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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1998
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-1483
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WASHINGTON GAS LIGHT COMPANY
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(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0162882
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 H Street, N. W., Washington, D. C. 20080
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (703) 750-4440
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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Common Stock $1.00 par value New York Stock Exchange
Philadelphia Stock Exchange
Preferred Stock, cumulative,
without par value:
$4.25 Series Philadelphia Stock Exchange
$4.36 Convertible Series Philadelphia Stock Exchange
$4.60 Convertible Series Philadelphia Stock Exchange
$4.80 Series Philadelphia Stock Exchange
$5.00 Series Philadelphia Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days, Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
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State the aggregate market value of the voting stock held by non-affiliates of
the registrant. The aggregate market value shall be computed by reference to
the price at which the stock was sold, or the average bid and asked prices of
such stock, as of a specified date within 60 days prior to the date of filing.
$ 1,175,795,506 October 30, 1998
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Market Value Date
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
Common Stock $1.00 par value 46,226,720 November 30, 1998
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Class Number of Shares Date
DOCUMENTS INCORPORATED BY REFERENCES
List hereunder the following documents if incorporated by reference
and the Part of the Form 10-K:
PART I - Annual Report to Shareholders for the fiscal year
ended September 30, 1998.
PART II - Annual Report to Shareholders for the fiscal year
ended September 30, 1998 (Pages 22 through 55).
PART III - Proxy Statement dated January 25, 1999.
PART IV - Form S-7 Registration Statement number 2-53658, filed May 12, 1975,
and Amendment No. 2 thereof, filed June 24, 1975.
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TABLE OF CONTENTS
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PART I
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Page
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Item 1. Business
Subsidiaries........................................................................................... 3
Rate Regulation, Retail Gas Rates and Rate Increases................................................... 4
Competition............................................................................................ 7
Gas Supply and Capacity................................................................................ 12
Environmental Matters.................................................................................. 14
Year 2000.............................................................................................. 16
Other.................................................................................................. 19
Item 2. Properties.............................................................................................. 20
Item 3. Legal Proceedings....................................................................................... 21
Item 4. Submission of Matters to a Vote of Security Holders..................................................... 21
Executive Officers of the Registrant............................................................................ 22
PART II
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Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................................................................... 23
Item 6. Selected Financial Data................................................................................. 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................................................................... 23
Item 7A.Quantitative and Qualitative Disclosures About Market Risk.............................................. 24
Item 8. Financial Statements and Supplementary Data............................................................. 24
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................................................................... 24
PART III
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Item 10. Directors and Executive Officers of the Registrant..................................................... 24
Item 11. Executive Compensation................................................................................. 24
Item 12. Security Ownership of Certain Beneficial Owners and Management......................................... 25
Item 13. Certain Relationships and Related Transactions......................................................... 25
PART IV
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Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................................................................ 25
Report of Independent Public Accountants on Schedule......................................................... 31
Signatures................................................................................................... 33
</TABLE>
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FORWARD-LOOKING STATEMENTS
Certain matters discussed in this report, excluding historical information,
include forward-looking statements. Certain words, such as, but not limited to,
"estimates," "expects," "anticipates," "intends," "believes," and variations of
these words, identify forward-looking statements that involve uncertainties and
risks. Although Washington Gas Light Company (the Company) believes such
forward-looking statements are based on reasonable assumptions, it cannot give
assurance that every objective will be reached. The Company makes such
statements in reliance on the safe harbor protections provided under the Private
Securities Litigation Reform Act of 1995.
As required by such Act, the Company hereby identifies the following important
factors, which are not intended to cover all events, that could cause actual
results to differ materially from any results projected, forecasted, estimated
or budgeted by the Company in forward-looking statements: (1) risks and
uncertainties impacting the Company as a whole primarily related to changes in
general economic conditions in the United States; (2) changes in laws and
regulations to which the Company is subject, including tax, environmental and
employment laws and regulations; (3) the effect of fluctuations in weather from
normal levels; (4) variations in prices of natural gas and competing energy
sources; (5) the Company's ability to develop new markets and product and
service offerings as well as to maintain existing markets and the expenditures
required to develop and provide such products and services; (6) conditions of
the capital markets utilized by the Company to access capital to finance
operations and capital expenditures; (7) improvements in products or services
offered by competitors; (8) the cost and effects of legal and administrative
claims and proceedings against the Company or which may be brought against the
Company; and (9) estimates of future costs or the effect on future operations as
a result of events that could result from the Year 2000 issue described further
herein.
PART I
ITEM 1. BUSINESS
The Company is a public utility that delivers and sells natural gas to
metropolitan Washington, D.C. and adjoining areas in Maryland and Virginia. A
distribution subsidiary serves portions of Virginia and West Virginia. The
Company has been engaged in the gas distribution business for 150 years, having
been originally incorporated by an Act of Congress in 1848. It became a domestic
corporation of the Commonwealth of Virginia in 1953 and a corporation of the
District of Columbia in 1957.
The population of the area served by the Company is estimated to be 4.6 million.
As of September 30, 1998, the Company and its distribution subsidiary served
819,719 customer meters. A listing of meters served and therms delivered as of
and for the twelve months ended September 30, 1998, respectively, by
jurisdiction is shown in the table below. A therm of gas contains 100,000
British Thermal Units of heat, the heat content of approximately 100 cubic feet
of natural gas.
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Therms Delivered
Jurisdiction Meters Served (millions)
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District of Columbia 141,497 320
Maryland 340,701 661
Virginia 334,173 478
West Virginia 3,348 24
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Total 819,719 1,483
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Of the 1,483 million therms delivered in fiscal year 1998, 70% was sold by the
Company and its distribution subsidiary and 30% was delivered to various
customers that acquired their gas from other suppliers. Of the therms sold and
delivered by the Company, 60% was sold to firm residential customers, 33% was
sold to firm commercial and industrial customers and 7% was sold to
interruptible commercial and industrial customers. Interruptible customers must
be capable of using an alternate fuel as a substitute for natural gas when the
Company determines their service must be interrupted to accommodate firm
customers' needs during periods of peak demand. Therms delivered by the parent
company amounted to 96% of the total consolidated deliveries.
SUBSIDIARIES
The Company has four wholly owned active subsidiaries that are described below.
Shenandoah Gas Company (Shenandoah) is engaged in the delivery and sale of
natural gas at retail in the Shenandoah Valley, including Winchester,
Middletown, Strasburg, Stephens City and New Market, Virginia, and Martinsburg,
West Virginia. Deliveries of natural gas for the twelve months ended September
30, 1998 totaled 63 million therms, of which 12% was sold to firm residential
customers, 35% was sold to firm commercial and industrial customers, 28% was
sold to interruptible commercial and industrial customers, and 25% was delivered
to various customers that acquired their gas from other suppliers.
On November 2, 1998, Shenandoah entered into an agreement to sell its natural
gas utility assets located in West Virginia. According to this agreement,
Shenandoah will provide natural gas transportation service through its pipeline
system in Virginia to the purchaser to assure continued natural gas service in
the Eastern Panhandle of West Virginia. Shenandoah will continue to provide
natural gas utility service to its approximately 10,000 customers in the
northern Shenandoah Valley of Virginia. The proposed transaction is subject to
approval by the Public Service Commission of West Virginia (PSC of WVA). The
transportation service to be provided by Shenandoah to the purchaser is subject
to approval by the Federal Energy Regulatory Commission (FERC).
In fiscal year 1998, Shenandoah's natural gas therm deliveries in West Virginia
represented less than two percent of the Company's consolidated natural gas
therm deliveries and less than one percent of associated consolidated revenues.
Shenandoah's West Virginia operations contributed approximately $200,000 (0.3%)
to the Company's fiscal year 1998 net income applicable to common stock. This
represents less than one-half of one cent of basic and diluted earnings per
average common share for fiscal year 1998. Page 53 of the Company's 1998 Annual
Report to Shareholders, which is incorporated by reference into this report,
includes a discussion of the earnings impact of this sale.
Hampshire Gas Company (Hampshire) operates an underground gas storage field in
the vicinity of Augusta, West Virginia on behalf of the Company under a cost of
service tariff regulated by the FERC.
Crab Run Gas Company (Crab Run) is an exploration and production subsidiary
whose assets are being managed by an Oklahoma-based limited partnership. At
September 30, 1998, Crab Run's investment in this partnership was not material.
The Company expects that any additional investments in the partnership will be
minimal.
Washington Gas Resources Corp. (WGR) is a wholly owned subsidiary under which
the Company's unregulated subsidiaries, except Crab Run, are organized. WGR's
subsidiaries, which are described below, are Washington Gas Consumer Services,
Inc., American Combustion, Inc., American Combustion Industries, Inc. and
Washington Gas Energy Services, Inc. (WGES). WGES also has subsidiaries, as
described further below.
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Washington Gas Consumer Services, Inc. offers a program under which it earns
fees for matching customers with finance companies.
On March 25, 1998, WGR acquired a 100% interest in American Combustion, Inc. and
American Combustion Industries, Inc. The two companies are jointly operated
under the name ACI. ACI is a heating, ventilating and air-conditioning
contracting firm serving commercial customers in the Washington, D.C.
metropolitan area. Page 45 of the Company's 1998 Annual Report to Shareholders,
which is incorporated by reference into this report, includes an additional
discussion of the acquisition of these subsidiaries.
Washington Gas Energy Services, Inc.(WGES) is primarily engaged in the sale of
natural gas in competition with unregulated gas marketers and unregulated
subsidiaries of other utility companies. WGES serves nearly 30,000 residential,
commercial and industrial customers both inside and outside the Company's
traditional service territory. WGES holds a power marketing certificate from the
FERC and plans to sell electricity. WGES' subsidiaries are described below.
Washington Gas Energy Systems, Inc. provides commercial energy services,
including the design and renovation of mechanical heating, ventilating and air
conditioning systems.
Brandywood Estates, Inc. (Brandywood) is a general partner, along with a major
developer, in a venture designed to develop 1,600 acres in Prince George's
County, Maryland for sale or lease. This acreage was contributed to the
Brandywood Development Limited Partnership by Brandywood in 1992. In March 1996,
the partnership submitted to Prince George's County a rezoning application for
790 acres of its property. The mixed-use development plan proposes approximately
1,600 homes, 100,000 square feet of retail space and 105,000 square feet of
office space. Final review of the development proposal is presently not expected
until 1999. Brandywood continues to have sole ownership of approximately 1,000
additional acres adjacent to this property that are not being currently
developed or otherwise utilized.
Advanced Marketing Concepts, Inc. previously provided services primarily in the
area of energy-related home improvements. This subsidiary is currently
inactive.
RATE REGULATION, RETAIL GAS RATES AND RATE INCREASES
RATE REGULATION
The Company is regulated by the Public Service Commission of the District of
Columbia (PSC of DC), the Public Service Commission of Maryland (PSC of MD) and
the State Corporation Commission of Virginia (SCC of VA). Shenandoah is
regulated by the SCC of VA and the PSC of WVA. The FERC regulates Hampshire.
The PSC of DC consists of three full-time members who are appointed by the
Mayor and confirmed by the District of Columbia City Council. The term of each
commissioner is four years. There are no limitations on the number of terms
that can be served. There is no statutory suspension period related to rate
requests.
The PSC of MD consists of five full-time members who are appointed by the
Governor and confirmed by the Senate of Maryland. The term of each commissioner
is five years. There are no limitations on the number of terms that can be
served. The Company is required to give 30 days' notice when filing for a rate
increase. The PSC of MD may initially suspend the proposed increase for 150 days
beyond the 30-day notice period and then has the option to extend the suspension
for an additional 30 days. If action has not been taken after 210 days, rates
may be placed into effect subject to refund.
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The SCC of VA consists of three full-time members who are elected by the General
Assembly of Virginia. A commissioner's term is for six years with no limitation
on the number of terms that can be served. An Expedited Rate Case (ERC)
procedure is available which provides that rate increases may take effect 30
days after the filing date. Under the ERC mechanism, the Company may not propose
any changes in accounting policies and the rate of return on common equity
cannot be modified from the rate established in the last fully adjudicated case.
General rate applications may take effect 150 days after the filing. Before new
rates become final, both types of rate increases are subject to refund.
RETAIL GAS RATES
Unbundling Initiatives
Currently, for the majority of its business, the price the Company charges its
customers is based on the combination of the cost it incurs for the natural gas
commodity delivered to the entry point of the Company's distribution system and
the cost it incurs to deliver natural gas from this entry point to the
customers' premises. Although the Company continues to generate the majority of
its revenues from the sale and delivery of natural gas on this combined or
bundled basis, state regulatory and Company initiatives are seeking to separate
or unbundle the sale of the natural gas commodity from the delivery of gas on
the Company's distribution system (delivery service). Margins generated from
delivering customer-owned gas are equivalent to those earned on bundled gas
service. Therefore, the Company does not experience any loss of margins from
customers that choose to purchase their gas from a third-party supplier.
In all of the Company's major jurisdictions, nearly all of its interruptible
customers and certain firm customers have the option of purchasing their gas
from third-party suppliers including the Company's gas-marketing subsidiary,
WGES. The Company continues to charge these customers for delivering gas
through its distribution system. The status of the unbundling programs in the
Company's major jurisdictions as of September 30, 1998 are discussed further in
the Competition section below, under the subsection entitled Unbundling in the
Company's Major Jurisdictions.
As of September 30, 1998, WGES provided third-party supplier gas to
interruptible customers in all of the Company's major jurisdictions and to
various firm customers in the District of Columbia and Maryland. WGES retains
the full amount of margins generated on sales of the natural gas commodity.
Regulated Service to Firm Customers
In the District of Columbia jurisdiction, the firm residential and
non-residential rate schedules are based upon a flat commodity charge for each
therm of gas consumed and a fixed customer charge designed to recover certain
fixed costs. In addition to this two-part rate design, a peak-usage charge is
in place for non-residential firm customers. This charge was established to
send accurate price signals as to the cost of gas to customers during both peak
and non-peak periods. In the Maryland and Virginia jurisdictions, the rate
schedules for firm service are comprised of a fixed customer charge and
declining-block commodity rates. The Company and Shenandoah do not have any
weather normalization mechanisms designed into their rate structures.
The current firm tariff provisions in all of the major jurisdictions of the
Company and Shenandoah contain gas cost recovery mechanisms that provide for
the recovery of the invoice cost of gas applicable to firm customers. Under
these mechanisms, the Company periodically adjusts its rates to firm customers
to reflect increases and decreases in the invoice cost of gas. Moreover, each
of the major jurisdictions in which the Company and Shenandoah operate provides
for an annual reconciliation of gas costs collected from firm customers to the
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invoice cost of gas applicable to firm customers.
Regulated Service to Interruptible Customers
For services provided to interruptible customers, the Company requires that
these customers be capable of using an alternate fuel as a substitute for
natural gas when the Company determines their service must be interrupted to
accommodate firm customers' needs during periods of peak demand. The effect on
net income of changes in delivered volumes and prices to the interruptible
class is minimized by margin-sharing arrangements that are part of the design
of the Company's rates. Under these arrangements, the Company returns a
majority of the margins earned on interruptible gas sales and deliveries to
firm customers after a gross margin threshold is reached or in exchange for the
shift of a portion of the fixed costs of providing service from the
interruptible to the firm class. In Maryland, the Company retains 100% of the
gross margins associated with sales and deliveries to interruptible customers
until the Company has recovered its investment in capital costs associated
therewith. This arrangement has been in effect in Maryland for interruptible
customers added since August 1989.
RATE INCREASES IN THE COMPANY'S MAJOR JURISDICTIONS
District of Columbia
On October 8, 1993, the PSC of DC issued a final order based on a rate increase
requested in December 1992 that approved a $4.7 million increase, or 2.5%, in
annual revenues, effective October 19, 1993. The order, which included an
overall rate of return of 9.86% and a return on common equity of 11.50%,
provided for a phase-in, rather than immediate recognition, of the additional
costs associated with the implementation of Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS No. 106). The incremental costs related to SFAS No. 106
were phased-in over a five-year period that ended September 30, 1998. In each
year of the phase-in, the Company filed for an increase in rates, through
streamlined procedures, to reflect an additional increment of SFAS No. 106
costs in excess of a stipulated pay-as-you-go level. The difference between the
incremental annual amount reflected in rates during the phase-in period and the
full SFAS No. 106 cost was deferred as a regulatory asset. On September 30,
1998, the PSC of DC granted the Company recovery of the regulatory asset
established during the phase-in period over a fifteen-year amortization period
effective October 1, 1998.
On August 1, 1994, the PSC of DC issued an order approving a Stipulation and
Agreement signed by a majority of the parties to a rate case filed in January
1994, providing for a $6.4 million annual increase in revenues, or 3.4%,
effective August 1, 1994. The agreement did not specify a rate of return. The
agreement provided for an increase in the curtailment charge to interruptible
customers during periods of interruption and established the
previously-discussed peak usage charge for non-residential firm customers.
Maryland
On July 29, 1993, the PSC of MD authorized an increase in base rates designed
to collect an additional $10.6 million, or 3.7%, in annual revenues, effective
August 1, 1993. The order resulted from a settlement agreement entered into by
most of the parties to a rate case filed in March 1993. Recovery of SFAS No.
106 costs, which had been included in the Company's request, was not
specifically addressed in the order; however, the amount authorized was
sufficient to cover the costs associated with implementing this standard in the
Company's Maryland jurisdiction. The order also included a revision to the
Company's purchased gas cost recovery mechanism to provide for recovery of
carrying costs on actual storage gas balances and provided for an annual
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increase in revenues of $1.0 million resulting from the modification to, or the
addition of, certain service-related charges. The return on equity indicated in
the order of 11.50% was not utilized to establish rates.
On October 18, 1994, the PSC of MD issued an order approving an unopposed
Stipulation and Agreement signed by a majority of the parties to a rate case
filed in June 1994 and base rates, designed to collect an additional $7.4
million, or 2.4%, annually were placed into effect on December 1, 1994.
Virginia
On September 27, 1994, the Company implemented rates designed to recover an
additional $15.7 million annually, based on a rate case filed in April 1994.
These rates were collected subject to refund. On September 28, 1995, the SCC of
VA issued an order approving an increase in annual revenues of $6.8 million, or
2.7%, effective September 27, 1994. The order included an overall rate of
return of 9.72% and a return on equity of 11.50%. The order allowed the Company
to collect SFAS No. 106 costs in accordance with a generic order of the SCC of
VA. The Company refunded amounts associated with the difference between the
interim rates that were collected subject to refund and the amount approved by
the SCC of VA, with interest, by January 1, 1996.
Page 52 of the Company's 1998 Annual Report to Shareholders, which is
incorporated by reference into this report, includes a discussion of the
conclusions reached in two proceedings in the Company's Virginia jurisdiction
related to the Virginia jurisdictional portion of regulatory assets.
Page 36 of the Company's 1998 Annual Report to Shareholders, which is
incorporated by reference into this report, includes a summary of rate
applications of the parent company.
On August 6, 1995, Shenandoah placed into effect new rates in Virginia designed
to collect an additional $1.2 million in annual revenues, subject to refund,
based on a rate case filed in July 1995. On May 30, 1996, the SCC of VA issued
an order approving an increase in annual revenues of $883,000, effective August
6, 1995. The increase reflected an overall rate of return of 9.51% and a return
on equity of 11.00%. Shenandoah returned, with interest, amounts collected under
interim rates in excess of the amount ultimately granted to customers by
September 1, 1996.
On December 28, 1997, Shenandoah implemented new rates in Virginia designed to
recover an additional $2.3 million annually, based on a rate case filed in
August 1997. On July 16, 1998, the SCC of VA issued an order approving an
increase in annual revenues of $1.4 million, or 6.78%, effective December 28,
1997. The order included an overall rate of return of 9.062% and a return on
equity of 10.70%. Shenandoah refunded amounts associated with the difference
between the interim rates that were collected subject to refund and the amount
approved by the SCC of VA, with interest, by November 1, 1998.
COMPETITION
COMPETITION WITH OTHER FUELS
In its core utility business, the Company faces competition based on its
customers' preferences for its product, natural gas, compared to other energy
products and also in relation to the price of those products. Currently, the
most significant product-side competition is between natural gas and
electricity in the residential market. This portion of the Company's business
currently contributes a substantial amount of the Company's net income. The
Company continues to derive the majority share of the new residential
construction market in its service territory and believes customer preference
for natural gas allows it to maintain its strong presence.
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Currently, the Company generally maintains a price advantage over electricity
in the jurisdictions it serves. However, as discussed further below,
restructuring in both the natural gas and electric industries is leading to
changes in traditional pricing models. As electric utilities restructure their
services, certain functions of their business are expected to move toward
market-based pricing, with third-party providers of electricity participating
in retail markets. Electric restructuring is likely to result in lower
comparative costs for electric service and increased competition for the
Company.
In the interruptible market, where customers must be capable of using a fuel
other than natural gas when demand by the Company's firm customers peaks, fuel
oil is the most significant competing energy alternative. The Company's success
in this market is dependent largely on changes in gas prices versus oil prices.
The price of natural gas, which is developed primarily from domestic sources,
is influenced greatly by the relationship between supply and demand. However,
the price of oil, much of which comes from foreign sources, is impacted greatly
by political events.
NATURAL GAS INDUSTRY RESTRUCTURING AND COMPANY STRATEGY
The natural gas industry, which has traditionally included producers,
interstate pipelines and local distribution companies (LDCs) such as the
Company, has a long history and has undergone many changes since its inception.
Those changes have been the most significant over the past 10 years. The
driving forces behind the changes are customers' and regulators' desires to
promote competition in situations where it is economically beneficial to
consumers.
The restructuring of the natural gas industry generally began at the producer
level with the passage of the Natural Gas Policy Act in 1978, which brought
about a gradual decontrol of the wellhead price of natural gas and allowed for
market-based prices. In the pipeline segment of the industry, FERC Order No.
636 separated the merchant function of selling natural gas from the interstate
transportation and storage services of the pipeline companies in order to
increase competition. As a result of FERC Order No. 636, pipeline companies are
now responsible for providing gas storage and transportation services, and LDCs
have taken on the responsibility and risk of separately obtaining storage and
transportation capacity from pipelines and procuring competitive natural gas
supplies from producers and marketers. Transmission and storage rates charged
by pipelines are still regulated by FERC, but negotiated, market-based rates
are beginning to appear.
Traditionally, as a natural gas utility, the Company has provided a "bundled"
service to customers, including two primary functions:(1) the merchant
function; and (2) the core utility, or delivery function. As the industry has
changed, the Company has changed its view of these functions. The following
discussion describes the merchant and core utility functions as they exist
today, and how the Company expects them to change over time. In addition, the
Company's current plans for energy-related activities are discussed below.
The Merchant Function
Historically, the Company has purchased natural gas for its customers from
producers, and has contracted with interstate pipeline companies to have the
natural gas delivered to the entrance point of its distribution system. Subject
to regulatory prudence reviews, the Company has passed on the costs paid to the
producers and the interstate pipelines directly to its customers, generally
without the Company having any opportunity for profit or any risk of loss.
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The merchant function is the industry segment currently experiencing the
greatest change. Customers in many states are being offered the opportunity to
purchase their natural gas from unregulated marketers as well as from their
regulated local distribution company. As discussed further below, in the
Company's major jurisdictions, state regulatory and Company initiatives have
culminated in customer choice programs covering nearly all customer classes.
Under these programs, unregulated gas marketers compete for natural gas sales
to customers and have the opportunity to make a profit or incur a loss from
them. One of the Company's subsidiaries, WGES, is an unregulated gas marketer.
The separating or unbundling of the merchant function from the core utility or
delivery function allows unregulated marketers and unregulated marketing
subsidiaries of other utility companies to gain access to the Company's
customers. In addition, price competition among the Company and gas marketers
for the sale of the natural gas commodity has become more prevalent. It is
expected that natural gas prices charged to customers will tend to decline as a
result of this competition.
Ultimately, the Company expects regulated LDCs to play a much smaller role in
the merchant function. The Company may ultimately exit the merchant function as
more customers buy natural gas from unregulated marketers. During this
transition period, the Company will continue to have certain obligations under
long-term contracts to purchase both natural gas from producers and
transportation capacity from interstate pipeline companies. Accordingly, the
Company's strategy will focus on recovering contractual costs and maximizing
the value of contractual assets. The Company currently plans to avoid some
activities that are often considered part of the merchant function, such as
commodity trading, exploring for and producing natural gas, operating
interstate natural gas pipelines, or expanding storage facilities beyond
current capacity.
The Core Utility or Delivery Function
Through the construction of its distribution system, the Company has committed
over 90% of its assets to the delivery of natural gas to customers. The core
utility function currently includes the infrastructure needed to provide such
customer services as reading meters, preparing bills and answering telephone
inquiries. Historically, the Company's local regulatory commissions have
allowed it to earn a fair rate of return on the capital invested in its
distribution system and to recover expenses such as customer service and
maintenance costs, taxes and depreciation.
The high cost of constructing a duplicate distribution system is a strong
barrier to potential competitors for the delivery function. Thus, the Company
does not expect direct competition from another natural gas distributor. In
addition, the Company believes that bypass of its facilities by other potential
providers of delivery service is unlikely to be a significant threat, primarily
because of the nature of the customer base and the location of customers in
relation to the interstate pipelines. The Company expects that the local
regulatory commissions will continue to function as surrogates for competition,
determining the prices the Company charges its customers and the terms and
conditions of service for the delivery function. Because of continuing
regulation, the Company does not expect the risk profile of the delivery
function to change, nor does it expect the profitability of the delivery
function to decline as a result of customers purchasing natural gas from
unregulated marketers. The Company plans to continue to construct, operate and
maintain its natural gas distribution system, increase the efficiency of its
operations, add customers profitably and compete against other fuels such as
electricity and oil.
Although the Company currently provides customer services as part of its core
utility function, these services can potentially be offered economically by
competitors. The Company is continuing to reduce the cost of performing these
functions, with a goal of moving that cost to a market level. Once at market,
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the Company may or may not continue its role as the provider of customer
services or may offer these services at the wholesale level, depending on its
competitive position, customer demand and regulatory policy preferences.
Certain activities that could be offered as separate services include billing,
meter reading and other services on customers' premises. As customer bills
begin to display costs separately for each service component, customers will
become more familiar with these costs, enabling them to compare prices offered
by competitors in the future. Currently, the Company's customer bills display
natural gas commodity costs and charges for certain appliance service functions
separate from the delivery service charge.
Energy-Related Activities
The Company believes that success in future energy markets will not be driven by
profits from one product or service, but instead will hinge on a company's
ability to provide a package encompassing multiple products and services that
consumers value at competitive prices. As such, the Company and its subsidiaries
currently provide certain energy-related services to consumers, including the
following:
1. Selling natural gas in competition with unregulated marketers and
unregulated marketing subsidiaries of other utility companies;
2. Providing commercial energy services by designing and renovating
mechanical heating, ventilating and air conditioning systems; and
3. Financing gas appliances and certain other equipment for residential
and small commercial customers.
At the present time, the Company's energy-related activities are not significant
to its results of operations. The Company intends to continue competing in the
energy-related markets listed above, and potentially to enter into others.
UNBUNDLING IN THE COMPANY'S MAJOR JURISDICTIONS
Natural Gas
The Company has actively promoted competition for the sale of natural gas, as it
believes that competition supports greater choice in energy suppliers and,
therefore, increased customer satisfaction with natural gas. The Company's goal
is to provide customers with the products, services and conveniences they want
and, in addition, to gain new opportunities to profit from the sale of natural
gas through its gas-marketing subsidiary, WGES. The Company made progress
towards this goal during fiscal year 1998 by advancing its unbundling
initiatives in each of its major jurisdictions. The table on page 11 shows the
status of the unbundling programs in the Company's major jurisdictions as of
September 30, 1998.
10
<PAGE> 13
STATUS OF NATURAL GAS UNBUNDLING IN THE COMPANY'S MAJOR JURISDICTIONS
As of September 30, 1998
<TABLE>
<CAPTION>
Approximate Percentage
Number of of Eligible
Customers Customers
Jurisdiction Customer Class Effective Date Eligible Participating
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Maryland Residential 9/1/98 100,000 26%
Commercial 6/1/98 23,820 35%
Interruptible
(40,000+ Therms) 5/87 290 100%
Virginia Residential 1/1/99 30,000 --
Commercial 1/1/99 2,000 --
Interruptible
(60,000+ Therms) 6/88 220 93%
District of Residential 1/1/99 13,000 --
Columbia Commercial (Small) Pending approval -- --
Commercial (Large) 4/1/98 250 22%
Interruptible
(60,000+ Therms) Pending approval -- --
Interruptible
(250,000+ Therms) 1/88 50 89%
</TABLE>
Unbundling initiatives in Maryland continue to set the pace in the region. The
Company's Customer Choice pilot program for Maryland residential customers is in
its third year and has expanded rapidly in the past year. During fiscal year
1998, the Company received permission to increase the number of eligible
participants from 25,000 to 100,000 (approximately 34% of the Company's Maryland
residential customers).
In Virginia, fiscal year 1998 saw important progress towards unbundling. All of
the Company's interruptible customers in Virginia may choose their supplier of
the natural gas commodity. Also during 1998, the SCC of VA approved the
Company's request to begin a two-year pilot program for firm commercial and
residential customers, allowing eligible customers to choose their natural gas
suppliers. In the first year of the program, up to 10% of the Company's firm
customers in Virginia will be eligible to participate in the program,
increasing to 20% in the second year.
In the District of Columbia, effective April 1, 1998, large firm commercial
customers (those with at least 60,000 in annual natural gas therm deliveries)
became eligible to purchase gas from third-party suppliers. Additionally, in
fiscal year 1998, the PSC of DC approved the Company's request to offer a pilot
customer choice program to residential customers, beginning January 1, 1999.
Electricity
The electric industry still lags behind the natural gas industry in its
progress toward restructuring and deregulation, but the pace of change has
accelerated at both the local and national levels. Restructuring in the
electric industry will likely result in the division of integrated electric
utilities into their component parts of generation, transmission and local
distribution. The Company expects that, similar to the gas industry, the
transmission and distribution of electricity will remain regulated, while the
generating function, much like the merchant function in the natural gas
industry, will move to a competitive environment with market-based pricing.
Direct customer access to electricity providers at the retail level was
implemented in several states in early 1998 and has been studied in virtually
all states. Regulatory changes at the state level should increase competition
11
<PAGE> 14
among electricity providers and in relation to competing fuels, such as natural
gas. Over time, this competition should tend to reduce prices to consumers.
All of the Company's major jurisdictions have investigated, or are in the
process of investigating, the advisability of mandating retail electric
unbundling. The Company supports moving to an unbundled electric market and has
actively participated in proceedings in its jurisdictions. The PSC of MD issued
an order that adopted a phased implementation of retail electric unbundling over
a three-year period, commencing in 2000. The PSC of MD also directed the
investor-owned electric companies in Maryland to fully unbundle their rates
prior to the deregulation of generation. These actions are consistent with
testimony submitted by the Company to the PSC of MD.
In the District of Columbia, the PSC of DC is conducting a review of electric
industry restructuring. The Company has actively participated in the matter to
date, submitting comments which call for the unbundling of electric services and
permit competition in providing electricity to consumers.
The Virginia legislature passed a statute that calls for the provision of
customer choice of electricity supplier beginning in 2004. Pilot programs are
likely to be implemented in the interim. Indeed, two Virginia electric
companies submitted pilot program filings in 1998.
As local regulatory commissions move forward on electric deregulation, the
Company is planning to take advantage of resulting new opportunities. Although
local opportunities are developing more slowly than originally anticipated, WGES
holds a power marketing certificate from the FERC and plans to sell electricity.
INDUSTRY CONSOLIDATION AND CORPORATE STRUCTURE
The energy industry, much like other industries that are becoming increasingly
deregulated and more competitive, has seen a number of consolidations,
combinations, disaggregations and other strategic alliances and restructurings.
This is being driven, in part, as energy companies seek to offer a broader range
of energy services to compete more effectively in attracting and retaining
customers. For example, affiliations with other operating utilities could
potentially result in economies and synergies, and could provide a means to
offer customers a more complete range of energy services. Consolidation will
present combining entities with the challenges of remaining focused on the
customer and integrating different organizations. Others in the energy industry
are discontinuing operations in certain portions of the energy industry or
divesting portions of their business and facilities.
The Company, from time to time, performs studies, and in some cases holds
discussions regarding utility and energy-related investments and transactions
with other companies. The ultimate impact on the Company of any such investments
and transactions that may occur cannot be determined at this time. The Company
is also studying the possibility of changing its corporate structure to clarify
the separation of regulated from unregulated operations, if appropriate for
business and regulatory reasons. One structural option the Company is
considering is the formation of a parent holding company like that of many other
utilities.
GAS SUPPLY AND CAPACITY
The Company and Shenandoah arrange to have natural gas delivered to the entry
points of their distribution systems using the delivery capacity of interstate
pipelines companies. The Company acquires natural gas delivery and storage
capacity for itself and Shenandoah on a system-wide basis because of the
integrated nature of the service agreements between the pipelines and the
Company's consolidated distribution operations. The Company's supply and
12
<PAGE> 15
capacity plan is based on the requirements of the system and takes into account
estimated load growth by type of customer as well as customer attrition,
conservation, and movement of customers from bundled to unbundled service.
The Company has the responsibility of acquiring both sufficient gas supplies to
meet customer requirements and appropriate pipeline capacity to ensure delivery
to the Company's distribution system.
While considering the continuing trend toward unbundling the sale of the gas
commodity from the delivery of the commodity to the customer, the Company must
ensure that it enters into flexible contracts for supply and capacity levels
that will allow it to remain competitive. The Company has adopted a diversified
portfolio approach designed to satisfy the supply and deliverability
requirements of its customers. The Company maintains numerous sources of
supply, dependable transportation and storage arrangements and its own
substantial storage and peaking capabilities to meet the demands of its
customers.
The Company has 12 long-term gas supply contracts with various producers or
marketers that expire between fiscal years 1999 and 2004. Under these
contracts, the Company can purchase up to 100 million dekatherms of natural gas
per year. The Company acquires the balance of its supplies at market prices
under shorter term contracts.
To meet its anticipated annual supply requirements, the Company expects to
utilize firm city-gate (volumes of gas delivered to the entry point of the
Company's distribution system) supply arrangements, firm transportation and
storage retained by the Company, off-system peaking resources under contract,
and Company-owned peak shaving facilities. At September 30, 1998, the Company
had contracts for firm storage and transportation with four pipeline suppliers
that are directly connected to the Company's distribution system, as well as
four upstream pipelines. The Company has entered into contracts with
unregulated marketers to use the Company's firm storage and transportation
rights to meet the Company's city-gate delivery needs and to make off-system
sales when such storage and transportation rights are underutilized. Most of
the Company's storage and transportation rights are assigned to these
marketers; the Company uses several marketers so as to diversify risks. The
Company continues to pay the fixed charges associated with the firm storage and
transportation contracts released to the unregulated marketers. Current
pipeline storage and transportation contracts have termination dates ranging
from fiscal years 1999 to 2016.
As reflected in the first table on page 14, there were five sources of delivery
through which the Company received natural gas to satisfy the sendout
requirements in pipeline year 1998 (November 1, 1997 through October 31, 1998)
and from which supplies can be received in pipeline year 1999 (November 1, 1998
through October 31, 1999). Firm transportation denotes gas purchased and
transported directly to the Company's city-gates in volumes agreed upon by the
Company and the applicable pipeline. Transportation storage denotes volumes
purchased by the Company and stored by a pipeline for withdrawal during the
heating season. Peak load requirements are met by: (1) underground natural gas
storage at the Hampshire storage field in Hampshire County, West Virginia; (2)
the local production of propane air from plants located at Company-owned
facilities in Rockville, Maryland and Ravensworth, Virginia; and (3) other
storage and peak-shaving arrangements.
During pipeline year 1998, total sendout on the system was 1,057 million
therms, excluding deliveries to electric generation facilities and volumes
delivered to customers that acquire their gas from other suppliers. The sendout
for pipeline year 1999 is estimated to be 1,012 million therms (based on normal
weather) excluding deliveries to electric generation facilities and volumes
delivered to customers that acquire their gas from other suppliers. The sources
of delivery and related volumes that were used to satisfy the requirements of
pipeline year 1998 and those projected for pipeline year 1999 are shown on page
14.
13
<PAGE> 16
SOURCES OF DELIVERY FOR
ANNUAL SENDOUT
(millions of therms)
<TABLE>
<CAPTION>
Actual Projected
Sources of Delivery Pipeline Year 1998 Pipeline Year 1999
----------------------------------- ------------------ ------------------
<S> <C> <C>
Firm Transportation 721 679
Transportation Storage 325 293
Hampshire Storage 8 20
Company-Owned Propane-Air Plants 1 4
Other Peak-Shaving Sources 2 16
----- -----
1,057 1,012
===== =====
</TABLE>
The effectiveness of the Company's gas supply program is largely dependent on
the sources from which the design day requirement is satisfied. A design day is
the maximum anticipated demand on the gas supply system during a 24-hour period
assuming a 5 degree Fahrenheit average temperature. The Company assumes that all
interruptible customers will be curtailed on the design day. The Company's
design day estimate is currently 14.2 million therms. The Company is currently
capable of meeting 69% of its design day requirements with storage and peaking
capabilities. Emphasizing storage and peaking facilities on the Company's design
day reduces the necessity to purchase firm transportation, the most expensive
form of capacity from a design day perspective. The following table reflects the
sources of delivery that are projected to be used to satisfy the design day
sendout estimate for pipeline year 1999.
PROJECTED SOURCES OF DELIVERY FOR
DESIGN DAY SENDOUT
(millions of therms)
<TABLE>
<CAPTION>
Pipeline Year 1999
-----------------------
Sources of Delivery Therms Percent
------------------------------------- ------ -------
<S> <C> <C>
Firm Transportation 4.4 31%
Transportation Storage 5.0 35
Company-Owned Propane-Air Plants,
Hampshire Storage and Other Peaking 4.8 34
---- ----
14.2 100%
==== ====
</TABLE>
The Company believes the combination of the gas supply it can purchase under
short-term and long-term contracts, its peaking supplies, and the capacity on
the pipelines required to deliver the purchased supplies, is sufficient to
satisfy the needs of existing customers and allow for growth in future years.
The Company continues to seek opportunities to restructure existing contracts
to maximize the competitiveness of its gas supply portfolio.
ENVIRONMENTAL MATTERS
The Company and its subsidiaries are subject to federal, state and local laws
and regulations related to environmental matters. These evolving laws and
regulations may require expenditures over a long period of time to control
environmental impacts.
Estimates of liabilities for environmental response costs are difficult to
determine with precision because of the factors that can affect their ultimate
level. These factors include, but are not limited to: (1) the complexity of the
site; (2) changes in environmental laws and regulations at the federal, state
and local levels; (3) the number of regulatory agencies or other parties
involved; (4) new technology that renders previous technology obsolete, or
experience with existing technology that proves ineffective; (5) the ultimate
selection of technology; (6) the level of remediation required; and (7)
14
<PAGE> 17
variations between the estimated number of years that must be devoted to
respond to an environmentally contaminated site as compared to the actual
number of years required.
The Company has identified up to ten sites where the Company, its subsidiaries,
or their predecessors may have operated manufactured gas plants (MGPs). The
Company last used any such plant in 1984. In connection with these operations,
the Company is aware that certain by-products of the gas manufacturing process
are present at or near some former sites and may be present at others.
At one of the former MGP sites, studies show the presence of coal tar under the
site and an adjoining property. The Company's risk assessment study performed
on the site shows that there is no unacceptable risk to human health or the
environment. The Company has taken steps to control the movement of
contaminants into an adjacent river. A water treatment system removes and
treats groundwater at the site. The Company continues to advance discussions of
remediation options with the appropriate governmental agency and the adjacent
landowner. The Company completed a feasibility study of remedial alternatives
in fiscal year 1998 and submitted its recommended remedial action plan to the
governmental agency. The Company expects the governmental agency to issue a
decision document outlining the appropriate remediation methodology.
At a second former MGP site, tests identified tar products under the property,
and a risk assessment showed that there was no unacceptable risk to human
health or the environment. The Company designed and installed a state-approved
treatment and recovery system to recover free tar and continues to recover
minimal volumes of tar products from pumping. The Company will continue to pump
tar, monitor the site and provide annual activity reports to the state's
Department of the Environment.
At a third former MGP site, initial studies identified that tar products are
present under the property, and a risk assessment showed that there was no
unacceptable risk to human health or the environment. The Company completed and
submitted a remedial investigation/feasibility study (RI/FS) to the appropriate
state regulatory agency. The Company has yet to receive any response from the
state regarding its submission, but continues to monitor the site.
At a fourth former MGP site and on an adjacent parcel of land, the Company
plans to apply for the state voluntary closure program, which will require some
additional study to determine appropriate remediation.
At a fifth former MGP site, a treatment system for contaminated groundwater has
been operating for eight years. The Company believes, at this time, that no
additional action other than water treatment will be necessary.
At a sixth former MGP site, a governmental authority has notified the Company
about the detection of tar in an adjacent river. At this time, the extent and
nature of any contamination and the Company's related obligation, if any, to
perform remediation can not be determined. The Company will continue its
discussions with the governmental authority and may perform studies to assess
the extent and nature of contamination as well as the need for remediation.
Through September 30, 1998, the Company had paid $10.5 million for
environmental response costs. The Company has recorded a liability of $9.1
million on an undiscounted basis at September 30, 1998 related to future
environmental response costs. This estimate is primarily composed of the
minimum liabilities associated with a range of environmental response costs
expected to be incurred at five of the six sites described above. The Company
estimates the maximum liability associated with these sites to be approximately
$18.6 million at September 30, 1998. The estimates were determined by the
Company's environmental experts based on experience in remediating MGP sites
and advice from legal counsel and environmental consultants. Variations within
the range of estimated
15
<PAGE> 18
liability result primarily from differences in the number of years that will be
required to perform environmental response processes at each site (5 to 25
years) and the extent of remediation that may be required.
The Company believes, at this time, that no remediation of any of the remaining
four sites will be necessary.
Based on existing knowledge, the Company does not expect that the ultimate
impact of these matters will have a significant effect on its competitive
position, results of operations or the level of future capital expenditures.
YEAR 2000
The millennial change to the Year 2000 could affect the Company's software
programs and computing infrastructure that use two-digit years to define the
applicable year, rather than four-digit years. As such they may recognize a
date using "00" as the year 1900 rather than the year 2000. This could result
in the computer or device shutting down, performing incorrect computations or
performing inconsistently.
In 1996, the Company began a structured program to address Year 2000 issues. It
has been implementing individual strategies targeted at the specific nature of
Year 2000 issues in each of the following areas: (1) business-application
systems including, but not limited to, the Company's customer service,
operations and financial systems and end-user applications; (2) embedded
systems, including equipment that operates such items as the Company's storage
and distribution system, meters, telecommunications, fleet and buildings; (3)
vendor and supplier relationships; (4) interruptible customers and their
ability to switch to alternate fuels as required under their tariffs; and (5)
contingency planning.
To implement this comprehensive Year 2000 program, the Company established a
Year 2000 Project Office, chaired by the Vice President and Chief Information
Officer who reports directly to the Chairman and Chief Executive Officer. The
multi-disciplinary project office includes executive management and employees
with expertise from various disciplines including, but not limited to,
information technology, engineering, finance, communications, internal audit,
facilities management, procurement, law and human resources. In addition, the
Company has utilized the expertise of outside consultants to assist in the
implementation of the Year 2000 program in such areas as business-application
system remediation, business-application system replacement, embedded systems
inventory and analysis and contingency planning.
BUSINESS-APPLICATION SYSTEMS
In March 1997, the Company completed its assessment of all its
business-application systems. It is resolving Year 2000 issues through
remediation of 19 systems to recognize the turn of the century and the
replacement of 20 systems with new systems that provide additional business
management information and recognize four-digit years. By June 30, 1998, the
Company had completed modifications to all 16 business applications targeted
for remediation by outside resources, representing approximately 84 percent of
those systems targeted for remediation. The three remaining systems to be
remediated by in-house staff represent the remaining approximately 16 percent
of the total. The Company expects them to be remediated by the end of the
second quarter of fiscal year 1999.
The Company is using in-house staff to test all remediated applications and is
using a testing procedure commonly known as trace-based testing to test
modified business applications for Year 2000 functionality. This method first
captures current processing steps and relevant data, which are run prior to
remediation
16
<PAGE> 19
(baseline test) and again after remediation (regression test). This process is
intended to identify any business rules that may have changed during the
remediation effort and to confirm that only date processes have been changed.
Once the regression test is successfully completed, the Company uses automated
test software tools to perform additional applicable future date tests for each
system.
The Company is also installing an enterprise-wide software system that will
replace 18 business application systems, including its financial, human
resources and supply chain systems. Two other systems will be replaced with
systems not included in the enterprise-wide software initiative. These 20
business applications represent approximately one-half of the business
application software code requiring remediation or replacement. The Company
currently expects to complete the replacement no later than the end of the
third quarter of fiscal year 1999.
In summary, the Company expects that remediation or replacement of
approximately 41 percent of the critical business-application systems will be
completed by the end of the first quarter of fiscal year 1999, and expects all
business-application systems will be completed no later than the end of the
third quarter of fiscal year 1999. Testing will continue through the end of
fiscal year 1999.
During the fourth quarter of fiscal year 1998, the Company completed a
comprehensive, prioritized inventory of end-user applications (i.e., PC-based
databases) and is implementing project plans to replace or remediate these
applications, as necessary. It expects to complete replacement or remediation,
including testing, by the end of the third quarter of fiscal year 1999.
EMBEDDED SYSTEMS
The Company has performed a comprehensive inventory of its embedded systems at
the component level. This inventory identified several hundred components that
were potentially date sensitive. The Company has contacted all manufacturers of
those components that it has identified as critical to operations. At this time,
approximately three percent of the date-sensitive components that the Company
has identified are non-compliant based on information provided by the
manufacturers. The Company implemented remediation or replacement plans as
necessary and expects them to be completed by the end of the second quarter of
fiscal year 1999. The quality of the responses received from manufacturers, the
estimated impact of the individual systems on the Company, and the ability of
the Company to perform meaningful tests will influence its decision to conduct
independent testing of embedded systems through the end of fiscal year 1999.
VENDOR AND SUPPLIER RELATIONSHIPS
The Company is contacting in writing or through face-to-face discussions all
vendors and suppliers of products and services that it considers critical or
important to its operation. These contacts include providers of interstate
transportation capacity and storage, natural gas suppliers, financial
institutions and electric, telephone and water companies. The Company is
evaluating the initial responses and continues the process of following up with
the vendors and suppliers either through meetings or by letter. The Company
will consider new business relationships with alternate providers of products
and services as necessary and to the extent alternatives are available.
However, the Company recognizes there are no practical alternatives for
external infrastructure such as electric and telephone service, suppliers of
natural gas and providers of interstate transportation capacity and storage to
deliver natural gas to the Company's distribution system.
17
<PAGE> 20
INTERRUPTIBLE CUSTOMERS
The Company is communicating with its major interruptible customers to inform
them about the potential vulnerability of embedded boiler and plant control
systems. The Company informed them that they should assess the need to include
potential remediation and/or replacement of these systems as part of their Year
2000 programs to ensure their ability to switch to an alternate fuel source, as
required by applicable tariffs and contracts and if called on to do so.
YEAR 2000 RISKS AND CONTINGENCY PLANNING
With respect to its internal operations, over which the Company has direct
control, the Company believes the most significant potential risks are: (1) its
ability to use electronic devices to control and operate its distribution
system; (2) its ability to render timely bills to its customers; (3) its
ability to enforce tariffs and contracts applicable to interruptible customers;
and (4) its ability to maintain continuous operation of its computer systems.
The Company's Year 2000 program addresses each of these risks, and the
remediation or replacement of these systems is well under way. In the event
that any Year 2000-related problems may occur, the Company's contingency plan
will outline alternatives to mitigate the impact of such failures, to the
extent possible.
The Company relies on the suppliers of natural gas and interstate transportation
and storage capacity to deliver natural gas to the Company's distribution
system. External infrastructure, such as electric, telephone and water service,
is necessary for the Company's basic operation as well as the operations of many
of its customers. Should any of these critical vendors fail, the impact of any
such failure could become a significant challenge to the Company's ability to
meet the demands of its customers, to operate its distribution system and to
communicate with its customers. It could also have a material adverse financial
impact including, but not limited to, lost sales revenues, increased operating
costs and claims from customers related to business interruptions. The Company
has no way of ensuring that those vendors or suppliers mentioned above for which
there are no viable options will be timely Year 2000 compliant.
As part of its normal business practice, the Company maintains plans to follow
during emergency circumstances. These plans will be used as a basis to build the
Company's contingency plan for potential Year 2000-related problems. The Company
maintains and operates a command center that is activated during emergency
circumstances. The Company will manage specific Year 2000 contingency operations
from the command center during the millennium change as well as at other points
in time on an as needed basis.
Because of the interconnected nature of potential Year 2000-related problems,
the Company recognizes that effective contingency planning must focus on both
internal and external operations and is working with local organizations and
other utilities as it completes its planning effort. The Company has
participated in association meetings and customer meetings with other local
utilities to discuss the Company's Year 2000 program.
The Company believes that its work will serve to reduce the risk that its
internal systems will fail for Year 2000 reasons. However, the contingency plan
cannot mitigate interrupted delivery to the Company's distribution system of
natural gas by the producers of natural gas and providers of interstate
transportation capacity or the impact on operations of failures of electric,
telephone and water services.
FINANCIAL IMPLICATIONS
To implement its Year 2000 strategies, the Company currently expects to generate
non-recurring expenses of approximately $10 million over the three fiscal-year
periods ending September 30, 1999 for business-application systems remediation,
18
<PAGE> 21
embedded systems replacement, end-user applications remediation and replacement,
and certain costs associated with the replacement of certain existing business
systems. The Company will capitalize costs of approximately $28 million incurred
to replace certain existing business-application software systems with new
systems that will be Year 2000 operational and provide additional business
management information.
The following table reflects the amounts charged to expense and capitalized
through September 30, 1998 for business-application systems remediation,
embedded systems replacement and end-user applications remediation and
replacement and for replacing existing business-application software systems.
<TABLE>
<CAPTION>
1998 1997 Total
-------------------------- -------------------------- -----------------------
Expense Capital Expense Capital Expense Capital
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(millions)
Business-application
systems remediation,
embedded systems
replacement and
end-user applications
remediation and
replacement $1 $1 $1 $ -- $2 $ 1
Business-application
software systems
replacement $4 $19 $ -- $ -- $4 $19
</TABLE>
Until the Company has completed further analysis of the impact of the Year 2000
issue on its embedded systems, vendor and supplier relationships and contingency
planning, it is unable to estimate the additional costs, if any, it may incur as
a result of its efforts.
Each of the components of the Company's Year 2000 program is progressing, and
the Company believes it is taking reasonable steps necessary to be able to
operate successfully through and beyond the turn of the century.
OTHER
Revenue from the sale or delivery of natural gas as a percentage of consolidated
operating revenue was 98% for 1998 and 1997 and 99% for 1996. The Company is not
dependent upon a single customer or a few customers such that the loss of any
one or more of such customers would have a significant adverse effect on the
Company. Large customers are generally on interruptible rate schedules, and
margin-sharing arrangements limit the effects of interruptible customer usage on
net income. As shown on page 2, the Company and Shenandoah had 819,719 customer
meters at September 30, 1998.
The Company's utility business is highly seasonal and weather sensitive since
the majority of its business is derived from residential and small commercial
customers who use gas for space heating purposes. In fiscal year 1998, 76% of
the therms delivered by the Company, excluding deliveries for electric
generation, occurred in the Company's first and second fiscal quarters. All of
the Company's earnings are generated in these two quarters and the Company
historically incurs losses in the third and fourth fiscal quarters. Results of
operations can be affected by the timing and level of approved rate increases.
The seasonal nature of the Company's business creates large variations in
short-term cash requirements, primarily due to fluctuations in the level of
customer accounts receivable and storage gas inventory levels. The Company
finances these seasonal requirements primarily through the sale of commercial
paper and short-term bank loans.
19
<PAGE> 22
Through the cost of services provided by the interstate pipelines, the Company
and Shenandoah contribute to the funding of the Gas Research Institute. The
Institute's primary focus is devoted to developing more efficient gas equipment
and to increase the long-term supply of gas. The Company also belongs to the
Natural Gas Vehicle Coalition and the Institute of Gas Technology. These
organizations are involved in developing new applications and technologies for
the use of natural gas. The cost of these memberships and the Company's own
research and development costs during fiscal years 1998, 1997 and 1996 were not
material.
At September 30, 1998, the Company and its wholly owned subsidiaries had 2,169
employees. This represents an increase of 99 employees from the level at
September 30, 1997 due to a higher level of non-utility employees resulting from
the purchase of ACI in March 1998. At September 30, 1998, there were 2,000
utility employees, a decline of 59 employees from the level at September 30,
1997.
ITEM 2. PROPERTIES
The Company and its subsidiaries hold such valid franchises, certificates of
convenience and necessity, licenses and permits as are necessary for the
maintenance and operation of their respective properties and businesses as now
conducted. The Company has no reason to believe that it will be unable to renew
any of such franchises as they expire.
As of September 30, 1998, the Company and its utility subsidiaries had 636
miles of transmission mains and 9,813 miles of distribution mains. The Company
has the capacity for storage of approximately 15 million gallons of propane for
peak shaving.
The Company owns the land and a 12-story office building (built in 1942) at 1100
H Street, Northwest in Washington, D.C., where its corporate offices are
located. The Company owns the land and a building (built in 1970) at 6801
Industrial Road in Springfield, Virginia, which houses the Company's operating
offices and certain administrative functions. The Company has title to land and
buildings used as substations for its utility operations.
The Company also has peaking facilities consisting of propane air plants in
Ravensworth, Virginia and Rockville, Maryland. Hampshire operates an underground
natural gas storage field in Hampshire County, West Virginia. Hampshire accesses
the storage field through 12 storage wells that are connected to an 18-mile
pipeline gathering system. Hampshire also operates a compressor station for
injection of gas into storage. The Augusta and Little Capon fields, located in
Hampshire County, have the capacity to provide the Company's system with
approximately 2.7 billion cubic feet of natural gas under design conditions. For
pipeline year 1999, it is projected that the Hampshire storage facility will
supply approximately 2.0 billion cubic feet of natural gas to the Company's
system for meeting seasonal demands.
The Company's Mortgage dated January 1, 1933 (Mortgage), as supplemented and
amended, securing the First Mortgage Bonds (FMBs) issued by the Company,
constitutes a direct lien on substantially all property and franchises owned by
the Company other than expressly excepted property.
The Company executed a supplemental indenture to its unsecured Medium-Term Notes
(MTNs) Indenture on September 1, 1993, providing that the Company can not issue
any FMBs under its Mortgage without making effective provision whereby any
outstanding MTNs shall be secured equally and ratably with any and all other
obligations and indebtedness secured by the Mortgage.
20
<PAGE> 23
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
21
<PAGE> 24
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- --------------------------------------------------------- -----------------
<S> <C>
The names, ages, and positions of the executive officers of the Registrant as of
the date of this report are listed below along with their business experience
during the past five years.
Elizabeth M. Arnold, Age 46
Vice President (corporate strategy and internal audit) January 31, 1996
Treasurer May 1, 1993
Beverly J. Burke, Age 47
Vice President and Assistant General Counsel October 1, 1998
Department Head - Office of the General Counsel January 22, 1997
Managing Attorney November 16, 1992
Richard J. Cook, Age 56
Vice President (Construction and Technical Support) October 1, 1996
Executive Assistant October 1, 1995
Director - Environment and Safety September 1, 1989
James H. DeGraffenreidt, Jr., Age 45
Chairman of the Board and Chief Executive Officer December 1, 1998
President and Chief Executive Officer January 1, 1998
President and Chief Operating Officer December 1, 1994
Senior Vice President - Jurisdictional Divisions
and Rates and Regulatory Affairs May 1, 1993
Richard L. Fisher, Age 51
Vice President (Delivery Services) June 1, 1996
Executive Director May 3, 1993
John K. Keane, Jr., Age 60
Senior Vice President and General Counsel May 1, 1993
Frederic M. Kline, Age 47
Vice President, Treasurer and Chief Financial Officer October 1, 1998
Vice President and Treasurer January 31, 1996
Controller November 27, 1985
Lisa M. Metcalfe, Age 34 (2)
Vice President and Chief Information Officer October 1, 1996
Douglas V. Pope, Age 53
Secretary July 25, 1979
Joseph M. Schepis, Age 45 (3)
President and Chief Operating Officer December 1, 1998
Executive Vice President and Chief Operating Officer January 1, 1998
Senior Vice President (gas supply, regulatory activities
and customer services) January 31, 1996
Senior Vice President and Chief Financial Officer December 15, 1994
Vice President - Rates and Regulatory Affairs May 1, 1993
Roberta W. Sims, Age 44
Vice President (corporate relations and communications) January 31, 1996
Vice President and General Manager -
District of Columbia Division October 1, 1992
</TABLE>
22
<PAGE> 25
EXECUTIVE OFFICERS OF THE REGISTRANT (CONTINUED)
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- ------------------------------------------------------------ -----------------
<S> <C>
Robert A. Sykes, Age 50
Vice President (human resources) February 21, 1996
Vice President - Human Resources October 1, 1987
Robert E. Tuoriniemi, Age 42 (4)
Controller October 1, 1996
James B. White, Age 48
Vice President (business development) February 21, 1996
Vice President and General Manager - Virginia Division May 1, 1993
</TABLE>
There is no family relationship among the officers. The age of each officer
listed is as of the date of filing.
(1) Each of the officers has served continuously since the dates indicated.
(2) Ms. Metcalfe was previously employed by the National Wildlife Federation and
served most recently as Vice President of Constituent Systems and Services. In
this capacity, she was responsible for the organization's information systems,
telecommunications systems, facilities, and administrative services.
(3) Mr. Schepis was elected to the Board of Directors effective at the close of
business on December 16, 1998.
(4) Mr. Tuoriniemi was previously employed by Central Maine Power Company (CMP),
an electric utility, and served most recently as Comptroller. In the Comptroller
position, Mr. Tuoriniemi's responsibilities included all accounting matters,
testifying before regulatory commissions in rate case proceedings, directing tax
planning and coordinating financial reporting activities.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information captioned "Common Stock Price Range and Dividends Paid" and
presented on page 55 of the Company's 1998 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into this
Item. Only owners of record are counted as common shareholders.
ITEM 6. SELECTED FINANCIAL DATA
Page 22 of the Company's 1998 Annual Report to Shareholders is included in
Exhibit 13 in this report and is incorporated by reference into this Item.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Pages 23 through 36 of the Company's 1998 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into this
Item.
23
<PAGE> 26
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk Exposure Related to Other Financial Instruments
At September 30, 1998, the Company had fixed-rate long-term debt aggregating
$428.6 million in principal amount and having a fair value of $462.2 million.
Fair value is defined as the present value of the debt securities' future cash
flows discounted at interest rates that reflect market conditions as of
September 30, 1998. While these instruments are fixed-rate and, therefore, do
not expose the Company to the risk of earnings loss due to changes in market
interest rates, they are subject to changes in fair value as market interest
rates change. Using sensitivity analysis to measure this market risk exposure,
the Company estimates that the fair value of its long-term debt would increase
by approximately $19.4 million if interest rates were to decline by 10%. The
Company also estimates that the fair value of its long-term debt would decrease
by approximately $17.6 million if interest rates were to increase by 10%. In
general, such an increase or decrease in fair value would impact earnings and
cash flows only if the Company were to reacquire all or a portion of these
instruments in the open market prior to their maturity.
Price Risk Related to Gas-Marketing Activities
The Company's gas-marketing activities are performed by its marketing
subsidiary, WGES. In the course of its business, WGES makes fixed-price sales
commitments to customers. WGES purchases the corresponding physical supplies at
fixed prices to lock in margins. WGES has exposure to changes in gas prices
related to volumetric differences between the purchase commitments and sales
commitments. The risk associated with gas price fluctuations is managed by
closely matching purchases from suppliers with sales commitments to customers.
At September 30, 1998, WGES' open position was not material to the Company's
financial position or results of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pages 37 through 55 of the Company's 1998 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into this
Item.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning Directors contained in the definitive proxy statement
dated January 25, 1999, is hereby incorporated herein by reference.
Information related to Executive Officers is reflected in Part I hereof.
ITEM 11. EXECUTIVE COMPENSATION
The information captioned "Executive Compensation" in the definitive proxy
statement dated January 25, 1999, is hereby incorporated herein by reference.
24
<PAGE> 27
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information captioned "Security Ownership of Management" in the definitive
proxy statement dated January 25, 1999, is hereby incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Karen Hastie Williams, a Director of the Company, is a partner in the law firm
Crowell & Moring. Michael D. Barnes, a Director of the Company, is a partner in
the law firm Hogan & Hartson. Both firms performed legal services for the
Company during fiscal year 1998.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
(a)1 All Financial Statements Pages in 1998
Annual Report to
Shareholders
Included in
Exhibit 13
-----------------
<S> <C>
Consolidated Statements of Income - for the years ended
September 30, 1998, 1997 and 1996............................... 37
Consolidated Balance Sheets - as of September 30, 1998 and 1997... 38
Consolidated Statements of Cash Flows - for the years ended
September 30, 1998, 1997 and 1996............................... 39
Consolidated Statements of Capitalization - as of September 30,
1998 and 1997................................................... 40
Consolidated Statements of Common Shareholders' Equity -
1998, 1997 and 1996............................................. 41
Consolidated Statements of Income Taxes - for the years ended
September 30, 1998, 1997 and 1996 and as of September 30, 1998
and 1997........................................................ 42
Notes to Consolidated Financial Statements........................ 43-53
Report of Independent Public Accountants.......................... 54
</TABLE>
(a)2 Financial Statement Schedules
Separate financial statements for Washington Gas Light Company are omitted
since the Company's total assets, exclusive of investments in and advances to
its subsidiaries, constitute more than 75% of the total assets shown in the
Consolidated Balance Sheets, and the Company's total gross revenue, exclusive
of interest and dividends received or equity in income from the consolidated
subsidiaries, constitutes more than 75% of total gross revenues shown in the
Consolidated Statements of Income.
Schedule II, listed on page 26, should be read in conjunction with the
financial statements in the 1998 Annual Report to Shareholders. Schedules not
included herein have been omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
25
<PAGE> 28
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONTINUED)
<TABLE>
<CAPTION>
Pages in
Schedule Description 10-K
- -------- -------------------------------------------------------------------------- --------
<S> <C> <C>
II Valuation and Qualifying Accounts and Reserves for the years ended
September 30, 1998, 1997 and 1996..................................... 32
(a)3 Exhibits
Exhibits Filed Herewith:
Pages in
Description 10-K
----------- ----------
3. Articles of Incorporation and Bylaws: See
Separate
Volume
Bylaws of the Company as amended on
October 28, 1998.
12. Statement re Computation of Ratios -
12.0 Computation of Ratio of Earnings to Fixed Charges
12.1 Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends
13. Annual Report to Security Holders -
1998 Annual Report to Shareholders (except for the
information presented on the front and rear covers and
Pages 1 through 21, which are not deemed to be filed
with the Securities and Exchange Commission for the
purposes of the Securities Exchange Act of 1934)
21. Subsidiaries of the Registrant
23. Consents of Experts and Counsel
27. Financial Data Schedule
</TABLE>
26
<PAGE> 29
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONTINUED)
Exhibits Incorporated by Reference:
Description
3. Articles of Incorporation and Bylaws:
Company Charter, filed on Form S-3 dated July 21, 1995.
4. Instruments defining the Rights of Security Holders including
indentures:
Mortgage and Deed of Trust of the Company, dated January 1,
1933, and filed as Exhibit 2.2 of the Registration Statement
on Form S-7 filed with the Commission on May 12, 1975.
Supplemental Indenture, dated March 1, 1987, to the
Company's Mortgage and Deed of Trust, dated January 1, 1933,
filed on Form 8-K dated March 13, 1987.
Supplemental Indenture, dated July 1, 1989, to the Company's
Mortgage and Deed of Trust, dated January 1, 1933, filed on
Form 8-K dated July 12, 1989.
Indenture, dated September 1, 1991 between the Company and
The Bank of New York, as Trustee, regarding issuance of
unsecured notes, filed on Form 8-K on September 19, 1991.
Supplemental Indenture, dated September 1, 1993 between the
Company and The Bank of New York, as Trustee, regarding the
addition of a new section to the Indenture dated September
1, 1991, filed on Form 8-K on September 10, 1993.
10. Material Contracts:
Service Agreement effective October 1, 1993 with
Transcontinental Gas Pipe Line Corporation related to the
upstream capacity on the CNG Transmission Corporation
system, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective October 1, 1993 with
Transcontinental Gas Pipe Line Corporation related to
General Storage Service, filed on Form 10-K for the fiscal
year ended September 30, 1993.
Service Agreement effective October 1, 1993 with Texas
Eastern Transmission Corporation related to transportation
service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective November 1, 1993 with Columbia
Gas Transmission Corporation related to Firm Storage
Service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
27
<PAGE> 30
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONTINUED)
Service Agreement effective November 1, 1993 with Columbia
Gas Transmission Corporation related to Firm Transportation
Service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective November 1, 1993 with Columbia
Gulf Transmission Company related to Firm Transportation
Service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective November 1, 1993 with Columbia
Gulf Transmission Company related to Interruptible
Transportation Service, filed on Form 10-K for the fiscal
year ended September 30, 1993.
Service Agreement effective November 1, 1993 with Columbia
Gas Transmission Corporation related to Storage Service
Transportation, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective November 1, 1993 with Columbia
Gas Transmission Corporation related to Storage In Transit
Service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective October 1, 1993 with CNG
Transmission Corporation related to Firm Transportation
Service, filed on Form 10-K for the fiscal year ended
September 30, 1993.
Service Agreement effective October 1, 1993 with CNG
Transmission Corporation related to Firm Transportation
Storage Service, filed on Form 10-K for the fiscal year
ended September 30, 1993.
Service Agreement effective October 1, 1993 with CNG
Transmission Corporation related to General Storage Service,
filed on Form 10-K for the fiscal year ended September 30,
1993.
Service Agreement effective February 1, 1992 between
Transcontinental Gas Pipe Line Corporation and Frederick Gas
Company, Inc. related to Firm Transportation Service, filed
on Form 10-K for the fiscal year ended September 30, 1993.
Service Agreement effective February 1, 1992 with
Transcontinental Gas Pipe Line Corporation related to Firm
Transportation Service, filed on Form 10-K for the fiscal
year ended September 30, 1993.
Service Agreement effective August 1, 1991 with
Transcontinental Gas Pipe Line Corporation related to
Washington Storage Service, filed on Form 10-K for the
fiscal year ended September 30, 1993.
28
<PAGE> 31
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONTINUED)
Employment Agreement between the Company and certain
executive officers, as defined in Item 402(a)(3) of
Regulation S-K, filed on Form 10-Q for the period ended June
30, 1997.*
Directors' Stock Compensation Plan, as adopted on October
25, 1995 and filed on Form 10-K for the fiscal year ended
September 30, 1995*
Deferred Compensation Plan for Outside Directors as amended
filed on Form 10-K for the fiscal year ended December 31,
1986*
Retirement Plan for Outside Directors, as amended on
December 18, 1996 and filed on Form 10-K for the fiscal year
ended September 30, 1997 *
Long-Term Incentive Compensation Plan, as amended on
December 18, 1996 and filed on Form 10-K for the fiscal year
ended September 30, 1997 *
Executive Incentive Compensation Plan, as amended on
December 18, 1996 and filed on Form 10-K for the fiscal year
ended September 30, 1997 *
Supplemental Executive Retirement Plan, as amended on
December 18, 1996 and filed on Form 10-K for the fiscal year
ended September 30, 1997 *
* Compensatory plan arrangement required to be filed
pursuant to Item 14(c) of Form 10-K.
29
<PAGE> 32
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(CONTINUED)
(b) Reports on Form 8-K:
The following reports were filed on Form 8-K during the fourth
fiscal quarter of 1998 and the first fiscal quarter of 1999 up until
the date of this report.
<TABLE>
<CAPTION>
Date Filed Description of Event Reported
--------------- -------------------------------------------
<S> <C>
July 10, 1998 Update of regulatory matters in Virginia.
On June 25, 1998, the Hearing Examiner Of
the State Corporation of Virginia issued a
report related to certain of the Company's
regulatory assets associated with its
Virginia operations.
October 13, 1998 Announcement of the future retirement date
of Chairman of the Board, Patrick J. Maher
and other succession plans.
October 30, 1998 Announcement of the unaudited results of
operations for fiscal Year 1998 and the
three months ended September 30,1998.
November 4, 1998 Announcement that Shenandoah Gas Company
entered into an agreement to sell its
utility assets located in West Virginia.
November 25, 1998 A copy of the Underwriting Agreement and
Price Determination Agreement related to
the public issuance of up to 2.3 million
shares of the Company's common stock.
Announcement of the Underwriters exercising
their option to purchase an additional
300,000 shares from the Company.
</TABLE>
30
<PAGE> 33
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To the Shareholders and Board of Directors of Washington Gas Light Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements included in Washington Gas Light Company's annual
report to shareholders incorporated by reference in this Form 10-K, and have
issued our report thereon dated October 26, 1998 (except with respect to the
matters discussed in Note 13, as to which the date is November 18, 1998). Our
audit was made for the purpose of forming an opinion on those statements taken
as a whole. The Schedule II - Valuation and Qualifying Accounts and Reserves for
the years ended September 30, 1998, 1997 and 1996 - listed in the index on page
26 is the responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This Schedule II has been subjected
to the auditing procedures applied in the audit of the basic financial
statements and, in our opinion, fairly states in all material respects the
financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Washington, D.C.,
October 26, 1998.
31
<PAGE> 34
WASHINGTON GAS LIGHT COMPANY & SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
ADDITIONS CHARGED TO
BALANCE AT ------------------------------- BALANCE
BEGINNING COSTS AND OTHER AT END
OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS (C) OF PERIOD
-------------- -------------- ------------ ----------------- --------------
<S> <C> <C> <C> <C> <C>
1998
----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 11,043 9,855 2,503 (A) 14,323 $ 9,078
Provision for impairment of investments
and other deferred charges 5,970 - - 1,823 4,147
Reserves:
Injuries and Damages 10,145 2,490 254 (B) 4,019 8,870
Other 900 - - 450 450
1997
----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 11,846 $ 11,237 $ 1,857 (A) $ 13,897 $ 11,043
Provision for impairment of investments
and other deferred charges 6,507 - - 537 5,970
Reserves:
Injuries and Damages 9,292 2,146 826 (B) 2,119 10,145
Other 900 - - - 900
1996
----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 10,580 $ 7,752 $ 2,070 (A) $ 8,556 $ 11,846
Provision for impairment of investments
and other deferred charges 5,397 1,150 - 40 6,507
Reserves:
Injuries and Damages 11,873 2,409 1,845 (B) 6,835 9,292
Other 900 - - - 900
</TABLE>
NOTES:
(A) Recoveries on receivables previously written off as uncollectible and
unclaimed customer deposits, overpayments, etc., not refundable.
(B) Portion of injuries and damages charged to construction and
reclassification from other accounts.
(C) Includes deductions for purposes for which reserves were provided or
revisions made of estimated exposure.
32
<PAGE> 35
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
WASHINGTON GAS LIGHT COMPANY
/s/ JAMES H. DEGRAFFENREIDT, JR.
--------------------------------
James H. DeGraffenreidt, Jr.
Chairman of the Board
and Chief Executive Officer
Date: December 16, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ JAMES H. DEGRAFFENREIDT, JR. Chairman of the Board 12/16/98
--------------------------------- and Chief Executive Officer ---------
(James H. DeGraffenreidt, Jr.)
/s/ FREDERIC M. KLINE Vice President, Treasurer 12/16/98
--------------------------------- and Chief Financial Officer ---------
(Frederic M. Kline) (Principal Financial Officer)
/s/ ROBERT E. TUORINIEMI Controller 12/16/98
--------------------------------- (Principal Accounting Officer) ---------
(Robert E. Tuoriniemi)
/s/ MICHAEL D. BARNES Director 12/16/98
--------------------------------- ---------
(Michael D. Barnes)
/s/ FRED J. BRINKMAN Director 12/16/98
--------------------------------- ---------
(Fred J. Brinkman)
/s/ DANIEL J. CALLAHAN, III Director 12/16/98
--------------------------------- ---------
(Daniel J. Callahan, III)
/s/ ORLANDO W. DARDEN Director 12/16/98
--------------------------------- ---------
(Orlando W. Darden)
/s/ MELVYN J. ESTRIN Director 12/16/98
--------------------------------- ---------
(Melvyn J. Estrin)
/s/ PATRICK J. MAHER Director 12/16/98
--------------------------------- ---------
(Patrick J. Maher)
/s/ KAREN HASTIE WILLIAMS Director 12/16/98
--------------------------------- ---------
(Karen Hastie Williams)
</TABLE>
33
<PAGE> 36
WASHINGTON GAS LIGHT COMPANY
1998 FORM 10-K EXHIBIT INDEX
Exhibit Description
3. Articles of Incorporation and Bylaws
12. Statement re Computation of Ratios
12.0 Computation of Ratio of Earnings to Fixed Charges
12.1 Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividends
13. Annual Report to Security Holders -
1998 Annual Report to Shareholders (except for
the information presented on the front and rear
covers and Pages 1 through 21, which are not
deemed to be filed with the Securities and
Exchange Commission for the purposes of the
Securities Exchange Act of 1934)
21. Subsidiaries of the Registrant
23. Consents of Experts and Counsel
27. Financial Data Schedule
<PAGE> 1
Effective 10/28/98
WASHINGTON GAS LIGHT COMPANY
----------------------------
BYLAWS
------
ARTICLE I
Stockholders.
SECTION 1. Annual Meeting. The annual meeting of stockholders of
Washington Gas Light Company (the Company) shall be held on the fourth
Wednesday in the month of February in each year, at 10:00 a.m., at the Grand
Hyatt Washington Hotel, 11th and H Streets, N.W., Washington, D.C., for the
purpose of electing directors and for the transaction of such other business as
properly may come before such meeting. If the day fixed for the annual meeting
shall be a legal holiday in the District of Columbia, such meeting shall be
held on the next succeeding business day.
SECTION 2. Special Meetings. Special meetings of stockholders may be
held upon call by the Chairman of the Board, the President, the Secretary, a
majority of the Board of Directors, or a majority of the Executive Committee,
and shall be called by the Chairman of the Board, the President or Secretary
upon the request in writing of the holders of record of not less than one-tenth
of all the outstanding shares of stock entitled by its terms to vote at such
meeting, at such time and at such place within the District of Columbia as may
be fixed in the call and stated in the notice setting forth such call. Such
request by the stockholders and such notice shall state the purpose of the
proposed meeting.
SECTION 3. Notice of Meetings. Notice of the time, place and purpose
of every meeting of the stockholders, shall, except as otherwise required by
law, be delivered personally or mailed at least ten (10) but not more than one
hundred (100) days prior to the date of such meeting to each stockholder of
record entitled to vote at the meeting at his address as it appears on the
records of the Company. Any meeting may be held without notice if all of the
stockholders entitled to vote thereat
<PAGE> 2
- 2 - Effective 10/28/98
are present in person or by proxy at the meeting, or if notice is waived by
those not so present in person or by proxy.
SECTION 4. Quorum. At every meeting of the stockholders, the holders
of record of a majority of the shares entitled to vote at the meeting,
represented in person or by proxy, shall constitute a quorum. The vote of the
majority of such quorum shall be necessary for the transaction of any business,
unless otherwise provided by law or the articles of incorporation. If the
meeting cannot be organized because a quorum has not attended, those present in
person or by proxy may adjourn the meeting from time to time until a quorum is
present when any business may be transacted that might have been transacted at
the meeting as originally called.
SECTION 5. Voting. Unless otherwise provided by law or the articles
of incorporation, every stockholder of record entitled to vote at any meeting
of stockholders shall be entitled to one vote for every share of stock standing
in his name on the records of the Company on the record date fixed as provided
in these Bylaws. In the election of directors, all votes shall be cast by
ballot and the persons having the greatest number of votes shall be the
directors. On matters other than election of directors, votes may be cast in
such manner as the Chairman of the meeting may designate.
SECTION 6. Inspectors. The Board of Directors shall annually appoint
two or more persons to act as inspectors or judges at any election of directors
or vote conducted by ballot at any meeting of stockholders. Such inspectors or
judges of election shall take charge of the polls and after the balloting shall
make a certificate of the result of the vote taken. In case of a failure to
appoint inspectors, or in case an inspector shall fail to attend, or refuse or
be unable to serve, the Chairman
<PAGE> 3
- 3 - Effective 10/28/98
of the meeting may appoint, or the stockholders may elect, an inspector or
inspectors to act at such meeting. Such inspector or inspectors shall make a
certificate of the result of the vote taken.
SECTION 7. Conduct of Stockholders' Meeting. The following persons,
in the order named, shall be entitled to call each stockholders' meeting to
order: (1) the Chairman of the Board, (2) the President of the Company, (3) a
Vice President, or (4) any person elected by the stockholders. The
stockholders shall have the right to elect a Chairman of the meeting.
The Secretary of the Company, or in his absence any person appointed
by the Chairman, shall act as Secretary of the meeting for organization
purposes. The stockholders shall have the right to elect a secretary of the
meeting.
SECTION 8. Record Date. In lieu of closing the stock transfer books,
the Board of Directors, in order to make a determination of stockholders
entitled to notice of or to vote at any meeting, or to receive payment of any
dividends or for any other proper purpose, may fix in advance a date, but not
more than fifty days in advance, as a record date for such determination, and
in such case only stockholders of record on the date so fixed shall be entitled
to notice of, and to vote at, such meeting, or to receive payment of such
dividend, or to exercise such other rights, as the case may be, notwithstanding
any transfer of stock on the books of the Company after such date. If the
Board of Directors does not fix a record date as aforesaid, such date shall be
as provided by law.
SECTION 9. Notice of Business. At any meeting of the stockholders,
only such business shall be conducted as shall have been brought before the
meeting (1) by or at the direction of the Board of Directors or (2) by any
stockholder of the Company who is a stockholder of record at the
<PAGE> 4
- 4 - Effective 10/28/98
time of giving of the notice as provided for in this Section 9, who shall be
entitled to vote at such meeting and who complies with the following
procedures:
Requirement of Timely Notice. For business to be properly
brought before a meeting of stockholders by a stockholder, the
business shall be a proper subject of stockholder action and the
stockholder shall have given timely notice thereof in writing to the
Secretary. To be timely, a stockholder's notice shall be delivered to
or mailed and received by the Secretary at the principal executive
office of the Company not less than sixty (60) days prior to the
scheduled date of the meeting (regardless of any postponements,
deferrals or adjournments of the meeting to a later date); provided,
however, if no notice is given and no public announcement is made to
the stockholders regarding the date of the meeting at least 75 days
prior to the meeting, the stockholder's notice shall be valid if
delivered to or mailed and received by the Secretary at the principal
executive office of the Company not less than fifteen (15) days
following the day on which the notice or public announcement of the
date of the meeting was given or made.
Contents of Notice. Such stockholder's notice to the
Secretary shall set forth as to each item of business the stockholder
proposes to bring before the meeting (1) a brief description of the
business desired to be brought before the meeting, the reasons for
conducting such business at the meeting and, in the event that such
business includes a proposal to amend either the Charter or these
Bylaws, the language of the proposed amendment, (2) the name and
address, as they appear on the Company's books, of the
<PAGE> 5
- 5 - Effective 10/28/98
stockholder proposing such business, (3) the class and number of
shares of capital stock of the Company that are beneficially owned by
such stockholder, and (4) any material interest (financial or other)
of such stockholder in such business.
Compliance with Bylaws. Notwithstanding anything in these
Bylaws to the contrary, no business shall be conducted at a
stockholders' meeting except in accordance with the procedures set
forth in this Section 9. The chairman of the meeting shall, if the
facts warrant, determine and declare to the meeting that the business
was not properly brought before the meeting and in accordance with the
provisions of these Bylaws, and if he should so determine, he shall so
declare to the meeting and any such business not properly brought
before the meeting shall not be transacted at the meeting.
Notwithstanding the foregoing provisions of this Section 9, a
stockholder shall also comply with all applicable requirements of the
Securities Exchange Act of 1934, as amended, and the rules and
regulations thereunder with respect to the matters set forth in this
Section 9.
Effective Date of Stockholder Business. Notwithstanding
anything in these Bylaws to the contrary, no business brought before a
meeting of the stockholders by a stockholder shall become effective
until the final termination of any proceeding which may have been
commenced in any court of competent jurisdiction for an adjudication
of any legal issues incident to determining the validity of such
business and the procedure pursuant to which it was brought before the
stockholders, unless and until such court shall have determined that
such proceedings are not being pursued expeditiously and in good
faith.
<PAGE> 6
- 6 - Effective 10/28/98
ARTICLE II
Board of Directors.
SECTION 1. Number, Powers, Term of Office, Quorum. The Board of
Directors of the Company shall consist of eight persons. The Board of
Directors may exercise all the powers of the Company and do all acts and things
which are proper to be done by the Company which are not by law or by these
Bylaws directed or required to be exercised or done by the stockholders. The
members of the Board of Directors shall be elected at the annual meeting of
stockholders and shall hold office until the next succeeding annual meeting, or
until their successors shall be elected and shall qualify. A majority of the
number of directors fixed by the Bylaws shall constitute a quorum for the
transaction of business. The action of a majority of the directors present at
any lawful meeting at which there is a quorum shall, except as otherwise
provided by law or by these Bylaws, be the action of the Board.
SECTION 2. Election. Except as provided in Section 3 hereof,
directors shall be elected by the stockholders of the Company pursuant to the
procedures enumerated below:
Eligible Persons. Only persons who are nominated in
accordance with the following procedures shall be eligible for
election by the stockholders as directors of the Company.
Nominations. Nominations of persons for election as directors
of the Company may be made at a meeting of stockholders (1) by or at
the direction of the Board of Directors, (2) by any nominating
committee or person appointed by the Board of Directors or (3) by any
stockholder of the Company entitled to vote for the election of
directors at the meeting who complies with the notice procedures set
forth in this Section 2.
<PAGE> 7
- 7 - Effective 10/28/98
Nomination by Directors or Nominating Committee. Nominations
made by or at the direction of the Board of Directors or the
nominating committee or person appointed by the Board of Directors may
be made at any time prior to the stockholders' meeting. The Board of
Directors must send notice of nominations to the stockholders together
with the notice of the meeting of the stockholders; provided, however,
if the nominations are made after the notice of the meeting has been
mailed, the Board of Directors must send notice of its nominations to
the stockholders as soon as practicable.
Nomination by Stockholders. Nominations, other than those
made by or at the direction of the Board of Directors or the
nominating committee or person appointed by the Board of Directors,
shall be made pursuant to timely notice in writing to the Secretary.
To be timely, a stockholder's notice shall be delivered to or mailed
and received by the Secretary at the principal executive office of the
Company not less than sixty (60) days prior to the scheduled date of
the meeting (regardless of any postponements, deferrals or
adjournments of the meeting to a later date); provided, however, if no
notice is given and no public announcement is made to the stockholders
regarding the date of the meeting at least 75 days prior to the
meeting, the stockholder's notice shall be valid if delivered to or
mailed and received by the Secretary at the principal executive office
of the Company not less than fifteen (15) days following the day on
which the notice or public announcement of the date of the meeting was
given or made.
Contents of Notice. Nominations, other than those made by or
at the direction of the Board of Directors or the nominating committee
or person appointed by the Board of
<PAGE> 8
- 8 - Effective 10/28/98
Directors, shall set forth:
(1) as to each person whom the stockholder proposes
to nominate for election or reelection as a director, (a) the
name, age, business address and residential address of the
person, (b) the principal occupation or employment of the
person (c) the class and number of shares of capital stock of
the Company that are beneficially owned by the person, (d)
written consent by the person, agreeing to serve as director
if elected, (e) a description of all arrangements or
understandings between the person and the stockholder
regarding the nomination, (f) a description of all
arrangements or understandings between the person and any
other person or persons (naming such persons) regarding the
nomination, (g) all information relating to the person that is
required to be disclosed in solicitations for proxies for
election of directors pursuant to Rule 14a under the
Securities Exchange Act of 1934, as amended, and (h) such
other information as the Company may reasonably request to
determine the eligibility of such proposed nominee to serve as
director of the Company; and
(2) as to the stockholder giving the notice, (a) the
name, business address and residential address of the
stockholder giving the notice, (b) the class and number of
shares of capital stock of the Company that are beneficially
owned by such stockholder, (c) a description of all
arrangements or understandings between the stockholder and the
nominee regarding the nomination, and (d) a description of all
arrangements or understandings between the stockholder and any
other person or persons (naming such persons) regarding the
nomination.
<PAGE> 9
- 9 - Effective 10/28/98
Compliance with Bylaws. No person shall be eligible for
election by the stockholders as a director of the Company unless
nominated in accordance with the procedures set forth in this section
of the Bylaws. The Chairman of the Board of Directors shall, if the
facts warrant, determine and declare prior to the meeting of
stockholders that the nomination was not made in accordance with the
foregoing procedure, and if he should so determine, he shall so inform
the nominee and the stockholder who nominated the nominee as soon as
practicable and the defective nomination shall be disregarded.
Effective Date of Election of Director. Notwithstanding
anything in these Bylaws to the contrary, no election of a director
nominated by a stockholder shall become effective until the final
termination of any proceeding which may have been commenced in any
court of competent jurisdiction for an adjudication of any legal
issues incident to determining the procedure pursuant to which the
nomination of such director was brought before the stockholders,
unless and until such court shall have determined that such
proceedings are not being pursued expeditiously and in good faith.
SECTION 3. Vacancies. Whenever any vacancy shall occur in the Board
of Directors by any cause other than by reason of an increase in the number of
directors, a majority of the remaining directors, by an affirmative vote at any
lawful meeting may elect a director to fill the vacancy and to hold office
until the next annual election, or until his successor is duly elected and
qualified.
SECTION 4. Meetings. Regular meetings of the Board shall be held at
the office of the Company in the District of Columbia at times fixed by
resolution of the Board of Directors. Notice of such meetings need not be
given.
<PAGE> 10
- 10 - Effective 10/28/98
Special meetings of the Board may be called by the Chairman of the
Board, the President of the Company, or by any two directors. At least two
days' notice of all special meetings of the Board shall be given to each
director personally by telegraphic or written notice. Any meeting may be held
without notice if all of the directors are present, or if those not present
waive notice of the meeting by telegram or in writing. Special meetings of the
Board of Directors may be held within or without the District of Columbia.
SECTION 5. Committees. The Board of Directors shall, by resolution
or resolutions passed by a majority of the whole Board, designate an Executive
Committee, to consist of the Chief Executive Officer of the Company who may be
the Chairman of the Board, or the President and three additional members, and
three alternates to serve at the call of the Chief Executive Officer in case of
the unavoidable absence of one of the regular members, to be elected from the
Board of Directors. The Executive Committee shall, when the Board is not in
session, have and may exercise all of the authority of the Board of Directors
in the management of the business and affairs of the Company.
The Board of Directors may appoint other committees, standing or
special, from time to time, from among their own number, or otherwise, and
confer powers on such committees, and revoke such powers and terminate the
existence of such committees at its pleasure.
A majority of the members of any such committee shall constitute a
quorum for the purpose of fixing the time and place of its meetings, unless the
Board shall otherwise provide. All action taken by any such committee shall be
reported to the Board at its meeting next succeeding such action.
SECTION 6. Compensation of Directors. The Board of Directors shall
fix the fee to be paid to each director for attendance at any meeting of the
Board or of any committee thereof, and may,
<PAGE> 11
- 11 - Effective 10/28/98
in its discretion, authorize payment to directors of traveling expenses
incurred in attending any such meeting.
SECTION 7. Removal. Any directors may be removed from office at any
time, with or without cause, and another be elected in his place, by the vote
of the holders of record of a majority of the outstanding shares of stock of
the Company (of the class or classes by which such director was elected)
entitled to vote thereon, at a special meeting of stockholders called for such
purpose.
ARTICLE III
Officers.
SECTION 1. Officers. The officers of the Company shall be elected by
the Board of Directors and shall consist of a Chairman of the Board, a
President, a Secretary, a Treasurer, and one or more Vice Presidents, and such
other officers as the Board from time to time shall elect, with such duties as
the Board shall deem necessary to conduct the business of the Company. Any
officer may hold two or more offices (including those of the Chairman of the
Board and President) except that the offices of President and Secretary may not
be held by the same person. The Chairman of the Board shall be a director;
other officers, including any Vice Chairman and the President, may be, but are
not required to be, Directors.
SECTION 2. Term of Office. Removal. In the absence of a special
contract, all officers shall hold their respective offices for one year or
until their successors shall have been duly elected and qualified, but they or
any of them may be removed from their respective offices on a vote by a
majority of the Board.
SECTION 3. Powers and Duties. The officers of the Company shall have
such powers and
<PAGE> 12
- 12 - Effective 10/28/98
duties as generally pertain to their offices, respectively, as well as such
powers and duties as from time to time shall be conferred by the Board of
Directors and/or by the Executive Committee. In the absence of the Chairman of
the Board, if any, the President shall preside at the meetings of the Board of
Directors. In the absence of both the Chairman of the Board and the President,
and provided a quorum is present, the senior member of the Board present, in
terms of service on the Board, shall serve as Chairman pro tem of the meeting.
SECTION 4. Salaries. The salaries of all executive officers of the
Company shall be determined and fixed by the Board of Directors, or pursuant to
such authority as the Board may from time to time prescribe.
ARTICLE III-A
Indemnification of Directors and Officers.
SECTION 1. With respect to a Company officer, director, or employee,
the Company shall indemnify, and with respect to any other individual the
Company may indemnify, any person who was or is a party or is threatened to be
made a party to any threatened, pending or completed action, suit or proceeding
(an "Action"), whether civil, criminal, administrative, arbitrative or
investigative (including an action by or in the right of the Company) by reason
of the fact the person is or was a director, officer, employee, or agent of the
Company, or is or was serving at the request of the Company as a director,
officer, employee, or agent of another corporation, partnership, joint venture,
trust or other enterprise, against expenses (including attorneys' fees),
judgments, fines and amounts paid in settlement actually and reasonably
incurred by that person in connection with such Action; except in relation to
matters as to which the person shall be finally adjudged in such Action to have
<PAGE> 13
- 13 - Effective 10/28/98
knowingly violated the criminal law or be liable for willful misconduct in the
performance of the person's duty to the Company. The termination of any Action
by judgment, order, settlement, conviction, or upon a plea of nolo contendere
or its equivalent, shall not of itself create a presumption that the person was
guilty of willful misconduct.
<PAGE> 14
- 14 - Effective 10/28/98
Any indemnification (unless ordered by a court) shall be made by the
Company only as authorized in the specific case upon a determination that
indemnification of the director, officer, employee or agent is proper in the
circumstance because the person has met the applicable standard of conduct set
forth above. In the case of any director, such determination shall be made:
(1) by the Board of Directors by a majority vote of a quorum consisting of
directors who were not parties to such Action; or (2) if such a quorum is not
obtainable, by majority vote of a committee duly designated by the Board of
Directors (in which designation directors who are parties may participate)
consisting solely of two or more directors not at the time parties to the
proceeding; or (3) by special legal counsel selected by the Board of Directors
or its committee in the manner prescribed by clause (1) or (2) of this
paragraph, or if such a quorum is not obtainable and such a committee cannot be
designated, by majority vote of the Board of Directors, in which selection
directors who are parties may participate; or (4) by vote of the shareholders,
in which vote shares owned by or voted under the control of directors, officers
and employees who are at the time parties to the Action may not be voted. In
the case of any officer, employee, or agent other than a director, such
determination may be made (i) by the Board of Directors or a committee thereof;
(ii) by the Chairman of the Board of the Company or, if the Chairman is a party
to such Action, the President of the Company, or (iii) such other officer of
the Company, not a party to such Action, as such person specified in clause (i)
or (ii) of this paragraph may designate. Authorization of indemnification and
evaluation as to reasonableness of expenses shall be made in the same manner as
the determination that indemnification is permissible, except that if the
determination is made by special legal counsel, authorization of
indemnification and evaluation as to reasonableness of expenses shall be made
by
<PAGE> 15
- 15 - Effective 10/28/98
those entitled hereunder to select such legal counsel.
Expenses incurred in defending an Action for which indemnification may
be available hereunder shall be paid by the Company in advance of the final
disposition of such Action as authorized in the manner provided in the
preceding paragraph, subject to execution by the person being indemnified of a
written undertaking to repay such amount if and to the extent that it shall
ultimately be determined by a court that such indemnification by the Company is
not permitted under applicable law.
It is the intention of the Company that the indemnification set forth
in this Section of Article III-A, shall be applied to no less extent than the
maximum indemnification permitted by law. In the event that any right to
indemnification or other right hereunder may be deemed to be unenforceable or
invalid, in whole or in part, such unenforceability or invalidity shall not
affect any other right hereunder, or any right to the extent that is not deemed
to be unenforceable. The indemnification provided herein shall be in addition
to, and not exclusive of, any other rights to which those indemnified may be
entitled under any Bylaw, agreement, vote of stockholders, or otherwise, and
shall continue as to a person who has ceased to be a director, officer,
employee, or agent and inure to the benefit of such person's heirs, executors,
and administrators.
SECTION 2. In any proceeding brought by a stockholder in the right of
the Company or brought by or on behalf of the stockholders of the Company, no
monetary damages shall be assessed against an officer or director. The
liability of an officer or director shall not be limited as provided in this
section if the officer or director engaged in willful misconduct or a knowing
violation of the criminal law or of any federal or state securities law.
<PAGE> 16
- 16 - Effective 10/28/98
ARTICLE IV
Checks, Notes, Etc.
SECTION 1. All checks and drafts on the Company's bank accounts and
all bills of exchange and promissory notes, and all acceptances, obligations
and other instruments for the payment of money, shall be signed by such officer
or officers, agent or agents, as shall be thereunto authorized from time to
time by the Board of Directors.
SECTION 2. Shares of stock and other interests in other corporations
or associations shall be voted by such officer or officers as the Board of
Directors may designate.
SECTION 3. Except as the Board of Directors shall otherwise provide,
all contracts expressly approved by the Board shall be signed on behalf of the
Company by the Chairman of the Board, the President, or a Vice President.
ARTICLE V
Capital Stock.
SECTION 1. Certificate for shares. The interest of each stockholder
of the Company shall be evidenced by a certificate or certificates for shares
of stock in such form as required by law and as the Board of Directors may from
time to time prescribe. The certificates of stock shall be signed by the
President or a Vice President and the Secretary or an Assistant Secretary and
sealed with the seal of the Company. Such seal may be a facsimile.
Where any such certificate is countersigned by a transfer agent other
than the Company, or an employee of the Company, or is countersigned by a
transfer clerk and is registered by a registrar, the signatures of the
President or Vice President and the Secretary or Assistant Secretary may be
<PAGE> 17
- 17 - Effective 10/28/98
facsimiles.
In case any officer who has signed, or whose facsimile signature has
been placed upon such certificate, shall have ceased to be such officer before
such certificate is issued, it may nevertheless be issued by the Company with
the same effect as if such officer had not ceased to hold such office at the
date of its issue.
SECTION 2. Transfer of Shares. The shares of stock of the Company
shall be transferable on the books of the Company by the holders thereof in
person or by duly authorized attorney, upon surrender and cancellation of
certificates for a like number of shares, with duly executed assignment and
power of transfer endorsed thereon or attached thereto, and with such proof of
the authenticity of the signatures as the Company or its agents may reasonably
require.
SECTION 3. Lost, Stolen or Destroyed Certificates. No certificate of
stock claimed to have been lost, destroyed or stolen shall be replaced by the
Company with a new certificate of stock until the holder thereof has produced
evidence of such loss, destruction or theft, and has furnished indemnification
to the Company and its agents to such extent and in such manner as the proper
officers or the Board of Directors may from time to time prescribe.
ARTICLE VI
Corporate Records.
SECTION 1. Where Kept. The books, records and papers belonging to
the business of the Company, and the corporate seal, shall be kept at the
office of the Company in the District of Columbia.
SECTION 2. Inspection. Any stockholder or stockholders, who shall
have been such for at
<PAGE> 18
- 18 - Effective 10/28/98
least six months, or who shall be the holder or holders of record of at least
five percent of all the outstanding shares of stock of the Company, desiring to
inspect the books or records of the Company, shall present to the Board of
Directors or the Executive Committee an application for such inspection,
specifying the particular books or records to be inspected and the purpose for
which such inspection is desired. If, upon such application, the Board of
Directors or Executive Committee deems such inspection is sought for a
legitimate purpose connected with the interest of the applicant as a
stockholder of the Company, such application shall be granted and a time and
place for the inspection shall be specified. The stock and transfer books of
the Company shall at all times, during business hours, be open to the
inspection of stockholders. The Board of Directors shall have the power from
time to time to establish general regulations conferring upon stockholders such
further rights with respect to inspection of books and records of the Company
as the Board shall deem proper.
ARTICLE VII
Fiscal Year.
The fiscal year of the Company shall begin on the 1st day of October
in each year and shall end on the 30th day of September following.
ARTICLE VIII
Corporate Seal.
The seal of the Company shall be circular in form and there shall be
inscribed thereon -- Washington Gas Light Company -- a Corporation of the
District of Columbia and Virginia -- Originally Chartered by Congress in 1848.
<PAGE> 19
- 19 - Effective 10/28/98
ARTICLE IX
Amendments.
The Board of Directors shall have power to make and alter (unless the
stockholders shall in any particular instance have otherwise prescribed) any
Bylaws of the Company. Such action may be taken at any meeting of the Board by
the affirmative vote of a majority of the total number of directors, provided
that notice of the proposed change shall have been given to all directors prior
to the meeting, or that all of the directors shall be present at the meeting.
Any Bylaws made or altered by the Board of Directors may be altered or repealed
at any time by the stockholders.
<PAGE> 1
EXHIBIT 12.0
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
Years Ended September 30
(Dollars in Thousands)
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
------------ ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 37,473 $ 33,599 $ 29,876 $ 30,932 $ 30,899
Amortization of Debt Premium,
Discount and Expense 370 299 256 315 367
Interest Component of Rentals 12 17 96 56 34
------------ ------------- ------------- ------------- -------------
Total Fixed Charges $ 37,855 $ 33,915 $ 30,228 $ 31,303 $ 31,300
============ ============= ============= ============= =============
EARNINGS:
Net Income $ 68,629 $ 82,019 $ 81,591 $ 62,909 $ 60,459
Add:
Income Taxes Applicable to
Operating Income 38,006 47,864 49,376 37,514 37,264
Income Taxes Applicable to
Other Income (Loss) - Net 1,799 577 (629) (730) 326
Total Fixed Charges 37,855 33,915 30,228 31,303 31,300
------------ ------------- ------------- ------------- -------------
Total Earnings $ 146,289 $ 164,375 $ 160,566 $ 130,996 $ 129,349
============ ============= ============= ============= =============
Ratio of Earnings to Fixed Charges 3.9 4.8 5.3 4.2 4.1
============ ============= ============= ============= =============
</TABLE>
<PAGE> 1
EXHIBIT 12.1
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividends
Years Ended September 30
(Dollars in Thousands)
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
--------------- --------------- ---------------- --------------- ----------------
FIXED CHARGES AND PRE-TAX PREFERRED
STOCK DIVIDENDS
<S> <C> <C> <C> <C> <C>
Preferred Dividends $ 1,331 $ 1,331 $ 1,332 $ 1,333 $ 1,335
Effective Income Tax Rate .3671 .3713 .3740 .3690 .3834
Complement of Effective Income
Tax Rate (1 - Tax Rate) .6329 .6287 .6260 .6310 .6166
Pre-tax Preferred Dividends $ 2,103 $ 2,117 $ 2,128 $ 2,113 $ 2,165
=============== =============== ================ ============= ================
Interest Expense $ 37,473 $ 33,599 $ 29,876 $ 30,932 $ 30,899
Amortization of Debt Premium,
Discount and Expense 370 299 256 315 367
Interest Component of Rentals 12 17 96 56 34
--------------- --------------- ---------------- --------------- ----------------
Total Fixed Charges 37,855 33,915 30,228 31,303 31,300
Pre-tax Preferred Dividends 2,103 2,117 2,128 2,113 2,165
--------------- --------------- ---------------- --------------- ----------------
Total $ 39,958 $ 36,032 $ 32,356 $ 33,416 $ 33,465
=============== =============== ================ ============= =============
EARNINGS:
Net Income $ 68,629 $ 82,019 $ 81,591 $ 62,909 $ 60,459
Add:
Income Taxes Applicable to
Operating Income 38,006 47,864 49,376 37,514 37,264
Income Taxes Applicable to
Other Income (Loss) - Net 1,799 577 (629) (730) 326
Total Fixed Charges 37,855 33,915 30,228 31,303 31,300
--------------- --------------- ---------------- --------------- ----------------
Total Earnings $ 146,289 $ 164,375 $ 160,566 $ 130,996 $ 129,349
=============== =============== ================ =============== ================
Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends 3.7 4.6 5.0 3.9 3.9
=============== =============== ================ =============== ================
</TABLE>
<PAGE> 1
Washington Gas Light Company
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands, Except Per Share Data)
<S> <C> <C> <C> <C> <C>
Operating revenues $1,040,618 $1,055,754 $ 969,778 $ 828,748 $ 914,863
Cost of gas 575,786 572,925 469,925 390,041 462,195
---------- ---------- ---------- ---------- ----------
Net revenues $ 464,832 $ 482,829 $ 499,853 $ 438,707 $ 452,668
---------- ---------- ---------- ---------- ----------
Net income $ 68,629 $ 82,019 $ 81,591 $ 62,909 $ 60,459
Dividends on preferred stock 1,331 1,331 1,332 1,333 1,335
---------- ---------- ---------- ---------- ----------
Net income applicable to common stock $ 67,298 $ 80,688 $ 80,259 $ 61,576 $ 59,124
---------- ---------- ---------- ---------- ----------
Earnings per average common share--basic $ 1.54 $ 1.85 $ 1.85 $ 1.45 $ 1.41
---------- ---------- ---------- ---------- ----------
Earnings per average common share--diluted $ 1.54 $ 1.85 $ 1.85 $ 1.45 $ 1.41
---------- ---------- ---------- ---------- ----------
Total assets at year-end $1,682,433 $1,552,032 $1,464,601 $1,360,138 $1,332,954
---------- ---------- ---------- ---------- ----------
Property, plant and equipment--net $1,319,501 $1,217,137 $1,130,574 $1,056,058 $ 995,021
---------- ---------- ---------- ---------- ----------
Capital expenditures $ 158,874 $ 139,871 $ 124,414 $ 112,715 $ 119,796
---------- ---------- ---------- ---------- ----------
Long-term obligations at year-end $ 428,929 $ 432,368 $ 353,893 $ 329,051 $ 342,308
---------- ---------- ---------- ---------- ----------
COMMON STOCK DATA
Annualized dividends per share $ 1.20 $ 1.18 $ 1.14 $ 1.12 $ 1.11
Dividends declared per share $ 1.1950 $ 1.1700 $ 1.1350 $ 1.1175 $ 1.1050
Book value per share $ 13.86 $ 13.48 $ 12.79 $ 11.95 $ 11.51
Return on average common equity 11.2% 14.1% 15.0% 12.3% 12.5%
Yield on book value 8.6% 8.7% 8.9% 9.4% 9.6%
Payout ratio 77.6% 63.2% 61.4% 77.1% 78.4%
Common shares outstanding--year-end (thousands) 43,839 43,700 43,703 42,932 42,187
CAPITALIZATION AT YEAR-END
Common shareholders' equity $ 607,755 $ 589,035 $ 558,809 $ 513,044 $ 485,504
Preferred stock 28,424 28,430 28,440 28,471 28,498
Long-term debt 428,641 431,575 353,893 329,051 342,270
---------- ---------- ---------- ---------- ----------
Total $1,064,820 $1,049,040 $ 941,142 $ 870,566 $ 856,272
---------- ---------- ---------- ---------- ----------
GAS SALES & DELIVERIES (thousands of therms)
Gas sold and delivered
Residential 615,786 665,452 739,603 596,499 672,958
Commercial and industrial--
Firm 345,809 426,831 473,645 403,177 443,246
Interruptible 73,554 147,375 182,730 247,600 236,068
Electric generation -- 51 1,808 112,523 86,183
---------- ---------- ---------- ---------- ----------
1,035,149 1,239,709 1,397,786 1,359,799 1,438,455
---------- ---------- ---------- ---------- ----------
Gas delivered for others
Firm 110,542 27,574 3,772 -- --
Interruptible 243,166 185,487 84,788 61,467 26,147
Electric generation 93,721 94,022 57,689 18,538 --
---------- ---------- ---------- ---------- ----------
447,429 307,083 146,249 80,005 26,147
---------- ---------- ---------- ---------- ----------
Total 1,482,578 1,546,792 1,544,035 1,439,804 1,464,602
---------- ---------- ---------- ---------- ----------
OTHER STATISTICS
Customer meters 819,719 798,739 772,281 750,849 725,960
Degree days 3,662 3,876 4,570 3,660 4,311
Percent colder (warmer) than normal (5.1)% 0.5% 18.6% (5.2)% 11.8%
</TABLE>
22
<PAGE> 2
Washington Gas Light Company
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Certain matters discussed in this report, excluding historical information,
include forward-looking statements. Certain words, such as, but not limited to,
"estimates," "expects," "anticipates," "intends," "believes," and variations of
these words, identify forward-looking statements that involve uncertainties and
risks. Although Washington Gas Light Company (company) believes such
forward-looking statements are based on reasonable assumptions, it cannot give
assurance that every objective will be reached. The company makes such
statements in reliance on the safe harbor protections provided under the Private
Securities Litigation Reform Act of 1995.
As required by such Act, the company hereby identifies the following
important factors, which are not intended to cover all events, that could cause
actual results to differ materially from any results projected, forecasted,
estimated or budgeted by the company in forward-looking statements: (1) risks
and uncertainties impacting the company as a whole primarily related to changes
in general economic conditions in the United States; (2) changes in laws and
regulations to which the company is subject, including tax, environmental and
employment laws and regulations; (3) the effect of fluctuations in weather from
normal levels; (4) variations in prices of natural gas and competing energy
sources; (5) the company's ability to develop new markets and product and
service offerings as well as to maintain existing markets and the expenditures
required to develop and provide such products and services; (6) conditions of
the capital markets utilized by the company to access capital to finance
operations and capital expenditures; (7) improvements in products or services
offered by competitors; (8) the cost and effects of legal and administrative
claims and proceedings against the company or which may be brought against the
company; and (9) estimates of future costs or the effect on future operations
as a result of events that could result from the Year 2000 issue described
further herein.
COMPETITION
COMPETITION WITH OTHER FUELS
In its core utility business, the company faces competition based on its
customers' preferences for its product, natural gas, compared to other energy
products and also in relation to the price of those products. Currently, the
most significant product-side competition is between natural gas and
electricity in the residential market. This portion of the company's business
currently contributes a substantial amount of the company's net income. The
company continues to derive the majority share of the new residential
construction market in its service territory and believes customer preference
for natural gas allows it to maintain its strong presence.
Currently, the company generally maintains a price advantage over
electricity in the jurisdictions it serves. However, as discussed further
below, restructuring in both the natural gas and electric industries is leading
to changes in traditional pricing models. As electric utilities restructure
their services, certain functions of their business are expected to move toward
market-based pricing, with third-party providers of electricity participating
in retail markets. Electric restructuring is likely to result in lower
comparative costs for electric service and increased competition for the
company.
In the interruptible market, where customers must be capable of using a fuel
other than natural gas when demand by the company's firm customers peaks, fuel
oil is the most significant competing energy alternative. The company's success
in this market is dependent largely on changes in gas prices versus oil prices.
The price of natural gas, which is developed primarily from domestic sources,
is influenced greatly by the relationship between supply and demand. However,
the price of oil, much of which comes from foreign sources, is impacted greatly
by political events.
NATURAL GAS INDUSTRY RESTRUCTURING AND COMPANY STRATEGY
The natural gas industry, which has traditionally included producers,
interstate pipelines and local distribution companies (LDCs) such as the
company, has a long history and has undergone many changes since its inception.
Those changes have been the most significant over the past 10 years. The
driving forces behind the changes are customers' and regulators' desires to
promote competition in situations where it is economically beneficial to
consumers.
The restructuring of the natural gas industry generally began at the
producer level with the passage of the Natural Gas Policy Act in 1978, which
brought about a gradual decontrol of the wellhead price of natural gas and
allowed for market-based prices. In the pipeline segment of the industry,
Federal Energy Regulatory Commission (FERC) Order No. 636 separated the
merchant function of selling natural gas from the interstate transportation and
storage services of the pipeline companies in order to increase competition. As
a result of FERC Order No. 636, pipeline companies are now responsible for
providing gas storage and transportation services, and LDCs have taken on the
responsibility and risk of separately obtaining storage and transportation
capacity from pipelines and procuring competitive natural gas supplies from
producers and marketers. Transmission and storage rates charged by pipelines
are still regulated by FERC, but negotiated, market-based rates are beginning
to appear.
Traditionally, as a natural gas utility, the company has provided a
"bundled" service to customers, including two primary functions: (1) the
merchant function; and (2) the core utility, or delivery function. As the
industry has changed, the company has changed its view of these functions. The
following discussion describes the merchant and core utility functions as they
exist today, and how the company expects them to change over time. In addition,
the company's current plans for energy-related activities are discussed below.
The Merchant Function
Historically, the company has purchased natural gas for its customers from
producers, and has contracted with interstate pipeline companies to have the
natural gas delivered to the entrance point of its distribution system. Subject
to regulatory prudence reviews, the company has passed on the costs paid to the
producers and the interstate pipelines directly to its customers, generally
without the company having any opportunity for profit or any risk of loss.
23
<PAGE> 3
Washington Gas Light Company
The merchant function is the industry segment currently experiencing the
greatest change. Customers in many states are being offered the opportunity to
purchase their natural gas from unregulated marketers as well as from their
regulated local distribution company. As discussed further below, in the
company's major jurisdictions, state regulatory and company initiatives have
culminated in customer choice programs covering nearly all customer classes.
Under these programs, unregulated gas marketers compete for natural gas sales
to customers and have the opportunity to make a profit or incur a loss from
them. One of the company's subsidiaries, Washington Gas Energy Services, Inc.
(WGES), is an unregulated gas marketer. The separating or unbundling of the
merchant function from the core utility or delivery function allows unregulated
marketers and unregulated marketing subsidiaries of other utility companies to
gain access to the company's customers. In addition, price competition among
the company and gas marketers for the sale of the natural gas commodity has
become more prevalent. It is expected that natural gas prices charged to
customers will tend to decline as a result of this competition.
Ultimately, the company expects regulated LDCs to play a much smaller role
in the merchant function. The company may ultimately exit the merchant function
as more customers buy natural gas from unregulated marketers. During this
transition period, the company will continue to have certain obligations under
long-term contracts to purchase both natural gas from producers and
transportation capacity from interstate pipeline companies. Accordingly, the
company's strategy will focus on recovering contractual costs and maximizing
the value of contractual assets. The company currently plans to avoid some
activities that are often considered part of the merchant function, such as
commodity trading, exploring for and producing natural gas, operating
interstate natural gas pipelines, or expanding storage facilities beyond
current capacity.
The Core Utility or Delivery Function
Through the construction of its distribution system, the company has committed
over 90% of its assets to the delivery of natural gas to customers. The core
utility function currently includes the infrastructure needed to provide such
customer services as reading meters, preparing bills and answering telephone
inquiries. Historically, the company's local regulatory commissions have
allowed it to earn a fair rate of return on the capital invested in its
distribution system and to recover expenses such as customer service and
maintenance costs, taxes and depreciation.
The high cost of constructing a duplicate distribution system is a strong
barrier to potential competitors for the delivery function. Thus, the company
does not expect direct competition from another natural gas distributor. In
addition, the company believes that bypass of its facilities by other potential
providers of delivery service is unlikely to be a significant threat, primarily
because of the nature of the customer base and the location of customers in
relation to the interstate pipelines. The company expects that the local
regulatory commissions will continue to function as surrogates for competition,
determining the prices the company charges its customers and the terms and
conditions of service for the delivery function. Because of continuing
regulation, the company does not expect the risk profile of the delivery
function to change, nor does it expect the profitability of the delivery
function to decline as a result of customers purchasing natural gas from
unregulated marketers. The company plans to continue to construct, operate and
maintain its natural gas distribution system, increase the efficiency of its
operations, add customers profitably and compete against other fuels such as
electricity and oil.
Although the company currently provides customer services as part of its
core utility function, these services can potentially be offered economically
by competitors. The company is continuing to reduce the cost of performing
these functions, with a goal of moving that cost to a market level. Once at
market, the company may or may not continue its role as the provider of
customer services or may offer these services at the wholesale level, depending
on its competitive position, customer demand and regulatory policy preferences.
Certain activities that could be offered as separate services include billing,
meter reading and other services on customers' premises. As customer bills
begin to display costs separately for each service component, customers will
become more familiar with these costs, enabling them to compare prices offered
by competitors in the future. Currently, the company's customer bills display
natural gas commodity costs and charges for certain appliance service functions
separate from the delivery service charge.
Energy-Related Activities
The company believes that success in future energy markets will not be driven
by profits from one product or service, but instead will hinge on a company's
ability to provide a package encompassing multiple products and services that
consumers value at competitive prices. As such, the company and its
subsidiaries currently provide certain energy-related services to consumers,
including the following:
1. Selling natural gas in competition with unregulated marketers and
unregulated marketing subsidiaries of other utility companies;
2. Providing commercial energy services by designing and renovating
mechanical heating, ventilating and air conditioning systems; and
3. Financing gas appliances and certain other equipment for residential
and small commercial customers.
At the present time, the company's energy-related activities are not
significant to its results of operations. The company intends to continue
competing in the energy-related markets listed above, and potentially to enter
into others.
UNBUNDLING IN THE COMPANY'S MAJOR JURISDICTIONS
Natural Gas
The company has actively promoted competition for the sale of natural gas, as
it believes that competition supports greater choice in energy suppliers and,
therefore, increased customer satisfaction with natural gas. The company's goal
is to provide customers with the products, services and conveniences they want
and, in addition, to gain new opportunities to profit from the sale of natural
gas through its gas-marketing subsidiary, WGES. The company made progress
towards this goal during fiscal year 1998 by advancing its unbundling
initiatives in each of its major jurisdictions. The table on page 25 shows the
status of the unbundling programs in the company's major jurisdictions as of
September 30, 1998.
24
<PAGE> 4
Washington Gas Light Company
STATUS OF NATURAL GAS UNBUNDLING
IN THE COMPANY'S MAJOR JURISDICTIONS
As of September 30, 1998
<TABLE>
<CAPTION>
Approximate Number Percentage of Eligible
Jurisdiction Customer Class Effective Date of Customers Eligible Customers Participating
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Maryland Residential 9/1/98 100,000 26%
Commercial 6/1/98 23,820 35%
Interruptible (40,000+ Therms) 5/87 290 100%
Virginia Residential 1/1/99 30,000 --
Commercial 1/1/99 2,000 --
Interruptible (60,000+ Therms) 6/88 220 93%
District of Columbia Residential 1/1/99 13,000 --
Commercial (Small) Pending approval -- --
Commercial (Large) 4/1/98 250 22%
Interruptible (60,000+ Therms) Pending approval -- --
Interruptible (250,000+ Therms) 1/88 50 89%
</TABLE>
Unbundling initiatives in Maryland continue to set the pace in the region.
The company's Customer Choice pilot program for Maryland residential customers
is in its third year and has expanded rapidly in the past year. During fiscal
year 1998, the company received permission to increase the number of eligible
participants from 25,000 to 100,000 (approximately 34% of the company's
Maryland residential customers).
In Virginia, fiscal year 1998 saw important progress towards unbundling. All
of the company's interruptible customers in Virginia may choose their supplier
of the natural gas commodity. Also during 1998, the State Corporation
Commission of Virginia (SCC of VA) approved the company's request to begin a
two-year pilot program for firm commercial and residential customers, allowing
eligible customers to choose their natural gas suppliers. In the first year of
the program, up to 10% of the company's firm customers in Virginia will be
eligible to participate in the program, increasing to 20% in the second year.
In the District of Columbia, effective April 1, 1998, large firm commercial
customers (those with at least 60,000 in annual natural gas therm deliveries)
became eligible to purchase gas from third-party suppliers. Additionally, in
fiscal year 1998, the Public Service Commission of the District of Columbia
(PSC of DC) approved the company's request to offer a pilot customer choice
program to residential customers, beginning January 1, 1999.
Electricity
The electric industry still lags behind the natural gas industry in its
progress toward restructuring and deregulation, but the pace of change has
accelerated at both the local and national levels. Restructuring in the
electric industry will likely result in the division of integrated electric
utilities into their component parts of generation, transmission and local
distribution. The company expects that, similar to the gas industry, the
transmission and distribution of electricity will remain regulated, while the
generating function, much like the merchant function in the natural gas
industry, will move to a competitive environment with market-based pricing.
Direct customer access to electricity providers at the retail level was
implemented in several states in early 1998 and has been studied in virtually
all states. Regulatory changes at the state level should increase competition
among electricity providers and in relation to competing fuels, such as
natural gas. Over time, this competition should tend to reduce prices to
consumers.
All of the company's major jurisdictions have investigated, or are in the
process of investigating, the advisability of mandating retail electric
unbundling. The company supports moving to an unbundled electric market and has
actively participated in proceedings in its jurisdictions. The Public Service
Commission of Maryland (PSC of MD) issued an order that adopted a phased
implementation of retail electric unbundling over a three-year period,
commencing in 2000. The PSC of MD also directed the investor-owned electric
companies in Maryland to fully unbundle their rates prior to the deregulation
of generation. These actions are consistent with testimony submitted by the
company to the PSC of MD.
In the District of Columbia, the PSC of DC is conducting a review of
electric industry restructuring. The company has actively participated in the
matter to date, submitting comments which call for the unbundling of electric
services and permit competition in providing electricity to consumers.
The Virginia legislature passed a statute that calls for the provision of
customer choice of electricity supplier beginning in 2004. Pilot programs are
likely to be implemented in the interim. Indeed, two Virginia electric
companies submitted pilot program filings in 1998.
25
<PAGE> 5
Washington Gas Light Company
As local regulatory commissions move forward on electric deregulation, the
company is planning to take advantage of resulting new opportunities. Although
local opportunities are developing more slowly than originally anticipated,
WGES holds a power marketing certificate from the FERC and plans to sell
electricity.
INDUSTRY CONSOLIDATION AND CORPORATE STRUCTURE
The energy industry, much like other industries that are becoming increasingly
deregulated and more competitive, has seen a number of consolidations,
combinations, disaggregations and other strategic alliances and restructurings.
This is being driven, in part, as energy companies seek to offer a broader
range of energy services to compete more effectively in attracting and
retaining customers. For example, affiliations with other operating utilities
could potentially result in economies and synergies, and could provide a means
to offer customers a more complete range of energy services. Consolidation will
present combining entities with the challenges of remaining focused on the
customer and integrating different organizations. Others in the energy industry
are discontinuing operations in certain portions of the energy industry or
divesting portions of their business and facilities.
The company, from time to time, performs studies, and in some cases holds
discussions regarding utility and energy-related investments and transactions
with other companies. The ultimate impact on the company of any such
investments and transactions that may occur cannot be determined at this time.
The company is also studying the possibility of changing its corporate
structure to clarify the separation of regulated from unregulated operations,
if appropriate for business and regulatory reasons. One structural option the
company is considering is the formation of a parent holding company like that
of many other utilities.
ACCOUNTING FOR REGULATED ACTIVITIES
As the industry continues to address changes that have the effect of increasing
the level of competition the company faces, the cost-of-service regulation the
company uses to ensure it is adequately compensated for the costs it incurs
providing its regulated services will continue to evolve. Non-traditional
ratemaking initiatives and market-based pricing of products and services could
have additional financial implications for the company. The company records the
results of its regulated activities in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71). In certain circumstances, SFAS No. 71 allows
entities whose rates are determined by third-party regulators to defer costs as
"regulatory" assets in the balance sheet to the extent that they are expected
to be recovered in future rates. However, as competition increases and the
company becomes more impacted by deregulation and its attendant effects, the
company may not be able to continue to apply SFAS No. 71 to all or parts of its
business. If this were to occur, the company would be required to apply
accounting standards utilized by unregulated enterprises. This would require
the charging to expense costs previously deferred as regulatory assets in the
Consolidated Balance Sheets at the time the company determined the provisions
of SFAS No. 71 no longer apply. The composition of regulatory assets is shown
in Note 1 to the Consolidated Financial Statements. While the company believes
the provisions of SFAS No. 71 continue to apply to its regulated operations,
the changing nature of its business requires it to continually assess the
impact of those changes on its accounting policies.
ORGANIZATIONAL REDESIGN
In 1996, in response to changing requirements and greater competition in the
markets in which it operates, the company announced and began implementing a
corporate reorganization. The reorganization moved the company away from a
traditional, functional structure and towards a more customer-focused
organization designed to encourage innovation, initiative and teamwork. The new
structure flattened the corporate hierarchy and resulted in fewer supervisory
positions.
In the course of the reorganization, the company incurred various expenses,
including professional consulting fees and costs associated with a voluntary
separation pay program for certain eligible supervisory employees. In fiscal
year 1996, the company recorded non-recurring operation expenses of $13.4
million related to the reorganization.
GAS SUPPLY AND CAPACITY
The company has the responsibility of acquiring both sufficient gas supplies to
meet customer requirements and appropriate pipeline capacity to ensure delivery
to the company's distribution system.
While considering the continuing trend toward unbundling the sale of the gas
commodity from the delivery of the commodity to the customer, the company must
ensure that it enters into flexible contracts for supply and capacity levels
that will allow it to remain competitive. The company has adopted a diversified
portfolio approach designed to satisfy the supply and deliverability
requirements of its customers. The company maintains numerous sources of
supply, dependable transportation and storage arrangements and its own
substantial storage and peaking capabilities to meet the demands of its
customers.
The company has 12 long-term gas supply contracts with various producers or
marketers that expire between fiscal years 1999 and 2004. Under these
contracts, the company can purchase up to 100 million dekatherms of natural gas
per year. The company acquires the balance of its supplies at market prices
under shorter term contracts.
To meet its anticipated annual supply requirements, the company expects to
utilize firm city-gate (volumes of gas delivered to the entry point of the
company's distribution system) supply arrangements, firm transportation and
storage retained by the company, off-system peaking resources under contract,
and company-owned peak shaving facilities. At September 30, 1998, the company
had contracts for firm storage and transportation with four pipeline suppliers
that are directly connected to the company's distribution system, as well as
four upstream pipelines. The company has entered into contracts with unregulated
marketers to use the company's firm storage and transportation rights to meet
the company's city-gate delivery needs and to make off-system sales when
26
<PAGE> 6
Washington Gas Light Company
such storage and transportation rights are underutilized. Most of the company's
storage and transportation rights are assigned to these marketers; the company
uses several marketers so as to diversify risks. The company continues to pay
the fixed charges associated with the firm storage and transportation contracts
released to the unregulated marketers. Current pipeline storage and
transportation contracts have termination dates ranging from fiscal years 1999
to 2016.
The company includes the cost of natural gas and pipeline services in
purchased gas costs and recovers these costs in the rates charged to customers,
subject to regulatory review. The company's jurisdictional tariffs contain gas
cost mechanisms that provide for the recovery of the actual invoice cost of gas
applicable to firm customers. The company believes it prudently entered into
its gas contracts and that the costs being incurred should be recoverable from
customers. If the current gas cost recovery mechanisms are removed in the
future as part of unbundling or other initiatives, the company could be
impacted to the extent its gas costs are not competitive and there are no other
satisfactory regulatory mechanisms available to recover any costs that would
exceed market prices. The company continues to seek opportunities to
restructure existing contracts to maximize the competitiveness of its gas
supply portfolio. See Note 10 to the Consolidated Financial Statements for a
further discussion of the commitments under the contracts previously described.
The company continues to pay to the pipelines transition costs associated
with the implementation of FERC Order No. 636. This matter is discussed in Note
10 to the Consolidated Financial Statements.
RESULTS OF OPERATIONS
EARNINGS
1998 vs. 1997
Net income applicable to common stock for 1998 was $67.3 million, or $13.4
million lower than the results for the same period last year. Basic and diluted
earnings per average common share were $1.54, or $0.31 per average common share
lower than in fiscal year 1997. Average common shares outstanding declined
slightly from 1997, primarily due to reduced shares from the company's
repurchase of 88,700 common shares during the first quarter of fiscal year
1998, partially offset by new shares issued through the company's Dividend
Reinvestment and Common Stock Purchase Plan (DRP) and Employee Savings Plans.
The company earned 11.2% on average common equity in 1998 compared to 14.1% in
1997. The following factors contributed to the change in earnings:
NET INCOME APPLICABLE TO COMMON STOCK
(MILLIONS)
** this graph presented the Company's Net
Income Applicable to Common Stock
for 1993-1998
<TABLE>
<CAPTION>
Year Millions of Dollars
<S> <C>
1993 53.7
1994 59.1
1995 61.6
1996 80.3
1997 80.7
1998 67.3
</TABLE>
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE
** this graph presented the Company's Basic and Diluted
Earnings Per Average Common share
for 1993-1998
<TABLE>
<CAPTION>
Year Dollars
<S> <C>
1993 1.31
1994 1.41
1995 1.45
1996 1.85
1997 1.85
1998 1.54
</TABLE>
Lower Net Revenues. The primary reason for the decline in earnings this year
was 5.5% warmer weather than last year, which caused lower firm therm
deliveries and associated net revenues. A 2.6% increase in the number of
customer meters reduced the effects of the warmer weather experienced during
this heating season.
Increased Operation & Maintenance Expenses. Operation and maintenance
expenses in the current year increased primarily because of: (1) $8.6 million
in additional costs associated with the company's technology initiatives,
including the Year 2000 program; and (2) a $1.6 million non-recurring charge to
write-off certain regulatory assets. Lower labor costs in the current year
because of greater operating efficiencies and the impact of fewer employees
served to partially offset these increased costs.
Increased Other Income (Loss)-Net. $3.2 million in after-tax gains recorded
from sales of the company's retail propane assets and investments in certain
venture capital funds were the primary reasons for the increase in other income
(loss)-net.
Increased Depreciation and Interest Expense. Investments in new facilities
to meet customer growth and replace existing capacity, which the company
partially financed with long-term debt, caused increases in depreciation and
interest expense.
1997 vs. 1996
Net income applicable to common stock for 1997 was $80.7 million, reflecting a
slight increase over 1996. Basic and diluted earnings per average common share
were $1.85, or the same as for 1996. Average common shares outstanding
increased by less than 1.0% over 1996. The company earned 14.1% on average
common equity in 1997 compared to 15.0% in 1996. The following factors
contributed to the change in earnings:
Lower Net Revenues. Weather during 1997 was 15.2% warmer than the prior
year. The warmer weather reduced the total amount of firm therm deliveries in
1997 and, as a result, lowered net revenues, despite a 3.4% increase in
customer meters.
Lower Operation & Maintenance Expenses. Operation expenses declined by more
than the drop in net revenues, primarily reflecting the absence in 1997 of
non-recurring costs recorded in 1996 associated with the company's redesign of
its organization and improved operating efficiencies in 1997.
27
<PAGE> 7
Washington Gas Light Company
Increased Other Income (Loss)-Net. Higher other income (loss)-net included
$1.25 million of earnings generated from the company's energy-related
businesses, an increase of $0.9 million from 1996.
NET REVENUES
Net revenues decreased by $18.0 million, or 3.7%, in 1998 and decreased by
$17.0 million, or 3.4%, in 1997. The following table provides factors
contributing to the changes in net revenues between years.
COMPOSITION OF THE CHANGES IN NET REVENUES
<TABLE>
<CAPTION>
Increase/(Decrease)
From Prior Year
(Millions) 1998 1997
- ------------------------------------------------------------------
<S> <C> <C>
Gas Delivered to Firm Customers:
Volumes $(15.7) $(25.8)
Rate Increases 1.0 0.2
Gas Delivered to Interruptible Customers (1.8) 2.9
Gross Receipts Taxes (4.0) 0.2
Other 2.5 5.5
------ ------
$(18.0) $(17.0)
====== ======
</TABLE>
1998 vs. 1997
Gas Delivered to Firm Customers. The level of gas delivered to firm customers
is highly sensitive to the variability of weather since such a large portion of
the company's deliveries of natural gas is used for space heating. The
company's rates are based on normal weather. Weather for 1998 was 5.1% warmer
than normal while weather for 1997 was 0.5% colder than normal. For a
comparison of actual weather to normal for the last five years, see the
Selected Financial Data on page 22. The company has no weather normalization
tariff provision in any of its jurisdictions. However, the company has
declining block rates in its Maryland and Virginia jurisdictions that reduce
the impact on net revenues of deviations in weather from normal.
Therm deliveries to firm customers, which include the amounts reflected in
the Selected Financial Data shown on page 22 for residential gas sold and
delivered, firm commercial and industrial gas sold and delivered, and firm gas
delivered for others, decreased by 47.7 million therms (4.3%) in 1998, causing
a decrease in net revenues of $15.7 million. This decline was due to 5.5%
warmer weather in 1998, partially offset by a 2.6% increase in customer meters.
The effect of increased rates on net revenues in 1998 amounted to $1.0
million. In July 1998, the SCC of VA granted the company's distribution
subsidiary, Shenandoah Gas Company, an increase in annual revenues of $1.4
million, effective December 28, 1997. The company did not have any rate
requests outstanding in any of its major jurisdictions at September 30, 1998.
Under delivery service tariffs, certain firm commercial and residential
customers are eligible to acquire their gas supply from the company (bundled
gas service) or a third-party supplier, such as unregulated marketers and
unregulated subsidiaries of other utility companies. The company continues to
serve all customers by delivering gas through its distribution system (delivery
service), which results in the company earning a regulated return on this
service. Customers that do not acquire their gas supply from the company do
not affect net revenues since margins generated from delivering customer-owned
gas are equivalent to those earned on bundled gas service. In those instances
where customers choose to buy their gas from the company's gas-marketing
subsidiary, the company has an opportunity to earn profits and assumes the risk
of incurring losses on the sale of the gas commodity. The results of the
company's gas-marketing activities are included in the caption Other Income
(Loss)-Net in the Consolidated Statements of Income.
Gas Delivered to Interruptible Customers. To provide interruptible service
to customers, the company requires that these customers be capable of using an
alternate fuel as a substitute for natural gas when the company determines
their service must be interrupted to accommodate firm customers' needs during
periods of peak demand. Nearly all of these customers have the option of buying
bundled gas service from the company or electing to have the company deliver
gas purchased from third-party suppliers.
Therms delivered to interruptible customers, which include the amounts in
the Selected Financial Data shown on page 22 for interruptible commercial and
industrial gas sold and delivered, and interruptible gas delivered for others,
decreased by 16.1 million therms (4.8%) when compared to 1997. This decrease in
volumes delivered resulted primarily from the warmer weather experienced this
year. Net revenues associated with therms delivered to this customer class
decreased by $1.8 million.
The effect on net income of changes in delivered volumes and prices to the
interruptible class is minimized by margin-sharing arrangements that are part
of the design of the company's rates. Under these arrangements, the company
returns a majority of the margins earned on interruptible gas sales and
deliveries to firm customers after it reaches a gross margin threshold or in
exchange for the shifting of a portion of the fixed costs of providing service
from the interruptible to the firm class.
Gross Receipts Taxes. Various taxing authorities levy a gross receipts tax
on the company based on revenues. The company collects these taxes from
customers and remits them to the various taxing authorities. Gross receipts
taxes reflected in revenues decreased by $4.0 million in 1998. The company
records the amounts collected from customers in general tax expense and,
therefore, there is generally no effect on net income.
Other. Other net revenues increased by $2.5 million. Included in this
caption are amounts associated with: (1) gas deliveries to customers for
electric generation; (2) amounts generated from optimizing the value of the
company's contractual assets for transportation and storage of natural gas on
the interstate pipelines; and (3) miscellaneous other operating revenues not
associated with volumes of gas sold.
28
<PAGE> 8
Washington Gas Light Company
The company has two customers to which it sells and/or delivers gas to
facilities in Maryland that are used to generate electricity. Volumes delivered
for electric generation in the current period decreased by 0.4 million therms
from the same period last year. The impact on net revenues and net income of
increases or decreases in volumes delivered for electric generation is not
significant due to a margin-sharing arrangement in the state of Maryland. Under
this arrangement, the company returns substantially all of the gross margins
earned on such sales and deliveries of gas, less related expenses, to firm
customers after the company recovers its investment in the facilities
constructed to serve these two customers. By returning margins from these
deliveries to firm customers in the Maryland jurisdiction, the cost of
delivering gas to customers is lowered, thereby enhancing the company's
competitive position.
NET REVENUES AND COST OF GAS
(MILLIONS)
** this graph presented the Company's Net
Revenues and Cost of Gas
for 1993-1998
<TABLE>
<CAPTION>
Net Cost of
Year Revenues Gas Total
<S> <C> <C> <C>
1993 415 479 894
1994 453 462 915
1995 439 390 829
1996 500 470 970
1997 483 573 1,056
1998 465 576 1,041
</TABLE>
Cost of Gas. The company's cost of natural gas includes relatively fixed
costs known as demand charges that are paid to pipeline companies for the
transportation and storage of commodity purchases and variable commodity rates
that are paid to natural gas producers. Variations in the company's cost of gas
expense result from changes in gas sales volumes, the price of gas purchased
and the level of gas costs collected through the operation of the firm gas cost
recovery mechanisms included in the company's rate schedules. The company
defers in the current period any difference between actual firm gas costs
incurred and the amount of current gas cost recoveries included in revenues.
Any differences are recovered or refunded to customers in subsequent periods.
Therefore, increases or decreases in the cost of gas associated with sales made
to firm customers have no effect on net income.
The company's cost of gas expense on a per therm basis, excluding the cost
and related volumes applicable to sales made outside of the company's service
territory, decreased to 38.95 cents in 1998 from the 1997 level of 41.11 cents.
The decrease resulted primarily from a decrease in the cost of gas recovered
from customers reflecting lower commodity gas prices this year. The commodity
cost of gas invoiced the company was 28.13 cents and 30.96 cents per therm for
1998 and 1997, respectively, which reflects the lower market prices incurred
during the winter months of fiscal year 1998, primarily from lower demand due
to warmer weather.
1997 vs. 1996
Gas Delivered to Firm Customers. Therm deliveries to firm customers decreased
by 97.2 million therms (8.0%) in 1997, causing a decrease in net revenues of
$25.8 million. This decline was due to 15.2% warmer weather in 1997, partially
offset by a 3.4% increase in customer meters.
The effect of increased rates on net revenues in 1997 amounted to $0.2
million and was limited to an increase granted to Shenandoah Gas Company.
Gas Delivered to Interruptible Customers. Therms delivered to interruptible
customers increased by 65.3 million therms (24.4%) when compared to 1996. This
increase resulted primarily from the company interrupting service to these
customers to meet its firm commitments to a greater extent in 1996 due to the
significantly colder weather in that period. Net revenues associated with
therms delivered to this customer class increased by $2.9 million.
Gross Receipts Taxes. Gross receipts taxes reflected in revenues increased
by $0.2 million in 1997. As discussed previously, the company records the
amounts collected from customers in general tax expense and, therefore, there
is generally no effect on net income.
Cost of Gas. The company's cost of gas expense on a per therm basis,
excluding the cost and related volumes applicable to sales made outside of the
company's service territory, increased in 1997 to 41.11 cents from the 1996
level of 32.81 cents. The increase resulted primarily from: (1) an increase in
the cost of gas recovered from customers reflecting higher commodity gas prices
in 1997 and the effect of the collection from firm customers of the prior
year's undercollection of gas costs; (2) a decline in the amount of refunds
received from pipelines in 1997; and (3) the effect of fewer volumes purchased
which increased fixed costs per therm. The commodity cost of gas invoiced the
company was 30.96 cents and 26.53 cents per therm for 1997 and 1996,
respectively, which reflected the higher market prices incurred during the
early winter months of fiscal year 1997.
OTHER OPERATING EXPENSES
1998 vs. 1997
Operation and maintenance expenses increased by $3.7 million (1.9%) in 1998.
The primary factors contributing to this increase include: (1) $8.6 million of
costs associated with the company's technology initiatives including
substantial progress toward implementing programmatic solutions to challenges
presented by date-sensitive devices and systems which must be addressed before
December 31, 1999; and (2) a $1.6 million non-recurring
OTHER OPERATING EXPENSES
(MILLIONS)
** this graph presented a breakdown of
The Company's Operating Expenses
for 1993-1998
<TABLE>
<CAPTION>
Operation & Depreciation and
Year Maintenance Taxes Amortization Total
<S> <C> <C> <C> <C>
1993 185 104 40 329
1994 207 109 44 360
1995 195 106 46 347
1996 221 118 48 387
1997 197 119 52 368
1998 201 107 55 363
</TABLE>
29
<PAGE> 9
Washington Gas Light Company
charge to write off a regulatory asset associated with Postretirement Benefits
Other Than Pensions related to the company's Virginia jurisdiction. Lower labor
costs in the current year because of greater operating efficiencies and the
impact of fewer employees served to partially offset these increased costs.
At September 30, 1998, the company had 2,000 utility employees, a decline of
59 employees (2.9%) from the level at September 30, 1997.
Depreciation and amortization increased by $3.5 million (6.8%) primarily due
to the company's increased investment in plant and equipment to meet customer
growth and to replace existing capacity. Capital expenditures totaled $158.9
million in 1998, and the composite depreciation rate was 2.93% compared to
2.94% in 1997.
General taxes decreased by $2.1 million (2.9%) primarily due to lower gross
receipts taxes reflecting lower revenues caused by the warmer weather in the
current period. Partially offsetting this decrease were higher property taxes
due to a rise in property investments compared to last year. Further
information on general taxes is shown in Note 7 to the Consolidated Financial
Statements.
The composition of the change in income tax expense is detailed in the
Consolidated Statements of Income Taxes on page 42.
1997 vs. 1996
Operation and maintenance expenses declined by $23.9 million (10.8%) in 1997.
The decline was primarily caused by the absence in 1997 of $13.4 million of
non-recurring charges recorded in 1996 associated with the company's redesign
of its organization. For a further discussion of the company reorganization,
please refer to page 26 and Note 11 to the Consolidated Financial Statements.
Also contributing to this decline were lower labor and employee benefit costs
primarily caused by reduced employee levels. Partially offsetting these
decreases were higher uncollectible account expenses due primarily to increased
revenues caused by higher gas costs during the 1997 heating season.
At September 30, 1997, the company had 2,059 utility employees, a decline of
205 employees (9.1%) from the level at September 30, 1996.
Depreciation and amortization increased by $3.5 million (7.3%) in 1997
primarily due to the company's increased investment in plant and equipment.
Capital expenditures totaled $139.9 million in 1997, and the composite
depreciation rate was 2.94% compared to 2.96% in 1996.
General taxes increased by $2.7 million (3.9%) in 1997 primarily due to
increased property taxes resulting from greater investments in plant and
equipment and higher gross receipts taxes.
OTHER INCOME (LOSS)-NET
Other income (loss)-net increased by $3.5 million in 1998 due primarily to a
$1.6 million net of income tax gain on the sale of the company's retail propane
assets (See Note 2 to the Consolidated Financial Statements) and a $1.6 million
net of income tax gain on the sale of investments in certain venture capital
funds. Other income (loss)-net for 1997 was $0.9 million, an improvement from
1996 of $1.8 million. The improvement over 1996 primarily resulted from the
absence in 1997 of valuation reserves for certain non-utility activities
recorded in 1996, and higher earnings generated from energy-related activities.
Energy-related activities engaged in by the company and its subsidiaries,
which include energy marketing, commercial energy services, consumer financing
and merchandising, contributed $640,000 to 1998 net income compared to $1.25
million in 1997. A discussion of the company's energy-related activities
follows:
Energy Marketing
The company's gas-marketing subsidiary, WGES, sells natural gas in competition
with unregulated marketers and unregulated subsidiaries of other utility
companies. WGES serves nearly 30,000 residential, commercial and industrial
customers both inside and outside the company's traditional service territory.
WGES increased its sales volumes by 65% over last year.
Commercial Energy Services
The company's commercial energy services include the design and renovation of
mechanical heating, ventilating and air conditioning systems through two of its
subsidiaries including American Combustion, Inc. and American Combustion
Industries, Inc., which are jointly operated under the name ACI. ACI is a
mechanical contracting firm that the company purchased in March 1998 (See Note
2 to the Consolidated Financial Statements).
Consumer Financing
This business activity includes the financing of gas appliances and certain
other equipment for residential and small commercial customers.
Merchandising
The company's merchandising activities include the sale of carbon monoxide (CO)
detectors and electronic billing services. In addition, the company has a
marketing alliance through which the company earns fees for selling pagers and
paging services.
INTEREST EXPENSE
Total interest expense increased by $3.6 million, or 10.5%, in 1998 and
increased by $3.5 million, or 11.6%, in 1997. The following table shows the
components of changes in interest expense between years.
COMPOSITION OF THE CHANGES IN INTEREST EXPENSE
<TABLE>
<CAPTION>
Increase/(Decrease)
From Prior Year
(Millions) 1998 1997
- ------------------------------------------------------------------
<S> <C> <C>
Long-term debt $ 3.7 $ 2.5
Short-term debt -- 2.0
Other (0.1) (1.0)
----- -----
$ 3.6 $ 3.5
===== =====
</TABLE>
30
<PAGE> 10
Washington Gas Light Company
1998 vs. 1997
Long-Term Debt. The increase in interest on long-term debt of $3.7 million in
1998 was primarily due to a $62.0 million rise in the average amount of
long-term debt outstanding, partially offset by a decline of 0.2 percentage
points in the weighted-average cost of such debt. The company's embedded cost
of long-term debt was 6.9% at September 30, 1998, compared to 7.1% at September
30, 1997. The decline in the embedded cost of long-term debt was primarily due
to a partial retirement of $11.0 million of the 8-3/4% Series First Mortgage
Bonds (FMBs) in February 1998 and lower rates for more recent Medium-Term Note
(MTN) issues.
Short-Term Debt. Interest on short-term debt was essentially the same as
last year, reflecting a $1.8 million decrease in the average amount of
short-term debt outstanding, offset by a 0.2 percentage point increase in the
weighted-average cost of such debt. Please refer to Short-Term Cash
Requirements and Related Financing for a discussion of fluctuations in
short-term debt balances.
1997 vs. 1996
Long-Term Debt. The increase in interest on long-term debt of $2.5 million in
1997 was primarily due to a $52.4 million rise in the average amount of
long-term debt outstanding, partially offset by a decline of 0.3 percentage
points in the weighted-average cost of such debt. The company's embedded cost
of long-term debt was 7.1% at September 30, 1997, compared to 7.5% at September
30, 1996. The decline in the embedded cost of long-term debt was primarily due
to the partial retirement of $27.5 million of the 8-5/8% Series FMBs in March
1997.
Short-Term Debt. The increase in interest on short-term debt of $2.0 million
was primarily due to a $36.5 million increase in the average amount of
short-term debt outstanding, partially offset by a 0.1 percentage point decline
in the weighted-average cost of such debt.
Other. Other interest expense decreased by $1.0 million, primarily due to a
$0.7 million decrease in interest on supplier refunds, reflecting a decline in
the average balance due to customers.
LIQUIDITY AND CAPITAL RESOURCES
The company has historically had a goal of maintaining its common equity ratio
in the mid-50% range of total capital and a general policy of repaying
short-term debt after the heating season ends in the spring as significant
levels of current assets are converted into cash. Accomplishing these
objectives and maintaining sufficient cash flow are necessary to preserve the
company's credit ratings and to allow access to capital at relatively low
costs.
CAPITALIZATION
(Including Current Maturities of Long-Term Debt)
(MILLIONS)
** this graph presented a break down of the Company's
capital structure for 1993-1998
<TABLE>
<CAPTION>
Long-Term
Debt Including
Common Preferred Current
Year Equity Stock Maturities Total
<S> <C> <C> <C> <C>
1993 458 28 366 852
1994 486 28 351 865
1995 513 28 382 923
1996 559 28 362 949
1997 589 28 453 1,070
1998 608 28 493 1,129
</TABLE>
At September 30, 1998, total capitalization, including current maturities of
long-term debt, was composed of 53.8% common equity, 2.5% preferred stock and
43.7% long-term debt.
SHORT-TERM CASH REQUIREMENTS AND RELATED FINANCING
The company's business is highly weather sensitive and seasonal. In 1998, 76%
of total therms delivered in the company's franchise area (excluding deliveries
to two electric generation facilities) were delivered in the first and second
fiscal quarters. This weather sensitivity causes short-term cash requirements
to vary significantly during the year. Cash requirements peak in the fall and
winter months when accounts receivable, accrued utility revenues and storage
gas are at or near their highest levels. After the winter heating season, these
assets are converted into cash and are used to liquidate short-term debt and
acquire storage gas for the subsequent heating season.
Storage gas, which represents gas purchased from producers and primarily
stored in facilities owned by interstate pipelines, is generally paid for
between heating seasons and withdrawn during the heating season. Significant
variations in storage balances at September 30 are usually caused by the price
paid to producers and marketers, which is a function of short-term market
fluctuations in gas costs. Such costs are recovered from customers as a
component of the cost of gas.
Variations in the timing of collections of gas costs under the company's
gas cost recovery mechanisms and the level of refunds from pipeline companies
that will be returned to customers can significantly affect short-term cash
requirements. At September 30, 1998, the company had a net undercollection of
gas costs of $4.3 million, compared to a $7.0 million net undercollection at
September 30, 1997. Amounts that are undercollected and overcollected are
reflected in the captions Gas costs due from customers and Gas costs due to
customers in the Consolidated Balance Sheets. Most of the current balances will
be collected from or returned to customers in fiscal year 1999. At September
30, 1998, refunds received from pipelines that are being returned to the
company's customers totaled $1.4 million, compared to $6.1 million at September
30, 1997.
The company uses short-term debt in the form of commercial paper and
short-term bank loans to fund seasonal requirements. Alternative sources
include unsecured lines of credit, some of which are seasonal, and $160 million
in a revolving credit agreement maintained with a group of banks. The company
activates these financing options to support or replace the company's
commercial paper. Additional information regarding the company's short-term
borrowing capabilities is included in Note 3 to the Consolidated Financial
Statements.
At September 30, 1998, the company had notes payable outstanding of $124.9
million, as compared with $67.9 million at September 30, 1997. At September 30,
1998, current maturities of long-term debt were $64.1 million, including $21.7
million of MTNs, $39.0 million of 8-3/4% Series FMBs that can be called by or
put to the company on July 1, 1999 and a $2.0 million required sinking-fund
payment for the 8-5/8% Series FMBs.
31
<PAGE> 11
Washington Gas Light Company
LONG-TERM CASH REQUIREMENTS AND RELATED FINANCING
The company's long-term cash requirements are dependent upon the level of
capital expenditures, long-term debt maturity requirements and decisions to
refinance long-term debt. The majority of the company's capital expenditures
are devoted to adding new customers in its existing service area. At September
30, 1998, the company was authorized to issue up to $106 million of long-term
debt under an existing shelf registration. In October 1998, the company issued
an additional $25 million of MTNs under this shelf registration. The nature of
the company's long-term debt is discussed further in Note 4 to the Consolidated
Financial Statements.
Effective May 1, 1998, shares issued through the Dividend Reinvestment and
Common Stock Purchase Plan (DRP) and Employee Savings Plans are being issued as
new shares rather than being purchased on the open market. On November 12,
1998, the company offered publicly 2 million shares of common stock at $25.0625
per share. On November 18, 1998, the underwriters involved in the offering
exercised their option to purchase an additional 300,000 shares from the
company at the same price per share. Net proceeds from the sale will amount to
$55,712,000, and will be used for general corporate purposes, including capital
expenditures and working capital requirements.
1998
Cash Flow from Operating Activities. In 1998, net cash provided by operating
activities amounted to $121.8 million, a decrease of $33.0 million from the
1997 level. The decline primarily resulted from: (1) a decrease in collections
of gas costs from customers; (2) lower net income, adjusted for noncash items;
and (3) a decrease in accounts payable balances, primarily from lower gas
costs.
Cash Flow from Financing Activities. The company raised $5.3 million through
the DRP and Employee Savings Plans in fiscal year 1998. During the first
quarter of fiscal year 1998, the company paid $2.3 million to repurchase 88,700
shares of common stock for company stock-based compensation plans.
The long-term debt issued in the current year of $72.2 million includes MTN
issuances at a weighted-average interest rate of 6.72%. The terms of the
unsecured MTNs issued are discussed in Note 4 to the Consolidated Financial
Statements. In February 1998, the company used the proceeds of a $12 million
MTN issuance to retire $11 million of 8-3/4% Series FMBs. The company paid a
premium of $0.5 million on the redemption. Additional retirements of long-term
debt in 1998 included $18.8 million of MTNs with coupon rates ranging from
6.43% to 8.00%, and $4.0 million of 8-5/8% Series FMBs.
Cash Flow from Investing Activities. As shown in the table on page 33,
capital expenditures for 1998 totaled $158.9 million. New business
expenditures, which result in additional therm deliveries and include amounts
invested to convert customers from other energy sources, totaled $87.4 million,
or 55.0% of the total. Other capital expenditures include $19 million for the
purchase and installation of enterprise-wide software to replace the financial,
human resources and supply chain systems. By the end of fiscal year 1998,
customer meters rose to 819,719, an increase of 20,980, or 2.6% over the level
at the end of fiscal year 1997.
During 1998, the company received $1.6 million from the sale of investments
in certain venture capital funds. As further discussed in Note 2 to the
Consolidated Financial Statements, the company sold all of its retail propane
assets for $4.1 million, recognizing a net-of-income-tax gain of $1.6 million.
As further discussed in Note 2 to the Consolidated Financial Statements, the
company purchased ACI with $3.0 million in cash and $2.0 million of debt
financing that is being repaid in monthly installments over two years.
During 1998, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $83.6 million, representing 52.6% of
capital expenditures.
1997
Cash Flow from Operating Activities. In 1997, net cash provided by operating
activities amounted to $154.8 million, an increase of $95.3 million from the
1996 level. The improvement was brought about by: (1) increased collections of
gas costs from customers; (2) higher costs for gas storage withdrawals in 1997,
combined with lower levels of storage gas injections due to the warmer weather
in 1997; and (3) refunds made to customers in 1996 for amounts overcollected
from the implementation of an interim rate increase. Partially offsetting
these sources of cash were greater funds supporting accounts receivable
primarily from higher gas costs and a decrease in cash provided by accounts
payable primarily due to payments made during 1997 of amounts associated with
the redesign of the company's organization.
Cash Flow from Financing Activities. The long-term debt issued in fiscal
year 1997 of $125.8 million included MTN issuances at a weighted-average
interest rate of 6.60%. Proceeds from the MTN issuances were used to retire
$27.5 million of the 8-5/8% Series FMBs in March 1997 and $8.0 million of
maturing MTNs and for other corporate purposes.
Cash Flow from Investing Activities. Capital expenditures for 1997 totaled
$139.9 million. New business expenditures totaled $89.3 million, or 63.8% of
the total. By the end of fiscal year 1997, customer meters rose to 798,739, an
increase of 26,458, or 3.4% over the level at the end of fiscal year 1996.
During 1997, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $94.5 million, representing 67.6% of
capital expenditures.
32
<PAGE> 12
Washington Gas Light Company
1996
Cash Flow from Operating Activities. In 1996, net cash provided by operating
activities amounted to $59.5 million, a decline of $118.7 million from the 1995
level. The sharp decrease was due primarily to: (1) the effect of a shift from
an overcollection of gas costs from customers in 1995 to an undercollection of
gas costs in 1996; (2) the effect of a higher 1996 cost per therm to replace
storage gas volumes withdrawn during the prior winter heating season; (3)
higher funds used to support accounts receivable balances resulting primarily
from higher gas costs; and (4) refunds made to customers for amounts
overcollected from the implementation of an interim rate increase. These uses
of cash were partially offset by higher net income and increased sources of
cash reflected in accounts payable due to higher gas prices and the amounts
associated with the redesign of the company's organization.
Cash Flow from Financing Activities. In connection with an in-substance
defeasance, the company issued $50.0 million of unsecured MTNs at a coupon rate
of 6.15%. The $69.8 million of long-term debt retired included $50.0 million of
7-7/8% Series FMBs retired effective September 1, 1996, $17.325 million of
9-1/4% Series FMBs extinguished for financial reporting purposes in accordance
with the in-substance defeasance, and a $2.5 million scheduled MTN maturity. In
fiscal year 1998, the company legally retired the $17.325 million of 9-1/4%
Series FMBs.
During 1996, the company raised $12.6 million through its DRP and
Employee Savings Plans.
Cash Flow from Investing Activities. Capital expenditures for 1996
totaled $124.4 million. New business expenditures totaled $77.9 million, or
62.6% of the total. By the end of fiscal year 1996, customer meters rose to
772,281, an increase of 21,432, or 2.9% over the level at the end of fiscal
year 1995.
During 1996, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $101.0 million or 81.2% of capital
expenditures.
SALES OF ACCOUNTS RECEIVABLE
During 1998, the company augmented cash flow through the sale of $27.2 million
of certain non-utility accounts receivable. Similar sales of non-utility
accounts receivable in 1997 and 1996 amounted to $33.0 million and $30.5
million, respectively. For further discussion of the company's sales of
non-utility accounts receivable, see Note 10 to the Consolidated Financial
Statements.
MATURITIES AND SINKING FUND REQUIREMENTS
The amount of maturities and sinking fund requirements on long-term debt for the
ensuing five-year period is included in Note 4 to the Consolidated Financial
Statements.
SECURITY RATINGS
Shown below are the ratings on the company's debt instruments at September 30,
1998. There were no changes in these ratings from 1997.
First Mortgage Bonds
Standard & Poor's Corporation AA-
Moody's Investors Service Aa2
Fitch IBCA, Inc. AA-
Unsecured Medium-Term Notes
Standard & Poor's Corporation AA-
Moody's Investors Service Aa3
Fitch IBCA, Inc. AA-
Commercial Paper
Standard & Poor's Corporation A-1+
Moody's Investors Service P-1
Fitch IBCA, Inc. F1+
CAPITAL EXPENDITURES
The company's actual capital expenditures for fiscal years 1996-1998 and
projected capital expenditures for fiscal years 1999-2003 are shown in the table
below. The company believes that the combination of available internal and
external sources of funds will be adequate to meet its requirements.
CAPITAL EXPENDITURES
(Millions)
<TABLE>
<CAPTION>
Actual Projected
---------------------------------- ---------------------------------------------------------------------------
1996 1997 1998 1999 2000 2001 2002 2003 Total
- -------------------------------------------------- ---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
New Business $ 77.9 $ 89.3 $ 87.4 $ 81.4 $ 83.0 $ 90.7 $ 88.0 $ 88.1 $431.2
Replacements 34.5 36.4 36.2 35.7 37.3 37.8 38.8 39.8 189.4
Other 12.0 14.2 35.3 24.8 26.4 25.6 26.6 21.8 125.2
-------- --------- --------- -------- --------- --------- --------- --------- ---------
Total $124.4 $139.9 $158.9 $141.9 $146.7 $154.1 $153.4 $149.7 $745.8
======== ========= ========= ======== ========= ========= ========= ========= =========
</TABLE>
33
<PAGE> 13
Washington Gas Light Company
OTHER FACTORS AFFECTING THE COMPANY
ENVIRONMENTAL MATTERS
The company and its subsidiaries are subject to various laws related to
environmental matters, as discussed in Note 9 to the Consolidated Financial
Statements.
MARKET RISK
Interest Rate Risk Exposure Related to Other Financial Instruments
At September 30, 1998, the company had fixed-rate long-term debt aggregating
$428.6 million in principal amount and having a fair value of $462.2 million.
Fair value is defined as the present value of the debt securities' future cash
flows discounted at interest rates that reflect market conditions as of
September 30, 1998. While these instruments are fixed-rate and, therefore, do
not expose the company to the risk of earnings loss due to changes in market
interest rates, they are subject to changes in fair value as market interest
rates change. Using sensitivity analysis to measure this market risk exposure,
the company estimates that the fair value of its long-term debt would increase
by approximately $19.4 million if interest rates were to decline by 10%. The
company also estimates that the fair value of its long-term debt would decrease
by approximately $17.6 million if interest rates were to increase by 10%. In
general, such an increase or decrease in fair value would impact earnings and
cash flows only if the company were to reacquire all or a portion of these
instruments in the open market prior to their maturity.
Price Risk Related to Gas-Marketing Activities
The company's gas-marketing activities are performed by its marketing
subsidiary, WGES. In the course of its business, WGES makes fixed-price sales
commitments to customers. WGES purchases the corresponding physical supplies at
fixed prices to lock in margins. WGES has exposure to changes in gas prices
related to volumetric differences between the purchase commitments and sales
commitments. The risk associated with gas price fluctuations is managed by
closely matching purchases from suppliers with sales commitments to customers.
At September 30, 1998, WGES' open position was not material to the company's
financial position or results of operations.
YEAR 2000
The millennial change to the Year 2000 could affect the company's software
programs and computing infrastructure that use two-digit years to define the
applicable year, rather than four-digit years. As such they may recognize a date
using "00" as the year 1900 rather than the year 2000. This could result in the
computer or device shutting down, performing incorrect computations or
performing inconsistently.
In 1996, the company began a structured program to address Year 2000
issues. It has been implementing individual strategies targeted at the specific
nature of Year 2000 issues in each of the following areas: (1)
business-application systems including, but not limited to, the company's
customer service, operations and financial systems and end-user applications;
(2) embedded systems, including equipment that operates such items as the
company's storage and distribution system, meters, telecommunications, fleet and
buildings; (3) vendor and supplier relationships; (4) interruptible customers
and their ability to switch to alternate fuels as required under their tariffs;
and (5) contingency planning.
To implement this comprehensive Year 2000 program, the company established
a Year 2000 Project Office, chaired by the Vice President and Chief Information
Officer who reports directly to the Chairman and Chief Executive Officer. The
multi-disciplinary project office includes executive management and employees
with expertise from various disciplines including, but not limited to,
information technology, engineering, finance, communications, internal audit,
facilities management, procurement, law and human resources. In addition, the
company has utilized the expertise of outside consultants to assist in the
implementation of the Year 2000 program in such areas as business-application
system remediation, business-application system replacement, embedded systems
inventory and analysis and contingency planning.
Business-Application Systems
In March 1997, the company completed its assessment of all its
business-application systems. It is resolving Year 2000 issues through
remediation of 19 systems to recognize the turn of the century and the
replacement of 20 systems with new systems that provide additional business
management information and recognize four-digit years. By June 30, 1998, the
company had completed modifications to all 16 business applications targeted for
remediation by outside resources, representing approximately 84 percent of those
systems targeted for remediation. The three remaining systems to be remediated
by in-house staff represent the remaining approximately 16 percent of the total.
The company expects them to be remediated by the end of the second quarter of
fiscal year 1999.
The company is using in-house staff to test all remediated applications
and is using a testing procedure commonly known as trace-based testing to test
modified business applications for Year 2000 functionality. This method first
captures current processing steps and relevant data, which are run prior to
remediation (baseline test) and again after remediation (regression test). This
process is intended to identify any business rules that may have changed during
the remediation effort and to confirm that only date processes have been
changed. Once the regression test is successfully completed, the company uses
automated test software tools to perform additional applicable future date tests
for each system.
The company is also installing an enterprise-wide software system that
will replace 18 business application systems, including its financial, human
resources and supply chain systems. Two other systems will be replaced with
systems not included in the enterprise-wide software initiative. These 20
business applications represent approximately one-half of the business
application software code requiring remediation or replacement. The company
currently expects to complete the replacement no later than the end of the third
quarter of fiscal year 1999.
34
<PAGE> 14
Washington Gas Light Company
In summary, the company expects that remediation or replacement of
approximately 41 percent of the critical business-application systems will be
completed by the end of the first quarter of fiscal year 1999, and expects all
business-application systems will be completed no later than the end of the
third quarter of fiscal year 1999. Testing will continue through the end of
fiscal year 1999.
During the fourth quarter of fiscal year 1998, the company completed a
comprehensive, prioritized inventory of end-user applications (i.e., PC-based
databases) and is implementing project plans to replace or remediate these
applications, as necessary. It expects to complete replacement or remediation,
including testing, by the end of the third quarter of fiscal year 1999.
Embedded Systems
The company has performed a comprehensive inventory of its embedded systems at
the component level. This inventory identified several hundred components that
were potentially date sensitive. The company has contacted all manufacturers of
those components that it has identified as critical to operations. At this time,
approximately three percent of the date-sensitive components that the company
has identified are non-compliant based on information provided by the
manufacturers. The company implemented remediation or replacement plans as
necessary and expects them to be completed by the end of the second quarter of
fiscal year 1999. The quality of the responses received from manufacturers, the
estimated impact of the individual systems on the company, and the ability of
the company to perform meaningful tests will influence its decision to conduct
independent testing of embedded systems through the end of fiscal year 1999.
Vendor and Supplier Relationships
The company is contacting in writing or through face-to-face discussions all
vendors and suppliers of products and services that it considers critical or
important to its operation. These contacts include providers of interstate
transportation capacity and storage, natural gas suppliers, financial
institutions and electric, telephone and water companies. The company is
evaluating the initial responses and continues the process of following up with
the vendors and suppliers either through meetings or by letter. The company will
consider new business relationships with alternate providers of products and
services as necessary and to the extent alternatives are available. However, the
company recognizes there are no practical alternatives for external
infrastructure such as electric and telephone service, suppliers of natural gas
and providers of interstate transportation capacity and storage to deliver
natural gas to the company's distribution system.
Interruptible Customers
The company is communicating with its major interruptible customers
to inform them about the potential vulnerability of embedded boiler and plant
control systems. The company informed them that they should assess the need to
include potential remediation and/or replacement of these systems as part of
their Year 2000 programs to ensure their ability to switch to an alternate fuel
source, as required by applicable tariffs and contracts and if called on to do
so.
Year 2000 Risks and Contingency Planning
With respect to its internal operations, over which the company has direct
control, the company believes the most significant potential risks are: (1) its
ability to use electronic devices to control and operate its distribution
system; (2) its ability to render timely bills to its customers; (3) its ability
to enforce tariffs and contracts applicable to interruptible customers; and (4)
its ability to maintain continuous operation of its computer systems. The
company's Year 2000 program addresses each of these risks, and the remediation
or replacement of these systems is well under way. In the event that any Year
2000-related problems may occur, the company's contingency plan will outline
alternatives to mitigate the impact of such failures, to the extent possible.
The company relies on the suppliers of natural gas and interstate
transportation and storage capacity to deliver natural gas to the company's
distribution system. External infrastructure, such as electric, telephone and
water service, is necessary for the company's basic operation as well as the
operations of many of its customers. Should any of these critical vendors fail,
the impact of any such failure could become a significant challenge to the
company's ability to meet the demands of its customers, to operate its
distribution system and to communicate with its customers. It could also have a
material adverse financial impact including, but not limited to, lost sales
revenues, increased operating costs and claims from customers related to
business interruptions. The company has no way of ensuring that those vendors or
suppliers mentioned above for which there are no viable options will be timely
Year 2000 compliant.
As part of its normal business practice, the company maintains plans to
follow during emergency circumstances. These plans will be used as a basis to
build the company's contingency plan for potential Year 2000-related problems.
The company maintains and operates a command center that is activated during
emergency circumstances. The company will manage specific Year 2000 contingency
operations from the command center during the millennium change as well as at
other points in time on an as needed basis.
Because of the interconnected nature of potential Year 2000-related
problems, the company recognizes that effective contingency planning must focus
on both internal and external operations and is working with local organizations
and other utilities as it completes its planning effort. The company has
participated in association meetings and customer meetings with other local
utilities to discuss the company's Year 2000 program.
The company believes that its work will serve to reduce the risk that its
internal systems will fail for Year 2000 reasons. However, the contingency plan
cannot mitigate interrupted delivery to the company's distribution system of
natural gas by the producers of natural gas and providers of interstate
transportation capacity or the impact on operations of failures of electric,
telephone and water services.
35
<PAGE> 15
Washington Gas Light Company
Financial Implications
To implement its Year 2000 strategies, the company currently expects to generate
non-recurring expenses of approximately $10 million over the three fiscal-year
periods ending September 30, 1999 for business-application systems remediation,
embedded systems replacement, end-user applications remediation and replacement,
and certain costs associated with the replacement of certain existing business
systems. The company will capitalize costs of approximately $28 million incurred
to replace certain existing business-application software systems with new
systems that will be Year 2000 operational and provide additional business
management information.
The following table reflects the amounts charged to expense and
capitalized through September 30, 1998 for business-application
systems remediation, embedded systems replacement and end-user applications
remediation and replacement and for replacing existing business-application
software systems.
<TABLE>
<CAPTION>
1998 1997 Total
------ ------ ------
Expense Capital Expense Capital Expense Capital
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
(millions)
Business-application
systems remediation,
embedded systems
replacement and
end-user applications
remediation and
replacement $ 1 $ 1 $ 1 $-- $2 $ 1
Business-application
software systems
replacement $ 4 $19 $-- $-- $4 $19
</TABLE>
Until the company has completed further analysis of the impact of the Year
2000 issue on its embedded systems, vendor and supplier relationships and
contingency planning, it is unable to estimate the additional costs, if any, it
may incur as a result of its efforts.
Each of the components of the company's Year 2000 program is progressing,
and the company believes it is taking reasonable steps necessary to be able to
operate successfully through and beyond the turn of the century.
INFLATION
To help cope with the effects of inflation on its capital investment and
returns, the company seeks rate increases from its regulatory commissions. The
most significant impact of inflation is on the company's replacement cost of
plant and equipment. While the regulatory commissions having jurisdiction over
the company's retail rates allow depreciation only on the basis of historical
cost to be recovered in rates, the company anticipates that it will be allowed
to recover the increased cost of its investment and earn a return thereon after
replacement of the facilities occurs.
REGULATORY MATTERS
Requests for a modification to existing rates are based on increased investment
in plant and equipment, higher operating expenses and the need to earn an
adequate return on invested capital. In July 1998, the SCC of VA granted the
company's distribution subsidiary, Shenandoah Gas Company, an increase in
annual revenues of $1.4 million, effective December 28, 1997. The company's
base rates did not change in any of its major jurisdictions in 1998. A Summary
of Major Rate Applications and Results is shown below.
SUMMARY OF MAJOR RATE APPLICATIONS AND RESULTS
<TABLE>
<CAPTION>
Increase in Annual Revenues
---------------------------------
Effective Test Year Amount Amount Allowed Return
Jurisdiction Date 12 Mos. Ended Requested (Millions) Granted (Millions) on Common Equity
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Virginia 7/6/90 3/31/90 $ 7.7 $ 7.1 13.00%
Maryland 8/1/93 12/31/92 26.2 10.6 (a)
District of Columbia 10/19/93 9/30/92 24.5 4.7 11.50
District of Columbia 8/1/94 9/30/93 17.3 6.4 (b)
Virginia 9/27/94 12/31/93 15.7 6.8 11.50
Maryland 12/1/94 3/31/94 17.6 7.4 (a)
</TABLE>
(a) Rates were implemented as a result of a settlement agreement. The return on
equity indicated in the order of 11.5% was not utilized to establish rates.
(b) Application was settled without stipulating the return on common equity.
36
<PAGE> 16
Washington Gas Light Company
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Years Ended September 30, 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C>
OPERATING REVENUES (Note 1) $1,040,618 $1,055,754 $969,778
Cost of Gas (Note 1) 575,786 572,925 469,925
---------------- ---------------- -------------
NET REVENUES 464,832 482,829 499,853
---------------- ---------------- -------------
OTHER OPERATING EXPENSES
Operation (Note 11) 162,336 160,193 187,817
Maintenance 38,458 36,857 33,105
Depreciation and amortization (Note 1) 54,875 51,363 47,887
General taxes (Note 7) 69,178 71,277 68,605
Income taxes (See Statements and Note 6) 38,006 47,864 49,376
---------------- ---------------- -------------
362,853 367,554 386,790
---------------- ---------------- -------------
OPERATING INCOME 101,979 115,275 113,063
Other Income (Loss)--Net (Note 1) 4,369 886 (874)
---------------- ---------------- -------------
INCOME BEFORE INTEREST EXPENSE 106,348 116,161 112,189
---------------- ---------------- -------------
INTEREST EXPENSE
Interest on long-term debt 33,859 30,135 27,622
Other 3,860 4,007 2,976
---------------- ---------------- -------------
37,719 34,142 30,598
---------------- ---------------- -------------
NET INCOME 68,629 82,019 81,591
Dividends on Preferred Stock 1,331 1,331 1,332
---------------- ---------------- -------------
NET INCOME APPLICABLE TO COMMON STOCK $ 67,298 $ 80,688 $ 80,259
================ ================ =============
AVERAGE COMMON SHARES OUTSTANDING 43,691 43,706 43,360
================ ================ =============
EARNINGS PER AVERAGE COMMON SHARE--BASIC (Note 5) $ 1.54 $ 1.85 $ 1.85
================ ================ =============
EARNINGS PER AVERAGE COMMON SHARE--DILUTED (Note 5) $ 1.54 $ 1.85 $ 1.85
================ ================ =============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
37
<PAGE> 17
Washington Gas Light Company
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30, 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1 and 4)
At original cost $1,992,770 $1,846,471
Accumulated depreciation and amortization (673,269) (629,334)
--------------- ---------------
1,319,501 1,217,137
--------------- ---------------
CURRENT ASSETS
Cash and cash equivalents 17,876 9,708
Accounts receivable 92,178 65,232
Gas costs due from customers (Note 1) 9,921 9,445
Allowance for doubtful accounts (9,078) (11,043)
Accrued utility revenues (Note 1) 16,304 21,020
Materials and supplies--principally at average cost 15,607 15,186
Storage gas--at cost (first-in, first-out) 76,338 81,072
Deferred income taxes (See Statements and Note 6) 16,337 17,447
Other prepayments--principally taxes 13,864 11,907
Other 849 --
--------------- ---------------
250,196 219,974
--------------- ---------------
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets (Note 1) 95,352 101,956
Other 17,384 12,965
--------------- ---------------
112,736 114,921
--------------- ---------------
Total $1,682,433 $1,552,032
=============== ===============
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements)
Common shareholders' equity (Note 5) $ 607,755 $ 589,035
Preferred stock 28,424 28,430
Long-term debt (Note 4) 428,641 431,575
--------------- ---------------
1,064,820 1,049,040
--------------- ---------------
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4) 64,106 20,862
Notes payable (Note 3) 124,943 67,900
Accounts payable 103,243 99,578
Wages payable 13,527 13,590
Dividends declared 13,485 13,224
Customer deposits and advance payments 19,454 16,662
Accrued taxes 5,368 5,699
Accrued interest 3,832 5,235
Pipeline refunds due to customers 1,437 6,054
Gas costs due to customers (Note 1) 5,671 2,418
Other 1,146 --
--------------- ---------------
356,212 251,222
--------------- ---------------
DEFERRED CREDITS
Unamortized investment tax credits 20,493 21,427
Deferred income taxes (See Statements and Note 6) 145,519 136,682
Other (Notes 1, 8, 9 and 10) 95,389 93,661
--------------- ---------------
261,401 251,770
--------------- ---------------
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10)
Total $1,682,433 $1,552,032
=============== ===============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
38
<PAGE> 18
Washington Gas Light Company
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Years Ended September 30, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 68,629 $ 82,019 $ 81,591
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (a) 60,291 56,886 54,517
Deferred income taxes--net 11,055 10,434 11,337
Amortization of investment tax credits (934) (954) (972)
Allowance for funds used during construction (815) (411) (465)
Other noncash charges and (credits)--net,
including gains on investing activities (1,406) (1,444) 5,250
----------- ------------ ----------
136,820 146,530 151,258
Changes in assets and liabilities (net of effects from purchase of ACI [Note 2]):
Accounts receivable and accrued utility revenues (18,637) (18,351) (7,587)
Gas costs due from/to customers--net 2,777 19,594 (55,800)
Storage gas 4,734 2,757 (30,468)
Other prepayments--principally taxes (1,894) (1,860) (2,248)
Accounts payable 215 8,191 17,578
Wages payable (63) (718) (817)
Customer deposits and advance payments 2,792 3,665 (2,411)
Accrued taxes (389) 105 (659)
Pipeline refunds due to customers (4,617) (2,208) (2,298)
Rate refunds due to customers -- -- (9,306)
Deferred purchased gas costs--net 897 1,543 (1,435)
Other-net (817) (4,445) 3,727
----------- ------------ ----------
Net Cash Provided by Operating Activities 121,818 154,803 59,534
----------- ------------ ----------
FINANCING ACTIVITIES
Common stock issued 5,279 312 12,637
Common stock repurchased (2,340) -- --
Long-term debt issued 72,166 125,812 50,000
Long-term debt retired (34,537) (35,555) (69,830)
Premium on long-term debt retired (493) (1,422) (2,263)
Notes payable--net of effects from purchase of ACI (Note 2) 55,698 (47,378) 115,278
Dividends on common and preferred stock (53,228) (52,033) (50,264)
----------- ------------ ----------
Net Cash Provided by (Used in) Financing Activities 42,545 (10,264) 55,558
----------- ------------ ----------
INVESTING ACTIVITIES
Capital expenditures (158,874) (139,871) (124,414)
Proceeds from sale of venture funds 1,619 -- --
Proceeds from sale of retail propane assets 4,050 -- --
Payment for purchase of ACI--net of cash acquired (Note 2) (2,990) -- --
Other investing activities -- 451 --
----------- ------------ ----------
Net Cash Used in Investing Activities (156,195) (139,420) (124,414)
----------- ------------ ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (b) 8,168 5,119 (9,322)
Cash and Cash Equivalents at Beginning of Year (b) 9,708 4,589 13,911
----------- ------------ ----------
Cash and Cash Equivalents at End of Year (b) $ 17,876 $ 9,708 $ 4,589
=========== ============ ==========
(a) Includes amounts charged to other accounts.
(b) Cash equivalents are highly liquid investments with a maturity of three
months or less when purchased.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Income taxes paid $ 32,925 $ 37,494 $ 41,993
Interest paid $ 37,811 $ 33,662 $ 30,859
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
39
<PAGE> 19
Washington Gas Light Company
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
September 30, 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY (See Statements and Note 5)
Common stock, $1 par value, authorized 80,000,000 shares,
issued 43,954,658 and 43,742,148 shares, respectively $ 43,955 $ 43,742
Paid-in capital 310,477 305,123
Retained earnings 258,315 243,175
Deferred compensation (1,948) (2,022)
Treasury stock--at cost, 115,205 and 42,632 shares, respectively (3,044) (983)
------------ -------------
Total Common Shareholders' Equity 607,755 57.1% 589,035 56.2%
------------ ------- ------------- -------
PREFERRED STOCK without par value,
authorized 1,500,000 shares, issued and outstanding
$4.80 series, 150,000 shares 15,000 15,000
$4.25 series, 70,600 shares 7,173 7,173
$5.00 series, 60,000 shares 6,000 6,000
$4.36 convertible series, 1,942 and 1,994 shares, respectively 194 199
$4.60 convertible series, 569 and 576 shares, respectively 57 58
------------ -------------
Total Preferred Stock 28,424 2.7 28,430 2.7
------------ ------- ------------- -------
LONG-TERM DEBT (Note 4)
First Mortgage Bonds
8-5/8% series due March 1, 2017 4,000 8,000
8-3/4% series due July 1, 2019 39,000 50,000
------------ -------------
43,000 58,000
------------ -------------
Unsecured Medium-Term Notes
Due fiscal year 1998, 6.43% to 8.00% -- 15,800
Due fiscal year 1999, 6.50% to 7.97% 21,700 21,700
Due fiscal year 2002, 6.90% to 7.56% 42,600 45,600
Due fiscal year 2003, 6.90% 5,000 5,000
Due fiscal year 2008, 6.51% to 6.61% 20,100 20,100
Due fiscal year 2022, 6.94% to 6.95% 5,000 5,000
Due fiscal year 2023, 6.50% to 7.04% 50,000 30,000
Due fiscal year 2024, 6.95% 36,000 36,000
Due fiscal year 2025, 6.50% to 7.76% 40,000 40,000
Due fiscal year 2026, 6.15% 50,000 50,000
Due fiscal year 2027, 6.40% to 6.82% 125,000 125,000
Due fiscal year 2028, 6.57% to 6.85% 52,000 --
------------ -------------
447,400 394,200
------------ -------------
Other long-term debt 3,086 952
Unamortized premium and (discount)--net (739) (715)
Less current maturities 64,106 20,862
------------ -------------
Total Long-Term Debt 428,641 40.2 431,575 41.1
------------ ------- ------------- -------
Total Capitalization $1,064,820 100.0% $1,049,040 100.0%
============ ======= ============= =======
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
40
<PAGE> 20
Washington Gas Light Company
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Stock Issued
------------------------------------ Paid-in Retained
Shares Amount Capital Earnings
- --------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C>
BALANCE SEPTEMBER 30, 1995 42,944,831 $42,945 $289,285 $182,733
Net income -- -- -- 81,591
Common stock expense -- -- (9) --
Deferred compensation 127,100 127 2,420 --
Director compensation plan 1,603 2 34 --
Employee compensation 45,313 45 901 --
Dividend reinvestment plan 484,415 485 10,007 --
Employee savings plans 120,362 120 2,025 --
Conversion of preferred stock 3,229 3 28 --
Dividends declared:
Common stock ($1.1350 per share) -- -- -- (49,366)
Preferred stock -- -- -- (1,332)
--------------- ------------ -------------- -------------
BALANCE SEPTEMBER 30, 1996 43,726,853 43,727 304,691 213,626
Net income -- -- -- 82,019
Common stock expense -- -- (3) --
Deferred compensation -- -- 128 --
Director compensation plan -- -- -- --
Dividend reinvestment plan 7,861 8 166 --
Employee savings plans 6,356 6 132 --
Conversion of preferred stock 1,078 1 9 --
Dividends declared:
Common stock ($1.1700 per share) -- -- -- (51,139)
Preferred stock -- -- -- (1,331)
--------------- ------------ -------------- -------------
BALANCE SEPTEMBER 30, 1997 43,742,148 43,742 305,123 243,175
Net income -- -- -- 68,629
Deferred compensation -- -- 255 --
Director compensation plan -- -- 21 --
Dividend reinvestment plan 188,812 189 4,500 --
Employee savings plans 23,090 23 573 --
Conversion of preferred stock 608 1 5 --
Common stock repurchased -- -- -- --
Dividends declared:
Common stock ($1.1950 per share) -- -- -- (52,158)
Preferred stock -- -- -- (1,331)
--------------- ------------ -------------- -------------
BALANCE SEPTEMBER 30, 1998 43,954,658 $43,955 $310,477 $258,315
=============== ============ ============== =============
<CAPTION>
Deferred Treasury
Compensation Stock Total
- ----------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C>
BALANCE SEPTEMBER 30, 1995 $(1,680) $ (239) $513,044
Net income -- -- 81,591
Common stock expense -- -- (9)
Deferred compensation (1,017) (299) 1,231
Director compensation plan -- -- 36
Employee compensation -- -- 946
Dividend reinvestment plan -- -- 10,492
Employee savings plans -- -- 2,145
Conversion of preferred stock -- -- 31
Dividends declared:
Common stock ($1.1350 per share) -- -- (49,366)
Preferred stock -- -- (1,332)
----------- ----------- -------------
BALANCE SEPTEMBER 30, 1996 (2,697) (538) 558,809
Net income -- -- 82,019
Common stock expense -- -- (3)
Deferred compensation 675 (478) 325
Director compensation plan -- 33 33
Dividend reinvestment plan -- -- 174
Employee savings plans -- -- 138
Conversion of preferred stock -- -- 10
Dividends declared:
Common stock ($1.1700 per share) -- -- (51,139)
Preferred stock -- -- (1,331)
----------- ----------- -------------
BALANCE SEPTEMBER 30, 1997 (2,022) (983) 589,035
Net income -- -- 68,629
Deferred compensation 74 100 429
Director compensation plan -- 82 103
Dividend reinvestment plan -- -- 4,689
Employee savings plans -- 97 693
Conversion of preferred stock -- -- 6
Common stock repurchased -- (2,340) (2,340)
Dividends declared:
Common stock ($1.1950 per share) -- -- (52,158)
Preferred stock -- -- (1,331)
----------- ----------- -------------
BALANCE SEPTEMBER 30, 1998 $(1,948) $(3,044) $607,755
=========== =========== =============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
41
<PAGE> 21
Washington Gas Light Company
CONSOLIDATED STATEMENTS OF INCOME TAXES
<TABLE>
<CAPTION>
1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C>
INCOME TAX EXPENSE, YEARS ENDED SEPTEMBER 30 (Note 6),
Charged to other operating expenses
Current $28,226 $39,674 $39,224
----------- ----------- -----------
Deferred
Accelerated depreciation 11,550 10,438 9,761
Losses/gains on reacquired debt 556 233 (112)
Deferred gas costs 473 (4,283) 11,260
Pensions and other employee benefit costs 879 1,472 (132)
Demand-side management costs (414) 281 (481)
Inventory overheads (962) (562) (4,232)
Other (1,368) 1,565 (4,940)
----------- ----------- -----------
Total Deferred Income Tax Expense 10,714 9,144 11,124
----------- ----------- -----------
Amortization of investment tax credits (934) (954) (972)
----------- ----------- -----------
38,006 47,864 49,376
----------- ----------- -----------
Charged to other income (loss)--net
Current 1,459 (713) (842)
Deferred 341 1,290 213
----------- ----------- -----------
1,800 577 (629)
----------- ----------- -----------
Total Income Tax Expense $39,806 $48,441 $48,747
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
RECONCILIATION BETWEEN THE STATUTORY FEDERAL INCOME
TAX RATE AND THE EFFECTIVE TAX RATE
Income tax at statutory federal income tax rate $37,952 35.00% $45,661 35.00% $45,618 35.00%
Increases (decreases) in tax resulting from:
Accelerated depreciation less amount deferred 2,655 2.44 2,639 2.02 2,705 2.08
Amortization of investment tax credits (934) (.86) (954) (.73) (972) (.75)
Cost of removal (566) (.52) (588) (.45) (431) (.33)
State income taxes 1,840 1.70 2,036 1.56 2,180 1.67
Other items--net (1,141) (1.05) (353) (.27) (353) (.27)
---------- -------- --------- -------- --------- -------
Income Tax Expense and Effective Tax Rate $39,806 36.71% $48,441 37.13% $48,747 37.40%
========== ======== ========= ======== ========= =======
</TABLE>
<TABLE>
<CAPTION>
1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED DEFERRED INCOME TAXES AT SEPTEMBER 30, Current Non-current Current Non-current
-------- ------------- ---------- -------------
<S> <C> <C> <C> <C>
Deferred Income Tax Assets:
Pensions and other employee benefit costs $ 5,038 $ 3,384 $ 5,650 $ 3,898
Uncollectible accounts 2,131 -- 2,766 --
Inventory overheads 10,921 -- 9,734 --
Valuation allowance -- (943) -- (2,670)
Other 878 12,432 1,129 12,807
--------- ------------- ----------- -------------
Total Assets 18,968 14,873 19,279 14,035
--------- ------------- ----------- -------------
Deferred Income Tax Liabilities:
Accelerated depreciation -- 132,080 -- 120,620
Losses/gains on reacquired debt -- 3,669 -- 3,125
Construction overheads -- 2,748 -- 2,914
Income taxes recoverable through future rates -- 15,161 -- 16,284
Deferred gas costs 2,631 1,273 1,832 1,599
Demand-side management costs -- 7,516 -- 7,541
Other -- (2,055) -- (1,366)
--------- ------------- ----------- -------------
Total Liabilities 2,631 160,392 1,832 150,717
--------- ------------- ----------- -------------
Net Accumulated Deferred Income Tax Assets (Liabilities) $16,337 $(145,519) $17,447 $(136,682)
========= ============= =========== =============
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.
42
<PAGE> 22
Washington Gas Light Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
NATURE OF OPERATIONS
Washington Gas Light Company (company) is a public utility that delivers and
sells natural gas to metropolitan Washington, D.C. and adjoining areas in
Maryland and Virginia. At September 30, 1998, a distribution subsidiary,
Shenandoah Gas Company (Shenandoah Gas), served portions of Virginia and West
Virginia. Please refer to Note 13 to the Consolidated Financial Statements for a
discussion of a recent agreement to dispose of Shenandoah Gas' West Virginia
assets. The company also owns a subsidiary that operates an underground storage
field on behalf of the company. At September 30, 1998, the company and its
distribution subsidiary served nearly 820,000 customer meters. Therms delivered
to firm customers accounted for 72% of the company's total therms delivered in
fiscal year 1998, and the company is not dependent on one customer or group of
customers.
The company's unregulated subsidiaries are organized under a wholly owned
subsidiary, Washington Gas Resources Corp (WGR). A gas-marketing subsidiary,
Washington Gas Energy Services, Inc. (WGES), engages in the sale of gas in
competition with unregulated marketers and unregulated marketing subsidiaries
of other utility companies. Other energy-related activities of the company and
its subsidiaries include: (1) providing commercial energy services by designing
and renovating mechanical heating, ventilating and air conditioning systems;
and (2) the financing of gas appliances and certain other equipment for
residential and small commercial customers. During fiscal year 1998, WGR
acquired an additional energy-related business, as more fully discussed in Note
2 to the Consolidated Financial Statements.
CONSOLIDATION
The consolidated financial statements include the accounts of the company and
its subsidiaries. All significant intercompany transactions have been
eliminated. Certain amounts in financial statements of prior years have been
reclassified to conform to the presentation of the current year.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
REGULATED OPERATIONS
The company and its utility subsidiaries account for their regulated operations
in accordance with Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), as
amended and supplemented by subsequently issued standards. These standards set
forth the application of generally accepted accounting principles to those
companies whose rates are determined by an independent third-party regulator.
The economic effects of regulation can result in regulated companies recording
costs that have been or are expected to be allowed in the rate-setting process
in a period different from the period in which the costs would be charged to
expense by an unregulated enterprise. When this results, costs are deferred as
assets in the balance sheet (regulatory assets) and recorded as expenses as
those same amounts are reflected in rates charged to customers. Additionally,
regulators can impose liabilities upon a regulated company for amounts
previously collected from customers and for recovery of costs that are expected
to be incurred in the future (regulatory liabilities). As required by SFAS No.
71 (as amended and supplemented), the company monitors the regulatory and
competitive environment in which it operates to determine that its regulatory
assets continue to be probable of recovery. If the company were to determine
that a regulatory asset is no longer probable of recovery, it would write off
the asset against earnings. At present, the company believes that the provisions
of SFAS No.71 continue to apply to its regulated operations.
The amounts recorded as regulatory assets and regulatory liabilities in the
Consolidated Balance Sheets at September 30, 1998 and 1997 follow:
<TABLE>
<CAPTION>
(Millions) 1998 1997
- --------------------------------------------------------------------
<S> <C> <C>
REGULATORY ASSETS:
Income tax-related amounts
due from customers (Note 6) $ 36.2 $ 38.0
Demand-side management
costs due from customers 21.4 21.7
Other postretirement benefit costs (Note 8) 11.8 13.2
Losses on reacquired debt (Note 10) 9.9 10.1
Gas costs due from customers 9.9 9.4
Environmental response costs (Note 9) 8.5 10.2
Federal Energy Regulatory Commission
Order No. 636 transition costs due
from customers (Note 10) 3.7 4.0
Purchased gas costs 3.6 4.5
Other 0.3 0.3
------ ------
$105.3 $111.4
====== ======
REGULATORY LIABILITIES:
Income tax-related amounts
due to customers (Note 6) $ 21.1 $ 21.7
Gas costs due to customers 5.7 2.4
Refunds due to customers 1.4 6.1
Demand-side management costs due to customers 0.8 1.1
Other 4.6 3.1
------ ------
$ 33.6 $ 34.4
====== ======
</TABLE>
43
<PAGE> 23
Washington Gas Light Company
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at original cost including labor,
materials, taxes and overheads. The company capitalizes an Allowance for Funds
Used During Construction (AFUDC) as a component of construction overheads. The
company capitalized AFUDC of $815,000, $411,000, and $465,000 in 1998, 1997 and
1996, respectively.
For its utility operations, the company charges the original cost of
depreciable units of plant retired, together with the cost of removal, net of
salvage, to accumulated depreciation. Maintenance and repairs are charged to
operating expenses, except that charges applicable to transportation and
power-operated equipment are allocated to operating expenses, construction and
other accounts based on the use of such equipment. Betterments and renewals are
capitalized. Depreciation applicable to the company's gas plant in service is
calculated primarily on a straight-line remaining life basis. The composite
depreciation rate was 2.93% for 1998, 2.94% for 1997 and 2.96% for 1996. The
company periodically reviews the adequacy of its depreciation rates by
considering estimated remaining lives and other factors.
REVENUE AND COST RECOGNITION
Included in Operating Income
Revenues. For regulated deliveries of natural gas, the company reads meters and
bills customers on a cycle basis. It accrues revenues for gas delivered but not
yet billed.
Cost of Gas. The company's jurisdictional tariffs contain gas cost mechanisms
that provide for the recovery of the invoice cost of gas applicable to firm
customers. Under these mechanisms, the company periodically adjusts its rates to
firm customers to reflect increases and decreases in the invoice cost of gas.
Annually, the company reconciles the differences between the total gas costs
collected from firm customers and the invoice cost of gas. The company defers
any excess or deficiency and recovers from or refunds to customers the deferred
balance over a subsequent twelve-month period. The captions "Gas costs due from
customers" and "Gas costs due to customers" in the Consolidated Balance Sheets
reflect amounts related to these reconciliations.
Included in Other Income
Energy Marketing. WGES, the company's gas-marketing subsidiary, sells natural
gas to residential, commercial and industrial customers both inside and outside
of the company's service territory on an unregulated basis. Customer contracts
provide for WGES to bill customers based on: (1) quantities delivered to the
entry point of the local utility's distribution system; or (2) customer metered
usage. WGES recognizes revenues based on the amounts billed to customers.
WGES purchases gas for delivery to the entry point of the local utility's
distribution system; however, the amounts actually delivered to customers may
differ. For sales contracts based on quantities delivered to the entry point of
the local utility's distribution system, WGES records gas costs based on the
cost of gas delivered to the local utility's distribution system. For sales
contracts based on customers' metered usage, WGES estimates gas costs using the
margin inherent in the contracts applied to the volumes metered. Any differences
in gas costs invoiced and recorded as expense are deferred until the volumes are
delivered to customers at a future date.
Commercial Energy Services. The company's unregulated subsidiaries engaged in
the designing and renovating of mechanical heating, ventilating and air
conditioning systems enter into construction contracts as part of their business
activities. These subsidiaries recognize income using the
percentage-of-completion method for contracts with terms equal to or greater
than one year.
Under the percentage-of-completion method of accounting, the company records
income as work on contracts progress. That income is based on a percentage of
estimated total income using the percentage that incurred costs to date bear to
estimated total costs, after giving effect to estimates of costs to complete.
Under this method, current assets may include costs and recognized income not
yet billed, with respect to certain contracts; and current liabilities may
include billings in excess of costs and recognized income with respect to other
contracts. When the current estimate of total contract costs indicates a loss,
provision is made for the loss on the entire contract.
RATE REFUNDS DUE TO CUSTOMERS
The company records a provision for rate refunds for the difference between the
amount it is collecting in rates subject to refund and the amount expected to be
recovered as a result of a final regulatory decision. At September 30, 1998, the
company was not collecting any rates subject to refund.
REACQUISITION OF LONG-TERM DEBT
Gains or losses resulting from the reacquisition of long-term debt are deferred
for book purposes and amortized over future periods as adjustments to interest
expense in accordance with established regulatory practice. The company realized
and deferred losses of $0.5 million in 1998, $1.7 million in 1997 and $2.3
million in 1996. For income tax purposes, the company recognizes these gains and
losses when the debt is legally retired. Additional discussion of losses on
reacquired debt is included in Note 10 to the Consolidated Financial Statements.
DERIVATIVE ACTIVITIES
The company's derivative activities currently encompass hedge transactions
designed to manage interest rate risk associated with planned issuances of
Medium-Term Notes (MTNs). The company's interest costs associated with issuing
MTNs reflect coupon spreads over comparable maturity U.S. Treasury yields plus
additional costs for issuing corporate debt. During fiscal year 1998, in order
to lock in the U.S. Treasury yield for planned issuances of MTNs, the company
entered into agreements for the forward sale of U.S. Treasury notes at a fixed
price. The company accounts for these forward sales as hedges of anticipated
transactions in accordance with Statement of Financial Accounting Standards No.
80, "Accounting for
44
<PAGE> 24
Washington Gas Light Company
Futures Contracts" (SFAS No. 80). When the company settles hedge transactions
as part of issuances of MTNs, it recognizes the related gains and losses as MTN
issuance costs. If the company were to terminate a hedge agreement without
issuing MTNs, the gain or loss would be recognized in earnings immediately. See
Note 4 to the Consolidated Financial Statements for a discussion of interest
rate hedges outstanding at September 30, 1998.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS No. 133). This statement is effective for fiscal
years beginning after June 15, 1999, and the company must adopt it no later than
fiscal year 2000. SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
formally document, designate, and assess the effectiveness of transactions that
receive hedge accounting. The company is reviewing SFAS No. 133 and does not
currently expect it to materially impact its financial condition or results of
operations.
2. ACQUISITIONS AND DISPOSITIONS
ACQUISITION OF SUBSIDIARY
On March 25, 1998, WGR acquired a 100% interest in American Combustion, Inc.
and American Combustion Industries, Inc. The two companies are jointly operated
under the name ACI. ACI is a heating, ventilating and air-conditioning
contracting firm serving commercial customers in the Washington, D.C.
metropolitan area. The company purchased ACI with $3.0 million in cash and the
issuance of a $2.0 million promissory note that is being repaid in monthly
installments over two years. The company accounted for the acquisition using
the purchase method of accounting. The excess of the purchase price over net
assets acquired was recognized as goodwill and is being amortized on a
straight-line basis over fifteen years. The Consolidated Financial Statements
include the accounts of ACI since the date of acquisition. The effect of the
acquisition is not material to the company's results of operations or financial
position and, therefore, pro forma financial information is not presented.
DISPOSITION OF RETAIL PROPANE ASSETS
On May 1, 1998, the company sold all of its retail propane assets for $4.1
million, recognizing a gain of $2.5 million ($1.6 million after income taxes).
In fiscal year 1997, net income from propane sales amounted to less than
one-half of 1% of the company's total net income.
3. SHORT-TERM DEBT
The company satisfies its short-term financing requirements through the sale of
commercial paper or bank borrowings. The company maintains credit lines and a
revolving credit agreement to support its outstanding commercial paper and to
permit short-term borrowing flexibility. The table below summarizes the major
terms of financing options available to the company at September 30, 1998:
<TABLE>
<CAPTION>
Description/ Commitment or Facility
Amount of Credit Fees per Annum Expiration Date
- ---------------------------------------------------------------------------
<S> <C> <C>
Permanent Lines of Credit:
$ 5 million 0.07% June 29, 1999
$ 10 million 0.04% June 29, 1999
$ 10 million 0.07% June 30, 1999
Seasonal Lines of Credit:
$ 5 million 0.07% April 1, 1999
if activated
$ 10 million 0.07% April 30, 1999
if activated
Revolving Credit Agreement:
$160 million 0.04% May 22, 1999
</TABLE>
At September 30, 1998, the permanent lines of credit were unused. The
seasonal lines of credit became available on October 1, 1998 and are available
during most of the heating season.
The short-term revolving credit agreement is provided by a group of banks.
The company can reduce the amount of the commitment at its option. Under the
agreement, the banks apply the facility fees to the daily average amount of the
commitment. The agreement allows for an annual extension by mutual agreement,
with an ultimate termination date no later than May 26, 2000.
Collectively, the borrowing options under the bank lines of credit and the
revolving credit agreement include the prime lending rate, as well as rates
based on certificates of deposit and London Interbank Offered Rates.
At September 30, 1998, the company and its subsidiaries had $124.9 million in
short-term debt outstanding, excluding current maturities of long-term debt, at
a weighted-average cost of 5.71%. At September 30, 1997, the company had $67.9
million in short-term debt outstanding, excluding current maturities of
long-term debt, at a weighted-average cost of 5.68%.
45
<PAGE> 25
Washington Gas Light Company
4. LONG-TERM DEBT
FIRST MORTGAGE BONDS
The company's Mortgage dated January 1, 1933 (Mortgage), as supplemented and
amended, securing the First Mortgage Bonds (FMBs) issued by the company,
constitutes a direct lien on substantially all property and franchises owned by
the company other than expressly excepted property.
UNSECURED MEDIUM-TERM NOTES
The company issues unsecured MTNs whose terms are individually set as to
interest rate, maturity and any call or put option. These notes can have
maturity dates of one or more years from date of issuance. The company can not
issue any FMBs under its Mortgage without making effective provision whereby any
outstanding MTNs shall be secured equally and ratably with any and all other
obligations and indebtedness secured by the Mortgage. At September 30, 1998 and
1997, the weighted-average interest rate on all outstanding MTNs was 6.77% and
6.81%, respectively.
In fiscal year 1998, the company issued a total of $72.0 million in MTNs. The
table below summarizes the terms of each MTN issuance. For certain of these
MTNs, as indicated below, the company has an option to redeem the MTNs at any
time, as a whole or in part, at the greater of: (1) par value; or (2) the price
implied in the yield to maturity, plus 20 basis points, of a comparable-maturity
U.S. Treasury security.
MEDIUM-TERM NOTES ISSUED
<TABLE>
<CAPTION>
Fiscal Year Redeemable
Amount of Coupon Maturity Prior To
Date Issued Issuance Rate Date Maturity
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C>
January 1998 $10 million 6.57% 2028 No
February 1998 12 million 6.72% 2028 Yes
March 1998 4 million 6.85% 2028 Yes
March 1998 26 million 6.81% 2028 Yes
March 1998 20 million 6.65% 2023 Yes
-----------
Total $72 million
===========
</TABLE>
INTEREST RATE HEDGES
At September 30, 1998, the company had two interest rate hedge agreements
outstanding in connection with planned issuances of MTNs. As described in Note 1
to the Consolidated Financial Statements, the company accounted for these
agreements as hedges of anticipated transactions in accordance with SFAS No. 80.
Any gain or loss associated with settlement of these hedge agreements is
recognized as an MTN debt issuance cost.
On June 15, 1998, in order to lock in the Treasury yield for the anticipated
issuance of $25 million of 10-year MTNs in November 1998, the company entered
into an agreement that reflects the forward sale of $24,875,000 of 10-year U.S.
Treasury notes at a fixed price to be paid on November 3, 1998. The company
unwound its hedge position concurrent with the issuance of $25 million of MTNs
in October 1998. The notes have a 10-year nominal life and a coupon rate of
5.49%. The $2.1 million loss associated with the settlement of this hedge
agreement was recorded as a debt issuance cost and will be amortized over the
life of the MTNs. The effective cost of the debt is 6.74%.
The company has $39 million of 8-3/4% FMBs that can be called by the company,
or put to the company on July 1, 1999. On September 2, 1998, in order to lock in
the Treasury yield for an anticipated $39 million MTN issuance which will be
used to refund the 8-3/4% FMBs, the company entered into an agreement that
reflects the forward sale of $40 million of 10-year U.S. Treasury notes at a
fixed price to be paid on July 1, 1999.
MATURITIES AND SINKING FUND REQUIREMENTS
The amount of maturities and sinking fund requirements on long-term debt for the
ensuing five-year period at September 30, 1998 is $64.1 million in 1999, $2.9
million in 2000, $0.1 million in 2001, $47.7 million in 2002, and $35.1 million
in 2003.
5. COMMON STOCK AND EARNINGS PER SHARE
COMMON STOCK OUTSTANDING
Shares of Common Stock outstanding, net of Treasury stock, were 43,839,453 at
September 30, 1998, 43,699,516 at September 30, 1997, and 43,703,476 at
September 30, 1996.
COMMON STOCK RESERVES
At September 30, 1998, there were 1,418,795 authorized but unissued shares of
Common Stock reserved as follows:
<TABLE>
<S> <C>
Dividend Reinvestment and
Common Stock Purchase Plan 746,942
Employee Savings Plans 205,392
Long-Term Incentive Compensation Plan 391,050
Directors' Stock Compensation Plan 33,083
Conversion of Convertible Preferred Stock 42,328
---------
Total 1,418,795
=========
</TABLE>
STOCK-BASED COMPENSATION
The company periodically provides compensation in the form of Common Stock to
certain employees and company directors. This stock-based compensation is
designed to promote the long-term success of the company by recruiting and
retaining employees, and giving certain employees and company directors an
ownership interest in the company. Each of the company's stock-based
compensation arrangements is discussed more fully below.
46
<PAGE> 26
Washington Gas Light Company
As permitted under Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" (SFAS No. 123), the company applies
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" (APB No. 25) in accounting for its stock-based compensation. Because
the company values shares that it grants as stock-based compensation at fair
value (market value) on the grant date in determining compensation expense, net
income and earnings per share for fiscal years 1998, 1997 and 1996 are the same
under the expense recognition provisions of both APB No. 25 and SFAS No. 123.
Restricted Stock Granted to Employees
The company has granted restricted stock to participants in the Long-Term
Incentive Compensation Plan (LTICP) and to certain non-LTICP employees. These
shares are subject to restrictions on vesting, sale and transferability.
Restrictions lapse with the passage of time. As the restrictions on vesting
lapse, the company recognizes expense ratably over the restriction period. This
expense amounted to $955,000 in 1998, $952,000 in 1997 and $1,498,000 in 1996.
The company holds the certificates for restricted stock until they are fully
vested, but the recipients are entitled to full dividend and voting rights
during this period. The following table summarizes the grants of restricted
stock over the past three fiscal years. Shares granted in 1998 and 1997 were
previously held as Treasury stock.
<TABLE>
<CAPTION>
1998 1997 1996
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Shares of Restricted Stock Granted 32,350 17,850 127,100
Weighted-Average Fair Value
of Stock on Grant Dates $27.21 $22.16 $20.08
</TABLE>
Other Employee Stock Grants
In fiscal year 1996, the company made the following stock grants to employees:
(1) stock granted to certain employees through the Savings Plan, as described in
Note 8 to the Consolidated Financial Statements; and (2) a stock grant of 45,313
shares to eligible employees, at a weighted-average fair value on the grant date
of $20.87 per share, for a total expense of approximately $946,000. These shares
of stock were not subject to any restrictions.
Stock Grants to Directors
Non-employee directors receive a portion of their annual retainer fee in the
form of common stock through the Directors' Stock Compensation Plan. Shares
granted to directors totaled 3,725 in 1998, 1,589 in 1997 and 1,603 in 1996. The
fair value of the stock on the grant date was $27.31 in 1998, $21.94 in 1997 and
$21.81 in 1996. Shares granted in 1998 and 1997 were previously held as Treasury
stock. Shares awarded to the participants are immediately vested and
nonforfeitable, may be sold or transferred and have voting and dividend rights.
EARNINGS PER SHARE
The company adopted Statement of Financial Accounting Standards No. 128,
"Earnings Per Share" in the first quarter of fiscal year 1998. Basic and diluted
earnings per share (EPS) for the fiscal years ended September 30, 1997 and 1996
are the same as previously reported primary and fully diluted EPS, respectively,
for those periods. Basic EPS is computed by dividing net income applicable to
common stock by the weighted average number of common shares outstanding during
the period. Diluted EPS assumes conversion of convertible preferred stock at the
beginning of the applicable fiscal year. EPS calculations for the last three
fiscal years are shown below:
<TABLE>
<CAPTION>
Per Share
For the Year Ended September 30, 1998 Income Shares Amount
- ----------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C>
BASIC EPS:
Net Income Applicable
to Common Stock $67,298 43,691 $1.54
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible
Preferred Stock, Assuming
Conversion on October 1, 1997 11 26
------- ------
DILUTED EPS:
Net Income Applicable to Common
Stock Plus Assumed Conversions $67,309 43,717 $1.54
======= ====== =====
For the Year Ended September 30, 1997
- ----------------------------------------------------------------------------
BASIC EPS:
Net Income Applicable
to Common Stock $80,688 43,706 $1.85
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible
Preferred Stock, Assuming
Conversion on October 1, 1996 11 27
------- ------
DILUTED EPS:
Net Income Applicable to Common
Stock Plus Assumed Conversions $80,699 43,733 $1.85
======= ====== =====
For the Year Ended September 30, 1996
- ----------------------------------------------------------------------------
BASIC EPS:
Net Income Applicable
to Common Stock $80,259 43,360 $1.85
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible
Preferred Stock, Assuming
Conversion on October 1, 1995 12 31
------- ------
DILUTED EPS:
Net Income Applicable to Common
Stock Plus Assumed Conversions $80,271 43,391 $1.85
======= ====== =====
</TABLE>
47
<PAGE> 27
Washington Gas Light Company
6. INCOME TAXES
The company and its subsidiaries file a consolidated federal income tax return.
The company's federal income tax returns for all years through September 30,
1994 and for the year ended September 30, 1996 have been reviewed and closed or
closed without review by the Internal Revenue Service.
The company is amortizing investment tax credits as credits to income over
the estimated service lives of the related properties.
The company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No.
109). Under SFAS No. 109, deferred income taxes are recognized for all temporary
differences between the financial statement and tax basis of assets and
liabilities at currently enacted income tax rates.
SFAS No. 109 required recognition of the additional deferred income tax
assets and liabilities for temporary differences for which deferred income tax
treatment was prohibited for ratemaking purposes. Regulatory assets or
liabilities corresponding to such additional deferred tax assets or liabilities
are recorded to the extent the company believes they will be recoverable from or
be payable to customers through the ratemaking process. The company's regulatory
assets and liabilities associated with income taxes due from and to customers at
September 30, 1998 and 1997, are shown in Note 1 to the Consolidated Financial
Statements. Amounts applicable to income taxes due from and to customers
primarily represent differences between the book and tax basis of net utility
plant in service.
The Consolidated Statements of Income Taxes on page 42 show the components of
income tax expense, a reconciliation between income tax expense computed by
using the statutory federal income tax rate and the actual income tax expense
recorded, and the components of accumulated deferred income tax assets and
liabilities at September 30, 1998 and 1997.
7. GENERAL TAXES
The company is subject to significant taxes that are not related to income. The
amount of such general taxes recorded in the financial statements for the last
three years is detailed in the following table:
<TABLE>
<CAPTION>
Years Ended September 30, 1998 1997 1996
- --------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Type of Tax:
Gross receipts $44.2 $46.6 $44.1
Property 18.6 17.8 16.5
Payroll 8.6 8.9 9.3
Other 1.1 1.0 0.8
---- ---- ----
Total General Taxes $72.5 $74.3 $70.7
==== ==== ====
Allocation of Taxes:
Charged to operating expenses $69.2 $71.3 $68.6
Charged to other income (loss)-net 1.4 1.0 0.3
Charged to construction 1.9 2.0 1.8
---- ---- ----
Total General Taxes $72.5 $74.3 $70.7
==== ==== ====
</TABLE>
8. POSTEMPLOYMENT BENEFITS
PENSION BENEFITS
The company maintains a qualified, trusteed, noncontributory defined benefit
pension plan covering all active and vested former employees of the company and
its utility subsidiaries. Executive officers also participate in a nonfunded
supplemental executive retirement plan (SERP). A trust has been established for
the future funding of the SERP liability. It is the company's policy to fund
pension costs accrued for the qualified plan to the extent allowable by law.
Plan assets consist primarily of common stock and fixed income securities.
Net periodic pension cost included the following components:
<TABLE>
<CAPTION>
Years Ended September 30, 1998 1997 1996
- ----------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Service cost--benefits
earned during the period $ 9.3 $ 7.8 $ 8.9
Interest cost on projected benefit obligation 32.2 28.7 27.0
Actual return on plan assets (67.0) (87.7) (54.5)
Net amortization and deferral 25.7 46.8 17.6
---- ---- ----
Net periodic pension (income) cost $ 0.2 $ (4.4) $ (1.0)
==== ==== ====
Expected long-term rate
of return on plan assets 8.25% 8.25% 8.25%
==== ==== ====
</TABLE>
The following table sets forth the funded status of the plans at September
30, 1998 and 1997.
<TABLE>
<CAPTION>
(Millions) 1998 1997
- -------------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefit obligation $(403.8) $(340.0)
===== =====
Accumulated benefit obligation $(429.7) $(363.6)
===== =====
Projected benefit obligation $(495.4) $(428.2)
Plan assets at market value 631.2 591.4
----- -----
Plan assets in excess of projected
benefit obligation 135.8 163.2
Unrecognized net gains (171.0) (185.8)
Unrecognized prior service costs 26.5 15.8
Unrecognized net asset at transition (7.8) (10.2)
----- -----
Accrued pension costs in the
consolidated balance sheets $ (16.5) $ (17.0)
===== =====
Discount rate 6.50% 7.50%
===== =====
Rate of compensation increase 4.00% 4.50%
===== =====
</TABLE>
In fiscal year 1998, the company amended its pension plan to enhance the
pension benefit formula to participants. The amendment increased the projected
benefit obligation by $12.8 million and increased the fiscal year 1998 pension
expense by $2.5 million.
48
<PAGE> 28
Washington Gas Light Company
OTHER POSTRETIREMENT BENEFITS
The company provides certain health care and life insurance benefits for retired
employees. Substantially all employees may become eligible for such benefits if
they attain retirement status while working for the company. The company
accounts for these benefits under the provisions of Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions" (SFAS No. 106). The company elected to amortize the
accumulated postretirement benefit obligation existing at the October 1, 1993
adoption date of this standard (the transition obligation) of $190.6 million
over a twenty-year period.
Net periodic postretirement benefit cost included the following components:
<TABLE>
<CAPTION>
Years Ended September 30, 1998 1997 1996
- ---------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Service cost--benefits attributed
to service during the period $ 4.5 $ 4.6 $ 4.9
Interest cost on accumulated
postretirement benefit obligation 14.5 15.0 14.1
Actual return on plan assets (4.2) (2.9) (1.8)
Amortization of transition obligation 9.6 9.5 9.5
Other (2.9) (2.0) (1.7)
----- ----- -----
Net periodic postretirement benefit cost 21.5 24.2 25.0
Amount capitalized as construction cost (4.2) (4.8) (4.6)
Amount deferred as a regulatory asset-net
(Note 10) 1.5 (0.7) (2.0)
----- ----- -----
Amount charged to expense $18.8 $18.7 $18.4
===== ===== =====
</TABLE>
The following table sets forth the funded status of the trusteed plans at
September 30, 1998 and 1997.
<TABLE>
<CAPTION>
(Millions) 1998 1997
- ---------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees $(119.2) $ (98.9)
Fully eligible active employees (14.3) (15.2)
Other active employees (91.1) (84.0)
------- -------
Total accumulated postretirement
benefit obligation (224.6) (198.1)
Plan assets at fair value--invested
primarily in debt securities 83.5 66.4
------- -------
Accumulated postretirement benefit
obligation in excess of plan assets (141.1) (131.7)
Unrecognized net gains (23.6) (42.2)
Unrecognized transition obligation 143.0 152.6
------- -------
Accrued postretirement benefit costs
in the consolidated balance sheets $ (21.7) $ (21.3)
======= =======
Discount rate 6.50% 7.50%
======= =======
Rate of compensation increase 4.00% 4.50%
======= =======
</TABLE>
The assumed health care cost trend rates for fiscal year 1999 for Medicare
eligible and non-Medicare eligible retirees are 6.25% and 7.50%, respectively;
these rates are assumed to decrease gradually to 5.00% and 5.25%, respectively,
in 2003 and remain at those levels thereafter. The health care cost trend rate
assumption has a significant effect on the amounts reported. If the health care
cost trend rate were increased by 1 percentage point in each year, the
accumulated postretirement benefit obligation at September 30, 1998 would
increase by $29.1 million, and the aggregate of the service and interest cost
components of net periodic postretirement benefit cost for fiscal year 1998
would rise by $2.8 million.
Almost all of the estimated postretirement benefit costs and the transition
obligation are applicable to the company's and its subsidiaries' rate-regulated
activities. The Public Service Commission of the District of Columbia (PSC of
DC) granted the company recovery of postretirement benefit costs determined in
accordance with generally accepted accounting principles (GAAP) through a
five-year phase-in plan that ended September 30, 1998. The company deferred the
difference generated during the phase-in period as a regulatory asset. Effective
October 1, 1998, the PSC of DC granted the company full recovery of costs
determined under GAAP plus a fifteen-year amortization of the regulatory asset
established during the phase-in period. In an order dated September 28, 1995,
the State Corporation Commission of Virginia (SCC of VA) granted the company
recovery in accordance with a generic order allowing for recovery of costs
determined under GAAP in rates, with the exception of allowing recovery of the
transition obligation over forty years as opposed to the twenty-year maximum
amortization allowed under GAAP. The Public Service Commission of Maryland (PSC
of MD) has not rendered a decision to the company that specifically addresses
recovery of postretirement benefit costs determined in accordance with GAAP;
however, the level of rates the PSC of MD has allowed is sufficient to recover
the cost determined under GAAP. The amount of postretirement benefit costs
deferred as a regulatory asset at September 30, 1998 is $11.8 million, and the
company expects that these costs will be recovered over a twenty-year period
that began October 1, 1993.
All of the regulatory commissions having jurisdiction over the company's
rates require the company to fund amounts reflected in rates for postretirement
benefits to irrevocable trusts. The expected long-term rate of return on the
assets in the trust was 8.25% for 1998 and 1997. To the extent the income in the
trusts is taxable, the income tax rate associated with the taxable portion of
this return is assumed to be 39.6%.
EMPLOYEE SAVINGS PLANS
The company and its subsidiaries offer savings plans for eligible employees,
covering all employee groups, that are designed to provide employees with an
incentive to save and invest regularly. The plans are defined
49
<PAGE> 29
Washington Gas Light Company
contribution plans, allowing salary deferral by participants from 1 percent to
14 percent of their salaries invested among various alternatives. An employer
contribution, which varies by plan, ranges from 25% of the first 1.25%, to 100%
of the first 4%, of employees' pre-tax contributions. For plans that allow
employees to make after-tax contributions, the employer contribution is equal to
100 percent of the first 2 percent and 50 percent of the next 2 percent of the
employees' after-tax contributions. Employer contributions can be invested among
various alternatives.
Contributions to the plans by the company and its subsidiaries for fiscal
years 1998, 1997 and 1996 were $2.2 million each year. In fiscal year 1996, the
company granted 100 shares of stock to the savings plan accounts of certain
employees. The cost per share was $23.558, for total compensation expense to the
company of $1.8 million.
9. ENVIRONMENTAL MATTERS
The company and its subsidiaries are subject to federal, state and local laws
and regulations related to environmental matters. These evolving laws and
regulations may require expenditures over a long period of time to control
environmental impacts.
Estimates of liabilities for environmental response costs are difficult to
determine with precision because of the factors that can affect their ultimate
level. These factors include, but are not limited to: (1) the complexity of the
site; (2) changes in environmental laws and regulations at the federal, state
and local levels; (3) the number of regulatory agencies or other parties
involved; (4) new technology that renders previous technology obsolete, or
experience with existing technology that proves ineffective; (5) the ultimate
selection of technology; (6) the level of remediation required; and (7)
variations between the estimated number of years that must be devoted to respond
to an environmentally contaminated site as compared to the actual number of
years required.
The company has identified up to ten sites where the company, its
subsidiaries, or their predecessors may have operated manufactured gas plants
(MGPs). The company last used any such plant in 1984. In connection with these
operations, the company is aware that certain by-products of the gas
manufacturing process are present at or near some former sites and may be
present at others.
At one of the former MGP sites, studies show the presence of coal tar under
the site and an adjoining property. The company's risk assessment study
performed on the site shows that there is no unacceptable risk to human health
or the environment. The company has taken steps to control the movement of
contaminants into an adjacent river. A water treatment system removes and treats
groundwater at the site. The company continues to advance discussions of
remediation options with the appropriate governmental agency and the adjacent
landowner. The company completed a feasibility study of remedial alternatives in
fiscal year 1998 and submitted its recommended remedial action plan to the
governmental agency. The company expects the governmental agency to issue a
decision document outlining the appropriate remediation methodology.
At a second former MGP site, tests identified tar products under the
property, and a risk assessment showed that there was no unacceptable risk to
human health or the environment. The company designed and installed a
state-approved treatment and recovery system to recover free tar and continues
to recover minimal volumes of tar products from pumping. The company will
continue to pump tar, monitor the site and provide annual activity reports to
the state's Department of the Environment.
At a third former MGP site, initial studies identified that tar products are
present under the property, and a risk assessment showed that there was no
unacceptable risk to human health or the environment. The company completed and
submitted a remedial investigation/feasibility study (RI/FS) to the appropriate
state regulatory agency. The company has yet to receive any response from the
state regarding its submission, but continues to monitor the site.
At a fourth former MGP site and on an adjacent parcel of land, the company
plans to apply for the state voluntary closure program, which will require some
additional study to determine appropriate remediation.
At a fifth former MGP site, a treatment system for contaminated groundwater
has been operating for eight years. The company believes, at this time, that no
additional action other than water treatment will be necessary.
At a sixth former MGP site, a governmental authority has notified the company
about the detection of tar in an adjacent river. At this time, the extent and
nature of any contamination and the company's related obligation, if any, to
perform remediation can not be determined. The company will continue its
discussions with the governmental authority and may perform studies to assess
the extent and nature of contamination as well as the need for remediation.
Through September 30, 1998, the company had paid $10.5 million for
environmental response costs. The company has recorded a liability of $9.1
million on an undiscounted basis at September 30, 1998 related to future
environmental response costs. This estimate is primarily composed of the minimum
liabilities associated with a range of environmental response costs expected to
be incurred at five of the six sites described above. The company estimates the
maximum liability associated with these sites to be approximately $18.6 million
at September 30, 1998. The estimates were determined by the company's
environmental experts based on experience in remediating MGP sites and advice
from legal counsel and environmental consultants. Variations within the range of
estimated liability result primarily from differences in the number of years
that will be required to perform environmental response processes at each site
(5 to 25 years) and the extent of remediation that may be required.
The company believes, at this time, that no remediation of any of the
remaining four sites will be necessary.
Regulatory orders issued by the PSC of MD allow the company to recover the
costs associated with the sites applicable to Maryland over periods ranging from
five to thirty years. Orders issued by the PSC of DC allow the company a
three-year recovery of prudently incurred environmental response costs and allow
the company to defer additional costs incurred between rate cases. At September
30, 1998, there is no environmental regulatory asset subject to recovery in
Virginia. The Public Service
50
<PAGE> 30
Washington Gas Light Company
Commission of West Virginia (PSC of WVA) has allowed a subsidiary to recover a
portion of environmental response costs.
At September 30, 1998, the company has recorded a regulatory asset of $8.5
million for the portion of environmental response costs it believes are
recoverable in rates. Based on existing knowledge, the company does not expect
that the ultimate impact of these matters will have a materially adverse effect
on its financial condition or results of operations.
10. COMMITMENTS AND CONTINGENCIES
The company is involved in certain legal and administrative proceedings
concerning claims arising in the ordinary course of business. In the opinion of
management, the company has recorded adequate provisions for probable losses
related to these proceedings and management does not expect the final
resolution of these matters will have a materially adverse effect on the
company's financial position or results of operations.
TRANSFERS AND SERVICING OF FINANCIAL ASSETS
The company has extended credit to certain residential and small commercial
customers to purchase gas appliances and equipment and energy conservation
products. The company transfers with recourse certain of these accounts
receivable to commercial banks. Effective for transfers after December 31, 1996,
the company accounts for these transfers in accordance with Statement of
Financial Accounting Standards No. 125, "Accounting for Transfers and Servicing
of Financial Assets and Extinguishment of Liabilities" (SFAS No. 125), which
supersedes Statement of Financial Accounting Standards No. 77, "Reporting by
Transferors for Transfers of Receivables with Recourse" (SFAS No. 77).
The company's transfers of receivables with recourse totaled $27.2 million in
1998, $33.0 million in 1997 and $30.5 million in 1996. The transfers after
December 31, 1996 were recognized as a sale in accordance with SFAS No. 125 and
in accordance with SFAS No. 77 for prior sales. Under the sales agreements with
the banks, the company acts as an agent for the bank and services the
receivables. At September 30, 1998, the company had a $1.4 million receivable
representing the present value of estimated future net cash flows related to
these sales. The company has also recognized a liability related to its
estimated recourse obligation for sales of receivables in 1998 and 1997.
Receivables transferred with recourse are considered financial instruments
with off-balance sheet risk. At September 30, 1998, the company's exposure to
credit loss in the event of non-performance by customers is represented by the
$52.6 million balance of transferred receivables that remain outstanding, less
the recourse obligation of $0.4 million (for transfers after December 31, 1996)
and a provision for uncollectible accounts of $1.2 million (for transfers prior
to January 1, 1997).
NATURAL GAS CONTRACTS
Regulated Operations
The company has 12 long-term natural gas purchase contracts with producers or
marketers to purchase natural gas at market-sensitive prices. These contracts
provide for commodity charges based upon an ascertainable index and either fixed
reservation charges based on contracted minimum volumes or premiums built into
volumetric charges. The contracts also provide for the company to pay monthly
and/or annual deficiency charges if actual volumes fall below minimum levels.
These gas purchase contracts have expiration dates ranging from fiscal years
1999 to 2004. At September 30, 1998, the company is required to make total fixed
payments under these natural gas purchase contracts in the amount of
approximately $25.8 million, including annual payments of $6.9 million in 1999,
$6.5 million in 2000, $5.4 million in 2001, $3.9 million in 2002, and $3.0
million in 2003.
At September 30, 1998, the company also had pipeline service agreements with
four pipelines that serve the company directly and four upstream pipelines that
provide for firm transportation and storage services. These agreements, which
have expiration dates ranging from fiscal years 1999 to 2016, provide for the
company to pay fixed monthly charges. The aggregate amount of required payments
under the pipeline service agreements totals approximately $768 million at
September 30, 1998, including required annual payments of $104 million in 1999,
$103 million in 2000, $94 million in 2001, $83 million in 2002, and $76 million
in 2003.
The company recovers the costs incurred under these natural gas purchase
contracts as part of the cost of gas through the gas cost recovery mechanisms
included in the company's retail rate schedules in each jurisdiction in which
the company operates.
Unregulated Operations
WGES, the company's gas-marketing subsidiary, has contracts to purchase fixed
quantities of natural gas with terms of up to 24 months. Purchase contracts are
designed to match the duration of WGES' sales commitments and to effectively
lock in a margin on gas sales over the terms of existing sales contracts.
At any point in time, WGES may have a difference between the volumes of
natural gas committed to its customers and the volumes of purchase commitments.
WGES' open position at September 30, 1998 was not material to the company's
financial position or results of operations.
51
<PAGE> 31
Washington Gas Light Company
FERC ORDER NO. 636 AND TRANSITION COSTS
On November 1, 1993, the Federal Energy Regulatory Commission (FERC) implemented
Order No. 636 (Order). The Order removed the merchant function from interstate
pipeline companies' operations and required them to provide storage and
transportation services to gas shippers such as the company.
The pipeline companies are incurring certain costs, known as transition
costs, in connection with the implementation of the Order. Transition costs that
the FERC considers to be prudently incurred can be recovered from customers of
the pipelines, such as the company. Through September 30, 1998, the company had
paid $47.2 million in such costs to six pipeline companies and currently
estimates that additional transition costs to be assigned to the company will
not be less than $3.7 million. The company has recorded a liability in the
balance sheet at September 30, 1998 in this amount.
The total level of transition costs that will ultimately be incurred by the
company and reflected in the financial statements cannot be estimated at this
time. This is because either the costs have yet to be incurred by the applicable
pipeline companies, or the level of costs may be affected by requests pending or
to be filed at FERC.
The company is currently in the process of collecting transition costs paid
to the pipeline companies through the gas cost recovery mechanisms of the
company's retail rate schedules. At September 30, 1998, the company had recorded
a regulatory asset of $3.7 million for amounts yet to be recovered from its
customers.
VIRGINIA REGULATORY MATTERS
In those years when the company does not request a modification of its basic
rates, the company is required to make a filing with the SCC of VA that provides
the basis for the Staff of the Commission to make a recommendation to the SCC of
VA on the reasonableness of the company's rates on a prospective basis (referred
to as the company's Annual Information Filing).
Losses on Reacquired Debt
In August 1997, the Staff of the SCC of VA issued its report in response to the
company's 1996 Annual Information Filing. They concluded that the company's
calendar year 1996 earnings level (under an "earnings test," as defined by the
Staff of the SCC of VA) effectively allowed the company to recover certain
regulatory assets associated with losses on reacquired debt recorded on the
company's books at December 31, 1996, and thus recommended that these regulatory
assets should be written off. The company took exception to the Staff's report,
and both the company and Staff participated in a hearing in which both parties
presented their positions before a Hearing Examiner in October 1997. On June 25,
1998, the Hearing Examiner issued a report recommending that the SCC of VA order
the company to write off the portion of the regulatory asset related to losses
on reacquired debt incurred during the twelve months ended December 31, 1996.
The company disagreed with the conclusions of the Hearing Examiner, and the
company and the Staff filed comments with the SCC of VA on July 10, 1998.
On August 6, 1998, the SCC of VA issued an order ruling that any regulatory
assets associated with losses on reacquired debt incurred when the debt is
refunded with new long-term debt are not subject to an earnings test and need
not be written off. Additionally, the SCC of VA ruled that the company must file
an earnings test with the Commission if it seeks to establish any new regulatory
assets other than those associated with losses on reacquired debt refunded with
new long-term debt. As a result of the August 6, 1998 order of the SCC of VA,
the uncertainty regarding the status of regulatory assets associated with losses
on reacquired debt applicable to the company's Virginia operations has been
resolved in favor of the company.
SFAS No. 106 Costs
On September 25, 1998, the Staff of the SCC of VA issued a report in response to
the company's 1997 Annual Information Filing recommending that the company
eliminate a regulatory asset associated with implementation of SFAS No. 106. The
company concluded that the Virginia regulatory asset related to the
implementation of SFAS No. 106 did not meet the conditions for continued
deferral under SFAS No. 71. Therefore, in the fourth quarter of fiscal year
1998, the company recorded a $1.6 million charge to write-off the Virginia
regulatory asset related to the implementation of SFAS No. 106.
The company believes, in accordance with SFAS No. 71, that its regulatory
assets recorded as of September 30, 1998 applicable to operations in Virginia,
are probable of future recovery.
11. ORGANIZATIONAL REDESIGN
In 1996, in response to changing requirements and greater competition in the
markets in which it operates, the company announced and began implementing a
corporate reorganization. The reorganization moved the company away from a
traditional, functional structure and towards a more customer-focused
organization designed to encourage innovation, initiative and teamwork. The new
structure flattened the corporate hierarchy and resulted in fewer supervisory
positions.
In the course of the reorganization, the company incurred various expenses,
including professional consulting fees and costs associated with a voluntary
separation pay program for certain eligible supervisory employees. In 1996, the
company recorded non-recurring operation expenses of $13.4 million related to
the reorganization, that were paid in fiscal years 1996 and 1997.
52
<PAGE> 32
Washington Gas Light Company
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair value of
the company's financial instruments at September 30, 1998 and 1997. The fair
value of a financial instrument is the amount at which the instrument could be
exchanged in a current transaction between willing parties.
<TABLE>
<CAPTION>
1998 1997
------------------------------------------------
Carrying Fair Carrying Fair
(Millions) Amount Value Amount Value
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Current assets $127.2 $127.2 $ 94.4 $ 94.4
Current liabilities 345.0 345.0 240.0 240.0
Long-term debt 428.6 462.2 431.6 437.1
</TABLE>
Financial instruments included in current assets are cash and cash
equivalents, net accounts receivable, accrued utility revenues and other
miscellaneous receivables. Financial instruments included in current liabilities
are total current liabilities from the Consolidated Balance Sheets excluding
capital lease obligations and accrued vacation costs. The carrying amount of the
financial instruments included in current assets and current liabilities
approximates fair value because of the short maturity of these instruments. The
fair value of long-term debt was estimated based on the quoted market prices of
U.S. Treasury issues having a similar term to maturity, adjusted for the
company's credit quality and the present value of future cash flows.
13. SUBSEQUENT EVENTS
AGREEMENT TO SELL ASSETS
On November 2, 1998, Shenandoah Gas entered into an agreement to sell its
natural gas utility assets located in West Virginia. According to this
agreement, Shenandoah Gas will provide natural gas transportation service
through its pipeline system in Virginia to the purchaser to assure continued
natural gas service in the Eastern Panhandle of West Virginia.
At September 30, 1998, Shenandoah Gas served 3,348 customers in Martinsburg
and surrounding areas in Berkeley County, West Virginia. Shenandoah Gas will
continue to provide natural gas utility service to its approximately 10,000
customers in the northern Shenandoah Valley of Virginia.
In fiscal year 1998, Shenandoah Gas' natural gas therm deliveries in West
Virginia represented less than two percent of the company's consolidated natural
gas therm deliveries and less than one percent of associated consolidated
revenues. Shenandoah Gas' West Virginia operations contributed approximately
$200,000 (0.3%) to the company's fiscal year 1998 net income applicable to
common stock. This represents less than one-half of one cent of basic and
diluted earnings per average common share for fiscal year 1998. The sale is
expected to generate a non-recurring loss, after applicable income taxes, of
approximately $1.9 million or approximately $.04 per average common share in
fiscal year 1999.
The proposed transaction is subject to approval by the PSC of WVA. The
transportation service to be provided by Shenandoah Gas to the purchaser is
subject to approval by the FERC.
SALE OF COMMON STOCK
On November 12, 1998, the company offered publicly 2 million shares of common
stock at $25.0625 per share. On November 18, 1998, the underwriters involved in
the offering exercised their option to purchase an additional 300,000 shares
from the company at the same price per share. Net proceeds from the sale will
amount to $55,712,000, and will be used for general corporate purposes,
including capital expenditures and working capital requirements.
53
<PAGE> 33
Washington Gas Light Company
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The presentation of financial data that accurately and fairly reflects the
results of operations and financial position of the company is one of
management's stewardship obligations to its shareholders. Management has
prepared the accompanying financial statements in accordance with generally
accepted accounting principles, including the estimates and judgments made by
management which are necessary to prepare the statements in accordance with such
principles. To assure the integrity of the underlying financial records
supporting the financial statements, management maintains a system of internal
accounting controls sufficient to provide reasonable assurances at reasonable
costs that assets are properly safeguarded and accounted for and are utilized
only in accordance with management's authorization.
The system of internal accounting controls is augmented by the company's
internal audit department, which has unrestricted access to all levels of
company management. In addition, the internal auditor meets periodically with
the Audit Review Committee of the Board of Directors to discuss, among other
things, the company's system of internal accounting controls and the adequacy of
the internal audit program. The report of the Audit Review Committee appears
below.
As discussed in its report, the Audit Review Committee also meets
periodically with Arthur Andersen LLP, the company's independent public
accountants, with and without management, to discuss the results of Arthur
Andersen LLP's audit of the company's financial statements. The report of Arthur
Andersen LLP appears below.
/s/ JAMES H. DEGRAFFENREIDT, JR.
James H. DeGraffenreidt, Jr., Chairman of the Board and Chief Executive Officer
/s/ FREDERIC M. KLINE
Frederic M. Kline, Vice President, Treasurer and Chief Financial Officer
REPORT OF THE AUDIT REVIEW COMMITTEE
The Audit Review Committee of the Board of Directors of Washington Gas Light
Company is comprised of four directors who are not employees of the company:
Karen Hastie Williams (Chair), Fred J. Brinkman, Daniel J. Callahan, III and
Orlando W. Darden. The committee held five meetings during fiscal year 1998.
The Audit Review Committee oversees Washington Gas Light Company's financial
reporting process on behalf of Washington Gas Light Company's Board of
Directors. In fulfilling its responsibility, the committee recommended to the
Board of Directors, subject to ratification by the stockholders, the selection
of Washington Gas Light Company's independent public accountants, Arthur
Andersen LLP.
The Audit Review Committee discussed with the company's internal auditor and
the independent public accountants the overall scope and specific plans for
their respective audits, and the adequacy of the company's internal controls.
The committee discussed the company's financial statements with the independent
public accountants and met separately with the company's internal auditor and
independent public accountants, with and without management present, to discuss
the results of their audits, their evaluation of the company's internal
controls, and the overall quality of the company's financial reporting. The
meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditor or independent
public accountants.
/s/ KAREN HASTIE WILLIAMS
Karen Hastie Williams, Chair, Audit Review Committee
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Washington Gas Light Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Washington Gas Light Company (a District of
Columbia and Virginia corporation) and subsidiaries as of September 30, 1998 and
1997, and the related consolidated statements of income, cash flows, common
shareholders' equity and income taxes for each of the three years in the period
ended September 30, 1998. These financial statements are the responsibility of
the company'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, the financial statements referred to above present fairly, in
all material respects, the financial position of Washington Gas Light Company
and subsidiaries as of September 30, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 1998, in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Washington, D.C.
October 26, 1998 (except with respect to the matters discussed in Note 13, as to
which the date is November 18, 1998).
54
<PAGE> 34
Washington Gas Light Company
SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION
In the opinion of the company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of such periods. Due
to the seasonal nature of the company's business, there are substantial
variations in operations reported on a quarterly basis.
<TABLE>
<CAPTION>
Quarter Ended
Dec. 31 March 31 June 30 Sept. 30
- ------------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C> <C>
FISCAL YEAR 1998
Operating revenues $367,547 $390,221 $156,390 $126,460
Operating income (loss) 47,702 61,701 (654) (6,770)
Net income (loss) 38,123 53,729 (7,022) (16,201)
Earnings (loss) per average share
of common stock--basic and diluted 0.87 1.22 (0.17) (0.38)
FISCAL YEAR 1997
Operating revenues $344,958 $431,465 $171,942 $107,389
Operating income (loss) 46,056 66,961 7,018 (4,760)
Net income (loss) 37,424 59,144 (365) (14,184)
Earnings (loss) per average share
of common stock--basic 0.85 1.35 (0.02) (0.33)
Earnings (loss) per average share
of common stock--diluted (a) 0.85 1.34 (0.02) (0.33)
</TABLE>
(a) The sum of these amounts does not equal the annual amount because the
quarterly calculations are based on varying numbers of common shares
outstanding.
<TABLE>
<CAPTION>
COMMON STOCK PRICE RANGE AND DIVIDENDS PAID
Dividends Paid Dividend
High Low Per Share Payment Date
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FISCAL YEAR 1998
Fourth Quarter $27 7/8 $23 1/16 $0.300 8/1/98
Third Quarter 28 1/4 24 3/4 0.300 5/1/98
Second Quarter 30 3/4 25 9/16 0.295 2/1/98
First Quarter 31 3/8 23 13/16 0.295 11/1/97
FISCAL YEAR 1997
Fourth Quarter $26 1/2 $23 15/16 $0.295 8/1/97
Third Quarter 25 5/8 20 7/8 0.295 5/1/97
Second Quarter 23 1/2 21 5/8 0.285 2/1/97
First Quarter 25 21 1/8 0.285 11/1/96
</TABLE>
The common stock of the company is listed for trading on the New York Stock
Exchange and on the Philadelphia Stock Exchange, and is shown as WashGasLt or
WashGs in newspapers. At September 30, 1998, the company had 22,790 common
shareholders.
55
<PAGE> 1
EXHIBIT 21
WASHINGTON GAS LIGHT COMPANY
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
Percent of
Voting
Securities State of
Owned Incorporation
---------- -------------
<S> <C> <C>
Subsidiaries of Washington Gas Light
Company (Parent) -
Shenandoah Gas Company 100% Virginia
Hampshire Gas Company 100% West Virginia
Crab Run Gas Company 100% Virginia
Washington Gas Resources Corp. a/ 100% Delaware
Virginia Intrastate Pipeline Company c/ 100% Virginia
a/ Subsidiary companies of Washington
Gas Resources Corp. -
American Combustion Industries, Inc. 100% Maryland
American Combustion, Inc. 100% Virginia
Washington Gas Energy Services, Inc. b/ 100% Delaware
Washington Gas Consumer Services, Inc. 100% Delaware
b/ Subsidiary companies of Washington
Gas Energy Services, Inc. -
Washington Gas Energy Systems, Inc. 100% Delaware
Brandywood Estates, Inc. 100% Maryland
Advanced Marketing Concepts, Inc. c/ 100% Delaware
c/ Inactive
</TABLE>
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports included or incorporated by reference in this Form 10-K, into the
Company's previously filed Registration Statements File Nos. 33-57041, 33-61199,
333-01469, 333-01471, 333-16181 and 333-18965.
ARTHUR ANDERSEN LLP
Washington, D.C.,
December 18, 1998.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Schedule contains summary financial information extracted from the Income
Statement, Balance Sheet and Statement of Cash Flows and is qualified in its
entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,316,925
<OTHER-PROPERTY-AND-INVEST> 2,576
<TOTAL-CURRENT-ASSETS> 250,196
<TOTAL-DEFERRED-CHARGES> 112,736
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,682,433
<COMMON> 43,955
<CAPITAL-SURPLUS-PAID-IN> 305,485
<RETAINED-EARNINGS> 258,315
<TOTAL-COMMON-STOCKHOLDERS-EQ> 607,755
0
28,424
<LONG-TERM-DEBT-NET> 428,641<F1>
<SHORT-TERM-NOTES> 57,190<F2>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 67,753<F2>
<LONG-TERM-DEBT-CURRENT-PORT> 64,106
0
<CAPITAL-LEASE-OBLIGATIONS> 834
<LEASES-CURRENT> 546
<OTHER-ITEMS-CAPITAL-AND-LIAB> 427,730
<TOT-CAPITALIZATION-AND-LIAB> 1,682,433
<GROSS-OPERATING-REVENUE> 1,040,618
<INCOME-TAX-EXPENSE> 38,006
<OTHER-OPERATING-EXPENSES> 900,633
<TOTAL-OPERATING-EXPENSES> 938,639
<OPERATING-INCOME-LOSS> 101,979
<OTHER-INCOME-NET> 4,369
<INCOME-BEFORE-INTEREST-EXPEN> 106,348
<TOTAL-INTEREST-EXPENSE> 37,719
<NET-INCOME> 68,629
1,331
<EARNINGS-AVAILABLE-FOR-COMM> 67,298
<COMMON-STOCK-DIVIDENDS> 52,158
<TOTAL-INTEREST-ON-BONDS> 37,719<F3>
<CASH-FLOW-OPERATIONS> 121,818
<EPS-PRIMARY> 1.54
<EPS-DILUTED> 1.54
<FN>
<F1>Represents total long-term debt including $2,000 in First Mortgage Bonds,
$425,700 in unsecured Medium-Term Notes, $1,680 in other long-term debt and
$(739) in unamortized premium and discount-net.
<F2>Total of short-term Notes Payable and Commercial Paper ties to Balance Sheet
caption entitled Notes Payable.
<F3>Represents total Interest Expense, per Statements of Income.
</FN>
</TABLE>
