Management's Discussion and Analysis of Results of Operations and Financial
Condition
Forward-Looking Statements
The Private Securities Litigation Reform Act of 1995 requires public companies
to provide cautionary remarks about forward-looking statements that they make
in documents that are filed with the Securities and Exchange Commission.
Forward-looking statements in our Management's Discussion and Analysis
include statements about the following:
- - deregulation;
- - environmental investigations and cleanups; and
- - "Year 2000" readiness.
Important factors that could cause our actual results to differ substantially
from those in the forward-looking statements include, but are not limited to,
the following:
- - changes in price and demand for natural gas and related products;
- - uncertainties about state and federal legislative and regulatory issues;
- - the effects of deregulation and competition, particularly in markets
where prices and providers historically have been regulated;
- - changes in accounting policies and practices;
- - uncertainties about environmental and competitive issues; and
- - other factors discussed in the following section: Year 2000 Readiness
Disclosure - Forward-Looking Statements.
Nature of Our Business
Following shareholder and regulatory approval on March 6, 1996, AGL Resources
Inc. became the holding company for:
- - Atlanta Gas Light Company (AGLC) and its wholly owned subsidiary, Chattanooga
Gas Company (Chattanooga), which are local natural gas distribution utilities;
and
- - several nonutility subsidiaries.
We collectively refer to AGL Resources Inc. and its subsidiaries as "AGL
Resources."
AGLC conducts our primary business: the distribution of natural gas in
Georgia, including the Atlanta, Athens, Augusta, Brunswick, Macon, Rome,
Savannah, and Valdosta areas and in Tennessee, including the Chattanooga and
Cleveland areas. The Georgia Public Service Commission (GPSC) regulates AGLC,
and the Tennessee Regulatory Authority (TRA) regulates Chattanooga. AGLC
comprises substantially all of AGL Resources' assets, revenues, and earnings.
When we discuss the operations and activities of AGLC and Chattanooga, we refer
to them, collectively, as the "utility."
Graph depicts the utility service area (major cities).
AGL Resources also owns the following wholly owned nonutility subsidiaries:
- - AGL Energy Services, Inc., a gas supply services company that has one wholly
owned nonutility subsidiary, Georgia Gas Company;
- - AGL Interstate Pipeline Company which owns a 50% interest in Cumberland
Pipeline Company; Cumberland Pipeline Company is expected to provide interstate
pipeline services to customers in Georgia and Tennessee beginning November 1,
2000;
- - AGL Investments, Inc., which was established to develop and manage
certain nonutility businesses including:
* AGL Gas Marketing, Inc., which owns a 35% interest in Sonat Marketing, L.P.;
Sonat Marketing, L.P. engages in wholesale and retail natural gas trading;
* AGL Power Services, Inc., which owns a 35% interest in Sonat Power Marketing,
L.P.; Sonat Power Marketing, L.P. engages in wholesale power trading;
* AGL Propane, Inc., which engages in the sale of propane and related products
and services;
* Trustees Investments, Inc., which owns Trustees Gardens, a residential and
retail development located in Savannah, Georgia; and
* Utilipro, Inc., which engages in the sale of integrated customer care
solutions to energy marketers; and
- - AGL Peaking Services, Inc., which owns a 50% interest in Etowah LNG Company
LLC; Etowah LNG Company LLC is a joint venture with Southern Natural Gas
Company and was formed for the purpose of constructing, owning, and
operating a liquefied natural gas peaking facility.
In July 1998, AGL Resources formed a joint venture known as SouthStar Energy
Services LLC (SouthStar). SouthStar was established to sell natural gas,
propane, fuel oil, electricity, and related services to industrial, commercial,
and residential customers in Georgia and the Southeast. SouthStar is a joint
venture among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a
subsidiary of Dynegy, Inc., and Piedmont Energy Company, a subsidiary of
Piedmont Natural Gas Company. SouthStar filed for certification as a retail
marketer with the GPSC on July 15, 1998, and was approved on October 6, 1998.
SouthStar operates in Georgia under the name "Georgia Natural Gas Services."
Graph reflects throughput (utility operations) of therms sold and transported by
class of customer for the year ended September 30, 1998. Data presented is as
follows:
Throughput
(utility Percentage
Customer operations) of Total
- ----------------------------------------------
Industrial 1.7 billion 51%
Commercial .55 billion 16%
Residential 1.1 billion 33%
- ----------------------------------------------
Graph reflects margin (utility operations) by class of customer for the year
ended September 30, 1998. Data presented is as follows:
Margin
(utility
Customer operations)
- -------------------------------
Industrial 10%
Commercial 22%
Residential 68%
- -------------------------------
Results of Operations
In this section we compare the results of our operations for fiscal 1996, 1997,
and 1998. Our fiscal year ends on September 30.
Fiscal 1998 compared with fiscal 1997
Operating Revenues Our fiscal 1998 operating revenues increased 4.0%
compared with fiscal 1997 primarily for four reasons:
- - We sold more gas outside of the utility's distribution system;
- - The utility sold more gas to its customers due to weather that was 28.1%
colder in 1998 than in 1997;
- - We received increased revenues in the fourth quarter due to the timing of the
implementation of the new rate structure that became effective July 1, 1998,
for AGLC's gas distribution service. (For a discussion of the levelizing
effect that the new rate structure will have on the collection of revenues by
AGLC for its gas distribution service, see Financial Condition.); and
- - The utility sold more gas due to an increase of approximately 35,000 in
the average number of customers served.
The increase in operating revenues was offset somewhat because of a decrease of
$16.8 million in the amount that AGLC recovered through a rate rider for
expenses associated with an Integrated Resources Plan (IRP), a demand-side
management program that was phased out during fiscal 1998. AGLC balanced IRP
expenses, which were included in operating expenses, with revenues collected
under the rate rider, thereby eliminating the effect that recovery of IRP
expenses otherwise would have had on net income.
Cost of Sales We incur costs for the natural gas that we purchase and resell
to our customers. Our cost of sales increased 3.8% in fiscal 1998 compared with
fiscal 1997 for the following reasons:
- - We sold more gas outside of the utility's distribution system;
- - The utility sold more gas to its customers due to weather that was 28.1%
colder in 1998 than in 1997; and
- - The utility sold more gas due to an increase of approximately 35,000 in the
average number of customers served.
The utility's cost of gas per therm was 36.9 cents in fiscal 1998 and 39.4 cents
in fiscal 1997.
We charged our utility customers for the cost of the natural gas they
consumed using purchased gas adjustment (PGA) mechanisms approved by the GPSC
and the TRA. Under the PGA, we deferred (included as a current asset or
liability in our Consolidated Balance Sheets and excluded from our Statements of
Consolidated Income) the difference between the utility's actual cost of gas
and what the utility collected from its customers in a given period. Then,
the utility either billed or refunded its customers the deferred amount.
Operating Margin Because the utility's cost of gas was completely recovered
from its customers, the cost of gas had no effect on our operating margin. Our
operating margin increased 4.1% in fiscal 1998 over fiscal 1997 for three
primary reasons:
- - the timing of the implementation of the new rate structure that became
effective July 1, 1998, for AGLC's gas distribution service. (For a discussion
of the levelizing effect that the new rate structure will have on operating
margin associated with AGLCs gas distribution service, see Financial
Condition.);
- - an increase of approximately 35,000 in the average number of utility
customers served; and
- - increased margins of $10.7 million from nonutility operations.
The increase in operating margin was offset somewhat because of a decrease of
$16.8 million in the amount that AGLC recovered through a rate rider for
expenses associated with an IRP.
Other Operating Expenses Operation and maintenance expenses increased 7.6% in
fiscal 1998 compared with fiscal 1997 primarily because of the following:
- - noncash, nonrecurring charges of $13.9 million associated with the impairment
of certain assets no longer useful primarily due to changes in our information
systems strategy. (See Note 1 in Notes to Consolidated Financial Statements.);
- - increased expenses of $6.2 million related to maintenance of general plant
and distribution facilities;
- - start-up marketing expenses of $3.7 million for
Georgia Natural Gas Services the trade name in Georgia for SouthStar Energy
Services;
- - charges of $2.6 million related to management restructuring; and
- - increased operating expenses of $2.1 million for AGL Propane, Inc.,
reflecting twelve months' activity for propane operations acquired during
February and June 1997.
The increase in other operating expenses was offset somewhat because of a
decrease of $16.8 million in the amount that AGLC recovered through a rate rider
for expenses associated with an IRP.
Depreciation expense increased 6.8% in fiscal 1998 compared with fiscal 1997
primarily because of more depreciable plant in service. The composite
straight-line depreciation rate was approximately 3.2% for depreciable
utility and nonutility property, excluding transportation equipment, during
fiscal 1998 and fiscal 1997.
Taxes other than income taxes increased $1.4 million in fiscal 1998 compared
with fiscal 1997 primarily because of higher ad valorem taxes.
Other Income Other income increased $2.6 million in fiscal 1998 compared with
fiscal 1997 primarily because of increased income from two joint ventures: AGL
Power Services, Inc. and AGL Gas Marketing, Inc.
Interest Expense Total interest expense increased $2.7 million in fiscal 1998
compared with fiscal 1997 primarily because of higher amounts of long-term deb
outstanding during the period. That increase in interest expense was offset
partly by less interest expense for short-term debt due to decreased amounts of
short-term debt outstanding.
Dividends on Preferred Stock of Subsidiaries Dividends on Preferred Stock of
Subsidiaries increased $.5 million in fiscal 1998 compared with fiscal 1997.
That increase was due to dividend requirements for a full twelve-month period on
$75 million in principal amount of Capital Securities issued in June 1997.
Income Taxes Income taxes decreased $8.0 million in fiscal 1998 compared with
fiscal 1997 due to a decrease in taxable income and a reduction of income tax
expense related to a favorable resolution of certain outstanding income tax
issues. Income tax reserves related to those issues were reduced, thereby
reducing income tax expense. Also, tax benefits associated with the contribution
of certain assets to a private charitable foundation resulted in a decrease in
the effective tax rate for fiscal 1998. (See Note 3 in Notes to Consolidated
Financial Statements.)
Net Income, Earnings per Share, and Dividends per Share:
_______________________________________________________________________________
Basic Earnings Diluted Earnings Dividends
per Common per Common per Common
Fiscal Year Net Income Share Share Share
________________________________________________________________________________
1998 $80.6 million $1.41 $1.41 $1.08
________________________________________________________________________________
1997 $76.6 million $1.37 $1.36 $1.08
________________________________________________________________________________
Net Income and Earnings per Share Net income for fiscal 1998 was $80.6 million
compared with $76.6 million in fiscal 1997. The increase is primarily due to
increased operating margins and decreased income taxes. Increased operating
margins are due to the timing of the implementation of the new rate structure
that became effective July 1, 1998, for AGLC's gas distribution service. (For a
discussion of the levelizing effect that the new rate structure will have on
operating margin associated with AGLCs gas distribution service, see Financial
Condition.) Increased operating margins are also due to an increase of
approximately 35,000 in the average number of utility customers served. However,
that increase in operating margin was offset partly by higher operating
expenses resulting principally from charges associated with the impairment of
certain assets no longer useful primarily due to changes in our information
systems strategy. (See Note 1 in Notes to Consolidated Financial Statements.)
Basic earnings per share in fiscal 1998 were $1.41 compared with $1.37 in fiscal
1997. The weighted average number of common shares outstanding increased
from 56.1 million to 57.0 million. Diluted earnings per common share in fiscal
1998 were $1.41 compared with $1.36 in fiscal 1997. The weighted average
number of common shares outstanding and common share equivalents
increased from 56.2 million to 57.1 million.
Fiscal 1997 compared with fiscal 1996
Operating Revenues Our fiscal 1997 operating revenues increased 4.8% compared
with fiscal 1996 primarily for two reasons:
- - higher revenues from two subsidiaries - $54.4 million from a nonutility
retail energy marketing company, which was formed in June 1996, and $4.4
million from a nonutility gas supply services company, which was formed in
July 1996; and
- - higher utility base revenues as a result of approximately 32,000 new
customers served.
However, the increase in operating revenues was offset somewhat because of the
following:
- - The utility sold less gas to its customers due to weather that was 24.7%
warmer in 1997 than in 1996; and
- - Some industrial customers began using AGLCs transportation services only and
stopped buying gas from AGLC. Therefore, operating revenues related to
those industrial customers did not include revenues related to recovery of
gas costs.
Cost of Sales We incur costs for the natural gas we purchase and resell to
our customers. Our cost of sales increased 5.7% in fiscal 1997 compared with
fiscal 1996 for the following reasons:
- - a nonutility retail energy marketing company and a nonutility gas supply
services company formed in June and July 1996, incurred greater gas
costs of $30.2 million and $12.5 million, respectively.
- - The cost of gas for the utility was higher.
The increase in the cost of gas was offset somewhat by the following:
- - The utility sold less gas to its customers due to weather that was 24.7%
warmer in 1997 than in 1996.
- - As noted above, some industrial customers began using AGLCs transportation
services only and stopped buying gas from AGLC.
The utility's cost of gas per therm was 39.4 cents in fiscal 1997 and 32.2 cents
in fiscal 1996.
We charged our utility customers for the cost of the natural gas they
consumed using PGA mechanisms approved by the GPSC and the TRA. Under the PGA,
we deferred (included as a current asset or liability in our Consolidated
Balance Sheets and excluded from our Statements of Consolidated Income) the
difference between the utilitys actual cost of gas and what the utility
collected from its customers in a given period. Then, the utility either billed
or refunded its customers the deferred amount.
Operating Margin Because the utility's cost of gas was completely recovered
from its customers, the cost of gas had no effect on our operating margin. Our
operating margin increased 3.6% in fiscal 1997 over fiscal 1996 for two primary
reasons:
- - Approximately 32,000 additional utility customers generated higher base
revenues.
- - AGL Energy Services, Inc., which was formed in July 1996, and AGL Propane,
Inc., which acquired operating assets in February and June 1997, produced
greater operating margins.
Other Operating Expenses Operation and maintenance expenses increased 2.3% in
fiscal 1997 compared with fiscal 1996 primarily because of $4.3 million in
greater expenses related to uncollectible accounts, $3.9 million in greater
expenses related to AGL Propane, Inc., which acquired operating assets in
February and June 1997, and $1.9 million in greater expenses related to
maintenance of general plant.
Depreciation expense increased 5.2% in fiscal 1997 compared with fiscal 1996
primarily because of more depreciable plant in service. In fiscal 1997 and
fiscal 1996, the composite straight-line depreciation was approximately 3.2% for
depreciable utility and nonutility property excluding transportation equipment.
Taxes other than income taxes increased $1 million in fiscal 1997
compared with fiscal 1996 primarily because of higher gross receipts taxes and
ad valorem taxes.
Other Income Other income decreased $2.8 million in fiscal 1997 compared
with fiscal 1996 primarily for the following reasons:
- - $3.8 million less income from AGL Gas Marketing, Inc.;
- - $1.5 million less in recoveries of environmental response costs
(investigation, testing, cleanup and litigation costs associated with
our former manufactured gas production sites) from insurance carriers and
third parties; and
- - $1.3 million in higher carrying costs on recoveries of environmental
response costs from insurance carriers and third parties.
Partly offsetting the decrease in other income was the recovery from utility
customers of $2.7 million in increased carrying costs related to storage gas
inventories that were not included in base rates.
Interest Expense Total interest expense increased $3.1 million in fiscal 1997
compared with fiscal 1996 primarily because higher amounts of long-term and
short-term debt were outstanding during the period.
Dividends on Preferred Stock of Subsidiaries Dividends on preferred stock
of subsidiaries increased $1.8 million in fiscal 1997 compared with fiscal 1996.
That increase came from dividends on $75 million in Capital Securities that an
AGL Resources wholly owned business trust issued in June 1997. (See Note 7 in
Notes to Consolidated Financial Statements.)
Income Taxes Income taxes decreased $.7 million in fiscal 1997 compared
with fiscal 1996 because our effective tax rate was lower. The rate was lower
because we made a tax-deductible interest payment on subordinated debt that was
used to fund dividends on Capital Securities issued in June 1997.
Net Income, Earnings per Share, and Dividends per Share:
_______________________________________________________________________________
Basic Earnings Diluted Earnings Dividends
per Common per Common per Common
Fiscal Year Net Income Share Share Share
________________________________________________________________________________
1997 $76.6 million $1.37 $1.36 $1.08
________________________________________________________________________________
1996 $75.6 million $1.37 $1.36 $1.06
________________________________________________________________________________
Net Income and Earnings per Share Net income for fiscal 1997 was $76.6
million compared with $75.6 million in fiscal 1996. The increase in net income
was due to higher operating margins from approximately 32,000 new utility
customers and from two nonutility businesses that were formed during 1996.
However, that increase was offset partly by higher operating expenses and
financing costs and lower other income.
Basic earnings per common share in fiscal 1996 were unchanged compared to
fiscal 1997. The weighted average number of common shares outstanding
increased from 55.3 million to 56.1 million. Diluted earnings per common share
in fiscal 1996 were unchanged compared to fiscal 1997. The weighted average
number of common shares outstanding and common share equivalents increased from
55.4 million to 56.2 million.
Financial Condition
Impact of Deregulation Under Georgias Natural Gas Competition and Deregulation
Act (the Act), AGLC elected to unbundle, or separate, the various components
of its services to its customers. As a result, numerous changes have occurred
with respect to the services being offered by AGLC and with respect to the
manner in which AGLC prices and accounts for those services. Consequently,
AGLCs future expenses and revenues will not follow the same pattern as they
have historically.
Pursuant to the Act, regulated rates ended on October 6, 1998, for natural gas
commodity sales to AGLC customers. Consequently, AGLC will no longer defer
any over-recoveries or under-recoveries of gas costs and will refund to
customers the over-recovery that existed when the PGA provisions were
deregulated.
Going forward, AGLC intends to design its prices for deregulated gas sales
in a manner that, at a minimum, will allow it to recover its annual gas
costs. Accordingly, substantial changes to future quarterly statements of
income are expected from this new regulatory approach. AGLC intends to
recover all its gas costs through the prices it will establish such that on
an annual basis it recovers, at a minimum, the actual costs of acquiring gas
supplies for sales services.
As part of the GPSCs rate case ruling, AGLC began billing customers on
July 1, 1998, under a rate structure that recovers nongas costs evenly
throughout the year consistent with the way the costs are incurred. The
effect of the new rate structure will be to levelize on a
quarter-to-quarter basis the revenues collected by AGLC for gas delivery
services rendered by the utility. Prior to July 1, rates to provide
distribution service were based principally on the amount of gas
customers used.Therefore, total distribution rates were typically lower in
the summer when customers used less gas, and higher in the winter when customers
used more gas. Going forward, AGLC will collect such rates evenly throughout
the year regardless of volumetric summer and winter differences in gas usage.
Graph reflects consolidated operating revenues, operating expenses and operating
expenses as a percentage of operating revenues for the fiscal years ended
September 30, 1996 through 1998, inclusive. Data presented is as follows:
In millions of dollars * 1996 1997 1998
- ----------------------------------------------------
Operating Revenues * 1,229 1,288 1,339
Operating Expenses * 1,065 1,116 1,171
% Operating Expenses to
Operating Revenues 87% 87% 87%
- ----------------------------------------------------
Graph reflects common stock market value, book value and % market to book value
for the fiscal years ended September 30, 1996, through 1998, inclusive. Data
presented is as follows:
In dollars per share * 1996 1997 1998
- ----------------------------------------------------
Market value per share * 19.13 18.94 19.38
Book value per share * 10.56 10.99 11.42
% market value to book
value 181% 172% 170%
- ----------------------------------------------------
In addition, there are other AGLC revenues that reflect costs associated
with services deemed ancillary to distribution service that will change as
customers select a marketer for sales service. For example, as customers choose
a marketer, the associated revenues to AGLC for billing, billing inquiries,
payment collection, payment processing, and possibly meter reading will decrease
if those services are provided by the marketer. The regulatory provisions
provide for a reduction in the revenues associated with those services as AGLC
has the opportunity to avoid such future costs. Consequently, those provisions
will reduce some of the regulated revenue and associated expenses for AGLC.
Subsidiary Obligated Mandatorily Redeemable Preferred Securities (Capital
Securities) In June 1997 we established AGL Capital Trust (the Trust), a
Delaware business trust. The Trust issued two types of securities. Common
voting securities were issued to AGL Resources. In addition, the Trust issued
and sold $75 million principal amount of 8.17% Capital Securities to certain
initial investors. The Trust used the proceeds to purchase 8.17% Junior
Subordinated Deferrable Interest Debentures, which are due June 1, 2037,
from AGL Resources.
The Capital Securities are subject to mandatory redemption at the time
of the repayment of the Junior Subordinated Debentures on June 1, 2037, or
the optional prepayment by AGL Resources after May 31, 2007.
AGL Resources fully and unconditionally guarantees all of the Trust's
obligations for the Capital Securities. We used the net proceeds of
approximately $74 million from the sale of the Junior Subordinated Debentures
to repay short-term debt, to redeem some of AGLC's outstanding issues of
preferred stock, and for other corporate purposes.
AGLC Preferred Securities On August 15, 1997, AGLC fully redeemed the
following:
- - 4.5% Cumulative Preferred Stock;
- - 4.72% Cumulative Preferred Stock;
- - 5% Cumulative Preferred Stock;
- - 7.84% Cumulative Preferred Stock; and
- - 8.32% Cumulative Preferred Stock.
Those issues of preferred stock were redeemed, at the call price in effect for
each issue, for a total of $14.7 million.
On December 1, 1997, AGLC redeemed all of its outstanding 7.70% Series
depositary preferred stock. Accordingly, a current liability associated with
that redemption of $44.5 million was recorded on the Consolidated Balance Sheets
as of September 30, 1997. (See Note 7 in Notes to Consolidated Financial
Statements for additional information regarding preferred stock.)
Common Stock We issued the following shares of common stock:
- - 739,380 shares in fiscal 1998;
- - 753,866 shares in fiscal 1997; and
- - 792,919 shares in fiscal 1996.
Those shares were issued under ResourcesDirect, a direct stock purchase
and dividend reinvestment plan; the Retirement Savings Plus Plan; the Long-Term
Stock Incentive Plan; the Nonqualified Savings Plan; and the Non-Employee
Directors Equity Compensation Plan.
Those issuances increased common equity by the following amounts:
- - $12.9 million in fiscal 1998;
- - $13.8 million in fiscal 1997; and
- - $14.0 million in fiscal 1996.
Ratios and Coverages: -----------------------------------
September 30,
-----------------------------------
1998 1997 1996
___________________________________
Weighted average cost of long-term debt 7.5% 7.5% 7.6%
-----------------------------------
Weighted average cost of preferred stock 8.1% 8.0% 7.5%
-----------------------------------
Return on average common equity 12.6% 12.7% 13.2%
-----------------------------------
Ratio of earnings to combined fixed
charges(1) and preferred stock dividends 2.77 2.90 3.08
-----------------------------------
Ratio of earnings to interest charges(2)
and preferred stock dividends 2.94 3.10 3.28
-----------------------------------
Ratio of earnings to interest charges(2) 3.30 3.46 3.58
___________________________________
(1) Fixed charges consist of interest on short- and long-term debt, other
interest, and the estimated interest components of rentals.
(2) Interest charges exclude the debt portion of allowance for funds used
during construction.
Long-Term Debt During fiscal 1997 we issued $105.5 million in principal
amount of medium-term notes, Series C, with maturity dates ranging from 20 to
30 years and with interest rates ranging from 6.55% to 7.30%. The notes are
unsecured and rank on parity with all other unsecured indebtedness. We used
the net proceeds to fund capital expenditures, repay short-term debt, and
for other corporate purposes. We issued no long-term debt
during fiscal 1998.
Short-Term Debt Because our primary business is highly seasonal, we use
short-term debt 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 and are subject to
annual renewal. The current lines of credit vary from $240 million in the
summer to $290 million for peak winter financing.
Short-term debt increased $47 million from $29.5 million as of September 30,
1997, to $76.5 million as of September 30, 1998, to meet working capital
requirements. (See Note 9 in Notes to Consolidated Financial Statements for
additional information concerning short-term debt.)
Capital Requirements Capital expenditures for construction of distribution
facilities, purchase of equipment, and other general improvements were $121.8
million during fiscal 1998. Typically, we provide funding for those
expenditures through a combination of internal sources, the issuance of
short-term and long-term debt, and issuance of equity securities.
We estimate our capital requirements for the next three years, ending on
September 30, 2001, to be approximately $471.9 million, of which approximately
$150 million is attributable to a pipeline replacement program approved
by the GPSC.
As of September 30, 1998, natural gas stored underground decreased $13.7
million to $138.1 million, primarily due to a decrease in the cost of the gas
that we placed into storage.
Ratios and Coverages On September 30, 1998, our capitalization ratios
consisted of:
- - 47.5% long-term debt;
- - 5.4% preferred securities; and
- - 47.1% common equity.
The weighted average cost of long-term debt decreased from 7.6% on
September 30, 1996, to 7.5% on September 30, 1998. The decrease was due to lower
interest rates for long-term debt issued in fiscal 1997.
The ratio of earnings to combined fixed charges and preferred stock
dividends decreased in fiscal 1998 compared with fiscal 1996 primarily due to
increased interest charges. The ratio of earnings to interest charges and
preferred stock dividends decreased in fiscal 1998 compared with fiscal 1996
primarily due to increased interest charges. The ratio of earnings to interest
charges decreased in fiscal 1998 compared with fiscal 1996 primarily due to
increased interest charges.
State Regulatory Activity
Unbundling and AGLC Rate Filing Georgia's Natural Gas Competition and
Deregulation Act became law on April 14, 1997. It provides a legal
framework for comprehensive deregulation of many aspects of the natural
gas business in Georgia.
On November 26, 1997, AGLC filed the following items with the GPSC:
- - a notice of AGLC's election to be subject to the Act; and
- - an application to unbundle (offer separately and establish separate rates for)
the various components of AGLC's services to its customers and to
regulate distribution rates, charges, classifications, and services
under a performance-based regulation plan.
After hearings were held in that proceeding, the GPSC set the rates AGLC will
charge end-use customers (during the transition to competition) and marketers
(during and after the transition to competition) for natural gas delivery and
ancillary services. Those decisions are reflected in the GPSC's initial order
of June 30, 1998. On July 10, 1998, AGLC and other parties to the proceeding
petitioned the GPSC to reconsider some issues in its initial order. The GPSC
subsequently issued partial orders on reconsidered issues on September 18,
October 16, and October 22, 1998.
Key decisions adopted by the GPSC are as follows:
- - a $12.75 million annual rate decrease based on a fully forecasted future test
year for the 12 months ending May 31, 1999;
- - an 11% rate of return on common equity;
- - the end of regulated rates for natural gas commodity sales effective
October 6, 1998;
- - separate, distinct ancillary service rates for meter reading, billing, billing
inquiries, payment processing, and payment collection based on AGLC's fully
allocated costs;
- - balancing services, storage services, and peaking services provided on a
separate basis;
- - denial of AGLC's proposed comprehensive performance-based rate regulation
plan;
- - any customer may, during the transition period, return to the natural gas
commodity sales service offered by AGLC;
- - advance payment by marketers to AGLC for fixed charges for services to
be provided;
- - 90% of revenues from interruptible service by AGLC will go to a
universal service fund (see explanation below), and the remaining 10% will
be revenue for AGLC;
- - AGLC must conduct its business so that it does not give preference to any
marketer; and
- - AGLC must implement a fully operational electronic bulletin board (EBB)
by November 1, 1998; the EBB provides marketers with equal and timely access
to information about the availability of distribution service to
residential and small commercial customers.
As part of the GPSC's rate case ruling, AGLC began billing customers on July 1,
1998, under a rate structure that recovers nongas costs evenly throughout
the year consistent with the way the costs are incurred. The new rate
structure:
- - provides for a level monthly charge for gas delivery service;
- - provides the opportunity to grow margins at a rate more commensurate with
AGLC's above average customer growth rate;
- - eliminates the need for weather normalization; and
- - eliminates the adverse effects of declining use per customer, which AGLC
has experienced for the past several years.
The Act provides for a transition period before competition is fully in effect.
AGLC will unbundle, or separate, all services to its natural gas customers;
allocate delivery capacity to approved marketers who sell the gas commodity
to residential and small commercial users; and create a secondary market for
large commercial and industrial transportation capacity.
Approved marketers, including our marketing affiliate, will compete to
sell natural gas to all end-use customers at market-based prices. AGLC will
continue to deliver gas to all end-use customers through its existing pipeline
system, subject to the GPSC's continued regulation. The GPSC's order
acknowledges that under the Act, the PGA mechanism will be deregulated when
at least five nonaffiliated marketers are authorized to serve an area of
Georgia. The GPSC issued more than five such authorizations on October 6, 1998.
Consequently, AGLC will no longer defer any over-recoveries or under-recoveries
of gas costs, and will refund to customers the over-recovery that existed when
the PGA mechanism was deregulated on October 6, 1998.
Going forward, AGLC intends to design its prices for deregulated gas
sales in a manner that, at a minimum, will allow it to recover its annual gas
costs. Even though the recovery of gas costs is not currently subject to price
regulation, the GPSC continues to regulate delivery rates, safety, access to
AGLC's system, and quality of service for all aspects of delivery service.
Generally, under the Act, the transition to full-scale competition
occurs when residential and small commercial customers who represent one-third
of the peak day requirements for a particular delivery group have voluntarily
selected a marketer. When the GPSC determines such market conditions exist,
there will be a 120-day process to notify and assign customers who have not
selected a marketer. Following the 120-day period, residential and small
commercial customers who have not yet selected a marketer will be randomly
assigned a marketer under the rules issued by the GPSC.
The Act provides marketing standards and rules of business practice to
ensure the benefits of a competitive natural gas market are available to
all customers on our system. It imposes on marketers an obligation to
serve end-use customers, and creates a universal service fund. The
universal service fund provides a method to fund the recovery of
marketer's uncollectible accounts, and it enables AGLC to expand its
facilities to serve the public interest.
Retail marketing companies, including our marketing affiliate, filed separate
applications with the GPSC to sell natural gas to AGLC's residential and small
commercial customers. On October 6, 1998, the GPSC approved 19 marketers'
applications to begin selling natural gas services at market prices to
Georgia customers on November 1, 1998.
Regulatory Accounting We have recorded regulatory assets and liabilities in
our Consolidated Balance Sheets in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71).
In July 1997, the Emerging Issues Task Force (EITF) concluded that once
legislation is passed to deregulate a segment of a utility and that legislation
includes sufficient detail for the enterprise to determine how the transition
plan will affect that segment, SFAS 71 should be discontinued for that segment
of the utility. The EITF consensus permits assets and liabilities of a
deregulated segment to be retained if they are recoverable through a segment
that remains regulated.
Georgia has enacted legislation, the Act, which allows deregulation of
natural gas sales and the separation of some ancillary services of local natural
gas distribution companies. However, the rates that AGLC, as the local gas
distribution company, charges to transport natural gas through its intrastate
pipe system will continue to be regulated by the GPSC. Therefore, we have
concluded that the continued application of SFAS 71 remains appropriate. The
remaining regulatory liability associated with the deregulated gas function will
be refunded.
Chattanooga Gas Company - Rate Filing On May 1, 1997, Chattanooga filed a
rate case with the TRA seeking an annual increase in revenues of $4.4
million. Chattanooga sought the additional revenue in order to:
- - improve and expand Chattanooga's natural gas distribution system;
- - recover increased operation, maintenance and tax expenses; and
- - provide a reasonable return to investors.
Hearings were held in February 1998. On July 21, 1998, the TRA voted to direct
Chattanooga to decrease rates by $1.2 million, primarily as a result of the
TRA's rejection of the proposed overhead allocation method and rejection of
proposed recovery of a previously incurred acquisition premium. Following
the TRA's October 7, 1998, written order, Chattanooga filed tariffs
reflecting the reduction in revenue for service beginning November 1, 1998.
Gas Supply Plan Filing AGLC had been required by Georgia law to submit
annually for GPSC approval a proposed gas supply plan, as well as a proposed
cost recovery factor for the following year.
In September 1997, the GPSC approved AGLC's fiscal 1998 Gas Supply Plan,
which included limited gas supply hedging activities. Under that plan, AGLC was
allowed to hedge up to one-half of its estimated monthly winter wellhead
purchases. Furthermore, to help avoid price fluctuation, AGLC was able to set a
price for those purchases at an amount other than the beginning-of-the-month
index price. Because AGLC then passed on those costs directly to residential and
small commercial customers, its hedging program did not affect fiscal 1998
earnings.
On July 31, 1998, AGLC filed with the GPSC its fiscal 1999 Gas Supply
Plan (the 1999 Plan), which consisted of gas supply, transportation, and storage
options. The 1999 Plan was designed to provide reliable gas service to
residential and small commercial customers at the best cost (least cost
consistent with desired levels of reliability and flexibility). The GPSC
approved the 1999 Plan with some modifications on September 14, 1998.
Under the Act, the 1999 Plan, as approved, became AGLCs first Capacity
Supply Plan (Capacity Plan) when, on October 6, 1998, the GPSC approved more
than five marketers' applications to begin selling natural gas services at
market prices to Georgia consumers. Capacity plans, which must be approved by
the GPSC at least once every three years, describe the array of interstate
capacity assets selected by AGLC to make gas available to end-use
customers on its system. Rights to use capacity assets as set forth in the
Capacity Plan are assigned by AGLC to marketers as the marketers acquire firm
customers. Marketers are responsible for paying fixed charges associated with
the assigned capacity assets.
AGLC Pipeline Safety On January 8, 1998, the GPSC issued procedures and set a
schedule for hearings about alleged pipeline safety violations. On July 21,
1998, the GPSC approved a settlement between AGLC and the Adversary Staff of
the GPSC that details a 10-year replacement program for approximately 2,300
miles of cast iron and bare steel pipelines. Over that 10-year period, AGLC
will recover from customers the costs related to the program net of any cost
savings resulting from the replacement program.
Weather Normalization The GPSC authorized a weather normalization adjustment
rider (WNAR) which was in effect during fiscal 1996, fiscal 1997, and the first
nine months of fiscal 1998. In addition, the TRA has authorized a WNAR. They are
designed to offset the impact of unusually cold or warm weather on customer
billings and operating margin. Consequently, weather normalization affected net
income in the following manner:
- - net income decreased by $1.2 million in fiscal 1998;
- - net income increased by $16.2 million in fiscal 1997; and
- - net income decreased by $4.4 million in fiscal 1996.
On June 30, 1998, the WNAR for AGLC
was discontinued, since the rate structure mandated by the Act eliminates the
effect of weather-related volumetric variances on nongas cost revenue
collections. The WNAR for Chattanooga remains in effect.
Inventory Assignment In Georgia's new competitive environment, certificated
marketing companies, including AGLC's marketing affiliate, began selling natural
gas to firm end-use customers at market-based prices in November 1998. Part of
the unbundling process that provides for this competitive environment is the
allocation of certain pipeline services that AGLC has under contract. In
particular, AGLC will allocate the majority of its pipeline storage services
that it has under contract to the certificated marketing companies along with a
corresponding amount of inventory. Consequently, AGLC has filed tariff
provisions with the GPSC to govern the sale of its gas storage inventories to
certificated marketers. Following the rules of the tariff, the sale price will
be the weighted-average cost of the storage inventory at the time of sale. AGLC
changed its inventory costing method for its gas inventories from first-in,
first-out to weighted average effective October 1, 1998. The weighted-average
cost-flow assumption provides for a more equitable pricing method for the sale
of gas inventories to certificated marketers.
Federal Regulatory Activity
FERC Order 636: Transition Costs Settlement Agreements The utility purchases
natural gas transportation and storage services from interstate pipeline
companies, and the Federal Energy Regulatory Commission (FERC) regulates those
services and the rates the interstate pipeline companies charge the utility.
During the past decade, the FERC has dramatically transformed the natural gas
industry through a series of generic orders promoting competition in the
industry. As part of that transformation, the interstate pipelines that serve
the utility have been required to:
- - unbundle, or separate, their transportation and gas supply services; and
- - provide a separate transportation service on a nondiscriminatory basis for the
gas that is supplied by numerous gas producers or other third parties.
The FERC is considering further revisions to its rules, including the following:
- - its policies governing secondary market transactions for use of pipeline
capacity; and
- - revisions that would permit pipelines and their customers to establish
individually negotiated terms and conditions of service that depart
from generally applicable pipeline tariff rules.
The utility cannot predict whether those changes will be adopted or how they
potentially might affect it.
The FERC has required the utility, as well as other interstate pipeline
customers, to pay transition costs associated with the separation of the
suppliers' transportation and gas supply services. Based on its pipeline
suppliers' filings with the FERC, the utility estimates the total portion of its
transition costs from all its pipeline suppliers will be approximately $106.2
million. As of September 30, 1998, approximately $97.8 million of those costs
had been incurred and were being recovered from the utility's customers under
the purchased gas provisions of its rate schedules. Going forward, AGLC will
recover the majority of the remaining costs through its gas sales. A small
portion of the costs will be recovered from certificated marketers as
part of the assignment process under its unbundling plan.
The largest portion of the transition costs the utility must pay
consists of gas supply realignment costs that Southern Natural Gas
Company (Southern) and Tennessee Gas Pipeline Company (Tennessee) bill
the utility. The utility and other parties have entered restructuring
settlements with Southern and Tennessee that resolve all transition cost
issues for those pipelines.
Under the Southern settlement, the utility's share of Southern's transition
costs is approximately $88 million, of which the utility incurred $84.5
million as of September 30, 1998. Under the Tennessee settlement, the utility's
share of Tennessee's transition costs is approximately $14.7 million, of
which the utility incurred approximately $10 million as of September 30, 1998.
AGLC requested and was granted clarification and assignment waiver of certain
FERC policies concerning interstate pipeline capacity. The request was
necessary to ensure that it would be able to make certain pipeline
services it receives available to certificated marketers as part of its
unbundling plan.
Environmental Matters Before natural gas was available in the Southeast in
the early 1930s, AGLC manufactured gas from coal and other materials. Those
manufacturing operations were known as "manufactured gas plants," or "MGPs."
Because of recent environmental concerns, we are required to investigate
possible contamination at those plants and, if necessary, clean them up.
Through the years AGLC has been associated with twelve MGP sites in
Georgia and three in Florida. Based on investigations to date, we believe that
some cleanup will be likely at most of the sites. In Georgia, the state
Environmental Protection Division supervises the investigation and cleanup of
MGP sites. In Florida, the U.S. Environmental Protection Agency has that
responsibility.
For each of the MGP sites, we estimated our share of the likely costs of
investigation and cleanup. We used the following process to make the estimates:
First, we eliminated the sites where we believe no cleanup or further
investigation is likely to be necessary. Second, we estimated the likely future
cost of investigation and cleanup at each of the remaining sites. Third, for
some sites, we estimated our likely "share" of the costs. We developed our
estimate based on any agreements for cost sharing we have, the legal principles
for sharing costs, our evaluation of other entities' ability to pay, and other
similar factors.
Using that process, we believe our total future cost of investigating and
cleaning up our MGP sites is between $47 million and $81.3 million. Within that
range, we cannot identify a single number as the "best" estimate. Therefore,
we have recorded the lower value, or $47 million, as a liability as of September
30, 1998. As of September 30, 1997, the liability which we had recorded was
$37.3 million. During the year, the liability increased $25.7 million. After
making payments of $16.0 million, related to legal fees and technical support,
the net increase in the liability was $9.7 million. The increase in the
liability was based on revised estimates, which resulted in a corresponding
increase in the unrecovered environmental response cost asset.
We have two ways of recovering investigation and cleanup costs. First,
the GPSC has approved an "Environmental Response Cost Recovery Rider." It allows
us to recover our costs of investigation, testing, cleanup, and litigation.
Because of that rider, we have recorded an asset in the same amount as our
investigation and cleanup liability. The GPSC, however, is conducting hearings
about three aspects of the rider. Depending on how the GPSC rules, our
recoveries under the rider could be affected. If the GPSC were to limit
significantly our recovery under the rider, the results could be material.
The second way we could recover costs is by exercising the legal rights
we believe we have to recover a share of our costs from other corporations and
from insurance companies. We have been actively pursuing those recoveries. In
fiscal 1998, we recovered $1.9 million. As required by the rider, we retained
$.9 million of that amount, and we credited the balance to our customers.
Accounting Developments In June 1997 the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" (SFAS 130) and Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS 131).
- - SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components (revenues, expenses, gains,
and losses) in a full set of general-purpose financial statements.
- - SFAS 131 establishes standards for the way public companies report
information about operating segments in annual financial statements.
It also requires those companies to report selected information about
operating segments in interim financial reports issued to shareholders.
We will adopt SFAS 130 and SFAS 131 in fiscal 1999.
In June 1998 the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133). SFAS 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. We will adopt
SFAS 133 in fiscal 2000.
In March 1998 the American Institute of Certified Public Accountants
issued Statement of Position 98-1 (SOP 98-1), "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." SOP 98-1 provides
guidance on accounting for the costs of computer software developed or
obtained for internal use. We will adopt SOP 98-1 in fiscal 2000.
We do not expect those new pronouncements to have a material effect on
our consolidated financial statements.
Competition
In this section we discuss the way competition affects our utility and
nonutility businesses.
Utility The utility competes to supply natural gas to large commercial and
industrial customers. Those customers can switch to alternative fuels,
including propane, fuel and waste oils, electricity and, in some cases,
combustible wood by-products. We also compete to supply gas to large
commercial and industrial customers who seek to bypass our distribution system.
Before the GPSCs rate case order of June 30, 1998, AGLC was providing
service under 56 negotiated contracts with customers who had the ability to
bypass our distribution system and receive service directly from interstate
pipelines. In addition, AGLC was providing service under seven special long-term
contracts that involve competing with alternative fuels where physical bypass is
not the relevant competition. Under the regulatory structure then in place, AGLC
was allowed to recover from other customers most of the discounts associated
with such contracts.
The change in the regulatory structure associated with unbundling and
restatement of rates removed the need to recover discounts going
forward. Nevertheless, the GPSC specifically authorized AGLC to continue
to enter into future contracts if the initial term of a contract does
not exceed three years and if all such future contracts include
market-out provisions. The GPSC issued a written order setting forth its
decision on May 21, 1998.
Subsequent to July 1, 1998, AGLC can price distribution services to large
commercial and industrial customers in one of three ways:
- - GPSC-approved rates in AGLCs tariff;
- - discounted rates - if an existing rate is not priced competitively with
a customers competitive alternative fuel; or
- - special contracts approved by the GPSC.
Additionally, interruptible customers have the option of purchasing delivery
service directly from marketers, who are authorized to use capacity on AGLCs
distribution system that is allocated to the marketers for residential and small
business firm customers, whenever such capacity is not being used for firm
customers.
On November 27, 1996, the TRA approved an experimental rule allowing
Chattanooga to negotiate contracts with large commercial and industrial
customers who have long-term competitive options, including bypass. The
experimental rule requires that before a large Tennessee customer is
allowed a discounted rate, both the customer and Chattanooga must
request that the TRA approve the rates requested in the contract.
On October 7, 1997, the TRA denied requests from Chattanooga and four large
customers for discounted rates after deciding that customer bypass was
not imminent. On January 14, 1998, however, the Federal Energy
Regulation Commission (FERC) issued an order authorizing Southern
Natural Gas Company to bypass Chattanooga to serve a large industrial
customer. Chattanooga later reached a settlement with that customer to
avoid bypass.
Nonutility We engage in several competitive, energy-related businesses,
including gas supply services, wholesale and retail propane sales, wholesale
gas and power marketing, retail energy marketing, customer care
services, and the sale of energy-related products and services for residential,
commercial, and industrial customers throughout the Southeast. (For a brief
description of each nonutility business refer to the section, Nature of Our
Business, at the beginning of this Managements Discussion and Analysis of
Results of Operations and Financial Condition.)
Unlike the utility, our nonutility businesses are not regulated. Our
nonutility businesses typically face competition from other companies in the
same or similar businesses. Currently, our nonutility businesses do not have a
material effect on our consolidated financial statements.
Year 2000 Readiness Disclosure
The widespread use by governments and businesses, including us, of computer
software that relies on two digits, rather than four digits, to define the
applicable year may cause computers, computer-controlled systems, and equipment
with embedded software to malfunction or incorrectly process data as we approach
and enter the year 2000.
Our Year 2000 Readiness Initiative In view of the potential adverse impact of
the "Year 2000" issue on our business, operations, and financial condition, we
have established a cross-functional team to coordinate, and to report to
management on a regular basis about, our assessment, remediation planning, and
plan implementation processes directed to Year 2000. We also have engaged
independent consultants to assist us in the assessment, remediation planning,
and implementation phases of our Year 2000 initiative. Our Year 2000 initiative
is proceeding on schedule.
The mission of our Year 2000 initiative is to define and provide a
continuing process for assessment, remediation planning, and plan implementation
to achieve a level of readiness that will meet the challenges presented to us by
the Year 2000 in a timely manner. Achieving Year 2000 readiness does not mean
correcting every Year 2000 limitation. Achieving Year 2000 readiness does mean
that critical systems, critical electronic assets, and relationships with key
business partners have been evaluated and are expected to be suitable for
continued use into and beyond the Year 2000, and that contingency plans are in
place.
Our Year 2000 readiness initiative involves a three-phase process. The
initiative is a continuing process with all phases of the initiative progressing
concurrently with respect to both IT and non-IT assets, as defined below, and
with respect to key business relationships. The three phases of our Year 2000
initiative are as follows:
1. Assessment -Assessment involves identifying and inventorying business assets
and processes. It also involves determining the Year 2000 readiness status
of our assets and of key business partners. Key business partners are
those customers and suppliers who we believe may be material to our business,
results of operations, or financial condition. In appropriate
circumstances, pre-remediation testing is conducted as a part of the
assessment phase. The assessment phase of our Year 2000 initiative includes
assessment for Year 2000 readiness of the following:
- - information technology (IT) assets - Computer systems and software maintained
by our Information Systems (IS) Department;
- - noninformation technology (non-IT) assets - including microprocessors embedded
in equipment, and information technology purchased and maintained by
business units other than our IS Department; and
- - and key business partners (customers and suppliers).
2. Preparation of Remediation Plans - The purpose of this phase is to develop
plans which, when implemented, will enable assets and business relationships
to be Year 2000 ready. This phase involves implementation planning and
prioritizing the implementation of remediation plans.
3. Implementation - This step involves the implementation of remediation plans,
including post-remediation testing and contingency planning.
State of Readiness We continue to assess the impact of the Year 2000 issue
throughout our business and operations, including our customer and supplier
base. The scope of our Year 2000 initiative includes AGL Resources and its
subsidiaries. A number of our joint ventures, including Sonat Power Services,
L.P., Sonat Marketing, L.P., and SouthStar Energy Services LLC, are not within
the scope of our Year 2000 initiative. We plan to address the Year 2000
readiness of those joint ventures using the same processes we use to assess the
Year 2000 readiness of key business partners. (See "Key Business Partners"
below.) The following is a description of the progress of our Year 2000
initiative in all business units that are within the scope of our Year 2000
initiative, with the exception of Utilipro, Inc., a recently acquired
subsidiary. The Year 2000 initiative is about to commence with respect to
Utilipro, Inc., and we expect Utilipro's business and operations to achieve
Year 2000 readiness.
IT Assets Assessment of IT assets is complete. Remediation planning and
implementation are underway. As part of our IT assessment process, we completed
the assessment of our 79 mainframe and personal computer systems. We deem 13 of
those 79 systems to be critical systems. The results of our Year 2000 initiative
with respect to IT assets indicate that, to date:
- - 29 systems now are ready for Year 2000, including 12 of the 13 critical
systems;
- - one critical system is being evaluated to determine whether replacement
or remediation is the most efficient course of action;
- - 10 systems are in testing to verify Year 2000 readiness;
- - two systems are in remediation for purposes of correcting
noncompliant Year 2000 code;
- - three systems have been eliminated; and
- - 34 systems are scheduled for either testing, replacement, remediation,
or elimination in the future.
We expect our one critical IT asset that is not yet
Year 2000 ready to be Year 2000 ready by March 31, 1999. Remediation completion
schedules for achieving Year 2000 readiness of noncritical IT assets are
expected to extend through September 1999.
Non-IT Assets Assessment of non-IT assets is complete. Our non-IT asset
assessment process involved the following:
- - identifying business processes;
- - identifying non-IT assets and defining the business process or processes
to which such assets relate;
- - identifying the mission criticality of each non-IT asset and business
process; and
- - documenting in a tracking database the existence, and the
mission-criticality, of each non-IT asset and business process.
We expect to complete remediation planning for critical non-IT assets by
December 15, 1998. The expected completion date for remediation plan
implementation for critical non-IT assets will depend on the results of the
remediation planning phase for non-IT assets, but is not expected to extend
beyond June 30, 1999.
Key Business Partners We are contacting key business partners, including
suppliers and customers, to evaluate their Year 2000 readiness plans and status
of readiness. We have contacted over 1,400 suppliers by letter. That group of
suppliers includes suppliers whom we consider key business partners as well as
other selected suppliers. However, to date, we have not received responses from
the majority of suppliers we contacted. We have begun following up by telephone
with those key suppliers from whom we have not yet received responses. We also
initiated contact with more than 2,500 commercial and industrial customers by
personal or telephone interview or by fax survey. To date, we have not received
responses from most of those customers. If key customers do not respond by
January 1, 1999, we plan to begin to follow up by fax or telephone with those
customers.
We are assessing the state of readiness of key business partners who
have responded to our request for information and will continue to do so as we
receive additional responses. As a general matter, we, like other businesses,
are vulnerable to key business partners' inability to achieve Year 2000
readiness. We cannot predict the outcome of our business partners' readiness
efforts. However, we plan to develop contingency plans to mitigate risks
associated with the Year 2000 readiness of certain business partners, including
key business partners. At this stage of our review of key business partners, we
do not have sufficient information to determine whether the Year 2000 readiness
of key business partners is likely to have a material impact on our business,
results of operations, or financial condition.
Costs to Address Year 2000 Issues Management intends to devote the resources
necessary to achieve a level of readiness that will meet our Year 2000
challenges in a timely manner. Through September 30, 1998, our cumulative
expenses in connection with our Year 2000 assessment, remediation planning, and
plan implementation processes were approximately $3 million. Through September
30, 1998, we had spent an additional $7.1 million for the replacement of our
general ledger and human resources information systems. Our primary reason for
replacing those systems was to achieve increased efficiency and functionality.
An added benefit of replacing those systems was the avoidance of the costs of
remediating Year 2000 problems associated with our previous general ledger and
human resources information systems. We will capitalize the costs of our new
general ledger and human resources information systems, in accordance with our
accounting policies and with generally accepted accounting principles.
We expect to spend approximately $6 million in fiscal 1999 in connection
with our Year 2000 initiative. That estimate includes costs associated with the
use of outside consultants as well as hardware and software costs. It also
includes direct costs associated with employees of our IS Department who work on
the Year 2000 initiative. However, the fiscal 1999 estimate is subject to
change, based on the results of our ongoing Year 2000 processes.
On June 30, 1998, the GPSC issued a rate case order in response to a
filing by AGLC. The GPSC provided for the deferral and amortization of some Year
2000 costs over a five-year period, beginning July 1, 1998. The portion of those
costs that will be deferred in this way includes costs that are required to be
expensed under generally accepted accounting principles and that are
attributable to AGLC. Going forward, we estimate that approximately 90% of our
Year 2000 costs will be attributable to AGLC. At September 30, 1998, AGLC had
deferred total costs of $2.0 million less accumulated amortization of $.1
million.
At present, the cost estimates associated with achieving Year 2000
readiness are not expected to materially impact our consolidated financial
statements. We will account for costs related to achieving Year 2000 readiness
in accordance with our accounting policies, with regulatory treatment, and with
generally accepted accounting principles.
Risks of Year 2000 Issues We are in the process of identifying our most
reasonably likely worst case Year 2000 scenarios. As such, we are not yet able
to comment on whether the consequences of such scenarios could have a material
impact on our business, results of operations, or financial condition. The
process of defining our most reasonably likely worst case scenarios is part of
the contingency planning effort that is currently underway. Our process for
identifying our most reasonably likely worst case scenarios includes the
following:
- - identifying core business processes;
- - identifying key business partners (including suppliers and customers);
- - conducting Year 2000 business impact analysis; and
- - reviewing experts' views of factors likely to contribute to such a scenario.
The contingency planning process and the process of developing most reasonably
likely worst case scenarios will be ongoing processes, requiring continuing
development, modification, and refinement as we obtain additional information
regarding (a) our internal systems and equipment during the implementation phase
of our Year 2000 initiative, and (b) the status, and the impact on us, of the
Year 2000 readiness of others.
Business Continuity and Contingency Planning
We are developing Year 2000 contingency plans. Those plans, which are intended
to enable us to deliver an acceptable level of service despite Year 2000
failures, include performing certain processes manually, changing suppliers, and
reducing or suspending certain noncritical aspects of our operations. We expect
our contingency planning effort to focus on our potential internal risks as well
as potential risks associated with our suppliers and customers. Identifying our
most reasonably likely worst case scenarios as described above will define the
boundaries of our contingency planning effort. The contingency planning process
also includes, but is not limited to the following:
- - identifying the nature of Year 2000 risks to understand the business impact of
those risks;
- - identifying our minimal acceptable service levels;
- - identifying alternative providers of goods and services;
- - identifying necessary investments in additional back-up equipment such as
generators and communications equipment; and
- - developing manual methods of performing critical functions currently
performed by electronic systems and equipment.
From February through June 1999, we expect to be testing and refining our
contingency plans, with a planned testing completion date of June 30, 1999.
Although the expected completion date for our contingency planning effort is
June 30, 1999, during the last half of 1999 we will update and refine our
contingency plans, as needed, to reflect system and business changes as
they evolve.
Presently, management believes that its assessment, remediation
planning, plan implementation and contingency planning processes will be
effective to achieve Year 2000 readiness in a timely manner.
Forward-Looking Statements The preceding "Year 2000 Readiness Disclosure"
discussion contains various forward-looking statements that represent our
beliefs or expectations regarding future events. When used in the "Year 2000
Readiness Disclosure" discussion, the words "believes," "intends," "expects,"
"estimates," "plans," "goals," and similar expressions are intended to
identify forward-looking statements. Forward-looking statements include,
without limitation, our expectations as to when we will complete the assessment,
remediation planning, and implementation phases of our Year 2000 initiative
as well as our Year 2000 contingency planning; our estimated cost of
achieving Year 2000 readiness; and our belief that our internal systems and
equipment will be Year 2000 ready in a timely and appropriate manner. All
forward-looking statements involve a number of risks and uncertainties that
could cause the actual results to differ materially from the projected results.
Factors that may cause those differences include availability of information
technology resources; customer demand for our products and services;
continued availability of materials, services, and data from our suppliers;
the ability to identify and remediate all date-sensitive lines of computer
code and to replace embedded computer chips in affected systems and equipment;
the failure of others to timely achieve appropriate Year 2000 readiness;
and the actions or inaction of governmental agencies and others with respect to
Year 2000 problems.
Statements of Consolidated Income
For the years ended September 30,
---------------------------------------------------------------------
In millions 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
Operating Revenues $ 1,338.6 $ 1,287.6 $ 1,228.6
Cost of Sales 796.0 766.5 725.5
- -----------------------------------------------------------------------------------------------------------------------------
Operating Margin 542.6 521.1 503.1
- -----------------------------------------------------------------------------------------------------------------------------
Other Operating Expenses
Operation 238.1 226.2 221.8
Maintenance 38.4 30.8 29.5
Depreciation 71.1 66.6 63.3
Taxes other than income taxes 27.4 26.0 25.0
- -----------------------------------------------------------------------------------------------------------------------------
Total other operating expenses 375.0 349.6 339.6
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 167.6 171.5 163.5
- -----------------------------------------------------------------------------------------------------------------------------
Other Income 12.9 10.3 13.1
- -----------------------------------------------------------------------------------------------------------------------------
Interest Expense and Preferred Stock
Dividends
Interest on long-term debt 49.7 45.1 42.2
Other interest 4.7 7.1 6.9
Dividends on preferred stock of subsidiary 6.7 6.2 4.4
- -----------------------------------------------------------------------------------------------------------------------------
Total interest expense and preferred stock
dividends 61.1 58.4 53.5
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 119.4 123.4 123.1
- -----------------------------------------------------------------------------------------------------------------------------
Income Taxes 38.8 46.8 47.5
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 80.6 $ 76.6 $ 75.6
- -----------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share (Note 1)
Basic $ 1.41 $ 1.37 $ 1.37
Diluted $ 1.41 $ 1.36 $ 1.36
- -----------------------------------------------------------------------------------------------------------------------------
Weighted Average Number of Common
Shares Outstanding (Note 1)
Basic 57.0 56.1 55.3
Diluted 57.1 56.2 55.4
- -----------------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
Statements of Consolidated Cash Flows
For the years ended September 30,
------------------------------------------------------
In millions 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Operating Activities
Net income $ 80.6 $ 76.6 $ 75.6
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization 75.7 70.3 67.5
Provision for writedown of assets 13.9
Deferred income taxes 11.3 18.5 25.7
Other 2.0 0.3 0.4
- -------------------------------------------------------------------------------------------------------------------
183.5 165.7 169.2
Changes in assets and liabilities
Receivables (29.6) 5.8 (29.6)
Inventories 13.1 (10.3) (35.8)
Deferred purchased gas adjustment 17.4 (3.8) (11.0)
Accounts payable (13.8) (12.8) 1.4
Other-net 6.9 8.6 (12.3)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from operating
activities 177.5 153.2 81.9
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses .9 1.7 1.8
Short-term borrowings, net 47.0 (124.0) 101.0
Redemptions of preferred securities (44.5) (14.7)
Sale of preferred securities, net of expenses 74.3
Sale of long-term debt 105.5
Dividends paid on common stock (51.6) (50.7) (49.1)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from financing
activities (48.2) (7.9) 53.7
- -------------------------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Utility plant expenditures (94.8) (123.5) (132.0)
Nonutility property expenditures (22.5) (23.3) .3
Cash received from joint ventures 3.0 2.0 3.1
Investment in joint ventures (12.9) (2.8) (1.0)
Other (6.0) (1.6) (1.0)
- -------------------------------------------------------------------------------------------------------------------
Net cash flow from investing
activities (133.2) (149.2) (130.6)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents (3.9) (3.9) 5.0
Cash and cash equivalents
at beginning of year 4.8 8.7 3.7
- -------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents
at end of year $ .9 $ 4.8 $ 8.7
- -------------------------------------------------------------------------------------------------------------------
Cash Paid During the Year for
Interest $ 51.5 $ 48.8 $ 49.2
Income taxes $ 39.2 $ 28.2 $ 19.3
- -------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
Consolidated Balance Sheets
Assets September 30,
------------------------------------------
In millions 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ .9 $ 4.8
Receivables
Gas (less allowance for uncollectible accounts
of $3.7 in 1998 and $2.4 in 1997) 81.6 56.1
Integrated Resource Plan loans (less allowance
for uncollectible accounts of $.1) 3.2
Other (less allowance for uncollectible accounts
of $.4 in 1998 and $.1 in 1997) 8.7 10.8
Unbilled revenues 31.4 22.0
Inventories
Natural gas stored underground 138.1 151.8
Liquefied natural gas 17.7 17.5
Materials and supplies 10.0 8.2
Other 4.6 6.0
Deferred purchased gas adjustment 8.5
Other 1.9 2.0
- ---------------------------------------------------------------------------------------------------------------
Total current assets 294.9 290.9
- ---------------------------------------------------------------------------------------------------------------
Property, Plant, and Equipment
Utility plant 2,133.5 2,069.1
Less accumulated depreciation 680.9 648.8
- ---------------------------------------------------------------------------------------------------------------
Utility plant - net 1,452.6 1,420.3
- ---------------------------------------------------------------------------------------------------------------
Nonutility property 106.0 106.7
Less accumulated depreciation 24.6 29.5
- ---------------------------------------------------------------------------------------------------------------
Nonutility property - net 81.4 77.2
- ---------------------------------------------------------------------------------------------------------------
Total property, plant and equipment - net 1,534.0 1,497.5
- ---------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Unrecovered environmental response costs 77.6 55.0
Investment in joint ventures 46.3 34.5
Unrecovered postretirement benefits costs 9.3 10.0
Prepaid pension costs 3.2
Unamortized cost to repurchase long-term debt 1.0 2.2
Other 18.7 32.2
- ---------------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 152.9 137.1
- ---------------------------------------------------------------------------------------------------------------
Total Assets $ 1,981.8 $ 1,925.5
- ---------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
Liabilities and Capitalization September 30,
------------------------------------------
In millions 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Current Liabilities
Accounts payable-trade $ 48.4 $ 62.2
Short-term debt 76.5 29.5
Customer deposits 30.5 29.2
Interest 32.8 29.6
Wages and salaries 14.8 8.0
Other accrued liabilities 12.1 21.3
Deferred purchased gas adjustment 8.9
Redemption requirements on preferred stock 44.5
Other 26.0 19.1
- ---------------------------------------------------------------------------------------------------------------
Total current liabilities 250.0 243.4
- ---------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Taxes 203.0 191.7
- ---------------------------------------------------------------------------------------------------------------
Long-Term Liabilities
Accrued environmental response costs 47.0 37.3
Accrued pension costs 2.2
Accrued postretirement benefits costs 33.4 34.3
- ---------------------------------------------------------------------------------------------------------------
Total long-term liabilities 82.6 71.6
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits
Unamortized investment tax credit 25.8 27.3
Regulatory tax liability 17.3 18.3
Other 14.7 16.8
- ---------------------------------------------------------------------------------------------------------------
Total deferred credits 57.8 62.4
- ---------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 10 and 12)
- ---------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 660.0 660.0
Subsidiary obligated mandatorily redeemable
preferred securities 74.3 74.3
Common stockholders' equity (See accompanying
statements of consolidated common stock equity) 654.1 622.1
- ---------------------------------------------------------------------------------------------------------------
Total capitalization 1,388.4 1,356.4
- ---------------------------------------------------------------------------------------------------------------
Total Liabilities and Capitalization $ 1,981.8 $ 1,925.5
- ---------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
Statements of Consolidated Common Stock Equity
For the years ended September 30,
-------------------------------------------------
In millions, except per share amounts 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------------
Common Stock
$5 par value; authorized 100.0 shares;
outstanding, 57.3 in 1998, 56.6 in 1997
and 55.7 in 1996
Beginning of year $ 283.1 $ 278.4 $ 137.3
Benefit, stock compensation, dividend
reinvestment and stock purchase plans 3.5 3.7 3.6
Stock dividend 137.5
Acquisition of nonregulated operation 1.0
- -------------------------------------------------------------------------------------------------------------------------
End of year 286.6 283.1 278.4
- -------------------------------------------------------------------------------------------------------------------------
Premium on Capital Stock
Beginning of year 183.6 170.6 297.7
Benefit, stock compensation, dividend
reinvestment and stock purchase plans 9.4 10.1 10.4
Stock dividend (137.5)
Acquisition of nonregulated operation 2.9
- -------------------------------------------------------------------------------------------------------------------------
End of year 193.0 183.6 170.6
- -------------------------------------------------------------------------------------------------------------------------
Earnings Reinvested
Beginning of year 155.4 139.3 122.3
Net income 80.6 76.6 75.6
Common stock dividends ($1.08 a share in 1998, $1.08
a share in 1997 and $1.06 a share in 1996) (61.5) (60.5) (58.6)
- -------------------------------------------------------------------------------------------------------------------------
End of year 174.5 155.4 139.3
- -------------------------------------------------------------------------------------------------------------------------
Total common stock equity $ 654.1 $ 622.1 $ 588.3
- -------------------------------------------------------------------------------------------------------------------------
<FN>
See notes to consolidated financial statements.
</FN>
Note 1. Significant Accounting Policies
Nature of Our Business
Following shareholder and regulatory approval on March 6, 1996, AGL Resources
Inc. became the holding company for:
- - Atlanta Gas Light Company (AGLC) and its wholly owned subsidiary, Chattanooga
Gas Company (Chattanooga), which are local natural gas distribution
utilities; and
- - several nonutility subsidiaries.
We collectively refer to AGL Resources Inc. and its subsidiaries as "AGL
Resources."
AGLC conducts our primary business: the distribution of natural gas in
Georgia, including the Atlanta, Athens, Augusta, Brunswick, Macon, Rome,
Savannah, and Valdosta areas and in Tennessee, including the Chattanooga and
Cleveland areas. The Georgia Public Service Commission (GPSC) regulates AGLC,
and the Tennessee Regulatory Authority (TRA) regulates Chattanooga. AGLC
comprises substantially all of AGL Resources' assets, revenues, and earnings.
When we discuss the operations and activities of AGLC and Chattanooga, we refer
to them, collectively, as the "utility."
AGL Resources also operates the following wholly owned nonutility
subsidiaries:
- - AGL Energy Services, Inc., a gas supply services company that has one
wholly owned nonutility subsidiary, Georgia Gas Company;
- - AGL Interstate Pipeline Company which owns a 50% interest in Cumberland
Pipeline Company; Cumberland Pipeline Company is expected to provide
interstate pipeline services to customers in Georgia and Tennessee beginning
November 1, 2000;
- - AGL Investments, Inc., which was established to develop and manage
certain nonutility businesses including:
* AGL Gas Marketing, Inc., which owns a 35% interest in Sonat Marketing,
L.P.; Sonat Marketing, L.P. engages in wholesale and retail natural gas
trading;
* AGL Power Services, Inc., which owns a 35% interest in Sonat Power
Marketing, L.P.; Sonat Power Marketing, L.P. engages in wholesale power
trading;
* AGL Propane, Inc., which engages in the sale of propane and
related products and services;
* Trustees Investments, Inc., which owns Trustees Gardens, a residentia
and retail development located in Savannah, Georgia; and
* Utilipro, Inc., which engages in the sale of integrated customer care
solutions to energy marketers; and
- - AGL Peaking Services, Inc., which owns a 50% interest in Etowah LNG Company
LLC; Etowah LNG Company LLC is a joint venture with Southern Natural Gas
Company and was formed for the purpose of constructing, owning, and operating
a liquefied natural gas peaking facility.
In July 1998, AGL Resources formed a joint venture known as SouthStar Energy
Services LLC (SouthStar). SouthStar was established to sell natural gas,
propane, fuel oil, electricity, and related services to industrial, commercial,
and residential customers in Georgia and the Southeast. SouthStar is a joint
venture among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a
subsidiary of Dynegy, Inc., and Piedmont Energy Company, a subsidiary of
Piedmont Natural Gas Company. SouthStar filed for certification as a retail
marketer with the GPSC on July 15, 1998, and was approved on October 6, 1998.
SouthStar operates in Georgia under the name Georgia Natural Gas Services.
Regulation of the Utility Business
The GPSC and the TRA regulate our utility business with respect to rates,
maintenance of accounting records, and various other matters. Generally, we use
the same accounting policies and practices nonutility companies use for
financial reporting under generally accepted accounting principles. However,
sometimes the GPSC and the TRA order an accounting treatment different from
that used by nonregulated companies to determine the rates we charge our
customers. (See Note 4 in Notes to Consolidated Financial Statements.)
Consolidation Policy
We use two different accounting methods to report our investments in our
subsidiaries or other companies: consolidation and the equity method.
Consolidation We use consolidation when we own a majority of the voting stock
of the subsidiary or if we can otherwise exercise control over the entity. That
means we combine our subsidiaries' accounts with our accounts. We eliminate
intercompany balances and transactions when we consolidate the accounts. Our
consolidated financial statements include the accounts of the following
subsidiaries:
- - AGLC and its subsidiary, Chattanooga;
- - AGL Energy Services, Inc. and its subsidiary;
- - AGL Interstate Pipeline Company;
- - AGL Investments, Inc. and its subsidiaries; and
- - AGL Peaking Services, Inc.
The Equity Method We use the equity method to report corporate joint
ventures where we hold a 20% to 50% voting interest, unless we can
exercise control over the entity. Under the equity method, we report our
interest in the entity as an investment in our Consolidated Balance
Sheets, and our percentage share of the earnings from the entity in our
Statements of Consolidated Income.
We use the equity method to report our investments in the following:
- - Sonat Power Marketing, L.P.;
- - Sonat Marketing Company, L.P.;
- - Etowah LNG;
- - SouthStar Energy Services LLC; and
- - Cumberland Pipeline Company.
Utility Revenues
We record utility revenues in our Statements of Consolidated Income when we
provide service to customers. Those revenues include estimated amounts
for gas delivered, but not yet billed. Revenues from our utility
business are based on rates approved by the GPSC and the TRA.
On July 1, 1998, AGLC began billing customers under a new rate structure
that recovers nongas costs evenly throughout the year consistent with the way
the costs are incurred. (See Note 2 in Notes to Consolidated Financial
Statements.)
The GPSC authorized a weather normalization adjustment
rider (WNAR), which was in effect during fiscal 1996, fiscal 1997, and
the first nine months of fiscal 1998. In addition, the TRA has
authorized a WNAR. They are designed to offset the impact
of unusually cold or warm weather on customer billings and operating margin. On
June 30, 1998, the WNAR for AGLC was discontinued, since the rate design
mandated by the Georgia Natural Gas Competition and Deregulation Act (the Act)
eliminates the effect of weather-related volumetric variances on nongas cost
revenue collections. The WNAR for Chattanooga remains in effect.
Some industrial and commercial customers purchase gas directly from gas
producers and marketers. The GPSC and the TRA have approved programs in which
transportation charges are billed on those purchases.
Gas Costs
The utility incurs costs for the natural gas that it purchases and resells to
customers. The utility charged its customers for the natural gas they consumed
using purchased gas adjustment (PGA) mechanisms set by the GPSC and the TRA.
Under the PGA, the utility deferred (included as a current asset or liability in
the Consolidated Balance Sheets and excluded from the Statements of Consolidated
Income) the difference between the utility's actual cost of gas and what it
collected from customers in a given period. Then, the utility either billed or
refunded its customers the deferred amount. The GPSC's order acknowledges that
under the Act, AGLC's PGA will be deregulated when at least five nonaffiliated
marketers are authorized to serve an area of Georgia. The GPSC issued more than
five such authorizations on October 6, 1998. Consequently, AGLC will no longer
defer any over-recoveries or under-recoveries of gas costs, and will refund to
customers any over-recovery that existed when the PGA mechanism was deregulated
on October 6, 1998.
Risk Management
AGLCs Gas Supply Plan for fiscal 1998 included limited gas supply hedging
activities. AGLC was authorized to begin an expanded program to hedge up to
one-half its estimated monthly winter wellhead purchases and to establish a
price for those purchases at an amount other than the beginning-of-the-month
index price. Such a program creates an additional element of diversification and
price stability. The financial results of all hedging activities were passed
through to residential and small commercial customers under the PGA provisions
of AGLC's rate schedules. Accordingly, the hedging program did not affect our
earnings.
Consistent with fiscal 1998, AGLC's Gas Supply Plan for fiscal 1999 will
include limited gas supply hedging activities. In conjunction with deregulation,
the fiscal 1999 hedging results will not pass through to residential and small
commercial customers through a regulated PGA mechanism. Accordingly, in fiscal
1999, the hedging program may affect earnings.
Beginning in November 1998, AGLC began to make public the price at which
it sells gas. AGLC also began a fixed-price option program to minimize the risk
of loss incurred as a result of gas volume and price volatility after the price
has been published. Each month before publishing the sales price, AGLC will
determine whether to enter into a fixed-price option agreement for the
respective month. In the event AGLC enters into such an agreement,it will pay a
monthly option premium based on the potential need for incremental wellhead
purchases. Such premium will fix AGLC's maximum gas purchase cost for
incremental wellhead purchases at the agreements fixed price. Accordingly, in
the event actual gas prices on any day during the month exceed the agreement's
fixed price for the month, the option reimburses AGLC the difference in excess
of the fixed price. If the actual gas price on any day during the month is less
than the fixed price, AGLC pays the lesser price. The anticipated results of
fixed-price option agreements will be to limit the effect of gas price
volatility on earnings.
Income Taxes
We must report some of our assets and liabilities differently for financial
accounting purposes than we do for income tax purposes. The tax effects
of the differences in those items are reported as deferred income tax assets
or liabilities in our Consolidated Balance Sheets. Investment tax credits
associated with our utility have been deferred and are being amortized as
credits to income in accordance with regulatory treatment over the estimated
lives of the related properties. We reduce income tax expense in our
Statements of Consolidated Income for the investment tax credits and other
tax credits associated with our nonutility subsidiaries.
Evaluation of Assets for Impairment
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
(SFAS 121) requires us to review long-lived assets and certain intangibles
for impairment when events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. Any impairment losses are
reported in the period in which the recognition criteria are first applied
based on the fair value of the asset. In accordance with SFAS 121, AGL
Resources has evaluated its long-lived assets for financial impairment. As
a result of this review, AGL Resources recorded charges totaling $13.9
million to other operating expenses during the fourth quarter of 1998. Those
charges included:
- - a $10.8 million expense related to the impairment of certain assets no
longer useful primarily due to changes in our information systems strategy;
and
- - a $3.1 million expense due to a decision by management not to seek recovery
for certain deferred expenses.
Utility Plant and Depreciation
Utility Plant Utility plant is the term we use to describe our utility
business property and equipment that is in use, being held for future use,
and under construction. We report our utility plant at its original cost,
which includes:
- - material and labor;
- - contractor costs;
- - construction overhead costs (where applicable); and
- - an allowance for funds used during construction (described later in this
note).
We charge retired or otherwise-disposed-of utility plant to accumulated
depreciation.
Depreciation Expense We compute depreciation by applying composite,
straight-line rates (approved by the GPSC and TRA) to the average investment
in classes of depreciable utility property. The composite straight-line
depreciation rate was approximately 3.2% for depreciable utility and nonutility
property excluding transportation equipment during fiscal years 1998, 1997,
and 1996. Transportation equipment is depreciated on a straight-line basis over
a period of five to ten years.
Allowance for Funds Used During Construction (AFUDC) We finance construction
projects with borrowed funds and equity funds. The GPSC allows us to record
the cost of those funds as part of the cost of construction projects
on our Consolidated Balance Sheets. We do that through the AFUDC in our
Statements of Consolidated Income. We calculate the AFUDC using a rate
authorized by the GPSC. Beginning July 1, 1998, the GPSC authorized a rate
of 9.11% for AFUDC. For the nine months ended June 30, 1998, and for
fiscal 1997 and fiscal 1996, the authorized AFUDC rate was 9.32%.
Statement of Cash Flows
For reporting our cash flows, we define cash equivalents as highly liquid
investments that mature in three months or less.
Noncash investing and financing transactions include the following:
- - the issuance of common stock for ResourcesDirect, a stock purchase and
dividend reinvestment plan; the Retirement Savings Plus Plan; the Long-Term
Stock Incentive Plan; the Nonqualified Savings Plan; and the Non-Employee
Directors Equity Compensation Plan of $12.0 million in fiscal 1998, $12.5
million in fiscal 1997, and $12.3 million in fiscal 1996; and
- - the issuance of 200,000 shares of AGL Resources common stock in the amount
of $3.9 million for the acquisition of propane operations in June 1997.
During fiscal 1998 AGL Resources recorded noncash charges of $13.9 million
related to the impairment of certain long-lived assets.
Earnings per Common Share
Earnings per common share for all periods have been computed under the
provisions of a new accounting standard, Statement of Financial Accounting
Standards No.128, "Earnings Per Share," which was adopted October 1, 1997, and
calls for the restatement of all periods presented on a comparable basis. The
following weighted average common share and common share equivalent amounts
were used for the calculation of basic and diluted earnings per common
share. The common share equivalents relate to stock options under stock
compensation plans.
______________________________________________________________
Weighted Average Weighted Average Number
Number of Common Shares and
of Common Shares Common Share Equivalents
Fiscal Year (Basic Shares) (Diluted Shares)
- -----------------------------------------------------------------------------
1998 57.0 million 57.1 million
- -----------------------------------------------------------------------------
1997 56.1 million 56.2 million
- -----------------------------------------------------------------------------
1996 55.3 million 55.4 million
_____________________________________________________________________________
Use of Accounting Estimates
We make estimates and assumptions when preparing financial statements under
generally accepted accounting principles. Those estimates and assumptions
affect various matters:
- - reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements;
- - disclosure of contingent assets and liabilities at the dates of the
financial statements; and
- - reported amounts of revenues and expenses in our Statements of
Consolidated Income during the reporting periods.
Those estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. Consequently, actual amounts could differ from our estimates.
Other
Gas inventories are stated at cost principally on a 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 GPSC and the TRA, vacation
pay and short-term disability benefits for the utility are expensed as those
benefits are paid.
We have reclassified certain prior year amounts for comparative purposes. Those
reclassifications did not affect consolidated net income for the years
presented.
Recently Issued Accounting Pronouncements
In June 1997 the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 130, "Reporting Comprehensive Income"
(SFAS 130) and Statement of Financial Accounting Standards No. 131,
"Disclosures about Segments of an Enterprise and Related Information"
(SFAS 131).
- - SFAS 130 establishes standards for reporting and displaying comprehensive
income and its components (revenues, expenses, gains, and losses) in a full
set of general-purpose financial statements.
- - SFAS 131 establishes standards for the way public companies report
information about operating segments in annual financial statements. It also
requires those companies to report selected information about operating
segments in interim financial reports issued to shareholders.
We will adopt SFAS 130 and SFAS 131 in fiscal 1999.
In June 1998 the FASB issued Statement of Financial Accounting Standards
No. 133, "Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133). SFAS 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. We will adopt
SFAS 133 in fiscal 2000.
In March 1998 the American Institute of Certified Public Accountants
issued Statement of Position 98-1 (SOP 98-1), "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." SOP 98-1 provides
guidance on accounting for the costs of computer software developed or
obtained for internal use. We will adopt SOP 98-1 in fiscal 2000.
We do not expect those new pronouncements to have a material effect on
our consolidated financial statements.
Note 2. Impact of Deregulation
Under Georgias Natural Gas Competition and Deregulation Act (the Act), AGLC
elected to unbundle, or separate, the various components of its services to its
customers. As a result, numerous changes have occurred with respect to the
services being offered by AGLC and with respect to the manner in which AGLC
prices and accounts for those services. Consequently, AGLC's future
expenses and revenues will not follow the same pattern as they have
historically.
Pursuant to the Act, regulated rates ended on October 6, 1998, for natural gas
commodity sales to AGLC customers. Consequently, AGLC will no longer defer
any over-recoveries or under-recoveries of gas costs and will refund to
customers the over-recovery that existed when the purchased gas adjustment
provisions were deregulated.
Going forward, AGLC intends to design its prices for deregulated gas sales
in a manner that, at a minimum, will allow it to recover its annual gas costs.
Accordingly, substantial changes to future quarterly statements of income
are expected from this new regulatory approach. AGLC intends to recover all
its gas costs through the prices it will establish such that on an annual
basis it recovers, at a minimum, the actual costs of acquiring gas supplies
for sales services.
As part of the GPSC's rate case ruling, AGLC began billing customers on
Therefore, total distribution rates were typically lower in the summer when
customers used less gas, and higher in the winter when customers used more gas.
Going forward, AGLC will collect such rates evenly throughout the year
regardless of volumetric summer and winter differences in gas usage.
In addition, there are other AGLC revenues that reflect costs associated
with services deemed ancillary to distribution service that will change as
customers select a marketer for sales service. For example, as customers choose
a marketer, the associated revenues to AGLC for billing, billing inquiries,
payment collection, payment processing, and possibly meter reading will
decrease if those services are provided by the marketer. The regulatory
provisions provide for a reduction in the revenues associated with those
services as AGLC has the opportunity to avoid such future costs.
Consequently, those provisions will reduce some of the regulated revenue and
associated expenses for AGLC.
Note 3. Income Taxes
Income Tax Expense
We have two categories of income taxes in our Statements of Consolidated Income:
current and deferred. Our current income tax expense consists of regular tax
less applicable tax credits. Our deferred income tax expense generally is
equal to the changes in the deferred income tax liability during the year.
Investment Tax Credits
We have deferred investment tax credits associated with our utility as a
regulatory liability in our Consolidated Balance Sheets. (See Note 4 in Notes
to Consolidated Financial Statements.) Those investment tax credits are
being amortized as credits to income in accordance with regulatory treatment
over the estimated life of the related properties. We reduce income tax
expense in our Statements of Consolidated Income for the investment tax credits
and other tax credits associated with our nonutility subsidiaries.
Deferred Income Tax Assets and Liabilities
We must report some of our assets and liabilities differently for financial
accounting purposes than we do for income tax purposes. The tax effects of the
differences in those items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect. Because of
the regulated nature of the utility's business, a regulatory tax liability has
been recorded in accordance with Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes." The regulatory tax liability is being
amortized over approximately 30 years. (See Note 4 in Notes to Consolidated
Financial Statements.)
Components of income tax expense shown in the Statements of Consolidated Income
are as follows:
___________________________________
Millions of dollars 1998 1997 1996
- ----------------------------------------------------------------------
Included in expenses:
Current income taxes
Federal $25.3 $24.2 $20.3
State 3.6 5.5 3.0
Deferred income taxes
Federal 9.7 16.7 21.6
State 1.6 1.8 4.1
Amortization of investment
tax credits (1.4) (1.4) (1.5)
- ----------------------------------------------------------------------
Total $38.8 $46.8 $47.5
______________________________________________________________________
Reconciliation between the statutory federal income tax rate and the effective
rate is as follows:
_________________________
Millions of dollars 1998
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $41.8 35.0
State income tax, net of federal
income tax benefit 3.5 2.9
Amortization of investment tax credits (1.4) (1.2)
Adjustment of prior year's income taxes (2.3) (1.9)
Other - net (2.8) (2.3)
- ----------------------------------------------------------------------
Total income tax expense $38.8 32.5
______________________________________________________________________
_________________________
Millions of dollars 1997
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $43.2 35.0
State income tax, net of federal
income tax benefit 4.5 3.7
Amortization of investment tax credits (1.4) (1.1)
Other - net .5 .4
- ----------------------------------------------------------------------
Total income tax expense $46.8 38.0
______________________________________________________________________
_________________________
Millions of dollars 1996
- ----------------------------------------------------------------------
% of Pretax
Amount Income
- ----------------------------------------------------------------------
Computed tax expense $43.1 35.0
State income tax, net of federal
income tax benefit 4.3 3.5
Amortization of investment tax credits (1.5) (1.2)
Other - net 1.6 1.3
- ----------------------------------------------------------------------
Total income tax expense $47.5 38.6
______________________________________________________________________
Components that give rise to the net deferred income tax liability as of
September 30 are as follows:
____________________
Millions of dollars 1998 1997
- ----------------------------------------------------------------------
Deferred tax liabilities:
Property - accelerated depreciation and
other property-related items $221.9 $206.8
Other 19.1 18.5
- ----------------------------------------------------------------------
Total deferred tax liabilities 241.0 225.3
- ----------------------------------------------------------------------
Deferred tax assets:
Deferred investment tax credits $ 10.0 $ 10.6
Other 28.0 23.0
- ----------------------------------------------------------------------
Total deferred tax assets 38.0 33.6
- ----------------------------------------------------------------------
Net deferred tax liability $203.0 $191.7
______________________________________________________________________
Note 4. Regulatory Assets and Liabilities
As discussed in Note 1, the GPSC and the TRA regulate our utility business. We
generally use the same accounting policies and practices nonregulated
companies use for financial reporting under generally accepted accounting
principles. However, sometimes the GPSC and the TRA order an accounting
treatment different from that used by nonregulated companies to determine
the rates we charge our customers. When that happens, we must defer certain
utility expenses and income in our Consolidated Balance Sheets as
regulatory assets and liabilities. We then record them in our Statements
of Consolidated Income (using amortization) when we include them in the
rates we charge our customers.
We have recorded regulatory assets and liabilities in our Consolidated
Balance Sheets in accordance with Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71).
In July 1997, the Emerging Issues Task Force (EITF) concluded that once
legislation is passed to deregulate a segment of a utility and that legislation
includes sufficient detail for the enterprise to determine how the transition
plan will affect that segment, SFAS 71 should be discontinued for that segment
of the utility. The EITF consensus permits assets and liabilities of a
deregulated segment to be retained if they are recoverable through a segment
that remains regulated.
Georgia has enacted legislation, the Act, which allows deregulation of
natural gas sales and the separation of some ancillary services of local
natural gas distribution companies. However, the rates local gas distribution
companies charge to transport natural gas through their intrastate pipe
system will continue to be regulated by the GPSC. Therefore, we have
concluded that the continued application of SFAS 71 remains appropriate. The
remaining regulatory liability associated with the deregulated gas function
will be refunded.
We summarize our regulatory assets and liabilities in the following
table (in millions):
_________________________
At September 30, 1998 1997
- ----------------------------------------------------------------------
Assets:
Unrecovered environmental response costs $77.6 $55.0
Unrecovered postretirement benefits costs 9.3 10.0
Deferred purchased gas adjustment 8.5
Other 7.9 4.2
- ---------------------------------------------------------------------
Total $94.8 $77.7
- ---------------------------------------------------------------------
Liabilities:
Unamortized investment tax credit $25.8 $27.3
Deferred purchased gas adjustment 8.9
Regulatory tax liability 17.3 18.3
Environmental response cost recoveries
from third parties - customer portion 9.5 10.1
Environmental response cost recoveries
from third parties - deferred company
portion 4.8 6.1
Other 2.2 3.7
- ----------------------------------------------------------------------
Total $68.5 $65.5
______________________________________________________________________
Note 5. Employee Benefit Plans and Stock-Based Compensation Plans
Substantially all AGL Resources employees are eligible to participate in the
company's employee benefit plans.
Pension Benefits
AGL Resources sponsors a defined benefit retirement plan for its employees.
A defined benefit plan specifies the amount of benefits an eligible plan
participant eventually will receive using information about the participant.
We generally calculate the benefits under that plan based on age, years of
service, and pay. Our employees do not contribute to that plan.
Sometimes we amend the plan retroactively. Retroactive plan amendments require
us to recalculate benefits related to participants' past service. We amortize
the change in the benefit costs from those plan amendments on a straight-line
basis over the average remaining service period of active employees. We fund
the plan by contributing annually the amount required by applicable regulations
and recommended by our actuary. We calculate the amount of funding using an
actuarial method called the projected unit credit cost method. The plan's assets
consist primarily of marketable securities, corporate obligations, U.S.
government obligations, insurance contracts, mutual funds, and cash
equivalents.
AGL Resources has an excess benefit plan that is unfunded and provides
supplemental benefits to some officers after retirement. In September 1994
we established a voluntary early retirement plan for some AGL Resources
officers 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.
We show the components of total net pension cost in the following table:
______________________________________
Millions of dollars 1998 1997 1996
- -----------------------------------------------------------------------------
Service cost $ 4.6 $ 4.0 $ 4.0
Interest cost 16.6 16.2 15.8
Actual return on assets (32.0) (30.6) (19.3)
Net amortization and deferral 16.2 16.9 6.3
- ----------------------------------------------------------------------------
Net periodic pension cost $ 5.4 $ 6.5 $ 6.8
- ----------------------------------------------------------------------------
Actuarial assumptions used include:
Discount rate 7.5% 7.5% 7.8%
Rate of increase in compensation
levels 4.5% 4.5% 4.5%
Expected long-term rate of return
on assets 8.3% 8.3% 8.3%
____________________________________________________________________________
We show the funded status of the plan in the following table:
____________________
Millions of dollars 1998 1997
- ---------------------------------------------------------------------------
Actuarial present value of benefit obligations
Vested benefit obligation $ 202.1 $ 187.2
- ---------------------------------------------------------------------------
Accumulated benefit obligation $ 206.2 $ 190.5
- ---------------------------------------------------------------------------
Projected benefit obligation $(242.8) $(223.8)
Plan assets at fair value 229.5 212.1
- ---------------------------------------------------------------------------
Plan assets less than projected benefit
obligation (13.3) (11.7)
Unrecognized net loss 11.0 15.1
Remaining unrecognized net assets at date
of initial adoption (3.0) (3.7)
Unrecognized prior service cost 3.1 3.5
- ---------------------------------------------------------------------------
Prepaid (accrued) pension costs $ (2.2) $ 3.2
___________________________________________________________________________
Employee Savings Plan Benefits
AGL Resources also sponsors the Retirement Savings Plus Plan, a defined
contribution benefit plan. In a defined contribution benefit plan, the benefits
a participant ultimately receives come from regular contributions to a
participant account. Under the Retirement Savings Plus Plan, we made matching
contributions to participant accounts in the following amounts:
- - $3.5 million in fiscal 1998;
- - $3.3 million in fiscal 1997; and
- - $3.2 million in fiscal 1996.
AGL Resources' Nonqualified Savings Plan, an unfunded, nonqualified plan
similar to the defined contribution savings plan described above, was
established on July 1, 1995. The Nonqualified Savings Plan provides an
opportunity for eligible employees to contribute for retirement savings. Our
contributions to the Nonqualified Savings Plan during fiscal years 1998, 1997,
and 1996 were not significant.
Employee Stock Ownership Benefits
AGL Resources' Leveraged Employee Stock Ownership Plan (LESOP) provides eligible
employees with another source of retirement income, while enabling them to be
AGL Resources shareholders.
In January 1988 we purchased 2 million shares of common stock for $11.75 per
share with the proceeds of a loan secured by the common stock. We did not
guarantee the repayment of the loan. The loan was repaid from regular cash
dividends on our common stock paid to the LESOP and from contributions to the
LESOP, as approved by our Board of Directors. Repayment of the loan was
completed December 31, 1997. Contributions to the LESOP were as follows:
- - $.2 million for fiscal 1998;
- - $.9 million for fiscal 1997; and
- - $.7 million for fiscal 1996.
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans,
which cover nearly all employees if they reach retirement age while working for
AGL Resources. We generally calculate the benefits under those plans based on
age and years of service.
Some retirees contribute a portion of health care plan costs. Retirees do not
contribute toward the cost of the life insurance plan.
Effective October 1, 1993, we adopted Statement of Financial Accounting
Standards No. 106, "Employer's Accounting for Postretirement Benefits Other Than
Pensions," which requires accrual of postretirement benefits other than pensions
during the years an employee provides service. In 1993 the GPSC approved a
five-year phase-in that defers a portion of other postretirement benefits
expense for future recovery. A regulatory asset has been recorded for that
amount. In 1993 the TRA approved the recovery of other postretirement benefits
expense that is funded through an external trust.
We show the components of net periodic postretirement benefits costs in the
following table:
___________________________________
Millions of dollars 1998 1997 1996
- ---------------------------------------------------------------------------
Service cost $ .9 $ .8 $ .8
Interest cost 7.6 8.0 8.8
Actual return on assets (1.5) (1.0) (.6)
Amortization of transition obligation 3.6 3.8 4.2
- ---------------------------------------------------------------------------
Net postretirement benefits costs $ 10.6 $ 11.6 $ 13.2
___________________________________________________________________________
Net periodic postretirement benefits costs were recovered from utility
customers as follows:
- - $11.3 million in fiscal 1998;
- - $11.3 million in fiscal 1997; and
- - $10.7 million in fiscal 1996.
The difference between our total net postretirement benefits costs and the
associated costs recovered from our utility customers of $.3 million in 1997
and $2.5 million in fiscal 1996 was deferred for future recovery through
amortization and recognized as regulatory assets in the financial statements
consistent with regulatory decisions. The $.7 million difference in fiscal
1998 represents the amortization of the regulatory asset.
The following schedule sets forth the plan's funded status as of September 30,
1998 and 1997:
___________________________
Millions of dollars 1998 1997
- ------------------------------------------------------------------------
Retirees $ 81.5 $ 82.2
Fully eligible active plan participants 7.1 6.4
Other active plan participants 16.2 14.8
- ------------------------------------------------------------------------
Total accumulated postretirement benefit
obligation 104.8 103.4
Plan assets at fair value 23.6 17.9
- ------------------------------------------------------------------------
Accumulated postretirement benefit
obligation in excess of plan assets 81.2 85.5
Unrecognized transition obligation (61.3) (65.5)
Unrecognized gain 13.5 14.3
- ------------------------------------------------------------------------
Accrued postretirement benefits costs $ 33.4 $ 34.3
________________________________________________________________________
Assumptions For purposes of measuring the accumulated postretirement benefit
obligation, the assumed health care inflation rate for pre-Medicare eligibility
is as follows:
- - 10.0% in 1998, decreasing .5% per year to 6.0% in the year 2006, decreasing
.25% to 5.75% in 2007, and decreasing .5% to 5.25% in 2008.
The assumed health care inflation rate for post-Medicare eligibility is as
follows:
- - 8.5% in 1998, decreasing .5% per year to 5.5% in the year 2004, decreasing
.25% to 5.25% in 2005, and decreasing .25% to 5.0% in 2006.
Increasing the assumed health care inflation rate by 1% would increase the
accumulated postretirement benefit obligation by approximately $4.2 million as
of September 30, 1998, and increase the accrued postretirement benefits cost by
approximately $.3 million for fiscal 1998.
The assumed discount rate used in determining the postretirement benefit
obligation was as follows:
- - 7.0% in 1998;
- - 7.5% in 1997; and
- - 7.75% in 1996.
Stock-Based Compensation Plans
AGL Resources' Long-Term Stock Incentive Plan (LTSIP) provides for grants of
restricted stock awards, incentive and nonqualified stock options, and stock
appreciation rights to key employees. The LTSIP currently authorizes issuance of
up to 3.2 million shares of our common stock. In addition, we maintain AGL
Resources' Non-Employee Directors Equity Compensation Plan (Directors Plan) in
which all non-employee directors participate. The Directors Plan currently
authorizes the issuance of up to 200,000 shares of common stock. Key employees
and non-employee directors realize value from option grants only to the extent
that the fair market value of the common stock of AGL Resources on the date of
exercise of the option exceeds the fair market value of the common stock on the
date of grant.
LTSIP Stock Awards
Stock awards generally are subject to some vesting restrictions. We recognize
compensation expense for those stock awards over the related vesting periods.
We awarded shares of stock to key employees in the following amounts:
- - 41,424 shares in fiscal 1998;
- - 31,863 shares in fiscal 1997; and
- - 7,249 shares in fiscal 1996.
At the date of the award, the weighted average fair value of the
shares was as follows:
- - $19.890 in fiscal 1998;
- - $20.125 in fiscal 1997; and
- - $19.758 in fiscal 1996.
LTSIP Incentive and Nonqualified Stock Options
Incentive and nonqualified stock options are granted at the fair market value
on the date of grant. The vesting of incentive options is subject to a
statutory limitation of $100,000 per year under Section 422A of the Internal
Revenue Code. Otherwise, nonqualified options become fully exercisable six
months after the date of grant and generally expire 10 years after that date.
A summary of activity related to grants of incentive and nonqualified stock
options follows:
_________________________________________
Number of Weighted Average
Options Excercise Price
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1995 849,160 $ 17.18
Granted 299,340 19.40
Exercised (109,980) 17.24
Forfeited (27,176) 19.49
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1996 1,011,344 $ 17.77
- -----------------------------------------------------------------------
Granted 510,119 $ 20.17
Exercised (104,520) 16.70
Forfeited (28,169) 19.76
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1997 1,388,774 $ 18.69
- -----------------------------------------------------------------------
Granted 810,572 19.90
Exercised (68,684) 16.95
Forfeited (51,867) 20.11
- -----------------------------------------------------------------------
Outstanding - Sept. 30, 1998 2,078,795 $ 19.19
_______________________________________________________________________
Information about outstanding and exercisable options as of September 30, 1998,
follows:
_____________________________________________________ _________________________________
Options Outstanding Options Exercisable
_____________________________________________________ _________________________________
Weighted Average
Remaining Weighted Weighted
Contractual Life Average Average
Range of Exercise Prices Number of Options (in years) Exercise Price Number of Options Exercise Price
- ------------------------------------------------------------------------------------------------------------------------------
$13.75 to $17.44 299,730 4.8 $15.88 299,730 $15.88
$18.13 to $19.81 815,138 6.9 $19.23 755,138 $19.26
$20.00 to $22.06 963,927 8.2 $20.18 953,713 $20.16
- ------------------------------------------------------------------------------------------------------------------------------
$13.75 to $22.06 2,078,795 7.2 $19.19 2,008,581 $19.18
______________________________________________________________________________________________________________________________
A summary of outstanding options that are fully exercisable follows:
___________________________________
Number of Weighted Average
Options Exercise Price
- -----------------------------------------------------------------------
Exercisable - September 30, 1996 1,006,166 $17.76
Exercisable - September 30, 1997 1,384,125 $18.69
Exercisable - September 30, 1998 2,008,581 $19.18
_______________________________________________________________________
We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for our stock
option plans. Accordingly, no compensation expense has been recognized in
connection with our LTSIP option grants. If we had determined compensation
expense for the issuance of options based on the fair value method described
in SFAS No. 123, "Accounting for Stock-Based Compensation," our net income and
earnings per share would have been reduced to the pro forma amounts presented
below:
___________________________________________
For the years ended Sept. 30, 1998 1997 1996
- -------------------------------------------------------------------------------
Net income-as reported (millions) $80.6 $76.6 $75.6
Net income-pro forma (millions) $79.4 $75.6 $75.2
Basic earnings per share-as reported $1.41 $1.37 $1.37
Basic earnings per share-pro forma $1.39 $1.35 $1.36
Diluted earnings per share-as reported $1.41 $1.36 $1.36
Diluted earnings per share-pro forma $1.39 $1.35 $1.36
_______________________________________________________________________________
In accordance with the fair value method of determining compensation expense,
the weighted average grant date fair value per share of options granted was as
follows:
- - $2.55 in fiscal 1998;
- - $2.93 in fiscal 1997; and
- - $2.34 in fiscal 1996.
We used the Black-Scholes pricing model to estimate the fair value of each
option granted with the following weighted average assumptions:
__________________________________
For the years ended Sept. 30, 1998 1997 1996
- ---------------------------------------------------------------------
Expected life (years) 7 7 7
Interest rate 5.5% 6.3% 5.5%
Volatility 17.8% 17.1% 16.5%
Dividend yield 5.5% 5.3% 5.4%
_____________________________________________________________________
Non-Employee Directors Equity Compensation Plan (Directors Plan)
Under the Directors Plan, each non-employee director receives an annual grant
of:
- - a stock award equal to the fair market value of the $16,000 annual retainer,
which is payable to each director; and
- - a nonqualified stock option to purchase the same number of shares of common
stock as the annual stock award.
Nonqualified stock options are granted at the fair market market value on the
date of grant. Options generally expire 10 years after the date of grant.
Non-employee directors were granted options to purchase an aggregate of the
following:
- - 7,980 shares in fiscal 1998;
- - 7,960 shares in fiscal 1997; and
- - 9,306 shares in fiscal 1996.
Note 6. Common Stock
Shareholder Rights Plan
On March 6, 1996, AGL Resources' Board of Directors adopted a Shareholder Rights
Plan. The plan contains provisions to protect AGL Resources' shareholders in the
event of unsolicited offers to acquire AGL Resources or other takeover bids and
practices that could impair the ability of the Board of Directors to represent
shareholders' interests fully. As required by the Shareholder Rights Plan, the
Board of Directors declared a dividend of one preferred share purchase right (a
"Right") for each outstanding share of AGL Resources' common stock, with
distribution made to shareholders of record on March 22, 1996.
The Rights, which will expire March 6, 2006, initially will be
represented by, and traded together with, AGL Resources common stock. The Rights
are not currently exercisable and do not become exercisable unless some
triggering events occur. One of the triggering events is the acquisition of 10%
or more of AGL Resources' common stock by a person or group of affiliated or
associated persons. Unless previously redeemed, upon the occurrence of one of
the specified triggering events, each Right will entitle its holder to purchase
one one-hundredth of a share of Class A Junior Participating Preferred Stock at
a purchase price of $60. Each preferred share will have 100 votes, voting
together with the common stock. Because of the nature of the preferred shares'
dividend, liquidation and voting rights, one one-hundredth of a share of
preferred stock is intended to have the value, rights, and preferences of one
share of common stock. As of September 30, 1998, 1 million shares of Class A
Junior Participating Preferred Stock were reserved for issuance under that plan.
Stock Split
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.
All references to number of shares and to per share amounts have been restated
retroactively to reflect the stock dividend.
Other
AGL Resources issued the following:
- - 739,380 shares of its common stock in fiscal 1998;
- - 753,866 shares of its common stock in fiscal 1997; and
- - 792,919 shares of its common stock in fiscal 1996
under ResourcesDirect, a stock purchase and dividend reinvestment plan; the
Retirement Savings Plus Plan; the Long-Term Stock Incentive Plan; the
Nonqualified Savings Plan; and the Non-Employee Directors Equity Compensation
Plan.
As of September 30, 1998, 7,295,993 shares of common stock were reserved
for issuance pursuant to ResourcesDirect, the Retirement Savings Plus Plan, the
Long-Term Stock Incentive Plan, the Nonqualified Savings Plan, and the
Non-Employee Directors Equity Compensation Plan.
Note 7. Preferred Stock
Subsidiary Obligated Mandatorily Redeemable Preferred Securities
(Capital Securities)
In June 1997 we established AGL Capital Trust (the Trust), a Delaware business
trust, and we own all the common voting securities. The Trust issued and sold
$75 million principal amount of 8.17% Capital Securities (liquidation amount
$1,000 per Capital Security) to certain initial investors. The Trust used the
proceeds to purchase 8.17% Junior Sub-ordinated Deferrable Interest Debentures,
which are due June 1, 2037, from AGL Resources.
The Capital Securities are subject to mandatory redemption at the time
of the repayment of the Junior Subordinated Debentures on June 1, 2037, or the
optional prepayment by AGL Resources after May 31, 2007.
We fully and unconditionally guarantee all the Trust's obligations for the
Capital Securities. We used the net proceeds of approximately $74 million
from the sale of the Junior Subordinated Debentures to repay short-term debt,
to redeem some of AGLC's outstanding issues of preferred stock, and for
other corporate purposes.
Other Preferred Securities
As of September 30, 1998, AGL Resources had 10 million shares of
authorized, but unissued, Class A Junior Participating Preferred Stock,
no par value; and 10 million shares of authorized, but unissued,
preferred stock, no par value. As of September 30, 1998, AGLC had 10
million shares of authorized, but unissued, preferred stock, no par
value.
On August 15, 1997, AGLC redeemed the following
- - 4.5% Cumulative Preferred Stock;
- - 4.72% Cumulative Preferred Stock;
- - 5% Cumulative Preferred Stock;
- - 7.84% Cumulative Preferred Stock; and
- - 8.32% Cumulative Preferred Stock.
Those issues of preferred stock were redeemed at the call price in effect for
each issue, for a total of $14.7 million. They have been retired in full.
On December 1, 1997, AGLC redeemed its 7.70% Series depositary preferred
stock at the redemption price of $100 per share. That issue of preferred stock
has been retired in full.
Note 8. Long-Term Debt
Long-term debt matures more than one year from the date of the financial
statements. 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
parity with all other unsecured indebtedness. During 1997 the remaining $105.5
million in principal amount of such notes was issued, with maturity dates
ranging from 20 to 30 years and with interest rates ranging from 6.55% to 7.3%.
Net proceeds from the issuance of medium-term notes were used to fund capital
expenditures, repay short-term debt, and for other corporate purposes. The
annual maturities of long-term debt for the five-year period ending September
30, 2003, are as follows:
- - $50 million in fiscal 2000;
- - $20 million in fiscal 2001;
- - $45 million in fiscal 2002; and
- - $48 million in fiscal 2003.
The outstanding long-term debt as of September 30 is as follows:
________________________
Millions of dollars 1998 1997
- -----------------------------------------------------------
Medium-term notes
Series A(1) $ 60.0 $ 60.0
Series B(2) 300.0 300.0
Series C(3) 300.0 300.0
- -----------------------------------------------------------
Total $660.0 $660.0
___________________________________________________________
(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 7.30% with maturity dates from 2004 to 2027.
Note 9. Short-Term Debt
Short-term debt matures within one year from the date of the financial
statements. 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 $240 million in the summer months to $290 million for peak
winter financing. Certain of the lines are on a commitment-fee basis. As of
September 30, 1998, $165 million was available on lines of credit.
__________________________________
Millions of dollars 1998 1997 1996
- --------------------------------------------------------------------------
Maximum amounts of short-term debt
outstanding at any month end
during the year $ 149.0 $ 189.0 $ 156.3
- --------------------------------------------------------------------------
Weighted average interest rates
Short-term debt outstanding at end
of year 5.8% 5.9% 5.7%
__________________________________________________________________________
Note 10. Commitments and Contingencies
Agreements for Firm Pipeline and Storage Capacity
In connection with its utility business, AGL Resources has agreements for firm
pipeline and storage capacity that expire at various dates through 2014. The
aggregate amount of required payments under such agreements totals
approximately $1.3 billion, with annual required payments of $221 million in
fiscal 1999, $221 million in fiscal 2000, $203 million in fiscal 2001,
$181 million in fiscal 2002, and $77 million in fiscal 2003. Total payments
of fixed charges under all agreements were $220 million in fiscal 1998,
$215 million in fiscal 1997, and $225 million in fiscal 1996. The purchased
gas adjustment provisions of the utilitys rate schedules have permitted
the recovery of these gas costs from customers. As a result of the Act, AGLC's
rights to capacity under the purchase agreements will be assigned to
certificated marketers as they acquire firm customers. Marketers will be
responsible for payment of the fixed charges associated with the assignments.
FERC Order 636: Transition Costs Settlement Agreements
The utility purchases natural gas transportation and storage services from
interstate pipeline companies, and the Federal Energy Regulatory Commission
(FERC) regulates those services and the rates the interstate pipeline companies
charge it. During the past decade, the FERC has transformed dramatically the
natural gas industry through a series of generic orders promoting competition in
the industry. As part of that transformation, the interstate pipelines that
serve the utility have been required to -
- - unbundle, or separate, their transportation and gas supply services, and
- - provide a separate transportation service on a nondiscriminatory basis for
the gas that is supplied by numerous gas producers or other third parties.
The FERC is considering further revisions to its rules, including the
following:
- - its policies governing secondary market transactions; and
- - revisions that would permit pipelines and their customers to establish
individually negotiated terms and conditions of service that depart
from generally applicable pipeline tariff rules.
The utility cannot predict whether those changes will be adopted or how they
potentially might affect it.
The FERC has required the utility, as well as other interstate pipeline
customers, to pay transition costs associated with the separation of the
suppliers' transportation and gas supply services. Based on its pipeline
suppliers' filings with the FERC, the utility estimates the total portion of its
transition costs from all its pipeline suppliers will be approximately $106.2
million. As of September 30, 1998, approximately $97.8 million of those costs
has been incurred and is being recovered from the utility's customers under the
purchased gas provisions of its rate schedules. Going forward, AGLC will
recover the majority of the remaining costs through its gas sales. A small
portion of the costs will be recovered from certificated marketers as
part of the assignment process under its unbundling plan.
The largest portion of the transition costs the utility must pay consists of
gas supply realignment costs that Southern Natural Gas Company (Southern)
and Tennessee Gas Pipeline Company (Tennessee) bill the utility. The utility
and other parties have entered restructuring settlements with Southern and
Tennessee that resolve all transition cost issues for those pipelines.
Under the Southern settlement, the utility's share of Southern's transition
costs is about $88 million, of which the utility incurred $84.5 million as of
September 30, 1998. Under the Tennessee settlement, the utility's share of
Tennessee's transition costs is about $14.7 million, of which the utility
incurred $10 million as of September 30, 1998.
Collective Bargaining Agreements
On September 30, 1998, AGL Resources and its subsidiaries had 2,791 employees.
Of that total, approximately 702 employees are covered under collective
bargaining agreements. Those agreements provided for a $500 lump sum payment
to each bargaining unit employee in 1998. Based on current pay levels,
it is anticipated that the majority of bargaining unit employees will not
receive any base pay increases until 1999. The collective bargaining
agreements expire in 2000 and 2001.
Rental Expense
Total rental expense for property and equipment was as follows:
- - $7.7 million in fiscal 1998;
- - $6.5 million in fiscal 1997; and
- - $7 million in fiscal 1996.
Minimum annual rentals under noncancelable operating leases are as follows:
- - fiscal 1999 - $8.9 million;
- - fiscal 2000 - $8.6 million;
- - fiscal 2001 - $8.8 million;
- - fiscal 2002 - $8.6 million;
- - fiscal 2003 - $6.1 million; and
- - thereafter - $6.5 million.
On October 14, 1998, AGL Resources entered into an arrangement to sublease
certain corporate office space, the term of which will begin on December 1,
1998, and will expire on January 3, 2003. The original lease is an operating
lease. Annual sublease rental receipts are as follows:
- - fiscal 1999 - $.9 million;
- - fiscal 2000 - $1.5 million;
- - fiscal 2001 - $1.5 million;
- - fiscal 2002 - $1.5 million; and
- - fiscal 2003 - $.4 million.
Litigation
We are involved in litigation arising in the normal course of business. (See
Note 12 in Notes to Consolidated Financial Statements regarding Environmental
Matters.) We believe the ultimate resolution of that litigation will not
have a material adverse effect on the consolidated financial statements.
Note 11. Suppliers' Refunds
The utility has received refunds from its interstate natural gas suppliers.
Those refunds are a result of FERC orders that adjust the price of various
pipeline services purchased by the utility from suppliers in prior periods.
Under purchased gas provisions of rate schedules approved by the TRA,
Chattanooga credits the refunds to customers. Under purchased gas provisions of
rate schedules approved by the GPSC, AGLC credited the refunds to customers
until June 30, 1998. Beginning July 1, 1998, and thereafter, the Act requires
AGLC to credit refunds from interstate natural gas suppliers to a universal
service fund. The universal service fund provides a method to fund the recovery
of marketers' uncollectible accounts, and it enables AGLC to expand its
facilities to serve the public interest.
Note 12. Environmental Matters
Before natural gas was available in the Southeast in the early 1930s, AGLC
manufactured gas from coal and other materials. Those manufacturing operations
were known as "manufactured gas plants," or "MGPs." Because of recent
environmental concerns, we are required to investigate possible contamination at
those plants and, if necessary, clean them up.
Through the years AGLC has been associated with twelve MGP sites in
Georgia and three in Florida. Based on investigations to date, we believe that
some cleanup will be likely at most of the sites. In Georgia, the state
Environmental Protection Division supervises the investigation and cleanup of
MGP sites. In Florida, the U.S. Environmental Protection Agency has that
responsibility.
For each of those sites, we estimated our share of the likely costs of
investigation and cleanup. We used the following process to do the estimates:
First, we eliminated the sites where we believe no cleanup or further
investigation is likely to be necessary. Second, we estimated the likely
future cost of investigation and cleanup at each of the remaining sites.
Third, for some sites, we estimated our likely "share" of the costs.
We developed our estimate based on any agreements for cost sharing we have,
the legal principles for sharing costs, our evaluation of other entities'
ability to pay, and other similar factors.
Using that process, we believe our total future cost of investigating and
cleaning up our MGP sites is between $47 million and $81.3 million. Within
the range of $47 million to $81.3 million, we cannot identify a single number
as the "best" estimate. Therefore, we have recorded the lower value, or $47
million, as a liability as of September 30, 1998. As of September 30, 1997,
the liability which we had recorded was $37.3 million. During the year the
liability increased $25.7 million. After making payments of $16.0 million,
related to legal fees and technical support, the net increase in the
liability was $9.7 million. The increase in the liability was based on
revised estimates, which resulted in a corresponding increase in the
unrecovered environmental response cost asset.
We have two ways of recovering investigation and cleanup costs. First,
the GPSC has approved an "Environmental Response Cost Recovery Rider." It allows
us to recover our costs of investigation, testing, cleanup, and litigation.
Because of that rider, we have recorded an asset in the same amount as our
investigation and cleanup liability. The GPSC, however, is conducting hearings
about three aspects of the rider. Depending on how the GPSC rules, our
recoveries under the rider could be affected. If the GPSC were to limit
significantly our recovery under the rider, the results could be material.
The second way we could recover costs is by exercising the legal rights
we believe we have to recover a share of our costs from other corporations and
from insurance companies. We have been actively pursuing those recoveries. In
fiscal 1998, we recovered $1.9 million. As required by the rider, we retained
$.9 million of that amount, and we credited the balance to our customers.
Note 13. Fair Value of Financial Instruments
In the following table, we show the carrying amounts and fair values of
financial instruments included in our Consolidated Balance Sheets as of
September 30, 1998, and 1997.
Carrying Estimated
Millions of dollars Amount Fair Value
1998
Long-term debt including
current portion $660.0 $714.6
Capital Securities 74.3 81.5
1997
Long-term debt including
current portion $660.0 $687.0
Capital Securities 74.3 76.3
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.
* Capital securities - quoted market price and dividend rates for preferred
stock with similar terms.
Considerable judgment is required to develop the fair value estimates;
therefore, the values are not necessarily indicative of the amounts that could
be realized in a current market exchange. The fair value estimates are based on
information available to management as of September 30, 1998. Management is not
aware of any subsequent factors that would affect significantly the estimated
fair value amounts.
Note 14. Joint Ventures and Nonutility Acquisitions
SouthStar Energy Services LLC
In July 1998, AGL Resources formed a venture known as SouthStar Energy Services
LLC (SouthStar). SouthStar was established to sell natural gas, propane, fuel
oil, electricity, and related services to industrial, commercial, and
residential customers in Georgia and the Southeast. SouthStar is a joint venture
among a subsidiary of AGL Resources, Dynegy Hub Services, Inc., a subsidiary of
Dynegy, Inc., and Piedmont Energy Company, a subsidiary of Piedmont Natural Gas
Company. SouthStar filed for certification as a retail marketer with the GPSC on
July 15, 1998, and was approved on October 6, 1998. SouthStar operates in
Georgia under the name "Georgia Natural Gas Services."
Etowah LNG
On December 15, 1997, AGL Resources, through its subsidiary AGL Peaking
Services, and Southern Natural Gas Company, a subsidiary of Sonat Inc., signed
an agreement to construct, own, and operate a new liquefied natural gas peaking
facility, Etowah LNG (Etowah). AGL Peaking Services and Southern each will own
50% of Etowah, the operations of which will be subject to jurisdiction of the
FERC. Etowah is located in Polk County, Georgia.
The proposed plant will connect AGLC's and Southern's pipelines directly.
Etowah will provide natural gas storage and peaking services to AGLC and
other southeastern customers. The new facility will cost approximately
$90 million and will have 2.5 billion cubic feet of natural gas storage
capacity and 300 million cubic feet per day of vaporization capacity.
AGL Resources' affiliates will manage the construction of the facility
and operate it. Southern will provide administrative services.
The companies filed a certificate application with the FERC on April 20,
1998. Subject to receiving timely FERC approval, construction is expected to
begin in early 1999 in order to provide peaking services during the 2001-2002
winter heating season.
Etowah has received subscriptions for peaking services for 71% of its
firm peak-service capacity. The majority of such capacity has been subscribed
for by AGLC pursuant to an agreement between AGLC and Etowah LNG Company LLC.
Under this agreement, AGLC may, until February 15, 1999, terminate its
subscription for capacity if, among other things, it determines that as a result
of GPSC actions or inactions, the subscription for such capacity is not in
AGLC's best interests. Termination by AGLC of its capacity subscription would
not have a material effect on our consolidated financial statements.
Cumberland Pipeline Company
On December 1, 1997, AGL Resources, through its subsidiary AGL Interstate
Pipeline, entered a joint venture with Transcumberland Pipeline Company, a
subsidiary of Transcontinental Gas Pipe Line Corporation (Transco). The joint
venture, Cumberland Pipeline Company (Cumberland), will provide interstate
pipeline services to customers in Georgia and Tennessee.
Initially, the 135-mile pipeline will include existing pipeline
infrastructure owned by the two companies extending from Walton County, Georgia,
to Catoosa County, Georgia. The pipeline is projected to enter service by
November 1, 2000; Cumberland will be positioned to serve AGLC, Chattanooga, and
other markets throughout the eastern Tennessee Valley, northwest Georgia, and
northeast Alabama. Transco and AGL Resources affiliates each will own 50% of
Cumberland, and a Transco affiliate will serve as operator. The companies
announced an open season from March 30, 1998, to May 29, 1998, for nonbinding
subscriptions for capacity on Cumberland, and the project will be submitted to
the FERC for approval during fiscal 1999.
Service from Cumberland was included in the five-year forecast filed
with AGLCs 1999 Gas Supply Plan at the GPSC. In that proceeding, the GPSC
granted a request by East Tennessee Natural Gas Company (East Tennessee) to
establish a separate proceeding to examine AGLC's plans to replace service from
East Tennessee with service from Cumberland. The separate proceeding provides
for two rounds of comments by interested parties, to be filed with the GPSC in
December 1998 and January 1999. Although the GPSC decision may affect
AGLC's plans to contract for service from Cumberland, AGLC cannot predict the
outcome of that proceeding.
Sonat Marketing Company, L.P.
During August 1995 AGLC signed an agreement with Sonat Inc. to form the joint
venture, Sonat Marketing Company, L.P. (Sonat Marketing). Sonat Marketing offers
natural gas sales, transportation, risk management, and storage services in key
natural gas producing and consuming areas of the United States.
AGLC invested $32.6 million for a 35% ownership interest in Sonat
Marketing, which was transferred to AGL Gas Marketing, Inc., a wholly owned
subsidiary of AGL Investments, during the third quarter of fiscal 1996. AGL Gas
Marketing, Inc.'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. Those assets are being
amortized over 10 and 35 years, respectively.
AGL Investments has rights through August 2000 to sell its interest in
Sonat Marketing to Sonat Inc. at a predetermined fixed price, as defined, or for
fair market value at any time.
Sonat Power Marketing, L.P.
AGL Power Services, Inc., a wholly owned subsidiary of AGL Investments, holds a
35% interest in Sonat Power Marketing, L.P., which provides power marketing and
all related services in key market areas throughout the United States. During
fiscal 1996, AGL Power Services, Inc. invested approximately $1 million in
exchange for a 35% ownership interest in the partnership.
Regional Propane Operations
During fiscal 1997 AGL Investments acquired regional propane operations in
northern Alabama, northern Georgia, and eastern Tennessee for approximately
$17.7 million. Those acquisitions are accounted for following the purchase
method of accounting. The excess of the purchase price over the estimated fair
value of the net tangible assets of approximately $5.8 million has been
allocated to goodwill and is being amortized over 40 years.
Note 15. Related Party Transactions
AGL Resources purchased gas totaling $208.2 million in fiscal 1998, $287.9
million in fiscal 1997, and $247.5 million in fiscal 1996 from Sonat Marketing
and its affiliates. AGL Resources had outstanding obligations payable to Sonat
Marketing of $27.4 million as of September 30, 1998, and $32.6 million as
of September 30, 1997.
AGL Resources sold gas totaling $1.9 million in fiscal 1998 to
SouthStar. AGL Resources recognized revenue of $.5 million on services provided
to SouthStar during fiscal 1998. AGL Resources had $2.5 million in accounts
receivable from SouthStar as of September 30, 1998. AGL Resources' purchases
from SouthStar in fiscal 1998 were immaterial.
Note 16. Quarterly Financial Data (Unaudited)
The increase in operating revenues and net income in the quarter ended September
30, 1998, is primarily due to a new rate structure, which recovers nongas costs
evenly throughout the year consistent with the way the costs are incurred. That
rate structure for AGLC's gas distribution service was effective July 1, 1998.
The increase was offset partly by higher operating expenses resulting
principally from noncash, nonrecurring charges of $13.9 million
associated with the impairment of certain assets no longer useful
primarily due to changes in our information systems strategy. (See Note
1 in Notes to Consolidated Financial Statements.) During the quarter ended
September 30, 1998, we reduced our income tax liability for prior years by
$2.3 million.
Quarterly financial data for fiscal 1998 and fiscal 1997 are summarized as
follows:
Millions of dollars,
except per share data Operating Operating
Quarter Ended Revenues Income
1998
December 31, 1997 $402.3 $52.4
March 31, 1998 483.9 83.3
June 30, 1998 247.0 8.8
September 30, 1998 205.4 23.1
1997
December 31, 1996 $379.6 $60.2
March 31, 1997 496.7 89.0
June 30, 1997 216.7 15.1
September 30, 1997 194.6 7.2
Basic Diluted
Earnings Earnings
Net (Loss)Per (Loss) Per
Income Common Common
Quarter Ended (Loss)(a) Share(a) Share(a)
1998
December 31, 1997 $25.7 $.45 $.45
March 31, 1998 45.1 .79 .79
June 30, 1998 (1.2) (.02) (.02)
September 30, 1998 11.0 .19 .19
1997
December 31, 1996 $29.6 $.53 $.53
March 31, 1997 49.0 .88 .87
June 30, 1997 1.4 .03 .03
September 30, 1997 (3.4) (.06) (.06)
(a) The wide variance in quarterly earnings results from the highly seasonal
nature of AGL Resources' primary business.
Basic and diluted earnings per common share are calculated based on the weighted
average number of common shares outstanding and common share equivalents during
the quarter. Those totals differ from the basic and diluted earnings per share,
as shown on the Statements of Consolidated Income, which are based on the
weighted average number of common shares outstanding and common share
equivalents for the entire year.
Independent Auditors' Report
To the Shareholders and Board of Directors of AGL Resources Inc.:
We have audited the accompanying consolidated balance sheets of AGL Resources
Inc. and subsidiaries as of September 30, 1998 and 1997, 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, 1998. These financial
statements are the responsibility of AGL Resource's management. Our
responsibility is to express an opinion on these financial statements 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 consolidated financial statements present fairly, in all
material respects, the financial position of AGL Resources Inc. and subsidiaries
as of September 30, 1998 and 1997, and the results of its operations and its
cash flows for each of the three years in the period ended September 30, 1998,
in conformity with generally accepted accounting principles.
DELOITTE AND TOUCHE LLP
Atlanta, Georgia
November 2, 1998
Management's Responsibility for Financial Reporting
The consolidated financial statements and related information are the
responsibility of management. The financial statements have been prepared in
conformity with generally accepted accounting principles appropriate in the
circumstances. The financial information contained elsewhere in this Annual
Report is consistent with that in the financial statements.
AGL Resources maintains a system of internal accounting controls designed to
provide reasonable assurance that assets are safeguarded from loss and that
transactions are executed and recorded in accordance with established
procedures. The concept of reasonable assurance is based on the recognition that
the cost of maintaining a system of internal accounting controls should not
exceed related benefits. The system of internal accounting controls is
supported by written policies and guidelines.
The financial statements have been audited by Deloitte & Touche LLP, independent
auditors. Their audits were made in accordance with generally
accepted auditing standards, as indicated in the Independent Auditors' Report,
and included a review of the system of internal accounting controls and tests of
transactions to the extent they considered necessary to carry out their
responsibilities.
The Board of Directors pursues its responsibility for reported financial
information through its Audit Committee. The Audit Committee meets
periodically with management and the independent auditors to assure that they
are carrying out their responsibilities and to discuss internal accounting
controls, auditing and financial reporting matters.
Walter M. Higgins J. Michael Riley
President and Senior Vice President and
Chief Executive Officer Chief Financial Officer
November 2, 1998 November 2, 1998
Selected Financial Data
For the years ended September 30,
-------------------------------------------------------------------------------
In millions, except per share amounts 1998 1997 1996 1995 1994 1993
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Income Statement Data
Operating revenues $ 1,338.6 $ 1,287.6 $ 1,228.6 $ 1,068.5 $ 1,199.9 $ 1,130.3
Cost of sales 796.0 766.5 725.5 574.1 736.8 701.0
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Operating margin 542.6 521.1 503.1 494.4 463.1 429.3
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Other operating expenses
Operation 238.1 226.2 221.8 215.5 207.0 187.6
Restructuring costs 70.3
Maintenance 38.4 30.8 29.5 30.4 32.8 30.9
Depreciation 71.1 66.6 63.3 59.0 55.4 58.8
Taxes other than income taxes 27.4 26.0 25.0 25.7 26.0 23.9
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Total other operating expenses 375.0 349.6 339.6 400.9 321.2 301.2
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Operating income 167.6 171.5 163.5 93.5 141.9 128.1
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Other income 12.9 10.3 13.1 1.5 5.2 6.6
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Interest expense and
preferred stock dividends 61.1 58.4 53.5 51.9 52.1 51.0
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Income before income taxes 119.4 123.4 123.1 43.1 95.0 83.7
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Income taxes 38.8 46.8 47.5 16.7 36.3 30.5
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Net income 80.6 76.6 75.6 26.4 58.7 53.2
Common dividends paid 61.5 60.5 58.6 54.2 52.2 51.1
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- -----------------------------------------------------------------------------------------------------------------------------------
Earnings reinvested $ 19.1 $ 16.1 $ 17.0 $ (27.8) $ 6.5 $ 2.1
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Common Stock Data (1)
Weighted average shares outstanding - basic 57.0 56.1 55.3 52.4 50.2 49.2
Weighted average shares outstanding - diluted 57.1 56.2 55.4 52.5 50.3 49.2
Earnings per share - basic $ 1.41 $ 1.37 $ 1.37 $ 0.50 $ 1.17 $ 1.08
Earnings per share - diluted $ 1.41 $ 1.36 $ 1.36 $ 0.50 $ 1.17 $ 1.08
Dividends paid per share $ 1.08 $ 1.08 $ 1.06 $ 1.04 $ 1.04 $ 1.04
Dividend payout ratio 76.6% 78.8% 77.4% 208.0% 88.9% 96.3%
Book value per share (2) $ 11.42 $ 10.99 $ 10.56 $ 10.15 $ 10.20 $ 9.90
Market value per share (3) $ 19.38 $ 18.94 $ 19.13 $ 19.31 $ 15.31 $ 18.81
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Balance Sheet Data (2)
Total assets $ 1,981.8 $ 1,925.5 $ 1,823.1 $ 1,674.6 $ 1,642.9 $ 1,533.0
Long-term liabilities
Accrued environmental response costs $ 47.0 $ 37.3 $ 30.4 $ 28.6 $ 24.3 $ 19.6
Accrued pension costs $ 2.2 $ 4.9 $ 10.3
Accrued postretirement benefits costs $ 33.4 $ 34.3 $ 36.2 $ 30.1 $ 3.6
Deferred credits $ 57.8 $ 62.4 $ 60.9 $ 65.6 $ 66.6 $ 42.3
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Capitalization
Long-term debt
(including current portion) $ 660.0 $ 660.0 $ 554.5 $ 554.5 $ 569.5 $ 500.7
Preferred stock
(including current portion)
Preferred stock of subsidiary 44.5 58.8 58.8 58.8 59.0
Subsidiary obligated mandatorily
redeemable preferred securities 74.3 74.3
Common equity 654.1 622.1 588.3 557.3 518.5 492.0
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Total $ 1,388.4 $ 1,400.9 $ 1,201.6 $ 1,170.6 $ 1,146.8 $ 1,051.7
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Financial Ratios (2)
Capitalization
Long-term debt 47.5% 47.1% 46.1% 47.4% 49.6% 47.6%
Preferred stock of subsidiary 3.2 4.9 5.0 5.2 5.6
Subsidiary obligated mandatorily
redeemable preferred securities 5.4 5.3
Common equity 47.1 44.4 49.0 47.6 45.2 46.8
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Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
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Return on average common equity 12.6% 12.7% 13.2% 4.9% 11.6% 11.0%
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Ratio of earnings to: (4)
Interest charges 3.30 3.46 3.58 1.99 3.08 2.86
Interest charges and
preferred stock dividends 2.94 3.10 3.28 1.83 2.82 2.63
Combined fixed charges and
preferred stock dividends (5) 2.77 2.90 3.08 1.75 2.66 2.49
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<FN>
(1) Adjusted for two-for-one stock splits paid in the form of 100% stock
dividends on December 1, 1995. (2) Year-end.
(3) September 30 closing market price.
(4) Interest charges exclude the debt portion of allowance for funds used during
construction.
(5) Fixed charges consist of interest on short- and long-term debt, other
interest and the estimated interest component of rentals.
</FN>
Gas Sales and Statistics
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For the years ended September 30,
--------------------------------------------------------------------
1998 1997 1996 1995 1994 1993
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Operating Revenues (Millions of Dollars)
Sales of natural gas
Residential $ 775.9 $ 728.5 $ 708.8 $ 610.6 $ 700.7 $ 658.2
Commercial 294.1 290.9 288.8 243.2 285.8 268.1
Industrial 152.6 148.0 178.8 169.4 172.1 154.2
Transportation revenues 34.8 28.5 21.5 23.9 22.6 33.8
Miscellaneous revenues 21.4 20.2 19.7 15.9 18.7 16.0
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Total utility operating revenues 1,278.8 1,216.1 1,217.6 1,063.0 1,199.9 1,130.3
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Other operating revenues 59.8 71.5 11.0 5.5
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Total operating revenues $ 1,338.6 $ 1,287.6 $ 1,228.6 $ 1,068.5 $ 1,199.9 $ 1,130.3
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Utility Throughput
Therms sold (Millions)
Residential 1,084.9 986.1 1,165.4 916.8 1,003.1 1,001.4
Commercial 467.8 455.5 538.2 454.0 478.9 478.5
Industrial 438.1 344.9 449.6 526.0 424.8 388.7
Therms transported 1,310.6 1,014.5 738.7 722.8 697.4 795.6
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Total utility throughput 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
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Average Utility Customers (Thousands)
Residential 1,351.5 1,319.0 1,289.4 1,250.4 1,215.2 1,182.7
Commercial 107.4 104.5 102.5 100.0 98.0 95.7
Industrial 2.6 2.7 2.6 2.6 2.5 2.5
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Total 1,461.5 1,426.2 1,394.5 1,353.0 1,315.7 1,280.9
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Sales, Per Average Residential
Utility Customer
Gas sold (Therms) 803 748 904 733 825 847
Revenue $574.10 $552.00 $550.00 $488.32 $576.61 $556.52
Revenue per therm (cents) 71.5 73.9 60.8 66.6 69.9 65.7
Degree Days - Atlanta Area
30-year normal 2,991 2,991 2,991 2,991 2,991 3,021
Actual 3,078 2,402 3,191 2,121 2,565 2,852
Percentage of actual to 30-year normal 102.9 80.3 106.7 70.9 85.8 94.4
Gas Account (Millions of Therms)
Natural gas purchased 1,459.1 1,323.4 1,632.9 1,406.9 1,453.6 1,629.9
Natural gas withdrawn from storage 604.7 472.4 596.0 520.7 500.3 276.4
Natural gas transported 1,310.8 1,014.5 738.7 722.8 697.4 795.6
- ----------------------------------------------------------------------------------------------------------------------
Total send-out 3,374.6 2,810.3 2,967.6 2,650.4 2,651.3 2,701.9
Less
Unaccounted for 66.2 1.3 60.4 20.4 37.2 29.0
Company use 7.0 8.0 15.3 10.4 9.9 8.7
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Sold and transported
to utility customers 3,301.4 2,801.0 2,891.9 2,619.6 2,604.2 2,664.2
- ----------------------------------------------------------------------------------------------------------------------
Cost of Gas (Millions of Dollars)
Natural gas purchased $ 558.8 $ 532.5 $ 547.1 $ 389.4 $ 550.1 $ 595.7
Natural gas withdrawn from storage 203.7 175.7 171.6 182.4 186.7 105.3
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Cost of gas - utility operations 762.5 708.2 718.7 571.8 736.8 701.0
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Cost of gas - other 33.5 58.3 6.8 2.3
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Total cost of gas $ 796.0 $ 766.5 $ 725.5 $ 574.1 $ 736.8 $ 701.0
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Utility Plant - End of Year
(Millions of Dollars)
Gross plant $ 2,133.5 $ 2,069.1 $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6
Net plant $ 1,452.6 $ 1,420.3 $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9
Gross plant investment per utility
customer (Thousands of Dollars) $ 1.5 $ 1.5 $ 1.4 $ 1.4 $ 1.4 $ 1.4
Capital Expenditures (Millions of Dollars) $ 118.2 $ 147.7 $ 132.5 $ 121.7 $ 122.5 $ 122.2
Gas Mains - Miles of 3" Equivalent 30,753 30,261 29,045 28,520 27,972 27,390
Employees - Average 3,024 2,986 2,942 3,249 3,764 3,764
Average Btu Content of Natural Gas 1,028 1,024 1,024 1,027 1,032 1,027
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