, between Chattanooga Gas
Company and Southern Natural Gas Company (Exhibit
10(pp), Form 10-K for the fiscal year ended September
30, 1994).
10.37 - Service Agreement #S20130 under Rate Schedule CSS,
dated November 1, 1994, between Chattanooga Gas Company
and Southern Natural Gas Company (Exhibit 10(qq), Form
10-K for the fiscal year ended September 30, 1994).
10.38 - Firm Storage (FS) Agreement, dated November 1, 1994,
between the Company and ANR Storage Company (Exhibit
10(a), Form 10-Q for the quarter ended March 31, 1996).
10.39 - Firm Storage (FS) Agreement, dated November 1, 1994,
between the Company and ANR Storage Company (Exhibit
10(b), Form 10-Q for the quarter ended March 31, 1996).
10.40 - Firm Transportation Agreement, dated March 1, 1996,
between the Company and Southern Natural Gas Company
amending Exhibits 10(jj), 10(ll) and 10(mm), Form 10-K
for the fiscal year ended September 30, 1994 (Exhibit
10(c),
Form 10-Q for the quarter ended March 31, 1996).
10.41 - Firm Transportation Agreement, dated March 1, 1996,
between the Company and Southern Natural Gas Company
amending Exhibits 10(hh), 10(ii), 10(kk) and 10(nn),
Form 10-K for the fiscal year ended September 30, 1994
(Exhibit 10(d), Form 10-Q for the quarter ended March
31, 1996).
Exhibit
Number Description
10.42 - Firm Transportation Agreement, dated March 1, 1996,
between Chattanooga Gas Company and Southern Natural
Gas Company amending Exhibits 10(oo), 10(pp) and
10(qq), Form 10-K for the fiscal year ended September
30, 1994 (Exhibit 10(a), Form 10-Q for the quarter
ended June 30, 1996).
10.43 - Firm Transportation Agreement, dated June 1, 1996,
between the Company and Southern Natural Gas Company
amending Exhibit 10(ii), Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(tt), Form 10-K for
the fiscal year ended
September 30, 1995).
10.44 - Firm Storage Agreement, effective December 1, 1994,
between Chattanooga Gas Company and Tennessee Gas
Pipeline Company amending Exhibit 10(ff), Form 10-K for
the fiscal year ended September 30, 1994 (Exhibit
10(uu), Form 10-K for the fiscal year ended September
30, 1995).
10.45 - Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline
Company amending Exhibit 10(ff), Form 10-K for the
fiscal year ended September 30, 1994 (Exhibit 10(vv),
Form 10-K for the fiscal year ended September 30,
1995).
10.46 - Firm Storage Agreement, effective July 1, 1996, between
Chattanooga Gas Company and Tennessee Gas Pipeline
Company amending Exhibit 10(dd), Form 10-K for the
fiscal year ended September 30, 1994 (Exhibit 10(ww),
Form 10-K for the fiscal year ended September 30,
1995).
10.47 - Firm Transportation Agreement, dated September 26,
1994, between The Company and South Georgia Natural Gas
Company amending Exhibit 10(s), Form 10-K for the
fiscal year ended September 30, 1994 (Exhibit 10(xx),
Form 10-K for the fiscal year ended September 30,
1995).
10.48 - Firm Storage Agreement, effective July 1, 1996, between
The Company and Tennessee Gas Pipeline Company amending
Exhibit 10(ee), Form 10-K for the fiscal year ended
September 30, 1994 (Exhibit 10(yy), Form 10-K for the
fiscal year ended September 30, 1995).
Exhibit
Number Description
10.49 - Firm Storage Agreement, effective July 1, 1996,
between The Company and Tennessee Gas Pipeline Company
amending Exhibit 10(cc), Form 10-K for the fiscal year
ended September 30, 1994 (Exhibit 10(zz), Form 10-K for
the fiscal year ended September 30, 1995).
10.50 - Firm Storage Agreement, effective January 1, 1996,
between the Company and Tennessee Gas Pipeline Company
amending Exhibit 10(z) and replacing Exhibit 10(u),
Form 10-K for the fiscal year ended September 30, 1995
(Exhibit 10(a), Form 10-Q for the quarter ended
December 31, 1995).
10.51 - Firm Storage Agreement, effective January 1, 1996,
between Chattanooga Gas Company and Tennessee Gas
Pipeline Company amending Exhibit 10(aa) and replacing
Exhibit 10(dd), Form 10-K for the fiscal year ended
September 30, 1995 (Exhibit 10(b), Form 10-Q for the
quarter ended December 31, 1995).
10.52 - Gas Sales Agreement between Seller and Atlanta Gas
Light Company, as Buyer (Exhibit 10(a), Form 10-Q for
the quarter ended March 31, 1995).
10.53 - FPS-1 Service Agreement, dated July 9, 1996, between
Atlanta Gas Light Company and Cove Point LNG Limited
Partnership (Exhibit 10(a), Form 10-Q for the quarter
ended June 30, 1996).
10.54 - Amendment to FS Agreement, dated September 13, 1994,
between Atlanta Gas Light Company and Transcontinental
Gas Pipe Line Corporation.
10.55 - Amendment to Letter Agreement, dated July 13, 1994,
among and between Southern Natural Gas Company, Atlanta
Gas Light Company and Chattanooga Gas Company.
10.56 - Three-party agreement between ANR Storage Company,
Atlanta Gas Light Company and Southern Natural Gas
Company, effective November 1, 1994.
10.57 - Displacement Service Agreement, effective December 15,
1996, between Washington Gas Light Company and Atlanta
Gas Light Company.
Exhibit
Number Description
10.58 - Amendment to Firm Storage Agreement, effective July 26,
1996, between Chattanooga Gas Company and Southern
Natural Gas Company amending Exhibit 10(jj) , Form 10-K
for the fiscal year ended September 30, 1995.
10.59 - Amendatory Agreement, effective August 23, 1996,
between Southern Natural Gas Company and Atlanta Gas
Light Company amending Exhibits 10(ee), 10(ff), 10(hh)
and 10(kk), Form 10-K for the fiscal year ended
September 30, 1995.
21 - Subsidiaries of the Registrant.
23 - Independent Auditors' Consent.
24 - Powers of Attorney (included with Signature Page
hereto).
27 - Financial Data Schedule.