<PAGE> 1
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, 1996
------------------------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
------------------- -----------------------
Commission file number 1-1483
---------------------------------------------------------
WASHINGTON GAS LIGHT COMPANY
- -------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0162882
- ------------------------------------------- --------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 H Street, N. W., Washington, D. C. 20080
- ------------------------------------------- --------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (703) 750-4440
--------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
- ------------------------------------ ---------------------------------
Common Stock $1.00 par value New York Stock Exchange
Philadelphia Stock Exchange
Preferred Stock, cumulative,
without par value:
$4.25 Series Philadelphia Stock Exchange
$4.36 Convertible Series Philadelphia Stock Exchange
$4.60 Convertible Series Philadelphia Stock Exchange
$4.80 Series Philadelphia Stock Exchange
$5.00 Series Philadelphia Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----
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]
<PAGE> 2
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.
<TABLE>
<CAPTION>
$ 989,945,000 October 31, 1996
------------------ ---------------------
<S> <C>
Market Value Date
</TABLE>
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Common Stock $1.00 par value 43,714,749 November 29, 1996
- ---------------------------- ----------------- ---------------------
<S> <C> <C>
Class Number of Shares Date
</TABLE>
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, 1996.
PART II - Annual Report to Shareholders for the fiscal year ended
September 30, 1996 (Pages 33 through 60).
PART III - Proxy Statement dated January 21, 1997.
PART IV - Form S-7 Registration Statement number 2-53658, filed May 12,
1975, and Amendment No. 2 thereof, filed June 24, 1975.
<PAGE> 3
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I PAGE
- ------ ----
<S> <C>
Item 1. Business
Subsidiaries...................................................... 2
Rate Regulation, Retail Gas Rates and Rate Increases.............. 3
Competition....................................................... 7
Gas Supply and Capacity........................................... 10
Environmental Matters............................................. 12
Other............................................................. 13
Item 2. Properties.......................................................... 14
Item 3. Legal Proceedings................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders................. 14
Executive Officers of the Registrant........................................... 15
PART II
- -------
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters............................................... 17
Item 6. Selected Financial Data............................................. 17
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations..................... 17
Item 8. Financial Statements and Supplementary Data......................... 17
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure............................ 17
PART III
- --------
Item 10. Directors and Executive Officers of the Registrant.................. 17
Item 11. Executive Compensation.............................................. 17
Item 12. Security Ownership of Certain Beneficial Owners
and Management.................................................... 17
Item 13. Certain Relationships and Related Transactions...................... 17
PART IV
- -------
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K............................................... 18
Auditors' Report on Schedule................................................... 22
Signatures..................................................................... 25
</TABLE>
1
<PAGE> 4
FORWARD-LOOKING STATEMENTS
Statements contained in this report that are not based on historical facts are
forward-looking statements as defined in the Private Securities Litigation
Reform Act of 1995. Actual results could differ from the expectations discussed
herein.
Factors that could cause actual results to differ from management's beliefs
described in this report include, among other matters: (1) the effect of
fluctuations in weather from normal levels; (2) regulatory and legislative
changes; (3) variations in prices of natural gas and competing energy sources;
(4) improvements in products or services offered by competitors; and (5)
changing economic conditions.
PART I
ITEM 1. BUSINESS
Washington Gas Light Company (the Company) is a public utility that delivers
and sells natural gas to metropolitan Washington, D.C. and adjoining areas in
Maryland and Virginia. A distribution subsidiary serves portions of Virginia
and West Virginia. The Company has been engaged in the gas distribution
business for 148 years, having been originally incorporated by an Act of
Congress in 1848. It became a domestic corporation of the Commonwealth of
Virginia in 1953 and a corporation of the District of Columbia in 1957.
The population of the area served by the Company is estimated to be 4.5
million. As of September 30, 1996, the Company and its distribution subsidiary
served 772,281 customer meters. A listing of meters served and therms
delivered as of and for the twelve months ended September 30, 1996 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.
<TABLE>
<CAPTION>
Therms Delivered
Jurisdiction Meters Served (millions)
------------ ------------- ----------------
<S> <C> <C>
District of Columbia 143,160 337
Maryland 322,554 671
Virginia 303,718 511
West Virginia 2,849 25
------- -----
Total 772,281 1,544
======= =====
</TABLE>
Of the 1,544 million therms delivered in fiscal year 1996, 91% was sold by the
Company and its distribution subsidiary and 9% was delivered to various
customers that acquired their gas from others. Of the therms sold and delivered
by the Company, 53% was sold to firm residential customers, 34% was sold to firm
commercial and industrial customers and 13% was sold to interruptible
commercial, industrial and electric generation customers. Therms delivered by
the parent company amounted to 95% of the total consolidated deliveries. In
1996, the Company sold gas outside of its service territory. These off-system
sales totalled 40.5 million therms.
SUBSIDIARIES
The Company has four wholly-owned active subsidiaries which are described
below. Frederick Gas Company, Inc., previously a wholly-owned distribution
subsidiary, was merged into the parent company effective January 1, 1996.
2
<PAGE> 5
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, 1996 totalled 62 million therms, of which 13% was sold to firm residential
customers, 39% was sold to firm commercial and industrial customers, 43% was
sold to interruptible commercial and industrial customers, and 5% was delivered
to various customers that acquired their gas from others.
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, 1996, Crab Run's investment in this partnership was not material.
The Company expects that any additional investments in the partnership will be
minimal.
Washington Gas Energy Services, Inc. (WGES), was formerly known as Washington
Resources Group, Inc., and 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. This subsidiary
is primarily engaged in the unregulated sale of gas in competition with
third-party suppliers such as gas marketers or other gas utilities. WGES has
also received a power certificate from the FERC and plans to market electricity
in the near future. WGES' subsidiaries are described below.
Washington Gas Energy Systems, Inc. previously supplied and installed
residential and commercial energy conservation products and services. The
company is currently engaged in commercial energy services, including the
design and renovation of mechanical heating, air conditioning and ventilation
systems.
Brandywood Estates, Inc. (Brandywood) is a general partner, along with a major
developer, in a venture designed to develop 1,600 acres in Prince George's
County, Maryland for sale or lease. This acreage was contributed to the
Brandywood Development Limited Partnership by Brandywood in 1992. In March
1996, the partnership submitted to Prince George's County a rezoning
application for 790 acres of its property. The mixed-use development plan
proposes approximately 1,600 homes, 100,000 square feet of retail space and
105,000 square feet of office space. Final review of the development proposal
is expected in 1997. Brandywood continues to have sole ownership of
approximately 1,000 additional acres adjacent to this property that are not
being currently developed or otherwise utilized.
Advanced Marketing Concepts, Inc. previously provided services primarily in the
area of energy-related home improvements. This subsidiary is currently
inactive.
RATE REGULATION, RETAIL GAS RATES AND RATE INCREASES
RATE REGULATION
The Company is regulated by the Public Service Commission of the District of
Columbia (PSC of DC), the Public Service Commission of Maryland (PSC of MD) and
the State Corporation Commission of Virginia (SCC of VA). Shenandoah is
regulated by the SCC of VA and the Public Service Commission of West Virginia
(PSC of WVA). The FERC regulates Hampshire.
The PSC of DC consists of three full-time members who are appointed by the
Mayor and confirmed by the District of Columbia City Council. The term of each
commissioner is
3
<PAGE> 6
four years. There are no limitations on the number of terms that can be
served. There is no statutory suspension period related to rate requests.
The PSC of MD consists of five full-time members who are appointed by the
Governor and confirmed by the Senate of Maryland. The term of each
commissioner is five years. There are no limitations on the number of terms
that can be served. The Company is required to give 30 days' notice when
filing for a rate increase. The PSC of MD may initially suspend the proposed
increase for 150 days beyond the 30-day notice period and then has the option
to extend the suspension for an additional 30 days. If action has not been
taken after 210 days, rates may be placed into effect subject to refund.
The SCC of VA consists of three full-time members who are elected by the
General Assembly of Virginia. A commissioner's term is for six years with no
limitation on the number of terms that can be served. An Expedited Rate Case
(ERC) procedure is available which provides that rate increases may take effect
30 days after the filing date. Under the ERC mechanism, the Company may not
propose any changes in accounting policies and the rate of return on common
equity cannot be modified from the rate established in the last fully
adjudicated case. General rate applications may take effect 150 days after the
filing. Before new rates become final, both types of rate increases are
subject to refund.
RETAIL GAS RATES
In the District of Columbia jurisdiction, the firm residential and
non-residential rate schedules are based upon a flat commodity charge for each
therm of gas consumed and a customer charge designed to recover certain fixed
costs. In addition to this two-part rate design, a peak-usage charge is in
place for non-residential firm customers. This charge was established to send
accurate price signals as to the cost of gas to customers during both peak and
non-peak periods. In the Maryland and Virginia jurisdictions, the rate
schedules for firm service are comprised of a fixed customer charge and
declining-block commodity rates. The current firm tariff provisions in all
jurisdictions of the Company and Shenandoah contain a purchased gas adjustment
clause which allows the Company and Shenandoah to pass on any increases or
decreases in gas costs from a stipulated base cost. Moreover, each jurisdiction
in which the Company and Shenandoah operate provides for an annual
reconciliation of total gas costs billed firm customers with the actual cost of
gas incurred.
Although the Company continues to charge the majority of its firm customers
rates based on the sale and delivery of natural gas on a combined or bundled
basis, state regulatory and Company initiatives are seeking to separate or
"unbundle" the rates charged to firm customers for the natural gas commodity
("city gate supply service") from rates charged for delivery of gas on the
Company's distribution system ("delivery service"). During fiscal year 1996,
unbundled city gate supply and delivery service became available to large
volume and groups of small volume firm commercial and industrial customers in
the State of Maryland. Additionally, effective November 1, 1996, a pilot
program was implemented in this state that offers up to 6,600 residential
customers unbundled services. The Company's firm cost of gas purchased related
to bundled sales of natural gas will continue to be collected under the
purchased gas tariff provisions mentioned above. Future unbundling initiatives
in the Company's District of Columbia and Virginia jurisdictions are discussed
in the Competition section, under the subsection entitled Unbundling in the
Company's Major Jurisdictions.
Interruptible customers are required under contract to be capable of using an
alternative fuel as a substitute for natural gas when the Company determines
their service must be curtailed to accommodate firm customers' needs during
periods of peak demand. Nearly all of this customer class has the option of
buying gas from the Company or a third-party supplier. In either case, the
Company charges these customers for delivering the gas supplies on its
distribution system.
4
<PAGE> 7
All of the Company's major jurisdictions have rate structures which provide for
the firm ratepayers and the Company to share portions of gross margins from
sales to the interruptible customer class. In the District of Columbia and
Virginia jurisdictions, 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 of providing service from the interruptible to the
firm class.
In the Maryland jurisdiction, as a result of unbundling initiatives, all
interruptible customers became delivery service customers and must elect
whether to purchase gas from the Company or a third-party supplier. The vast
majority of the revenues from the delivery of gas to interruptible customers,
whether purchased from the Company or from a third-party supplier, are being
returned to firm customers, after a gross margin threshold is reached. In
recognition of the increased competition in making gas sales to interruptible
customers, margins earned from gas sales made by the Company in Maryland have
been shared equally between firm customers and the Company. In addition, the
Company retains 100% of the gross margins associated with sales and deliveries
to interruptible customers until the Company has recovered its investment in
capital costs associated therewith. This arrangement has been in effect in
Maryland for interruptible customers added since August 1989.
During fiscal year 1996, WGES provided third-party supplier gas to
interruptible customers in the District of Columbia and Virginia jurisdictions.
Beginning in October 1996, WGES became eligible to provide third-party supplier
gas to various customers of the Company in the Maryland jurisdiction. Margins
generated on the sale of the natural gas commodity are being fully retained by
WGES.
RATE INCREASES
District of Columbia
On October 8, 1993, the PSC of DC issued a final order based on a rate increase
requested in December 1992 that approved a $4.7 million increase, or 2.5%, in
annual revenues, effective October 19, 1993. The order, which included an
overall rate of return of 9.86% and a return on common equity of 11.50%,
provided for a phase-in, rather than immediate recognition, of the additional
costs associated with the implementation of Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS No. 106). The incremental costs related to SFAS No. 106
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. The Company has
received four increases to reflect the effect of the phase-in policy.
On August 1, 1994, the PSC of DC issued an order approving a Stipulation and
Agreement signed by a majority of the parties to a rate case filed in January
1994, providing for a $6.4 million annual increase in revenues, or 3.4%,
effective August 1, 1994. The agreement did not specify a rate of return.
Terms of the agreement provided that the Company would not file for additional
rate relief prior to April 1, 1996 and that any increase in rates could not 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.
Maryland
On July 29, 1993, the PSC of MD authorized an increase in base rates designed
to collect an additional $10.6 million, or 3.7%, in annual revenues, effective
August 1, 1993. The order resulted from a settlement agreement entered into by
most of the parties to a rate case filed in March 1993. Recovery of SFAS No.
106 costs, which had been included in the Company's request, was not
specifically addressed in the order;
5
<PAGE> 8
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 purchase gas adjustment to
provide for recovery of carrying costs on actual storage gas balances and
provided for an annual increase in revenues of $1.0 million resulting from the
modification to, or the addition of, certain service-related charges. The
return on equity indicated in the order of 11.50% was not utilized to establish
rates.
On October 18, 1994, the PSC of MD issued an order approving an unopposed
Stipulation and Agreement signed by a majority of the parties to a rate case
filed in June 1994 and base rates, designed to collect an additional $7.4
million, or 2.4%, annually were placed into effect on December
1, 1994.
Virginia
On September 27, 1994, the Company implemented rates designed to recover an
additional $15.7 million annually, based on a rate case filed in April 1994.
These rates were collected subject to refund. On September 28, 1995, the SCC of
VA issued an order approving an increase in annual revenues of $6.8 million, or
2.7% effective September 27, 1994. The order included an overall rate of
return of 9.72% and a return on equity of 11.50%. The order allowed the Company
to collect SFAS No. 106 costs in accordance with a generic order of the SCC of
VA and allowed the recovery of 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 were refunded, with
interest, by January 1, 1996.
Shenandoah
The PSC of WVA issued an order, effective on September 18, 1995, that approved
a joint Stipulation and Agreement between the Staff of the PSC of WVA and
Shenandoah, based on a rate increase request filed by Shenandoah in January
1995. The agreement provided for an annual increase in rates of $522,000 and
did not specify a return on equity or an overall rate of return. The Company
placed the new rates in effect on December 4, 1995.
On August 6, 1995, Shenandoah placed into effect new rates designed to collect
an additional $1.2 million in annual revenues, subject to refund, based on a
rate case filed in July 1995. On May 30, 1996, the SCC of VA issued an order
approving an increase in annual revenues of $883,000, effective August 6, 1995.
The increase reflected an overall rate of return of 9.51% and a return on
equity of 11.00%. Amounts collected under interim rates in excess of the amount
ultimately granted were returned, with interest, to customers by September 1,
1996.
On February 2, 1996, Shenandoah filed a request with the PSC of WVA for a rate
increase of $604,000. The request included an overall rate of return of 10.33%
and a return on common equity of 12.25%. In addition to requesting the
recovery of increased operating expenses and a return on additional capital
investment, Shenandoah requested full recovery of costs associated with SFAS
No. 106. On August 8, 1996, a settlement agreement was reached between
Shenandoah, the Staff of the PSC of WVA and the Consumer Advocate Division of
the PSC of WVA which would result in an increase in annual revenues of
$216,000. On November 27, 1996, the PSC of WVA issued an order approving the
terms of the agreement and the increased rates became effective on December 2,
1996.
Page 44 of the Company's Annual Report to Shareholders, which is incorporated
by reference into this report, includes a summary of the amount of the
requested rate increase associated with each of the parent company's rate cases
described above.
6
<PAGE> 9
COMPETITION
Sources of Competition
The most significant competition the Company faces continues to be between
natural gas and electricity in the residential market, which contributes a
substantial 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, where customers must be capable of using
a fuel other than natural gas when demand by firm customers peaks, fuel oil is
the most significant competing energy alternative. The Company's success in
this market is largely dependent on changes in the price of gas versus the
price of oil.
While the Company has historically faced competitive pressures from other
energy sources, it is experiencing added competitive pressures within the gas
industry and will be impacted by changes expected to take place in the electric
industry. The effect of these matters on the Company's competitive position is
discussed further below.
Natural Gas Industry Deregulation
The natural gas industry, which has traditionally included producers,
interstate pipelines and local distribution companies (LDCs) such as the
Company, has a long history and has undergone many changes since its inception.
Perhaps no greater changes have taken place than those that have been
experienced over the past 10 years. These changes have generally been in
response to desires for deregulation that promote competition in situations
where it is economically beneficial to consumers. The changes continue while
the pace of change for LDCs is accelerating.
The restructuring of the natural gas industry generally began at the producer
level with the passage of the Natural Gas Policy Act in 1978, which brought
about a gradual decontrol of the wellhead price of natural gas and allowed for
market-based prices. In the pipeline segment of the industry, FERC Order No.
636 separated the merchant function of selling natural gas from interstate
transportation and storage services of the pipeline companies. This separation,
or as it is oftentimes called, unbundling, of the traditional pipeline services
of transporting and storing natural gas from the sale of natural gas was done
in order to increase competition. As a result of this order, the pipeline
companies are responsible for providing gas storage and transportation
services, and LDCs have taken on the responsibility and risk of separately
procuring storage and transportation capacity from the pipelines and marketers,
and competitive natural gas supplies from producers and marketers. The rates
charged by the pipelines for transmission and storage are still regulated by
FERC, but negotiated, market-based rates are beginning to appear.
As an LDC, the Company is undergoing changes similar to those already
experienced by producers and pipelines. Historically, the Company charged its
customers one rate for the cost it paid pipelines for natural gas delivered to
the entry point at its gas distribution system and the costs it incurred to
deliver natural gas to the customers' premises. And, although the Company
continues to generate the overwhelming majority of its revenues from the sale
and delivery of natural gas on a combined or bundled basis, state regulatory
and Company initiatives are seeking to separate or unbundle the rates charged
to customers for the natural gas commodity from rates charged for delivery of
gas on the Company's distribution system. Unbundling the sale of the natural
gas commodity allows other gas utilities and marketers the opportunity to gain
access to the Company's customers, resulting in increased competition for that
portion of the Company's business.
7
<PAGE> 10
The Company does not expect most delivery service components to become subject
to competition because of the economic disincentives to construct duplicate
facilities. Although delivery service is likely to remain regulated, it will
undergo greater scrutiny as unbundling occurs and customers see greater
information of the charges on their bills. Bypass of the Company's facilities
by other potential providers of delivery service is not considered a
significant threat because of the nature of the Company's customer base and the
location of the customers in relation to the interstate pipelines.
The Company supports the move to unbundle city gate supply service from
delivery service which maximizes choices for its customers. In the past, the
Company generally could not make profits or incur losses from the sale of
natural gas. The cost of the natural gas commodity was simply a pass-through to
its customers. In one jurisdiction in which it operates, the separation of the
city gate supply service charge from the delivery service charge has provided
the Company the opportunity to make profits or the chance to incur losses from
the sale of natural gas.
The Company believes it will ultimately transition to fully deregulated,
competitive city gate supply service for all customers. However, only a
relatively small portion of customers is currently eligible to choose their
supplier of that service. Accordingly, the level of profits recorded to date
has not been material. The complete transition in all jurisdictions to fully
competitive city gate supply service to all customer classes could take several
years.
Currently, some states have instituted initiatives to further extend the
benefits of competition to the consumer. These include performance-based
regulation for gas cost recovery by LDCs and a greater focus on incentive
regulation or basing cost recovery on external measures of efficiency.
Depending on the circumstances in the jurisdictions in which the Company
operates, some of these types of alternatives could be initiated on an interim
basis before city gate supply service is fully implemented.
In response to the changing competitive situation, the Company has had
to assess the nature of its business and explore alternatives to the
traditional role of purchase, transport and sale of natural gas. The Company
anticipates that opportunities for non-regulated sales will increase as
competition intensifies and as unbundling initiatives further expand. The
Company is desirous of maximizing the number of product offerings that it can
make to its customer base. This will require the Company to develop new
products and services that its customers value at a profitable price relative
to various alternatives.
In order to capitalize on potential profits from offering unregulated city gate
supply service, the Company's non-utility subsidiary, WGES, has entered the
natural gas sales market in direct competition with other gas utilities and
marketers. Additionally, WGES competes with oil marketers and, having received
a power certificate from the FERC, plans to market electricity in the near
future. Other energy services offered by WGES and its Washington Gas Energy
Systems, Inc. subsidiary include the design and installation of energy
equipment as well as heating and air conditioning inspections on both gas and
electric equipment.
The significant level of change in energy markets provides both opportunities
and challenges to the Company over the next several years. Important factors to
the Company's success include, among others: (1) its ability to ensure it has
access to a supply of natural gas and pipeline capacity at competitive prices;
(2) its ability to quickly react to changing market conditions; and (3) the
timing and extent of access to its markets by other competitors.
8
<PAGE> 11
Unbundling in the Company's Major Jurisdictions
Unbundling initiatives have progressed furthest in Maryland. Currently,
competitive natural gas supply options are available in Maryland for all
interruptible customers, and certain firm commercial and residential customers.
The program for residential customers, effective November 1, 1996, is being
administered under a pilot program whereby up to 6,600 customers (2% of
Maryland residential customers) can choose from among four suppliers of gas,
including the Company. Depending on the Company's success, these options
provide the opportunity to earn a profit or the chance of a loss on the sale of
gas, in addition to the revenues historically generated from the delivery of
gas.
In Virginia, the Company has filed with the SCC of VA to expand the eligible
base of interruptible customers who could purchase gas from third-party
suppliers, including WGES, the Company's unregulated subsidiary. A decision by
the Commission is expected in 1997.
In the District of Columbia, the Company has filed tariff proposals with the
PSC of DC to expand the number of interruptible and large commercial customers
eligible to purchase gas from third-party suppliers. Also proposed is a
two-year pilot program that would allow third-party gas sales to a limited
group of residential customers. The PSC of DC has held hearings to address each
of the Company's proposals and a decision is expected in 1997.
Electric Industry Deregulation
The movement toward deregulation in the electric industry has implications for
the gas industry. The Energy Policy Act of 1992 allowed unregulated independent
power producers to sell power to wholesale customers in competition with
regulated electric utilities. In April 1996, the FERC issued Order No. 888,
that is intended to further increase competition within the electric
industry beginning in 1998.
Order No. 888 addresses open access and stranded cost issues. Open access
provisions stimulate wholesale electric power sales competition by requiring
public utilities that own, control or operate electric transmission lines to
file non-discriminatory tariffs that offer others the same transmission
services they provide themselves, under comparable terms and conditions. These
utilities must also use these tariffs for their own wholesale energy sales and
purchases. The order also provides that stranded costs, the unrecovered costs
incurred by electric utilities in anticipation of continued service to their
customers, are eligible for recovery, under certain terms and conditions, from
customers who use open access to move to another electricity supplier.
While Order No. 888 addresses electric sales at the wholesale level, many
states have implemented proceedings that seek to apply competitive concepts
outlined in Order No. 888 at the retail level. The PSC of MD has issued an
order calling on electric utilities to form discussion groups to develop retail
unbundling proposals for the commission's consideration in late 1997. The
implementation of Order No. 888 and any similar regulatory changes at the state
level should increase competition and, over time, tend to reduce prices to
consumers.
Industry Consolidation
Merger activity in the utility industry has increased as some companies choose
combination rather than independence as a way to reach more customers, to offer
more products and services, and to reduce costs. Consolidations will also
present combining entities with the challenges of remaining focused on the
customer and integrating different organizations. In the immediate vicinity of
the Company, the proposed merger of Baltimore Gas and Electric Company and
Potomac Electric Power Company is expected
9
<PAGE> 12
to affect the competitive environment in the Company's service territory.
GAS SUPPLY AND CAPACITY
The Company and Shenandoah arrange to have natural gas delivered to the entry
points of their distribution systems using the delivery capacity of interstate
pipeline companies. The Company acquires natural gas delivery capacity for
itself and Shenandoah on a system-wide basis because of the integrated nature
of the service agreements between the pipelines and the Company's consolidated
distribution operations. The Company's supply and 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.
Pursuant to FERC Order No. 636, the 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 prior to the implementation
of the order. The Company utilizes the delivery capacity of eight pipelines,
four of which connect directly to the Company's distribution system.
The Company has the responsibility of acquiring both sufficient gas supplies to
meet customer requirements and appropriate pipeline capacity to ensure delivery
to the Company's distribution system.
At the same time, and considering the continuing trend toward unbundling the
sale of the gas commodity from the delivery of the commodity to the customer,
the Company must ensure that it contracts for supply and capacity levels that
will allow it to remain competitive. The Company has adopted a diversified
portfolio approach designed to satisfy the supply and deliverability
requirements of its customers. The Company maintains numerous sources of
supply, dependable transportation and storage arrangements and its own
substantial storage and peaking capabilities to meet the demands of its
customers.
The Company has 13 long-term gas supply contracts with various producers or
marketers that expire between fiscal years 1998 and 2004 under which the
Company can purchase up to 102 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 1996, supplies were acquired from a combination of 62 producers or
marketers including volumes acquired under the 13 contracts discussed above.
As reflected in the first table on page 11, there were six sources of delivery
through which the Company received natural gas to satisfy the sendout
requirements in pipeline year 1996 (November 1, 1995 through October 31, 1996)
and from which supplies can be received in pipeline year 1997 (November 1, 1996
through October 31, 1997). 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: (1)
the local production of propane air from plants located at Company-owned
facilities in Rockville, Maryland and Ravensworth, Virginia; (2) underground
natural gas storage at the Hampshire storage field in Hampshire County, West
Virginia; and (3) other storage and peak-shaving arrangements.
During pipeline year 1996, total sendout on the system was 1,494 million
therms,
10
<PAGE> 13
excluding deliveries to electric generation facilities and volumes delivered to
customers that acquire their gas from others. The sendout for pipeline year
1997 is estimated to be 1,263 million therms (based on normal weather)
excluding deliveries for electric generation and volumes delivered for others.
The sources of delivery and related volumes that were used to satisfy the
requirements of pipeline year 1996 and those projected for pipeline year 1997
are shown in the following table.
SOURCES OF DELIVERY FOR
ANNUAL SENDOUT
(millions of therms)
<TABLE>
<CAPTION>
Actual Projected
Sources of Delivery Pipeline Year 1996 Pipeline Year 1997
---------------------------------- ------------------ ------------------
<S> <C> <C>
Firm Transportation 1,131 950
Transportation Storage 333 278
Interruptible Transportation 1 -
Hampshire Storage 17 18
Company-Owned Propane-Air Plants 5 4
Other Peak Shaving Sources 7 13
------ -----
1,494 1,263
====== =====
</TABLE>
The effectiveness of the Company's gas supply program is largely dependent on
the sources from which the design day requirement is satisfied. A design day is
the maximum anticipated demand on the gas supply system during a 24-hour period
assuming a 5 degree Fahrenheit average temperature. The Company assumes that
all interruptible customers will be curtailed on the design day. The Company's
design day estimate is currently 13.5 million therms. The Company is currently
capable of meeting 65% of its design day requirements with storage and peaking
capabilities. Emphasizing storage and peaking facilities on the Company's
design day reduces the necessity to purchase firm transportation, the most
expensive form of capacity from a design day perspective. The following table
reflects the sources of delivery that are projected to be used to satisfy the
design day sendout estimate for pipeline year 1997.
SOURCES OF DELIVERY FOR
DESIGN DAY SENDOUT
(millions of therms)
<TABLE>
<CAPTION>
Pipeline Year 1997
----------------------
Sources of Delivery Therms Percent
----------------------------------- ------ ----------
<S> <C> <C>
Firm Transportation 4.7 35%
Transportation Storage 4.6 34
Company-Owned Propane-Air Plants,
Hampshire Storage and Other Peaking 4.2 31
------ ------
13.5 100%
====== ======
</TABLE>
The Company believes the combination of the gas supply it can purchase under
short-term and long-term contracts, its peaking supplies, and the capacity on
the pipelines required to deliver the purchased supplies, is sufficient to
satisfy the needs of existing customers and allow for growth in future years.
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.
11
<PAGE> 14
Estimates of liabilities for environmental response costs are difficult to
determine with precision because of the factors that can affect their ultimate
level. These factors include, but are not limited to: (1) the complexity of the
site; (2) changes in environmental laws and regulations at the federal, state
and local levels; (3) the number of regulatory agencies or other parties
involved; (4) new technology that renders previous technology obsolete, or
experience with existing technology that proves ineffective; (5) the ultimate
selection of technology; (6) the level of remediation required; and (7)
variations between the estimated number of years that must be devoted to
respond to an environmentally contaminated site as compared to the actual
number of years required.
The Company has identified up to ten sites where the Company, its subsidiaries,
or their predecessors may have operated manufactured gas plants (MGPs). The
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. Studies and analytical work were performed during 1996 and
the project is scheduled to commence in fiscal year 1997, 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 and continue to be recovered from pumping. The Company will continue
to pump tar 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. The
Company has yet to receive any response from the state regarding its
submission. The Company expects to install a recovery system to recover free
tar beginning in fiscal year 1997 and will monitor the site.
At a fourth former MGP site and on an adjacent parcel of land, the Company
plans to perform additional studies and analytical work in fiscal year 1997 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 six 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, 1996, the Company had paid $9.0 million for environmental
response costs. A liability of $11.7 million on an undiscounted basis has been
recorded as of September 30, 1996 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.
12
<PAGE> 15
The maximum liability associated with these sites is estimated at $20.7 million
at September 30, 1996. The estimates were determined by the Company's
environmental experts based on experience in remediating MGP sites and advice
from legal counsel and environmental consultants. Variations within the range
of estimated liability result primarily from differences in the number of years
that will be required to perform environmental response processes at each site
(15 to 25 years) and differences in remediation 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.
OTHER
Revenue from the sale or delivery of natural gas as a percentage of
consolidated revenue was 97% for 1996 and 1995 and 96% for 1994. 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. Large
customers are generally on interruptible rate schedules and margin sharing
arrangements limit the effects of interruptible customer usage on net income.
As shown on page 2, the Company and Shenandoah had 772,281 customer meters at
September 30, 1996.
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 1996, 74% of
the therms delivered by the Company, excluding deliveries for electric
generation, occurred in the Company's first and second fiscal quarters. All of
the Company's earnings are generated in these two quarters and the Company
incurs losses in the third and fourth fiscal quarters. Results of operations
can be affected by the timing and level of approved rate increases. The
seasonal nature of the Company's business creates large variations in
short-term cash requirements, primarily due to fluctuations in the level of
customer accounts receivable and storage gas inventory levels. The Company
finances these seasonal requirements primarily through the sale of commercial
paper and short-term bank loans.
Through the cost of services provided by the interstate pipelines, the Company
and Shenandoah contribute to the funding of the Gas Research Institute. The
Institute's primary focus is devoted to developing more efficient gas equipment
and to increase the long-term supply of gas. The Company also belongs to the
Natural Gas Vehicle Coalition, 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 1996, 1995 and 1994 were not material.
As of September 30, 1996, the Company and its wholly-owned subsidiaries had
2,274 employees. This represents a decline of 131 employees from the level at
September 30, 1995, due primarily to continuing efforts to reduce the Company's
workforce through attrition. For a further discussion of labor-related issues,
refer to the caption entitled Labor Matters on page 37 of the 1996 Annual
Report to Shareholders, which is incorporated into this report 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
13
<PAGE> 16
as they expire.
As of September 30, 1996, the Company and its utility subsidiaries had 613
miles of transmission mains and 9,147 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 1997, 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.
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.
14
<PAGE> 17
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 44
Vice President (corporate strategy, investor relations
and internal audit) January 31, 1996
Treasurer May 1, 1993
Director of Marketing Services May 6, 1991
Patrick E. Clarke, Age 60 (2)
Senior Vice President (customer services and marketing) February 21, 1996
Senior Vice President - Customer Services and Marketing May 1, 1993
Vice President - Distribution and Marketing March 1, 1992
Vice President - Distribution September 6, 1984
Richard J. Cook, Age 54
Vice President (corporate engineering and environmental
quality assurance) October 1, 1996
Executive Assistant October 1, 1995
Director - Environment and Safety September 1, 1989
James H. DeGraffenreidt, Jr., Age 43
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
Richard L. Fisher, Age 49
Vice President (gas distribution) June 1, 1996
Executive Director May 3, 1993
Director - Federal Regulation and Gas Planning October 6, 1986
John K. Keane, Jr., Age 58
Senior Vice President and General Counsel May 1, 1993
Vice President and General Counsel September 1, 1990
Ronald C. King, Age 55
Vice President (customer services) February 21, 1996
Vice President - Customer Services November 1, 1991
Executive Director November 1, 1989
Frederic M. Kline, Age 45
Vice President and Treasurer January 31, 1996
Controller November 27, 1985
Patrick J. Maher, Age 60
Chairman of the Board and Chief Executive Officer November 24, 1992
President and Chief Executive Officer March 1, 1992
President October 1, 1987
Lisa M. Metcalfe, Age 32 (3)
Vice President and Chief Information Officer October 1, 1996
Wayne A. Mills, Age 53
Vice President (oversees Shenandoah, the Frederick division
of the Company and Washington Gas Energy Systems, Inc.) February 21, 1996
Vice President and General Manager - Maryland Division November 1, 1989
</TABLE>
15
<PAGE> 18
EXECUTIVE OFFICERS OF THE REGISTRANT (CONTINUED)
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- ------------------------------------------------------------ -----------------
<S> <C>
Douglas V. Pope, Age 51
Secretary July 25, 1979
Joseph M. Schepis, Age 43
Senior Vice President (gas supply, regulatory activities
and customer services) January 31, 1996
Senior Vice President and Chief Financial Officer December 15, 1994
Vice President - Rates and Regulatory Affairs May 1, 1993
Treasurer October 1, 1986
Roberta Willis Sims, Age 42
Vice President (corporate relations and communications) January 31, 1996
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
Robert A. Sykes, Age 48
Vice President (human resources) February 21, 1996
Vice President - Human Resources October 1, 1987
Robert E. Tuoriniemi, Age 40 (4)
Controller October 1, 1996
James B. White, Age 46
Vice President (business development) February 21, 1996
Vice President and General Manager - Virginia Division May 1, 1993
Director of Sales July 6, 1992
Director of Financial Relations May 6, 1991
</TABLE>
There is no family relationship among the officers. The age of each officer
listed is as of the date of filing.
(1) Each of the officers has served continuously since the dates indicated.
(2) Mr. Clarke will retire effective January 1, 1997.
(3) Ms. Metcalfe was previously employed by the National Wildlife Federation
and served most recently as Vice President of Constituent Systems and Services.
In this capacity, she was responsible for the organization's information
systems, telecommunications systems, facilities, and administrative services.
(4) Mr. Tuoriniemi was previously employed by Central Maine Power Company
(CMP), an electric utility, and served most recently as Comptroller. CMP has a
customer base of 515,000 customer meters. In the Comptroller position, Mr.
Tuoriniemi's responsibilities included all accounting matters, testifying
before regulatory commissions in rate case proceedings, directing tax planning
and coordinating financial reporting activities.
16
<PAGE> 19
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 60 of the Company's 1996 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into
this Item. Only owners of record are counted as common shareholders.
ITEM 6. SELECTED FINANCIAL DATA
Page 33 of the Company's 1996 Annual Report to Shareholders is included in
Exhibit 13 in this report and is incorporated by reference into this Item.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Pages 34 through 44 of the Company's 1996 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into
this Item.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pages 45 through 60 of the Company's 1996 Annual Report to Shareholders is
included in Exhibit 13 in this report and is incorporated by reference into
this Item.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning Directors contained in the definitive proxy statement
dated January 21, 1997, is hereby incorporated herein by reference.
Information related to Executive Officers is reflected in Part I hereof.
ITEM 11. EXECUTIVE COMPENSATION
The information captioned "Executive Compensation" in the definitive proxy
statement dated January 21, 1997, is hereby incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information captioned "Security Ownership of Certain Beneficial Owners and
Management" in the definitive proxy statement dated January 21, 1997, 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 1996.
17
<PAGE> 20
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
(a)1 All Financial Statements Pages in 1996
Annual Report to
Shareholders
Included in
Exhibit 13
-----------------
<S> <C>
Consolidated Statement of Income - for the years ended
September 30, 1996, 1995 and 1994 45
Consolidated Balance Sheet - as of September 30, 1996 and 1995 46
Consolidated Statement of Cash Flows - for the years ended
September 30, 1996, 1995 and 1994 47
Consolidated Statement of Capitalization - as of September 30,
1996 and 1995 48
Consolidated Statement of Common Shareholders' Equity -
1996, 1995 and 1994 49
Consolidated Statement of Income Taxes - for the years ended
September 30, 1996, 1995 and 1994 and as of September 30, 1996
and 1995 50
Notes to Consolidated Financial Statements 51-58
Report of Independent Public Accountants 59
(a)2 Financial Statement Schedules
</TABLE>
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.
Schedule II, listed on page 19, should be read in conjunction with the
financial statements in the 1996 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.
18
<PAGE> 21
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
<TABLE>
<CAPTION>
Pages in
Schedule Description 10-K
- -------- ----------------------------------------------------------------------------------- ---------
<S> <C> <C>
II Valuation and Qualifying Accounts and Reserves for the
years ended September 30, 1996, 1995 and 1994 23-24
(a)-3 Exhibits
Exhibits Filed Herewith:
Pages in
Description 10-K
----------- ---------
3. Articles of Incorporation and Bylaws - See
Separate
Bylaws of the Company as amended on Volume
October 30, 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
12 Statement re Computation of Ratios -
12.0 Computation of Ratio of Earnings to Fixed Charges
12.1 Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends
13. Annual Report to Security Holders -
1996 Annual Report to Shareholders (except for
the information presented on the front and rear
covers and pages 1 through 32, which are not
deemed to be filed with the Securities and
Exchange Commission for the purposes of the
Securities Exchange Act of 1934)
21. Subsidiaries of the Registrant
23. Consents of Experts and Counsel
27. Financial Data Schedule
Exhibits Incorporated by Reference:
Description
-----------
3. Articles of Incorporation and Bylaws
Company Charter, filed on Form S-3 dated July 21, 1995
</TABLE>
19
<PAGE> 22
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
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.
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.
20
<PAGE> 23
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
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.
Retirement Plan for Outside Directors, as
amended on October 25, 1995 and filed on
Form 10-K for the fiscal year ended
September 30, 1995 *
Directors' Stock Compensation Plan, as
adopted on October 25, 1995 and filed on
Form 10-K for the fiscal year ended
September 30, 1995 *
Supplemental Executive Retirement Plan, as
amended on October 25, 1995 and filed on
Form 10-K for the fiscal year ended
September 30, 1995 *
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
1996.
21
<PAGE> 24
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To the Shareholders and Board of Directors of Washington Gas Light Company:
We have audited in accordance with generally accepted auditing standards,
the financial statements included in Washington Gas Light Company's annual
report to shareholders incorporated by reference in this Form 10-K, and have
issued our report thereon dated October 28, 1996. 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 19 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 28, 1996.
22
<PAGE> 25
SCHEDULE II
Page 1 of 2
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1996, 1995 and 1994
<TABLE>
<CAPTION>
Additions
Charged to
Balance at --------------------- Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deduction (C) of Period
- ----------------------------------------------- ----------- ---------- -------- ------------- ---------
(Thousands)
<S> <C> <C> <C> <C> <C>
1996
- ----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet -
Allowance for doubtful accounts $ 10,580 $ 7,752 $ 2,070 (A) $ 8,556 $ 11,846
Provision for impairment of investments
and other deferred charges 5,397 1,150 - 40 6,507
Reserves -
Injuries and damages 11,873 2,409 1,845 (B) 6,835 9,292
Other 900 - - - 900
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
</TABLE>
NOTES: See Page 2 of 2.
23
<PAGE> 26
SCHEDULE II
Page 2 of 2
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1996, 1995 and 1994
<TABLE>
<CAPTION>
Additions
Charged to
Balance at --------------------- Balance
Beginning Costs and Other at End
Description of Period Expenses Accounts Deduction (C) of Period
- ----------------------------------------------- ----------- ---------- -------- ------------- ---------
(Thousands)
<S> <C> <C> <C> <C> <C>
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 (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.
24
<PAGE> 27
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 18, 1996 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 12/18/96
----------------------------- and Chief Executive -----------
(Patrick J. Maher) Officer and Director
JAMES H. DEGRAFFENREIDT, JR. President and Chief 12/18/96
-------------------------------- Operating Officer and -----------
(James H. DeGraffenreidt, Jr.) Director
FREDERIC M. KLINE Vice President and 12/18/96
-------------------------------- Treasurer -----------
(Frederic M. Kline) (Principal Financial Officer)
ROBERT E. TUORINIEMI Controller 12/18/96
-------------------------------- (Principal Accounting Officer) -----------
(Robert E. Tuoriniemi)
MICHAEL D. BARNES Director 12/18/96
-------------------------------- -----------
(Michael D. Barnes)
FRED J. BRINKMAN Director 12/18/96
-------------------------------- -----------
(Fred J. Brinkman)
DANIEL J. CALLAHAN, III Director 12/18/96
-------------------------------- -----------
(Daniel J. Callahan, III)
ORLANDO W. DARDEN Director 12/18/96
-------------------------------- -----------
(Orlando W. Darden)
MELVYN J. ESTRIN Director 12/18/96
-------------------------------- -----------
(Melvyn J. Estrin)
KAREN HASTIE WILLIAMS Director 12/18/96
-------------------------------- -----------
(Karen Hastie Williams)
STEPHEN G. YEONAS Director 12/18/96
-------------------------------- -----------
(Stephen G. Yeonas)
</TABLE>
25
<PAGE> 28
Washington Gas Light Company
1996 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 30, 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
12 Statement re Computation of Ratios -
12.0 Computation of Ratio of Earnings to Fixed Charges
12.1 Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends
13. Annual Report to Security Holders -
1996 Annual Report to Shareholders (except for
the information presented on the front and rear
covers and pages 1 through 32, which are not
deemed to be filed with the Securities and
Exchange Commission for the purposes of the
Securities Exchange Act of 1934)
21. Subsidiaries of the Registrant
23. Consents of Experts and Counsel
27. Financial Data Schedule
</TABLE>
<PAGE> 1
EXHIBIT 3
WASHINGTON GAS LIGHT COMPANY As Amended
BYLAWS on 10/30/96
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 Friday in the month of February in each year, at 10:00 a.m., at the
Willard Inter-Continental Hotel, 1401 Pennsylvania Avenue, 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.
1
<PAGE> 2
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 Company on the record date fixed as
provided in these Bylaws. In
2
<PAGE> 3
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.
3
<PAGE> 4
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:
4
<PAGE> 5
Requirement of Timely Notice. For business to be
properly brought before a meeting of stockholders by a
stockholder, the business shall be a proper subject of
stockholder action and the stockholder shall have given timely
notice thereof in writing to the Secretary. To be timely, a
stockholder's notice shall be delivered to or mailed and
received by the Secretary at the principal executive office of
the Company not less than sixty (60) days prior to the
scheduled date of the meeting (regardless of any
postponements, deferrals or adjournments of the meeting to a
later date); provided, however, if no notice is given and no
public announcement is made to the stockholders regarding the
date of the meeting at least 75 days prior to the meeting, the
stockholder's notice shall be valid if delivered to or mailed
and received by the Secretary at the principal executive
office of the Company not less than fifteen (15) days
following the day on which the notice or public announcement
of the date of the meeting was given or made.
Contents of Notice. Such stockholder's notice to the
Secretary shall set forth as to each item of business the
stockholder proposes to bring before the meeting (1) a brief
description of the business desired to be brought before the
meeting, the reasons for conducting such business at the
meeting and, in the event that such business includes a
proposal to amend either the Charter or these Bylaws, the
language of the proposed amendment, (2) the name and address,
5
<PAGE> 6
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 which may have been commenced in any court
of competent jurisdiction for an adjudication of any legal
issues incident
6
<PAGE> 7
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 nine 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.
7
<PAGE> 8
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.
8
<PAGE> 9
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 of the person, (b) the principal
occupation or employment
9
<PAGE> 10
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
10
<PAGE> 11
(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.
SECTION 3. Vacancies. Whenever any vacancy shall occur in
11
<PAGE> 12
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 serve at the call of the Chief Executive
Officer in case of the unavoidable absence of one of the regular members, to be
elected
12
<PAGE> 13
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 by which such director was elected)
entitled to vote thereon, at a special meeting of stockholders called for such
purpose.
ARTICLE III
13
<PAGE> 14
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 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
14
<PAGE> 15
senior member of the Board present, in terms of service on the Board, shall
serve as Chairman pro tem of the meeting.
SECTION 4. Salaries. The salaries of all executive officers
of the Company shall be determined and fixed by the Board of Directors, or
pursuant to such authority as the Board may from time to time prescribe.
ARTICLE III-A
Indemnification of Directors and Officers.
SECTION 1. With respect to a Company officer, director, or
employee, the Company shall indemnify, and with respect to any other individual
the Company may indemnify, any person who was or is a party or is threatened to
be made a party to any threatened, pending or completed action, suit or
proceeding (an "Action"), whether civil, criminal, administrative, arbitrative
or investigative (including an action by or in the right of the Company) by
reason of the fact the person is or was a director, officer, employee, or agent
of the Company, or is or was serving at the request of the Company as a
director, officer, employee, or agent of another corporation, partnership,
joint venture, trust or other enterprise, against expenses (including
attorneys' fees), judgments, fines and amounts paid in settlement actually and
reasonably incurred by that person in connection with such Action; except in
relation to matters as to which the person shall be finally adjudged in such
Action to have 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
15
<PAGE> 16
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 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
16
<PAGE> 17
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.
17
<PAGE> 18
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.
18
<PAGE> 19
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.
19
<PAGE> 20
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,
20
<PAGE> 21
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 shall have the
power from time to time to establish general
21
<PAGE> 22
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
22
<PAGE> 23
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.
23
<PAGE> 24
CERTIFICATE OF SECRETARY
OF
WASHINGTON GAS LIGHT COMPANY
I, DOUGLAS V. POPE, Secretary of WASHINGTON GAS LIGHT COMPANY,
DO HEREBY CERTIFY, that attached is a currently effective copy of the Bylaws of
Washington Gas Light Company.
IN WITNESS WHEREOF, I have hereunto set my hand and the seal
of Washington Gas Light Company this day of , 19 .
-----------------------------------
Secretary
24
<PAGE> 1
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
------------------------------
1996 1995 1994
-------- -------- --------
(Thousands, except per share data)
<S> <C> <C> <C>
EARNINGS PER AVERAGE SHARE ASSUMING FULL DILUTION
- -------------------------------------------------
Net Income $ 81,591 $ 62,909 $ 60,459
Dividends on preferred stock (excluding
dividends on convertible preferred
stock) 1,320 1,320 1,320
-------- -------- --------
Net income applicable to common stock $ 80,271 $ 61,589 $ 59,139
======== ======== ========
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 43,391 42,609 41,876
======== ========= ========
Earnings per average share of common stock
assuming full dilution $ 1.85 $ 1.45 $ 1.41
======== ========= ========
</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.
<PAGE> 1
EXHIBIT 12.0
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
YEARS ENDED SEPTEMBER 30
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
--------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 29,876 $ 30,932 $ 30,899 $ 27,872 $ 27,386
Amortization of Debt Premium,
Discount and Expense 256 315 367 410 358
Interest Component of Rentals 96 56 34 94 42
--------- -------- -------- -------- --------
Total Fixed Charges $ 30,228 $ 31,303 $ 31,300 $ 28,376 $ 27,786
========= ======== ======== ======== ========
EARNINGS:
Net Income $ 81,591 $ 62,909 $ 60,459 $ 55,079 $ 52,213
Add:
Income Taxes Applicable to
Operating Income 49,376 37,514 37,264 34,601 31,483
Income Taxes Applicable to
Other Income (Loss) - Net (629) (730) 326 (1,479) (694)
Total Fixed Charges 30,228 31,303 31,300 28,376 27,786
--------- -------- -------- -------- --------
Total Earnings $ 160,566 $130,996 $129,349 $116,577 $110,788
========= ======== ======== ======== ========
Ratio of Earnings to Fixed
Charges 5.3 4.2 4.1 4.1 4.0
========= ======== ======== ======== ========
</TABLE>
<PAGE> 1
EXHIBIT 12.1
WASHINGTON GAS LIGHT COMPANY AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges and
Preferred Stock Dividends
Years Ended September 30
(Dollars in Thousands)
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
------------ ----------- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 29,876 $ 30,932 $ 30,899 $ 27,872 $ 27,386
Amortization of Debt Premium,
Discount and Expense 256 315 367 410 358
Interest Component of Rentals 96 56 34 94 42
------------ ----------- --------- -------- ---------
Total Fixed Charges 30,228 31,303 31,300 28,376 27,786
Pre-tax Preferred Dividends 2,128 2,113 2,165 2,139 2,127
------------ ----------- --------- -------- ---------
Total $ 32,356 $ 33,416 $ 33,465 $ 30,515 $ 29,913
============ =========== ========= ======== =========
Preferred Dividends $ 1,332 $ 1,333 $ 1,335 $ 1,336 $ 1,338
Effective Income Tax Rate .3740 .3690 .3834 .3755 .3709
Complement of Effective Income
Tax Rate (1 - Tax Rate) .6260 .6310 .6166 .6245 .6291
Pre-tax Preferred Dividends $ 2,128 $ 2,113 $ 2,165 $ 2,139 $ 2,127
============ =========== ========= ======== =========
EARNINGS:
Net Income $ 81,591 $ 62,909 $ 60,459 $ 55,079 $ 52,213
Add:
Income Taxes Applicable to
Operating Income 49,376 37,514 37,264 34,601 31,483
Income Taxes Applicable to
Other Income (Loss) - Net (629) (730) 326 (1,479) (694)
Total Fixed Charges 30,228 31,303 31,300 28,376 27,786
------------ ----------- --------- -------- ---------
Total Earnings $ 160,566 $ 130,996 $ 129,349 $ 116,577 $ 110,788
============ =========== ========= ======== =========
Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends 5.0 3.9 3.9 3.8 3.7
============ =========== ========= ======== =========
</TABLE>
<PAGE> 1
SELECTED FINANCIAL DATA
Washington Gas Light Company
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands, Execept Per Share Data)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 969,778 $ 828,748 $ 914,863 $ 894,300 $ 746,224
Cost of gas 469,925 390,041 462,195 478,982 352,686
---------- ---------- ---------- ------------ -----------
Net revenues $ 499,853 $ 438,707 $ 452,668 $ 415,318 $ 393,538
---------- ---------- ---------- ------------ -----------
Net income $ 81,591 $ 62,909 $ 60,459 $ 55,079 $ 52,213
Dividends on preferred stock 1,332 1,333 1,335 1,336 1,338
---------- ---------- ---------- ------------ -----------
Net income applicable to common stock $ 80,259 $ 61,576 $ 59,124 $ 53,743 $ 50,875
---------- ---------- ---------- ------------ -----------
Earnings per average share of common stock $ 1.85 $ 1.45 $ 1.41 $ 1.31 $ 1.26
---------- ---------- ---------- ------------ -----------
Total assets at year-end $1,464,601 $1,360,138 $1,332,954 $ 1,205,788 $ 1,065,732
---------- ---------- ---------- ------------ -----------
Long-term obligations at year-end $ 353,893 $ 329,051 $ 342,308 $ 347,884 $ 296,357
---------- ---------- ---------- ------------ -----------
COMMON STOCK DATA
Annualized dividends per share $ 1.14 $ 1.12 $ 1.11 $ 1.09 $ 1.07
Dividends declared per share $ 1.135 $ 1.1175 $ 1.105 $ 1.085 $ 1.065
Book value per share $ 12.79 $ 11.95 $ 11.51 $ 11.04 $ 10.66
Return on average common equity 15.0% 12.3% 12.5% 12.1% 12.0%
Yield on book value 8.9% 9.4% 9.6% 9.8% 10.0%
Payout ratio 61.4% 77.1% 78.4% 82.8% 84.5%
Common shares outstanding--
year-end (thousands) 43,703 42,932 42,187 41,495 40,616
CAPITALIZATION AT YEAR-END
Common shareholders' equity $ 558,809 $ 513,044 $ 485,504 $ 458,044 $ 433,121
Preferred stock 28,440 28,471 28,498 28,521 28,552
Long-term debt 353,893 329,051 342,270 347,701 294,451
---------- ---------- ---------- ------------ -----------
Total $ 941,142 $ 870,566 $ 856,272 $ 834,266 $ 756,124
---------- ---------- ---------- ------------ -----------
GAS SALES & DELIVERIES (thousands of therms)
Gas sold and delivered
Residential 739,603 596,499 672,958 641,529 603,952
Commercial and industrial--
Firm 473,645 403,177 443,246 422,977 406,218
Interruptible 182,730 247,600 236,068 258,433 255,880
Electric generation 1,808 112,523 86,183 35,447 73,485
---------- ---------- ---------- ------------ -----------
1,397,786 1,359,799 1,438,455 1,358,386 1,339,535
---------- ---------- ---------- ------------ -----------
Gas delivered for others
Firm 3,772 - - - -
Interruptible 84,788 61,467 26,147 16,699 13,264
Electric generation 57,689 18,538 - - -
---------- ---------- ---------- ------------ -----------
146,249 80,005 26,147 16,699 13,264
---------- ---------- ---------- ------------ -----------
Total 1,544,035 1,439,804 1,464,602 1,375,085 1,352,799
---------- ---------- ---------- ------------ -----------
GAS SOLD OFF SYSTEM (thousands of therms) 40,510 - - - -
OTHER STATISTICS
Customer meters 772,281 750,849 725,960 703,122 683,277
Degree days 4,570 3,660 4,311 4,246 3,946
Percent colder (warmer)
than normal 18.6% (5.2)% 11.8% 10.1% 1.8%
Capital expenditures $ 124,414 $ 112,715 $ 119,796 $ 100,778 $ 88,182
</TABLE>
33
<PAGE> 2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements contained in this Management's Discussion and Analysis that are not
based on historical facts are forward-looking statements as defined in the
Private Securities Litigation Reform Act of 1995. Actual results could differ
from the expectations discussed herein.
Factors that could cause actual results to differ from management's beliefs
described in this report include, among other matters: (i) the effect of
fluctuations in weather from normal levels; (ii) regulatory and legislative
changes; (iii) variations in prices of natural gas and competing energy
sources; (iv) improvements in products or services offered by competitors; and
(v) changing economic conditions.
COMPETITION
SOURCES OF COMPETITION
The most significant competition Washington Gas Light Company (company) faces
continues to be between natural gas and electricity in the residential market,
which contributes a substantial 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, where customers must be capable
of using a fuel other than natural gas when demand by firm customers peaks,
fuel oil is the most significant competing energy alternative. The company's
success in this market is largely dependent on changes in the price of gas
versus the price of oil.
While the company has historically faced competitive pressures from other
energy sources, it is experiencing added competitive pressures within the gas
industry and will be impacted by changes expected to take place in the electric
industry. The effect of these matters on the company's competitive position is
discussed further below.
NATURAL GAS INDUSTRY DEREGULATION
The natural gas industry, which has traditionally included producers,
interstate pipelines and local distribution companies (LDCs) such as the
company, has a long history and has undergone many changes since its inception.
Perhaps no greater changes have taken place than those that have been
experienced over the past 10 years. These changes have generally been in
response to desires for deregulation that promote competition in situations
where it is economically beneficial to consumers. The changes continue while
the pace of change for LDCs is accelerating.
The restructuring of the natural gas industry generally began at the producer
level with the passage of the Natural Gas Policy Act in 1978, which brought
about a gradual decontrol of the wellhead price of natural gas and allowed for
market-based prices. In the pipeline segment of the industry, Federal Energy
Regulatory Commission (FERC) Order No. 636 separated the merchant function of
selling natural gas from the interstate transportation and storage services of
the pipeline companies. This separation, or as it is oftentimes called,
"unbundling," of the traditional pipeline services of transporting and storing
natural gas from the sale of natural gas was done in order to increase
competition. As a result of this order, the pipeline companies are responsible
for providing gas storage and transportation services, and LDCs have taken on
the responsibility and risk of separately procuring storage and transportation
capacity from the pipelines and marketers, and competitive natural gas supplies
from producers and marketers. The rates charged by the pipelines for
transmission and storage are still regulated by FERC, but negotiated,
market-based rates are beginning to appear.
As an LDC, the company is undergoing changes similar to those already
experienced by producers and pipelines. Historically, the company charged its
customers one rate for the cost it paid pipelines for natural gas delivered to
the entry point at its gas distribution system and the costs it incurred to
deliver natural gas to the customers' premises. And, although the company
continues to generate the overwhelming majority of its revenues from the sale
and delivery of natural gas on a combined or bundled basis, state regulatory
and company initiatives are seeking to separate or unbundle the rates charged
to customers for the natural gas commodity ("city gate supply service") from
rates charged for delivery of gas on the company's distribution system
("delivery service"). Unbundling the sale of the natural gas commodity allows
other gas utilities and marketers the opportunity to gain access to the
company's customers, resulting in increased competition for that portion of the
company's business.
The company does not expect most delivery service components to become subject
to competition because of the economic disincentives to construct duplicate
facilities. Although delivery service is likely to remain regulated, it will
undergo greater scrutiny as unbundling occurs and customers see greater
information of the charges on their bills. Bypass of the company's facilities
by other potential providers of delivery service is not considered a
significant threat because of the nature of the company's customer base and the
location of the customers in relation to the interstate pipelines.
The company supports the move to unbundle city gate supply service from
delivery service which maximizes choices for its customers. In the past, the
company generally could not make profits or incur losses from the sale of
natural gas. The cost of the natural gas commodity was simply a pass-through to
its customers. In one jurisdiction in which it operates, the separation of the
city gate supply service charge from the delivery service charge has provided
the company the opportunity to
34
<PAGE> 3
make profits or the chance to incur losses from the sale of natural gas.
The company believes it will ultimately transition to fully deregulated,
competitive city gate supply service for all customers. However, only a
relatively small portion of customers is currently eligible to choose their
supplier of that service. Accordingly, the level of profits recorded to date
has not been material. The complete transition in all jurisdictions to fully
competitive city gate supply service to all customer classes could take several
years.
Currently, some states have instituted initiatives to further extend the
benefits of competition to the consumer. These include performance-based
regulation for gas cost recovery by LDCs and a greater focus on incentive
regulation or basing cost recovery on external measures of efficiency.
Depending on the circumstances in the jurisdictions in which the company
operates, some of these types of alternatives could be initiated on an interim
basis before city gate supply service is fully implemented.
In response to the changing competitive situation, the company has had to
assess the nature of its business and explore alternatives to the traditional
role of purchase, transport and sale of natural gas. The company anticipates
that opportunities for non-regulated sales will increase as competition
intensifies and as unbundling initiatives further expand. The company is
desirous of maximizing the number of product offerings that it can make to its
customer base. This will require the company to develop new products and
services that its customers value at a profitable price relative to various
alternatives.
In order to capitalize on potential profits from offering unregulated city gate
supply service, the company's non-utility subsidiary, Washington Gas Energy
Services (WGES), has entered the natural gas sales market in direct competition
with other gas utilities and marketers. Additionally, WGES competes with oil
marketers and, having received a power certificate from the FERC, plans to
market electricity in the near future. Other energy services offered by WGES
and another non-utility subsidiary include the design and installation of
energy equipment as well as heating and air conditioning inspections on both
gas and electric equipment.
The significant level of change in energy markets provides both opportunities
and challenges to the company over the next several years. Important factors to
the company's success include, among others: (i) its ability to ensure it has
access to a supply of natural gas and pipeline capacity at competitive prices;
(ii) its ability to quickly react to changing market conditions; and (iii) the
timing and extent of access to its markets by other competitors.
UNBUNDLING IN THE COMPANY'S MAJOR JURISDICTIONS
Unbundling initiatives have progressed furthest in Maryland. Currently,
competitive natural gas supply options are available in Maryland for all
interruptible customers, and certain firm commercial and residential customers.
The program for residential customers, effective November 1, 1996, is being
administered under a pilot program whereby up to 6,600 customers (2% of
Maryland residential customers) can choose from among four suppliers of gas,
including the company. Depending on the company's success, these options
provide the opportunity to earn a profit or the chance of a loss on the sale of
gas, in addition to the revenues historically generated from the delivery of
gas.
In Virginia, the company has filed with the State Corporation Commission of
Virginia (SCC of VA) to expand the eligible base of interruptible customers who
could purchase gas from third-party suppliers, including WGES, the company's
unregulated subsidiary. A decision by the Commission is expected in 1997.
In the District of Columbia, the company has filed tariff proposals with the
Public Service Commission of the District of Columbia (PSC of DC) to expand the
number of interruptible and large commercial customers eligible to purchase gas
from third-party suppliers. Also proposed is a two-year pilot program that
would allow third-party gas sales to a limited group of residential customers.
The PSC of DC has held hearings to address each of the company's proposals and
a decision is expected in 1997.
ELECTRIC INDUSTRY DEREGULATION
The movement toward deregulation in the electric industry has implications for
the gas industry. The Energy Policy Act of 1992 allowed unregulated independent
power producers to sell power to wholesale customers in competition with
regulated electric utilities. In April 1996, the FERC issued Order No. 888,
that is intended to further increase competition within the electric industry
beginning in 1998.
Order No. 888 addresses open access and stranded cost issues. Open access
provisions stimulate wholesale electric power sales competition by requiring
public utilities that own, control or operate electric transmission lines to
file non-discriminatory tariffs that offer others the same transmission
services they provide themselves, under comparable terms and conditions. These
utilities must also use these tariffs for their own wholesale energy sales and
purchases. The order also provides that stranded costs, the unrecovered costs
incurred by electric utilities in anticipation of continued service to their
customers, are eligible for recovery, under certain terms and conditions, from
customers who use open access to move to another electricity supplier.
While Order No. 888 addresses electric sales at the wholesale level, many
states have implemented proceedings that seek to apply competitive concepts
outlined in Order No. 888 at the retail level. The Public Service Commission of
Maryland (PSC of MD) has issued an order calling on electric utilities to form
discussion groups to develop retail unbundling proposals for the commission's
consideration in late 1997. The implementation of Order No. 888 and any similar
regulatory changes at the state level should increase competition and, over
time, tend to reduce prices to consumers.
INDUSTRY CONSOLIDATION
Merger activity in the utility industry has increased as some companies choose
combination rather than
35
<PAGE> 4
independence as a way to reach more customers, to offer more products and
services, and to reduce costs. Consolidations will also present combining
entities with the challenges of remaining focused on the customer and
integrating different organizations. In the immediate vicinity of the company,
the proposed merger of Baltimore Gas and Electric Company and Potomac Electric
Power Company is expected to affect the competitive environment in the
company's service territory.
ACCOUNTING FOR REGULATED
ACTIVITIES
As the industry continues to address changes that have the effect of increasing
the level of competition the company faces, the cost-of-service regulation the
company uses to ensure it is adequately compensated for the costs it has
incurred in the provision of its regulated services will continue to evolve.
Non-traditional ratemaking initiatives and market-based pricing of products and
services could have additional financial implications for the company. The
company accounts for its regulated activities in accordance with Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71). In certain circumstances, SFAS No. 71
allows entities whose rates are determined by third-party regulators to defer
costs as "regulatory" assets in the balance sheet to the extent that they are
expected to be recovered in future rates. However, as competition increases and
the company becomes more subject to the impact of deregulation and the
attendant effects that it brings, the company may not be able to continue to
apply SFAS No. 71 to all or parts of its business. If this were to occur, the
company would be required to apply accounting standards utilized by unregulated
enterprises. This would require the charging to expense, at the time the
company determined the provisions of SFAS No. 71 no longer apply, 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.
While the company believes the provisions of SFAS No. 71 continue to apply to
its regulated operations, the changing nature of its business requires
continual assessment of the impact of those changes on its accounting policies.
ORGANIZATIONAL REDESIGN
In response to the changing requirements faced in the enhanced competitive
markets in which it operates, the company has undertaken significant efforts to
align its organization to meet the challenges it faces. In June 1996, the
company announced a redesigned organizational structure and the process under
which the new organizational structure would be staffed.
The company has moved away from a traditional, functional structure and adopted
a more customer-focused organization designed to encourage innovation,
initiative and teamwork. The new structure, which is expected to be in place by
December 31, 1996, flattens the corporate hierarchy and results in fewer
supervisory positions.
In the initial stage of the reorganization, the company offered certain
eligible supervisory employees a voluntary separation pay program which
entitles these employees to a year of salary upon reaching their separation
date. In the staffing phase of the reorganization process, most management
positions are being filled through a competitive bidding and selection process.
In fiscal year 1996, the company recorded nonrecurring charges of $13.4
million, representing the estimated expenses associated with this
reorganization.
GAS SUPPLY AND CAPACITY
The company has the responsibility of acquiring both sufficient gas supplies to
meet customer requirements and appropriate pipeline capacity to ensure delivery
to the company's distribution system.
At the same time, and considering the continuing trend toward unbundling the
sale of the gas commodity from the delivery of the commodity to the customer,
the company must ensure that it contracts for supply and capacity levels that
will allow it to remain competitive. The company has adopted a diversified
portfolio approach designed to satisfy the supply and deliverability
requirements of its customers. The company maintains numerous sources of
supply, dependable transportation and storage arrangements and its own
substantial storage and peaking capabilities to meet the demands of its
customers.
The company has 13 long-term gas supply contracts with various producers or
marketers that expire between fiscal years 1998 and 2004 under which the
company can purchase up to 102 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 1996, supplies were acquired from a combination of 62 producers or
marketers including volumes acquired under the 13 contracts discussed above.
Of the anticipated annual sendout, 75% is expected to be delivered under
contracts with pipelines for firm transportation, 22% will be delivered from
pipelines under contracts for storage on their transportation system 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 four 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 2015.
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
36
<PAGE> 5
company charges its customers, subject to regulatory review. Each of the
jurisdictions in which the company operates has a purchased gas adjustment
clause in its tariffs that provides for the adjustment of rates charged to firm
customers as gas costs rise or fall from a stipulated base gas cost. The
company believes that its gas contracts were prudently entered into and the
costs being incurred should be recoverable from customers. If the current
purchased gas adjustment clauses are removed in the future as part of
unbundling or other initiatives, the company could be impacted to the extent
its gas costs are not competitive and there are no other satisfactory
regulatory mechanisms available to recover any costs that would exceed market
prices. 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 8 to
the Consolidated Financial Statements.
LABOR MATTERS
The company has three unions that represent five "bargaining units" or groups
of employees at the company and its subsidiaries. The three unions are the
Office and Professional Employees International Union Local No. 2, the
International Brotherhood of Electrical Workers Local 1900, and the
International Brotherhood of Teamsters (IBT) Local 96. IBT Local 96 was
formerly known as the International Union of Gas Workers (IUGW) and it
represents workers separately at the company and at its subsidiary, Shenandoah
Gas Company. The members of IUGW affiliated with the IBT in July 1996. In
fiscal year 1995, the company signed new labor contracts with all of these
bargaining units except the IBT Local 96 bargaining unit at the parent company.
On May 31, 1995, a three-year labor agreement between the parent company and
the approximately 1,050 member bargaining unit of what is currently IBT Local
96 expired. IBT Local 96 currently represents 930 employees or 41% 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 the
bargaining process but the membership of IUGW voted to reject these offers. On
September 25, 1995, after negotiations between the company and 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. All eligible employees returned to work.
Employees represented by IUGW (now IBT Local 96) have been working
productively under the terms and conditions of the company's final contract
offer, as amended, since September 1995. The National Labor Relations Board
(NLRB) has ruled in favor of the company three separate times on charges of
unfair labor practices brought by IUGW, including a decision on April 29, 1996
by the Office of Appeals of the NLRB to dismiss IUGW's appeal, with no further
right of appeal.
In October 1996, the company invited the bargaining unit, now represented by
IBT Local 96, to resume negotiations. IBT Local 96 accepted the invitation and
the parties have commenced discussions. Since the company had not reached an
agreement with IBT Local 96 as of November 21, 1996, a 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, the company is prepared to maintain operations.
RESULTS OF OPERATIONS
EARNINGS
1996 VS. 1995. Net income applicable to common stock for 1996 was $80.3
million, which was $18.7 million higher than the results for 1995. Weather
during 1996 was substantially colder than the prior year, measuring 24.9%
colder than 1995. The colder weather and a 2.9% increase in the number of
customer meters resulted in a significant increase in firm therm sales and net
revenues. Also contributing to the increase in net income was the effect of
reduced interest expense. The positive impact of the colder weather was
partially offset by increased other operating expenses, which included expenses
amounting to $13.4 million applicable to estimated costs associated with the
redesign of the company's organization, and lower other income (loss) -net.
Earnings per average common share were $1.85, or $.40 higher than 1995. Average
common shares outstanding increased by 1.8%. The company earned 15.0% on
average common equity in 1996 compared to 12.3% in 1995.
EARNINGS PER AVERAGE COMMON SHARE
[GRAPH]
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, which was 15.1% warmer than
the prior year, resulted in lower firm therm sales and lower net revenues, and
was almost completely offset by the combined effect of a 3.4% increase in
customer meters, increased retail rates and lower other
37
<PAGE> 6
operating expenses. Other income (loss)-net improved by $2.3 million, and
included 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 compared to 12.5% in
1994.
NET REVENUES
Net revenues increased by $61.1 million, or 13.9%, in 1996 and declined by
$14.0 million, or 3.1%, in 1995. The factors contributing to the changes in
net revenues between years are provided in the following table and the
discussion below. The level of gas sold and delivered to firm customers 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. The company's rates are based on normal weather. A comparison of
weather to normal for 1992 to 1996 is shown in the Selected Financial Data on
page 33. 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
1996 1995
- ------------------------------------------------------------
(Millions)
<S> <C> <C>
Gas Sold and Delivered to
Firm Customers:
Volumes $ 56.5 $ (27.5)
Rate Increases 2.7 19.3
Gas Delivered to
Interruptible Customers (1.8) .8
Gross Receipts Taxes (.7) (4.6)
Other 4.4 (2.0)
------------ ------------
$ 61.1 $ (14.0)
============ ============
</TABLE>
1996 VS. 1995.
GAS SOLD AND DELIVERED TO FIRM CUSTOMERS
Therm sales to firm customers rose by 213.6 million therms (21.4%) in 1996,
causing net revenues to rise by $56.5 million. The significant increase was due
to the previously discussed colder weather in 1996 and a 2.9% increase in firm
customer meters.
The impact of increased rates on net revenues for 1996 was $2.7 million. The
increase was due to the effect of higher rates granted in the State of Maryland
in December 1994 that were not fully reflected in net revenues for fiscal year
1995 and amounts granted Shenandoah Gas Company, a distribution subsidiary.
The company had no rate requests outstanding in any of its major jurisdictions
at September 30, 1996.
GAS DELIVERED TO INTERRUPTIBLE CUSTOMERS
Interruptible customers are required under contract to be capable of using an
alternate fuel as a substitute for natural gas when the company determines
their service must be curtailed to accommodate firm customers' needs during
periods of peak demand. Nearly all of 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 these customers for delivering natural gas on its
distribution system.
Therms delivered to interruptible customers declined by 41.5 million therms
when compared to 1995. The decrease was due primarily to significantly longer
interruptions in service to these customers in the first and second fiscal
quarters of 1996 due to the sharply colder weather. Net revenues associated
with therms delivered to this customer class declined by $1.8 million.
In the District of Columbia and the Commonwealth of Virginia, the effect on net
income of changes in delivered volumes and prices to the interruptible class is
minimized by margin sharing arrangements that are part of the design of the
company's rates. To date, these arrangements have provided for a return to
firm customers of the majority of the gross margins earned on such sales or
deliveries after a gross margin threshold is reached or in exchange for the
shift of a portion of the fixed costs of providing service from the
interruptible to the firm class.
NET INCOME APPLICABLE TO COMMON STOCK
[GRAPH]
In the Maryland jurisdiction, as a result of unbundling initiatives, all
interruptible customers became delivery service customers and must elect
whether to buy gas from the company or a third-party supplier, but will
continue to use the company's distribution system for delivery of their supply.
The vast majority of the revenues from the delivery of gas to interruptible
customers, whether purchased from the company or from a third-party supplier,
are being returned to firm customers, after a gross margin threshold is
reached. Recognizing the increased competition in making gas sales to
interruptible customers, margins earned from gas sales made by the company are
being shared equally between firm customers and the company.
GROSS RECEIPTS TAXES
Gross receipts taxes are imposed on the company based on gas sold and delivered
in each of its jurisdictions. These taxes, which are recovered from customers
and remitted to the various taxing authorities, decreased by
38
<PAGE> 7
$709,000. The effect of a drop in the fuel tax rate for service to customers in
Montgomery County, Maryland was largely offset by higher other gross receipts
taxes due to higher revenues because of the colder weather in 1996. Amounts
collected from customers, which are reflected in revenues, are offset by an
equivalent amount recorded in general tax expense and, therefore, changes in
such amounts have no effect on net income.
OTHER
Other net revenues increased by $4.4 million. Included in this caption are
amounts associated with deliveries to customers for electric generation, sales
of gas made outside the company's service territory, delivery service revenues
applicable to certain Maryland firm customers and miscellaneous other operating
revenues not associated with volumes of gas sold.
The company has two customers to which it sells and/or transports gas to
facilities in Maryland where the supplies are used in generating electricity.
Volumes delivered for electric generation in 1996 totalled 59.5 million therms,
or 71.6 million therms lower than the volumes delivered in 1995. The decline is
attributable to the combined effect of the lack of available pipeline capacity
during the most recent winter due to the colder weather, reduced cooling
requirements during the summer of 1996 due to cooler weather and pricing
considerations for competing fuels due to the effect of higher gas prices. The
impact on net revenues and net income of increases or decreases in volumes
delivered for electric generation is not material due to a margin sharing
arrangement in the State of Maryland that requires the return to firm customers
of substantially all of the gross margins earned on sales and deliveries of
gas, less related expenses, after the company recovers its investment in the
facilities constructed to serve these customers. By returning margins from
these deliveries to firm customers in the Maryland jurisdiction, the cost of
providing gas to customers is lowered and, therefore, the company's competitive
position is enhanced.
NET REVENUES AND COST OF GAS
[GRAPH]
In 1996, the company sold gas outside of its service territory. These sales,
which totalled 40.5 million therms, are shown as gas sold off system in the
Selected Financial Data on page 33. The contribution to net revenues was not
material.
In the Maryland jurisdiction, the company expanded unbundled services to firm
customers. Delivery service tariffs for large and groups of small volume firm
commercial customers were implemented on November 1, 1995, and June 1, 1996,
respectively. Under these tariffs, eligible customers may acquire their gas
supply either from the company or a third-party supplier, such as marketers or
other gas companies. The company continues to serve these customers by
delivering gas through its distribution system under tariff rates. As shown in
the Selected Financial Data on page 33, volumes delivered to firm customers
acquiring their gas from others amounted to 3.8 million therms.
COST OF GAS
The company's total cost of gas increased to 32.67 cents per therm from the
1995 level of 28.68 cents per therm. The increase was due primarily to higher
gas costs incurred for supplies during the most recent heating season arising
from the sharply colder weather. This factor was partially mitigated by the
effect of a reduced firm cost of gas due to the return of prior year
overcollected gas costs to firm customers in 1996 and increased refunds from
pipelines during the year, including a refund from Columbia Gas Transmission
Corporation upon its emergence from bankruptcy in November 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 company's commodity cost of gas for 1996 increased to
26.53 cents per therm from the 1995 level of 19.33 cents per therm due to the
effect of the increased demand during the colder weather.
COST OF GAS SOLD
[GRAPH]
1995 VS. 1994.
GAS SOLD AND DELIVERED TO FIRM CUSTOMERS
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 increases on net revenues in fiscal year 1995 was an
increase of $19.3 million, substantially caused by the impact of decisions in
the company's three major jurisdictions. The company was granted an annual
increase in retail rates of $6.4 million on August 1, 1994, by the PSC of DC.
An annual increase of $6.8 million was granted by the SCC of VA effective
September 27, 1994, and an annual increase of $7.4 million was granted by the
PSC of MD on December 1, 1994.
39
<PAGE> 8
GAS DELIVERED TO INTERRUPTIBLE CUSTOMERS
Therms delivered to interruptible customers increased by 46.9 million therms
(17.9%). This increase reflected 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 in 1995.
GROSS RECEIPTS TAXES
Gross receipts taxes decreased by $4.6 million due to the warmer weather in
1995 as compared to 1994. As discussed previously, these taxes are levied on
revenues and, therefore, decreased with the decline in revenues.
COST OF GAS
The company's total cost of gas for 1995 dropped to 28.68 cents per therm from
the 1994 level of 32.13 cents per therm. This decline was due to a significant
drop in the per therm cost of gas purchased from producers or marketers during
1995 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 spread over fewer volumes
purchased and delivered in 1995. The commodity cost of gas invoiced the company
was 19.33 cents and 25.61 cents per therm for 1995 and 1994, respectively.
OTHER OPERATING EXPENSES
1996 VS. 1995. Operation and maintenance expenses increased by $26.1 million
(13.4%) in 1996. Of this increase, $13.4 million was attributable to
nonrecurring charges related to the redesign of the company's organization, as
described on page 36 and in Note 10 to the Consolidated Financial Statements.
Other factors that contributed to the increase included: (i) increased
compensation to employees, including cash payouts to management and
union-eligible employees and compensation in the form of a common stock grant;
(ii) higher labor charged to operating expenses in 1996 as a result of the
lockout of certain union-eligible employees in 1995; and (iii) increased
amortization of environmental expenses. Items that partially offset these
increases were lower employee benefits expenses, including reduced health care
expenses reflecting the effect of cost saving programs and lower pension
expenses, and the effect of attrition in the work force on labor expense.
OTHER OPERATING EXPENSES
[GRAPH]
At September 30, 1996, the company had 2,264 utility employees, a decline of
141 employees (5.9%) from the level at September 30, 1995. For a further
discussion of labor-related issues, please refer to the caption entitled "Labor
Matters" on page 37.
Depreciation and amortization increased by $1.5 million (3.2%) in 1996. The
increase was due to additional depreciation of $2.7 million on the company's
rising investment in plant and equipment. Partially offsetting the additional
depreciation was a decrease in the amount of amortization expense due to the
company's full recovery of its investment to serve certain interruptible
customers in the State of Maryland. The PSC of MD has permitted the company to
recover its investment to serve certain interruptible customers before sharing
with firm customers any margins earned on sales and deliveries to these
customers. In 1996, capital expenditures totalled $124.4 million and the
composite depreciation rate was 2.96% compared to 2.97% in 1995.
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 50.
1995 VS. 1994. Operation and maintenance expenses declined by $12.6 million
(6.1%) from the 1994 level. Included in this drop were 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 postretirement 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.
Depreciation and amortization increased by $2.9 million (6.6%) in 1995, 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 an electric
generation customer. 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 50.
OTHER INCOME (LOSS)-NET
1996 VS. 1995. Other income (loss)-net declined by
$3.5 million in 1996. The decline primarily reflects the effect of: (i) a prior
year $1.9 million after-tax gain on the sale of a non-utility subsidiary; (ii)
valuation reserves recorded related to certain non-utility investments in the
current year to reflect diminished expectations of their
40
<PAGE> 9
value; and (iii) lower interest income on temporary cash investments due to
substantially lower invested balances and lower interest rates earned on
amounts invested.
1995 VS. 1994. Other income (loss)-net was $2.3 million higher in 1995 than in
1994. The increase reflected 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 1995, of valuation 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.
INTEREST EXPENSE
1996 VS. 1995. Interest expense declined by $1.3 million or 4.1% in 1996. The
decline was primarily due to reduced interest expense on both long-and
short-term debt. Interest on long-term debt dropped by $330,000 due to a
decline in the weighted average cost of such debt of .2 percentage points,
partially offset by a $6.1 million increase in the average amount of long-term
debt outstanding. The company's embedded cost of long-term debt was 7.5% at
September 30, 1996, compared to 7.7% at September 30, 1995. The drop in the
cost of long-term debt was due primarily to the effect of the refinancing of
two First Mortgage Bond Series in January 1996. Interest expense on short-term
debt declined by $596,000 due to a $9.9 million drop in the average amount of
such debt outstanding and a decline in the weighted average cost of short-term
debt of .13 percentage points. See Short-Term Cash Requirements and Related
Financing for a discussion of fluctuations in short-term debt balances.
1995 VS. 1994. Interest expense declined by $253,000 or .8% in 1995. Interest
expense due customers resulting from lower levels of Demand-Side Management
costs overcollected from Maryland customers and a lower level of refunds from
pipeline companies to be passed back to customers with interest, 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% as compared to 7.8% at September 30, 1994. 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 reflecting higher market
rates for borrowings.
LIQUIDITY AND CAPITAL RESOURCES
The company has historically had a goal of maintaining its common equity ratio
in the mid-50% range of total capital and a general policy of repaying
short-term debt after the heating season ends in the spring as significant
levels of current assets are converted into cash.
Accomplishing these objectives and maintaining sufficient cash flow are
necessary to preserve the company's credit ratings and to allow access to
capital at relatively low costs. At September 30, 1996, total capitalization
was composed of 59.4% common equity, 3.0% preferred stock and 37.6% long-term
debt. Effective November 1, 1996, shares issued through the Dividend
Reinvestment and Common Stock Purchase Plan (DRP) and Employee Savings Plans
will be purchased in the open market instead of issuing new shares.
CAPITALIZATION
[GRAPH]
SHORT-TERM CASH
REQUIREMENTS
AND RELATED FINANCING
The company's business is highly weather sensitive and seasonal. In fiscal year
1996, 74% of total therms delivered (excluding deliveries to two electric
generation facilities) were delivered in the first and second fiscal quarters.
This weather sensitivity causes short-term cash requirements to vary
significantly during the year. Cash requirements peak in the fall and winter
months when accounts receivable, accrued utility revenues and storage gas are
at or near their highest levels. After the winter heating season, these assets
are converted into cash and are used to liquidate short-term debt and acquire
storage gas for the subsequent heating season.
Storage gas, which represents gas purchased from producers and primarily stored
in facilities owned by interstate pipelines, is generally paid for between
heating seasons and withdrawn during the heating season. Significant variations
in storage balances at September 30 are usually caused by the price paid to
producers and marketers, which is a function of short-term market fluctuations
in gas costs. Such costs are recovered from customers as a component of the
cost of gas.
Variations in the timing of collections of gas costs under the company's
purchased gas adjustment provisions and the level of refunds from the pipeline
companies that will be returned to the company's customers can significantly
affect short-term cash requirements. At September 30, 1996, the company had a
temporary net undercollection of gas costs of $26.6 million, compared to a
$29.2 million net overcollection at September 30, 1995. Amounts that are
undercollected and overcollected are reflected in the captions Gas costs due
from customers and Gas costs due to customers in the Consolidated Balance Sheet
and most of the current balances will be collected from or returned to
customers in fiscal year 1997. At September 30, 1996, refunds received from
pipelines that are to be returned to the company's customers totalled $8.3
million.
41
<PAGE> 10
As of September 30, 1996, current maturities of long-term debt were $8.0
million. The company was authorized at September 30, 1996 to issue up to $60
million of long-term debt and $50 million of equity securities under an
existing shelf registration which expires in January 1997. In October 1996, the
company issued an additional $53 million in unsecured Medium-Term Notes (MTNs),
thereby reducing its long-term debt issuance capability under the existing
shelf registration to $7 million.
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. Additional
information regarding the company's short-term borrowing capabilities is
included in Note 2 to the Consolidated Financial Statements. At September 30,
1996, the company had notes payable outstanding of $115.3 million, as compared
to no such borrowings outstanding at September 30, 1995. The financing was
required in the most recent year due primarily to the effect of a temporary
undercollection of gas costs, increased prices for gas which included the cost
to fill storage inventories for the next heating season, and an increased
emphasis on using short-term debt to finance current assets.
LONG-TERM CASH REQUIREMENTS AND
RELATED FINANCING
The company's long-term cash requirements are dependent upon the level of
capital expenditures, long-term debt maturity requirements and decisions to
refinance long-term debt. The majority of the company's capital expenditures
are devoted to adding new customers in its service area. The nature of the
company's MTNs and First Mortgage Bonds are discussed in Note 3 to the
Consolidated Financial Statements.
1996. As shown in the table on page 43, capital expenditures for 1996 totalled
$124.4 million. New business expenditures, which include amounts invested to
convert customers from other energy sources, totalled $77.9 million, or 62.6%
of the total. By the end of 1996, customer meters rose to 772,281, an increase
of 21,432, or 2.9% over the level at the end of 1995.
In 1996, net cash provided by operating activities amounted to $57.3 million, a
decline of $120.9 million from the 1995 level. The sharp decrease was due
primarily to: (i) the effect of a shift from an overcollection of gas costs
from customers in the prior year to an undercollection of gas costs in the
current year; (ii) the effect of a higher current year cost per therm to
replace storage gas volumes withdrawn during the prior winter heating season;
(iii) higher funds used to support accounts receivable balances resulting
primarily from higher gas costs; and (iv) refunds made to customers for amounts
overcollected from the implementation of an interim rate increase. These uses
of cash were partially offset by higher net income and increased sources of
cash reflected in accounts payable due to higher gas prices and the amounts
associated with the redesign of the company's organization.
In connection with a January 1996 in-substance defeasance as discussed in Note
3 to the Consolidated Financial Statements, the company issued $50.0 million of
unsecured MTNs at a coupon rate of 6.15%. The MTNs have a 30-year nominal life
and allow the holder to elect early maturity at par during a one-month period
30 days prior to the tenth anniversary date. Additionally, the company may
redeem the MTNs at par at any time on or after the tenth anniversary date of
their issuance up until the end of the 30-year nominal life. The $69.8 million
of long-term debt retired included $50.0 million of 7-7/8% First Mortgage Bonds
retired effective September 1, 1996, $17.325 million of 9-1/4% First Mortgage
Bonds extinguished for financial reporting purposes in accordance with the
in-substance defeasance, and a $2.5 million MTN retirement.
During 1996, the company raised $12.6 million through its DRP and Employee
Savings Plans. The sum of net income and noncash charges, less dividends on
common and preferred stock, totalled $101.0 million or 81.2% of capital
expenditures.
1995. 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, the company had
750,849 customer meters, 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 included: (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 1995; and (iii) lower payments made in
1995 related to FERC Order No. 636 transition costs that are reflected in
accounts payable. Partially offsetting these items was the effect of a lower
source of cash from 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.
In 1995, the company issued $40 million of unsecured 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.
During 1995, the company raised $13.4 million through its 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 3.3% over the level at the end of 1993.
42
<PAGE> 11
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 MTNs at an interest rate
of 6.95%. Proceeds from the 1994 issuance were used to retire $32.7 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, the company raised $14.0 million through its 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.
NON-UTILITY ACTIVITIES
During 1996, the company augmented cash flow through the sale of $30.5 million
of certain non-utility accounts receivable related to merchandise. Similar
sales of non-utility accounts receivable in 1995 and 1994 amounted to $45.1
million and $45.0 million, respectively. In 1995, the company received $2.0
million in cash as a result of the sale of a non-utility 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.
SECURITY RATINGS
Shown below are the ratings on the company's debt instruments at year-end for
1996. There were no changes in these ratings from 1995.
<TABLE>
<S> <C>
First Mortgage Bonds
Standard & Poor's Corporation AA-
Moody's Investors Service Aa2
Fitch Investors Service, Inc. AA-
Unsecured Medium-Term Notes
Standard & Poor's Corporation AA-
Moody's Investors Service Aa3
Fitch Investors Service, Inc. AA-
Commercial Paper
Standard & Poor's Corporation A-1+
Moody's Investors Service P-1
Fitch Investors Service, Inc. F-1+
</TABLE>
CAPITAL EXPENDITURES
The company's actual capital expenditures for 1994-1996 and projected capital
expenditures for 1997-2001 are shown in the table below. The company believes
that the combination of available internal and external sources of funds will
be adequate to meet its capital requirements.
CAPITAL EXPENDITURES
(Millions)
<TABLE>
<CAPTION>
Actual Projected
1994 1995 1996 1997 1998 1999 2000 2001 Total
----------------------- ----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
New Business $ 73.4 $ 78.9 $ 77.9 $ 87.6 $ 88.4 $ 84.1 $ 88.0 $ 93.0 $ 441.1
Replacements 27.0 25.6 34.5 41.2 38.2 40.1 41.8 43.2 204.5
Other 19.4 8.2 12.0 24.4 19.5 18.1 15.4 13.7 91.1
------------------------ ---------------------------------------------------
Total $ 119.8 $ 112.7 $ 124.4 $ 153.2 $ 146.1 $ 142.3 $ 145.2 $ 149.9 $ 736.7
======================== ===================================================
</TABLE>
43
<PAGE> 12
OTHER FACTORS AFFECTING
THE COMPANY
RATE INCREASES
Requests for rate increases 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's rates did not change in any of its major jurisdictions in 1996.
However, results of operations in fiscal year 1996 benefitted from rate
increases implemented by a distribution subsidiary in fiscal years 1995 and
1996, and a rate increase that was granted effective December 1, 1994 in the
company's Maryland jurisdiction. A Summary of Major Rate Applications and
Results is shown below.
ENVIRONMENTAL MATTERS
The company and its subsidiaries are subject to various laws related to
environmental matters, as discussed in Note 9 to the Consolidated Financial
Statements.
YEAR 2000
Like all companies with business application software programs, including
mainframe, client/server and personal computer applications written over many
years, the company is also affected by the so-called "Year 2000" issue. These
programs, which include the company's customer service, operations and
financial systems, were written using two-year digits to define the applicable
year, rather than four. Any of the company's programs that have time-sensitive
software may recognize a date using "00" as the year 1900 rather than the year
2000. This could result in the computer shutting down or performing incorrect
computations.
The company is in the process of identifying the systems that could be affected
by the year 2000 issue and is developing an implementation plan to resolve the
issue. The company believes, with the appropriate modifications, it will be
able to operate its time-sensitive business application software programs
through the turn of the century.
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.
SUMMARY OF MAJOR RATE APPLICATIONS AND RESULTS
<TABLE>
<CAPTION>
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 7/6/90 3/31/90 $ 7.7 $ 7.1 13.00%
Maryland 8/1/93 12/31/92 26.2 10.6 a/
District of Columbia 10/19/93 9/30/92 24.5 4.7 11.50
District of Columbia 8/1/94 9/30/93 17.3 6.4 b/
Virginia 9/27/94 12/31/93 15.7 6.8 11.50
Maryland 12/1/94 3/31/94 17.6 7.4 a/
</TABLE>
a/ Rates were implemented as a result of a settlement agreement. The return on
equity indicated in the order of 11.5% was not utilized to establish rates.
b/ Application was settled without stipulating the return on common equity.
44
<PAGE> 13
CONSOLIDATED STATEMENT OF INCOME
Washington Gas Light Company, Years Ended September 30
<TABLE>
<CAPTION>
1996 1995 1994
- ------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C>
OPERATING REVENUES (Note 1) $ 969,778 $ 828,748 $ 914,863
Cost of Gas (Note 1) 469,925 390,041 462,195
---------- --------- ----------
NET REVENUES 499,853 438,707 452,668
---------- --------- ----------
OTHER OPERATING EXPENSES
Operation (Note 10) 187,817 163,518 171,612
Maintenance 33,105 31,268 35,789
Depreciation and amortization (Note 1) 47,887 46,385 43,494
General taxes (Note 6) 68,605 67,829 72,177
Income taxes (See Statement and Note 5) 49,376 37,514 37,264
---------- --------- ----------
386,790 346,514 360,336
---------- --------- ----------
OPERATING INCOME 113,063 92,193 92,332
Other Income (Loss)-Net (874) 2,610 274
---------- --------- ----------
INCOME BEFORE INTEREST EXPENSE 112,189 94,803 92,606
Interest Expense 30,598 31,894 32,147
---------- --------- ----------
NET INCOME 81,591 62,909 60,459
Dividends on Preferred Stock 1,332 1,333 1,335
---------- --------- ----------
NET INCOME APPLICABLE TO COMMON STOCK $ 80,259 $ 61,576 $ 59,124
========== ========= ==========
AVERAGE COMMON SHARES OUTSTANDING 43,360 42,575 41,835
========== ========= ==========
EARNINGS PER AVERAGE SHARE OF COMMON STOCK $ 1.85 $ 1.45 $ 1.41
========== ========= ==========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
45
<PAGE> 14
CONSOLIDATED BALANCE SHEET
Washington Gas Light Company, September 30
<TABLE>
<CAPTION>
1996 1995
- --------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 1)
At original cost $1,721,956 $1,608,518
Accumulated depreciation and amortization (591,382) (552,460)
---------- ----------
1,130,574 1,056,058
---------- ----------
CURRENT ASSETS
Cash and cash equivalents 4,589 13,911
Accounts receivable 53,587 41,528
Gas costs due from customers 28,109 692
Allowance for doubtful accounts (11,846) (10,580)
Accrued utility revenues 15,117 18,323
Materials and supplies-principally at average cost 14,425 14,296
Storage gas-at cost (first-in, first-out) 83,829 53,361
Deferred income taxes (See Statement and Note 5) 17,888 19,710
Other prepayments-principally taxes 10,047 7,799
---------- ----------
215,745 159,040
---------- ----------
DEFERRED CHARGES AND OTHER ASSETS (Note 1) 118,282 145,040
---------- ----------
Total $1,464,601 $1,360,138
========== ==========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statement)
Common shareholders' equity $ 558,809 $ 513,044
Preferred stock 28,440 28,471
Long-term debt (Note 3) 353,893 329,051
---------- ----------
941,142 870,566
---------- ----------
CURRENT LIABILITIES
Current maturities (Note 3) 8,006 52,505
Notes payable (Note 2) 115,278 --
Accounts payable 90,524 65,398
Wages payable 14,308 15,125
Dividends declared 12,787 12,353
Customer deposits and advance payments 12,997 15,408
Accrued taxes 5,594 6,253
Accrued interest 4,910 5,577
Pipeline refunds due to customers 8,262 10,560
Gas costs due to customers 1,488 29,871
Rate refund due to customers (Note 1) -- 9,306
---------- ----------
274,154 222,356
---------- ----------
DEFERRED CREDITS
Unamortized investment tax credits 22,381 23,353
Deferred income taxes (See Statement and Note 5) 128,936 121,157
Other (Notes 1, 7, 8 and 9) 97,988 122,706
---------- ----------
249,305 267,216
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 8, 9 and 11)
Total $1,464,601 $1,360,138
========== ==========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
46
<PAGE> 15
CONSOLIDATED STATEMENT OF CASH FLOWS
Washington Gas Light Company, Years Ended September 30
<TABLE>
<CAPTION>
1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net Income $ 81,591 $ 62,909 $ 60,459
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization (a) 54,517 52,329 49,029
Deferred income taxes-net 11,337 2,036 13,277
Amortization of investment tax credits (972) (992) (1,014)
Allowance for funds used during construction (465) (443) (200)
Other noncash charges and credits-net 5,250 1,519 12,937
------------ --------- ------------
151,258 117,358 134,488
Changes in assets and liabilities:
Accounts receivable and accrued utility revenues (7,587) 21,693 4,764
Gas costs due from/to customers-net (55,800) 29,008 (4,243)
Storage and prepaid gas costs (30,468) 6,606 16,187
Other prepayments-principally taxes (2,248) 43 (1,752)
Accounts payable 17,578 (8,485) (26,097)
Wages payable (817) 531 (1,833)
Customer deposits and advance payments (2,411) (333) (382)
Accrued taxes (659) (3,394) 3,925
Pipeline refunds due to customers (2,298) 2,988 5,717
Rate refund due to customers (9,306) 9,306 --
Deferred purchased gas costs (1,435) (2,625) 3,046
Other-net 1,464 5,492 1,909
------------ --------- ------------
Net Cash Provided by Operating Activities 57,271 178,188 135,729
------------ --------- ------------
FINANCING ACTIVITIES
Common stock issued 12,637 13,368 14,027
Long-term debt issued 50,000 40,000 36,000
Long-term debt retired (69,830) (9,322) (50,719)
Notes payable-net 115,278 (52,912) 31,458
Dividends on common and preferred stock (50,264) (48,731) (48,042)
------------ --------- ------------
Net Cash Provided by (Used in) Financing Activities 57,821 (57,597) (17,276)
------------ --------- ------------
INVESTING ACTIVITIES
Proceeds from sale of non-utility subsidiary -- 2,000 --
Capital expenditures (124,414) (112,715) (119,796)
Other investing activities -- 513 --
------------ --------- ------------
Net Cash Used in Investing Activities (124,414) (110,202) (119,796)
------------ --------- ------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (b) (9,322) 10,389 (1,343)
Cash and Cash Equivalents at Beginning of Year (b) 13,911 3,522 4,865
------------ --------- ------------
Cash and Cash Equivalents at End of Year (b) $ 4,589 $ 13,911 $ 3,522
============ ========= ============
</TABLE>
(a) Includes amounts charged to other accounts.
(b) Cash equivalents are highly liquid investments with a maturity of three
months or less when purchased.
<TABLE>
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Income taxes paid $ 41,993 $ 38,824 $ 22,334
Interest paid $ 30,859 $ 30,879 $ 31,345
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
47
<PAGE> 16
CONSOLIDATED STATEMENT OF CAPITALIZATION
Washington Gas Light Company, September 30
<TABLE>
<CAPTION>
1996 1995
- ------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY (See Statement and Note 4)
Common stock, $1 par value, authorized 80,000,000 shares,
issued 43,726,853 and 42,944,831 shares $ 43,727 $ 42,945
Paid-in capital 304,691 289,285
Retained earnings 213,626 182,733
Deferred compensation (2,697) (1,680)
Treasury stock-at cost, 23,377 and 12,868 shares (538) (239)
---------- ---------
Total Common Shareholders' Equity 558,809 59.4% 513,044 58.9%
---------- ------- --------- ------
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, 2,073 and 2,348 shares 207 235
$4.60 convertible series, 600 and 635 shares 60 63
---------- ---------
Total Preferred Stock 28,440 3.0 28,471 3.3
---------- ------- --------- ------
LONG-TERM DEBT (Note 3)
First mortgage bonds
7-7/8% series due September 1, 2016 -- 50,000
8-5/8% series due March 1, 2017 35,500 35,500
9-1/4% series due April 15, 2018 -- 17,325
8-3/4% series due July 1, 2019 50,000 50,000
---------- ---------
85,500 152,825
---------- ---------
Unsecured medium-term notes
Due fiscal year 1996, 4.57% -- 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 40,000
Due fiscal year 2026, 6.15% 50,000 --
---------- ---------
277,200 229,700
---------- ---------
Other long-term debt 196 201
Unamortized premium and (discount)-net (997) (1,170)
---------- ---------
Total long-term debt 361,899 381,556
---------- ---------
Less current maturities 8,006 52,505
---------- ---------
Long-Term Debt 353,893 37.6 329,051 37.8
---------- ------- --------- -------
$ 941,142 100.0% $ 870,566 100.0%
========== ======= ========= =======
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
48
<PAGE> 17
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, 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
Net income 81,591
Common stock expense (9)
Deferred compensation 127,100 127 2,420 (1,017) (299)
Director compensation plan 1,603 2 34
Employee compensation 45,313 45 901
Dividend reinvestment plan 484,415 485 10,007
Employee savings plans 120,362 120 2,025
Conversion of preferred stock 3,229 3 28
Dividends declared:
Common stock ($1.135 per share) (49,366)
Preferred stock (1,332)
---------- ------- -------- -------- ------- ---------
BALANCE SEPTEMBER 30, 1996 43,726,853 $43,727 $304,691 $ (2,697) $ (538) $ 213,626
========== ======= ======== ======== ======= =========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
49
<PAGE> 18
CONSOLIDATED STATEMENT OF INCOME TAXES
Washington Gas Light Company
<TABLE>
<CAPTION>
1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
INCOME TAX EXPENSE, YEARS ENDED SEPTEMBER 30 (NOTE 5) (Dollars in Thousands)
<S> <C> <C> <C>
Charged to other operating expenses
Current $ 39,224 $ 35,598 $ 24,637
---------- ---------- ----------
Deferred
Accelerated depreciation 9,761 10,215 10,254
Losses/gains on reacquired debt (112) (469) 1,662
Deferred gas costs 11,260 (4,450) 4,255
Pensions and other employee benefit costs (132) 214 (2,077)
Demand side management costs (481) 1,976 155
Inventory overheads (4,232) (3,126) 48
Other (4,940) (1,452) (656)
---------- ---------- ----------
Total Deferred Income Tax Expense 11,124 2,908 13,641
---------- ---------- ----------
Amortization of investment tax credits (972) (992) (1,014)
---------- ---------- ----------
49,376 37,514 37,264
---------- ---------- ----------
Charged to other income (loss)-net
Current (842) 142 690
Deferred 213 (872) (364)
---------- ---------- ----------
(629) (730) 326
---------- ---------- ----------
Total Income Tax Expense $ 48,747 $ 36,784 $ 37,590
========== ========== ==========
RECONCILIATION BETWEEN THE STATUTORY FEDERAL INCOME
TAX RATE AND THE EFFECTIVE TAX RATE
Income tax at statutory Federal income tax rate $ 45,618 35.00% $ 34,893 35.00% $ 34,317 35.00%
-------- ------ -------- ------ -------- ------
Increases (decreases) in tax resulting from
Accelerated depreciation less amount deferred 2,705 2.08 2,837 2.85 2,195 2.24
Amortization of investment tax credits (972) (.75) (992) (1.00) (1,014) (1.03)
Cost of removal (431) (.33) (488) (.49) (435) (.44)
State income taxes 2,180 1.67 2,112 2.12 1,892 1.93
Other items-net (353) (.27) (1,578) (1.58) 635 .64
-------- ------ -------- ------ -------- ------
Income Tax Expense and Effective Tax Rate $ 48,747 37.40% $ 36,784 36.90% $ 37,590 38.34%
======== ====== ======== ====== ======== ======
</TABLE>
<TABLE>
<CAPTION>
1996 1995
--------------------- --------------------
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 $ 6,043 $ 5,614 $ 5,623 $ 6,202
Uncollectible accounts 3,158 -- 2,703 --
Inventory overheads 9,397 -- 5,165 --
Valuation allowance -- (2,670) -- (2,470)
Other 4,819 11,896 991 12,905
------- -------- ------- ---------
Total Assets 23,417 14,840 14,482 16,637
------- -------- ------- ---------
Deferred tax liabilities
Accelerated depreciation -- 110,122 -- 100,381
Losses/gains on reacquired debt -- 2,913 -- 3,046
Construction overheads -- 3,080 -- 3,246
Income taxes recoverable through future rates -- 18,531 -- 20,267
Deferred gas costs 5,529 2,185 (5,228) 1,682
Demand side management costs -- 6,945 -- 7,196
Other -- -- -- 1,976
------- -------- ------- ---------
Total Liabilities 5,529 143,776 (5,228) 137,794
------- -------- ------- ---------
Total Accumulated Deferred Income Taxes $17,888 $(128,936) $19,710 $(121,157)
======= ========= ======= =========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of this statement.
50
<PAGE> 19
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 in
Maryland and Virginia. A distribution subsidiary, Shenandoah Gas Company,
serves portions of Virginia and West Virginia. The company also owns a
subsidiary that operates an underground storage field on behalf of the company.
As of September 30, 1996, the company and its distribution subsidiary served
over 772,000 customer meters. Therms delivered to firm customers accounted for
79% of the company's total therms delivered in fiscal year 1996, and the
company is not dependent on one customer or group of customers. In 1996,
Washington Gas Energy Services, Inc. (WGES), a non-utility subsidiary, entered
the energy services market. During fiscal year 1996, its operations were
primarily limited to selling gas in competition with third-party suppliers,
such as marketers or other gas companies. The company's non-utility operations,
including the activities of WGES, are not currently material.
CONSOLIDATION
The consolidated financial statements include the accounts of the company and
its subsidiaries. All significant intercompany transactions have been
eliminated. Certain amounts in financial statements of prior years have been
reclassified to conform to the presentation of the current year.
USE OF ESTIMATES IN THE
PREPARATION OF FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
REGULATED OPERATIONS
The company and its utility subsidiaries account for their regulated operations
in accordance with Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), as
amended and supplemented by subsequently issued standards. These standards set
forth the application of generally accepted accounting principles to those
companies whose rates are determined by an independent third party regulator.
The economic effects of regulation can result in regulated companies recording
costs that have been or are expected to be allowed in the rate setting process
in a period different from the period in which the costs would be charged to
expense by an unregulated enterprise.When this results, costs are deferred as
assets in the balance sheet (regulatory assets) and recorded as expenses as
those same amounts are reflected in rates. 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, 1996 and 1995 follow.
<TABLE>
<CAPTION>
1996 1995
- -------------------------------------------------
(Millions)
<S> <C> <C>
REGULATORY ASSETS
- -----------------
Income tax-related amounts
due from customers (Note 5) $ 40.9 $ 43.8
Gas costs due from customers 28.1 .7
Demand side management
costs due from customers 22.3 22.0
Other postretirement
benefit costs (Note 7) 12.5 10.5
Environmental response
costs (Note 9) 12.2 14.3
Losses on reacquired debt 9.0 7.6
Purchased gas costs 6.0 4.6
Order 636 transition costs
due from customers (Note 8) 5.7 17.8
Other .9 1.2
------ ------
$137.6 $122.5
====== ======
REGULATORY LIABILITIES
- ----------------------
Income tax-related amounts
due to customers (Note 5) $22.4 $ 23.5
Demand side management
costs due to customers 3.4 2.6
Gas costs due to customers 1.5 29.9
Refunds due to customers 8.3 33.7
Other 1.8 2.3
------ ------
$37.4 $ 92.0
====== ======
</TABLE>
51
<PAGE> 20
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 construction overheads.
The amount of AFUDC capitalized in 1996, 1995 and 1994 was $465,000, $443,000,
and $200,000, respectively.
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 2.96% for 1996 and 2.97% for 1995
and 1994. 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 in accordance with established regulatory practice. Losses realized and
deferred were $2.3 million in 1996 and $6.2 million in 1994. No gains or losses
were realized in 1995. For income tax purposes, gains and losses are recognized
currently.
NEW ACCOUNTING STANDARDS
In October 1995, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123), which establishes a fair value based
method of accounting for stock-based compensation granted in fiscal years
beginning after December 15, 1994. SFAS No. 123 is not expected at this time to
have any impact on results of operations or financial condition of the company.
In June 1996, the FASB issued Statement of Financial Accounting Standards No.
125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities" (SFAS No. 125). SFAS No. 125 establishes
accounting and reporting standards for transfers and servicing of financial
assets and extinguishments of liabilities based on the consistent application
of a financial components approach that focuses on control. Under that
approach, when a financial asset is transferred, the transferor recognizes all
financial and servicing assets it controls and the liabilities it has incurred,
and derecognizes financial assets when control has been surrendered. SFAS No.
125 provides consistent standards for distinguishing transfers of financial
assets that are sales from transfers that are secured borrowings, and
supersedes Statement of Financial Accounting Standards No. 77, "Reporting by
Transferors for Transfers of Receivables with Recourse" (SFAS No. 77).
The company has previously accounted for sales of receivables with recourse in
accordance with SFAS No. 77, including disclosure of its liability under the
recourse obligation in the Notes to the Consolidated Financial Statements. SFAS
No. 125 will require the company to record a liability for its recourse
obligation for any such sales occurring after December 31, 1996, and to
continue recourse obligation disclosure for sales occurring prior to that date.
SFAS No. 125 will not affect the company's results of operations.
In October 1996, the American Institute of Certified Public Accountants issued
Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP 96-1),
which the company will be required to adopt in fiscal 1998. SOP 96-1 provides
additional guidance on the accrual, measurement and disclosure of environmental
liabilities. The company is reviewing SOP 96-1 and does not currently expect it
to materially impact its financial condition or results of operations.
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, 1996, 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. These lines expire on June 30, 1997. 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
52
<PAGE> 21
compensation is paid unless activated. The temporary lines became available on
October 1, 1996. Of these lines, $5 million will expire on April 1, 1997 and
$15 million will expire on April 30, 1997.
As of September 30, 1996, 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 23, 1997, allows for
annual extension by mutual agreement in each of the next three 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, 1996, the company had $115.3 million in short-term debt
outstanding, excluding current maturities, at a weighted average cost of 5.52%.
As of September 30,1995, the company had no short-term debt outstanding,
excluding current maturities.
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.
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. At September 30, 1996 and 1995, the weighted
average interest rate on all outstanding MTNs was 6.90% and 7.04%,
respectively.
In October 1996, the company issued a total of $53 million in MTNs with
maturity dates in fiscal year 2027. Of this total, $25 million in such notes
were issued with a coupon rate of 6.82%. Holders of these MTNs have a one-time
option to have the company redeem the notes at their face value on October 9,
2006. The remaining $28 million was issued with coupon rates of 6.62% and
6.63%. Holders of these MTNs have a one-time option to have the company redeem
the notes at their face value on October 23, 2003.
REFINANCING TRANSACTION
On January 25, 1996, the company issued $50 million of unsecured MTNs at a
coupon rate of 6.15% and $21.6 million of short-term commercial paper. The MTNs
have a 30-year nominal life and allow the holder to elect early maturity of the
MTNs at par during a one-month period 30 days prior to the tenth anniversary
date. Additionally, the company can redeem the MTNs at par at any time on or
after the tenth anniversary date of their issuance up until the end of the
30-year nominal life. The proceeds of these issuances were used to purchase
approximately $71.6 million of U.S. Treasury Securities. These securities were
deposited in an irrevocable trust for the sole purpose of paying the principal
and interest on $50 million of 7-7/8% Series First Mortgage Bonds due September
1, 2016 and $17.325 million of 9-1/4% Series First Mortgage Bonds due April 15,
2018 up to and including their first call dates on September 1, 1996 and April
15, 1998, respectively. This transaction was accounted for as an in-substance
defeasance in which the affected debt was extinguished for financial reporting
purposes, although not legally retired. A premium incurred in connection with
acquiring the Treasury securities of approximately $2.3 million was recorded as
a regulatory asset and is being amortized over future periods as an adjustment
to interest expense in accordance with regulatory practice.
On September 1, 1996, proceeds from the trust were used to legally retire the
7-7/8% Series First Mortgage Bonds. The remaining proceeds in the trust will be
used to pay the interest and principal payments on the outstanding 9-1/4%
Series First Mortgage Bonds up to and including the first call date on April
15, 1998, at which time they will be legally retired.
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, 1996 is $8.0 million in 1997,
$17.8 million in 1998, $73.7 million in 1999, $2.0 million in 2000 and $2.0
million in 2001.
4. COMMON STOCK
At September 30, 1996, there were 1,260,864 authorized but unissued shares of
Common Stock reserved for the Dividend Reinvestment and Common Stock Purchase
Plan, for the Directors' Stock Compensation 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 432,500 shares remain reserved for potential future awards under
the LTICP at September 30, 1996. During 1996, 98,400 shares of stock were
granted and during 1995, 17,500 shares of stock 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
53
<PAGE> 22
the passage of time and the expense, amounting to $1,383,000, $497,000, and
$847,000 in 1996,1995 and 1994, respectively, is being recognized ratably over
the periods during which the restrictions lapse. Shares of Common Stock
outstanding, net of Treasury shares, were 43,703,476, 42,931,963 and 42,186,622
as of September 30, 1996, 1995 and 1994, 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, 1992 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.
The company accounts for income taxes in accordance with Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109).
Under SFAS No. 109, deferred income taxes are recognized for all temporary
differences between the financial statement and tax basis of assets and
liabilities at currently enacted income tax rates.
SFAS No. 109 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 the company believes they will be recoverable from or be
payable to customers through the ratemaking process. The company's regulatory
assets and liabilities associated with income taxes due from and to customers,
as of September 30, 1996 and 1995, are shown in Note 1 to the Consolidated
Financial Statements.
The Consolidated Statement of Income Taxes on page 50 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, 1996 and 1995.
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 1996 1995 1994
- ------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Charged to operating expenses
Gross receipts $ 43.9 $ 44.6 $49.2
Property 15.9 15.1 13.8
Payroll 7.6 7.0 8.0
Other 1.2 1.1 1.2
------ ------ -----
68.6 67.8 72.2
------ ------ -----
Charged to other income
(loss)-net .3 .3 .4
Charged to construction 1.8 2.6 2.3
------ ------ -----
Total General Taxes $ 70.7 $ 70.7 $74.9
====== ====== =====
</TABLE>
7. 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
executive retirement plan (SERP). A trust has been established for the future
funding of the SERP liability. It is the company's policy to fund pension costs
accrued for the 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 1996 1995 1994
- -------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Service cost-benefits
earned during the period $ 8.9 $ 7.8 $ 8.8
Interest cost on projected
benefit obligation 27.0 27.5 25.6
Actual return on plan assets (54.5) (80.7) (1.4)
Net amortization and
deferral 17.6 46.9 (31.1)
-------- -------- --------
Net periodic pension
(income) cost $ (1.0) $ 1.5 $ 1.9
======== ======== ========
Expected long-term rate of
return on plan assets 8.25% 8.25% 8.25%
======== ======== ========
</TABLE>
54
<PAGE> 23
The following table sets forth the funded status of the plans as of September
30, 1996 and 1995.
<TABLE>
<CAPTION>
1996 1995
- --------------------------------------------------------------------------------
(Millions)
<S> <C> <C>
Actuarial present value of
benefit obligations:
Vested benefit obligation $ (267.9) $ (264.9)
========== ===========
Accumulated benefit obligation $ (284.6) $ (284.3)
========== ===========
Projected benefit obligation $ (357.4) $ (368.7)
Plan assets at market value 506.1 472.0
---------- -----------
Plan assets in excess of projected
benefit obligation 148.7 103.3
Unrecognized net (gains) (164.6) (118.7)
Unrecognized prior service costs 6.4 6.7
Unrecognized net asset at transition (12.7) (15.1)
---------- -----------
Accrued pension costs in the
consolidated balance sheet $ (22.2) $ (23.8)
========== ===========
Discount rate 8.00% 7.50%
========== ===========
Rate of compensation increase 5.00% 5.00%
========== ===========
</TABLE>
OTHER POSTRETIREMENT BENEFITS
The company provides certain health care and life insurance benefits for
retired employees. Substantially all employees may become eligible for such
benefits if they attain retirement status while working for the company. The
company accounts for these benefits under the provisions of Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106). The company
elected to amortize the accumulated postretirement benefit obligation existing
at the October 1, 1993 adoption date of this standard (the transition
obligation) of $190.6 million over a twenty-year period.
Net periodic postretirement benefit cost included the following components:
<TABLE>
<CAPTION>
Years Ended September 30 1996 1995 1994
- --------------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C>
Service cost-benefits
attributed to service
during the period $ 4.9 $ 4.9 $ 5.3
Interest cost on accumulated
postretirement benefit
obligation 14.1 14.9 13.6
Actual return on plan assets (1.8) (1.0) (.2)
Amortization of transition
obligation 9.5 9.5 9.5
Other (1.7) (.3) (.1)
---------- ---------- ------------
Net periodic postretirement
benefit cost 25.0 28.0 28.1
Amount capitalized as
construction cost (4.6) (5.7) (6.0)
Amount deferred as a
regulatory asset-net (2.0) (3.8) (6.7)
---------- ---------- ------------
Amount charged to expense $ 18.4 $ 18.5 $ 15.4
========== ========== ============
</TABLE>
The following table sets forth the funded status of the trusteed plans as of
September 30, 1996 and 1995.
<TABLE>
<CAPTION>
1996 1995
- ------------------------------------------------------------------
(Millions)
<S> <C> <C>
Accumulated postretirement
benefit obligation:
Retirees $ (95.2) $ (86.0)
Fully eligible active employees (18.2) (16.4)
Other active employees (79.3) (83.8)
--------- ---------
Total accumulated
postretirement benefit
obligation (192.7) (186.2)
Plan assets at fair value-
invested primarily in short-
term debt securities 47.8 30.2
--------- ---------
Accumulated postretirement
benefit obligation in excess
of plan assets (144.9) (156.0)
Unrecognized net (gains) (36.9) (32.7)
Unrecognized transition
obligation 162.1 171.6
--------- ---------
Accrued postretirement benefit
costs in the consolidated
balance sheet $ (19.7) $ (17.1)
========= =========
Discount rate 8.00% 7.75%
========= =========
Rate of compensation increase 5.00% 5.00%
========= =========
</TABLE>
The assumed health care cost trend rates for fiscal year 1997 for Medicare
eligible and non-Medicare eligible retirees are 7.50% and 9.00%, respectively;
these rates are assumed to decrease gradually to 5.50% and 5.75%, respectively,
through 2003 and remain at those levels thereafter. The health care cost trend
rate assumption has a significant effect on the amounts reported. If the health
care cost trend rate were increased by 1% in each year, the accumulated
postretirement benefit obligation at September 30, 1996 would increase by $25.2
million, and the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for fiscal year 1996 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. The Public Service Commission of the District of Columbia (PSC of
DC) has granted the company recovery through 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. In an order dated September 28, 1995,
the State Corporation Commission of Virginia granted the company recovery in
accordance with a generic order allowing for recovery of costs determined under
GAAP in rates, with the exception of allowing recovery of the transition
55
<PAGE> 24
obligation over forty years as opposed to the twenty-year maximum amortization
allowed under GAAP. The Public Service Commission of Maryland (PSC of MD) has
not rendered a decision to the company that specifically addresses recovery of
postretirement benefit costs determined in accordance with GAAP; however, the
level of rates the PSC of MD has allowed is sufficient to recover the cost
determined under GAAP. The amount of postretirement benefit costs deferred as
a regulatory asset at September 30, 1996 is $12.5 million, and the company
expects that these costs will be recovered over a twenty-year period that began
October 1, 1993.
All of the regulatory commissions having jurisdiction over the company's rates
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 trusts was 8.25% for 1996 and 1995. To the extent the income in
the trusts is taxable, the income tax rate associated with the taxable portion
of this return is assumed to be 39.6%.
EMPLOYEE SAVINGS PLANS
The company offers employee savings plans for eligible management (Savings
Plan) and union-eligible (Capital Appreciation Plan) employees which are
designed to provide employees with an incentive to save and invest regularly.
The Savings Plan is a defined contribution plan, allowing salary deferral by
participants from 1 percent to 14 percent of their salaries invested among
various alternatives. An employer contribution equal to 100 percent of the
first 4 percent of the employees' compensation they contribute on a pre-tax
basis, or 100 percent of the first 2 percent and 50 percent of the next 2
percent on an after-tax basis, are invested among various alternatives. The
Capital Appreciation Plan is a defined contribution plan, allowing salary
deferral by participants from 1 percent to 14 percent of their salaries, along
with an employer contribution, based on the first 1 or 2 percent of the
employees' compensation they contribute on a pre-tax basis, depending upon
bargaining unit affiliation. These amounts are invested among various
alternatives. The company's contributions to the plans for fiscal years 1996,
1995 and 1994 were $2.2 million, $2.3 million, and $2.2 million, respectively.
8. FERC ORDER NO. 636 AND
TRANSITION COSTS
On November 1, 1993, the Federal Energy Regulatory Commission (FERC)
implemented Order No. 636 (Order). The Order removed the merchant function from
the pipeline companies and required them to provide storage and transportation
services to gas shippers such as the company.
The pipeline companies are incurring certain costs, known as transition costs,
in connection with the implementation of the Order. Transition costs that the
FERC considers to be prudently incurred can be recovered from customers of the
pipelines, such as the company. Through September 30, 1996, the company had
paid $43.7 million in such costs to six pipeline companies and currently
estimates that additional transition costs to be assigned to the company will
not be less than $5.7 million. The company has recorded a liability in the
balance sheet at September 30, 1996 in this amount. The amount paid of $43.7
million includes amounts that were due to Columbia Gas Transmission Corporation
(CGT) which were resolved in a bankruptcy settlement with CGT, as discussed
below.
The total level of transition costs that will ultimately be incurred by the
company and reflected in the financial statements cannot be estimated at this
time. This is because 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.
On November 28, 1995, CGT, as well as its 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 included a comprehensive settlement between CGT
and its customers, including the company. The settlement resolved issues
related to a majority of the transition cost liability due to CGT and refunds
due the company by CGT from other proceedings previously filed before FERC.
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, 1996, the company had
recorded a regulatory asset of $5.7 million for amounts yet to be recovered
from its ratepayers.
9. ENVIRONMENTAL MATTERS
The company and its subsidiaries are subject to federal, state and local laws
and regulations related to environmental matters. These evolving laws and
regulations may require expenditures over a long period of time to control
environmental impacts.
Estimates of liabilities for environmental response costs are difficult to
determine with precision because of the factors that can affect their ultimate
level. These factors include, but are not limited to: (i) the complexity of the
site; (ii) changes in environmental laws and regulations at the federal, state
and local levels; (iii) the number of regulatory agencies or other parties
involved; (iv) new technology that renders previous technology obsolete, or
experience with existing technology that proves ineffective; (v) the ultimate
selection of technology; (vi) the level of remediation required; and (vii)
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
56
<PAGE> 25
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. Studies and analytical work were performed during 1996 and
the project is scheduled to commence in fiscal year 1997, 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 and continue to be recovered from pumping. The company will continue
to pump tar 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. The company
has yet to receive any response from the state regarding its submission. The
company expects to install a recovery system to recover free tar beginning in
fiscal year 1997 and will monitor the site.
At a fourth former MGP site and on an adjacent parcel of land, the company
plans to perform additional studies and analytical work in fiscal year 1997 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 six 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, 1996, the company had paid $9.0 million for environmental
response costs. A liability of $11.7 million on an undiscounted basis has been
recorded as of September 30, 1996 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 is estimated at $20.7 million at September 30, 1996. The estimates were
determined by the company's environmental experts based on experience in
remediating MGP sites and advice from legal counsel and environmental
consultants. Variations within the range of estimated liability result
primarily from differences in the number of years that will be required to
perform environmental response processes at each site (15 to 25 years) and
differences in remediation processes expected to be used.
In orders issued by the PSC of MD, the company has been allowed to recover the
costs associated with the sites applicable to Maryland over periods ranging
from five to thirty years. As a result of rate orders issued by the PSC of DC,
the company has been allowed three-year recovery of prudently incurred
environmental response costs and is being allowed to defer additional costs
incurred between rate cases. As of September 30, 1996, there is no material
environmental regulatory asset subject to recovery in Virginia. The Public
Service Commission of West Virginia has allowed a subsidiary to recover certain
environmental response costs.
At September 30, 1996, the company has recorded a regulatory asset of $12.2
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.
10. ORGANIZATIONAL REDESIGN
In response to the changing requirements it is facing as it addresses the
enhanced competitive markets in which it operates, the company has undertaken
significant efforts to align its organization to meet the new challenges. In
June 1996, it announced a redesigned organizational structure and the process
under which the new organizational structure would be staffed.
The restructuring is being completed in a move to emphasize operating
efficiency and to ensure superior customer service. The new structure, which is
expected to be in place by December 31, 1996, flattens the corporate hierarchy
and results in fewer supervisory positions.
In the initial stage of the reorganization, the company offered certain
eligible supervisory employees a voluntary separation pay program which
entitles these employees to a year of salary upon reaching their separation
date, and 87 employees accepted. In the staffing phase of the reorganization
process, management positions are being filled through a competitive bidding
and selection process. Employees not selected to fill management positions in
the staffing phase may choose from among three options: (i) leave the company's
payroll and receive voluntary separation pay; (ii) remain on the payroll for up
to six months while receiving the assistance of outplacement services; or (iii)
join a program that will allow employees to perform short-term work assignments
for up to nine months.
In fiscal year 1996, the company recorded in operation expenses nonrecurring
charges of $13.4 million. As of September 30, 1996, $2.6 million of this amount
had been paid and the remainder is expected to be paid by March 31, 1997.
57
<PAGE> 26
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 $30.5 million and
$45.1 million in 1996 and 1995, respectively. The transfers were recognized as
a sale in accordance with SFAS No. 77. At September 30, 1996, $56.0 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 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 13 long-term natural gas purchase contracts with producers or
marketers to purchase natural gas at market-sensitive prices. These contracts
provide for commodity charges based upon an ascertainable index and either
fixed reservation charges based on contracted minimum volumes or premiums built
into volumetric charges. The contracts also provide for the company to pay
monthly and/or annual deficiency charges if actual volumes fall below minimum
levels. These gas purchase contracts have expiration dates ranging from fiscal
years 1998 to 2004. At September 30, 1996, the company is required to make
total payments under these natural gas purchase contracts, exclusive of
commodity charges based on quantities purchased, in the amount of approximately
$22.1 million, including annual payments of $3.4 million in 1997 through 1999
and $3.1 million in 2000 and 2001.
The company also has pipeline service agreements with four pipelines that serve
the company directly and four upstream pipelines that provide for firm
transportation and storage services. These agreements, which have expiration
dates ranging from fiscal years 1997 to 2015, provide for the company to pay
fixed monthly charges. The aggregate amount of required payments under the
pipeline service agreements totals approximately $891 million, including
required annual payments of $105 million in 1997, $104 million in 1998, $103
million in 1999, $103 million in 2000 and $98 million in 2001.
The costs incurred under these natural gas purchase contracts and pipeline
service agreements 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, 1996 and 1995. The fair
value of a financial instrument is the amount at which the instrument could be
exchanged in a current transaction between willing parties.
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.
FAIR VALUE OF FINANCIAL INSTRUMENTS
<TABLE>
<CAPTION>
1996 1995
-------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------------------------------------------------------------------------------
(Millions)
<S> <C> <C> <C> <C>
Current assets $ 89.6 $ 89.6 $ 63.9 $ 63.9
Current liabilities 262.3 262.3 208.3 208.3
Long-term debt 353.9 353.1 329.1 341.7
</TABLE>
58
<PAGE> 27
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The presentation of financial data that accurately and fairly reflects the
results of operations and financial position of the company is one of
management's stewardship obligations to its shareholders. 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, to discuss, among other
things, the company's system of internal accounting controls and the adequacy
of the internal audit program. The report of the Audit Review Committee appears
below.
As discussed in their report, the Audit Review Committee also meets
periodically with Arthur Andersen LLP, the company's independent public
accountants, with and without management, to discuss the results of Arthur
Andersen LLP's audit of the company's financial statements. The report of
Arthur Andersen LLP appears below.
<TABLE>
<S> <C>
/s/ PATRICK J. MAHER /s/ FREDERIC M. KLINE
Patrick J. Maher, Chairman of the Board and Chief Executive Officer Frederic M. Kline, Vice President and Treasurer
</TABLE>
REPORT OF THE AUDIT REVIEW COMMITTEE
The Audit Review Committee of the Board of Directors of Washington Gas Light
Company is comprised of five directors who are not employees of the company:
Orlando W. Darden (Chairman), Fred J. Brinkman, Daniel J. Callahan, III, Karen
Hastie Williams and Stephen G. Yeonas. The committee held five meetings during
fiscal year 1996.
The Audit Review Committee oversees Washington Gas Light Company's financial
reporting process on behalf of Washington Gas Light Company's Board of
Directors. In fulfilling its responsibility, the committee recommended to the
Board of Directors, subject to ratification by the stockholders, the selection
of Washington Gas Light Company's independent public accountants, Arthur
Andersen LLP.
The Audit Review Committee discussed with the company's internal auditor and
the independent public accountants the overall scope and specific plans for
their respective audits, and the adequacy of the company's internal controls.
The committee discussed the company's financial statements with the independent
public accountants and met separately with the company's internal auditor and
independent public accountants, with and without management present, to discuss
the results of their audits, their evaluation of the company's internal
controls, and the overall quality of the company's financial reporting. The
meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditor or independent
public accountants.
/s/ ORLANDO W. DARDEN
Orlando W. Darden, Chairman, Audit Review Committee
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Washington Gas Light Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Washington Gas Light Company (a District of
Columbia and Virginia corporation) and subsidiaries as of September 30, 1996
and 1995, 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, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 1996 in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSON LLP
Washington, D.C.,
October 28, 1996.
59
<PAGE> 28
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 1996
Operating revenues $274,326 $431,826 $157,760 $105,866
Operating income (loss) 47,021 75,458 1,587 (11,003)
Net income (loss) 38,340 66,909 (5,421) (18,237)
Earnings (loss) per average share
of common stock (a) .88 1.54 (.13) (.43)
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)
</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 1996
Fourth Quarter $ 22-7/8 $ 20-3/8 $ .285 8/1/96
Third Quarter 22.00 19-1/8 .285 5/1/96
Second Quarter 22-1/2 20-1/2 .280 2/1/96
First Quarter 22-3/8 18-1/2 .280 11/1/95
FISCAL YEAR 1995
Fourth Quarter $ 20-1/2 $ 17-5/8 $ .280 8/1/95
Third Quarter 21 18-1/2 .280 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
</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, 1996, the company had 25,292 common
shareholders.
60
<PAGE> 29
Appendix A
WASHINGTON GAS LIGHT COMPANY
GRAPHS INCLUDED IN MANAGEMENT'S DISCUSSION AND ANALYSIS
1996
<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 1991 - 1996. applicable to common stock for 1991 - 1996.
year Dollars year Millions of dollars
<S> <C> <C> <C>
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
1996 1.85 1996 80.3
</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 1991 -1996. cost of gas per therm for 1991 - 1996.
millions of dollars
Net Cost of
year Revenues Gas total year cents per therm
<S> <C> <C> <C> <C> <C>
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
1996 500 470 970 1996 32.67
</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 1991 -1996. company's capital structure for 1991 -1996.
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>
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
1996 221 118 48 387 1996 354 28 559 941
</TABLE>
<PAGE> 1
EXHIBIT 21
WASHINGTON GAS LIGHT COMPANY
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
Percent of
Voting
Securities State of
Owned Incorporation
---------- -------------
<S> <C> <C>
Subsidiaries of Washington Gas Light
Company (Parent) -
Shenandoah Gas Company 100% Virginia
Hampshire Gas Company 100% West Virginia
Crab Run Gas Company 100% Virginia
Washington Gas Energy Services, Inc. a/ 100% Delaware
Virginia Intrastate Pipeline Company b/ 100% Virginia
a/ Subsidiary companies of Washington
- - Gas Energy Services, Inc. -
Washington Gas Energy Systems, Inc. 100% Delaware
Brandywood Estates, Inc. 100% Maryland
Advanced Marketing Concepts, Inc. b/ 100% Delaware
b/ Inactive
- -
</TABLE>
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included or incorporated by reference in this Form
10-K, into the Company's previously filed Registration Statements File Nos.
33-57041, 33-61199, 333-01469, 333-01471, and 333-16181.
ARTHUR ANDERSEN LLP
Washington, D.C.,
December 18, 1996.
<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>
<S> <C>
<MULTIPLIER> 1,000
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-START> OCT-01-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,127,614
<OTHER-PROPERTY-AND-INVEST> 2,960
<TOTAL-CURRENT-ASSETS> 215,745
<TOTAL-DEFERRED-CHARGES> 118,282
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,464,601
<COMMON> 43,727
<CAPITAL-SURPLUS-PAID-IN> 301,456
<RETAINED-EARNINGS> 213,626
<TOTAL-COMMON-STOCKHOLDERS-EQ> 558,809
0
28,440
<LONG-TERM-DEBT-NET> 353,893<F1>
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 269,390<F2>
<COMMERCIAL-PAPER-OBLIGATIONS> 115,278
<LONG-TERM-DEBT-CURRENT-PORT> 8,006
0
<CAPITAL-LEASE-OBLIGATIONS> 384
<LEASES-CURRENT> 384
<OTHER-ITEMS-CAPITAL-AND-LIAB> 399,791
<TOT-CAPITALIZATION-AND-LIAB> 1,464,601
<GROSS-OPERATING-REVENUE> 969,778
<INCOME-TAX-EXPENSE> 49,376
<OTHER-OPERATING-EXPENSES> 807,339
<TOTAL-OPERATING-EXPENSES> 856,715
<OPERATING-INCOME-LOSS> 113,063
<OTHER-INCOME-NET> (874)
<INCOME-BEFORE-INTEREST-EXPEN> 112,189
<TOTAL-INTEREST-EXPENSE> 30,598
<NET-INCOME> 81,591
1,332
<EARNINGS-AVAILABLE-FOR-COMM> 80,259
<COMMON-STOCK-DIVIDENDS> 49,366
<TOTAL-INTEREST-ON-BONDS> 30,598<F3>
<CASH-FLOW-OPERATIONS> 57,271
<EPS-PRIMARY> 1.85
<EPS-DILUTED> 1.85
<FN>
<F1>Represents total long-term debt including $85,500 in First Mortgage Bonds,
$269,200 in unsecured medium-term notes, $190 in other long-term debt and
$(997) in unamortized premium and discount-net.
<F2>Includes $269,200 in unsecured medium-term notes and other notes of $190.
<F3>Represents total interest expense, per Statement of Income.
</FN>
</TABLE>
