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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, 1995
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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)
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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)
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Registrant's telephone number, including area code (703) 750-4440
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Securities registered pursuant to Section 12(b) of the Act:
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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
$5.00 Series Philadelphia Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. /X/
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State the aggregate market value of the voting stock held by non-affiliates of
the registrant. The aggregate market value shall be computed by reference to
the price at which the stock was sold, or the average bid and asked prices of
such stock, as of a specified date within 60 days prior to the date of filing.
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$ 911,829,000 November 30, 1995
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Market Value Date
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Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
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Common Stock $1.00 par value 43,065,292 November 30, 1995
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Class Number of Shares Date
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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, 1995.
PART II - Annual Report to Shareholders for the fiscal year ended September
30, 1995 (Pages 22 through 47).
PART III - Proxy Statement dated January 19, 1996 (Pages 2 through 12).
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 PAGE
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Item 1. Business
Subsidiaries...................................................... 2
Rate Regulation, Retail Gas Rates, Recent Rate Increases.......... 3
Gas Supply and Capacity........................................... 6
Columbia Bankruptcy............................................... 8
Environmental Matters............................................. 9
Competition....................................................... 10
Other............................................................. 11
Item 2. Properties.......................................................... 12
Item 3. Legal Proceedings................................................... 13
Item 4. Submission of Matters to a Vote of Security Holders................. 13
Executive Officers of the Registrant.......................................... 14
PART II
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Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.............................................. 16
Item 6. Selected Financial Data............................................. 16
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................... 16
Item 8. Financial Statements and Supplementary Data......................... 16
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................... 16
PART III
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Item 10. Directors and Executive Officers of the Registrant.................. 16
Item 11. Executive Compensation.............................................. 16
Item 12. Security Ownership of Certain Beneficial Owners
and Management................................................... 16
Item 13. Certain Relationships and Related Transactions...................... 16
PART IV
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Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.............................................. 17
Auditors' Report on Schedules................................................. 21
Signatures.................................................................... 24
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PART I
ITEM 1. BUSINESS
Washington Gas Light Company (Company) provides natural gas service to
metropolitan Washington, D.C. and adjoining areas through three divisions and
two distribution subsidiaries. The Company has been engaged in the gas
distribution business for 147 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 Company's three jurisdictional divisions are located in the District
of Columbia, Maryland and Virginia. Portions of West Virginia are served by one
of the Company's distribution subsidiaries. The population of the area served
is estimated to be 4.5 million. As of September 30, 1995, the Company and its
distribution subsidiaries served 750,849 customer meters. A listing of meters
served and therms delivered as of and for the twelve months ended September 30,
1995 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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<S> <C> <C>
District of Columbia 144,407 315
Maryland 314,707 669
Virginia 289,050 432
West Virginia 2,685 24
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Total 750,849 1,440
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Of the 1,440 million therms delivered in fiscal year 1995, 42% was sold
to firm residential customers, 28% was sold to firm commercial and industrial
customers, 17% was sold to interruptible commercial and industrial customers, 9%
was delivered to an interruptible electric generation facility and 4% was
delivered to various end-use customers. Therms delivered by the parent company
amounted to 1,346 million therms, or 93% of the total consolidated deliveries.
SUBSIDIARIES
The Company has five wholly-owned active subsidiaries which are
described below.
Shenandoah Gas Company (Shenandoah) is engaged in the distribution 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, 1995 totalled 58 million therms, of which 11% was sold to firm residential
customers, 30% was sold to firm commercial and industrial customers, 56% was
sold to interruptible commercial and industrial customers, and 3% was delivered
to various end-use customers.
Frederick Gas Company, Inc. (Frederick) distributes and sells natural
gas at retail in Frederick County, Maryland in and near the City of Frederick.
It also provides propane gas service in Frederick County. Deliveries of natural
gas for the twelve months ended September 30, 1995 totalled 36 million therms,
of which 20% was
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sold to firm residential customers, 29% was sold to firm commercial and
industrial customers, 48% was sold to interruptible commercial and industrial
customers and 3% was delivered to various end-use customers. This subsidiary
will be merged with the parent company effective January 1, 1996, in an effort
to increase operating efficiencies. Frederick and the parent company share the
same rate structure in the Maryland jurisdiction.
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 Federal Energy Regulatory Commission
(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, 1995, Crab Run's investment in this partnership
amounted to $1.1 million. The Company expects that any additional investments
in the partnership will be minimal.
Washington Resources Group, Inc. (WRG) is a non-utility subsidiary that
holds the Company's diversified operations, except for Crab Run, to more clearly
delineate non-utility operations from the regulated utility businesses. For
several years, the operations of this subsidiary, excluding a real estate
venture described below, have been continually declining as the Company has
increased its emphasis on developing opportunities in the regulated natural gas
distribution business. As the utility industry continues to undergo the effects
of increased competition and deregulation, the Company foresees the possibility
of performing activities that have historically been considered part of the
regulated utility business in unregulated, non-utility subsidiaries. WRG's
subsidiaries are described below.
Washington Gas Energy Systems, Inc. previously supplied and installed
residential and commercial energy conservation products and services. On May
12, 1995, the assets of this subsidiary were sold and this company is currently
inactive.
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. 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. provides services primarily in the
area of energy-related home improvements.
RATE REGULATION, RETAIL GAS RATES, RECENT 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 Public Service Commission of West Virginia
(PSC of WVA). The PSC of MD regulates Frederick and 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
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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.
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 application are subject to
refund.
RETAIL GAS RATES
In the District of Columbia jurisdiction, the firm residential and
non-residential rate schedules are based upon a customer charge designed to
recover certain fixed costs and a flat commodity rate per therm. 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 encourage conservation during
periods of peak demand and to encourage cost-effective use of natural gas during
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 current firm tariff provisions in all
jurisdictions contain a purchased gas adjustment clause which allows the Company
to pass on any increases or decreases in gas costs from a stipulated base cost.
Moreover, each jurisdiction in which the Company and its distribution
subsidiaries operate provides for an annual reconciliation of total gas costs
billed firm customers with the actual cost of gas incurred.
Interruptible customers must be able to use another form of energy in
addition to natural gas to satisfy their requirements. The alternative fuel
most often used by interruptible customers is fuel oil. The prices for gas
service associated with interruptible contracts are driven by the comparative
cost of gas and the cost of customers' alternative fuels. Service to
interruptible customers has historically been based on short-term contracts.
However, recent regulatory proceedings have permitted increased flexibility for
negotiating long-term contracts. In the District of Columbia, the Company
received authority in 1994 from the PSC of DC to offer long-term and fixed price
contracts to its interruptible customers in this jurisdiction.
In the Maryland jurisdiction, significant steps have been taken toward
separating (unbundling) rates charged for gas utility services traditionally
priced as a package. The most significant services being unbundled are the sale
of the gas commodity and the transporting of such gas through the Company's
distribution system to the customer (delivery service). Effective September 1,
1995, all interruptible customers are charged separately for delivery service
and must elect whether to buy gas from the Company or a third-party supplier
such as marketers or other gas companies. Additionally, on November 1, 1995,
certain large volume firm customers were given the option to have the sale and
delivery of natural gas unbundled. A residential unbundled rate pilot program is
expected to be implemented in late 1996. The Company's firm cost of gas
purchased related to bundled sales of natural gas will continue to be collected
under the purchase gas tariff provisions mentioned above.
All of the Company's major divisions have rate structures which provide
for the firm ratepayers and the Company to share portions of gross margins from
sales to the
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interruptible customer class. The majority of these margins are returned to
firm customers after a gross margin threshold is reached or in exchange for a
shift of a portion of fixed costs from the interruptible to the firm class.
The Company also retains 100% of the gross margins associated with sales to
interruptible customers in the Maryland jurisdiction until the Company has
recovered its investment and capital costs associated therewith. This
arrangement has been in effect in Maryland for interruptible customers added
since August 1989.
RECENT RATE INCREASES
On December 18, 1992, the District of Columbia division of the Company
filed a request for an increase in annual revenues of $24.5 million from the PSC
of DC. The request included an overall rate of return of 10.6%, a return on
equity of 12.75% and a 54.1% common equity ratio. In addition to requesting the
recovery of routine increased operating expenses, the Company requested recovery
of additional costs associated with a Demand Side Management (DSM) program and
the incremental portion of costs related to implementing Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits
Other than Pensions" (SFAS No. 106). On October 8, 1993, the PSC of DC issued a
final order approving a $4.7 million increase, or 2.5%, in annual revenues for
this division, effective October 19, 1993. The order, which included an overall
rate of return of 9.86% and a return on common equity of 11.5%, established a
longer recovery period for DSM costs than the Company had proposed and provided
for phased-in, rather than immediate, recognition of the additional costs
associated with SFAS No. 106. The incremental costs related to SFAS No. 106 are
being phased-in over a five year period. In each year of the phase-in, the
company files 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 is
being deferred as a regulatory asset and will be collected over a 15-year period
beginning in approximately October 1998. As of October 1, 1995, the Company
has received three increases to reflect the effect of the phase-in policy.
On March 31, 1993, the Maryland division of the Company and the
Frederick subsidiary filed for an increase in annual revenues of $26.2 million
from the PSC of MD. The request included an overall rate of return of 10.63%, a
return on common equity of 13.00% and a 54.0% common equity ratio. The request
sought recovery of the incremental portion of SFAS No. 106 costs allocable to
this jurisdiction, increases in other operating expenses, recovery of costs
associated with the growth in rate base and a provision to include treatment of
carrying costs on storage gas inventory in the Company's purchased gas
adjustment (PGA). 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 the case. Recovery of SFAS No.
106 costs 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 PGA to provide for recovery of carrying costs on
actual storage gas balances and provided for an annual increase in revenue 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 January 14, 1994, the District of Columbia division filed a request
for a rate increase with the PSC of DC of $17.3 million or 9%. The request
included an overall rate of return of 10.39%, a return on common equity of
12.75% and a 54.3% common equity ratio. On June 3, 1994, a majority of the
parties to this case signed a Stipulation and Agreement providing for a $6.4
million annual increase in revenues for this division. The agreement did not
specify a rate of return. On August 1, 1994, the PSC
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of DC issued an order approving the settlement agreement and the new rates were
placed into effect on August 1, 1994. Terms of the agreement provided that the
Company will not file for additional rate relief prior to April 1, 1996 and
that any increase in rates cannot be placed into effect in this jurisdiction
before January 1, 1997. The agreement also 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.
On April 29, 1994, the Company's Virginia division filed a request with
the SCC of VA for a rate increase of $15.7 million, or 6.4%. The request
included an overall rate of return of 10.5%, a return on common equity of 12.75%
and a 53.1% common equity ratio. In the filing, the Company requested, among
other items, recovery of the additional costs associated with implementing the
effects of SFAS No. 106 in accordance with a previously issued generic order by
the SCC of VA. On September 27, 1994, the Company implemented rates designed to
recover the requested increase of $15.7 million. 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, effective September
27, 1994, which included a return on equity of 11.50% and an overall rate of
return of 9.72%. The order also allows the company to collect SFAS No. 106
costs in accordance with the generic order and certain environmental response
costs. Amounts associated with the difference between the interim rates that
were collected subject to refund and the amount approved by the SCC of VA will
be refunded, with interest, by January 1, 1996.
On June 1, 1994, the Company's Maryland division and the Frederick
subsidiary filed a request with the PSC of MD for a rate increase of $17.6
million, or 5.7%. The request included an overall rate of return of 10.6%, a
return on common equity of 13.00% and a 54.9% common equity ratio. 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 the case and increased rates
were placed into effect on December 1, 1994. These rates were designed to
collect an additional $7.4 million annually in base rates.
On January 27, 1995, Shenandoah filed for a request with the PSC of
WVA for an increase in annual revenues of $791,000, or 8.3%. The request
included an overall rate of return of 10.44% and a return on common equity of
12.5%. On July 13, 1995, a joint stipulation and agreement between the Staff
of the PSC of WVA and Shenandoah was submitted to the PSC of WVA. The
agreement provided for an annual increase of $522,000 and did not specify a
return on equity or an overall rate of return. An order of the PSC of WVA
approving the settlement became effective on September 18, 1995 and new rates
were placed into effect on December 4, 1995.
On July 7, 1995, Shenandoah filed an application with the SCC of VA
under expedited rate case rules for an increase in annual revenues of
approximately $1.2 million. The request included an overall return of 9.88% and
a return on equity of 11.50%. New rates were placed into effect, subject to
refund, on August 6, 1995.
GAS SUPPLY AND CAPACITY
As a natural gas distribution company, it is necessary that the Company
and its distribution subsidiaries arrange to have natural gas delivered to the
entry points (referred to as city gates) of its distribution system using the
delivery capacity of interstate pipeline companies. The Company acquires
natural gas delivery capacity for itself, Shenandoah and Frederick (Companies),
on a system-wide basis because of the integrated nature of the service
agreements between the pipelines and the Companies. The Company's supply and
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 and
conservation.
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On November 1, 1993, FERC Order No. 636 (Order) was implemented. The
Order has required pipelines to restructure their services to enhance
competition and maximize the benefits of wellhead price decontrol. This
restructuring has been accomplished primarily by unbundling the services
provided by the pipelines (the storage and transportation of natural gas) from
the pipelines' historical merchant function (purchase and sale of gas). Pipeline
companies are required to provide transportation and storage services to gas
shippers, such as the Company, that are comparable to the services the Company
received in the past. The Companies utilize the delivery capacity of seven
pipelines, three of which are major pipelines connecting directly to the
Company's distribution system.
The restructuring of the pipeline industry has had its greatest impact
on the operations of local distribution companies such as the Company. The
Company is now completely responsible for purchasing its own gas supplies and
thus conducts activities previously handled by pipeline companies. The Company
must assure that it has sufficient supplies to meet its obligations to serve
under all weather conditions. In addition, the Company must now completely
arrange for the delivery of the gas supplies it has purchased, using the
transportation and storage services rendered by the interstate pipelines.
Furthermore, considering the continuing trend toward unbundling the traditional
merchant function of the distribution company to procure natural gas and related
capacity on behalf of its retail customers, the Company must assure that it only
commits to supply and capacity levels that it believes 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 15 long-term gas supply contracts with various producers
or marketers which expire between 1997 and 2003 and under which the Company can
purchase up to 112 million dekatherms of natural gas per year. Any supplies not
acquired under these long-term contracts are acquired under seasonal contracts
or from short-term purchases on the spot market. In fiscal year 1995, supplies
were acquired from a combination of 49 producers or marketers including volumes
acquired under the 15 contracts discussed above.
As reflected in the first table on page 8, there were five sources of
delivery through which the Company and its distribution subsidiaries received
natural gas to satisfy their sendout requirements in pipeline year 1995
(November 1, 1994 through October 31, 1995) and six sources from which supplies
can be received in pipeline year 1996 (November 1, 1995 through October 31,
1996). Firm transportation denotes gas purchased directly from the spot market
or under long-term contracts and transported to the city gates in volumes agreed
upon by the Company and the applicable pipeline. Transportation storage denotes
volumes purchased by the Company on the spot market and/or under long-term
contracts and stored by a pipeline for withdrawal during the heating season.
Interruptible transportation denotes volumes purchased directly on the spot
market and transported to the city gates on a "best efforts" or "as available"
basis. Peak load requirements are met by the local production of propane air
from plants located at Company-owned facilities in Rockville, Maryland and
Ravensworth, Virginia and underground natural gas storage at the Hampshire
storage field in Hampshire County, West Virginia. In the projected pipeline
year 1996, the Company has contracted for new peak shaving sources, including
supplies delivered from a liquefied natural gas storage facility.
During pipeline year 1995, total sendout on the system was 1,303.4
million therms, excluding deliveries to an electric generation facility and
volumes delivered for end users. The sendout for pipeline year 1996 is
estimated to be 1,390.7 million therms (based on normal weather) excluding
deliveries for electric generation and for
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end users. The sources of delivery and related volumes that were used to
satisfy the requirements of pipeline year 1995 and those projected for pipeline
year 1996 are shown below.
SOURCES OF DELIVERY FOR
ANNUAL SENDOUT
(millions of therms)
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Actual Projected
Sources of Delivery Pipeline Year 1995 Pipeline Year 1996
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Firm Transportation 1,013.9 1,112.9
Transportation Storage 280.1 249.7
Interruptible Transportation 1.5 -
Hampshire Storage 5.7 18.0
Company-Owned Propane-Air Plants 2.2 4.0
Other Peak Shaving Sources - 6.1
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1,303.4 1,390.7
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The effectiveness of the Companies' 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
Companies assume that all interruptible customers will be curtailed on the
design day. The Companies' design day estimate is currently 13.3 million
therms. The Company is currently capable of meeting 64% of its design day
requirements with storage and peaking capabilities. Emphasizing storage and
peaking facilities on the Companies' 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 1996.
SOURCES OF DELIVERY FOR
DESIGN DAY SENDOUT
(millions of therms)
<TABLE>
<CAPTION>
Pipeline Year 1996
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Sources of Delivery Therms Percent
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Firm Transportation 4.8 36%
Transportation Storage 4.6 35
Company-Owned Propane-Air Plants,
Hampshire Storage and Other Peaking 3.9 29
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13.3 100%
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</TABLE>
The Company believes the combination of the gas supply it can purchase
under short- and long-term contracts and its peaking supplies, along with 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.
COLUMBIA BANKRUPTCY
On November 28, 1995, the Company's major supplier of pipeline and
storage services, Columbia Gas Transmission Corporation (CGT) as well as CGT's
parent, The Columbia Gas System, Inc., accepted a Bankruptcy Court order
confirming their respective reorganization plans, and thereby emerged from
bankruptcy protection. CGT's approved reorganization plan includes a
comprehensive settlement between CGT and its
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customers, including the Company. This settlement resolves both the remaining
transition cost liability of the Company (except for certain amounts being
collected by CGT in base rates) and refunds due to the Company by CGT from
other proceedings previously filed before FERC.
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; and (5)
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 last use of any such plant was in 1984. In connection with these
operations, certain by-products of the gas manufacturing process are known to be
present at or near some former sites and may be present at others.
At one of the former MGP sites, studies have shown the presence of coal
tar under the site and an adjoining property. A 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. Contaminated groundwater is being removed
and treated by a water treatment system. The Company has obtained approval from
an adjacent landowner to perform a demonstration project to determine the
feasibility of using bioremediation to treat soil contamination on the adjoining
property. This project is scheduled to commence in fiscal year 1996, and if
successful, may become the method of choice to remediate both the Company's site
and the adjoining property.
At a second former MGP site, tar-products were identified under the
property, and a risk assessment showed that there was no unacceptable risk to
human health or the environment. A state-approved treatment and recovery system
to recover free tar was designed and installed. Minimal volumes of tar-products
have been recovered from pumping thus far. The Company will continue to pump
and monitor the site.
At a third former MGP site, initial studies have shown that tar-products
are present under the property. A remedial investigation/feasibility study was
completed and submitted to the appropriate state regulatory agency in April
1995. Remediation should begin in fiscal year 1996.
At a fourth former MGP site and on an adjacent parcel of land, the
Company plans to perform studies and analytical work in fiscal year 1996 and
submit the results to the applicable state regulatory agency.
At a fifth former MGP site, a treatment system for contaminated
groundwater has been operating for five years. There is no indication at this
time that any additional action other than water treatment will be necessary.
9
<PAGE> 12
The Company has no reason to believe at this time that remediation of
any of the remaining five sites will be necessary.
Through September 30, 1995, the Company had paid $8.2 million for
environmental response costs. A liability of $11.1 million on an undiscounted
basis has been recorded as of September 30, 1995 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 the five sites described above. The maximum liability associated with these
sites at September 30, 1995 is estimated at $17.6 million. The estimates were
determined by the Company's environmental expert 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 (12 to 30 years) and
differences in the processes expected to be used.
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.
COMPETITION
The Company has historically faced competitive pressures from other
energy sources and is beginning to experience new competitive pressures within
the gas industry and as a result of changes taking place in the electric
industry.
The most significant competition the Company faces continues to be
between natural gas and electricity in the residential market, which contributes
the most significant portion of the Company's net income. The Company currently
maintains a price advantage over electricity in all of the jurisdictions it
serves. The Company continues to derive the majority share of the new
residential construction market and believes customer preference for natural gas
and a competitive price will allow the Company to maintain its strong presence.
In the interruptible market, fuel oil is the most significant competing energy
alternative for this class of customer. The Company's success in this market is
largely dependent on changes in the price of gas vis-a-vis changes in the price
of fuel oil.
The movement for deregulating natural gas and increasing competition in
the industry has been evolving since the passage of the Natural Gas Policy Act
of 1978, which brought about a gradual decontrol of the wellhead price of
natural gas and allowed for market-based prices. At the Federal regulatory
level, the trend toward deregulation continued throughout the 1980s and
substantially culminated in the implementation of FERC Order No. 636 in November
1993. This order removed the merchant function from the pipelines that serve
local distribution companies (LDCs) such as the Company. The pipelines have
become providers of storage and transportation services and LDCs have assumed
the responsibility for procuring satisfactory gas supplies and pipeline capacity
levels.
Recently, regulatory initiatives have begun in several states to further
extend the effects of competition to the consumer. Proposals have included
market-based performance standards for gas cost recovery by LDCs, a greater
focus on incentive regulation, and "unbundling" of the services currently
provided by LDCs. Unbundling is expected to increase competition among
providers and offer choices to consumers for those services that can be
separated and priced individually. Such services can include sales of gas,
interstate transportation services and servicing consumer appliances. In
unbundling situations, the Company will continue to offer delivery service for
the transportation of natural gas on its distribution system. The
10
<PAGE> 13
Company's customer base and its location in relation to pipelines make it less
susceptible to the risk of bypass on its system than other companies.
In the Company's service area, unbundled service has begun in the state
of Maryland. The PSC of MD has approved company tariffs that became effective
September 1, 1995, whereby all interruptible customers in Maryland became
delivery service customers and must elect whether to buy gas from the Company or
third-party suppliers such as marketers or other gas companies. The Company
still provides delivery service to transport gas through the distribution system
to the customer. New delivery service tariffs for certain firm group metered
apartments and commercial customers became effective on November 1, 1995, and a
residential delivery service pilot program is expected to be implemented in late
1996. If the unbundled sale of the gas commodity is no longer regulated at the
LDC level, the ability of the Company to compete successfully and take advantage
of the potential opportunity to increase its profitability will be dependent
upon, among other factors, the competitiveness of its gas supplies and capacity.
Regulatory filings addressing unbundling issues in the District of
Columbia and Virginia jurisdictions are likely to be filed in the near future.
The Company will continue to be progressive in its efforts to work with
regulators to shape the transition from traditional ratemaking concepts to new
concepts that incorporate competition and promote customer choices.
Changes in the electric industry have implications for the gas
industry. The National Energy Policy Act of 1992 allows unregulated
independent power producers to sell power to wholesale customers in competition
with regulated electric utilities. The FERC has proposed to require
jurisdictional electric utilities to offer nondiscriminatory open access
transmission and ancillary services to eligible customers comparable to the
service they provide at the wholesale level. Merger and acquisition activity
in the electric industry has increased, including a proposal for a merger in
1997 of two neighboring utilities to the Company, Baltimore Gas and Electric
Company and Potomac Electric Power Company. Events such as these should reduce
electricity costs and cause competition to intensify.
OTHER
Revenue from the sale or delivery of natural gas as a percentage of
consolidated revenue was 97% for 1995 and 96% for 1994 and 1993. The Company is
not dependent upon a single customer or a few customers, the loss of any one or
more of whom would have a significant adverse effect on the Company, since large
customers are generally on interruptible rate schedules and margin sharing
arrangements would limit the effects of customer usage on net income. A margin
sharing arrangement in the Company's Maryland jurisdiction limits the effect on
net income of variations in volumes delivered to Potomac Electric Power Company
(Pepco), the Company's largest customer. As shown on page 2, the Company and
its distribution subsidiaries had 750,849 customer meters at September 30, 1995.
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 1995, 74% of the therms delivered by the Company, excluding deliveries to
Pepco, 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 incurs
losses in the third and fourth fiscal quarters. Results of operations can be
affected by the timing and level of approved rate changes. 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.
11
<PAGE> 14
Through the cost of services provided the interstate pipelines, the
distribution companies 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, the American Gas Cooling Center 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 1995, 1994 and 1993 were not material.
As of September 30, 1995, the Company and its wholly-owned subsidiaries
had 2,405 employees. This represents a decline of 242 employees from the level
at September 30, 1994, due to both continuing efforts to reduce the Company's
workforce through attrition and the effects of the sale and discontinuation of
certain non-utility operations. In 1995, contracts with the two unions that
represent a majority of the Company's work force expired. For a further
discussion of the outcome of the 1995 contract negotiations, please refer to the
caption entitled Labor Matters on page 31 of the 1995 Annual Report to
Shareholders, which is incorporated herein by reference.
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, 1995, the Company and its utility subsidiaries had
608 miles of transmission mains and 8,829 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 which 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 1996, it is projected that the Hampshire
storage facility will supply approximately 1.8 billion cubic feet of natural gas
to the Company's system for meeting seasonal demands.
The Company's Mortgage dated January 1, 1933, as supplemented and
amended, securing the first mortgage bonds issued by the Company, constitutes a
direct lien on substantially all property and franchises owned by the Company
other than expressly excepted property.
12
<PAGE> 15
The Company executed a supplemental indenture to its unsecured
Medium-Term Notes Indenture on September 1, 1993, providing that the Company
will not issue any First Mortgage Bonds under its First Mortgage in addition to
its First Mortgage Bonds outstanding on September 1, 1993, without making
effective provision whereby the unsecured Medium-Term Notes shall be secured by
the First Mortgage equally and ratably with any and all other obligations and
indebtedness thereby secured.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
13
<PAGE> 16
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- ------------------------------------------------------------ ------------------
<S> <C>
Elizabeth M. Arnold, Age 43
Treasurer May 1, 1993
Director of Marketing Services May 6, 1991
Director of Financial Relations November 3, 1986
Patrick E. Clarke, Age 59
Senior Vice President - Customer Services and Marketing May 1, 1993
Vice President - Distribution and Marketing March 1, 1992
Vice President - Distribution September 6, 1984
James H. DeGraffenreidt, Jr., Age 42
President and Chief Operating Officer December 1, 1994
Senior Vice President - Jurisdictional Divisions
and Rates and Regulatory Affairs May 1, 1993
Vice President - Rates and Regulatory Affairs November 1, 1991
Senior Managing Attorney May 2, 1988
John K. Keane, Jr., Age 57
Senior Vice President and General Counsel May 1, 1993
Vice President and General Counsel September 1, 1990
Ronald C. King, Age 54
Vice President - Customer Services November 1, 1991
Executive Director November 1, 1989
Frederic M. Kline, Age 44
Controller November 27, 1985
Patrick J. Maher, Age 59
Chairman of the Board and Chief Executive Officer November 24, 1992
President and Chief Executive Officer March 1, 1992
President October 1, 1987
Wayne A. Mills, Age 52
Vice President and General Manager - Maryland Division November 1, 1989
Douglas V. Pope, Age 50
Secretary July 25, 1979
Joseph M. Schepis, Age 42
Senior Vice President and Chief Financial Officer December 15, 1994
Vice President - Rates and Regulatory Affairs May 1, 1993
Treasurer October 1, 1986
Roberta Willis Sims, Age 41
Vice President and General Manager -
District of Columbia Division October 1, 1992
Executive Director and Acting General Manager -
District of Columbia Division August 10, 1992
Executive Assistant March 2, 1992
Senior Managing Attorney September 23, 1991
Managing Attorney October 26, 1986
</TABLE>
14
<PAGE> 17
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 47
Vice President - Human Resources October 1, 1987
James B. White, Age 45
Vice President and General Manager - Virginia Division May 1, 1993
Director of Sales July 6, 1992
Director of Financial Relations May 6, 1991
Manager of Sales May 4, 1987
</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.
15
<PAGE> 18
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 47 of the Company's 1995 Annual Report to
Shareholders is hereby incorporated herein by reference. Only owners of record
are counted as common shareholders.
ITEM 6. SELECTED FINANCIAL DATA
Page 22 of the Company's 1995 Annual Report to Shareholders is hereby
incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Pages 23 through 31 of the Company's 1995 Annual Report to
Shareholders are hereby incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pages 32 through 47 of the Company's 1995 Annual Report to
Shareholders are hereby incorporated herein by reference.
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 Pages 2 through 5 of
the definitive proxy statement dated January 19, 1996, 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" on Pages 7 through
12 of the definitive proxy statement dated January 19, 1996, is hereby
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information captioned "Security Ownership of Management" on
Page 6 of the definitive proxy statement dated January 19, 1996, 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. This firm performed legal services for the Company
during fiscal year 1995.
16
<PAGE> 19
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
(a)1 All Financial Statements Pages in 1995
Annual Report to
Shareholders
Incorporated by
Reference
---------------
<S> <C>
Consolidated Statement of Income - 1995, 1994 and 1993 32
Consolidated Balance Sheet - September 30, 1995 and 1994 33
Consolidated Statement of Cash Flows - 1995, 1994 and 1993 34
Consolidated Statement of Capitalization - September 30,
1995 and 1994 35
Consolidated Statement of Common Shareholders' Equity -
1995, 1994 and 1993 36
Consolidated Statement of Income Taxes - 1995, 1994 and 1993 37
Notes to Consolidated Financial Statements 38-45
Report of Independent Public Accountants 46
</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 sheet, 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 Statement of Income.
The following additional data should be read in conjunction with the
financial statements in the 1995 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.
17
<PAGE> 20
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 - 1995,
1994 and 1993 22-23
(a)-3 Exhibits
Exhibits Filed Herewith:
<CAPTION>
Pages in
Description 10-K
----------- ---------
3. Articles of Incorporation and Bylaws - See
Separate
Bylaws of the Company as amended on Volume
October 25, 1995 for
Exhibits
3 & 10
10. Material Contracts -
10.1 Retirement Plan for Outside Directors,
as amended on October 25, 1995 *
10.2 Directors' Stock Compensation Plan,
as adopted on October 25, 1995 *
10.3 Supplemental Executive Retirement Plan, as
amended on October 25, 1995 *
* Compensatory plan arrangement required to be filed
pursuant to Item 14(c) of Form 10-K. Subject to approval
by Shareholders on February 21, 1996.
11. Statement re Computation of per Share Earnings -
Computation of Earnings per Average Share of
Common Stock Assuming Full Dilution from
Conversion of the $4.60 and $4.36 Convertible
Preferred Stock 25
12. Statement re Computation of Ratios -
12.0 Computation of Ratio of Earnings to Fixed Charges 26
12.1 Ratio of Earnings to Fixed Charges and Preferred
Stock Dividends 27
13. Annual Report to Security Holders -
1995 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 28
23. Consents of Experts and Counsel 29
27. Financial Data Schedule Separate
Volume
</TABLE>
18
<PAGE> 21
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 September 1, 1986, 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 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 April 15, 1988, to the Company's
Mortgage and Deed of Trust, dated January 1, 1933, filed on
Form 8-K dated April 22, 1988.
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 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.
19
<PAGE> 22
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.
Executive Incentive Compensation Plan filed on Form 10-K for the
fiscal year ended December 31, 1986 *
Deferred Compensation Plan for Outside Directors as amended
filed on Form 10-K for the fiscal year ended December 31, 1986 *
Long-Term Incentive Compensation Plan adopted June 28, 1989 and
filed with the Proxy Statement dated December 28, 1989 *
* Compensatory plan arrangement required to be filed pursuant
to Item 14(c) of Form 10-K.
(b) Reports on Form 8-K:
No Reports were filed on Form 8-K during the fourth fiscal
quarter of 1995.
20
<PAGE> 23
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To 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 24, 1995 (except with respect to the
matter discussed in Note 9, as to which the date is November 15, 1995). Our
audit was made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed in the index on page 18 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 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 24, 1995
21
<PAGE> 24
Schedule II
Page 1 of 2
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1995, 1994 and 1993
<TABLE>
<CAPTION>
Additions
Charged to
Balance at ------------------------ Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions (C) of Period
- -------------------------------------------- ---------- --------- ----------- ---------- ---------
(Thousands)
<S> <C> <C> <C> <C> <C>
1995
- ----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet -
Allowance for doubtful accounts $ 11,300 $ 8,228 $ 2,248 (A) $ 11,196 $ 10,580
Provision for impairment of investments
and other deferred charges 7,356 - - 1,959 5,397
Reserves -
Injuries and damages 10,854 3,248 303 (B) 2,532 11,873
Other 4,448 - - 3,548 900
1994
- ----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet -
Allowance for doubtful accounts $ 10,170 $ 8,505 $ 1,693 (A) $ 9,068 $ 11,300
Provision for impairment of investments
and other deferred charges 6,690 2,448 - 1,782 7,356
Reserves -
Injuries and damages 7,031 5,099 303 (B) 1,579 10,854
Other 2,600 2,148 - 300 4,448
</TABLE>
NOTES: See Page 2 of 2.
22
<PAGE> 25
Schedule II
Page 2 of 2
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1995, 1994 and 1993
<TABLE>
<CAPTION>
Additions
Charged to
Balance at ------------------------ Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deductions (C) of Period
- --------------------------------------------- ---------- --------- -------- ---------- ---------
(Thousands)
<S> <C> <C> <C> <C> <C>
1993
- ----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet -
Allowance for doubtful accounts $ 8,222 $ 7,724 $ 1,775 (A) $ 7,551 $ 10,170
Provision for impairment of investments 4,026 2,664 - - 6,690
Reserves -
Injuries and damages 5,929 1,728 774 (B) 1,400 7,031
Other 2,220 1,500 - 1,120 2,600
</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 of estimated exposure.
23
<PAGE> 26
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
PATRICK J. MAHER
---------------------------------------
Patrick J. Maher
Date: December 13, 1995 Chairman of the Board
and Chief Executive Officer
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>
PATRICK J. MAHER Chairman of the Board 12/13/95
-------------------------------- and Chief Executive -----------
(Patrick J. Maher) Officer and Director
JAMES H. DEGRAFFENREIDT, JR. President and Chief 12/13/95
-------------------------------- Operating Officer and -----------
(James H. DeGraffenreidt, Jr.) Director
JOSEPH M. SCHEPIS Senior Vice President 12/13/95
-------------------------------- and Chief Financial Officer -----------
(Joseph M. Schepis) (Principal Financial Officer)
FREDERIC M. KLINE Controller 12/13/95
-------------------------------- (Principal Accounting Officer) -----------
(Frederic M. Kline)
MICHAEL D. BARNES Director 12/13/95
-------------------------------- -----------
(Michael D. Barnes)
FRED J. BRINKMAN Director 12/13/95
-------------------------------- -----------
(Fred J. Brinkman)
DANIEL J. CALLAHAN, III Director 12/13/95
-------------------------------- -----------
(Daniel J. Callahan, III)
ORLANDO W. DARDEN Director 12/13/95
-------------------------------- -----------
(Orlando W. Darden)
MELVYN J. ESTRIN Director 12/13/95
-------------------------------- -----------
(Melvyn J. Estrin)
SHELDON W. FANTLE Director 12/13/95
-------------------------------- -----------
(Sheldon W. Fantle)
KAREN HASTIE WILLIAMS Director 12/13/95
-------------------------------- -----------
(Karen Hastie Williams)
STEPHEN G. YEONAS Director 12/13/95
-------------------------------- -----------
(Stephen G. Yeonas)
</TABLE>
24
<PAGE> 27
EXHIBIT 11
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER AVERAGE SHARE OF COMMON STOCK
ASSUMING FULL DILUTION FROM CONVERSION OF THE $4.60
AND $4.36 CONVERTIBLE PREFERRED STOCK
<TABLE>
<CAPTION>
Years Ended September 30
------------------------------
1995 1994 1993
-------- -------- --------
(Thousands, except per share data)
EARNINGS PER AVERAGE SHARE ASSUMING FULL DILUTION
- -------------------------------------------------
<S> <C> <C> <C>
Net Income $ 62,909 $ 60,459 $ 55,079
Dividends on preferred stock (excluding
dividends on convertible preferred
stock) 1,320 1,320 1,320
-------- -------- --------
Net income applicable to common stock $ 61,589 $ 59,139 $ 53,759
======== ======== ========
Average common shares outstanding on a fully
diluted basis assuming conversion of the
outstanding shares of the $4.60 and $4.36
convertible preferred stock on
October 1 of each year based on the
applicable conversion price 42,609 41,876 41,084
======== ========= ========
Earnings per average share of common stock
assuming full dilution $ 1.45 $ 1.41 $ 1.31
======== ========= ========
</TABLE>
- -------------------
Note: These calculations are submitted in accordance with Securities
Exchange Act of 1934 Release No. 9083 although not required by
footnote 2 to paragraph 14 of Accounting Principles Board Opinion No.
15 because no dilution results.
25
<PAGE> 28
EXHIBIT 12
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
YEARS ENDED SEPTEMBER 30
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
--------- -------- --------- -------- --------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 30,932 $ 30,899 $ 27,872 $ 27,386 $ 27,075
Amortization of Debt Premium,
Discount and Expense 315 367 410 358 304
Interest Component of Rentals 56 34 94 42 164
--------- -------- --------- -------- --------
Total Fixed Charges $ 31,303 $ 31,300 $ 28,376 $ 27,786 $ 27,543
========= ======== ========= ======== ========
EARNINGS:
Net Income $ 62,909 $ 60,459 $ 55,079 $ 52,213 $ 46,396
Add:
Income Taxes Applicable to
Operating Income 37,514 37,264 34,601 31,483 26,945
Income Taxes Applicable to
Other Income (Loss) - Net (730) 326 (1,479) (694) 109
Total Fixed Charges 31,303 31,300 28,376 27,786 27,543
--------- -------- --------- -------- --------
Total Earnings $ 130,996 $129,349 $ 116,577 $110,788 $100,993
========= ======== ========= ======== ========
Ratio of Earnings to Fixed
Charges 4.2 4.1 4.1 4.0 3.7
========= ======== ========= ======== ========
</TABLE>
26
<PAGE> 29
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>
1995 1994 1993 1992 1991
----------- ---------- ------------ ----------- ----------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 30,932 $ 30,899 $ 27,872 $ 27,386 $ 27,075
Amortization of Debt Premium,
Discount and Expense 315 367 410 358 304
Interest Component of Rentals 56 34 94 42 164
----------- ---------- ------------ ----------- ----------
Total Fixed Charges 31,303 31,300 28,376 27,786 27,543
Pre-tax Preferred Dividends 2,113 2,165 2,139 2,127 2,120
----------- ---------- ------------ ----------- ----------
Total $ 33,416 $ 33,465 $ 30,515 $ 29,913 $ 29,663
=========== ========== ============ =========== ==========
Preferred Dividends $ 1,333 $ 1,335 $ 1,336 $ 1,338 $ 1,339
Effective Income Tax Rate .3690 .3834 .3755 .3709 .3683
Complement of Effective Income
Tax Rate (1 - Tax Rate) .6310 .6166 .6245 .6291 .6317
Pre-tax Preferred Dividends $ 2,113 $ 2,165 $ 2,139 $ 2,127 $ 2,120
=========== ========== ============ =========== ==========
EARNINGS:
Net Income $ 62,909 $ 60,459 $ 55,079 $ 52,213 $ 46,396
Add:
Income Taxes Applicable to
Operating Income 37,514 37,264 34,601 31,483 26,945
Income Taxes Applicable to
Other Income (Loss) - Net (730) 326 (1,479) (694) 109
Total Fixed Charges 31,303 31,300 28,376 27,786 27,543
----------- ---------- ------------ ----------- ----------
Total Earnings $ 130,996 $ 129,349 $ 116,577 $ 110,788 $ 100,993
=========== ========== ============ =========== ==========
Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends 3.9 3.9 3.8 3.7 3.4
=========== ========== ============ =========== ==========
</TABLE>
27
<PAGE> 30
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
Frederick Gas Company, Inc. 100% Maryland
Hampshire Gas Company 100% West Virginia
Crab Run Gas Company 100% Virginia
Washington Resources Group, Inc. a/ 100% Delaware
-
Virginia Intrastate Pipeline Company b/ 100% Virginia
-
a/ Subsidiary companies of Washington
- - Resources Group, Inc. -
Brandywood Estates, Inc. 100% Maryland
Advanced Marketing Concepts, Inc. 100% Delaware
Washington Gas Energy Systems, Inc. c/ 100% Delaware
-
</TABLE>
b/ Inactive
- -
c/ The assets of this subsidiary were sold on May 12, 1995. This company is
- - currently inactive.
28
<PAGE> 31
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. 33-54010,
33-53134, 33-25112, 33-41575, 33-38167, 33-56726, 33-57039, 33-57041 and
33-61199.
ARTHUR ANDERSEN LLP
Washington, D.C.,
December 13, 1995
29
<PAGE> 32
WASHINGTON GAS LIGHT COMPANY
1995 FORM 10-K EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit Description
- ------- -----------
<S> <C>
3 Articles of Incorporation and Bylaws -
Bylaws of the Company as amended on
October 25, 1995
Material Contracts -
10.1 Retirement Plan for Outside Directors,
as amended on October 25, 1995
10.2 Directors' Stock Compensation Plan,
as adopted on October 25, 1995
10.3 Supplemental Executive Retirement Plan
as amended on October 25, 1995
13 Annual Report to Security Holders -
1995 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)
27 Financial Data Schedule
</TABLE>
<PAGE> 1
WASHINGTON GAS LIGHT COMPANY AS AMENDED ON
10/25/95
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 third Wednesday
in the month of February in each year, at 10:00 a.m., at the Capital Hilton
Hotel, 16th and K 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.
<PAGE> 2
- 2 - 10/25/95
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 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
<PAGE> 3
- 3 - 10/25/95
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 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.
<PAGE> 4
- 4 - 10/25/95
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 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:
<PAGE> 5
- 5 - 10/25/95
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
<PAGE> 6
- 6 - 10/25/95
language of the proposed amendment, (2) the name and address, as they
appear on the Company's books, of the 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
<PAGE> 7
- 7 - 10/25/95
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.
ARTICLE II
Board of Directors.
SECTION 1. Number, Powers, Term of Office, Quorum. The Board of
Directors of the Company shall consist of ten 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.
<PAGE> 8
- 8 - 10/25/95
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.
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.
<PAGE> 9
- 9 - 10/25/95
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 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
<PAGE> 10
- 10 - 10/25/95
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
<PAGE> 11
- 11 - 10/25/95
(d) a description of all arrangements or understandings
between the stockholder and any other person or persons
(naming such persons) regarding the nomination.
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.
<PAGE> 12
- 12 - 10/25/95
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.
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
<PAGE> 13
- 13 - 10/25/95
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, 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
<PAGE> 14
- 14 - 10/25/95
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 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
<PAGE> 15
- 15 - 10/25/95
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
<PAGE> 16
- 16 - 10/25/95
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 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.
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
<PAGE> 17
- 17 - 10/25/95
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 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.
<PAGE> 18
- 18 - 10/25/95
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> 19
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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.
<PAGE> 20
- 20 - 10/25/95
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
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,
<PAGE> 21
- 21 - 10/25/95
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 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
<PAGE> 22
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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.
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
<PAGE> 23
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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
WASHINGTON GAS LIGHT COMPANY
RETIREMENT PLAN FOR
OUTSIDE DIRECTORS
As Amended Through October 25, 1995
<PAGE> 2
WASHINGTON GAS LIGHT COMPANY
RETIREMENT PLAN
FOR OUTSIDE DIRECTORS
I. Purpose:
. To reward eligible non-employee members of the Board of Directors
("Directors") of Washington Gas Light Company ("Company") for their services as
a Board Member.
. To provide Directors with retirement income after completion of
their service to WGL.
. To remain competitive in Director compensation by providing a
special retirement benefit.
II. Eligibility - Full and Partial Benefits:
. A Director earns a full retirement benefit under this Plan after
ten years of service as a Director. A partial retirement benefit is earned
after at least five years but less than ten years of service. This partial
retirement benefit is earned ratably between years 6 and 10 (i.e., 0% for
service less than 5 years, 50% after 5 years, 60% after 6 years, 70% after 7
years, etc.).
III. Amount and Term of Benefit:
Amount of Benefit:
. For Directors eligible for the full retirement benefit, the annual
benefit is equal to the amount of the cash retainer provided by WGL at the time
of retirement of the Director from the Board. For example, presently the
retainer is $15,000; thus, a Director eligible for the full retirement benefit
would be entitled to receive an annual benefit of $15,000 for the period
specified below. The amount of the partial retirement benefit would be the
percentage of retainer determined under Paragraph II, above (for example, a
Director retiring after 5 years of service would be entitled to a 50% benefit
or $7,500).
FINAL: 10-25-95
<PAGE> 3
Term of Benefit:
. The benefit will be paid to an eligible Director (or designated
beneficiary) for a 10 year period.
. Payments will begin within 30 days after retirement from the Board
to a Director who retires on or after attainment of age 65. If a Director
retires from the Board prior to age 65 and the Director has 5 or more years of
service, payment of benefits will made to the Director within 30 days of his or
her attainment of age 65. In either case, the Director may elect to defer
payments to a later date provided such election is made in writing on a form
and in a manner satisfactory to the Company.
. Benefits will be paid monthly, unless the Director elects to
receive benefit payments annually or semi-annually.
IV. Disability/Death Benefit:
. If a Director, after a minimum of five years of Board service, is
disabled (construed in the same manner as the term "Disability" under the
Washington Gas Light Employees' Pension Plan), such Director will be eligible
for an immediate benefit under the Plan regardless of age. If the disabled
Director has at least five years of service but less than ten years, the
benefit will be a partial benefit determined in the manner described in
Paragraph II, above. The disability benefit will continue for a ten year
period, as in the case of the retirement benefit.
. If a Director, after a minimum of five years of Board service, dies
during the time of active Board service, benefits will be payable to any
designated beneficiary of the Director, for up to 10 years. The amount of the
benefit will be the same as the benefit paid in the case of disability. If a
retired Director dies while receiving benefits hereunder or prior to the date
that deferred benefits payable hereunder were scheduled to be paid, any
residual benefits or benefits otherwise due the Director, as applicable, will
be paid to the Director's designated beneficiary for the same period such
benefits would otherwise have been paid to the Director had he survived. If no
designated beneficiary is alive at the time of the Director's death, then any
benefits which would otherwise have been payable hereunder will be payable to
the Director's estate.
. Directors may elect, on properly completed forms supplied by the
Company, lump sum distributions to be paid to their designated beneficiaries on
their death. Any payments made to a Director's estate will automatically be in
a lump sum distribution. If the lump sum method is applicable, the death
benefit will be equal to the present value of future benefits, discounted at a
rate equal to the current rate on 5-year U.S. treasury securities.
- 2 - FINAL: 10-25-95
<PAGE> 4
V. Administration:
. The P & C Committee will be Administrator of the Plan. Eligibility
for Retirement and for a Disability benefit will be determined by the P & C
Committee as Plan Administrator.
VI. Funding/ERISA:
. This Plan shall at all times be maintained on an unfunded basis for
federal income tax purposes. A Director's rights to a benefit under this Plan
are contractual in nature and in the event the Company is unable to pay any
benefit required hereunder, the Director shall have, with respect to the
Company, only those rights of an unsecured creditor.
. This Plan does not cover employees of the Company and therefore is
wholly exempt from the requirements and provisions of the Employee Retirement
Income Security Act of 1974, as amended.
VII. Change of Control:
. In the event of a change of control, as defined below, a Director
who has less than 5 years of service as a Director, shall immediately become
100% vested in a benefit as if they had 5 years of service as a Director. For
any additional years of service as a Director, the Director shall continue to
earn benefits in accordance with Paragraph II herein.
. For purposes of this Plan, "Change of Control" means the occurrence
of any one or more of the triggering events specified below:
(a) In the event that any person other than an Affiliate
makes a tender offer or exchange offer for the Common Stock which
would result, if totally successful by its own terms, in such person's
owning greater than 50% of the outstanding Common Stock as measured on
the date such tender or exchange offer is first publicly announced.
(b) In the event of any merger or consolidation involving the
Company and another entity not an Affiliate, as a result of which the
Company would not be the surviving entity or, if the surviving entity,
would no longer be a reporting company under Section 12(b) or 12(g)
of the Securities Exchange Act of 1934, as amended, or of any sale or
lease of all or substantially all of the assets of the Company to
another entity, not an Affiliate.
- 3 - FINAL: 10-25-95
<PAGE> 5
(c) In the event of any change of control of the Company
otherwise than pursuant to one of the triggering events specified
above. For the purposes of the subsection only, a "change of control"
shall be deemed to have occurred if any person, or persons acting as a
group, having beneficial ownership of less than 5% of the Common Stock
as of the effective date of this Supplemental Plan thereafter becomes
the beneficial owner of greater than 50% of such Common Stock.
For purposes of this Section VII, the following terms shall have the
following meanings:
"Affiliate" means any entity that is (I) a member of a controlled
group of corporations as defined in Section 1563(a) of the Internal Revenue
Code of 1986, as amended ("Code"), determined without regard to Code Sections
1563(a)(4) and 1563(e)(3)(C), of which the Company is a member according to
Code Section 414(b); (ii) an unincorporated trade or business that is under
common control with the Company, as determined according to Code Section
414(c); (iii) a member of an affiliated service group of which the Company is a
member according to Code Section 414(m); or (iv) any other subsidiary
corporation or business in which the Company has a substantial interest or
business relation.
"Common Stock" means the common stock of the Company.
VIII. Governing Law:
. All matters relating to this Plan shall be governed by the laws of
the state of Virginia, without regard to the principles of conflict of laws.
- 4 - FINAL: 10-25-95
<PAGE> 1
WASHINGTON GAS LIGHT COMPANY
DIRECTORS' STOCK
COMPENSATION PLAN
AS ADOPTED ON OCTOBER 25, 1995
<PAGE> 2
WASHINGTON GAS LIGHT COMPANY
DIRECTOR'S STOCK COMPENSATION PLAN
ARTICLE I
DEFINITIONS
1.01 AFFILIATE means any "subsidiary" or "parent" corporation of
the Company (as such terms are defined in section 424 of the Code).
1.02 BOARD means the Board of Directors of the Company.
1.03 CODE means the Internal Revenue Code of 1986, as amended.
1.04 COMMON STOCK means the common stock of the Company.
1.05 COMPANY means Washington Gas Light Company.
1.06 DATE OF AWARD means each March 1 during the term of the Plan.
1.07 FAIR MARKET VALUE means, on any given date, the average of the
high and low prices of a share of Common Stock as reported on the New York
Stock Exchange or, if the Common Stock was not traded on such day, then on the
next preceding day that the Common Stock was traded on such exchange, all as
reported by the Wall Street Journal.
1.08 PARTICIPANT means a member of the Board who satisfies the
requirements of Article IV.
1.09 PLAN means the Washington Gas Light Company Directors' Stock
Compensation Plan.
FINAL: 10-25-95
<PAGE> 3
ARTICLE II
PURPOSES
The Plan is intended to assist the Company in promoting a greater
identity of interest between the Company's non-employee directors and its
shareholders, and to assist the Company in attracting and retaining
non-employee directors by affording Participants an opportunity to share in the
future success of the Company.
ARTICLE III
ADMINISTRATION
The Plan shall be administered by the Company's Vice President of
Human Resources in a manner that is consistent with the provisions of this
Plan. The Company's Vice President of Human Resources shall not be liable for
any act done in good faith with respect to this Plan. All expenses of
administering this Plan shall be borne by the Company and its Affiliates.
ARTICLE IV
ELIGIBILITY
Each member of the Board who is not an employee of the Company or an
Affiliate, and who has not been employed by the Company or one of its
Affiliates during the twelve months preceding the Date of Award will
participate in the Plan during his or her service on the Board.
- 2 - FINAL: 10-25-95
<PAGE> 4
ARTICLE V
AWARDS
Shares of Common Stock will be awarded to each Participant as of each
Date of Award. Subject to Article VIII's limitation on the number of shares of
Common Stock which may be issued under the Plan, on each Date of Award each
Participant will be awarded the number of whole shares determined by dividing
$5,000 by the Fair Market Value on the Date of Award. A fractional share shall
not be issued under the Plan but instead each Participant shall be paid the
Fair Market Value of the fractional shares (determined as of the Date of
Award), in cash with the balance of his or her retainer fee for the year.
ARTICLE VI
VESTING OF SHARES
The shares of Common Stock awarded under the Plan will be immediately
vested and nonforfeitable. Subject to the requirements of Article IX, the
shares awarded under the Plan may be sold or transferred by the Participant at
any time.
ARTICLE VII
SHAREHOLDER RIGHTS
Participants will have all the rights of shareholders with respect to
shares awarded under the Plan. Accordingly, Participants will be entitled to
vote the shares and receive dividends.
- 3 - FINAL: 10-25-95
<PAGE> 5
ARTICLE VIII
SHARES AUTHORIZED
Up to forty thousand shares of Common Stock may be awarded under the
Plan. If the Company effects one or more stock dividends, stock split-ups,
subdivisions, reclassifications, or consolidations of shares, or other similar
changes in capitalization after the Plan's adoption by the Board, the maximum
number of shares that may be awarded under the Plan shall be proportionately
adjusted.
ARTICLE IX
COMPLIANCE WITH LAW AND APPROVAL OF REGULATORY BODIES
No Common Stock shall be awarded and no certificates for shares of
Common Stock shall be delivered under the Plan except in compliance with all
applicable federal and state laws and regulations, any listing agreement to
which the Company is a party, and the rules of all domestic stock exchanges on
which the Company's shares may be listed. The Company shall have the right to
rely on the opinion of its counsel as to such compliance. Any share
certificate issued to evidence Common Stock issued under the Plan may bear such
legends and statements as the Company may deem advisable to assure compliance
with federal and state law and regulations. No Common Stock shall be awarded
and no certificates for shares of Common Stock shall be delivered until the
Company has obtained such consent or approval as it may deem advisable from
regulatory bodies having jurisdiction over such matters.
- 4 - FINAL: 10-25-95
<PAGE> 6
ARTICLE X
GENERAL PROVISIONS
10.01 UNFUNDED PLAN. The Plan, insofar as it provides for grants,
shall be unfunded, and the Company shall not be required to segregate any
assets that may at any time be represented by grants under the Plan. Any
liability of the Company to any person with respect to any grant under the Plan
shall be based solely upon any contractual obligations that may be created
pursuant to the Plan. No such obligation of the Company shall be deemed to be
secured by any pledge of, or other encumbrance on, any property of the Company.
10.02 RULES OF CONSTRUCTION. Headings are given to the articles and
sections of the Plan solely as a convenience to facilitate reference. The
references to any statute, regulation, or other property of law shall be
construed to refer to any amendment to or successor of such provisions of law.
ARTICLE XI
AMENDMENT OF PLAN
The Board may amend the Plan from time to time. No amendment may
become effective until shareholder approval is obtained if such approval is
required by any federal or state law or regulation or the rules of any stock
exchange on which the Common Stock may be listed, or if the Board in its
discretion determines that the obtaining of such shareholder approval is for
any reason advisable. No amendment shall, without a Participant's consent,
adversely affect any rights of such Participant under any Award outstanding at
the time such amendment is made.
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<PAGE> 7
ARTICLE XII
DURATION OF PLAN
The final award under the Plan will be made as of the Date of Award in
2006. The Board may terminate the Plan sooner by appropriate action. The Plan
will terminate automatically, without action by the Board, if there are
insufficient shares available to make the awards described in the Plan.
ARTICLE XIII
EFFECTIVE DATE OF PLAN
The Plan will become effective once it is adopted by the Board and
approved by a majority of the votes cast at a duly held shareholders' meeting
at which a quorum representing a majority of all outstanding voting stock is,
either in person or by proxy, present and voting on the Plan. No awards will
be made under the Plan prior to approval of the Plan, by the Company's
shareholders.
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<PAGE> 1
WASHINGTON GAS LIGHT COMPANY
SUPPLEMENTAL EXECUTIVE
RETIREMENT PLAN
As Amended Through October 25, 1995
FINAL: 10/25/95
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
Article 1. Purpose 1-1
Article 2. Definitions 2-1
Article 3. Participation 3-1
Article 4. Vesting 4-1
Article 5. Service 5-1
Article 6. Benefits 6-1
Article 7. Death Benefits 7-1
Article 8. Miscellaneous 8-1
</TABLE>
- i - FINAL: 10/25/95
<PAGE> 3
Article 1
Purpose
1.1 Purpose: The purpose of this Supplemental Executive Retirement Plan
(Supplemental Plan) is to provide a minimum level of retirement income in the
event of normal or early retirement and a minimum level of benefits in the
event of death or disability as a means of attracting, retaining, and
motivating executives. This Supplemental Plan is designed to provide a benefit
which, when added to the benefit provided by the Washington Gas Light Company
Employees' Pension Plan will meet the purpose described above.
The Company intends that the Supplemental Plan shall at all times be
maintained on an unfunded basis for federal income tax purposes under the
Internal Revenue Code of 1986, as amended, and be administered as a "top-hat"
plan exempt from the substantive requirements of the Employee Retirement Income
Security Act of 1974, as amended.
1 - 1 FINAL: 10/25/95
<PAGE> 4
Article 2
Definitions
2.1 Accredited Service: Accredited Service as defined in the Basic Plan.
2.2 Accrued Benefit: The amount expressed in terms of an annual
single-life annuity commencing at Normal Retirement Date and determined in
accordance with Section 6.4 which describes the Normal Retirement Pension.
2.3 Administrator: The Administrator appointed by the Personnel and
Compensation Committee to carry out the administration of this Supplemental
Plan.
2.4 Basic Plan: Washington Gas Light Company Employees' Pension Plan, as
amended from time to time.
2.5 Board or Board of Directors: The Board of Directors of the Washington
Gas Light Company.
2.6 Change of Control: The occurrence of any one or more of the
triggering events specified below:
2 - 1 FINAL: 10/25/95
<PAGE> 5
(a) In the event that any person other than an Affiliate makes a
tender offer or exchange offer for the Common Stock which would result, if
totally successful by its own terms, in such person's owning greater than 50%
of the outstanding Common Stock as measured on the date such tender or exchange
offer is first publicly announced.
(b) In the event of any merger or consolidation involving the
Company and another entity not an Affiliate, as a result of which the Company
would not be the surviving entity or, if the surviving entity, would no longer
be a reporting company under Section 12(b) or 12(g) of the Securities Exchange
Act of 1934, as amended, or of any sale or lease of all or substantially all of
the assets of the Company to another entity, not an Affiliate.
(c) In the event of any change of control of the Company otherwise
than pursuant to one of the triggering events specified above. For the
purposes of this subsection only, a "change of control" shall be deemed to have
occurred if any person, or persons acting as a group, having beneficial
ownership of less than 5% of the Common Stock as of the effective date of this
Supplemental Plan thereafter becomes the beneficial owner of greater than 50%
of such Common Stock.
2 - 2 FINAL: 10/25/95
<PAGE> 6
For purposes of this Section 2.6, the following terms shall
have the following meanings:
"Affiliate" means any entity that is (i) a member of a
controlled group of corporations as defined in Section 1563(a) of the Internal
Revenue Code of 1986, as amended ("Code"), determined without regard to Code
Sections 1563(a)(4) and 1563(e)(3)(C), of which the Company is a member
according to Code Section 414(b); (ii) an unincorporated trade or business that
is under common control with the Company, as determined according to Code
Section 414(c); (iii) a member of an affiliated service group of which the
Company is a member according to Code Section 414(m); or (iv) any other
subsidiary corporation or business in which the Company has a substantial
interest or business relation.
"Common Stock" means the common stock of the Company.
2.7 Company: Washington Gas Light Company.
2.8 Disability: Disability as defined in the Basic Plan.
2.9 Early Retirement Date: Early Retirement Date as defined in the Basic
Plan.
2 - 3 FINAL: 10/25/95
<PAGE> 7
2.10 Final Average Compensation: The average of the Participant's highest
Rates of Annual Basic Compensation on December 31 of each of the three years
out of the final five years of the Participant's Accredited Service as a
Participant preceding such Participant's Normal Retirement Date, Early
Retirement Date, date of Disability, death or the date of the Participant's
Termination as described in Section 3.2, whichever is applicable; however, if
such five-year period should include any approved leave of absence in effect on
December 31 of any year during such five-year period, his or her Rate of Annual
Basic Compensation in effect at the beginning of such leave shall be deemed to
be his or her Rates of Annual Basic Compensation in effect for that year. In
the event a Participant is entitled to an Accrued Benefit under this
Supplemental Plan but has less than five years of Accredited Service as a
Participant, the Participant's Rate of Annual Basic Compensation on December 31
of each year of service while a Participant shall be averaged and such average
shall be Participant's Final Average Compensation. Should a Participant die or
incur a Disability and have less than one year of Accredited Service, which
year does not include December 31, the Participant's Final Average Compensation
shall be, as applicable, his or her Rates of Annual Basic Compensation on the
day preceding the date of such Participant's death or the Administrator's
acceptance of the Disability under Section 6.7.
2 - 4 FINAL: 10/25/95
<PAGE> 8
2.11 Normal Retirement Date: Normal Retirement Date as defined in the Basic
Plan.
2.12 Participant: An employee designated as such by the Personnel and
Compensation Committee pursuant to Section 3.1 of this Supplemental Plan.
Unless expressly provided herein to the contrary or the context dictates
otherwise, a Participant shall also include any person (including a
beneficiary) who is entitled to a benefit under this Supplemental Plan.
2.13 Rates of Annual Basic Compensation: Participant's salary as of December
31 and any award declared during the year under the Company's Executive
Incentive Compensation Plan, whether taken in cash or deferred as provided by
the Plan.
2.14 Retirement: Retirement as defined in the Basic Plan.
2.15 Vesting Service: Vesting Service is 1000 hours of service with the
Company as a Participant in any one calendar year.
2 - 5 FINAL: 10/25/95
<PAGE> 9
Article 3
Participation
3.1 Designation: Each employee of the Company who is designated by the
Personnel and Compensation Committee of the Board of Directors shall be a
Participant in this Supplemental Plan. Each officer of the Company, as of June
28, 1989, whose remuneration was approved by the Board of Directors, shall
continue to be a Participant in this Supplemental Plan until further action by
the Personnel and Compensation Committee.
3.2 Termination: In the event Participant's employment with the Company is
terminated for whatever reason or in the event the Personnel and Compensation
Committee withdraws or rescinds its designation of Participant status with
respect to a current employee, such terminated or current employee, as
applicable, shall thereafter accrue no additional benefits under this
Supplemental Plan and shall have, with respect to previously credited benefits,
only such rights as are provided in Articles 4, 5 and 6 hereof.
3 - 1 FINAL: 10/25/95
<PAGE> 10
Article 4
Vesting
4.1 Vested Pension -- General: Except as provided in Section 4.2 of this
Article, a Participant shall be 100% vested in, and have rights to, an Accrued
Benefit only in the event of: (a) Disability while an employee of the Company
in active Participant status, (b) Retirement on or after attaining age 55, or
(c) a Change of Control as defined in Section 2.6.
4.2 Vested Pension -- Exceptions: Notwithstanding the general provisions in
Section 4.1, the following exceptions shall apply --
(a) For participation on or before June 27, 1989, a Participant shall
be vested in, and have rights to, an Accrued Benefit as set out in the table
below. Except as provided in (b) and (c) below, a Participant's vested
percentage shall not increase by reason of participation after June 27, 1989.
4 - 1 FINAL: 10/25/95
<PAGE> 11
<TABLE>
<CAPTION>
Completed Years
of Vested
Vesting Service Percentage
--------------- ----------
<S> <C>
1 20%
2 40%
3 60%
4 80%
5 100%
</TABLE>
(b) A Participant's Accrued Benefit shall vest in accordance with
the table in (a) above if his or her termination of employment occurs as a
result of a Company-initiated action or request or if his or her designation of
Participant status is withdrawn or rescinded by the Company; provided, however,
that this provision shall not apply if the forfeiture provisions of Section 8.5
apply.
(c) The Personnel and Compensation Committee may waive all vesting
requirements or permit accelerated vesting arrangements in any case which, in
the Personnel and Compensation Committee's discretion, represents special
circumstances.
4 - 2 FINAL: 10/25/95
<PAGE> 12
Article 5
Service
5.1 Benefit Service: Except as provided in Section 5.2 of this Article,
Benefit Service shall be equal to Accredited Service as determined under the
Basic Plan plus, for each full year of Accredited Service as a Participant, one
additional year to a maximum of 30 years.
5.2 Prior Benefit Service: A Participant who began participation on or before
June 27, 1989, shall receive Benefit Service which shall be equal to Accredited
Service as determined under the Basic Plan plus, for each full year of
Accredited Service as a Participant, two additional years for participation
through June 27, 1989.
5 - 1 FINAL: 10/25/95
<PAGE> 13
Article 6
Benefits
6.1 Normal Form of Pension: A Participant who is entitled to receive a
retirement benefit under this Supplemental Plan may elect to receive such
benefit in the form of a single-life annuity, joint-and-survivor annuity or any
other optional form of benefit as set forth in Section 5.2 of the Basic Plan.
The normal form of pension under this Supplemental Plan shall be identical to
the form of benefit selected by the Participant under the Basic Plan unless the
Participant requests, and the Company approves, the lump-sum option described
in Section 6.2 of this Supplemental Plan. Any temporary actuarial increase in
benefits generated by Participant's selection of the option in Section 5.2(b)
of the Basic Plan shall not be considered in determining the Normal Retirement
Pension upon which the benefit from this Supplemental Plan is calculated, nor
shall any reduction in Normal Retirement Pension under the Basic Plan at age 62
increase a benefit under this Supplemental Plan.
6.2 Lump-Sum Option: A Participant may request that the portion of his or her
retirement benefit under this Supplemental Plan related to any award declared
under the Company's Executive Incentive Compensation Plan, as used in
determining Rates of Annual Basic Compensation, maybe paid in the form of a
lump sum,
6 - 1 FINAL: 10/25/95
<PAGE> 14
the amount of which shall be the actuarial equivalent of the Accrued Benefit
otherwise payable to the Participant under this Supplemental Plan. A
Participant's request for a lump sum payment must be submitted in writing to
the Administrator at least six months prior to the date on which a benefit
would otherwise be payable hereunder and must be accompanied by a medical
certificate of the Participant's good health signed by the Company's Medical
Director in a form satisfactory to the Administrator; provided, however, that
if a Participant's retirement occurs within six months of the date on which
this provision becomes effective, a Participant's written request for a lump
sum payment shall be considered timely filed so long as it is received by the
Administrator at least 60 days prior to the date a benefit would be payable
hereunder. A Participant's request for a lump sum payment shall be subject to
the sole discretion of the Administrator and shall be approved by the
Administrator only if considered to be in the interests of the Company. If
approved by the Administrator, a Participant's lump-sum payment shall be
calculated on the basis of reasonable actuarial assumptions satisfactory to the
Company.
6.3 Election of Benefit: A Participant shall not defer a benefit under the
Basic Plan and receive a benefit under this Supplemental Plan. A Participant
shall not elect a benefit for a beneficiary of over 50% of the Participant's
benefit without
6 - 2 FINAL: 10/25/95
<PAGE> 15
presenting a medical certificate of the Participant's good health signed by the
Company's Medical Director in a form satisfactory to the Administrator.
6.4 Normal Retirement Pension: On Normal Retirement Date, a Participant shall
be eligible to receive a monthly Normal Retirement Pension equal to 1/12 of the
excess of (a) over (b) where:
(a) equals 2% of Final Average Compensation multiplied by the
number of years of Benefit Service; and
(b) equals the sum of:
(1) the Normal Retirement Pension payable under
the Basic Plan; and
(2) the annual amount of any other supplemental
pension benefit provided by the Company.
In no event shall the Normal Retirement Pension be less than the Accrued
Benefit calculated as of June 27, 1989.
6.5 Full Retirement Pension: A Participant who has attained age 60 and has 30
years of Benefit Service shall be eligible for a monthly payment of an amount
equal to 100% of the Normal Retirement Pension.
6 - 3 FINAL: 10/25/95
<PAGE> 16
6.6 Early Retirement Pension: A Participant who has attained age 55 and has
10 or more years of Benefit Service is eligible to select either:
(a) an amount, commencing at age 65, equal to the Accrued Benefit,
determined in the same manner as the Normal Retirement Pension
in Section 6.4, based on Benefit Service and Final Average
Compensation as of the Participant's Early Retirement Date; or
(b) an amount, commencing immediately upon Retirement, equal to
the Participant's Accrued Benefit subject to an early
retirement reduction determined in accordance with Table B in
Section 4.6 of the Basic Plan.
6.7 Disability Pension: A Participant who has 10 or more years of Benefit
Service and has suffered a Disability shall be eligible for a monthly amount
equal to: (1) the Early Retirement Pension (except that any such Participant
under age 55 will be treated as though age 55); or (2) an amount equal to 110%
of the Disability Pension available from the Basic Plan, whichever is greater;
but in no event shall the amount exceed the Normal Retirement Pension under
this Plan as set out in Section 6.4 above. An Application for a Disability
Pension shall be submitted to the Administrator by the applicant or by the
Company, together with a medical certificate signed by the
6 - 4 FINAL: 10/25/95
<PAGE> 17
Company's Medical Director in a form satisfactory to the Administrator. A
Participant with less than 10 years of Benefit Service who suffers a Disability
supported by a medical certificate satisfactory to the Administrator shall be
eligible for an immediate benefit calculated in a manner consistent with the
Early Retirement Pension described in Section 6.6(b), subject to an actuarial
reduction based on the Participant's actual age at the time of benefit
commencement.
6.8 Benefit Compensation: Except as provided in Section 6.9 of this Article, a
Participant's pension shall be computed under the terms of the Supplemental
Plan in effect as of the date of the Participant's Termination, as described in
Section 3.2 hereof, and shall not be recomputed, increased or decreased after
such Termination, except for supplemental increases, if any, as may be granted
by the Company's Board of Directors.
6.9 Prior Benefit Compensation: Any person who was a Participant in this
Supplemental Plan on June 27, 1989, and who retires at age 60 or above, on or
before December 31, 1998, shall in no event receive a pension benefit which is
less than the benefit calculated under the provisions of the Supplemental Plan
in effect on June 27, 1989.
6 - 5 FINAL: 10/25/95
<PAGE> 18
Article 7
Death Benefits
7.1 Death Benefits: Except for the surviving spouse's annuity described in
Sections 7.2 and 7.3, and any survivor death benefit selected by a Participant
in accordance with Section 7.4, no death benefits shall be payable under this
Supplemental Plan and a Participant shall forfeit all rights to any benefits
hereunder upon his or her death. As used in this Article, the term "surviving
spouse" refers to the person who is legally married to the Participant at the
time of his death and for the full one year (365 days) period immediately prior
to his death.
7.2 Surviving Spouse of Designated Participant: The surviving spouse of a
designated Participant who has not retired shall be eligible to receive a
monthly annuity in an amount equal to 50% of the deceased Participant's Accrued
Benefit (without regard to vesting) determined on the basis of (i) the
Participant's Final Average Compensation at the date of death, and (ii) the
Benefit Service the Participant would have had if employment had continued
until the Normal Retirement Date.
7.3 Surviving Spouse of Person in Termination Status: Upon the death of a
person who is no longer a designated Participant or who is not employed by the
Company at the time of death, the
7 - 1 FINAL: 10/25/95
<PAGE> 19
surviving spouse of such person shall receive an annuity under this
Supplemental Plan only to the extent, if any, that such person was vested in an
Accrued Benefit pursuant to Section 4.2. Such annuity shall be calculated
based on the Benefit Service accrued by such person at time of his or her
Termination, as described in Section 3.2 hereof, but in no event shall such
annuity exceed the amount which the surviving spouse would have received had
the spouse been entitled to the annuity described in Section 7.2 hereof.
7.4 Survivor Death Benefit: Upon the death of a retired Participant who
is receiving or is entitled to receive annuity benefits hereunder and who, in
accordance with Section 6.1 hereof, had previously elected to receive his or
her Accrued Benefit in a form which pays a death benefit to a designated
surviving beneficiary, such death benefit shall be paid to such designated
surviving beneficiary in accordance with such prior election.
7 - 2 FINAL: 10/25/95
<PAGE> 20
Article 8
Miscellaneous
8.1 Amendment, Suspension, or Termination: Any amendment, suspension, or
termination of this Supplemental Plan shall have prospective effect only, be
non-discriminatory, and shall not affect any Accrued Benefit or vested right.
8.2 Nonguarantee of Employment: Nothing in this Supplemental Plan shall be
construed as a contract of employment between the Company and any Participant,
or as a right of any Participant to be continued in the employment of the
Company, or as a limitation of the right of the Company to discharge any
Participant, with or without cause.
8.3 Cost: The Company shall pay the full cost of this Supplemental Plan and
the Plan shall at all times be maintained on an unfunded basis. A
Participant's rights to a benefit under this Supplemental Plan are contractual
in nature and in the event the Company is unable to pay any benefit required
hereunder, the Participant shall have, with respect to the Company, only those
rights of an unsecured creditor.
8 - 1 FINAL: 10/25/95
<PAGE> 21
8.4 Nonalienation of Benefits: Benefits payable under this Supplemental Plan
shall not be subject in any manner to alienation, anticipation, assignment,
charge, encumbrance, execution, garnishment, pledge, sale, transfer, or levy of
any kind, either voluntary or involuntary, including any such liability which
is for alimony or other payments for the support of a spouse or former spouse,
or for any other relative of the Participant, prior to actually being received
by the person entitled to the benefit under the terms of this Supplemental
Plan. Any attempt to alienate, anticipate, assign, charge, encumber, pledge,
sell, transfer, or otherwise dispose of any right to benefits payable under
this Supplemental Plan shall be void. This Supplemental Plan shall not in any
manner be liable for, or subject to, the contracts, debts, liabilities, or
torts of any person entitled to benefits under this Supplemental Plan.
8.5 Forfeiture: Anything herein to the contrary notwithstanding, if a
Participant or retired Participant willfully performs any act or willfully
fails to perform any act of material importance to the Company, which may
result in material discredit or substantial detriment to the Company, then upon
recommendation of the Administrator and upon a majority vote of the Board of
Directors, such Participant or retired Participant or the surviving spouse of
such Participant shall forfeit any benefit payments owing on and after the date
fixed by
8 - 2 FINAL: 10/25/95
<PAGE> 22
the Board of Directors and the Company shall have no further obligation under
this Supplemental Plan to such Participant, retired Participant, or the
surviving spouse of such Participant. If a Participant received his or her
benefit in the form of a lump sum payment pursuant to Section 6.2 hereof, then
the Participant or the surviving spouse of such Participant shall return to the
Company a proportionate share of such lump sum payment calculated as follows:
The proportionate share shall equal the product of the lump sum payment
multiplied by a fraction, the numerator of which is the number of full years
and months which elapsed from the time of the payment to the time of the
willful act or failure to act described herein and the denominator of which is
the number of full years and months of the Participant's life expectancy
determined as of the time of the lump sum payment.
8.6 Governing Law: All matters relating to this Supplemental Plan shall be
governed by the laws of the state of Virginia, without regard to the principles
of conflict of laws.
8 - 3 FINAL: 10/25/95
<PAGE> 1
SELECTED FINANCIAL DATA
Washington Gas Light Company
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands, Except Per Share Data)
<S> <C> <C> <C> <C> <C>
Operating revenues . . . . . . . . . $ 828,748 $ 914,863 $ 894,300 $ 746,224 $ 697,875
Cost of gas . . . . . . . . . . . . . 390,041 462,195 478,982 352,686 348,499
----------- ----------- ------------ ------------- -----------
Net revenues . . . . . . . . . . . . $ 438,707 $ 452,668 $ 415,318 $ 393,538 $ 349,376
----------- ----------- ------------ ------------- -----------
Net income . . . . . . . . . . . . . $ 62,909 $ 60,459 $ 55,079 $ 52,213 $ 46,396
Dividends on preferred stock . . . . 1,333 1,335 1,336 1,338 1,339
----------- ----------- ------------ ------------- -----------
Net income applicable to
common stock . . . . . . . . . . . $ 61,576 $ 59,124 $ 53,743 $ 50,875 $ 45,057
----------- ----------- ------------ ------------- -----------
Earnings per average share of
common stock . . . . . . . . . . . $ 1.45 $ 1.41 $ 1.31 $ 1.26 $ 1.14
----------- ----------- ------------ ------------- -----------
Total assets at year-end . . . . . . $ 1,360,138 $ 1,332,954 $ 1,205,788 $ 1,065,732 $ 1,013,921
----------- ----------- ------------ ------------- -----------
Long-term obligations at
year-end . . . . . . . . . . . . . $ 329,051 $ 342,308 $ 347,884 $ 296,357 $ 266,467
----------- ----------- ------------ ------------- -----------
Common Stock Data
Annualized dividends per share . . $ 1.12 $ 1.11 $ 1.09 $ 1.07 $ 1.05
Dividends declared per share . . . $ 1.1175 $ 1.105 $ 1.085 $ 1.065 $ 1.0425
Dividends paid per share . . . . . $ 1.115 $ 1.10 $ 1.08 $ 1.06 $ 1.035
Book value per share . . . . . . . $ 11.95 $ 11.51 $ 11.04 $ 10.66 $ 10.34
Return on average common equity . 12.3% 12.5% 12.1% 12.0% 11.1%
Yield on book value . . . . . . . 9.4% 9.6% 9.8% 10.0% 10.1%
Payout ratio . . . . . . . . . . . 77.1% 78.4% 82.8% 84.5% 91.4%
Common shares outstanding--
year-end (thousands) . . . . . 42,932 42,187 41,495 40,616 39,889
Capitalization at Year-End
Common shareholders' equity . . . $ 513,044 $ 485,504 $ 458,044 $ 433,121 $ 412,379
Preferred stock . . . . . . . . . 28,471 28,498 28,521 28,552 28,588
Long-term debt . . . . . . . . 329,051 342,270 347,701 294,451 262,987
----------- ----------- ------------ ------------- -----------
Total . . . . . . . . . . . . . $ 870,566 $ 856,272 $ 834,266 $ 756,124 $ 703,954
----------- ----------- ------------ ------------- -----------
Gas Delivered (thousands of therms)
Residential . . . . . . . . . . . 596,499 672,958 641,529 603,952 534,479
Commercial and industrial--
Firm . . . . . . . . . . . . . 403,177 443,246 422,977 406,218 361,819
Interruptible . . . . . . . . . 247,600 236,068 258,433 255,880 239,597
Electric generation--
Interruptible . . . . . . . . . 131,061 86,183 35,447 73,485 113,488
Transportation service . . . . . . 61,467 26,147 16,699 13,264 13,924
----------- ----------- ------------ ------------- -----------
Total . . . . . . . . . . . . . 1,439,804 1,464,602 1,375,085 1,352,799 1,263,307
----------- ----------- ------------ ------------- -----------
Other Statistics
Customer meters . . . . . . . . . 750,849 725,960 703,122 683,277 667,114
Degree days . . . . . . . . . . . 3,660 4,311 4,246 3,946 3,370
Percent colder (warmer)
than normal . . . . . . . . . . (5.2)% 11.8% 10.1% 1.8% (13.8)%
Capital expenditures . . . . . . . $ 112,715 $ 119,796 $ 100,778 $ 88,182 $ 81,587
</TABLE>
t w e n t y - t w o
<PAGE> 2
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
In fiscal year 1995, a two-for-one split of the company's common stock became
effective. All share disclosures and earnings per share calculations for
present and prior years are presented on a post-split basis.
EARNINGS
1995 VS. 1994. Net income applicable to common stock for 1995 was $61.6
million, which was $2.5 million higher than the results for 1994. Operating
income was virtually unchanged from 1994. Weather that was 15.1% warmer than
the prior year, which resulted in lower therm sales and lower net revenues, was
almost completely offset by the combined effect of a 3.4% increase in customer
meters, increased retail rates and lower other operating expenses. Other income
(loss)-net improved by $2.3 million, including a $1.9 million after-tax gain on
the sale of a non-utility subsidiary. Earnings per average common share were
$1.45, representing a $.04 increase over the level for 1994. Average common
shares outstanding increased by 1.8%. The company earned 12.3% on average
common equity in 1995.
1994 VS. 1993. Net income applicable to common stock for 1994 was $59.1
million, an increase of $5.4 million over the results for 1993. The earnings
improvement was primarily a result of the combined effect of a 3.2% increase in
the number of customer meters, increased retail rates in two of the company's
major jurisdictions and weather that was 1.5% colder than the prior year.
Improved results from the company's non-utility activities also contributed to
the increase in earnings. The beneficial impact of these factors was
substantially offset by higher other operating expenses and increased interest
expense. Earnings per average share of common stock were $1.41, representing an
increase of $.10 per average common share from the 1993 level of $1.31. Average
common shares outstanding increased by 1.9%. The company earned 12.5% on
average common equity in 1994.
[FIGURE 1 - SEE APPENDIX A]
NET REVENUES
Net revenues decreased by $14.0 million, or 3.1%, in 1995 and increased by
$37.4 million, or 9.0%, in 1994. The factors contributing to the changes in net
revenues between years are provided in the following table and the discussion
below. The level of annual therm sales is highly sensitive to the variability
of the weather from normal levels, since such a large portion of the company's
deliveries of natural gas is used for heating. Rate relief is granted based on
normal weather. A comparison of weather to normal for 1991 to 1995 is shown in
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 two of its three major jurisdictions,
which reduce the impact of deviations in weather from normal.
COMPOSITION OF THE CHANGES
IN NET REVENUES
<TABLE>
<CAPTION>
Increase/(Decrease)
From Prior Year
-------- ---------------
1995 1994
- ---------------------------------------------------------------------
(Millions)
<S> <C> <C>
Volumes Delivered to
Firm Customers. . . . . . . . $(27.5) $11.4
Rate Relief . . . . . . . . . . 19.3 16.0
Gross Receipts Taxes . . . . . (4.6) .9
Deliveries to Interruptible
Customers . . . . . . . . . . .8 (1.7)
Other . . . . . . . . . . . . . (2.0) 10.8
------- -----
$(14.0) $37.4
======= =====
</TABLE>
1995 VS. 1994. Therm sales to firm customers dropped by 116.5 million therms in
1995, or 10.4%. This net reduction was caused by weather that was 15.1% warmer
than the prior year, which was partially offset by a 3.4% increase in customer
meters. The overall decline in volumes sold to the firm class caused a $27.5
million drop in net revenues.
The effect of rate relief on net revenues in fiscal year 1995 was an increase
of $19.3 million, caused substantially by the impact of decisions in the
company's three major jurisdictions. The company was granted an increase in
retail rates of $6.4 million on August 1, 1994, by the Public Service
Commission of the District of Columbia (PSC of DC). An increase of $6.8 million
was granted by the State Corporation Commission of Virginia (SCC of VA)
effective September 27, 1994, and an increase of $7.4 million was granted by
the Public Service Commission of Maryland (PSC of MD) on December 1, 1994.
These decisions are discussed in detail under the caption entitled Rate Relief
on page 29. A summary of Rate Applications and Results is included on page 31.
t w e n t y - t h r e e
<PAGE> 3
[FIGURE 2 - SEE APPENDIX A]
Gross receipts taxes, which are recovered from customers and remitted to the
various taxing authorities, decreased by $4.6 million. These taxes are levied
on revenues and therefore decreased with the decline in revenues. This drop is
offset by a decline in the amount recorded in general tax expense and therefore
this change does not affect net income.
Interruptible customers are required to be capable of using an alternate fuel
as a substitute for natural gas when determined by the company, or in
circumstances in which the customer determines other fuels can be used more
economically. This customer class has the option of buying natural gas from the
company or from a third-party supplier. In either case, the company charges its
customers for delivering (transporting) natural gas on its distribution system.
A delineation of the volumetric changes in therms delivered to these customers
is shown in the Selected Financial Data on page 22. Volumes shown in this data
as transportation service represent situations in which the customer purchased
natural gas directly from a third-party supplier and used the company to
transport the natural gas on the company's distribution system.
Therms delivered to interruptible customers, excluding deliveries to Potomac
Electric Power Company (Pepco), increased by 46.9 million therms (17.9%). This
increase reflects the effect of significant interruptions during the second
fiscal quarter of 1994 due to extreme weather in that period. Net revenues
associated with therms delivered to the interruptible class increased by
$814,000. The effect on net income of changes in delivered volumes and prices
to this customer class is minimized by margin sharing arrangements that are
part of the company's rate design in each of its major jurisdictions. To date,
these arrangements have provided for a return of the majority of the gross
margins earned on such sales or deliveries to firm customers after a gross
margin threshold is reached or in exchange for the shift of a portion of the
fixed costs from the interruptible to the firm class.
Included in the caption entitled "Other" are deliveries to Pepco, the company's
largest customer. In 1995, the company delivered 131.1 million therms to Pepco.
Of this total, the volumes sold to Pepco totalled 112.5 million therms. The
total volumes delivered represents an increase over 1994 of 44.9 million therms
(52.1%) and includes the effect of increased cooling requirements during the
summer of 1995. The effect on net revenues and net income of increases or
decreases in volumes delivered to Pepco is not material due to a margin sharing
arrangement approved by the PSC of MD that requires the company to return
substantially all of the gross margins, less related expenses, earned on such
deliveries to firm customers. The arrangement also allows for accelerated
recovery of the company's investment to serve Pepco. By returning margins from
these deliveries to firm customers in the Maryland jurisdiction, the company's
competitive position is enhanced.
[FIGURE 3 - SEE APPENDIX A]
The company's total cost of gas for 1995 dropped to 28.68c. per therm from the
1994 level of 32.13c. per therm. This decline was due to a significant drop in
the per therm cost of gas purchased from producers or marketers during the
current year due to the mild winter. This favorable impact on the cost of gas
was partially offset by lower refunds received from the pipelines and the
effect of the level of fixed charges incurred in both years but with fewer
volumes purchased and delivered in 1995. Increases or decreases in the cost of
gas associated with sales made to firm customers have no effect on net income
because any change from the stipulated base cost of gas included in rates will
be recovered from or returned to customers in a succeeding period. The
commodity cost of gas invoiced the company was 19.33c. and 25.61c. per therm
for 1995 and 1994, respectively.
1994 VS. 1993. Therm sales to firm customers rose in 1994 by 51.7 million
therms, or 4.9%, due to a 3.2% increase in customer meters and weather that was
1.5% colder than the prior year. The increase in volumes sold to this customer
class resulted in an $11.4 million increase in net revenues.
t w e n t y - f o u r
<PAGE> 4
Rate relief granted to the company's District of Columbia and Maryland
divisions in calendar year 1993 and additional rate relief granted the District
of Columbia division in August 1994 contributed $16.0 million to net revenues.
Gross receipts taxes increased by $913,000. As discussed previously, the
increase in net revenues associated with these taxes is offset by an equivalent
amount recorded in general tax expense.
Therms delivered to interruptible customers (excluding sales for electric
generation) declined by 12.9 million therms (4.7%) during 1994, resulting
primarily from significant interruptions in the second fiscal quarter of 1994
because of severe weather conditions. Net revenues associated with therms
delivered to these customers declined by $1.7 million.
Other net revenues increased by $10.8 million. This resulted primarily from the
separation of the revenue requirement associated with the carrying costs on
storage gas inventories from base rates in the company's Maryland jurisdiction,
increased net revenues from sales to Pepco, higher miscellaneous service
revenues and increased system charges in each of the company's major
jurisdictions.
The cost of gas for 1994 fell to 32.13c. per therm from the 1993 level of
35.26c.. Contributing to this decline were increased refunds from pipelines
that are refunded to customers, a modest decline in the commodity cost of gas,
and the effect of greater volumes sold in 1994 when considered with the level
of fixed costs to acquire gas supplies in both years. The commodity cost of gas
invoiced the company was 25.61c. and 26.09c. per therm in 1994 and 1993,
respectively.
[FIGURE 4 - SEE APPENDIX A]
OTHER OPERATING EXPENSES
1995 VS. 1994. Operation and maintenance expenses declined by $12.6 million
(6.1%) from the 1994 level. Included in this drop are the effects of lower
employee levels resulting from attrition in the work force, lower overtime
costs, the lockout of approximately 1,050 union eligible employees for
approximately 16 weeks and a lower provision for injuries and damages.
Partially offsetting these factors were the additional costs of management
overtime and the use of outside contractors in fiscal year 1995 during the
lockout. Also increasing was the cost of post-retirement benefits other than
pensions reflecting the inclusion of additional costs in retail rates in the
District of Columbia and Virginia.
At September 30, 1995, the company had 2,405 utility employees, a drop of 140
employees (5.5%) from the level at September 30, 1994. For a discussion of the
results and status of the company's labor negotiations, please refer to the
caption entitled Labor Matters on page 31.
Depreciation and amortization increased by $2.9 million (6.6%), due to a $3.4
million increase in depreciation on the company's rising investment in plant
and equipment. This increase was partially offset by a drop in amortization of
the company's investment in facilities to serve Pepco. The PSC of MD has
permitted the company accelerated amortization of these facilities before
sharing the majority of margins earned on deliveries to this customer. All of
the company's investment to serve Pepco has been recovered at September 30,
1995. In 1995, capital expenditures totalled $112.7 million and the composite
depreciation rate was unchanged from the 1994 rate of 2.97%.
The composition of the change in general taxes is shown in Note 6 to the
Consolidated Financial Statements. The composition of the change in income tax
expense is detailed in the Consolidated Statement of Income Taxes on page 37.
[FIGURE 5 - SEE APPENDIX A]
1994 VS. 1993. Operation and maintenance expenses increased by $22.2 million
(12.0%) in 1994. Employee benefit expenses included therein rose by $10.1
million, due to the effect of the implementation in 1994 of Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106). Other factors
t w e n t y - f i v e
<PAGE> 5
that contributed to the increase included accruals for potential injuries and
damages and higher uncollectible accounts expenses. Demand Side Management
(DSM) expenses incurred on behalf of customers in the State of Maryland to help
reduce the demand for natural gas by giving customers rebates for installing
high efficiency appliances, increased by $963,000. Despite general wage
increases, labor expenses declined by $450,000 due to the effect of reduced
overtime, a slightly higher level of labor charged to construction of utility
plant and a modest decline in employee levels. At September 30, 1994, the
company had 2,545 utility employees, compared to 2,566 at the end of fiscal
year 1993. In 1994, union employees received a 3.75% increase in annual wages.
Depreciation and amortization increased by $3.7 million (9.4%), due to a $2.7
million increase in depreciation on the company's rising investment in plant
and equipment and a $1.0 million increase in amortization of the company's
investment in facilities to serve Pepco. In 1994, capital expenditures totalled
$119.8 million and the composite depreciation rate was unchanged from the 1993
rate of 2.97%.
The composition of the change in general taxes is shown in Note 6 to the
Consolidated Financial Statements. The composition of the change in income tax
expense is detailed in the Consolidated Statement of Income Taxes on page 37.
The company implemented SFAS No. 109, "Accounting for Income Taxes", in
fiscal year 1994. The effect on net income was not material and this matter is
discussed more fully in Note 5 to the Consolidated Financial Statements.
OTHER INCOME (LOSS) - NET
1995 VS. 1994. Other income (loss) - net improved by $2.3 million in 1995. The
increase reflects a $1.9 million after-tax gain recorded on the sale of a
non-utility subsidiary in the first fiscal quarter of 1995. Also contributing
to the improvement was the absence in the current year of reserves associated
with the company's venture capital investments and non-utility operating
companies. Partially offsetting these factors were lower gains recorded from
the sale of non-utility accounts receivable during 1995 and lower earnings from
sales of energy conservation products resulting from the discontinuance of this
business in 1995.
1994 VS. 1993. Other income (loss) - net improved by $2.0 million in 1994.
Greater income associated with the sale of non-utility accounts receivable
combined with a lower provision for uncollectible accounts associated with
these receivables accounted for $1.4 million of the improvement in 1994, net of
income taxes. Reserves recorded in 1994 associated with the company's venture
capital investments and non-utility operating companies amounted to
approximately $3.4 million, net of income taxes, which was equivalent to the
amount of after-tax reserves recorded in the previous year.
INTEREST EXPENSE
1995 VS. 1994. Interest expense declined by $253,000 or .8% in 1995. Interest
expense due customers resulting from lower levels of DSM costs overcollected
from Maryland customers and a lower level of refunds from pipeline companies to
be passed back to customers, caused interest expense to drop $1.5 million.
Interest expense on long-term debt was approximately the same as in 1994 as the
levels of average long-term debt outstanding and the weighted average interest
rates related thereto were virtually unchanged. The company's embedded cost of
long-term debt at September 30, 1995 was 7.7%. Interest on short-term debt rose
by $1.2 million due to an increase in the average amount of short-term debt
outstanding and an increase in the average short-term borrowing rate from 3.39%
in 1994 to 5.77% in 1995.
1994 VS. 1993. Interest expense increased by $3.0 million or 10.4% in 1994. Of
this rise, $1.6 million resulted from an increase in interest due to the
company's customers resulting from refunds received from the pipeline companies
and overcollected DSM expenses from Maryland customers. Interest on long-term
debt rose by $907,000 in 1994 as a result of an approximate $26 million
increase in the average amount of long-term debt outstanding in 1994 which was
partially offset by a drop in the weighted average interest rate on long-term
debt of approximately .3%. The company's embedded cost of long-term debt at
September 30, 1994 was 7.8%. Interest on short-term debt declined by $354,000
due to a sharply lower average amount of such debt outstanding in 1994. The
weighted average interest rate on the company's short-term debt for 1994 was
3.39%, as compared to an average cost of 3.40% for 1993.
LIQUIDITY AND CAPITAL RESOURCES
The company has a goal of maintaining its common equity ratio at approximately
55% of total capital, and a general policy of repaying short-term debt after
the heating season ends in the spring as current assets are converted into
cash. Meeting these goals and maintaining sufficient cash flow are necessary to
preserve the company's credit ratings and to allow access to capital at
relatively low costs. At September 30, 1995, the common equity ratio was 58.9%
of total capitalization.
t w e n t y - s i x
<PAGE> 6
[FIGURE 6 - SEE APPENDIX A]
SHORT-TERM CASH REQUIREMENTS AND
RELATED FINANCING
The company's business is highly weather sensitive and seasonal. In fiscal year
1995, 74% of total therms delivered (excluding deliveries to Pepco for electric
generation) 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 costs 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.
Variations in the timing of collections of gas costs under the company's
purchased gas adjustment provisions and the level of refunds from the pipeline
companies that will be repaid to the company's customers affect short-term cash
requirements. At September 30, 1995, the company had a temporary net
overcollection of gas costs of $29.2 million. Amounts that are under- and over-
collected are reflected in the captions Gas costs due from customers and Gas
costs due to customers in the Consolidated Balance Sheet and most of these
balances will be collected from or returned to customers in fiscal year 1996.
At September 30, 1995, refunds received from pipelines that are to be returned
to the company's customers totalled $10.6 million.
On September 27, 1994, the company placed into effect in the Commonwealth of
Virginia interim rates designed to collect an additional $15.7 million
annually. These rates were collected subject to refund. On September 28, 1995,
the company was granted an increase of $6.8 million, effective September 27,
1994. At September 30, 1995, the company has recorded a provision for a rate
refund of $9.3 million representing the estimated amount expected to be
refunded to customers in Virginia. The amount overcollected will be returned to
customers with interest by January 1, 1996.
As of September 30, 1995, current maturities of long-term debt were $52.5
million. The company anticipates that these maturities will be satisfied with
long-term sources of capital as they become due. The company is currently
authorized to issue up to $110 million of long-term debt and $50 million of
equity securities under an existing shelf registration which expires in January
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 $130 million in a
revolving credit agreement maintained with a group of banks. These financing
options may be activated to support or replace the company's commercial paper.
Additional information regarding the company's short-term borrowing
capabilities is included in Note 2 to the Consolidated Financial Statements.
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 to its service area.
1995
As shown in the table on page 29, capital expenditures totalled $112.7 million
in 1995. New business capital expenditures, including conversions from other
energy sources, totalled $78.9 million, or 70.0% of the total. By the end of
1995, customer meters rose to 750,849, an increase of 24,889, or 3.4% over the
level at the end of 1994.
In 1995, net cash provided by operating activities amounted to $178.2 million,
an increase of $42.5 million over the 1994 level. Factors causing this
increase include: (i) lower accounts receivable balances reflecting the timing
of sales of non-utility receivables to commercial banks in 1995 and lower therm
sales in September 1995; (ii) a greater level of gas costs overcollected and
rate refunds due to customers in the current year, and; (iii) lower payments
made in 1995 related to Federal Energy Regulatory Commission (FERC) Order No.
636 transition costs that are reflected in accounts and wages payable.
Partially offsetting these items was the effect of a reduced level of storage
gas inventory levels due to a smaller decline in the cost of gas than was
experienced in 1994 and increased income tax payments in 1995 resulting from
increased taxable income.
t w e n t y - s e v e n
<PAGE> 7
In 1995, the company issued $40 million of unsecured Medium-Term Notes (MTNs)
at a weighted average interest rate of 7.13%. These notes have 30-year terms
with 10 year put and call options. Maturing MTNs totalled $8.5 million in 1995.
The terms of the company's MTNs and First Mortgage Bonds are discussed in Note
3 to the Consolidated Financial Statements.
During 1995, $13.4 million was raised through the company's Dividend
Reinvestment and Common Stock Purchase Plan (DRP) and Employee Savings Plans.
The sum of net income and noncash charges, less dividends on common and
preferred stock, totalled $68.6 million, representing 60.9% of capital
expenditures.
1994
Capital expenditures totalled $119.8 million in 1994. Of this total, $73.4
million, or 61.3%, was expended for new business, reflecting greater housing
starts in 1994. By the end of 1994, the company had 725,960 customer meters, an
increase of 22,838, or 3.25% over the level at the end of 1993.
In 1994, net cash provided by operating activities amounted to $135.7 million,
an increase of $51.3 million over the 1993 level. The increase resulted
primarily from additional net income, reduced income tax payments because of
greater current deductions for gas costs and the effect of a large drop in the
cost of gas per therm on storage inventory levels. Partially offsetting these
factors was the effect of transition costs paid to pipelines in accordance with
FERC Order No. 636 that had not been collected from ratepayers.
In 1994, the company issued $36.0 million in 30-year unsecured MTNs at an
interest rate of 6.95%. Proceeds from the 1994 issuance were used to retire
$32.675 million of the 9 1/4% Series First Mortgage Bonds due 2018 and pay the
redemption premium applicable thereto. Maturing MTNs in 1994 totalled $18.0
million.
During 1994, $14.0 million was raised through the DRP and Employee Savings
Plans. The sum of net income and noncash charges, less dividends on common and
preferred stock, amounted to $86.4 million in 1994, representing 72.1% of
capital expenditures.
1993
In 1993, capital expenditures totalled $100.8 million. Of this level, $66.8
million, or 66.3% of the total was incurred for new business. By the end of
1993, the company had 703,122 customer meters, an increase of 19,845, or 2.9%
over the level at the end of 1992.
In 1993, net cash provided by operating activities rose $9.0 million from the
1992 level to $84.4 million. Contributing to this improvement was a modest
increase in net income and the positive cash flow effect of a shift from an
undercollection of gas costs at the end of 1992 to an overcollection at the end
of 1993. Partially offsetting these factors in 1993 was an increased outflow
for income taxes due to lower current deductions for gas costs and an increase
in storage gas inventories resulting from greater volumes and prices.
In 1993, the company issued $71.8 million in unsecured MTNs at a weighted
average interest rate of 6.38%. Proceeds from these issuances were used to
retire the remaining $20.0 million of the Adjustable Rate Series First Mortgage
Bonds due December 20, 1997, to purchase and construct fixed assets and for
other general corporate purposes.
During 1993, $16.0 million was raised through the DRP and Employee Savings
Plans. The sum of net income and noncash charges, less dividends on common and
preferred stock, amounted to $60.1 million in 1993, representing 59.7% of
capital expenditures.
NON-UTILITY ACTIVITIES
During 1995, the company augmented cash flow through the sale of $45.1 million
of certain non-utility accounts receivable related to the sale of merchandise.
Similar sales of non-utility accounts receivable in 1994 and 1993 amounted to
$45.0 million and $29.4 million, respectively. In 1995, the company received
$2.0 million in cash as a result of the sale of its American Environmental
Products, Inc. subsidiary.
HISTORICAL AND FUTURE CAPITAL REQUIREMENTS
The amount of maturities and sinking fund requirements on long-term debt for
the ensuing five-year period is included in Note 3 to the Consolidated
Financial Statements.
The company's commercial paper is currently rated A-1+, P-1 and F-1+ by
Standard & Poor's Corporation, Moody's Investors Service and Fitch Investors
Service, Inc., respectively. The company's First Mortgage Bonds are rated AA-,
Aa2, and AA-, by Standard & Poor's Corporation, Moody's Investors Service and
Fitch Investors Service, Inc., respectively. The company's unsecured MTNs are
rated AA-, Aa3, and AA-, by Standard & Poor's Corporation, Moody's Investors
Service and Fitch Investors Service, Inc., respectively.
The company's actual capital expenditures for 1993-1995 and projected capital
expenditures for 1996-2000 are shown on the subsequent page. The company
believes that the combination of available internal and external sources of
funds will be adequate to meet its capital requirements.
t w e n t y - e i g h t
<PAGE> 8
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
(Millions)
Actual Projected
------------------------- -----------------------------------------------------------
1993 1994 1995 1996 1997 1998 1999 2000 Total
- --------------------- ---- ---- ---- ---- ---- ---- ---- ---- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
New Business . . . . $ 66.8 $ 73.4 $ 78.9 $ 79.3 $ 90.9 $ 86.8 $ 90.3 $ 99.3 $446.6
Replacements . . . . 18.8 27.0 25.6 35.1 41.1 40.4 42.0 43.0 201.6
Other . . . . . . . . 15.2 19.4 8.2 15.9 15.9 16.6 15.5 14.9 78.8
------ ------ ------ ------ ------ ------ ------ ------ ------
Total . . . . . . . . $100.8 $119.8 $112.7 $130.3 $147.9 $143.8 $147.8 $157.2 $727.0
====== ====== ====== ====== ====== ====== ====== ====== ======
</TABLE>
OTHER FACTORS AFFECTING THE COMPANY
RATE RELIEF
Requests for rate relief are based on increased investment in plant and
equipment, higher operating expenses and the need to earn an adequate return on
invested capital.
The company made no filings for rate relief in any of its three major
jurisdictions in 1995. However, results of operations in fiscal year 1995
benefitted from rate increases that were granted based on previous rate
filings.
On August 1, 1994, the PSC of DC issued an order approving a Stipulation and
Agreement providing for a $6.4 million increase in annual revenues for the
District of Columbia division effective August 1, 1994. The agreement did not
specify a rate of return. Terms of the agreement provide that the company will
not file for additional rate relief prior to April 1, 1996, and that any
increase in rates cannot be placed into effect in this jurisdiction before
January 1, 1997.
On September 27, 1994, the company placed new rates into effect, subject to
refund, in the Commonwealth of Virginia that were designed to collect an
additional $15.7 million annually, pursuant to a rate filing made on April 29,
1994. In the filing, the company requested, among other items, recovery of the
additional costs associated with implementing the effects of SFAS No. 106 in
accordance with a previously issued generic order by the SCC of VA. On
September 28, 1995, the SCC of VA issued an order approving an increase in
annual revenues of $6.8 million, effective September 27, 1994, which included a
return on equity of 11.50% and an overall rate of return of 9.72%. The order
also allows the company to collect SFAS No. 106 costs in accordance with the
generic order and certain environmental response costs. Amounts associated with
the difference between the interim rates placed into effect on September 27,
1994, and the amount approved by the SCC of VA will be refunded, with interest,
by January 1, 1996.
In the State of Maryland, increased rates designed to collect an additional
$7.4 million in annual revenues were placed into effect on December 1, 1994,
pursuant to an order issued by the PSC of MD on October 18, 1994. The increased
rates apply to the company's Maryland division and Frederick Gas Company, Inc.
subsidiary. This order resulted from an unopposed Stipulation and Agreement
signed by a majority of the parties to the case, which had been filed on June
1, 1994.
COMPETITION AND CHANGE IN THE NATURAL GAS DISTRIBUTION INDUSTRY
The company has historically faced competitive pressures from other energy
sources and is beginning to experience new competitive pressures within the gas
industry and as a result of changes taking place in the electric industry.
The most significant competition the company faces continues to be between
natural gas and electricity in the residential market, which contributes the
most significant portion of the company's net income. The company currently
maintains a price advantage over electricity in all of the jurisdictions it
serves. The company continues to derive the majority share of the new
residential construction market and believes customer preference for natural
gas and a competitive price will allow the company to maintain its strong
presence. In the interruptible market, fuel oil is the most significant
competing energy alternative for this class of customer. The company's success
in this market is largely dependent on changes in the price of gas vis-a-vis
changes in the price of fuel oil.
The movement for deregulating natural gas and increasing competition in the
industry has been evolving since the passage of the Natural Gas Policy Act of
1978, which brought about a gradual decontrol of the wellhead price of natural
gas and allowed for market-based prices. At the Federal regulatory level the
trend toward deregulation continued throughout the 1980s and substantially
culminated in the implementation of FERC Order No. 636 in November 1993. This
order removed the merchant function from the pipelines that serve local
distribution companies (LDCs) such as the company. The pipelines have become
providers of storage and transportation services and LDCs have assumed the
responsibility for procuring satisfactory gas supplies and pipeline capacity
levels.
Recently, regulatory initiatives have begun in several states to further extend
competition to the consumer. Proposals have included market-based performance
standards for gas cost recovery by LDCs, a greater focus on incentive
regulation, and "unbundling" of the services currently provided by LDCs.
Unbundling is expected to increase competition among providers and
t w e n t y - n i n e
<PAGE> 9
offer choices to consumers for those services that can be separated and priced
individually. Such services can include sales of gas and servicing consumer
appliances. In unbundling situations, the company will continue to offer
delivery service for the transportation of natural gas on its distribution
system. The company's customer base and its location in relation to pipelines
make it less susceptible to the risk of bypass on its system than other
companies.
In the company's service area, unbundled service has begun in the state of
Maryland. The PSC of MD has approved company tariffs that became effective
September 1, 1995, whereby all interruptible customers in Maryland became
delivery service customers and must elect whether to buy gas from the company
or third-party suppliers such as marketers or other gas companies. The company
still provides delivery service to transport gas through the distribution
system to the customer. New delivery service tariffs for certain firm group
metered apartments and commercial customers became effective on November 1,
1995, and a residential delivery service pilot program is expected to be
implemented in late 1996. If the unbundled sale of the gas commodity is no
longer regulated at the LDC level, the ability of the company to compete
successfully and take advantage of the potential opportunity to increase its
profitability will be dependent upon, among other factors, the competitiveness
of its gas supplies and capacity.
Regulatory filings addressing unbundling issues in the District of Columbia and
Virginia jurisdictions are likely to be filed in the near future. The company
will continue to be proactive in its approach to shaping the transition from
traditional ratemaking concepts to new concepts that incorporate competition
and customer choice.
Changes in the electric industry have implications for the gas industry. The
National Energy Policy Act of 1992 allows unregulated independent power
producers to sell power to wholesale customers in competition with regulated
electric utilities. The FERC has proposed to require jurisdictional electric
utilities to offer nondiscriminatory open access transmission and ancillary
services to eligible customers comparable to the service they provide at the
wholesale level. Merger and acquisition activity in the electric industry has
increased, including a proposal for a merger in 1997 of two neighboring
utilities to the company, Baltimore Gas and Electric Company and Potomac
Electric Power Company. Events such as these should reduce electricity costs
and cause competition to intensify.
The company accounts for the regulated activities in which it is engaged 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 subject to the impact of
deregulation and the attendant effects that it brings, the company may not be
able 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 expensing of costs previously
deferred as regulatory assets in the Consolidated Balance Sheet. The
composition of regulatory assets is shown in Note 1 to the Consolidated
Financial Statements.
GAS SUPPLY AND CAPACITY
Since the FERC implemented Order No. 636 in November 1993, the company has been
responsible for purchasing its own gas supplies from producers and marketers,
and arranging for the delivery of these gas supplies using the transportation
and storage capacity rendered by the interstate pipelines.
The company must assure that it has sufficient gas supply and delivery capacity
to meet its obligations to serve its customers under all weather conditions. At
the same time, and considering the continuing trend toward unbundling the
traditional merchant function of the distribution company to procure natural
gas and related capacity on behalf of its retail customers, the company must
assure that it only commits to supply and capacity levels that it believes 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 15 long-term gas supply contracts with various producers or
marketers which expire between 1997 and 2003 and under which the company can
purchase up to 112 million dekatherms of natural gas per year. Any supplies not
acquired under these long-term contracts are acquired under seasonal contracts
or from short-term purchases on the spot market. In fiscal year 1995, supplies
were acquired from a combination of 49 producers or marketers including volumes
acquired under the 15 contracts discussed above.
Of the anticipated annual sendout, 80.0% is expected to be delivered through
firm transportation, 18.0% will be delivered from transportation storage and
the remainder will be supplied by company owned peak shaving facilities or
other peak shaving sources. The company has contracts for firm storage and
transportation services with three pipeline suppliers which connect directly to
the company's distribution system and four other upstream pipelines. The
company pays fixed charges to these direct and upstream pipeline suppliers for
the services they provide under contracts with termination dates as early as
1997 and as late as 2013.
t h i r t y
<PAGE> 10
The cost of natural gas and pipeline services supplied under the contracts
previously described are included in purchased gas costs and recoverable in the
rates the company charges its customers, subject to regulatory review. See Note
11 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 9 to
the Consolidated Financial Statements.
ENVIRONMENTAL MATTERS
The company and its subsidiaries are subject to various laws related to
environmental matters, as discussed in Note 10 to the Consolidated Financial
Statements.
LABOR MATTERS
On April 7, 1995, the approximately 500 members of the Office and Professional
Employees International Union (Local 2) voted to ratify a new labor agreement
with the company. The agreement is for five years, provides for a lump sum
payment of 2.25% of base pay on April 1, 1996, and allows Local 2 employees the
opportunity to earn annual cash incentives beginning in the third year based on
the company meeting certain financial goals.
On May 31, 1995, a three year labor agreement between the parent company and
the approximately 1,050 member bargaining unit of the International Union of
Gas Workers (IUGW) expired. These workers represent approximately 44% of the
company's work force.
On May 25, 1995, following two months of contract negotiations, the union
membership voted to give its leadership authority to strike. Faced with this
potential for a strike and the company's responsibility to provide
uninterrupted natural gas service to its customers, on June 10, 1995, the
company exercised its rights under Federal labor laws by locking out the IUGW
bargaining unit after agreeing to three contract extensions.
During the lockout, the company made two good faith offers as part of its
bargaining process but the membership of the IUGW voted three times to reject
these offers. On September 25, 1995, after negotiations between the company and
the IUGW had reached an impasse, the company installed the terms of its August
28, 1995 final contract offer. The bargaining unit was invited to return to
work on September 27, 1995. The vast majority of IUGW-eligible employees did
return to work on that date, and all were back within two weeks.
As of November 21, 1995, there was no signed contract in effect between the
company and IUGW. Accordingly, the no strike/no lockout provision, usually
included in a collective bargaining agreement, is not in effect and no
assurance can be given that work stoppages may not occur. In the event a work
stoppage occurs during the heating season of 1995/1996, the company is prepared
to maintain operations.
INFLATION
To help cope with the effects of inflation on its capital investment and
returns, the company seeks rate relief 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.
<TABLE>
<CAPTION>
SUMMARY OF RATE APPLICATIONS AND RESULTS Increase in
Annual Revenues
------------------------
Amount Amount Allowed
Effective Test Year Requested Granted Return on
Jurisdiction Date 12 Mos. Ended (Millions) (Millions) Common Equity
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Virginia . . . . . . . . . . . . . 4/5/89 12/31/88 $ 9 .1 $ 8.5 13.00%
Maryland . . . . . . . . . . . . . 8/23/89 4/30/89 16.5 7.9 12.80
District of Columbia . . . . . . . 6/1/90 5/31/89 17.2 4.5 a/
Virginia . . . . . . . . . . . . . 7/6/90 3/31/90 7 .7 7.1 13.00
Maryland . . . . . . . . . . . . . 8/1/93 12/31/92 26.2 10.6 b/
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 a/
Virginia . . . . . . . . . . . . . 9/27/94 12/31/93 15.7 6.8 11.50
Maryland . . . . . . . . . . . . . 12/1/94 3/31/94 17.6 7.4 b/
</TABLE>
a/ Application was settled without stipulating the return on common equity.
b/ 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.
t h i r t y - o n e
<PAGE> 11
CONSOLIDATED STATEMENT OF INCOME
Washington Gas Light Company
Years Ended September 30
<TABLE>
<CAPTION>
1995 1994 1993
- ---------------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . $828,748 $914,863 $894,300
Cost of Gas . . . . . . . . . . . . . . . . . . . . . . . 390,041 462,195 478,982
-------- -------- --------
NET REVENUES . . . . . . . . . . . . . . . . . . . . . . 438,707 452,668 415,318
-------- -------- --------
OTHER OPERATING EXPENSES
Operation . . . . . . . . . . . . . . . . . . . . . . 163,518 171,612 151,799
Maintenance . . . . . . . . . . . . . . . . . . . . . 31,268 35,789 33,452
Depreciation and amortization . . . . . . . . . . . . 46,385 43,494 39,766
General taxes (Note 6) . . . . . . . . . . . . . . . . 67,829 72,177 69,738
Income taxes (See Statement and Note 5) . . . . . . . 37,514 37,264 34,601
-------- -------- --------
346,514 360,336 329,356
-------- -------- --------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . 92,193 92,332 85,962
Other Income (Loss)-Net (Note 7) . . . . . . . . . . . . 2,610 274 (1,774)
-------- -------- --------
INCOME BEFORE INTEREST EXPENSE . . . . . . . . . . . . . 94,803 92,606 84,188
Interest Expense . . . . . . . . . . . . . . . . . . . . 31,894 32,147 29,109
-------- -------- --------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 62,909 60,459 55,079
Dividends on Preferred Stock . . . . . . . . . . . . . . 1,333 1,335 1,336
-------- -------- --------
NET INCOME APPLICABLE TO COMMON STOCK . . . . . . . . . $ 61,576 $ 59,124 $ 53,743
======== ======== ========
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 42,575 41,835 41,043
======== ======== ========
EARNINGS PER AVERAGE SHARE OF COMMON STOCK . . . . . . . $ 1.45 $ 1.41 $ 1.31
======== ======== ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - t w o
<PAGE> 12
CONSOLIDATED BALANCE SHEET
Washington Gas Light Company
September 30
<TABLE>
<CAPTION>
1995 1994
- -----------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
At original cost . . . . . . . . . . . . . . . . . . . . . . $1,608,518 $1,516,201
Accumulated depreciation and amortization . . . . . . . . . (552,460) (521,180)
---------- ----------
1,056,058 995,021
---------- ----------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . 13,911 3,522
Accounts receivable . . . . . . . . . . . . . . . . . . . . 41,528 60,682
Gas costs due from customers . . . . . . . . . . . . . . . . 692 3,790
Allowance for doubtful accounts . . . . . . . . . . . . . . (10,580) (11,300)
Accrued utility revenues . . . . . . . . . . . . . . . . . . 18,323 21,582
Materials and supplies-principally at average cost . . . . . 14,296 14,991
Storage gas-at cost (first-in, first-out) . . . . . . . . . 53,361 59,967
Deferred income taxes (See Statement and Note 5) . . . . . . 19,710 14,369
Other prepayments, principally taxes . . . . . . . . . . . . 7,799 7,842
---------- ----------
159,040 175,445
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS (Note 1) . . . . . . . . . . 145,040 162,488
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . $1,360,138 $1,332,954
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statement)
Common shareholders' equity . . . . . . . . . . . . . . . . $ 513,044 $ 485,504
Preferred stock . . . . . . . . . . . . . . . . . . . . . . 28,471 28,498
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . 329,051 342,270
---------- ----------
870,566 856,272
---------- ----------
CURRENT LIABILITIES
Current maturities (Note 3) . . . . . . . . . . . . . . . . 52,505 8,560
Notes payable (Note 2) . . . . . . . . . . . . . . . . . . . -- 52,912
Accounts and wages payable . . . . . . . . . . . . . . . . . 80,523 84,961
Dividends declared . . . . . . . . . . . . . . . . . . . . . 12,353 12,045
Customer deposits and advance payments . . . . . . . . . . . 15,408 15,741
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . 6,253 9,647
Accrued interest . . . . . . . . . . . . . . . . . . . . . . 5,577 5,524
Pipeline refunds due to customers . . . . . . . . . . . . . 10,560 7,572
Gas costs due to customers . . . . . . . . . . . . . . . . . 29,871 3,961
Rate refund due to customers . . . . . . . . . . . . . . . . 9,306 --
---------- ----------
222,356 200,923
---------- ----------
DEFERRED CREDITS
Unamortized investment tax credits . . . . . . . . . . . . . 23,353 24,345
Deferred income taxes (See Statement and Note 5) . . . . . . 121,157 116,046
Other . . . . . . . . . . . . . . . . . . . . . . . . . 122,706 135,368
---------- ----------
267,216 275,759
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 9, 10, and 11)
Total . . . . . . . . . . . . . . . . . . . . . . . $1,360,138 $1,332,954
========== ==========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - t h r e e
<PAGE> 13
CONSOLIDATED STATEMENT OF CASH FLOWS
Washington Gas Light Company
Years Ended September 30
<TABLE>
<CAPTION>
1995 1994 1993
- ----------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 62,909 $ 60,459 $ 55,079
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization (a) . . . . . . . . . . . . 52,329 49,029 42,689
Deferred income taxes-net . . . . . . . . . . . . . . . . 2,036 13,277 1,701
Amortization of investment tax credits . . . . . . . . . . (992) (1,014) (1,034)
Allowance for funds used during construction . . . . . . . (443) (200) (19)
Other noncash charges and credits-net . . . . . . . . . . 1,519 12,937 6,555
---------- ----------- -----------
117,358 134,488 104,971
Changes in assets and liabilities:
Accounts receivable and accrued utility revenues . . . . . 21,693 4,764 (12,972)
Gas costs due from/to customers-net . . . . . . . . . . . 29,008 (4,243) 16,732
Storage and prepaid gas costs . . . . . . . . . . . . . . 6,606 16,187 (22,775)
Other prepayments, principally taxes . . . . . . . . . . . 43 (1,752) (1,092)
Accounts and wages payable . . . . . . . . . . . . . . . . (7,954) (27,930) 9,174
Customer deposits and advance payments . . . . . . . . . . (333) (382) 629
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . (3,394) 3,925 (1,018)
Pipeline refunds due to customers . . . . . . . . . . . . 2,988 5,717 (2,610)
Rate refund due to customers . . . . . . . . . . . . . . . 9,306 -- --
Deferred purchased gas costs . . . . . . . . . . . . . . . (2,625) 3,046 (2,636)
Other-net . . . . . . . . . . . . . . . . . . . . . . . . 5,492 1,909 (3,984)
---------- ----------- -----------
Net Cash Provided by Operating Activities . . . . . . . 178,188 135,729 84,419
---------- ----------- -----------
FINANCING ACTIVITIES
Common stock issued . . . . . . . . . . . . . . . . . . . . . . 13,368 14,027 16,028
Long-term debt issued . . . . . . . . . . . . . . . . . . . . . 40,000 36,000 71,800
Long-term debt retired . . . . . . . . . . . . . . . . . . . . (9,322) (50,719) (20,632)
Notes payable . . . . . . . . . . . . . . . . . . . . . . . . . (52,912) 31,458 (5,481)
Dividends on common and preferred stock . . . . . . . . . . . . (48,731) (48,042) (44,842)
---------- ----------- -----------
Net Cash Provided by (Used in) Financing Activities . . . . (57,597) (17,276) 16,873
---------- ----------- -----------
INVESTING ACTIVITIES
Proceeds from sale of non-utility subsidiary . . . . . . . . . 2,000 -- --
Capital expenditures . . . . . . . . . . . . . . . . . . . . . (112,715) (119,796) (100,778)
Other investing activities . . . . . . . . . . . . . . . . . . 513 -- 1,146
---------- ----------- -----------
Net Cash Used in Investing Activities . . . . . . . . . . . (110,202) (119,796) (99,632)
---------- ----------- -----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . 10,389 (1,343) 1,660
Cash and Cash Equivalents at Beginning of Year . . . . . . . . 3,522 4,865 3,205
---------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR . . . . . . . . . . . $ 13,911 $ 3,522 $ 4,865
========== =========== ===========
</TABLE>
(a) Includes amounts charged to other accounts.
- -------------------------------------------------------------------------------
Cash equivalents are highly liquid investments with a maturity of three months
or less when purchased.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
<TABLE>
<S> <C> <C> <C>
Income taxes paid . . . . . . . . . . . . . . . . . . . . . $ 38,824 $ 22,334 $ 33,261
Interest paid . . . . . . . . . . . . . . . . . . . . . . . $ 30,879 $ 31,345 $ 28,238
- --------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - f o u r
<PAGE> 14
CONSOLIDATED STATEMENT OF CAPITALIZATION
Washington Gas Light Company
September 30
<TABLE>
<CAPTION>
1995 1994
- ---------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY (SEE STATEMENT)
Common stock, $1 par value, authorized
80,000,000 shares, issued 42,944,831
and 42,208,476 shares (Note 4) . . . . . . . . . . . . $ 42,945 $42,208
Paid-in capital . . . . . . . . . . . . . . . . . . . . . 289,285 276,729
Retained earnings . . . . . . . . . . . . . . . . . . . . 182,733 168,863
Deferred compensation . . . . . . . . . . . . . . . . . . (1,680) (1,854)
Treasury stock-at cost, 12,868 and 21,854 shares. . . . . (239) (442)
-------- --------
Total Common Shareholders' Equity . . . . . . . 513,044 58.9% 485,504 56.7%
-------- ----- -------- -----
PREFERRED STOCK WITHOUT PAR VALUE,
authorized 1,500,000 shares, 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, 2,348 and 2,549 shares . . . 235 255
$4.60 convertible series, 635 and 702 shares . . . . . 63 70
-------- --------
Total Preferred Stock . . . . . . . . . . . . . 28,471 3.3 28,498 3.3
-------- ----- -------- -----
LONG-TERM DEBT (Note 3)
First mortgage bonds
7 7/8% series due September 1, 2016 . . . . . . . . 50,000 50,000
8 5/8% series due March 1, 2017 . . . . . . . . . . . 35,500 35,500
9 1/4% series due April 15, 2018 . . . . . . . . . . . 17,325 17,325
8 3/4% series due July 1, 2019 . . . . . . . . . . . 50,000 50,000
-------- --------
152,825 152,825
-------- --------
Unsecured medium-term notes
Due fiscal year 1995, 4.80% to 5.38% . . . . . . . . . -- 8,500
Due fiscal year 1996, 4.57% . . . . . . . . . . . . . 2,500 2,500
Due fiscal year 1997, 6.50% to 6.58% . . . . . . . . . 8,000 8,000
Due fiscal year 1998, 6.43% to 8.00% . . . . . . . . . 15,800 15,800
Due fiscal year 1999, 6.50% to 7.97% . . . . . . . . . 21,700 21,700
Due fiscal year 2002, 6.90% to 7.56% . . . . . . . . . 45,600 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% . . . . . . . . . 30,000 30,000
Due fiscal year 2024, 6.95% . . . . . . . . . . . . . 36,000 36,000
Due fiscal year 2025, 6.50% to 7.76% . . . . . . . . . 40,000 --
-------- --------
229,700 198,200
-------- --------
Other long-term debt . . . . . . . . . . . . . . . . . . 201 1,023
Unamortized premium and (discount)-net . . . . . . . . . (1,170) (1,218)
-------- --------
Total long-term debt . . . . . . . . . . . . . . . . . . 381,556 350,830
-------- --------
Less current maturities . . . . . . . . . . . . . . . . 52,505 8,560
-------- --------
Long-Term Debt . . . . . . . . . . . . . . . . . 329,051 37.8 342,270 40.0
-------- ----- -------- -----
$870,566 100.0% $856,272 100.0%
======== ===== ======== =====
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - f i v e
<PAGE> 15
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
Washington Gas Light Company
<TABLE>
<CAPTION>
Common Stock Issued
--------------------- Paid-in Deferred Treasury Retained
Shares Amount Capital Compensation Stock Earnings
-------- ------ --------- ------------ -------- --------
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SEPTEMBER 30, 1992 . . . . . . 40,703,762 $40,704 $247,210 $ (647) $(1,195) $147,049
Net income . . . . . . . . . . . . . 55,079
Common stock expense . . . . . . . . (18)
Purchase of shares . . . . . . . . . (615)
Deferred compensation . . . . . . . 913 (2,054) 1,597
Dividend reinvestment plan . . . . . 596,412 596 11,386
Employee savings plans . . . . . . . 201,196 200 3,846
Conversion of preferred stock . . . 3,418 4 27
Dividends declared:
Common stock ($1.085 per share) . . (44,702)
Preferred stock . . . . . . . . . (1,336)
---------- ------- -------- -------- -------- -------
BALANCE SEPTEMBER 30, 1993 . . . . . . 41,504,788 41,504 263,364 (2,701) (213) 156,090
Net income . . . . . . . . . . . . . 60,459
Deferred compensation . . . . . . . . 21 847 (229)
Dividend reinvestment plan . . . . . 539,108 540 10,244
Employee savings plans . . . . . . . 162,226 162 3,081
Conversion of preferred stock . . . 2,354 2 19
Dividends declared:
Common stock ($1.105 per share) . . (46,351)
Preferred stock . . . . . . . . . (1,335)
---------- ------- -------- -------- -------- -------
BALANCE SEPTEMBER 30, 1994 . . . . . . 42,208,476 42,208 276,729 (1,854) (442) 168,863
Net income . . . . . . . . . . . . . 62,909
Common stock expense . . . . . . . . (18)
Deferred compensation . . . . . . . (83) 174 203
Dividend reinvestment plan . . . . . 596,140 596 10,264
Employee savings plans . . . . . . . 137,372 138 2,370
Conversion of preferred stock . . . 2,843 3 23
Dividends declared:
Common stock ($1.1175 per share). . (47,706)
Preferred stock . . . . . . . . . (1,333)
---------- ------- -------- -------- -------- -------
BALANCE SEPTEMBER 30, 1995 . . . . . . 42,944,831 $42,945 $289,285 $ (1,680) $ (239) $182,733
========== ======= ======== ======== ======== ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - s i x
<PAGE> 16
CONSOLIDATED STATEMENT OF INCOME TAXES
Washington Gas Light Company
<TABLE>
<CAPTION>
1995 1994 1993
- -------------------------------------------------------------------------------------------------------------
Years Ended September 30 (Dollars in Thousands)
<S> <C> <C> <C>
INCOME TAX EXPENSE (Note 5)
Charged to other operating expenses
Current . . . . . . . . . . . . . . . . . . . . . . $35,598 $24,637 $32,751
------- ------- -------
Deferred
Accelerated depreciation . . . . . . . . . . . . 10,215 10,254 9,564
Losses/gains on reacquired debt . . . . . . . . (469) 1,662 (91)
Deferred gas costs . . . . . . . . . . . . . . (4,450) 4,255 (5,161)
Pensions and other employee benefit costs . . . 214 (2,077) (429)
Demand side management costs . . . . . . . . . . 1,976 155 (518)
Inventory overheads . . . . . . . . . . . . . . (3,126) 48 225
Other . . . . . . . . . . . . . . . . . . . . . (1,452) (656) (706)
------- ------- -------
Total Deferred Income Tax Expense . . . . . . 2,908 13,641 2,884
------- ------- -------
Amortization of investment tax credits . . . . . . (992) (1,014) (1,034)
------- ------- -------
37,514 37,264 34,601
------- ------- -------
Charged to other income (loss)-net
Current . . . . . . . . . . . . . . . . . . . . . . 142 690 (296)
Deferred . . . . . . . . . . . . . . . . . . . . . (872) (364) (1,183)
------- ------- -------
(730) 326 (1,479)
------- ------- -------
Total Income Tax Expense . . . . . . . . . . $36,784 $37,590 $33,122
======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
RECONCILIATION BETWEEN THE STATUTORY FEDERAL
INCOME TAX RATE AND THE EFFECTIVE TAX RATE
<S> <C> <C> <C> <C> <C> <C>
Income tax at statutory Federal income tax rate . . . . . . $34,893 35.00% $34,317 35.00% $30,650 34.75%
------- ----- ------- ----- ------- -----
Increases (decreases) in tax resulting from
Accelerated depreciation less amount deferred . . . . . 2,837 2.85 2,195 2.24 1,800 2.04
Amortization of investment tax credits . . . . . . . . . (992) (1.00) (1,014) (1.03) (1,034) (1.17)
Cost of removal . . . . . . . . . . . . . . . . . . . . (488) (.49) (435) (.44) (322) (.37)
State income taxes . . . . . . . . . . . . . . . . . . . 2,112 2.12 1,892 1.93 1,796 2.04
Other items-net . . . . . . . . . . . . . . . . . . . . (1,578) (1.58) 635 .64 232 .26
------- ----- ------- ----- ------- -----
Income Tax Expense and Effective Tax Rate . . . . . . . . . $36,784 36.90% $37,590 38.34% $33,122 37.55%
======= ===== ======= ===== ======= =====
</TABLE>
<TABLE>
<CAPTION>
1995 1994
----------------------------- -------------------------------
ACCUMULATED DEFERRED INCOME TAXES AT SEPTEMBER 30 Current Non-current Current Non-current
---------- ------------- ---------- -----------
<S> <C> <C> <C> <C>
Deferred tax assets
Pensions and other employee benefit costs . . . $ 5,623 $ 6,202 $ 6,148 $ 5,913
Uncollectible accounts . . . . . . . . . . . . . 2,703 -- 2,879 --
Inventory overheads . . . . . . . . . . . . . . 5,165 -- 1,844 --
Other . . . . . . . . . . . . . . . . . . . . . 991 12,905 853 11,835
Valuation allowance . . . . . . . . . . . . . . -- (2,470) -- (3,352)
-------- --------- --------- --------
Total Assets . . . . . . . . . . . . . . . . $ 14,482 $ 16,637 $ 11,724 $ 14,396
-------- --------- --------- --------
Deferred tax liabilities
Accelerated depreciation . . . . . . . . . . . . $ -- $ 100,381 $ -- $ 90,205
Losses/gains on reacquired debt . . . . . . . . -- 3,046 -- 3,537
Construction overheads . . . . . . . . . . . . . -- 3,246 -- 3,412
Income taxes recoverable through future rates . -- 20,267 -- 22,545
Deferred gas costs . . . . . . . . . . . . . . . (5,228) 1,682 (2,645) 3,353
Demand side management costs . . . . . . . . . . -- 7,196 -- 4,994
Other . . . . . . . . . . . . . . . . . . . . . -- 1,976 -- 2,396
-------- --------- --------- --------
Total Liabilities . . . . . . . . . . . . . . $ (5,228) $ 137,794 $ (2,645) $ 130,442
-------- --------- --------- --------
Total Accumulated Deferred Income Taxes . . . $ 19,710 $(121,157) $ 14,369 $(116,046)
======== ========= ========= ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of this statement.
t h i r t y - s e v e n
<PAGE> 17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Washington Gas Light Company
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 through
three divisions and two distribution subsidiaries. The company's three
jurisdictional divisions are located in the District of Columbia, Maryland and
Virginia. Portions of West Virginia are served by one of the company's
distribution subsidiaries. An additional subsidiary operates an underground
storage field on behalf of the company. As of September 30, 1995, the company
and its distribution subsidiaries served almost 751,000 customer meters. Therms
delivered to firm customers accounted for 69% of the company's total therms
delivered in fiscal year 1995, and the company is not dependent on one customer
or group of customers. The company's non-utility operations are insignificant.
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 ratesetting 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. 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 it is determined that an asset is no longer probable
of recovery, the asset would be written off against income.
The amounts recorded as regulatory assets and regulatory liabilities in the
Consolidated Balance Sheet at September 30, 1995 and 1994 follow.
<TABLE>
<CAPTION>
1995 1994
-------- ----------
REGULATORY ASSETS: (Millions)
<S> <C> <C>
Income tax-related amounts
due from customers
(Note 5) . . . . . . . . . . . . . $ 43.8 $ 46.6
Demand side management
costs due from customers . . . . . 22.0 20.9
Order 636 transition costs
due from customers
(Note 9) . . . . . . . . . . . . . 17.8 37.1
Environmental response
costs (Note 10) . . . . . . . . . 14.3 12.4
Other postretirement benefit
costs (Note 8) . . . . . . . . . . 10.5 6.7
Losses on reacquired debt . . . . . . 7.6 8.7
Purchased gas costs . . . . . . . . . 4.6 1.9
Gas costs due from customers . . . . .7 3.8
Other . . . . . . . . . . . . . . . . 1.2 2.3
-------- ---------
$ 122.5 $ 140.4
======== =========
</TABLE>
<TABLE>
<CAPTION>
1995 1994
-------- ----------
REGULATORY LIABILITIES: (Millions)
<S> <C> <C>
Refunds due to customers . . . . . . $ 33.7 $ 22.6
Gas costs due to customers . . . . . 29.9 4.0
Income tax-related amounts
due to customers . . . . . . . . . 23.5 24.1
Demand side management
costs due to customers . . . . . . 2.6 7.9
Other . . . . . . . . . . . . . . . . 2.3 2.4
-------- ---------
$ 92.0 $ 61.0
======== =========
</TABLE>
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at original cost including labor,
materials, taxes and overheads. An Allowance for Funds Used During Construction
(AFUDC) is capitalized as a component of the construction overheads. The amount
of AFUDC capitalized in 1995, 1994 and 1993 was $443,000, $200,000 and $19,000,
respectively.
t h i r t y - e i g h t
<PAGE> 18
The original cost of depreciable units of plant retired, together with the cost
of removal, net of salvage, is charged 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 rate was 2.97% for 1995, 1994 and 1993.
The adequacy of the company's depreciation rates is periodically reviewed
considering estimated remaining lives and other factors.
REVENUES
Customer meters are read and bills are rendered on a cycle basis. Revenues from
gas delivered but not yet billed are accrued.
COST OF GAS
The company has a purchased gas adjustment clause in each jurisdiction which
provides for the adjustment of rates charged to firm customers as gas costs
rise or fall from a stipulated base gas cost. Moreover, each jurisdiction in
which the company operates provides for an annual reconciliation of total gas
costs billed to firm customers with the actual cost of gas recorded in the
accounts. Any excess or deficiency is deferred and the deferred balance is
recovered from or refunded to customers over a subsequent twelve-month period.
The amounts related to these reconciliations are reflected in the captions Gas
costs due from customers and Gas costs due to customers.
PROVISION FOR RATE REFUNDS
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.
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. No gains or losses were realized in 1995. Losses realized and
deferred were $6.2 million in 1994 and $0.8 million in 1993. For income tax
purposes, gains and losses are recognized currently.
NEW ACCOUNTING STANDARD
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of " (SFAS No. 121).
SFAS No. 121 establishes accounting standards for the impairment of long-lived
assets and also requires that regulatory assets which are no longer probable of
recovery through future revenues be charged to earnings. Since the company's
policy was identical to the policy prescribed by SFAS No. 121, implementation
of this standard in 1995 had no effect on the company.
2. SHORT-TERM DEBT
The company's short-term financing requirements are satisfied 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.
As of September 30, 1995, the company had permanent bank lines of credit
available of $20 million, all of which were unused. In support of the
permanent lines, the company pays commitment or non-usage fees of .07% per
annum of the unused lines. Of these lines, $15 million expire on June 30, 1996
with the remaining $5 million expiring on June 30, 1998. The company has $20
million of additional bank lines of credit which are temporary lines that are
available during the heating season and for which no compensation is paid
unless activated. The temporary lines became available in September and
October 1995. Of these lines, $5 million will expire on April 1, 1996 and $15
million will expire on April 30, 1996.
As of September 30, 1995, the company had a short-term revolving credit
agreement with a group of banks that allows the company to borrow up to $130
million. The company pays facility fees of .07% per annum on the daily average
amount of the commitment. The amount of the commitment can be reduced at the
option of the company. The agreement, which expires on May 24, 1996, allows for
annual extension by mutual agreement in each of the next four consecutive
years.
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.
As of September 30, 1995, the company had no short-term debt outstanding,
excluding current maturities. As of September 30, 1994, the company had $52.9
million in short-term debt outstanding, excluding current maturities, at a
weighted average cost of 5.05%.
3. LONG-TERM DEBT
FIRST MORTGAGE BONDS
The company's Mortgage dated January 1, 1933 (Mortgage), as supplemented and
amended, securing the First Mortgage Bonds issued by the company, constitutes a
direct lien on substantially all property and franchises owned by the company
other than expressly excepted property.
t h i r t y - n i n e
<PAGE> 19
UNSECURED MEDIUM-TERM NOTES
The company issues unsecured Medium-Term Notes (MTNs) which 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
will not issue any First Mortgage Bonds under its Mortgage in addition to the
First Mortgage Bonds that were outstanding on September 1, 1993, without making
effective provision whereby the unsecured MTNs shall be secured by the First
Mortgage equally and ratably with any and all other obligations and
indebtedness thereby secured.
During 1995, the company issued $40 million in MTNs due in fiscal year 2025
with 10 year put and call options. Of these notes, $10 million were issued at
an interest rate of 7.76%, $10 million were issued at a rate of 7.75% and $20
million were issued at a rate of 6.50%. At September 30, 1995 and 1994, the
weighted average interest rate on all outstanding MTNs was 7.04% and 6.94%,
respectively.
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, 1995 is $52.5 million in 1996,
$8.0 million in 1997, $35.1 million in 1998, $73.7 million in 1999 and $2.0
million in 2000.
4. COMMON STOCK
On May 1, 1995, additional shares of common stock were distributed to
shareholders of record on April 20, 1995 in connection with a two-for-one stock
split. All share disclosures and per share calculations included in these
financial statements are on a post-split basis and amounts associated with
common stock of prior years have been adjusted to reflect this effect.
At September 30, 1995, there were 2,080,473 authorized but unissued shares of
Common Stock reserved for the Dividend Reinvestment and Common Stock Purchase
Plan, for conversion of Convertible Preferred Stock and as an investment
alternative in the company's qualified Employee Savings Plans.
In connection with a Long-Term Incentive Compensation Plan (LTICP), 800,000
shares of Common Stock were reserved for various awards that can be granted
thereunder and 530,900 shares remain reserved for potential future awards under
the LTICP at September 30, 1995. During 1995 and 1993, 17,500 and 121,500
shares of stock, respectively, previously held in the Treasury were granted
with restrictions to certain employees under the LTICP. No shares were granted
under the LTICP in 1994. The restrictions lapse with the passage of time and
the expense, amounting to $497,000, $847,000, and $630,000 in 1995, 1994 and
1993, respectively, is being recognized ratably over the periods during which
the restrictions lapse.
Shares of Common Stock outstanding, net of Treasury shares, were 42,931,963,
42,186,622 and 41,494,936 as of September 30, 1995, 1994 and 1993,
respectively.
5. 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,
1991 have been reviewed and closed or closed without review by the Internal
Revenue Service.
Investment tax credits which were deferred because of regulatory requirements
are being amortized as credits to income over the estimated service lives of
the related properties.
Effective October 1, 1993, the company adopted 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 requires recognition of the additional deferred income tax assets
and liabilities for timing differences for which deferred income tax treatment
has been prohibited for ratemaking purposes. Regulatory assets or liabilities
corresponding to such additional deferred tax assets or liabilities may be
recorded to the extent it is believed they will be recoverable from or be
payable to customers through the ratemaking process.
The effect of the implementation of SFAS No. 109 on the company's net income
was immaterial because the company established a regulatory asset and liability
as described above. The company's regulatory assets and liabilities associated
with income taxes due from and to customers, respectively, as of September 30,
1995 and 1994, are shown in Note 1 to the Consolidated Financial Statements.
The Consolidated Statement of Income Taxes on page 37 shows current and
deferred 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, 1995 and 1994.
f o r t y
<PAGE> 20
6. GENERAL TAXES
The company is subject to significant taxes which are not related to income.
The amount of such general taxes recorded in the financial statements for the
last three years is detailed below.
<TABLE>
<CAPTION>
Years Ended September 30 1995 1994 1993
- --------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Charged to operating expenses
Gross receipts . . . . . . $44.6 $49.2 $48.3
Property . . . . . . . . . 15.1 13.8 12.9
Payroll . . . . . . . . . . 7.0 8.0 7.9
Other . . . . . . . . . . . 1.1 1.2 .6
----- ----- -----
67.8 72.2 69.7
----- ----- -----
Charged to other income
(loss)-net . . . . . . . . .3 .4 .4
Charged to construction . . 2.6 2.3 2.3
----- ----- -----
Total General Taxes . . . $70.7 $74.9 $72.4
===== ===== =====
</TABLE>
7. OTHER INCOME (LOSS)-NET
The components of Other Income (Loss)-Net are shown below. Sales and cost of
sales and related expenses were derived primarily from sales of energy
conservation products. In May 1995, the company sold substantially all of the
assets associated with this business and discontinued its operations. This
transaction had an immaterial effect on net income.
<TABLE>
<CAPTION>
Years Ended September 30 1995 1994 1993
- ---------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Sales . . . . . . . . . . . . . . $ 9.8 $ 21.3 $ 19.8
Cost of sales and
related expense . . . . . . . (8.7) (18.6) (18.5)
Interest income . . . . . . . . . 2.0 1.5 2.2
Net gain on sales of non-utility
accounts receivable . . . . . 2.7 3.4 2.5
Income and other taxes . . . . . .4 (.7) 1.1
Gains (losses) from sale or
devaluation of non-utility
investments-net . . . . . . . 1.9 (3.4) (4.5)
Other . . . . . . . . . . . . . . (5.5) (3.2) (4.4)
------ ------- -------
$ 2.6 $ .3 $ (1.8)
====== ====== =======
</TABLE>
8. POSTEMPLOYMENT BENEFITS
PENSION BENEFITS
The company maintains a 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
retirement plan. It is the company's policy to fund pension costs accrued for
the trusteed 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 1995 1994 1993
- ------------------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Service cost - benefits
earned during the period . . . . . . $ 7.8 $ 8.8 $ 7.7
Interest cost on projected
benefit obligation . . . . . . . . . . 27.5 25.6 25.0
Actual return on plan assets . . . . . . (80.7) (1.4) (52.4)
Net amortization and
deferral . . . . . . . . . . . . . . 46.9 (31.1) 21.9
-------- -------- ---------
Net periodic pension cost . . . . . . . . $ 1.5 $ 1.9 $ 2.2
======== ======== =========
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 trusteed and
supplemental plans as of September 30, 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
- -------------------------------------------------------------------------
(Millions)
<S> <C> <C>
Actuarial present value
of benefit obligations:
Vested benefit obligation . . . . $ (264.9) $ (234.2)
========== ==========
Accumulated benefit
obligation . . . . . . . . . . . . $ (284.3) $ (265.4)
========== ==========
Projected benefit
obligation . . . . . . . . . . . . $ (368.7) $ (344.7)
Plan assets at market value . . . . . 472.0 408.1
---------- ----------
Plan assets in excess of
projected benefit
obligation . . . . . . . . . . . . . 103.3 63.4
Unrecognized net (gain) . . . . . . . (118.7) (75.8)
Unrecognized prior
service costs . . . . . . . . . . . 6.7 7.0
Unrecognized net asset
at transition . . . . . . . . . . (15.1) (17.5)
---------- ----------
Accrued pension costs in
the consolidated
balance sheet . . . . . . . . . . . . $ (23.8) $ (22.9)
========== ==========
Discount rate . . . . . . . . . . . 7.50% 8.00%
========== ==========
Rate of compensation
increase . . . . . . . . . . . . . . 5.00% 5.50%
========== ==========
</TABLE>
f o r t y - o n e
<PAGE> 21
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.
Effective October 1, 1993, the company adopted the provisions of Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106), which requires
that the expected cost of these future benefits be included in the financial
statements during the years that employees render service. As permitted under
the standard, the company elected to amortize the accumulated postretirement
benefit obligation existing at the date of adopting 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 1995 1994
- -------------------------------------------------------------------------------
(Millions)
<S> <C> <C>
Service cost - benefits attributable
to service during the period . . . . . . . . . $ 4.9 $ 5.3
Interest cost on accumulated
postretirement benefit obligation . . . . . . 14.9 13.6
Actual return on plan assets . . . . . . . . . . (1.0) (.2)
Amortization of transition
obligation . . . . . . . . . . . . . . . . . . 9.5 9.5
Other . . . . . . . . . . . . . . . . . . . . . . (.3) (.1)
--------- ----------
Net periodic postretirement
benefit cost . . . . . . . . . . . . . . . . . 28.0 28.1
Amount capitalized as
construction cost . . . . . . . . . . . . . . (5.7) (6.0)
Amount deferred as a
regulatory asset . . . . . . . . . . . . . . . (3.8) (6.7)
--------- ----------
Amount charged to expense . . . . . . . . . . . . $ 18.5 $ 15.4
========= ==========
</TABLE>
The following table sets forth the funded status of the trusteed plans as of
September 30, 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
- -----------------------------------------------------------------------------------
(Millions)
<S> <C> <C>
Accumulated postretirement
benefit obligation:
Retirees . . . . . . . . . . . . . . . . . . . . $ (86.0) $ (86.6)
Fully eligible active employees . . . . . . . . . (16.4) (16.5)
Other active employees . . . . . . . . . . . . . (83.8) (81.0)
-------- --------
Total accumulated post-
retirement benefit obligation . . . . . . . (186.2) (184.1)
Plan assets at fair value, invested
primarily in short-term
debt securities . . . . . . . . . . . . . . . . . . 30.2 12.0
-------- --------
Accumulated postretirement
benefit obligation in excess
of plan assets . . . . . . . . . . . . . . . . . . (156.0) (172.1)
Unrecognized net (gain) . . . . . . . . . . . . . . . (32.7) (20.7)
Unrecognized transition obligation . . . . . . . . . 171.6 181.1
-------- --------
Accrued postretirement benefit
costs in the consolidated
balance sheet . . . . . . . . . . . . . . . . . . . $ (17.1) $ (11.7)
======== ========
Discount rate . . . . . . . . . . . . . . . . . . . . 7.75% 8.25%
======== ========
Rate of compensation increase . . . . . . . . . . . 5.00% 5.50%
======== ========
</TABLE>
The assumed health care cost trend rates for fiscal year 1996 for Medicare
eligible and non-Medicare eligible retirees are 8.00% and 9.50%, respectively;
these rates are assumed to decrease gradually to 5.25% and 5.50%, respectively,
through 2004 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% in each year, the accumulated
postretirement benefit obligation at September 30, 1995 would increase by $25.6
million, and the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for fiscal year 1995 would rise by $3.1
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. Accordingly, the company and its subsidiaries have sought to
recover, through increased rates, the effect of the adoption of SFAS No. 106.
The Public Service Commission of the District of Columbia (PSC of DC) has
granted the company a five-year phase-in for the approximate difference between
the cost of these benefits determined under generally accepted accounting
principles (GAAP) and the amount previously paid in cash for these benefits.
The difference generated during the phase-in period is being deferred as a
regulatory asset. The State Corporation Commission of Virginia (SCC of VA) has
issued 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. In an order dated September 28, 1995, the SCC of
f o r t y - t w o
<PAGE> 22
VA granted the company recovery in accordance with this generic order. 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, 1995 is $10.5 million, and it is expected that these costs will
be recovered over the twenty years commencing October 1, 1993.
All of the regulatory commissions having jurisdiction over the company's rates
are requiring 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 1995 and 5.5% for 1994. 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%.
Prior to adopting SFAS No. 106, the company recognized these costs as paid. The
amount recognized in 1993 was $5.7 million.
9. FERC ORDER NO. 636 AND TRANSITION COSTS
On November 1, 1993, Federal Energy Regulatory Commission (FERC) Order No. 636
(Order) was implemented. The Order removed the merchant function from the
pipelines 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. If the transition costs are
considered to be prudently incurred by FERC, these costs can be recovered from
customers of the pipelines such as the company. Through September 30, 1995, the
company has paid $27.5 million in such costs to seven pipeline companies and
currently estimates that additional transition costs to be assigned to the
company will not be less than $17.8 million. The company has recorded a
liability in the balance sheet at September 30, 1995 in this amount. All but
$400,000 of this liability is due to Columbia Gas Transmission Corporation
(CGT).
The total level of transition costs that will ultimately be incurred by the
company and reflected in the financial statements can not be estimated at this
time. This is because the level is not determinable with available information,
the costs have yet to be incurred by the applicable pipeline companies or with
the exception of CGT, the level of costs may be affected by requests pending or
to be filed at FERC.
As stated previously, the company owes the overwhelming majority of its
presently estimated remaining liability for transition costs to CGT. Therefore
the outcome of CGT's current bankruptcy filing affects the method that will
likely be utilized by the company to satisfy most of its existing liability.
CGT, as well as its parent, The Columbia Gas System, Inc. (CGS), continues to
operate as debtors in possession under Chapter 11 of the Bankruptcy Code. CGT
and CGS filed reorganization plans and disclosure statements with the United
States Bankruptcy Court (Court) on April 17, 1995. CGT's plan includes a
comprehensive settlement filed with the Court and FERC which would resolve the
transition cost issue of the company by netting the company's transition cost
liability (except for approximately $5 million at September 30, 1995 of amounts
to be included in base rates) against amounts owed to the company by CGT from
other proceedings pending before FERC. The FERC has approved the settlement and
on November 15, 1995, the Court confirmed both the CGT and CGS plans. The
company anticipates that the plans including the settlement will be implemented
in accordance with procedures ordered by the Court.
The company has actively participated in these bankruptcy proceedings to
protect its interests through its membership on the official Customer
Committee. The company believes it will continue to have access to reliable
services on the pipeline of CGT, regardless of how CGT is ultimately
restructured.
The company is currently in the process of collecting transition costs paid to
the pipeline companies through the purchased gas adjustment provision of the
company's retail rate schedules. At September 30, 1995, the company had
recorded a regulatory asset of $17.8 million for amounts yet to be recovered
from its ratepayers.
10. 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; and (5) 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.
f o r t y - t h r e e
<PAGE> 23
The company has identified up to ten sites where the company, its subsidiaries,
or their predecessors may have operated manufactured gas plants (MGPs). The
last use of any such plant was in 1984. In connection with these operations,
certain by-products of the gas manufacturing process are known to be present at
or near some former sites and may be present at others.
At one of the former MGP sites, studies have shown the presence of coal tar
under the site and an adjoining property. A 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. Contaminated groundwater is being removed
and treated by a water treatment system. The company has obtained approval from
an adjacent landowner to perform a demonstration project to determine the
feasibility of using bioremediation to treat soil contamination on the
adjoining property. This project is scheduled to commence in fiscal year 1996,
and if successful, may become the method of choice to remediate both the
company's site and the adjoining property.
At a second former MGP site, tar-products were identified under the property,
and a risk assessment showed that there was no unacceptable risk to human
health or the environment. A state-approved treatment and recovery system to
recover free tar was designed and installed. Minimal volumes of tar-products
have been recovered from pumping thus far. The company will continue to pump
and monitor the site.
At a third former MGP site, initial studies have shown that tar-products are
present under the property. A remedial investigation/feasibility study was
completed and submitted to the appropriate state regulatory agency in April
1995. Remediation should begin in fiscal year 1996.
At a fourth former MGP site and on an adjacent parcel of land, the company
plans to perform studies and analytical work in fiscal year 1996 and submit the
results to the applicable state regulatory agency.
At a fifth former MGP site, a treatment system for contaminated groundwater has
been operating for five years. There is no indication at this time that any
additional action other than water treatment will be necessary.
The company has no reason to believe at this time that remediation of any of
the remaining five sites will be necessary.
Through September 30, 1995, the company had paid $8.2 million for environmental
response costs. A liability of $11.1 million on an undiscounted basis has been
recorded as of September 30, 1995 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 the five sites described above. The maximum liability associated with these
sites at September 30, 1995 is estimated at $17.6 million. The estimates were
determined by the company's environmental expert 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 (12 to 30 years) and
differences in remediation processes expected to be used.
In a rate order issued by the PSC of MD in July 1993, the company received
approval to recover costs applicable to Maryland customers over twelve years
related to two of the sites mentioned above. In addition, an order issued in
October 1994 by the PSC of MD allows for recovery of the costs associated with
another of the aforementioned sites over periods ranging from five to thirty
years. As a result of rate orders issued by the PSC of DC in October 1993 and
August 1994, the company has been allowed three-year recovery of prudently
incurred environmental response costs expended through September 30, 1993.
Additional costs incurred between rate cases can be deferred for future cost
recovery consideration in this jurisdiction. In Virginia, the company has
received approval to recover environmental response costs over a 12-year
period. As a result of a West Virginia rate order, a subsidiary has been
allowed to recover certain environmental response costs.
The company has recorded a regulatory asset of $14.3 million for the portion of
environmental response costs it believes are recoverable in rates. 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.
11. COMMITMENTS AND CONTINGENCIES
TRANSFER OF RECEIVABLES WITH RECOURSE
The company has extended credit to certain residential and small commercial
customers to purchase gas appliances and equipment and energy conservation
products. The company transferred with recourse certain of these non-utility
accounts receivable to commercial banks in the amounts of $45.1 million and
$45.0 million in 1995 and 1994, respectively. The transfers were recognized as
a sale in accordance with Statement of Financial Accounting Standards No. 77,
"Reporting by Transferors for Transfers of Receivables with Recourse." At
September 30, 1995, $63.6 million of accounts receivable related to these and
prior sales remain outstanding. Receivables transferred with recourse are
considered financial instruments with off-balance sheet risk. The company's
exposure to credit loss in
f o r t y - f o u r
<PAGE> 24
the event of non-performance by customers is represented by the balance of
transferred receivables that remain outstanding, less a provision for
uncollectible accounts.
NATURAL GAS CONTRACTS
The company has 15 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 takes fall below minimum
levels. These gas purchase contracts have expiration dates ranging from 1997 to
2003.
The company also has pipeline service agreements with three 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 1997 to 2013, provide for the company to pay fixed monthly
charges.
At September 30, 1995, the company is required to make payments to producers or
marketers with respect to the contracts specified above, exclusive of commodity
charges based on quantities purchased, of approximately $3.4 million for each
year through the year 2003. The aggregate amount of required payments under the
pipeline service agreements totals approximately $989 million, including
required annual payments of $103 million in 1996, $103 million in 1997, $100
million in 1998, $99 million in 1999 and $96 million in 2000.
The costs incurred under these contracts are recovered as part of the cost of
gas through the purchased gas adjustment clause of the company's retail rate
schedules in each jurisdiction in which the company operates.
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, 1995 and 1994. 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>
1995 1994
------------------------ ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C> <C>
Current assets . . . . . . . . . . . . . . . . . $ 63.9 $ 63.9 $ 78.3 $ 78.3
Current liabilities . . . . . . . . . . . . . . . 208.3 208.3 187.3 187.3
Long-term debt . . . . . . . . . . . . . . . . . 329.1 341.7 342.3 331.5
</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 Sheet 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.
f o r t y - f i v e
<PAGE> 25
MANAGEMENT'S RESPONSIBILITY FOR
FINANCIAL STATEMENTS
The presentation of financial data that accurately and fairly reflect the
results of operations and financial position of the company is one of
management's stewardship obligations to its shareholders. The accompanying
financial statements have been prepared by management 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, comprised of directors
who are not officers or employees of the company, to discuss, among other
things, the company's system of internal accounting controls and the adequacy
of the internal audit program.
The Audit Review Committee also meets periodically with Arthur Andersen LLP,
the company's independent public accountants, with and without the presence of
management, to discuss the results of Arthur Andersen LLP's audit of the
company's financial statements. The Audit Review Committee and Arthur Andersen
LLP also discuss internal accounting control matters that come to their
attention during the course of their audit. The report of Arthur Andersen LLP
on the audit of the company's financial statements appears at right.
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of
Washington Gas Light Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Washington Gas Light Company (a District of
Columbia and Virginia corporation) and subsidiaries as of September 30, 1995
and 1994, 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, 1995. 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 an 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, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 1995 in conformity with generally accepted accounting principles.
As explained in Notes 5 and 8 to the consolidated financial statements,
effective October 1, 1993, the company changed its methods of accounting for
income taxes and postretirement benefits other than pensions.
/s/ ARTHER ANDERSEN LLP
- ------------------------
Washington, D.C.,
October 24, 1995 (except with respect to
the matter discussed in Note 9, as to which
the date is November 15, 1995).
f o r t y - s i x
<PAGE> 26
SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)
Washington Gas Light Company
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 1995
Operating revenues . . . . . . . . . . . . . $242,915 $353,650 $131,916 $100,267
Operating income (loss) . . . . . . . . . . . 33,389 61,577 2,231 (5,004)
Net income (loss) . . . . . . . . . . . . . . 27,726 53,438 (5,441) (12,814)
Earnings (loss) per average share
of common stock . . . . . . . . . . . .65 1.25 (.14) (.31)
FISCAL YEAR 1994
Operating revenues . . . . . . . . . . . . . $271,222 $410,184 $130,907 $102,550
Operating income (loss) . . . . . . . . . . 37,707 65,289 (2,799) (7,865)
Net income (loss) . . . . . . . . . . . . . . 30,252 54,958 (10,129) (14,622)
Earnings (loss) per average share
of common stock (a) . . . . . . . . . .72 1.31 (.25) (.36)
</TABLE>
(a) The sum of these amounts does not equal the annual amount because the
quarterly calculations are based on an increasing number of common
shares outstanding.
COMMON STOCK PRICE RANGE AND DIVIDENDS PAID
<TABLE>
<CAPTION>
Dividends Paid Dividend
High Low Per Share Payment Date
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FISCAL YEAR 1995
Fourth Quarter . . . . . . . . . . . . . . . $ 20 1/2 $ 17 5/8 $ .28 8/1/95
Third Quarter . . . . . . . . . . . . . . . . 21 18 1/2 .28 5/1/95
Second Quarter . . . . . . . . . . . . . . 20 1/4 16 1/8 .2775 2/1/95
First Quarter . . . . . . . . . . . . . . . 19 3/8 16 .2775 11/1/94
FISCAL YEAR 1994
Fourth Quarter . . . . . . . . . . . . . . . $ 19 5/8 $ 16 7/8 $ .2775 8/1/94
Third Quarter . . . . . . . . . . . . . . . . 20 3/8 18 3/8 .2775 5/1/94
Second Quarter . . . . . . . . . . . . . . 21 1/4 19 1/2 .2725 2/1/94
First Quarter . . . . . . . . . . . . . . . 22 3/4 18 1/8 .2725 11/1/93
</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, 1995, the company had 24,759 common
shareholders.
f o r t y - s e v e n
<PAGE> 27
Appendix A
WASHINGTON GAS LIGHT COMPANY
GRAPHS INCLUDED IN MANAGEMENT'S DISCUSSION AND ANALYSIS
1995
<TABLE>
<CAPTION>
Earnings per Average Common Share Net Income Applicable to Common Stock
- --------------------------------- -------------------------------------
** This graph presented the company's earnings ** This graph presented the company's net income
per average common share for 1990 - 1995. applicable to common stock for 1990 - 1995.
year Dollars year Millions of dollars
<S> <C> <C> <C>
1990 1.25 1990 48.9
1991 1.14 1991 45.1
1992 1.26 1992 50.9
1993 1.31 1993 53.7
1994 1.41 1994 59.1
1995 1.45 1995 61.6
</TABLE>
<TABLE>
<CAPTION>
Net Revenues and Cost of Gas Cost of Gas Sold
- ---------------------------- ----------------
** This graph presented the company's net ** This graph presented the company's
revenues and cost of gas for 1990 -1995. cost of gas per therm for 1990 - 1995.
millions of dollars
Net Cost of
year Revenues Gas total year cents per therm
<S> <C> <C> <C> <C> <C>
1990 352 382 734 1990 29.45
1991 349 349 698 1991 27.89
1992 393 353 746 1992 26.33
1993 415 479 894 1993 35.26
1994 453 462 915 1994 32.13
1995 439 390 829 1995 28.68
</TABLE>
<TABLE>
<CAPTION>
Other Operating Expenses Capitalization
- ------------------------ --------------
** This graph presented a breakdown of the ** This graph presented a breakdown of the
Company's operating expenses for 1990 -1995. company's capital structure for 1990 -1995.
millions of dollars millions of dollars
Operation & Long-term Preferred Common
year maintenance Taxes Depreciation total year Debt Stock Equity total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1990 164 77 35 276 1990 279 29 399 707
1991 167 76 36 279 1991 263 29 412 704
1992 180 94 37 311 1992 294 29 433 756
1993 185 104 40 329 1993 348 28 458 834
1994 208 109 43 360 1994 342 28 486 856
1995 195 106 46 347 1995 330 28 513 871
</TABLE>
<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-30-1995
<PERIOD-START> OCT-01-1994
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,053,367
<OTHER-PROPERTY-AND-INVEST> 2,691
<TOTAL-CURRENT-ASSETS> 159,040
<TOTAL-DEFERRED-CHARGES> 145,040
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,360,138
<COMMON> 42,945
<CAPITAL-SURPLUS-PAID-IN> 287,366
<RETAINED-EARNINGS> 182,733
<TOTAL-COMMON-STOCKHOLDERS-EQ> 513,044
0
28,471
<LONG-TERM-DEBT-NET> 329,051<F1>
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 227,396<F2>
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 52,505
0
<CAPITAL-LEASE-OBLIGATIONS> 826
<LEASES-CURRENT> 826
<OTHER-ITEMS-CAPITAL-AND-LIAB> 436,241
<TOT-CAPITALIZATION-AND-LIAB> 1,360,138
<GROSS-OPERATING-REVENUE> 828,748
<INCOME-TAX-EXPENSE> 37,514
<OTHER-OPERATING-EXPENSES> 699,041
<TOTAL-OPERATING-EXPENSES> 736,555
<OPERATING-INCOME-LOSS> 92,193
<OTHER-INCOME-NET> 2,610
<INCOME-BEFORE-INTEREST-EXPEN> 94,803
<TOTAL-INTEREST-EXPENSE> 31,894
<NET-INCOME> 62,909
1,333
<EARNINGS-AVAILABLE-FOR-COMM> 61,576
<COMMON-STOCK-DIVIDENDS> 47,706
<TOTAL-INTEREST-ON-BONDS> 31,894<F3>
<CASH-FLOW-OPERATIONS> 178,188
<EPS-PRIMARY> 1.45
<EPS-DILUTED> 1.45
<FN>
<F1>Represents total long-term debt including, $102,825 in First Mortgage Bonds,
$227,200 in unsecured medium-term notes, $196 in other long-term debt and
$(1,170) in unamortized premium and discount-net.
<F2>Includes $227,200 in unsecured medium-term notes and other notes of $196.
<F3>Represents total interest expense, per the Statement of Income.
</FN>
</TABLE>
