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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission file number 1-1483
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WASHINGTON GAS LIGHT COMPANY
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(Exact name of registrant as specified in its charter)
District of Columbia and Virginia 53-0162882
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1100 H Street, N. W., Washington, D. C. 20080
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (703) 750-4440
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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Common Stock $1.00 par value New York Stock Exchange
Philadelphia Stock Exchange
Preferred Stock, cumulative,
without par value:
$4.25 Series Philadelphia Stock Exchange
$4.36 Convertible Series Philadelphia Stock Exchange
$4.60 Convertible Series Philadelphia Stock Exchange
$4.80 Series Philadelphia Stock Exchange
$5.00 Series Philadelphia Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days, Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
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State the aggregate market value of the voting stock held by non-affiliates of
the registrant. The aggregate market value shall be computed by reference to
the price at which the stock was sold, or the average bid and asked prices of
such stock, as of a specified date within 60 days prior to the date of filing.
$ 1,279,774,219 October 29, 1999
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Market Value Date
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
Common Stock $1.00 par value 46,463,552 November 30, 1999
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Class Number of Shares Date
DOCUMENTS INCORPORATED BY REFERENCE
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, 1999.
PART II - Annual Report to Shareholders for the fiscal year ended September
30, 1999 (Pages 16 through 51).
PART III - Proxy Statement for the Annual Meeting of Shareholders to be held
at 10:00 a.m., March 3, 2000, at the Kellogg Conference Center at
Gallaudet University in Washington, D.C.
PART IV - Form S-7 Registration Statement number 2-53658, filed May 12,
1975, and Amendment No. 2 thereof, filed June 24, 1975.
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TABLE OF CONTENTS
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PART I PAGE
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Item 1. Business
Subsidiaries................................................................................. 3
Industry Segments............................................................................ 5
Rate Regulation, Retail Gas Rates and Rate Increases......................................... 6
Competition.................................................................................. 10
Gas Supply and Capacity...................................................................... 15
Environmental Matters........................................................................ 17
Year 2000.................................................................................... 18
Other........................................................................................ 22
Item 2. Properties..................................................................................... 22
Item 3. Legal Proceedings.............................................................................. 23
Item 4. Submission of Matters to a Vote of Security Holders............................................ 23
Executive Officers of the Registrant.................................................................... 24
PART II
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Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.......................................................................... 26
Item 6. Selected Financial Data........................................................................ 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.......................................................... 26
Item 7A. Quantitative and Qualitative Disclosures about Market Risk..................................... 26
Item 8. Financial Statements and Supplementary Data.................................................... 27
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.......................................................... 27
PART III
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Item 10. Directors and Executive Officers of the Registrant............................................. 28
Item 11. Executive Compensation......................................................................... 28
Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................................................. 28
Item 13. Certain Relationships and Related Transactions................................................. 28
PART IV
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Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................................................ 29
Report of Independent Public Accountants on Schedule.................................................... 35
Signatures ............................................................................................ 37
</TABLE>
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FORWARD-LOOKING STATEMENTS
Certain matters discussed in this report, excluding historical
information, include forward-looking statements. Certain words, such as, but
not limited to, "estimates," "expects," "anticipates," "intends," "plans,"
"believes," and variations of these words, identify forward-looking statements
that involve uncertainties and risks.
These statements are necessarily based upon various assumptions with
respect to the future, including: 1) economic, competitive, political and
regulatory conditions and developments; 2) capital and energy commodity market
conditions; 3) changes in relevant laws and regulations, including tax,
environmental and employment laws and regulations; 4) weather conditions; 5)
legislative, regulatory, and judicial mandates and decisions; 6) timing and
success of business and product development efforts; 7) technological
improvements; 8) the pace of deregulation efforts and the availability of other
competitive alternatives; 9) estimates of future costs or the effect on future
operations as a result of events that could result from the Year 2000 issue
described herein; and 10) other uncertainties. Accordingly, while it believes
that the assumptions are reasonable, the Company cannot ensure that all
expectations and objectives will be realized. All forward-looking statements
made in this report rely upon the safe harbor protections provided under the
Private Securities Litigation Reform Act of 1995.
PART I
ITEM 1. BUSINESS
Washington Gas Light Company (Washington Gas or the Company) is a public
utility that delivers and sells natural gas to customers in Washington, D.C.
and adjoining areas in Maryland and Virginia. Washington Gas is the parent
company of a regulated distribution subsidiary, Shenandoah Gas Company
(Shenandoah), which provides distribution services to customers in portions of
Virginia and transportation services to an unaffiliated utility in West
Virginia. The Company has been engaged in the gas distribution business for 151
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. During the fiscal years ending
September 30, 1999, 1998 and 1997, the regulated utility segment produced
revenues of $972 million, $1,041 million and $1,056 million, respectively, or
87%, 91% and 96%, respectively, of the Company's total operating revenues.
The population of the area served by the Company is estimated to be 4.5
million. As of September 30, 1999, the Company and its distribution subsidiary
served 846,381 customer meters. A listing of meters served and therms delivered
as of and for the twelve months ended September 30, 1999, respectively, by
jurisdiction is shown in the table below. A therm of gas contains 100,000
British Thermal Units of heat, the heat content of approximately 100 cubic feet
of natural gas.
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Therms Delivered
Jurisdiction Meters Served (Millions)
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District of Columbia 142,979 317
Maryland 353,524 707
Virginia 349,878 492
West Virginia - 21
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Total 846,381 1,537
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Of the 1,537 million therms delivered in fiscal year 1999, 61% was
sold and delivered by the Company and its distribution subsidiary and 39% was
delivered to various customers that acquired their gas from other suppliers. Of
the total therms delivered by the Company and its distribution subsidiary, 71%
went to firm customers and 29% went to interruptible customers. Interruptible
customers must be capable of using an alternate fuel as a substitute for
natural gas when the Company determines their service must be interrupted to
accommodate firm customers' needs during periods of peak demand.
Therms delivered by the parent company amounted to 96% of the total
consolidated deliveries in fiscal year 1999. For a discussion of therm sales
and deliveries in West Virginia, refer to the caption titled "Shenandoah Gas
Company" in the "Subsidiaries" section below.
SUBSIDIARIES
The Company has four wholly owned active subsidiaries and a 50%
interest in a limited liability company. These subsidiaries are described
below.
SHENANDOAH GAS COMPANY
Shenandoah Gas Company (Shenandoah) is currently engaged in the
delivery and sale of natural gas at retail in the northern Shenandoah Valley of
Virginia, including the City of Winchester and Towns of Middletown, Strasburg,
Stephens City, Berryville, Mount Jackson, Woodstock and New Market. Prior to
July 1, 1999, Shenandoah also served the Eastern Panhandle of West Virginia,
including the City of Martinsburg. Effective July 1, 1999, Shenandoah sold
substantially all of its natural gas utility assets located in West Virginia.
The purchaser is serving Shenandoah's former 3,800 natural gas customers in the
City of Martinsburg and in Berkeley County, West Virginia. To ensure continued
natural gas service in the Eastern Panhandle of West Virginia, Shenandoah
provides natural gas transportation service to the purchaser at the border of
Virginia and West Virginia. Shenandoah continues to provide natural gas utility
service to its nearly 11,000 customers in the northern Shenandoah Valley of
Virginia.
During fiscal years 1999 and 1998, Shenandoah's natural gas therm
deliveries in West Virginia represented less than 2% of the Company's
consolidated natural gas therm deliveries and less than 1% of associated
consolidated revenues. Shenandoah's West Virginia operations did not contribute
a material amount to the Company's net income in either 1999 or 1998.
On September 29, 1999, the Company's Board of Directors authorized a
merger of Shenandoah into Washington Gas to form a single corporation for the
regulated distribution of natural gas. An application was filed on October 5,
1999 with the State Corporation Commission of Virginia (SCC of VA) to begin the
merger process.
HAMPSHIRE GAS COMPANY
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).
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CRAB RUN GAS COMPANY
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, 1999, Crab Run's investment in this partnership
was not material. The Company expects that any additional investments in the
partnership will be minimal.
WASHINGTON GAS RESOURCES CORP.
Washington Gas Resources Corp. (WGR) is a wholly owned subsidiary of
the parent company under which the Company's unregulated subsidiaries, except
Crab Run and Primary Investors, LLC, are organized. WGR's subsidiaries, which
are described below, are Washington Gas Consumer Services, Inc., American
Combustion Industries, Inc. and Washington Gas Energy Services, Inc.
(WGEServices). WGEServices also has subsidiaries, as described further below.
In March 1998, WGR acquired a 100% interest in American Combustion,
Inc. and American Combustion Industries, Inc. The Company purchased these
companies with $3.0 million in cash and the issuance of a $2.0 million
promissory note, which is being repaid in monthly installments over two years
ending March 2000. On March 30, 1999, American Combustion, Inc. was merged into
American Combustion Industries, Inc. (ACI). ACI offers commercial customers
products and services associated with the design, renovation, sale, installation
and service of mechanical heating, ventilating and air conditioning (HVAC)
systems.
WGEServices is primarily engaged in the sale of natural gas in
competition with unregulated gas marketers and unregulated subsidiaries of
other utility companies. WGEServices serves nearly 65,000 residential,
commercial and industrial customers at September 30, 1999, both inside and
outside the Company's traditional service territory. WGEServices is preparing
to sell electricity to customers who participate in electric choice programs
that will soon be implemented in the areas currently serviced by the Company.
WGEServices has three subsidiaries, as described immediately below.
Washington Gas Energy Systems, Inc. (WGESystems), provides commercial
energy services, including the design and renovation of mechanical HVAC systems.
Its business is very similar to that of ACI.
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
proposed approximately 1,600 homes, 100,000 square feet of retail space and
105,000 square feet of office space. In 1999, the rezoning application was
remanded to a zoning hearing examiner for additional review. No date has been
set for a final decision on this application and any action on it is not
imminent. Separately, in July 1999, Brandywood sold separate parcels of
undeveloped land, totaling 1,000 acres, in Prince George's County, Maryland.
The financial effect of this sale is discussed in Note 2 to the Consolidated
Financial Statements, which is incorporated by reference into this report.
Advanced Marketing Concepts, Inc. previously provided services
primarily in the area of energy-related home improvements. This subsidiary is
currently inactive.
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Washington Gas Consumer Services, Inc. (WGCS) offers a program under
which it can earn fees for matching customers with finance companies.
PRIMARY INVESTORS, LLC
In August 1999, the Company and Thayer Capital Partners (Thayer)
formed Primary Investors, LLC, a limited liability company (Primary Investors).
Primary Investors, through its wholly owned subsidiary, Primary Service Group,
LLC (PSG), will focus on investment opportunities in after-market products and
services in the HVAC industry. PSG will sell, install, repair and maintain HVAC
equipment in the residential and light commercial markets. Initially, PSG is
entering this business by acquiring and expanding companies that currently
provide HVAC-oriented products and services in the District of Columbia, and
parts of Maryland and Virginia.
The Company and Thayer each owns 50% of Primary Investors and an equal
number of representatives from the Company and Thayer serve on Primary
Investors' Board of Directors. As a co-investor, the Company has initially
committed to invest up to $25 million of equity capital in Primary Investors.
The Company invested $7.5 million in Primary Investors through September 30,
1999.
INDUSTRY SEGMENTS
The operation of the Company and its subsidiaries is divided into four
segments: 1) regulated utility; 2) energy marketing; 3) HVAC; and 4) customer
financing. The overwhelming majority of consolidated assets are devoted to,
and revenues are derived from, the regulated utility and the energy marketing
segments. However, it is the plan of the Company to increase the significance
of the other segments.
Regulated Utility--The parent company, Washington Gas, and Shenandoah,
deliver natural gas to all retail customers in their service territories in
accordance with tariffs established by the state regulatory commissions that
have jurisdiction over their rates. Hampshire operates its storage facilities on
behalf of the parent company under an FERC-regulated tariff. These tariffs allow
the regulated utility segment the opportunity to earn a fair rate of return on
its invested capital and to recover the costs of providing service. Over 95% of
the assets of the consolidated entity are committed to the regulated utility
segment. During the fiscal years ending September 30, 1999, 1998 and 1997, the
regulated utility segment produced revenues of $972 million, $1,041 million and
$1,056 million, respectively, or 87%, 91% and 96%, respectively, of the
Company's total operating revenues.
Energy Marketing--A wholly owned subsidiary, WGEServices, competes
with unregulated marketers by selling the natural gas commodity directly to
residential, commercial and industrial customers, both inside and outside of
the regulated utility's traditional service territory. WGEServices is preparing
to sell electricity to customers who participate in electric choice programs
that will soon be implemented in the areas currently serviced by the Company.
HVAC--Through two wholly owned subsidiaries, WGESystems and ACI, and
as a partner in newly formed Primary Investors, the Company offers residential
and commercial customers a variety of products and services associated with the
design, renovation, sale, installation, and service of mechanical HVAC systems.
Customer Financing--The parent company offers financing for customers
to purchase natural gas appliances and certain energy-related equipment.
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Note 12 to the Consolidated Financial Statements, which is
incorporated by reference into this report, provides financial information
about each of these reported industry segments for the 1997, 1998 and 1999
fiscal years.
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 SCC of VA. The SCC of VA currently regulates Shenandoah.
The FERC regulates Hampshire.
The PSC of DC consists of three full-time members who are appointed by
the Mayor and confirmed by the District of Columbia City Council. The term of
each commissioner is four years. There are no limitations on the number of
terms that can be served. There is no statutory suspension period related to
rate requests.
The PSC of MD consists of five full-time members who are appointed by
the Governor and confirmed by the Senate of Maryland. Each commissioner is
appointed to a five-year term, with no limit 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. There are two methods
that may be used to request a modification of existing rates. The Company may
file a general rate application through an adjudicated process. The rates under
this process may take effect 150 days after the filing. In addition to the
adjudicated process, 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 allowed rate of return on common equity cannot be modified
from the rate established in the last fully adjudicated case. Before new rates
become final, both types of rate increases are subject to refund.
RETAIL GAS RATES
Unbundling Initiatives
Currently, for the majority of its business, the price the Company
charges its customers is based on the combination of the cost it incurs for the
natural gas commodity delivered to the entry point of the Company's
distribution system and the cost it incurs to deliver natural gas from this
entry point to the customers' premises. Although the Company continues to
generate the majority of its revenues from the sale and delivery of natural gas
on this combined or "bundled" basis, state regulatory and Company initiatives
are seeking to separate or unbundle the sale of the natural gas commodity from
the delivery of gas on the Company's distribution system (delivery service).
Margins generated from delivering customer-owned gas are equivalent to those
earned on bundled gas
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service. Therefore, the Company does not experience any loss of margins from
customers that choose to purchase their gas from a third-party supplier.
In all of the Company's major jurisdictions, nearly all of its
interruptible customers and certain firm customers have the option of
purchasing their gas from third-party suppliers, including the Company's
gas marketing subsidiary, WGEServices. The Company continues to charge these
customers for delivering gas through its distribution system. The status of the
unbundling programs in the Company's major jurisdictions as of September 30,
1999 are discussed further in the section of this report titled "Competition."
As of September 30, 1999, WGEServices provided third-party supplier
gas to interruptible customers in all of the Company's major jurisdictions and
to various firm customers in the District of Columbia and Maryland. WGEServices
retains the full amount of margins generated on sales of the natural gas
commodity.
Regulated Service to Firm Customers
In the District of Columbia jurisdiction, the firm residential and
non-residential rate schedules are based upon a flat commodity charge for each
therm of gas consumed and a 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-charge per customer and
declining block commodity rates. Neither the Company nor its distribution
subsidiary, Shenandoah, have weather-normalization mechanisms designed into
their rate structures.
The current firm tariff provisions in all of the major jurisdictions
of the Company, including Shenandoah, contain gas cost recovery mechanisms that
provide for the recovery of the invoice cost of gas applicable to firm
customers. Under these mechanisms, the Company periodically adjusts its rates
to firm customers to reflect increases and decreases in the invoice cost of
gas. Moreover, regulators in each of the major jurisdictions in which the
Company, including Shenandoah, operate provide for an annual reconciliation of
gas costs collected from firm customers to the invoice cost of gas applicable to
firm customers.
Regulated Service to Interruptible Customers
To receive service as an interruptible customer, the Company requires
these customers to be capable of using an alternate fuel as a substitute for
natural gas when the Company determines their service must be interrupted in
order to accommodate firm customers' needs during periods of peak demand. The
effect on net income of changes in delivered volumes and prices to the
interruptible class is minimized by margin-sharing arrangements that are part
of the design of the Company's rates. Under these arrangements, the Company
returns a majority of the margins earned on interruptible gas sales and
deliveries to firm customers after a gross margin threshold is reached or in
exchange for the shift of a portion of the fixed costs of providing service
from the interruptible to the firm class. In Maryland, the Company retains 100%
of the gross margins associated with sales and deliveries to interruptible
customers until the Company has recovered its investment and capital costs
associated therewith. This arrangement has been in effect in Maryland for
interruptible customers added since August 1989.
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RATE INCREASES IN THE COMPANY'S MAJOR JURISDICTIONS
The Company has not had an increase in its base rates that are charged
to customers in its major jurisdictions since 1994. Details on the most recent
rate increases in each of these jurisdictions are provided below.
District of Columbia
On October 8, 1993, the PSC of DC issued a final order based on a rate
increase requested in December 1992 that approved a $4.7 million increase, or
2.5%, in annual revenues, effective October 19, 1993. The order, which included
an overall rate of return of 9.86% and a return on common equity of 11.50%,
provided for a phase-in, rather than immediate recognition, of the additional
costs associated with the implementation of Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS No. 106). The incremental costs related to SFAS No. 106
were phased-in over a five-year period that ended September 30, 1998. In each
year of the phase-in, the Company filed for an increase in rates, through
streamlined procedures, to reflect an additional increment of SFAS No. 106
costs in excess of a stipulated pay-as-you-go level. The difference between the
incremental annual amount reflected in rates during the phase-in period and the
full SFAS No. 106 cost was deferred as a regulatory asset. On September 30,
1998, the PSC of DC granted the Company recovery of the regulatory asset
established during the phase-in period over a fifteen-year amortization period
effective October 1, 1998.
On August 1, 1994, the PSC of DC issued an order approving a
Stipulation and Agreement signed by a majority of the parties to a rate case
filed in January 1994, providing for a $6.4 million annual increase in
revenues, or 3.4%, effective August 1, 1994. The agreement did not specify a
rate of return. The agreement provided for an increase in the curtailment
charge to interruptible customers during periods of interruption and
established the previously discussed peak-usage charge for non-residential firm
customers.
Maryland
On July 29, 1993, the PSC of MD authorized an increase in base rates
designed to collect an additional $10.6 million, or 3.7%, in annual revenues,
effective August 1, 1993. The order resulted from a settlement agreement
entered into by most of the parties to a rate case filed in March 1993.
Recovery of SFAS No. 106 costs, which had been included in the Company's
request, was not specifically addressed in the order; however, the amount
authorized was sufficient to cover the costs associated with implementing this
standard in the Company's Maryland jurisdiction. The order also included a
revision to the Company's purchased gas cost recovery mechanism to provide for
recovery of carrying costs on actual storage gas balances and provided for an
annual 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. The Stipulation and Agreement, designed to
collect an additional $7.4 million, or 2.4%, annually went into effect on
December 1, 1994.
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Virginia
On September 27, 1994, the Company implemented rates designed to
recover an additional $15.7 million annually, based on a rate case filed in
April 1994. These rates were collected subject to refund. On September 28,
1995, the SCC of VA issued an order approving an increase in annual revenues of
$6.8 million, or 2.7%, effective September 27, 1994. The order included an
overall rate of return of 9.72% and a return on equity of 11.50%. The order
allowed the Company to collect SFAS No. 106 costs in accordance with a generic
order of the SCC of VA. The Company refunded amounts associated with the
difference between the interim rates that were collected subject to refund and
the amount approved by the SCC of VA, with interest, by January 1, 1996.
Note 10 to the Consolidated Financial Statements, which is
incorporated by reference into this report, includes a discussion of the
conclusion reached in a proceeding in the Company's Virginia jurisdiction
related to the Virginia jurisdictional portion of regulatory assets.
On August 6, 1995, Shenandoah placed into effect new rates in Virginia
designed to collect an additional $1.2 million in annual revenues, subject to
refund, based on a rate case filed in July 1995. On May 30, 1996, the SCC of VA
issued an order approving an increase in annual revenues of $883,000, effective
August 6, 1995. The increase reflected an overall rate of return of 9.51% and a
return on equity of 11.00%. Shenandoah returned, with interest, amounts
collected under interim rates in excess of the amount ultimately granted to
customers by September 1, 1996.
On December 28, 1997, Shenandoah implemented new rates in Virginia
designed to recover an additional $2.3 million annually, based on a rate case
filed in August 1997. On July 16, 1998, the SCC of VA issued an order approving
an increase in annual revenues of $1.4 million, or 6.78%, effective December
28, 1997. The order included an overall rate of return of 9.062% and a return
on equity of 10.70%. Shenandoah refunded amounts associated with the difference
between the interim rates that were collected subject to refund and the amount
approved by the SCC of VA, with interest, by November 1, 1998.
Management's Discussion and Analysis of Financial Condition and
Results of Operations, which is incorporated by reference into this report,
provides a summary of major rate applications and results of the parent
company.
INCENTIVE RATE PLAN PROPOSAL
On May 17, 1999, the Company filed an application for an Incentive
Rate Plan with the PSC of MD. The application requested that the Company's
rates be frozen at current levels for five years from the date of approval. In
addition to the rate freeze, the plan proposes a sharing mechanism when the
Company's earnings on its Maryland business exceeds a 12% return on equity
(ROE), with the customers receiving 50% and the Company retaining 50% of the
excess.
The proposal provides for a change in the 12% benchmark return on
equity when the twelve-month average of 30-year U.S. Treasury bonds moves by
more than 100 basis points in either direction. The proposal also allows for
adjustments to rates due to circumstances beyond the Company's control, such as
changes in tax laws, legislative mandates, Financial Accounting Standards Board
or Securities and Exchange Commission accounting modifications or regulatory
changes. The proposal provides the Company with the opportunity to adjust
rates, subject to PSC of MD review and refund, should its Maryland
weather-normalized
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ROE drop below 8.5%. Finally, the proposal maintains the gas cost mechanisms
that provide for the recovery of actual costs of gas from firm customers.
The Company believes that if the PSC of MD approves the proposal,
Maryland customers would receive significant protection from the risk of
inflationary increases for five years. The Company would also have an
additional incentive to increase its operational efficiency and reduce costs in
order to earn a greater return for its shareholders.
Under this proposal, the Company has an opportunity to increase its
earnings beyond its current 11.50% allowed return on equity. However, this
incentive proposal presents certain risks for the Company since the impact and
the risk of cost increases would almost completely be borne by the Company. The
Company believes that the incentive rate plan it has proposed and the
efficiencies it can derive represent an appropriate balance of the interests of
its customers and its shareholders.
Settlement discussions are currently underway among PSC of MD staff,
intervenor groups and the Company. If successful, the results of these
settlement discussions will be presented to the PSC of MD for its approval.
However, if a settlement is reached among the parties, a decision is not
expected by the PSC of MD that would have an impact on the fiscal year 2000
heating season.
COMPETITION
COMPETITION WITH OTHER ENERGY PRODUCTS
In its regulated utility business, the Company faces competition based
on customers' preferences for natural gas compared to other energy products and
the comparative prices of those products. Currently, the most significant
product competition occurs between natural gas and electricity in the
residential market. The residential market represents a substantial proportion
of the Company's net income. In its service territory, the Company continues to
attract the majority of the new residential construction market. The Company
believes that consumers' continuing preference for natural gas allows it to
maintain a strong presence.
Currently, the Company generally maintains a price advantage over
electricity in its service area. However, as discussed further below,
restructuring in both the natural gas and electric industries is leading to
changes in traditional pricing models. As part of the electric industry
restructuring effort, certain business segments are moving toward market-based
pricing, with third-party providers of electricity participating in retail
markets. Electric restructuring may result in lower comparative pricing for
electric service and other alternative energy sources, including natural gas.
These changes will result in increased competition for the Company.
In the interruptible market, customers must be capable of using a fuel
other than natural gas when demand by the Company's firm customers peaks. Fuel
oil is the most significant competing energy alternative to natural gas. The
Company's success in this market depends largely on the relationship between
gas and oil prices. Because the natural gas marketplace is primarily domestic,
the relationship between supply and demand generally has the greatest impact on
natural gas prices. Because a large portion of oil comes from foreign sources,
political events can have significant influences on oil prices.
10
<PAGE> 13
DEREGULATION
In 1978, the Natural Gas Policy Act was enacted. That act gradually
replaced regulated wellhead prices with natural gas prices that are market
driven. Since 1978, regulators and legislators have instituted an increasing
number of changes aimed at encouraging competition in the utility industry,
whenever it is economically beneficial to consumers.
Historically, and for most current customers of the regulated utility,
the Company provides a "bundled" service that includes two primary functions:
1) the core utility, or delivery, function, which involves delivering the gas
and providing customers with services, such as meter reading, bill preparation
and responding to customer telephone inquiries; and 2) the merchant function,
which involves supplying the natural gas commodity.
As regulatory reforms continue, the merchant and the delivery
functions are now becoming increasingly separated or "unbundled" from one
another at the regulated utility level. Deregulation initiatives to date have
been directed at the merchant function.
Customer choice pilot programs are underway in each of the Company's
jurisdictions that give customers the opportunity to select an unregulated
supplier from whom to purchase their natural gas commodity on a competitive
basis. At the present time, customers may also choose to continue to purchase
their natural gas commodity from the regulated utility. The transition toward
competitive sales of the natural gas commodity provides the Company with
significant opportunities to expand its operations and further improve its
profitability in this competitive market. However, participating in this
rapidly evolving marketplace also poses new risks and challenges that must be
addressed in the Company's current and future strategies. The following
sections discuss strategies the Company is undertaking to address these changes
proactively and to minimize its risk exposure in the years ahead.
The Gas Delivery Function
The gas delivery function, the Company's core business, continues to
be regulated by local regulatory commissions. In developing this core business,
the Company has invested over $2 billion to construct a safe, reliable and
economical gas distribution system.
Because of the high cost, safety and environmental considerations
associated with building and operating a duplicate distribution system, the
Company believes there will continue to be only one owner and operator of the
natural gas distribution system in its franchise areas for the foreseeable
future. In addition, the Company believes that the bypass of its facilities by
other potential delivery service providers is unlikely to become a significant
threat, primarily because of the nature of its customer base and the distance
of most customers from interstate pipelines.
The Company expects that local regulatory commissions will continue
functioning as surrogates for competition by setting the prices and the terms
and conditions for delivery service. Further, the Company believes that local
regulatory commissions will continue to allow it the opportunity to earn a fair
rate of return on the capital invested in its distribution system and to
recover reasonable operating expenses. The Company plans to continue
constructing, operating and maintaining its natural gas distribution system.
11
<PAGE> 14
The Company believes there will not be any change in the near future
of the risk profile of the regulated utility. The sale of the gas commodity by
the utility has historically been a cost that is simply passed through to
customers. Therefore, the extent to which the regulated utility no longer sells
the natural gas commodity, because unregulated marketers are selling it, will
not affect the profitability of the regulated utility.
The Merchant Function and Natural Gas Unbundling
Historically, the Company purchased natural gas for its customers from
producers, and entered into contracts with interstate pipeline companies to
have the gas delivered to its distribution system.
In 1995, Washington Gas became one of the first companies in the
nation to implement a customer choice pilot program for the purchase of natural
gas on an unregulated basis. This change in the historical model gave
participants the opportunity to select a supplier from whom they could purchase
the natural gas commodity. The Company introduced its first pilot program in
Maryland that year and subsequently established similar pilot programs in
Virginia and the District of Columbia. One of the purposes of the programs was
to test customers' acceptance and reaction to choice. Therefore, the
participation in these programs has been voluntary and the number of
participants has been limited by program design.
While participation in the Company's programs varies by jurisdiction,
customers have begun to elect their gas commodity supplier. Out of the more
than 300,000 customers eligible to participate in these programs on December 1,
1999, over 130,000 customers have already elected to purchase the natural gas
commodity from an unregulated third-party supplier, such as WGEServices. The
following table provides the status of natural gas unbundling in the Company's
major jurisdictions at December 1, 1999. The number and percentage of customers
reflected in this table include all customers who chose to purchase natural gas
from a third-party marketer, such as WGEServices.
<TABLE>
<CAPTION>
Eligible Customers
-------------------------
Jurisdiction Customer Class Total % Participating
- ------------ -------------------------- ------- ---------------
<S> <C> <C> <C>
Maryland Residential 100,000 70%
Commercial 25,000 43%
Industrial (>60,000 therms) 298 100%
Virginia Residential 64,000 52%
Commercial 5,657 100%
Industrial 230 90%
District of
Columbia Residential 130,000 8%
Small Commercial
(<40,000 therms) 13,000 18%
Large Commercial
(>40,000 therms) 488 26%
Interruptible 268 22%
</TABLE>
In the years ahead, the Company expects that these pilot programs will
be expanded gradually to include all natural gas customers. Ultimately, the
Company expects the regulated utility will play a much smaller role in the
merchant function and may eventually exit the merchant function as customers
buy natural gas from unregulated marketers. During this transition period, the
Company will continue to have certain obligations under long-term contracts to
purchase
12
<PAGE> 15
natural gas from producers and transportation capacity from interstate pipeline
companies. Accordingly, the Company's strategy focuses on recovering
contractual costs and maximizing the value of contractual assets. Note 10 to
the Consolidated Financial Statements, which is incorporated by reference into
this report, includes a description of the Company's obligations under natural
gas contracts.
Currently, the regulated utility includes the cost of the natural gas
commodity and pipeline services in the purchased gas costs that are included in
firm customers' rates, subject to regulatory review. The Company's
jurisdictional tariffs contain gas cost mechanisms that provide for the
recovery of the actual invoice cost of gas applicable to firm customers. The
Company believes it prudently entered into its gas contracts and that the costs
being incurred should be recoverable from customers. If future unbundling or
other initiatives remove the current gas cost recovery provisions, the Company
could suffer adverse impacts to the extent its gas costs are not competitive
and there are no other satisfactory regulatory mechanisms available to recover
any costs that may exceed market prices.
The Company currently has recovery mechanisms for such potentially
stranded costs in Maryland and the District of Columbia. In an interim ruling
addressing the Company's request for specific treatment of potential stranded
costs, the SCC of VA deferred consideration of the recovery of any
substantiated stranded costs to a future base rate proceeding. In the event
that a regulatory body disallows the recovery of such costs, they would be
borne by shareholders.
To minimize its exposure to long-term fixed cost contracting risk
during the transition period, the Company is not currently renewing expiring
long-term gas commodity and pipeline transportation and storage contracts. As
these contracts expire, the Company is entering into flexible short-term
purchasing arrangements when gas demand justifies additional resources. By
utilizing this strategy, the Company is mitigating its exposure to long-term
commitments, while continuing to ensure reliable and competitively priced gas
for its customers that continue to buy the natural gas commodity from the
regulated utility.
To maximize the value of its contractual assets, the Company has
entered into contracts with unregulated marketers that make use of the
Company's firm storage and transportation rights to meet the Company's
city-gate delivery needs and to make off-system sales when such storage and
transportation rights are underutilized. The Company continues to pay the fixed
charges associated with the firm storage and transportation contracts used to
make sales.
As local distribution companies' role in the merchant function
decreases over time, opportunities emerge for unregulated natural gas
providers. In the deregulated marketplace, third-party suppliers have
profit-making opportunities, but also assume the risk of loss.
Recognizing the opportunity to improve its profitability, the Company
established WGEServices, an unregulated gas marketing subsidiary, in 1997. To
date, WGEServices has attracted customer choice participants both inside and
outside the Company's traditional service area. Since it was established,
WGEServices has grown its unregulated customer base to include nearly 65,000
residential, commercial, industrial and governmental customers. Gross revenues
in 1999 were $103.9 million and net income was $1.6 million. The Company
believes that the customer choice programs will continue to expand, as well as
WGEServices' participation in these programs.
13
<PAGE> 16
The regulatory process buffers utilities somewhat from certain types
of risks. These protections do not, however, apply to unregulated marketers
such as WGEServices. Thus, while WGEServices has a significant potential for
continued growth, it must carefully manage the associated risks in order to be
successful.
WGEServices must compete with other third-party suppliers in order to
sell the natural gas commodity to customers. The prices WGEServices charges for
the natural gas commodity must be competitive with those charged not only by
other third-party suppliers, but also with those charged by the parent company,
Washington Gas, as part of its continued bundled service. WGEServices must also
spend considerable resources to attract new customers and retain its existing
customers. Consequently, operating margins for WGEServices tend to be low.
In addition, WGEServices faces supply-side risks. To minimize its
supply-side risks, WGEServices has a strategy to manage its natural gas
contract portfolio in a manner that closely aligns the volumes of gas it
purchases with firm commitments from customers to purchase this gas.
WGEServices purchases its gas from a number of wholesale suppliers in order to
avoid relying on any single provider for its natural gas supply. Similarly,
WGEServices' dependency on any one customer or group of customers is limited.
Electric Unbundling
Customer choice programs are not unique to the natural gas industry.
Choice for electric customers has been legislated or is being considered in
each jurisdiction in which the Company operates. These programs allow customers
to select their electric supplier as soon as July 2000, with phase-in periods
through 2004.
As local regulatory commissions move forward on electric deregulation
initiatives, the Company plans to take advantage of the new opportunities
provided by deregulation by further diversifying its products and services.
WGEServices is preparing to sell electricity to customers in the
electric customer choice programs that will soon be implemented in the areas it
currently serves. It intends to serve the same diversified customer base that
it services in its unregulated gas marketing business.
Potential for Further Unbundling
Currently, the parent company provides customer services, such as
preparing bills, reading meters and responding to customer inquiries, as part
of the regulated utility function. Unregulated third-party marketers have the
option to assume responsibility for bill preparation and customer collections.
In addition to billing and collecting from customers for the natural gas
commodity, third-party marketers' bills may include natural gas delivery
charges due the regulated utility, which are subsequently remitted to
Washington Gas.
Although the Company still provides most services on a bundled basis,
the potential exists for future deregulation initiatives to separate these
services from the core utility function. In that case, customers could choose
to have unregulated competitors provide these services.
The Company continues to improve quality and efficiencies and to
reduce the cost of performing these functions with a goal of achieving market
level performance in order to be competitive. As the functions become
unbundled, the Company will continue to review its role in that marketplace.
14
<PAGE> 17
GAS SUPPLY AND CAPACITY
The Company and its regulated distribution subsidiary, Shenandoah,
arrange to have natural gas delivered to the entry points of their distribution
systems (city gates) using the delivery capacity of interstate pipelines
companies. The Company acquires natural gas delivery and storage capacity 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, conservation, and movement of customers from
bundled to unbundled service.
Pursuant to FERC Order No. 636, the pipeline companies are required to
provide transportation and storage services to gas shippers, such as the
Company, including Shenandoah, that are comparable to the services the Company
received prior to the implementation of the order. At September 30, 1999, the
Company had service agreements with four pipeline companies that serve the
Company directly and three upstream pipelines that provide for firm
transportation and storage services. These contracts have expiration dates
ranging from 2001 to 2016.
The Company is responsible for acquiring sufficient gas supplies to
meet customer requirements, as well as the appropriate pipeline capacity to
ensure delivery to the Company's distribution system. The Company's contracting
activities take into account the continuing trend toward unbundling the sale of
the gas commodity from the delivery of the commodity to the customer, by
entering into flexible short-term agreements 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 uses multiple supply sources,
dependable transportation and storage arrangements and its own substantial
storage and peaking capabilities to meet its customers' demands.
The Company has 11 long-term natural gas supply contracts with various
producers or marketers that expire between fiscal years 2001 and 2003. Under
these contracts, the Company can purchase up to 99.6 million dekatherms of
natural gas per year. The Company acquires the balance of its supplies at
market prices under shorter-term contracts.
As reflected in the first table below, there were six sources of
delivery through which the Company received natural gas at its city gates to
satisfy the sendout requirements in pipeline year 1999 (November 1, 1998
through October 31, 1999) and from which supplies can be received in pipeline
year 2000 (November 1, 1999 through October 31, 2000). Firm transportation
denotes gas transported directly to the entry point of the Company's
distribution system in volumes agreed upon by the Company and the applicable
pipeline. Transportation storage denotes volumes stored by a pipeline for
withdrawal during the heating season. Peak load requirements are met by: 1)
underground natural gas storage at the Hampshire Gas Company storage field in
Hampshire County, West Virginia; 2) the local production of natural gas at
propane air plants located at Company-owned facilities in Rockville, Maryland
and Ravensworth, Virginia; and 3) other storage and peak-shaving arrangements.
Unregulated third-party marketers acquire interstate pipeline capacity and the
natural gas commodity on behalf of the Company's regulated utility customers.
These marketers have natural gas delivered to the entry point of the Company's
delivery system on behalf of those utility customers that have decided to
acquire the natural gas commodity on an unbundled basis as previously discussed.
15
<PAGE> 18
During pipeline year 1999, total sendout on the system was 1,580
million therms, including the sendout of sales and deliveries of natural gas
used for electric generation. The sendout for pipeline year 2000 is estimated
to be 1,533 million therms (based on normal weather), excluding the sendout for
the sales and deliveries of natural gas used for electric generation. The
sources of delivery and related volumes that were used to satisfy the
requirements of pipeline year 1999 and those projected for pipeline year 2000
are shown in the following table.
SOURCES OF DELIVERY FOR
ANNUAL SENDOUT
(Millions of Therms)
<TABLE>
<CAPTION>
Pipeline Year
-----------------------------------------
Sources of Delivery Actual 1999 Projected 2000
--------------------------------- ----------- --------------
<S> <C> <C>
Firm Transportation 612 579
Transportation Storage 337 292
Hampshire Storage 16 20
Company-Owned Propane-Air Plants 1 4
Other Peak-Shaving Sources 4 21
Unregulated Third-Party Marketers 610 617
----- -----
1,580 1,533
===== =====
</TABLE>
The effectiveness of the Company's gas supply program is largely
dependent on the sources from which the design day requirement is satisfied. A
design day is the maximum anticipated demand on the gas supply system during a
24-hour period assuming a 5 degree Fahrenheit average temperature. The Company
assumes that all interruptible customers will be curtailed on the design day.
The Company's design day estimate is currently 14.5 million therms. The Company
is currently capable of meeting 69% of its design day requirements with storage
and peaking capabilities. Emphasizing storage and peaking facilities on the
Company's design day reduces the necessity to purchase firm transportation, the
most expensive form of capacity from a design day perspective. The following
table reflects the sources of delivery that are projected to be used to satisfy
the design day sendout estimate for pipeline year 2000.
PROJECTED SOURCES OF DELIVERY FOR
DESIGN DAY SENDOUT
(Millions of Therms)
<TABLE>
<CAPTION>
Pipeline Year 2000
----------------------
Sources of Delivery Therms Percent
------------------------------------- ------ -------
<S> <C> <C>
Firm Transportation 3.4 23%
Transportation Storage 5.0 35
Company-Owned Propane-Air Plants,
Hampshire Storage and Other Peaking 4.9 34
Unregulated Third-Party Marketers 1.2 8
---- ---
14.5 100%
==== ===
</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. In the event that unregulated third-party marketers are unable to
deliver the quantities indicated above, the Company believes it has the ability
to enter the interstate market to secure sufficient capacity to make up any
such third-party
16
<PAGE> 19
marketer shortfalls. The Company continues to seek opportunities to restructure
existing contracts to maximize the competitiveness of its gas supply portfolio.
ENVIRONMENTAL MATTERS
The Company and its subsidiaries are subject to federal, state and
local laws and regulations related to environmental matters. These evolving
laws and regulations may require expenditures over a long timeframe to control
environmental impacts.
Estimates of liabilities for environmental response costs are difficult
to determine with precision because of the factors that can affect their
ultimate level. These factors include, but are not limited to: 1) the
complexity of the site; 2) changes in environmental laws and regulations at the
federal, state and local levels; 3) the number of regulatory agencies or other
parties involved; 4) new technology that renders previous technology obsolete or
experience with existing technology that proves ineffective; 5) the ultimate
selection of technology; 6) the level of remediation required; and 7) variations
between the estimated number of years that must be devoted to respond to an
environmentally contaminated site as compared to the actual number of years
required.
The Company has identified up to ten sites where the Company, its
subsidiaries, or their predecessors may have operated manufactured gas plants
(MGPs). The Company last used any such plant in 1984. In connection with these
operations, the Company is aware that certain by-products of the gas
manufacturing process are present at or near some former sites and may be
present at others.
At one of the former MGP sites, studies show the presence of coal tar
under the site and an adjoining property. The Company's risk assessment study
performed on the site shows that there is no unacceptable risk to human health
or the environment. The Company has taken steps to control the movement of
contaminants into an adjacent river by installing a water treatment system that
removes and treats contaminated groundwater at the site. The Company completed
a feasibility study of remedial alternatives in fiscal year 1998 and submitted
its recommended remedial action plan to the appropriate governmental agencies.
Both the U.S. Environmental Protection Agency and the local environmental
agency have approved the Company's remediation plan.
At a second former MGP site, tests identified tar products under the
property. However, a risk assessment showed that there was no unacceptable risk
to human health or the environment. The Company designed and installed a
state-approved treatment and recovery system to recover free tar and continues
to recover minimal volumes of tar products from pumping. The Company will
continue to pump tar, monitor the site and provide annual activity reports to
the state's Department of the Environment.
At a third former MGP site, initial studies determined that tar
products are present under the property, but a risk assessment showed that
there was no unacceptable risk to human health or the environment. The Company
completed and submitted a remedial investigation/feasibility study to the
appropriate state regulatory agency. The Company has yet to receive any
response from the state regarding its submission, but continues to monitor the
site.
At a fourth former MGP site and on an adjacent parcel of land, the
Company has applied for the state voluntary closure program, which will require
some additional study to determine ultimate resolution.
17
<PAGE> 20
At a fifth former MGP site, a treatment system for contaminated
groundwater has been operating for nine years. The Company believes, at this
time, that no additional action other than water treatment will be necessary.
At a sixth former MGP site, a local government has notified the
Company about the detection of a substance in an adjacent river that may be
related to this site. This same local government owned and operated the MGP for
the majority of the life of the plant. The local government sold the MGP to a
company, which was subsequently merged into Washington Gas. Washington Gas
retired the MGP many years ago. In addition, the Company is aware that the
local government has had communications about this condition with federal
environmental authorities. At this time, the extent and nature of the
contamination and the Company's related obligation, if any, to perform
remediation cannot be determined. The Company hopes to have discussions with
the local government and may participate in studies to assess the extent and
nature of contamination as well as the need for remediation.
Through September 30, 1999, the Company had paid $11.0 million for
environmental response costs. The Company has recorded a liability of $8.7
million on an undiscounted basis at September 30, 1999 related to future
environmental response costs. This estimate is primarily composed of the
minimum liabilities associated with a range of environmental response costs
expected to be incurred at five of the six sites described above. The Company
estimates the maximum liability associated with these sites to be approximately
$20.3 million at September 30, 1999. 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 (2 to 25 years) and the extent of remediation that may
be required.
The Company believes, at this time, that no remediation of any of the
remaining four sites will be necessary.
Based on existing knowledge, the Company does not expect that the
ultimate impact of these matters will have a materially adverse effect on the
level of its capital expenditures, its earnings or its competitive position.
YEAR 2000
The millennial change to the Year 2000 could affect the Company's
software programs and computing infrastructure that use two-digit years to
define the applicable year, rather than four-digit years. As such, they may
recognize a date using "00" as being the year 1900 rather than the year 2000.
This could result in the computer or device shutting down, performing incorrect
computations or performing inconsistently.
In 1996, the Company began a structured program to address Year 2000
issues. It has been implementing individual strategies targeted at the specific
nature of Year 2000 issues in each of the following areas: 1)
business-application systems including, but not limited to, the Company's
customer service, operations and financial systems and end-user applications;
2) embedded systems, including equipment that operates such items as the
Company's storage and distribution system, meters, telecommunications, fleet
and buildings; 3) vendor and supplier relationships; 4) communications with
customers; 5) business continuity management planning; and 6) independent
verification and validation.
18
<PAGE> 21
To implement this comprehensive Year 2000 program, the Company
established a Year 2000 Project Office, chaired by the Vice President and Chief
Information Officer who reports directly to the Chairman and Chief Executive
Officer. The multi-disciplinary project office includes executive management
and employees with expertise from various disciplines including, but not
limited to, information technology, engineering, finance, communications,
internal audit, facilities management, procurement, operations, law and human
resources. In addition, the Company has utilized the expertise of outside
consultants to assist in the implementation of the Year 2000 program in such
areas as business-application system remediation, business-application system
replacement, embedded systems inventory and analysis, business continuity
management planning, and independent verification and validation.
BUSINESS APPLICATION SYSTEMS
In March 1997, the Company completed its assessment of all its
business-application systems. It has resolved Year 2000 issues through
remediation of 18 systems to recognize the turn of the century and the
replacement of 21 systems with new systems that provide additional business
management information and recognize four-digit years. The Company has
completed modifications to all 18 of the business applications targeted for
remediation. Thus, the applications targeted for remediation have been
remediated, tested and placed back into a Year 2000 operational environment.
The Company used in-house staff to test all remediated applications
and used a testing procedure commonly known as trace-based testing to test
modified business applications for Year 2000 functionality. This method first
captures current processing steps and relevant data, which are run prior to
remediation (baseline test) and again after remediation (regression test). This
process is intended to identify any business rules that may have changed during
the remediation effort and to confirm that only date processes have been
changed. Once the regression test was successfully completed, the Company used
automated test software tools to perform additional applicable future date
tests for each system.
The Company installed an enterprise-wide software system that replaced
19 business application systems, including its financial, human resources and
supply chain systems. Two other systems have been replaced with systems not
included in the enterprise-wide software initiative. These 21 business
applications represent approximately one-half of the business application
software code requiring remediation or replacement. The Company has completed
the replacement of all critical and important business applications.
During the fourth quarter of fiscal year 1998, the Company completed a
comprehensive, prioritized inventory of end-user applications (i.e., PC-based
databases) and has implemented, replaced or remediated these applications, as
necessary. The Company has completed the replacement or remediation and testing
of all critical end-user applications.
EMBEDDED SYSTEMS
The Company has performed a comprehensive inventory of its embedded
systems at the component level. This inventory identified several hundred
components that were potentially date sensitive. The Company has contacted all
manufacturers of those components that it has identified as critical or
important to its operations. Approximately 3% of the date-sensitive components
that the Company has identified were non-compliant based on information
provided by the
19
<PAGE> 22
manufacturers. All critical and important components have been remediated,
tested and placed back into production.
VENDOR AND SUPPLIER RELATIONSHIPS
The Company has contacted in writing or through face-to-face
discussions all vendors and suppliers of products and services that it
considers critical or important to its operation. These contacts include
providers of interstate transportation capacity and storage, natural gas
suppliers, financial institutions and electric, telecommunications and water
companies. The Company has evaluated responses and continues the process of
following up with the vendors and suppliers either through meetings or by
letter. The Company recognizes there are no practical alternatives for external
infrastructure such as electric, telecommunications and water services,
suppliers of natural gas and providers of interstate transportation capacity
and storage to deliver natural gas to the Company's distribution system.
However, based upon the Company's communications with these suppliers, the
Company expects these providers to be ready to provide service at the turn of
the century and beyond.
CUSTOMER COMMUNICATIONS
The Company is communicating with its major interruptible customers to
inform them about the potential vulnerability of embedded boiler and plant
control systems. Last year the Company informed them that they should assess
the need to include potential remediation and/or replacement of these systems
as part of their Year 2000 programs to ensure their ability to switch to an
alternate fuel source, as required by applicable tariffs and contracts, if
called on to do so. In the summer of 1999, the Company informed its
interruptible customers that all interruptible sales and interruptible delivery
service customers will be required to switch to their alternate fuel sources on
the morning of December 31, 1999.
In addition, the Company is explaining its Year 2000 efforts to
customers through individual, community and association presentations; through
responses to written inquiries; through brochures explaining its program, which
were mailed to customers; and through its website.
YEAR 2000 RISKS AND BUSINESS CONTINUITY PLANNING
With respect to its internal operations, over which the Company has
direct control, the Company believes the most significant potential risks are:
1) its ability to use electronic devices to control and operate its
distribution system; 2) its ability to render timely bills to its customers; 3)
its ability to enforce tariffs and contracts applicable to interruptible
customers; and 4) its ability to maintain continuous operation of its computer
systems. The Company's Year 2000 program addresses each of these risks and the
remediation or replacement of these systems is essentially complete. In the
event that any Year 2000-related problems may occur, the Company's continuity
plan will outline alternatives to mitigate the impact of such failures, to the
extent possible.
The Company relies on the suppliers of natural gas and interstate
transportation and storage capacity to deliver natural gas to the Company's
distribution system. The external infrastructure, including electric,
telecommunications and water services, is necessary for the Company's basic
operation, as well as the operations of many of its customers. Should any of
these critical vendors fail, the impact of any such failure could become a
significant challenge to the Company's ability to meet the demands of its
customers, to operate its distribution system and to communicate with its
20
<PAGE> 23
customers. It could also have a material adverse financial impact including,
but not limited to, lost revenues, increased operating costs and claims from
customers related to business interruptions. The Company has no way of ensuring
that those vendors or suppliers mentioned above, for which there are no viable
options, will be timely Year 2000 compliant.
As part of its normal business practice, the Company maintains plans
to follow during emergency circumstances. These plans are being used as a basis
to build the Company's continuity plan for potential Year 2000-related
problems. As part of its contingency planning effort, the Company has performed
tabletop exercises to validate this plan. The Company will continue performing
tabletop exercises and drills, which are expected to continue through the end
of calendar year 1999.
The Company maintains and operates a command center that is activated
during emergency circumstances. The Company will manage specific Year 2000
continuity operations from the command center during the millennium change, as
well as at other points in time on an as-needed basis. The Company has informed
its employees that every employee will be expected to work or be available to
work between December 27, 1999, and January 7, 2000, and between February 22,
2000, and March 7, 2000.
Because of the interconnected nature of potential Year 2000-related
problems, the Company recognizes that effective continuity planning must focus
on both internal and external operations. Therefore, the Company has been in
contact with and will work with federal, state and local governmental agencies,
as well as local organizations and other utilities as it completes its planning
effort.
The Company believes that its work will serve to reduce the risk that
its internal systems will fail for Year 2000 reasons. However, the continuity
plan cannot fully offset interrupted delivery to the Company's distribution
system of natural gas by the producers of natural gas and providers of
interstate transportation capacity or the impact on operations of failures of
electric, telecommunications and water services.
INDEPENDENT VERIFICATION AND VALIDATION
The Company worked with external consultants to verify and validate
the Company's Year 2000 remediation and replacement strategies and results for
both business applications and embedded systems.
To verify and validate the Company's remediation efforts of its
business applications, the consultants reviewed all remediated business
applications to determine that the code was remediated correctly. The
consultants have reviewed the compliance statements received from the
manufacturers of the critical and important embedded system components and,
where possible, developed strategies and testing procedures to verify the
compliance statements. The Company has independently tested all of those
critical and important embedded systems that it has determined it can
meaningfully test.
FINANCIAL IMPLICATIONS
Management's Discussion and Analysis of Financial Condition and Results
of Operations, which is incorporated by reference into this report, describes
the financial implications of the Year 2000 activities of the Company.
21
<PAGE> 24
OTHER
The Company is not dependent upon a single customer or a few customers
such that the loss of any one or more of such customers would have a
significant adverse effect on the Company. Large customers are generally on
interruptible rate schedules, and margin-sharing arrangements limit the effects
of variations in interruptible customer usage on net income. As shown on page
2, the Company and Shenandoah had 846,381 customer meters at September 30,
1999.
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 natural gas for space heating purposes. In
fiscal year 1999, 75% 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 utility earnings are generated during
these two quarters and the Company historically incurs losses in the third and
fourth fiscal quarters. Results of operations can be affected by the timing and
level of approved rate increases. The seasonal nature of the Company's business
creates large variations in short-term cash requirements, primarily due to
fluctuations in the level of customer accounts receivable and storage gas
inventory levels. The Company finances these seasonal requirements primarily
through the sale of commercial paper and short-term bank loans.
Note 3 to the Consolidated Financial Statements, which is incorporated
by reference into this report, includes a discussion of the Company's short-term
borrowings.
Through the rates charged by the interstate pipelines, the Company
contributes to the funding of the Gas Research Institute. The Institute's
primary focus is devoted to developing more efficient gas equipment and to
increase the long-term supply of gas. The Company also belongs to the Natural
Gas Vehicle Coalition and the Institute of Gas Technology. These organizations
are involved in developing new applications and technologies for the use of
natural gas. The cost of these memberships and the Company's own research and
development costs during fiscal years 1999, 1998 and 1997 were not material.
At September 30, 1999, the Company and its wholly owned subsidiaries
had 2,117 employees. This represents a decrease of 52 employees from the level
at September 30, 1998. At September 30, 1999, there were 1,931 utility
employees, a decline of 69 employees from the level at September 30, 1998.
ITEM 2. PROPERTIES
The Company and its subsidiaries hold such valid franchises,
certificates of convenience and necessity, licenses and permits as are
necessary for the maintenance and operation of their respective properties and
businesses as now conducted. The Company has no reason to believe that it will
be unable to renew any of such franchises as they expire.
As of September 30, 1999, the Company and its utility subsidiaries had
612 miles of transmission mains and 10,006 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. 20080, where its
corporate offices are located. The Company owns the land and a building (built
in 1970) at 6801 Industrial Road in Springfield, Virginia 22151, 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.
22
<PAGE> 25
The Company owns a 12-acre parcel of land located in Southeast
Washington, D.C. The Company operated a manufactured gas plant at this site
until 1984. In May 1999, the Company announced its intention to pursue
commercial development of this site along with a national developer.
Negotiations are underway for the Company to enter a ground lease and obtain a
carried interest in the commercial development. No agreement has been reached as
of December 15, 1999. The Company will continue negotiations with the developer
and pursue the approvals that are necessary for the project to be completed.
The Company also has peaking facilities consisting of propane air
plants in West Springfield, Virginia (Ravensworth Station), and Rockville,
Maryland (Rockville Station). Hampshire operates an underground natural gas
storage field in Hampshire County, West Virginia. Hampshire accesses the
storage field through 12 storage wells that are connected to an 18-mile
pipeline gathering system. Hampshire also operates a compressor station for
injection of gas into storage. For pipeline year 2000, it is projected that the
Hampshire storage facility can supply approximately 2.0 billion cubic feet of
natural gas to the parent company's system for meeting seasonal demands.
The Company's Mortgage dated January 1, 1933 (Mortgage), as
supplemented and amended, securing the First Mortgage Bonds (FMBs) issued by
the Company, constitutes a direct lien on substantially all property and
franchises owned by the Company other than expressly excepted property. At
September 30, 1999, there were no FMBs outstanding under the Mortgage.
The Company executed a supplemental indenture to its unsecured
Medium-Term Notes (MTNs) Indenture on September 1, 1993, providing that the
Company will not issue any FMBs under its Mortgage without making effective
provision whereby any outstanding MTNs shall be secured equally and ratably
with any and all other obligations and indebtedness secured by the Mortgage.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
23
<PAGE> 26
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- -------------------------------------------------------- -----------------
The names, ages and positions of the executive officers of the
Registrant as of the date of this report are listed below along with their
business experience during the past five years.
<S> <C>
Elizabeth M. Arnold, Age 47
Vice President (corporate strategy and internal audit) January 31, 1996
Treasurer May 1, 1993
Beverly J. Burke, Age 48
Vice President and Assistant General Counsel October 1, 1998
Department Head - Office of the General Counsel January 22, 1997
Managing Attorney - Litigation November 16, 1992
Adrian P. Chapman, Age 42
Vice President (regulatory affairs and energy
acquisition) March 31, 1999
Department Head, Regulatory Affairs December 31, 1996
Director of Maryland Rates and Regulatory Affairs February 7, 1994
Richard J. Cook, Age 57
Vice President (construction and technical support) October 1, 1996
Executive Assistant October 1, 1995
Director - Environment and Safety September 1, 1989
James H. DeGraffenreidt, Jr., Age 46
Chairman of the Board and Chief Executive Officer December 1, 1998
President and Chief Executive Officer January 1, 1998
President and Chief Operating Officer December 1, 1994
Senior Vice President - Jurisdictional Divisions
and Rates and Regulatory Affairs May 1, 1993
Richard L. Fisher, Age 52
Vice President (delivery services) June 1, 1996
Executive Director May 3, 1993
Shelley C. Jennings, Age 51
Treasurer March 31, 1999
Department Head, Customer Accounts December 1, 1997
Area Head, Procurement December 16, 1996
Director, Accounting Operations January 24, 1994
John K. Keane, Jr., Age 61
Senior Vice President and General Counsel May 1, 1993
Frederic M. Kline, Age 48
Vice President and Chief Financial Officer March 31, 1999
Vice President, Treasurer and Chief Financial Officer October 1, 1998
Vice President and Treasurer January 31, 1996
Controller November 27, 1985
</TABLE>
24
<PAGE> 27
EXECUTIVE OFFICERS OF THE REGISTRANT (CONTINUED)
<TABLE>
<CAPTION>
Date Elected
Name, Age and Position with the Company or Appointed (1)
- -------------------------------------------------------- ------------------
<S> <C>
Lisa M. Metcalfe, Age 35 (2)
Vice President and Chief Information Officer October 1, 1996
Douglas V. Pope, Age 54
Secretary July 25, 1979
Joseph M. Schepis, Age 46
President and Chief Operating Officer December 1, 1998
Executive Vice President and Chief Operating Officer January 1, 1998
Senior Vice President (gas supply, regulatory activities
and customer services) January 31, 1996
Senior Vice President and Chief Financial Officer December 15, 1994
Vice President - Rates and Regulatory Affairs May 1, 1993
Roberta W. Sims, Age 45
Vice President (corporate relations and communications) January 31, 1996
Vice President and General Manager -
District of Columbia Division October 1, 1992
Robert A. Sykes, Age 51
Vice President (human resources) February 21, 1996
Vice President - Human Resources October 1, 1987
Robert E. Tuoriniemi, Age 43 (3)
Controller October 1, 1996
James B. White, Age 49
Vice President (business development) February 21, 1996
Vice President and General Manager - Virginia Division May 1, 1993
</TABLE>
There is no family relationship among the officers. The age of each officer
listed is as of the date of filing.
(1) Each of the officers has served continuously since the dates indicated.
(2) Ms. Metcalfe was previously employed by the National Wildlife Federation
and served most recently as Vice President of Constituent Systems and Services.
In that capacity, she was responsible for the organization's information
systems, telecommunications systems, facilities and administrative services.
(3) Mr. Tuoriniemi was previously employed by Central Maine Power Company, an
electric utility, and served most recently as Comptroller. In the Comptroller
position, Mr. Tuoriniemi's responsibilities included all accounting matters,
testifying before regulatory commissions in rate case proceedings, directing
tax planning and coordinating financial reporting activities.
25
<PAGE> 28
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 51 of the Company's 1999 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 16 of the Company's 1999 Annual Report to Shareholders titled
"Selected Financial and Operations Data" 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 17 through 30 of the Company's 1999 Annual Report to Shareholders
are included in Exhibit 13 in this report and are incorporated by reference into
this Item.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK EXPOSURE RELATED TO OTHER FINANCIAL INSTRUMENTS
At September 30, 1999, the Company had fixed-rate medium-term notes and
other long-term debt aggregating $506.1 million in principal amount and having
a fair value of $487.9 million. Fair value is defined as the present value of
the debt securities' future cash flows discounted at interest rates that
reflect market conditions as of September 30, 1999. While these are fixed-rate
instruments and, therefore, do not expose the Company to the risk of earnings
loss due to changes in market interest rates, they are subject to changes in
fair value as market interest rates change. A total of $36.0 million, or
approximately 7% of the Company's outstanding medium-term notes have call
options that enable the Company to mitigate this market risk through the early
redemption of those debt instruments. Likewise, a total of $40 million, or 8%
of the Company's medium-term notes have put options that allow the holders of
debt to mitigate market risk through the early redemption of those debt
instruments.
Using sensitivity analysis to measure this market risk exposure, the
Company estimates that the fair value of its long-term debt would increase by
approximately $22 million if interest rates were to decline by 10%. The Company
also estimates that the fair value of its long-term debt would decrease by
approximately $20 million if interest rates were to increase by 10%. In
general, such an increase or decrease in fair value would impact earnings and
cash flows only if the Company were to reacquire all or a portion of these
instruments in the open market prior to their maturity.
PRICE RISK RELATED TO GAS MARKETING OPERATIONS
The Company's subsidiary, WGEServices, performs the Company's gas
marketing activities. In the course of its business, WGEServices makes
fixed-price sales commitments to customers. WGEServices purchases the
corresponding physical supplies at fixed prices to lock in margins. WGEServices
has exposure to changes in gas prices related to the volumetric differences
between the purchase
26
<PAGE> 29
commitments and sales commitments. The risk associated with gas price
fluctuations is managed by closely matching purchases from suppliers with sales
commitments to customers. At September 30, 1999, WGEServices' open position was
not material to the Company's financial position or results of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pages 31 through 51 of the Company's 1999 Annual Report to Shareholders
are included in Exhibit 13 in this report and are incorporated by reference into
this Item.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
27
<PAGE> 30
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning Directors contained in the Company's definitive
Proxy Statement for the March 3, 2000, Annual Meeting of Shareholders, 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 Company's
definitive Proxy Statement for the March 3, 2000, Annual Meeting of
Shareholders, is hereby incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information captioned "Security Ownership of Management" in the
Company's definitive Proxy Statement for the March 3, 2000, Annual Meeting of
Shareholders, is hereby incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Karen Hastie Williams, a Director of the Company, is a partner in the
law firm Crowell & Moring. Michael D. Barnes, a Director of the Company, is a
partner in the law firm Hogan & Hartson. Both firms performed legal services for
the Company during fiscal year 1999.
28
<PAGE> 31
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
(a)1 All Financial Statements Pages in 1999
Annual Report to
Shareholders
Included in
Exhibit 13
------------------
<S> <C>
Consolidated Statements of Income - for the years ended
September 30, 1999, 1998 and 1997.............................................. 31
Consolidated Balance Sheets - as of September 30, 1999 and 1998.................. 32
Consolidated Statements of Cash Flows - for the years ended
September 30, 1999, 1998 and 1997.............................................. 33
Consolidated Statements of Capitalization - as of September 30,
1999 and 1998.................................................................. 34
Consolidated Statements of Common Shareholders' Equity -
1999, 1998 and 1997 ........................................................... 35
Consolidated Statements of Income Taxes - for the years ended
September 30, 1999, 1998 and 1997 and as of September 30, 1999
and 1998....................................................................... 36
Notes to Consolidated Financial Statements....................................... 37-48
Report of Independent Public Accountants......................................... 50
</TABLE>
(a)2 Financial Statement Schedules
Separate financial statements for Washington Gas Light Company are
omitted since the Company's total assets, exclusive of investments in and
advances to its subsidiaries, constitute more than 75% of the total assets shown
in the Consolidated Balance Sheets, and the Company's total gross revenue,
exclusive of interest and dividends received or equity in income from the
consolidated subsidiaries, constitutes more than 75% of total gross revenues
shown in the Consolidated Statements of Income.
Schedule II, on page 36, should be read in conjunction with the
financial statements in the 1999 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.
29
<PAGE> 32
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, 1999, 1998 and 1997.................................... 36
(a)3 Exhibits
Exhibits Filed Herewith:
3. Articles of Incorporation and Bylaws:
Bylaws of the Company as amended on See
September 29, 1999. Separate
Volume
10. Material Contract
Supplemental Executive Retirement Plan,
as amended January 1, 1999.*
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 -
1999 Annual Report to Shareholders (except for the
information presented on the front and rear covers and Pages
1 through 15, 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 Schedules
27.0 Financial Data Schedule--Fiscal Year 1999
27.1 Restated Financial Data Schedule--Fiscal Year 1998
27.2 Restated Financial Data Schedule--Fiscal Year 1997
</TABLE>
30
<PAGE> 33
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
Exhibits Incorporated by Reference:
Description
3. Articles of Incorportation and Bylaws:
Company Charter, filed on Form S-3 dated July 21, 1995.
4. Instruments defining the Rights of Security Holders including
indentures:
Mortgage and Deed of Trust of the Company, dated January 1,
1933, and filed as Exhibit 2.2 of the Registration Statement on
Form S-7 filed with the Commission on May 12, 1975.
Supplemental Indenture, dated September 1, 1986, to the
Company's Mortgage and Deed of Trust, dated January 1, 1933,
filed on Form 8-K dated March 13, 1987.
Supplemental Indenture, dated March 1, 1987, to the Company's
Mortgage and Deed of Trust, dated January 1, 1933, filed on Form
8-K dated March 13, 1987.
Supplemental Indenture, dated April 15, 1988, to the Company's
Mortgage and Deed of Trust, dated January 1, 1933, filed on Form
8-K dated April 22, 1988.
Supplemental Indenture, dated July 1, 1989, to the Company's
Mortgage and Deed of Trust, dated January 1, 1933, filed on Form
8-K dated July 12, 1989.
Indenture, dated September 1, 1991 between the Company and The
Bank of New York, as Trustee, regarding issuance of unsecured
notes, filed on Form 8-K on September 19, 1991.
Supplemental Indenture, dated September 1, 1993 between the
Company and The Bank of New York, as Trustee, regarding the
addition of a new section to the Indenture dated September 1,
1991, filed on Form 8-K on September 10, 1993.
31
<PAGE> 34
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
10. Material Contracts:
Service Agreement effective October 1, 1993 with
Transcontinental Gas Pipe Line Corporation related to the
upstream capacity on the CNG Transmission Corporation system,
filed on the 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.
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.
32
<PAGE> 35
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
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.
1999 Incentive Compensation Plan filed with the definitive proxy
statement filed on January 25, 1999.*
Directors' Stock Compensation Plan, adopted on October 25, 1998,
and amended on March 1, 1999 and filed on Form 10-Q for the
period ended March 31, 1999.*
Employment Agreement between the Company and the Chairman of the
Board and Chief Executive Officer, dated July 19, 1999, filed on
Form 10-Q for the period ended June 30, 1999.*
Employment Agreements between the Company and Messrs. Schepis,
Kline, and Keane, as defined in Item 402(a)(3) of Regulation
S-K, filed on Form 10-Q for the period ended June 30, 1999.*
Employment Agreement between the Company and the Chief Executive
Officer, dated May 19, 1997, filed on Form 10-Q for the period
ended June 30, 1997.*
Deferred Compensation Plan for Outside Directors as amended
November 26, 1986 filed on Form 10-K for the fiscal year ended
December 31, 1986.*
Retirement Plan for Outside Directors, as amended on December
18, 1996 and filed on Form 10-K for the fiscal year ended
September 30, 1997.*
Long-Term Incentive Compensation Plan, as amended on December
18, 1996 and filed on Form 10-K for the fiscal year ended
September 30, 1997.*
Executive Incentive Compensation Plan, as amended on December
18, 1996 and filed on Form 10-K for the fiscal year ended
September 30, 1997.*
* Compensatory plan arrangement required to be filed
pursuant to Item 14(c) of Form 10-K.
33
<PAGE> 36
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K (CONTINUED)
(b) Reports on Form 8-K:
The following report was filed on Form 8-K during the fourth fiscal
quarter of 1999.
<TABLE>
<CAPTION>
Date Filed Description of Event Reported
--------------- --------------------------------------------
<S> <C>
August 19, 1999 Announcement of the formation of Primary
Investors, LLC, a Limited Liability Company.
Primary Investors, LLC is owned jointly by
Washington Gas Light Company and Thayer
Capital Partners.
</TABLE>
34
<PAGE> 37
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 25, 1999. Our audit was made for the
purpose of forming an opinion on those statements taken as a whole. The
Schedule II - Valuation and Qualifying Accounts and Reserves for the years
ended September 30, 1999, 1998 and 1997 - listed in the index on page 36 is the
responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part
of the basic financial statements. This Schedule II has been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
Vienna, VA
October 25, 1999
35
<PAGE> 38
WASHINGTON GAS LIGHT COMPANY & SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
Additions Charged to
---------------------------
Balance at Balance
Beginning Costs and Other at End
of Period Expenses Accounts Deductions (c) of Period
------------- ------------ ------------ ----------------- ------------
1999
----
<S> <C> <C> <C> <C> <C>
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 9,078 $ 8,801 $ 2,339 (A) $ 13,592 $ 6,626
Provision for impairment of investments
and other deferred charges 4,147 - - - 4,147
Reserves:
Injuries and Damages 8,870 222 268 (B) 801 8,559
Other 450 - - - 450
1998
----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 11,043 $ 9,855 $ 2,503 (A) $ 14,323 $ 9,078
Provision for impairment of investments
and other deferred charges 5,970 - - 1,823 4,147
Reserves:
Injuries and Damages 10,145 2,490 254 (B) 4,019 8,870
Other 900 - - 450 450
1997
----
Valuation and Qualifying Accounts
Deducted from Assets in the Balance Sheet:
Allowance for doubtful accounts $ 11,846 $ 11,237 $ 1,857 (A) $ 13,897 $ 11,043
Provision for impairment of investments
and other deferred charges 6,507 - - 537 5,970
Reserves:
Injuries and Damages 9,292 2,146 826 (B) 2,119 10,145
Other 900 - - - 900
</TABLE>
NOTES:
(A) Recoveries on receivables previously written off as uncollectible and
unclaimed customer deposits, overpayments, etc., not refundable.
(B) Portion of injuries and damages charged to construction and
reclassification from other accounts.
(C) Includes deductions for purposes for which reserves were provided or
revisions made of estimated exposure.
36
<PAGE> 39
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
WASHINGTON GAS LIGHT COMPANY
/s/ JAMES H. DEGRAFFENREIDT, JR.
-------------------------------------
James H. DeGraffenreidt, Jr.
Chairman of the Board
and Chief Executive Officer
Date: December 15, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ JAMES H. DEGRAFFENREIDT, JR. Chairman of the Board 12/15/99
- ---------------------------------------- and Chief Executive --------
(James H. DeGraffenreidt, Jr.) Officer
/s/ JOSEPH M. SCHEPIS President and Chief 12/15/99
- ---------------------------------------- Operating Officer and --------
(Joseph M. Schepis) Director
/s/ FREDERIC M. KLINE Vice President and 12/15/99
- ---------------------------------------- Chief Financial Officer --------
(Frederic M. Kline) (Principal Financial Officer)
/s/ ROBERT E. TUORINIEMI Controller 12/15/99
- ---------------------------------------- (Principal Accounting Officer) --------
(Robert E. Tuoriniemi)
/s/ MICHAEL D. BARNES Director 12/15/99
- ---------------------------------------- ---------
(Michael D. Barnes)
/s/ FRED J. BRINKMAN Director 12/15/99
- ---------------------------------------- ---------
(Fred J. Brinkman)
/s/ DANIEL J. CALLAHAN, III Director 12/15/99
- ---------------------------------------- ---------
(Daniel J. Callahan, III)
/s/ ORLANDO W. DARDEN Director 12/15/99
- ---------------------------------------- ---------
(Orlando W. Darden)
/s/ MELVYN J. ESTRIN Director 12/15/99
- ---------------------------------------- ---------
(Melvyn J. Estrin)
/s/ PHILIP A. ODEEN Director 12/15/99
- ---------------------------------------- ---------
(Philip A. Odeen)
/s/ KAREN HASTIE WILLIAMS Director 12/15/99
- ---------------------------------------- ---------
(Karen Hastie Williams)
</TABLE>
37
<PAGE> 40
WASHINGTON GAS LIGHT COMPANY
1999 FORM 10-K EXHIBIT INDEX
Exhibit Description
- ------- -----------
3. Articles of Incorporation and Bylaws:
Bylaws of the Company as amended on September 29, 1999.
10. Material Contract
Supplemental Executive Retirement Plan, as amended
January 1, 1999.*
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 - 1999 Annual
Report to Shareholders (except for information
presented on the front and rear covers and Pages 1
through 15, 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 Schedules
27.0 Financial Data Schedule--Fiscal Year 1999
27.1 Restated Financial Data Schedule--Fiscal Year 1998
27.2 Restated Financial Data Schedule--Fiscal Year 1997
38
<PAGE> 1
EXHIBIT 3
Effective 9/29/99
WASHINGTON GAS LIGHT COMPANY
BYLAWS
ARTICLE I
Stockholders.
SECTION 1. Annual Meeting. The annual meeting of stockholders of Washington
Gas Light Company (the Company) shall be held on the first Friday in the month
of March in each year, at 10:00 a.m., at the Gallaudet University, Washington,
D.C., for the purpose of electing directors and for the transaction of such
other business as properly may come before such meeting. If the day fixed for
the annual meeting shall be a legal holiday in the District of Columbia, such
meeting shall be held on the next succeeding business day.
SECTION 2. Special Meetings. Special meetings of stockholders may be held
upon call by the Chairman of the Board, the President, the Secretary, a majority
of the Board of Directors, or a majority of the Executive Committee, and shall
be called by the Chairman of the Board, the President or Secretary upon the
request in writing of the holders of record of not less than one-tenth of all
the outstanding shares of stock entitled by its terms to vote at such meeting,
at such time and at such place within the District of Columbia as may be fixed
in the call and stated in the notice setting forth such call. Such request by
the stockholders and such notice shall state the purpose of the proposed
meeting.
SECTION 3. Notice of Meetings. Notice of the time, place and purpose of
every meeting of the stockholders, shall, except as otherwise required by law,
be delivered personally or mailed at least ten (10) but not more than one
hundred (100) days prior to the date of such meeting to each stockholder of
record entitled to vote at the meeting at his address as it appears on the
records of the Company. Any meeting may be held without notice if all of the
stockholders entitled to vote thereat
<PAGE> 2
-2- Effective 9/29/99
are present in person or by proxy at the meeting, or if notice is waived by
those not so present in person or by proxy.
SECTION 4. Quorum. At every meeting of the stockholders, the holders of
record of a majority of the shares entitled to vote at the meeting, represented
in person or by proxy, shall constitute a quorum. The vote of the majority of
such quorum shall be necessary for the transaction of any business, unless
otherwise provided by law or the articles of incorporation. If the meeting
cannot be organized because a quorum has not attended, those present in person
or by proxy may adjourn the meeting from time to time until a quorum is present
when any business may be transacted that might have been transacted at the
meeting as originally called.
SECTION 5. Voting. Unless otherwise provided by law or the articles of
incorporation, every stockholder of record entitled to vote at any meeting of
stockholders shall be entitled to one vote for every share of stock standing in
his name on the records of the Company on the record date fixed as provided in
these Bylaws. In the election of directors, all votes shall be cast by ballot
and the persons having the greatest number of votes shall be the directors. On
matters other than election of directors, votes may be cast in such manner as
the Chairman of the meeting may designate.
SECTION 6. Inspectors. The Board of Directors shall annually appoint two or
more persons to act as inspectors or judges at any election of directors or vote
conducted by ballot at any meeting of stockholders. Such inspectors or judges of
election shall take charge of the polls and after the balloting shall make a
certificate of the result of the vote taken. In case of a failure to appoint
inspectors, or in case an inspector shall fail to attend, or refuse or be unable
to serve, the Chairman
<PAGE> 3
-3- Effective 9/29/99
of the meeting may appoint, or the stockholders may elect, an inspector or
inspectors to act at such meeting. Such inspector or inspectors shall make a
certificate of the result of the vote taken.
SECTION 7. Conduct of Stockholders' Meeting. The following persons, in the
order named, shall be entitled to call each stockholders' meeting to order: (1)
the Chairman of the Board, (2) the President of the Company, (3) a Vice
President, or (4) any person elected by the stockholders. The stockholders shall
have the right to elect a Chairman of the meeting.
The Secretary of the Company, or in his absence any person appointed by the
Chairman, shall act as Secretary of the meeting for organization purposes. The
stockholders shall have the right to elect a secretary of the meeting.
SECTION 8. Record Date. In lieu of closing the stock transfer books, the
Board of Directors, in order to make a determination of stockholders entitled to
notice of or to vote at any meeting, or to receive payment of any dividends or
for any other proper purpose, may fix in advance a date, but not more than fifty
days in advance, as a record date for such determination, and in such case only
stockholders of record on the date so fixed shall be entitled to notice of, and
to vote at, such meeting, or to receive payment of such dividend, or to exercise
such other rights, as the case may be, notwithstanding any transfer of stock on
the books of the Company after such date. If the Board of Directors does not fix
a record date as aforesaid, such date shall be as provided by law.
SECTION 9. Notice of Business. At any meeting of the stockholders, only
such business shall be conducted as shall have been brought before the meeting
(1) by or at the direction of the Board of Directors or (2) by any stockholder
of the Company who is a stockholder of record at the
<PAGE> 4
-4- Effective 9/29/99
time of giving of the notice as provided for in this Section 9, who shall be
entitled to vote at such meeting and who complies with the following procedures:
Requirement of Timely Notice. For business to be properly brought
before a meeting of stockholders by a stockholder, the business shall be a
proper subject of stockholder action and the stockholder shall have given
timely notice thereof in writing to the Secretary. To be timely, a
stockholder's notice shall be delivered to or mailed and received by the
Secretary at the principal executive office of the Company not less than
sixty (60) days prior to the scheduled date of the meeting (regardless of
any postponements, deferrals or adjournments of the meeting to a later
date); provided, however, if no notice is given and no public announcement
is made to the stockholders regarding the date of the meeting at least 75
days prior to the meeting, the stockholder's notice shall be valid if
delivered to or mailed and received by the Secretary at the principal
executive office of the Company not less than fifteen (15) days following
the day on which the notice or public announcement of the date of the
meeting was given or made.
Contents of Notice. Such stockholder's notice to the Secretary shall
set forth as to each item of business the stockholder proposes to bring
before the meeting (1) a brief description of the business desired to be
brought before the meeting, the reasons for conducting such business at the
meeting and, in the event that such business includes a proposal to amend
either the Charter or these Bylaws, the language of the proposed amendment,
(2) the name and address, as they appear on the Company's books, of the
<PAGE> 5
-5- Effective 9/29/99
stockholder proposing such business, (3) the class and number of
shares of capital stock of the Company that are beneficially owned by
such stockholder, and (4) any material interest (financial or other)
of such stockholder in such business.
Compliance with Bylaws. Notwithstanding anything in these Bylaws
to the contrary, no business shall be conducted at a stockholders'
meeting except in accordance with the procedures set forth in this
Section 9. The chairman of the meeting shall, if the facts warrant,
determine and declare to the meeting that the business was not
properly brought before the meeting and in accordance with the
provisions of these Bylaws, and if he should so determine, he shall so
declare to the meeting and any such business not properly brought
before the meeting shall not be transacted at the meeting.
Notwithstanding the foregoing provisions of this Section 9, a
stockholder shall also comply with all applicable requirements of the
Securities Exchange Act of 1934, as amended, and the rules and
regulations thereunder with respect to the matters set forth in this
Section 9.
Effective Date of Stockholder Business. Notwithstanding anything
in these Bylaws to the contrary, no business brought before a meeting
of the stockholders by a stockholder shall become effective until the
final termination of any proceeding which may have been commenced in
any court of competent jurisdiction for an adjudication of any legal
issues incident to determining the validity of such business and the
procedure pursuant to which it was brought before the stockholders,
unless and until such court shall have determined that such
proceedings are not being pursued expeditiously and in good faith.
<PAGE> 6
-6- Effective 9/29/99
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.
SECTION 2. Election. Except as provided in Section 3 hereof, directors
shall be elected by the stockholders of the Company pursuant to the procedures
enumerated below:
Eligible Persons. Only persons who are nominated in accordance with
the following procedures shall be eligible for election by the stockholders
as directors of the Company.
Nominations. Nominations of persons for election as directors of the
Company may be made at a meeting of stockholders (1) by or at the direction
of the Board of Directors, (2) by any nominating committee or person
appointed by the Board of Directors or (3) by any stockholder of the
Company entitled to vote for the election of directors at the meeting who
complies with the notice procedures set forth in this Section 2.
<PAGE> 7
-7- Effective 9/29/99
Nomination by Directors or Nominating Committee. Nominations made by
or at the direction of the Board of Directors or the nominating committee
or person appointed by the Board of Directors may be made at any time prior
to the stockholders' meeting. The Board of Directors must send notice of
nominations to the stockholders together with the notice of the meeting of
the stockholders; provided, however, if the nominations are made after the
notice of the meeting has been mailed, the Board of Directors must send
notice of its nominations to the stockholders as soon as practicable.
Nomination by Stockholders. Nominations, other than those made by or
at the direction of the Board of Directors or the nominating committee or
person appointed by the Board of Directors, shall be made pursuant to
timely notice in writing to the Secretary. To be timely, a stockholder's
notice shall be delivered to or mailed and received by the Secretary at the
principal executive office of the Company not less than sixty (60) days
prior to the scheduled date of the meeting (regardless of any
postponements, deferrals or adjournments of the meeting to a later date);
provided, however, if no notice is given and no public announcement is made
to the stockholders regarding the date of the meeting at least 75 days
prior to the meeting, the stockholder's notice shall be valid if delivered
to or mailed and received by the Secretary at the principal executive
office of the Company not less than fifteen (15) days following the day on
which the notice or public announcement of the date of the meeting was
given or made.
Contents of Notice. Nominations, other than those made by or at the
direction of the Board of Directors or the nominating committee or person
appointed by the Board of Directors, shall set forth:
<PAGE> 8
-8- Effective 9/29/99
(1) as to each person whom the stockholder proposes to nominate
for election or reelection as a director, (a) the name, age, business
address and residential address of the person, (b) the principal
occupation or employment of the person (c) the class and number of
shares of capital stock of the Company that are beneficially owned by
the person, (d) written consent by the person, agreeing to serve as
director if elected, (e) a description of all arrangements or
understandings between the person and the stockholder regarding the
nomination, (f) a description of all arrangements or understandings
between the person and any other person or persons (naming such
persons) regarding the nomination, (g) all information relating to the
person that is required to be disclosed in solicitations for proxies
for election of directors pursuant to Rule 14a under the Securities
Exchange Act of 1934, as amended, and (h) such other information as
the Company may reasonably request to determine the eligibility of
such proposed nominee to serve as director of the Company; and
(2) as to the stockholder giving the notice, (a) the name,
business address and residential address of the stockholder giving the
notice, (b) the class and number of shares of capital stock of the
Company that are beneficially owned by such stockholder, (c) a
description of all arrangements or understandings between the
stockholder and the nominee regarding the nomination, and (d) a
description of all arrangements or understandings between the
stockholder and any other person or persons (naming such persons)
regarding the nomination.
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
<PAGE> 9
-9- Effective 9/29/99
procedures set forth in this section of the Bylaws. The Chairman of the
Board of Directors shall, if the facts warrant, determine and declare prior
to the meeting of stockholders that the nomination was not made in
accordance with the foregoing procedure, and if he should so determine, he
shall so inform the nominee and the stockholder who nominated the nominee
as soon as practicable and the defective nomination shall be disregarded.
Effective Date of Election of Director. Notwithstanding anything in
these Bylaws to the contrary, no election of a director nominated by a
stockholder shall become effective until the final termination of any
proceeding which may have been commenced in any court of competent
jurisdiction for an adjudication of any legal issues incident to
determining the procedure pursuant to which the nomination of such director
was brought before the stockholders, unless and until such court shall have
determined that such proceedings are not being pursued expeditiously and in
good faith.
SECTION 3. Vacancies. Whenever any vacancy shall occur in the Board of
Directors by any cause other than by reason of an increase in the number of
directors, a majority of the remaining directors, by an affirmative vote at any
lawful meeting may elect a director to fill the vacancy and to hold office until
the next annual election, or until his successor is duly elected and qualified.
SECTION 4. Meetings. Regular meetings of the Board shall be held at the
office of the Company in the District of Columbia at times fixed by resolution
of the Board of Directors. Notice of such meetings need not be given.
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
<PAGE> 10
-10- Effective 9/29/99
without notice if all of the directors are present, or if those not present
waive notice of the meeting by telegram or in writing. Special meetings of the
Board of Directors may be held within or without the District of Columbia.
SECTION 5. Committees. The Board of Directors shall, by resolution or
resolutions passed by a majority of the whole Board, designate an Executive
Committee, to consist of the Chief Executive Officer of the Company who may be
the Chairman of the Board, or the President and three additional members, and
three alternates to serve at the call of the Chief Executive Officer in case of
the unavoidable absence of one of the regular members, to be elected from the
Board of Directors. The Executive Committee shall, when the Board is not in
session, have and may exercise all of the authority of the Board of Directors in
the management of the business and affairs of the Company.
The Board of Directors may appoint other committees, standing or special,
from time to time, from among their own number, or otherwise, and confer powers
on such committees, and revoke such powers and terminate the existence of such
committees at its pleasure.
A majority of the members of any such committee shall constitute a quorum
for the purpose of fixing the time and place of its meetings, unless the Board
shall otherwise provide. All action taken by any such committee shall be
reported to the Board at its meeting next succeeding such action.
SECTION 6. Compensation of Directors. The Board of Directors shall fix the
fee to be paid to each director for attendance at any meeting of the Board or of
any committee thereof, and may, in its discretion, authorize payment to
directors of traveling expenses incurred in attending any such meeting.
<PAGE> 11
-11- Effective 9/29/99
SECTION 7. Removal. Any directors may be removed from office at any time,
with or without cause, and another be elected in his place, by the vote of the
holders of record of a majority of the outstanding shares of stock of the
Company (of the class or classes by which such director was elected) entitled to
vote thereon, at a special meeting of stockholders called for such purpose.
ARTICLE III
Officers.
SECTION 1. Officers. The officers of the Company shall be elected by the
Board of Directors and shall consist of a Chairman of the Board, a President, a
Secretary, a Treasurer, and one or more Vice Presidents, and such other officers
as the Board from time to time shall elect, with such duties as the Board shall
deem necessary to conduct the business of the Company. Any officer may hold two
or more offices (including those of the Chairman of the Board and President)
except that the offices of President and Secretary may not be held by the same
person. The Chairman of the Board shall be a director; other officers, including
any Vice Chairman and the President, may be, but are not required to be,
Directors.
SECTION 2. Term of Office. Removal. In the absence of a special contract,
all officers shall hold their respective offices for one year or until their
successors shall have been duly elected and qualified, but they or any of them
may be removed from their respective offices on a vote by a majority of the
Board.
SECTION 3. Powers and Duties. The officers of the Company shall have such
powers and 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
<PAGE> 12
-12- Effective 9/29/99
of Directors. In the absence of both the Chairman of the Board and the
President, and provided a quorum is present, the senior member of the Board
present, in terms of service on the Board, shall serve as Chairman pro tem of
the meeting.
SECTION 4. Salaries. The salaries of all executive officers of the Company
shall be determined and fixed by the Board of Directors, or pursuant to such
authority as the Board may from time to time prescribe.
ARTICLE III-A
Indemnification of Directors and Officers.
SECTION 1. With respect to a Company officer, director, or employee, the
Company shall indemnify, and with respect to any other individual the Company
may indemnify, any person who was or is a party or is threatened to be made a
party to any threatened, pending or completed action, suit or proceeding (an
"Action"), whether civil, criminal, administrative, arbitrative or investigative
(including an action by or in the right of the Company) by reason of the fact
the person is or was a director, officer, employee, or agent of the Company, or
is or was serving at the request of the Company as a director, officer,
employee, or agent of another corporation, partnership, joint venture, trust or
other enterprise, against expenses (including attorneys' fees), judgments, fines
and amounts paid in settlement actually and reasonably incurred by that person
in connection with such Action; except in relation to matters as to which the
person shall be finally adjudged in such Action to have knowingly violated the
criminal law or be liable for willful misconduct in the performance of the
person's duty to the Company. The termination of any Action by judgment, order,
settlement, conviction, or upon a plea of nolo contendere or its equivalent,
shall not of itself create a presumption that the person was guilty of willful
misconduct.
<PAGE> 13
-14-
Any indemnification (unless ordered by a court) shall be made by the
Company only as authorized in the specific case upon a determination that
indemnification of the director, officer, employee or agent is proper in the
circumstance because the person has met the applicable standard of conduct set
forth above. In the case of any director, such determination shall be made: (1)
by the Board of Directors by a majority vote of a quorum consisting of directors
who were not parties to such Action; or (2) if such a quorum is not obtainable,
by majority vote of a committee duly designated by the Board of Directors (in
which designation directors who are parties may participate) consisting solely
of two or more directors not at the time parties to the proceeding; or (3) by
special legal counsel selected by the Board of Directors or its committee in the
manner prescribed by clause (1) or (2) of this paragraph, or if such a quorum is
not obtainable and such a committee cannot be designated, by majority vote of
the Board of Directors, in which selection directors who are parties may
participate; or (4) by vote of the shareholders, in which vote shares owned by
or voted under the control of directors, officers and employees who are at the
time parties to the Action may not be voted. In the case of any officer,
employee, or agent other than a director, such determination may be made (i) by
the Board of Directors or a committee thereof; (ii) by the Chairman of the Board
of the Company or, if the Chairman is a party to such Action, the President of
the Company, or (iii) such other officer of the Company, not a party to such
Action, as such person specified in clause (i) or (ii) of this paragraph may
designate. Authorization of indemnification and evaluation as to reasonableness
of expenses shall be made in the same manner as the determination that
indemnification is permissible, except that if the determination is made by
special legal counsel, authorization of indemnification and evaluation as to
reasonableness of expenses shall be made by those entitled hereunder to select
such legal counsel.
Expenses incurred in defending an Action for which indemnification may be
available
<PAGE> 14
-15-
hereunder shall be paid by the Company in advance of the final disposition of
such Action as authorized in the manner provided in the preceding paragraph,
subject to execution by the person being indemnified of a written undertaking to
repay such amount if and to the extent that it shall ultimately be determined by
a court that such indemnification by the Company is not permitted under
applicable law.
It is the intention of the Company that the indemnification set forth in
this Section of Article III-A, shall be applied to no less extent than the
maximum indemnification permitted by law. In the event that any right to
indemnification or other right hereunder may be deemed to be unenforceable or
invalid, in whole or in part, such unenforceability or invalidity shall not
affect any other right hereunder, or any right to the extent that is not deemed
to be unenforceable. The indemnification provided herein shall be in addition
to, and not exclusive of, any other rights to which those indemnified may be
entitled under any Bylaw, agreement, vote of stockholders, or otherwise, and
shall continue as to a person who has ceased to be a director, officer,
employee, or agent and inure to the benefit of such person's heirs, executors,
and administrators.
SECTION 2. In any proceeding brought by a stockholder in the right of the
Company or brought by or on behalf of the stockholders of the Company, no
monetary damages shall be assessed against an officer or director. The liability
of an officer or director shall not be limited as provided in this section if
the officer or director engaged in willful misconduct or a knowing violation of
the criminal law or of any federal or state securities law.
<PAGE> 15
-16-
ARTICLE IV
Checks, Notes, Etc.
SECTION 1. All checks and drafts on the Company's bank accounts and all
bills of exchange and promissory notes, and all acceptances, obligations and
other instruments for the payment of money, shall be signed by such officer or
officers, agent or agents, as shall be thereunto authorized from time to time by
the Board of Directors.
SECTION 2. Shares of stock and other interests in other corporations or
associations shall be voted by such officer or officers as the Board of
Directors may designate.
SECTION 3. Except as the Board of Directors shall otherwise provide, all
contracts expressly approved by the Board shall be signed on behalf of the
Company by the Chairman of the Board, the President, or a Vice President.
ARTICLE V
Capital Stock.
SECTION 1. Certificate for shares. The interest of each stockholder of the
Company shall be evidenced by a certificate or certificates for shares of stock
in such form as required by law and as the Board of Directors may from time to
time prescribe. The certificates of stock shall be signed by the President or a
Vice President and the Secretary or an Assistant Secretary and sealed with the
seal of the Company. Such seal may be a facsimile.
Where any such certificate is countersigned by a transfer agent other than
the Company, or an employee of the Company, or is countersigned by a transfer
clerk and is registered by a registrar, the signatures of the President or Vice
President and the Secretary or Assistant Secretary may be facsimiles.
In case any officer who has signed, or whose facsimile signature has been
placed upon such
<PAGE> 16
-17-
certificate, shall have ceased to be such officer before such certificate is
issued, it may nevertheless be issued by the Company with the same effect as if
such officer had not ceased to hold such office at the date of its issue.
SECTION 2. Transfer of Shares. The shares of stock of the Company shall be
transferable on the books of the Company by the holders thereof in person or by
duly authorized attorney, upon surrender and cancellation of certificates for a
like number of shares, with duly executed assignment and power of transfer
endorsed thereon or attached thereto, and with such proof of the authenticity of
the signatures as the Company or its agents may reasonably require.
SECTION 3. Lost, Stolen or Destroyed Certificates. No certificate of stock
claimed to have been lost, destroyed or stolen shall be replaced by the Company
with a new certificate of stock until the holder thereof has produced evidence
of such loss, destruction or theft, and has furnished indemnification to the
Company and its agents to such extent and in such manner as the proper officers
or the Board of Directors may from time to time prescribe.
ARTICLE VI
Corporate Records.
SECTION 1. Where Kept. The books, records and papers belonging to the
business of the Company, and the corporate seal, shall be kept at the office of
the Company in the District of Columbia.
SECTION 2. Inspection. Any stockholder or stockholders, who shall have been
such for at 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
<PAGE> 17
-18-
inspection is desired. If, upon such application, the Board of Directors or
Executive Committee deems such inspection is sought for a legitimate purpose
connected with the interest of the applicant as a stockholder of the Company,
such application shall be granted and a time and place for the inspection shall
be specified. The stock and transfer books of the Company shall at all times,
during business hours, be open to the inspection of stockholders. The Board of
Directors shall have the power from time to time to establish general
regulations conferring upon stockholders such further rights with respect to
inspection of books and records of the Company as the Board shall deem proper.
ARTICLE VII
Fiscal Year.
The fiscal year of the Company shall begin on the 1st day of October in
each year and shall end on the 30th day of September following.
ARTICLE VIII
Corporate Seal.
The seal of the Company shall be circular in form and there shall be
inscribed thereon -- Washington Gas Light Company -- a Corporation of the
District of Columbia and Virginia -- Originally Chartered by Congress in 1848.
<PAGE> 18
-19-
ARTICLE IX
Amendments.
The Board of Directors shall have power to make and alter (unless the
stockholders shall in any particular instance have otherwise prescribed) any
Bylaws of the Company. Such action may be taken at any meeting of the Board by
the affirmative vote of a majority of the total number of directors, provided
that notice of the proposed change shall have been given to all directors prior
to the meeting, or that all of the directors shall be present at the meeting.
Any Bylaws made or altered by the Board of Directors may be altered or repealed
at any time by the stockholders.
<PAGE> 1
EXHIBIT 10
WASHINGTON GAS LIGHT COMPANY
SUPPLEMENTAL EXECUTIVE
RETIREMENT PLAN
AS AMENDED THROUGH JANUARY 1, 1999
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
Article 1. Purpose 1
Article 2. Definitions 2
Article 3. Participation 9
Article 4. Vesting 10
Article 5. Service 13
Article 6. Benefits 14
Article 7. Death Benefits 19
Article 8. Miscellaneous 22
Article 9. Appeals from Denial of Claims 25
Exhibit A Participants in the Supplemental Executive
Retirement Plan as of January 1, 1999 27
Exhibit B. Participants eligible to elect a Full Retirement
Pension or Early Retirement Pension 28
Exhibit C. Early Retirement Pension Benefit "Legacy"
Formula 29
Exhibit D. Early Retirement Pension Benefit "New"
Formula 30
Exhibit E. Lump Sum Calculation Procedure 31
Exhibit F. Actuarial Equivalent Reduction Factors for
Disability Benefits Commencing Prior to Age 55 32
</TABLE>
- i -
<PAGE> 3
Article 1
Purpose
1.1 Purpose: The purpose of this Supplemental Executive Retirement Plan
(Supplemental Plan) is to provide a minimum level of retirement income in the
event of normal or early retirement and a minimum level of benefits in the event
of death or disability as a means of attracting, retaining, and motivating
executives. This Supplemental Plan is designed to provide a benefit which, when
added to the benefit provided by the Washington Gas Light Company Employees'
Pension Plan will meet the purpose described above.
The Company intends that the Supplemental Plan shall at all times be
maintained on an unfunded basis for federal income tax purposes under the
Internal Revenue Code of 1986, as amended, and be administered as a "top-hat"
plan exempt from the substantive requirements of the Employee Retirement Income
Security Act of 1974, as amended.
- 1 -
<PAGE> 4
Article 2
Definitions
2.1 Accredited Service: Accredited Service as defined in the Basic Plan.
2.2 Accrued Benefit: The amount expressed in terms of an annual single-life
annuity commencing at Normal Retirement Date and determined in accordance with
Section 6.4 which describes the Normal Retirement Pension.
An Accrued Benefit payable at a date other than the Normal Retirement
Date shall be calculated by (1) applying to the amount determined in Section
6.4(a) the applicable adjustment factors to reflect the age of the Participant
at the commencement date, (2) determining the offsets under Section 6.4(b)
adjusted to reflect the age of the Participant at the benefit commencement date,
and, then (3) subtracting the amount determined in (2) from the amount
determined in (1). Any adjustments to the resulting benefit to reflect a payment
form other than a life annuity are then applied to the result of Step (3).
2.3 Administrator: The Administrator appointed by the Committee to carry
out the administration of this Supplemental Plan.
2.4 Affiliate: An "Affiliate" of a person is a person that directly or
indirectly, through one or more intermediaries, controls or is controlled by, or
is under common control with such person.
- 2 -
<PAGE> 5
2.5 Basic Plan: Washington Gas Light Company Employees' Pension Plan, as
amended from time to time.
2.6 Benefit Service: As defined in Section 5.1 of this Supplemental Plan.
2.7 Board or Board of Directors: The Board of Directors of Washington Gas
Light Company.
2.8 Change of Control: The occurrence of any one or more of the triggering
events specified below:
(a) The acquisition by any individual, entity or group (within the
meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934,
as amended (the "Exchange Act") (a "Person") of beneficial ownership (within the
meaning of Rule 13d-3 promulgated under the Exchange Act) of 30% or more of
either (i) the then-outstanding shares of stock of the Company (the "Outstanding
Company Common Stock") or (ii) the combined voting power of the then-outstanding
voting securities of the Company entitled to vote generally in the election of
directors (the "Outstanding Company Voting Securities"); provided, however, that
for purposes of this subsection (a), the following acquisitions shall not
constitute a Change of Control: (i) any acquisition directly from the Company,
(ii) any acquisition by the Company, (iii) any acquisition by any employee
benefit plan (or related trust) sponsored or maintained by the Company or any
corporation controlled by the Company, or (iv) any acquisition by any
corporation pursuant to a transaction which complies with clauses (i), (ii) and
(iii) of subsection (c) of this Article 2.8; or
- 3 -
<PAGE> 6
(b) Individuals who, as of December 18, 1996, constitute the Board
(the "Incumbent Board") cease for any reason to constitute at least a majority
of the Board; provided, however, that any individual becoming a Director
subsequent to December 18, 1996 whose election, or nomination for election by
the Company's stockholders, was approved by a vote of at least a majority of the
Directors then comprising the Incumbent Board shall be considered as though such
individual were a member of the Incumbent Board, but excluding, for this
purpose, any such individual whose initial assumption of office occurs as a
result of an actual or threatened election contest with respect to the election
or removal of directors or other actual or threatened solicitation of proxies or
consents by or on behalf of a Person other than the board; or
(c) Consummation of a reorganization, merger or consolidation or sale
or other disposition of all or substantially all of the assets of the Company (a
"Business Combination"), in each case, unless, following such Business
Combination, (i) all or substantially all of the individuals and entities who
were the beneficial owners, respectively, of the Outstanding Company Common
Stock and Outstanding Company Voting Securities immediately prior to such
Business Combination beneficially owned, directly or indirectly, more than 50%
of, respectively, the then-outstanding shares of common stock and the combined
voting power of the then-outstanding voting securities entitled to vote
generally in the election of directors, as the case may be, of the Corporation
resulting from such Business Combination (including, without limitation, a
corporation which as a result of such transaction owns the Company or all or
substantially all of the Companies assets either directly or through one or more
subsidiaries) in substantially the same proportions as their ownership,
immediately prior to such Business Combination of the Outstanding Company Common
Stock and Outstanding Company Voting
- 4 -
<PAGE> 7
Securities, as the case may be, (ii) no Person (excluding any Corporations
resulting from such Business Combination or any employee benefit plan (or
related trust) of the Company or such Corporation resulting from such Business
Combination) beneficially owns, directly or indirectly, 30% or more of,
respectively, the then-outstanding shares of common stock of the Corporation
resulting from such Business Combination, or the Combined Voting Power of the
then-outstanding voting securities of such corporation except to the extent that
such ownership existed prior to the business Combination and (iii) at least a
majority of the members of the Board of Directors of the Corporation resulting
from such Business Combination were members of the Incumbent Board at the time
of the execution of the initial agreement, or of the action of the Board,
providing for such Business Combination; or
(d) Approval by the stockholders of the Company of a complete
liquidation or dissolution of the Company.
2.9 Committee: Means the Committee appointed by the Board to administer the
Plan or if no committee is appointed, the Board.
2.10 Company: Washington Gas Light Company and/or its Affiliates.
2.11 Disability: Disability as defined in the Basic Plan.
2.12 Early Retirement Date: Early Retirement Date as defined in the Basic
Plan.
- 5 -
<PAGE> 8
2.13 Employee: Any employee who receives salary, wages or commissions from
the Company.
2.14 Final Average Compensation: The average of the Participant's highest
Rates of Annual Basic Compensation on December 31 of each of the three years out
of the final five years of the Participant's Accredited Service as a Participant
preceding such Participant's Normal Retirement Date, Early Retirement Date, date
of Disability, death or the date of the Participant's Termination as described
in Section 3.2, whichever is applicable; however, if such five-year period
should include any approved leave of absence in effect on December 31 of any
year during such five-year period, his or her Rate of Annual Basic Compensation
in effect at the beginning of such leave shall be deemed to be his or her Rates
of Annual Basic Compensation in effect for that year. In the event a Participant
is entitled to an Accrued Benefit under this Supplemental Plan but has less than
three years of Accredited Service as a Participant, the Participant's Rate of
Annual Basic Compensation on December 31 of each year of service while a
Participant shall be averaged and such average shall be Participant's Final
Average Compensation. Should a Participant die or incur a Disability and have
less than one year of Accredited Service, which year does not include December
31, the Participant's Final Average Compensation shall be, as applicable, his or
her Rates of Annual Basic Compensation on the day preceding the date of such
Participant's death or the Administrator's acceptance of the Disability under
Section 6.7.
2.15 Former Vested Participant: A person who was a former employee who has
earned a vested benefit under Article 4 of this Plan. See Sections 6.8 and 7.3
of this Plan.
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<PAGE> 9
2.16 Hardship Election: The election described in Section 7.5 of this Plan.
2.17 Normal Retirement Date: Normal Retirement Date as defined in the Basic
Plan.
2. 18 Participant: A person designated as such by the Committee pursuant to
Section 3.1 of this Supplemental Plan. Unless expressly provided herein to the
contrary or the context dictates otherwise, a Participant shall also include any
person (including a beneficiary) who is entitled to a benefit under this
Supplemental Plan.
2.19 Plan: This Supplemental Executive Retirement Plan, as it is in effect
from time to time (also referred to as the "Supplemental Plan").
2.20 Rates of Annual Basic Compensation: Participant's salary as of December
31 and any short term incentive award declared during the year under the
Company's Executive Incentive Compensation Plan, the 1999 Incentive Compensation
Plan, or any successor plan, whether taken in cash or deferred.
2.21 Retirement: Retirement as defined in the Basic Plan.
2.22 Supplemental Plan: This Supplemental Executive Retirement Plan
2.23 Vesting Service: See "Year of Vesting Service"
- 7 -
<PAGE> 10
2.24 Year of Vesting Service: 1000 hours of service with the Company as a
Participant in any one calendar year.
- 8 -
<PAGE> 11
Article 3
Participation
3.1 Designation: Each employee of the Company who is designated by the
Committee shall be a Participant in this Supplemental Plan. As of January 1,
1999, the active employees listed on Exhibit A are included as Participants in
this Supplemental Plan.
3.2 Termination: In the event Participant's employment with the Company is
terminated for whatever reason or in the event the Committee withdraws or
rescinds its designation of Participant status with respect to a current
employee, such terminated or current employee, as applicable, shall thereafter
accrue no additional benefits under this Supplemental Plan and shall have, with
respect to previously credited benefits, only such rights as are provided in
Articles 4, 5 and 6 hereof.
- 9 -
<PAGE> 12
Article 4
Vesting
4.1 Vested Pension -- General: Except as provided in Section 4.2 of
this Article, a Participant shall be vested in, and have rights to, an Accrued
Benefit as follows:
(a) PARTICIPANTS IN THIS PLAN ON JANUARY 1, 1999:
For persons who were Participants in this Plan on January 1, 1999,
benefits under this Plan vest at the rate of 10% for each completed 5-year
period of Accredited Service with the Company (whether or not as a Participant)
prior to January 1, 1999. Four complete Years of Accredited Service plus one day
of Accredited Service with the Company in any one calendar year will be treated
as a 5-year period for this purpose. After January 1, 1999, vesting for these
Employees is at the rate of 5% per Year of Vesting Service as a Participant to,
and including, the year the Participant attains age 49; and 10% per Year of
Vesting Service as a Participant hereafter, to a maximum of 100%.
(b) PARTICIPANTS JOINING THE PLAN AFTER JANUARY 1, 1999:
For any person first becoming a Participant in this Plan after January
1, 1999, benefits vest at the following rates:
(i) 10% for each completed 5-year period of Accredited Service up to
January 1 of the year in which he or she became a Participant. Four complete
Years of Accredited Service plus one day of Accredited Service with the Company
will be treated as a 5-year period for this purpose; and
- 10 -
<PAGE> 13
(ii) 5% per Year of Vesting Service earned up to, and including, the
year the Participant attains age 49, and
(iii) 10% per Year of Vesting Service thereafter, to a maximum of 100%.
Provided however, no person shall be vested in a benefit under this Plan prior
to completion of 60 months of Accredited Service with the Company, unless this
requirement is waived by the Committee pursuant to Sec. 4.2(c) of this Plan.
(c) MINIMUM VESTING LEVEL AS OF JANUARY 1, 1999:
For Participants on January 1, 1999, there is a minimum initial vesting
of 10%.
(d) GRANDFATHER PROVISION:
For persons who were Participants in this Plan on June 27, 1989, the
vested percentage is not less than the percentage earned by that Participant as
of June 27, 1989. This percentage is calculated under Section 4.2(a), below.
(e) DISABILITY:
Upon Disability of a Participant, the Participant is 100% vested under
the Plan. The Disability Pension benefit is provided under Article 6 of this
Plan.
(f) DEATH:
Death benefits are provided by Article 7 of this Plan and are
calculated without regard to vesting.
(g) CHANGE OF CONTROL:
Upon a Change of Control, Participants are 100% vested in their Accrued
Benefit.
- 11 -
<PAGE> 14
4.2 Vested Pension -- Exceptions: Notwithstanding the general provisions in
Section 4.1, the following exceptions shall apply --
(a) For participation on or before June 27, 1989, a Participant shall
be vested in, and have rights to, an Accrued Benefit as set out in the table
below.
<TABLE>
<CAPTION>
Completed Years
of Vested
Vesting Service Percentage
--------------- ----------
<S> <C>
1 20%
2 40%
3 60%
4 80%
5 100%
</TABLE>
(b) A Participant's Accrued Benefit shall vest in accordance with the
table in (a) above if his or her termination of employment occurs as a result of
a Company-initiated action or request or if his or her designation of
Participant status is withdrawn or rescinded by the Company; provided, however,
that this provision shall not apply if the forfeiture provisions of Section 8.5
apply.
(c) The Committee may waive all vesting requirements or permit
accelerated vesting arrangements in any case which, in the Committee's
discretion, represents special circumstances.
- 12 -
<PAGE> 15
Article 5
Service
5.1 Benefit Service: Except as provided in Section 5.2 of this Article,
Benefit Service shall be equal to Accredited Service as determined under the
Basic Plan plus, for each full year of Accredited Service as a Participant, one
additional year to a maximum of 30 years.
5.2 Prior Benefit Service: A Participant who began participation on or
before June 27, 1989, shall receive Benefit Service for the period prior to June
27, 1989 which shall be equal to (i) Accredited Service earned through that date
as determined under the Basic Plan plus; (ii) two additional years for each full
year of Accredited Service as a Participant prior to June 27, 1989.
- 13 -
<PAGE> 16
Article 6
Benefits
6.1 Normal Form of Pension: A Participant who is entitled to receive a
retirement benefit under this Supplemental Plan may elect to receive such
benefit in the form of a single-life annuity, joint-and-survivor annuity or any
other optional form of benefit as set forth in Section 5.2 of the Basic Plan.
The normal form of pension under this Supplemental Plan shall be identical to
the form of benefit selected by the Participant under the Basic Plan unless the
Participant requests, and the Company approves, the lump-sum option described in
Section 6.2 of this Supplemental Plan. Any temporary actuarial increase in
benefits generated by Participant's selection of the option in Section 5.2(b) of
the Basic Plan shall not be considered in determining the Normal Retirement
Pension upon which the benefit from this Supplemental Plan is calculated, nor
shall any reduction in Normal Retirement Pension under the Basic Plan at age 62
increase a benefit under this Supplemental Plan.
6.2 Lump-Sum Option: A Participant may request that the portion of his or
her retirement benefit under this Supplemental Plan related to any short-term
incentive award declared under the Company's Executive Incentive Compensation
Plan, the 1999 Incentive Compensation Plan, or any successor plan as used in
determining Rates of Annual Basic Compensation, be paid in the form of a lump
sum, the amount of which shall be the actuarial equivalent of the Accrued
Benefit otherwise payable to the Participant under this Supplemental Plan. A
Participant's request for a lump sum payment must be submitted in writing to the
Administrator at least six
- 14 -
<PAGE> 17
months prior to the date on which a benefit would otherwise be payable hereunder
and must be accompanied by a medical certificate of the Participant's good
health signed by the Company's Medical Director in a form satisfactory to the
Administrator. A Participant's request for a lump sum payment shall be subject
to the sole discretion of the Administrator and shall be approved by the
Administrator only if considered to be in the interests of the Company. If
approved by the Administrator, a Participant's lump-sum payment shall be
calculated on the basis specified on Exhibit E.
6.3 Election of Benefit: A Participant shall not receive a benefit under
this Supplemental Plan prior to initiating a benefit under the Basic Plan,
except in the case where Participant is not eligible to commence a benefit under
the Basic Plan. A Participant shall not elect a benefit for a beneficiary of
over 50% of the Participant's benefit without presenting a medical certificate
of the Participant's good health signed by the Company's Medical Director in a
form satisfactory to the Administrator.
6.4 Normal Retirement Pension: On Normal Retirement Date, a Participant
shall be eligible to receive a monthly Normal Retirement Pension equal to 1/12
of the excess of (a) over (b) where:
(a) equals 2% of Final Average Compensation multiplied by the number
of years of Benefit Service; and
- 15 -
<PAGE> 18
(b) equals the sum of:
(1) the Normal Retirement Pension payable under the Basic
Plan; and
(2) the annual amount of any other supplemental pension
benefit provided by the Company.
In no event shall the Normal Retirement Pension be less than the Accrued Benefit
calculated as of June 27, 1989.
6.5 Full Retirement Pension: A Participant listed on Exhibit B who has
attained at least age 60 and has 30 years of Benefit Service shall be eligible
for a monthly payment of an amount equal to 100% of the Normal Retirement
Pension.
6.6 Early Retirement Pension: A Participant who has attained age 55 and has
10 or more years of Benefit Service is eligible to select either:
(a) an amount, commencing at age 65, equal to the Accrued Benefit,
determined in the same manner as the Normal Retirement Pension in
Section 6.4, based on Benefit Service and Final Average
Compensation as of the Participant's Early Retirement Date; or
(b) an amount, commencing upon termination of employment, equal to
the Participant's Accrued Benefit subject to an early retirement
reduction determined in accordance with Exhibit C or D, as
applicable. Provided, however, that Participants listed on
Exhibit B shall receive the greater of the benefits determined in
accordance with Exhibits C and D; or
- 16 -
<PAGE> 19
(c) an amount equal to the Participant's Accrued Benefit to commence
on a specified date 24 months or more after termination of
employment, subject to an early retirement reduction determined in
accordance with Exhibit C or D, as applicable. Provided, however,
that Participants listed on Exhibit B shall receive the greater of
the benefits determined in accordance with Exhibits C and D.
6.7 Disability Pension: A Participant who has 10 or more years of Benefit
Service and has suffered a Disability shall be eligible for a monthly amount
equal to: (1) the Early Retirement Pension (except that any such Participant
under age 55 will be treated as though age 55); or (2) an amount equal to 110%
of the Disability Pension available from the Basic Plan, whichever is greater;
but in no event shall the amount exceed the Normal Retirement Pension under this
Plan as set out in Section 6.4 above. An Application for a Disability Pension
shall be submitted to the Administrator by the applicant or by the Company,
together with a medical certificate signed by the Company's Medical Director in
a form satisfactory to the Administrator. A Participant with less than 10 years
of Benefit Service who suffers a Disability supported by a medical certificate
satisfactory to the Administrator shall be eligible for an immediate benefit
calculated in a manner consistent with the Early Retirement Pension described
in Section 6.6(b), subject to an actuarial reduction calculated on the basis
specified in Exhibit F. The Supplemental Plan Disability Benefit will be
reduced by any payments under the Company's Long-term Disability Plan.
6.8 Vested Termination Pension - Former Vested Participants.
(a) Former Vested Participants. A Former Vested Participant who has
terminated
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<PAGE> 20
service with the Company prior to age 55 has the following
election which may be made during the calendar year prior to the
year in which the Former Vested Participant attains age 55: he or
she may elect to (i) commence receiving a benefit under this Plan
at age 55, or (ii) to defer commencement of payment to a
specified date at least 24 months following attainment of age 55.
(b) If the Former Vested Participant does not make a timely election
under Paragraph 6.8(a) above, then the benefit will commence at
age 55.
(c) Reference is made to the Hardship Election provision below.
(d) The amount of the benefit will be the Participant's Accrued
Benefit, subject to an early retirement reduction determined in
accordance with Exhibit C or D, as applicable. Participants listed
on Exhibit B shall receive the greater of the benefits determined
in accordance with Exhibits C and D.
6. 9 Benefit Compensation: Except as provided in Sections 4.1(d) and 5.2 of
this Plan, a Participant's pension shall be computed under the terms of the
Supplemental Plan in effect as of the date of the Participant's termination of
employment with the Company, and shall not be recomputed, increased or
decreased after such termination, except for supplemental increases, if any, as
may be granted by the Company's Board of Directors.
- 18 -
<PAGE> 21
Article 7
Death Benefits
7.1 Death Benefits: Except for the surviving spouse's annuity described in
Sections 7.2 and 7.3, and any survivor death benefit selected by a Participant
in accordance with Section 7.4, no death benefits shall be payable under this
Supplemental Plan and a Participant shall forfeit all rights to any benefits
hereunder upon his or her death. As used in this Article, the term "surviving
spouse" refers to the person who is legally married to the Participant at the
time of his death and for the full one year (365 days) period immediately prior
to his death.
7.2 Surviving Spouse of Active Participant: The surviving spouse of a
Participant who dies while an active employee shall be eligible to receive a
monthly annuity in an amount equal to 50% of the deceased Participant's Accrued
Benefit (without regard to vesting) determined on the basis of (i) the
Participant's Final Average Compensation at the date of death, and (ii) the
Benefit Service the Participant would have had if employment had continued until
the Normal Retirement Date, and (iii) no reduction for benefit commencement
before age 65. This benefit shall continue for the lifetime of the surviving
spouse. Payment of this benefit shall commence in the month following the
Participant's death.
7.3 Surviving Spouse of Former Vested Participant
(a) Upon the death of a person who is a Former Vested Participant and
is not
- 19 -
<PAGE> 22
receiving a benefit under this Plan, the surviving spouse of such
person shall receive an annuity in an amount equal to 50% of the
annuity that would have been paid to the Former Vested
Participant under Section 6.8.
(b) If the Former Vested Participant dies prior to the year in which
he or she would have reached age 55, then the surviving spouse may
elect in that year to (i) commence benefits at the time the Former
Vested Participant would have reached age 55 (the "age 55 date"),
or (ii) to defer receipt of that benefit to a specified date at
least 24 months following the age 55 date. If no such election is
made, the benefit will commence in the month following the age 55
date.
(c) If the Former Vested Participant dies on after the year he or she
reaches age 55, the benefit to the surviving spouse shall commence
in the month following the Former Vested Participant's death.
(d) Reference is made to the Hardship Election provision below.
(e) The amount of the benefit will be 50% of Former Vested
Participant's Accrued Benefit, subject to early retirement
reduction in accordance with Exhibits C or D, as applicable, and
shall continue for the lifetime of the surviving spouse.
7.4 Survivor Death Benefit: Upon the death of a retired Participant who is
receiving or is entitled to receive annuity benefits hereunder and who, in
accordance with Section 6.1 hereof, had previously elected to receive his or her
Accrued Benefit in a form which pays a death benefit to a designated
surviving beneficiary, such death benefit shall be paid to such designated
surviving beneficiary in accordance with such prior election.
- 20 -
<PAGE> 23
7.5 Hardship Election. If, in the opinion of the Committee, any election to
defer a benefit under this Plan results in an undue hardship, then upon request
of the beneficiary, the beneficiary may elect to accelerate payment of that
benefit.
- 21 -
<PAGE> 24
Article 8
Miscellaneous
8.1 Amendment, Suspension, or Termination: Any amendment, suspension, or
termination of this Supplemental Plan shall have prospective effect only, be
non-discriminatory, and shall not affect any Accrued Benefit or vested right.
8.2 Nonguarantee of Employment: Nothing in this Supplemental Plan shall be
construed as a contract of employment between the Company and any Participant,
or as a right of any Participant to be continued in the employment of the
Company, or as a limitation of the right of the Company to discharge any
Participant, with or without cause.
8.3 Cost: The Company shall pay the full cost of this Supplemental Plan and
the Plan shall at all times be maintained on an unfunded basis. A Participant's
rights to a benefit under this Supplemental Plan are contractual in nature and
in the event the Company is unable to pay any benefit required hereunder, the
Participant shall have, with respect to the Company, only those rights of an
unsecured creditor.
8.4 Nonalienation of Benefits: Benefits payable under this Supplemental
Plan shall not be subject in any manner to alienation, anticipation, assignment,
charge, encumbrance, execution, garnishment, pledge, sale, transfer, or levy of
any kind, either voluntary or involuntary, including
- 22 -
<PAGE> 25
any such liability which is for alimony or other payments for the support of a
spouse or former spouse, or for any other relative of the Participant, prior to
actually being received by the person entitled to the benefit under the terms
of this Supplemental Plan. Any attempt to alienate, anticipate, assign, charge,
encumber, pledge, sell, transfer, or otherwise dispose of any right to benefits
payable under this Supplemental Plan shall be void. This Supplemental Plan
shall not in any manner be liable for, or subject to, the contracts, debts,
liabilities, or torts of any person entitled to benefits under this
Supplemental Plan.
8.5 Forfeiture: Anything herein to the contrary notwithstanding, if a
Participant or retired Participant willfully performs any act or willfully fails
to perform any act of material importance to the Company, which may result in
material discredit or substantial detriment to the Company, then upon
recommendation of the Administrator and upon a majority vote of the Board of
Directors, such Participant or retired Participant or the surviving spouse of
such Participant shall forfeit any benefit payments owing on and after the date
fixed by the Board of Directors and the Company shall have no further obligation
under this Supplemental Plan to such Participant, retired Participant, or the
surviving spouse of such Participant. If a Participant received his or her
benefit in the form of a lump sum payment pursuant to Section 6.2 hereof, then
the Participant or the surviving spouse of such Participant shall return to the
Company a proportionate share of such lump sum payment calculated as follows:
The proportionate share shall equal the product of the lump sum payment
multiplied by a fraction, the numerator of which is the number of full years
and months which elapsed from the time of the payment to the time of the
willful act or failure to act described herein and the denominator of which is
the
- 23 -
<PAGE> 26
number of full years and months of the Participant's life expectancy determined
as of the time of the lump sum payment.
8.6 Governing Law: All matters relating to this Supplemental Plan shall be
governed by the laws of the state of Virginia, without regard to the principles
of conflict of laws.
- 24 -
<PAGE> 27
Article 9
Appeals from Denial of Claims
If any claim for benefits under the Plan is wholly or partially denied,
the claimant shall be given notice of the denial. This notice shall be in
writing, within a reasonable period of time after receipt of the claim by the
Committee. This period shall not exceed 90 days after receipt of the claim,
except that if special circumstances require an extension of time, written
notice of the extension shall be furnished to the claimant, and an additional 90
days will be considered reasonable.
This notice shall be written in a manner calculated to be understood by
the claimant and shall set forth the following information:
(a) the specific reasons for the denial;
(b) specific reference to the Plan provisions on which the denial is
based;
(c) a description of any additional material or information necessary
for the claimant to perfect the claim and an explanation of why this material of
information is necessary;
(d) an explanation that a full and fair review by the Committee of the
decision denying the claims may be requested by the claimant or an authorized
representative by filing with the Committee, within 60 days after the notice has
been received, a written request for the review; and
(e) if this request is so filed, an explanation that the claimant or
an authorized representative may review pertinent documents and submit issues
and comments in writing within the same 60-day period specified in subsection
(d).
- 25 -
<PAGE> 28
The decision of the Committee upon review shall be made promptly, and
not later than 60 days after the Committee questions receipt of the request for
review, unless specific circumstances require an extension of time for
processing. In this case the claimant shall be so notified, and a decision shall
be rendered as soon as possible, but not later than 120 days after receipt of
the request for review. If the claim is denied, wholly or in part, the claimant
shall be given a copy of the decision promptly. The decision shall be it
writing, shall include specific reasons for the denial, shall include specific
references to the pertinent Plan provisions on which the denial is based, and
shall be written in a manner calculated to be understood by the claimant.
- 26 -
<PAGE> 29
EXHIBIT A
PARTICIPANTS IN THE SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN AS OF JANUARY 1, 1999
ELIZABETH M. ARNOLD
BEVERLY J. BURKE
RICHARD J. COOK
JAMES H. DEGRAFFENREIDT, JR.
RICHARD L. FISHER
JOHN K. KEANE, JR.
FREDERIC M. KLINE
PATRICK J. MAHER
LISA M. METCALFE
DOUGLAS V. POPE
JOSEPH M. SCHEPIS
ROBERTA W. SIMS
ROBERT A. SYKES
ROBERT E. TUORINIEMI
JAMES B. WHITE
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<PAGE> 30
EXHIBIT B
PARTICIPANTS ELIGIBLE TO ELECT A FULL RETIREMENT PENSION OR EARLY RETIREMENT
PENSION ACCORDANCE WITH TERMS OF SECTIONS 6.5 AND 6.6 OF THE PLAN
RICHARD J. COOK
RICHARD L. FISHER
JOHN K. KEANE, JR.
PATRICK J. MAHER
DOUGLAS V. POPE
ROBERT A. SYKES
- 28 -
<PAGE> 31
EXHIBIT C
EARLY RETIREMENT PENSION BENEFIT
"LEGACY" FORMULA
<TABLE>
<CAPTION>
---------------------------------------------------------
BENEFIT SERVICE
---------------------------------------------------------
AGE* <30 YEARS 30 YEARS
---- --------- --------
---------------------------------------------------------
<S> <C> <C>
65 1 1
-- - -
---------------------------------------------------------
64 0.98 1
-- ---- -
---------------------------------------------------------
63 0.96 1
-- ---- -
---------------------------------------------------------
62 0.94 1
-- ---- -
---------------------------------------------------------
61 0.92 1
-- ---- -
---------------------------------------------------------
---------------------------------------------------------
60 0.90 1
-- ---- -
---------------------------------------------------------
59 0.85 0.85
-- ---- ----
---------------------------------------------------------
58 0.80 0.80
-- ---- ----
---------------------------------------------------------
57 0.75 0.75
-- ---- ----
---------------------------------------------------------
56 0.70 0.70
-- ---- ----
---------------------------------------------------------
55 0.65 0.65
-- ---- ----
---------------------------------------------------------
</TABLE>
* NEAREST AGE OF PARTICIPANT (OR FORMER VESTED PARTICIPANT) ON DATE BENEFITS
COMMENCE.
- 29 -
<PAGE> 32
EXHIBIT D
EARLY RETIREMENT PENSION BENEFIT
"NEW" FORMULA
<TABLE>
<CAPTION>
----------------------------------------
AGE * ALL SERVICE
LEVELS
----------------------------------------
<S> <C>
65 1
----------------------------------------
64 0.97
----------------------------------------
63 0.94
----------------------------------------
62 0.91
----------------------------------------
61 0.88
----------------------------------------
----------------------------------------
60 0.85
----------------------------------------
59 0.82
----------------------------------------
58 0.79
----------------------------------------
57 0.76
----------------------------------------
56 0.73
----------------------------------------
55 0.70
----------------------------------------
</TABLE>
* Nearest Age of Participant (or Former Vested Participant) on date benefits
commence.
- 30 -
<PAGE> 33
EXHIBIT E
LUMP SUM CALCULATION PROCEDURE
1. Determine the participant's life expectancy as of the lump sum payment
date using the 1983 Group Annuity Mortality Table. Round the result up
to the next higher whole number of years.
2. Determine the annual life annuity benefit, payable as of the lump sum
payment date, that is to be converted into an actuarially equivalent
lump sum.
3. Assuming mid-year payment of the amount in Step (2), for each year of
the Participant's future life expectancy, discount each year's payment
back to the lump sum payment date using the yield on the zero-coupon US
Treasury security with maturity equal to the maturity of each year's
payment. The lump sum shall equal the sum of the discounted payments.
The U.S. Treasury yields shall be those published for the date six
months prior to the lump sum payment date. If such date falls on day
when U.S. Treasury securities are not traded, yields for the next
following business day shall be used.
- 31 -
<PAGE> 34
EXHIBIT F
Actuarial Equivalent Reduction Factors for Disability Benefits
Commencing Prior to Age 55
<TABLE>
<CAPTION>
--------------------------------------------------------------------
Factor by Which Age 55 Benefit is
Nearest Age at Multiplied to Determine Benefit at
Commencement Commencement Age
--------------------------------------------------------------------
<S> <C>
54 0.9261
--------------------------------------------------------------------
53 0.8586
--------------------------------------------------------------------
52 0.7968
--------------------------------------------------------------------
51 0.7402
--------------------------------------------------------------------
50 0.6882
--------------------------------------------------------------------
--------------------------------------------------------------------
49 0.6404
--------------------------------------------------------------------
48 0.5963
--------------------------------------------------------------------
47 0.5557
--------------------------------------------------------------------
46 0.5183
--------------------------------------------------------------------
45 0.4837
--------------------------------------------------------------------
--------------------------------------------------------------------
44 0.4516
--------------------------------------------------------------------
43 0.4220
--------------------------------------------------------------------
42 0.3945
--------------------------------------------------------------------
41 0.3690
--------------------------------------------------------------------
40 0.3453
--------------------------------------------------------------------
--------------------------------------------------------------------
39 0.3233
--------------------------------------------------------------------
38 0.3028
--------------------------------------------------------------------
37 0.2837
--------------------------------------------------------------------
36 0.2660
--------------------------------------------------------------------
35 0.2494
--------------------------------------------------------------------
--------------------------------------------------------------------
34 0.2339
--------------------------------------------------------------------
33 0.2195
--------------------------------------------------------------------
32 0.2060
--------------------------------------------------------------------
31 0.1934
--------------------------------------------------------------------
30 0.1816
--------------------------------------------------------------------
--------------------------------------------------------------------
29 0.1706
--------------------------------------------------------------------
28 0.1603
--------------------------------------------------------------------
27 0.1507
--------------------------------------------------------------------
26 0.1416
--------------------------------------------------------------------
25 0.1331
--------------------------------------------------------------------
</TABLE>
- 32 -
<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>
1999 1998 1997 1996 1995
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest Expense $ 37,437 $ 37,473 $ 33,599 $ 29,876 $ 30,932
Amortization of Debt Premium,
Discount and Expense 566 370 299 256 315
Interest Component of Rentals 12 12 17 96 56
-------------- -------------- -------------- -------------- --------------
Total Fixed Charges $ 38,015 $ 37,855 $ 33,915 $ 30,228 $ 31,303
============== ============== ============== ============== ==============
EARNINGS:
Net Income $ 68,768 $ 68,629 $ 82,019 $ 81,591 $ 62,909
Add:
Income Taxes Applicable to
Utility Operating Income 38,606 38,006 47,864 49,376 37,514
Income Taxes Applicable to
Non-Utility Operating Income
and Other Income (Expenses) - Net 2,970 1,800 577 (629) (730)
Total Fixed Charges 38,015 37,855 33,915 30,228 31,303
-------------- -------------- -------------- -------------- --------------
Total Earnings $ 148,359 $ 146,290 $ 164,375 $ 160,566 $ 130,996
============== ============== ============== ============== ==============
Ratio of Earnings to Fixed Charges 3.9 3.9 4.8 5.3 4.2
============== ============== ============== ============== ==============
</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>
1999 1998 1997 1996 1995
-------------- -------------- -------------- -------------- --------------
<S> <C> <C> <C> <C> <C>
FIXED CHARGES AND PRE-TAX
PREFERRED STOCK DIVIDENDS
Preferred Dividends $ 1,331 $ 1,331 $ 1,331 $ 1,332 $ 1,333
Effective Income Tax Rate 0.3768 0.3671 0.3713 0.3740 0.3690
Complement of Effective Income
Tax Rate (1 - Tax Rate) 0.6232 0.6329 0.6287 0.6260 0.6310
Pre-tax Preferred Dividends $ 2,136 $ 2,103 $ 2,117 $ 2,128 $ 2,113
============== ============== ============== ============== ==============
Interest Expense $ 37,437 $ 37,473 $ 33,599 $ 29,876 $ 30,932
Amortization of Debt Premium,
Discount and Expense 566 370 299 256 315
Interest Component of Rentals 12 12 17 96 56
-------------- -------------- -------------- -------------- --------------
Total Fixed Charges 38,015 37,855 33,915 30,228 31,303
Pre-tax Preferred Dividends 2,136 2,103 2,117 2,128 2,113
-------------- -------------- -------------- -------------- --------------
Total $ 40,151 $ 39,958 $ 36,032 $ 32,356 $ 33,416
============== ============== ============== ============== ==============
EARNINGS:
Net Income $ 68,768 $ 68,629 $ 82,019 $ 81,591 $ 62,909
Add:
Income Taxes Applicable to
Utility Operating Income 38,606 38,006 47,864 49,376 37,514
Income Taxes Applicable to
Non-Utility Operating Income and
Other Income (Expenses) - Net 2,970 1,800 577 (629) (730)
Total Fixed Charges 38,015 37,855 33,915 30,228 31,303
-------------- -------------- -------------- -------------- --------------
Total Earnings $ 148,359 $ 146,290 $ 164,375 $ 160,566 $ 130,996
============== ============== ============== ============== ==============
Ratio of Earnings to Fixed Charges
and Preferred Stock Dividends 3.7 3.7 4.6 5.0 3.9
============== ============== ============== ============== ===============
</TABLE>
<PAGE> 1
EXHIBIT 13
WASHINGTON GAS LIGHT COMPANY
<TABLE>
<CAPTION>
Selected Financial and Operations Data
- ---------------------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands, Except Per Share Data)
<S> <C> <C> <C> <C> <C>
SUMMARY OF EARNINGS
Utility operating revenues $ 972,120 $ 1,040,618 $1,055,754 $ 969,778 $ 828,748
Less: Cost of gas 505,346 575,786 572,925 469,925 390,041
Revenue taxes 34,793 39,659 43,719 44,349 40,472
----------- ----------- ---------- ---------- -----------
Utility net revenues $ 431,981 $ 425,173 $ 439,110 $ 455,504 $ 398,235
=========== =========== ========== ========== ===========
Non-utility operating revenues $ 140,042 $ 102,834 $ 44,926 $ 3,382 $ 9,829
Net income $ 68,768 $ 68,629 $ 82,019 $ 81,591 $ 62,909
Dividends on preferred stock 1,331 1,331 1,331 1,332 1,333
----------- ----------- ---------- ---------- -----------
Net income applicable to common stock $ 67,437 $ 67,298 $ 80,688 $ 80,259 $ 61,576
=========== =========== ========== ========== ===========
Earnings per average common share--
basic and diluted $ 1.47 $ 1.54 $ 1.85 $ 1.85 $ 1.45
=========== =========== ========== ========== ===========
CAPITALIZATION AT YEAR-END
Common shareholders' equity $ 684,034 $ 607,755 $ 589,035 $ 558,809 $ 513,044
Preferred stock 28,420 28,424 28,430 28,440 28,471
Long-term debt 506,084 428,641 431,575 353,893 329,051
----------- ----------- ---------- ---------- -----------
Total $ 1,218,538 $ 1,064,820 $1,049,040 $ 941,142 $ 870,566
=========== =========== ========== ========== ===========
OTHER FINANCIAL DATA
Total assets at year-end $ 1,766,724 $ 1,682,433 $1,552,032 $1,464,601 $ 1,360,138
Property, plant and equipment--net $ 1,402,742 $ 1,319,501 $1,217,137 $1,130,574 $ 1,056,058
Capital expenditures $ 158,733 $ 158,874 $ 139,871 $ 124,414 $ 112,715
Long-term obligations at year-end $ 506,084 $ 428,929 $ 432,368 $ 353,893 $ 329,051
COMMON STOCK DATA
Annualized dividends per share $ 1.22 $ 1.20 $ 1.18 $ 1.14 $ 1.12
Dividends declared per share $ 1.2150 $ 1.1950 $ 1.1700 $ 1.1350 $ 1.1175
Book value per share $ 14.72 $ 13.86 $ 13.48 $ 12.79 $ 11.95
Return on average common equity 10.4% 11.2% 14.1% 15.0% 12.3%
Yield on book value 8.3% 8.6% 8.7% 8.9% 9.4%
Payout ratio 82.7% 77.6% 63.2% 61.4% 77.1%
Common shares outstanding--
year-end (thousands) 46,473 43,839 43,700 43,703 42,932
GAS SALES AND DELIVERIES
(THOUSANDS OF THERMS)
Gas sold and delivered
Residential 604,162 615,786 665,452 739,603 596,499
Commercial and industrial
Firm 285,349 345,809 426,831 473,645 403,177
Interruptible 48,989 73,554 147,375 182,730 247,600
Electric generation -- -- 51 1,808 112,523
----------- ----------- ---------- ---------- -----------
938,500 1,035,149 1,239,709 1,397,786 1,359,799
----------- ----------- ---------- ---------- -----------
Gas delivered for others
Firm 197,204 110,542 27,574 3,772 --
Interruptible 272,046 243,166 185,487 84,788 61,467
Electric generation 129,700 93,721 94,022 57,689 18,538
----------- ----------- ---------- ---------- -----------
598,950 447,429 307,083 146,249 80,005
----------- ----------- ---------- ---------- -----------
Total 1,537,450 1,482,578 1,546,792 1,544,035 1,439,804
=========== =========== ========== ========== ===========
OTHER STATISTICS
Customer meters--year-end 846,381 819,719 798,739 772,281 750,849
Degree days 3,652 3,662 3,876 4,570 3,660
Percent colder (warmer) than normal (5.2)% (5.1)% 0.5% 18.6% (5.2)%
</TABLE>
16 WASHINGTON GAS LIGHT COMPANY
<PAGE> 2
WASHINGTON GAS LIGHT COMPANY
Management's Discussion and Analysis of
Financial Condition and Results of Operations
Certain matters discussed in this report, excluding historical information,
include forward-looking statements. Certain words, including, but not limited
to, "estimates," "expects," "anticipates," "intends," "believes," "plans," and
variations of these words, identify forward-looking statements that involve
uncertainties and risks.
These statements are necessarily based upon various assumptions with respect
to the future, including: 1) economic, competitive, political and regulatory
conditions and developments; 2) capital and energy commodity market conditions;
3) changes in relevant laws and regulations, including tax, environmental and
employment laws and regulations; 4) weather conditions; 5) legislative,
regulatory and judicial mandates and decisions; 6) timing and success of
business and product development efforts; 7) technological improvements; 8) the
pace of deregulation efforts and the availability of other competitive
alternatives; 9) estimates of future costs or the effect on future operations as
a result of events that could result from the Year 2000 issue described herein;
and 10) other uncertainties. Such uncertainties are difficult to predict
accurately and are generally beyond the Company's direct control. Accordingly,
while it believes that the assumptions are reasonable, the Company cannot ensure
that all expectations and objectives will be realized. Readers are urged to use
care and consider the risks, uncertainties and other factors that could affect
the Company's business as described in this Annual Report. All forward-looking
statements made in this Annual Report rely upon the safe harbor protections
provided under the Private Securities Litigation Reform Act of 1995.
This management's discussion should be read in conjunction with the
Company's Consolidated Financial Statements and Notes thereto.
OVERVIEW
Washington Gas Light Company (Washington Gas or the Company) is an energy
corporation that sells and delivers natural gas and a variety of energy-related
products and services to customers in metropolitan Washington, D.C., Maryland
and Virginia. During its 151-year history, most of the Company's operations have
been closely regulated by independent regulatory commissions that serve as a
surrogate for competition, primarily at the state level. During the last few
years, the introduction of federal and state deregulation initiatives has
rapidly changed the regulated component of the Company's business. These changes
are providing the Company with the opportunity to offer new products and
services and to improve its profitability. The operation of the Company and its
subsidiaries is divided into four major segments:
Regulated Energy
Utility Marketing
WASHINGTON GAS
LIGHT COMPANY
Customer
HVAC Financing
Regulated Utility--The parent and flagship company, Washington Gas Light
Company, delivers natural gas to all retail customers in its service territory
in accordance with tariffs established by the state regulatory commissions that
have jurisdiction over its rates. These tariffs allow the regulated utility the
opportunity to earn a fair rate of return on its invested capital and to recover
the costs of providing service. The regulated utility also sells natural gas to
those customers who have not elected or are not yet eligible to purchase their
natural gas from unregulated energy marketers. Historically, the regulated
utility has neither made a profit nor incurred a loss as a result of the sale of
the natural gas commodity. Rather, the sale of the natural gas commodity
represents a cost that is simply passed through on the bills of the regulated
customers subject to routine review by regulators that the costs were
reasonable. Over 95% of the Company's assets are committed to the regulated
utility segment.
Energy Marketing--A wholly owned subsidiary, Washington Gas Energy Services,
Inc. (WGEServices), competes with unregulated marketers by selling the natural
gas commodity directly to residential, commercial and industrial customers, both
inside and outside of the regulated utility's traditional service territory.
Heating, Ventilating and Air Conditioning (HVAC)--Through two wholly owned
subsidiaries, Washington Gas Energy Systems, Inc. (WGESystems) and American
Combustion Industries, Inc. (ACI), and as a partner in newly formed Primary
Investors, LLC, (Primary Investors), the Company offers residential and
commercial customers a variety of products and services associated with the
design, renovation, sale, installation and service of mechanical heating,
ventilating and air conditioning systems.
Customer Financing--The parent company offers financing for consumers to
purchase natural gas appliances and certain energy-related equipment.
This Management's Discussion and Analysis of Financial Condition and Results
of Operations describes the Company's financial condition, cash flows and
results of operations with specific information on results of operations,
liquidity and capital resources. It also includes management's interpretation of
its financial results, the factors affecting these results, major factors
expected to affect future operating results, risks that the Company faces in the
years ahead and approaches Washington Gas uses to address these risks.
RESULTS OF OPERATIONS
CORPORATE OVERVIEW
1999 vs. 1998.
Net income applicable to common stock for 1999 was $67.4 million, slightly
higher than the results for last year.
NET INCOME APPLICABLE TO COMMON STOCK
(Millions)
** this graph presented the Company's Net
Income Applicable to Common Stock
for 1994-1999
<TABLE>
<CAPTION>
Year Millions of Dollars
<S> <C>
1999 67.4
1998 67.3
1997 80.7
1996 80.3
1995 61.6
1994 59.1
</TABLE>
1999 ANNUAL REPORT 17
<PAGE> 3
Basic and diluted earnings per average common share were $1.47 or $0.07 per
average common share lower than fiscal year 1998.
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE
** this graph presented the Company's Basic and Diluted
Earnings Per Average Common share
for 1994-1999
<TABLE>
<CAPTION>
Year Dollars
<S> <C>
1999 1.47
1998 1.54
1997 1.85
1996 1.85
1995 1.45
1994 1.41
</TABLE>
Earnings per share declined $0.07 per share as a result of a 5.25% increase
in the average number of shares outstanding, resulting primarily from a November
1998 public sale of 2.3 million shares of common stock. In addition, common
stock issued under the Company's Dividend Reinvestment and Common Stock Purchase
Plan (DRP) and its Employee Savings Plans contributed slightly to the rise in
the average number of common shares outstanding.
The Company earned 10.4% and 11.2% on average common equity in 1999 and
1998, respectively. The following factors affected the Company's earnings:
Warmer Weather. The weather during 1999 and 1998 was nearly identical.
During both years, the weather was more than 5% warmer than normal.
Consequently, Washington Gas estimates that it earned approximately $0.37 less
per average common share each year than it would have earned under normal
weather conditions.
Higher Utility Net Revenues. Net revenues (operating revenues, less the cost
of gas and applicable revenue taxes) were $6.8 million higher in fiscal year
1999 than in 1998. The Company's firm therm deliveries rose by 1.4% as customer
meters increased 3.25% and weather was 0.3% warmer than in 1998.
Increased Non-Utility Income. In 1999, net income from the Company's
non-utility retail activities increased $3.3 million, or approximately $0.07 per
average common share over 1998. This improvement results from the continuing
growth and profitability of the Company's energy marketing, HVAC and customer
financing segments.
Higher Operation & Maintenance Expenses. Utility operation and maintenance
expenses in the current year increased $0.4 million, primarily because of $3.9
million of additional costs associated with technological initiatives. These
increases were offset by a $2.1 million net decline in labor and benefit
expenses, significantly affected by a 3.5% decrease in the Company's regulated
utility workforce. In addition, uncollectible accounts expense decreased by $1.6
million as a result of the drop in gross revenues this year.
Increased Depreciation and Amortization Expense. Depreciation and
amortization expense increased by $5.1 million, reflecting $145.4 million in
capital additions. Approximately $1.4 million of the increase is attributable to
amortization related to an enterprise-wide software system that was completed in
1999. Going forward, the Company will amortize approximately $4 million per year
over the useful life of this system, estimated at ten years.
Nonrecurring Transactions. The Company's 1999 and 1998 earnings include a
number of nonrecurring transactions. The 1999 results include a $1.8 million
after-tax gain from a subsidiary's sale of undeveloped land, offset by a $1.9
million after-tax loss from the sale of natural gas utility assets located in
West Virginia. During 1998, the Company recorded $3.2 million of after-tax gains
from asset sales, partially offset by a $1.0 million after-tax write-off of a
regulatory asset. Excluding these nonrecurring transactions, the Company's net
income applicable to common stock was $67.5 million and $65.1 million, or $1.47
and $1.49 per average common share, for fiscal years 1999 and 1998,
respectively.
1998 vs. 1997.
Net income applicable to common stock for 1998 was $67.3 million, or $13.4
million lower than the results for 1997. Basic and diluted earnings per average
common share were $1.54, or $0.31 per average common share lower than 1997.
Average common shares outstanding declined slightly from 1997, after the
Company's repurchase of 88,700 shares during the first fiscal quarter of 1998.
This decline was partially offset by new shares issued through the Company's DRP
and Employee Savings Plans. The Company earned 11.2% on average common equity in
1998 compared to 14.1% in 1997. The following factors contributed to the change
in earnings:
Lower Utility Net Revenues. Weather during 1998 was 5.5% warmer than in
1997. The warmer weather reduced the Company's 1998 firm therm deliveries and
associated net revenues, despite a 2.6% increase in customer meters.
Higher Operation & Maintenance Expenses. Operation and maintenance expenses
in 1998 increased primarily because of: 1) $8.6 million of additional costs
associated with the Company's technology initiatives, including the Year 2000
program; and 2) a $1.6 million pre-tax write-off of a regulatory asset. Lower
labor costs in 1998 partially offset these increased costs.
Higher Non-Utility Income. Fiscal year 1998 results reflected $3.2 million
of after-tax nonrecurring gains from the sales of the Company's retail propane
assets and investments in certain venture capital funds.
Higher Depreciation and Interest Expense. Investments in new facilities to
meet customer growth and replace existing capacity, which the Company partially
financed with long-term debt, caused increases in depreciation and interest
expense.
REGULATED UTILITY OPERATING RESULTS
This section describes the detailed results of the Company's consolidated
regulated utility operations in the District of Columbia, Maryland, Virginia and
West Virginia. During 1999, 1998 and 1997, utility operations contributed $1.38,
$1.45 and $1.83, respectively, toward basic and diluted earnings per average
common share.
NET REVENUES
Net revenues consist of utility operating revenues, less the cost of gas and
applicable revenue taxes. Net revenues increased by $6.8 million, or 1.6%, in
1999, reflecting a 1.4% increase in firm therm deliveries as a result of a 3.25%
rise in customer meters. In 1998, net utility revenues decreased by $13.9
million or 3.2% from the previous year.
18 1999 ANNUAL REPORT
<PAGE> 4
UTILITY OPERATING REVENUES
(Millions)
**this space presented the Company's Net
Revenues, Cost of Gas and Revenue Taxes
for 1994-1999
<TABLE>
<CAPTION>
Net Cost of Revenue
Year Revenues Gas Taxes Total
- ---- -------- ------- ------- -----
<S> <C> <C> <C> <C>
1999 432 505 35 972
1998 425 576 40 1,041
1997 439 573 44 1,056
1996 456 470 44 970
1995 398 390 41 829
1994 406 462 47 915
</TABLE>
The following table provides the factors contributing to the changes in net
revenues between years, net of applicable revenue taxes.
Composition of Utility Net Revenue Changes
<TABLE>
<CAPTION>
Increase/(Decrease)
from Prior Year
- -----------------------------------------------------------------
(Millions) 1999 1998
- -----------------------------------------------------------------
<S> <C> <C>
Gas Delivered to Firm Customers:
Volumes $4.6 $(15.7)
Rate Increases 0.4 1.0
Gas Delivered to Interruptible Customers 1.4 (1.8)
Other 0.4 2.6
---- ------
$6.8 $(13.9)
==== ======
</TABLE>
1999 vs. 1998.
Gas Delivered to Firm Customers. The level of gas delivered to firm customers is
highly sensitive to the variability of weather, because a large portion of
natural gas deliveries is used for space heating. The Company's rates are based
on normal weather temperatures. During 1999 and 1998, respectively, the weather
was 5.2% and 5.1% warmer than normal. For a comparison of actual weather to
normal for the last five years, see the Selected Financial and Operations Data
on page 16. The Company has no weather normalization tariff provision in any of
its jurisdictions. However, it does have declining block rates in its Maryland
and Virginia jurisdictions that reduce the impact on net revenues of deviations
from normal weather.
During 1999, the Company's deliveries to its firm customers increased by
nearly 14.6 million therms over 1998 results. These increases were driven
primarily by a 3.25% increase in the total number of meters served by the
Company. The net revenues generated by deliveries to this expanded customer base
more than offset the impact of warmer weather in 1999 compared to 1998. Of the
$6.8 million increase in total utility net revenues, approximately $4.6 million
was due to the increase in firm therm deliveries.
Historically, the regulated utility has neither made a profit nor incurred a
loss as a result of selling the natural gas commodity. Subject to regulatory
prudence reviews, the Company passes the commodity costs directly to its
customers. Currently, however, programs are underway in each of the Company's
jurisdictions in which certain customers can choose to continue purchasing
natural gas as part of a bundled service from the regulated utility or to
purchase the gas commodity separately from unregulated marketing companies.
Whichever option customers choose, Washington Gas continues to deliver their
natural gas through its distribution system and has the opportunity to earn a
regulated return for this delivery service. Utility net revenues and net income
are unaffected by the customers' choice of third-party natural gas suppliers.
However, when customers choose to buy gas from the Company's unregulated energy
marketing segment, the Company not only has an opportunity to earn profits, but
also assumes the risk of incurring losses on the sale of the natural gas
commodity. The results of the Company's unregulated energy marketing segment are
described in the "Non-Utility Operating Results" section of this management's
discussion and analysis.
Gas Delivered to Interruptible Customers. In order to receive interruptible
service, a customer must maintain the capability to substitute an alternate fuel
for natural gas whenever the Company needs to interrupt their service to meet
firm customers' demands. In exchange for this flexibility, interruptible
customers pay a lower delivery rate than firm customers. In the District of
Columbia and Virginia, interruptible customers can choose to buy bundled gas
service from the Company or have the Company only deliver gas that they purchase
from unregulated third-party marketers. In Maryland, interruptible customers may
buy only from third-party marketers.
Deliveries to interruptible customers increased by 4.3 million therms or
1.4% over 1998 levels because of increased customer demand. Net revenues
associated with therms delivered to this customer class increased by $1.4
million. The effect of these increased deliveries on net income is minimized by
margin-sharing arrangements embedded in the Company's interruptible rate design.
Under these arrangements, the Company applies a majority of the margins earned
on interruptible gas sales and deliveries to firm customers' rates. This occurs
once the Company reaches a pre-established gross margin threshold or occurs in
exchange for shifting certain fixed costs of providing service from the
interruptible to the firm class.
Other. The "Other" net revenue category includes: 1) gas deliveries to
customers for electric generation; 2) amounts generated from optimizing the
value of the Company's contractual assets for transportation and storage of
natural gas on the interstate pipelines; and 3) miscellaneous other operating
revenues that are not associated with volumes of gas sold. Other net revenues
increased $0.4 million over 1998 results.
The Company sells and/or delivers gas to two companies that use natural gas
to fuel their electric generation facilities in Maryland. Deliveries to these
customers were 36.0 million therms higher in 1999 than in 1998. Variations in
the volumes of deliveries to these two customers have little impact on the
Company's net revenues and net income because of a margin-sharing arrangement in
the state of Maryland. Under that arrangement, the Company calculates the gross
margins, less related expenses, and the cost to recover the Company's investment
in the facilities constructed to serve these two customers. Most of the
remaining gross margins from these customers is then applied to reduce firm
customers' rates.
Cost of Gas. The Company's cost of natural gas includes both fixed and
variable components. The fixed costs or "demand charges" are paid to pipeline
companies for system capacity needed to transport and store natural gas. The
variable costs, or the cost of the natural gas itself, are paid to natural gas
1999 ANNUAL REPORT 19
<PAGE> 5
producers. Variations in the Company's cost of gas expense result from changes
in gas sales volumes, the price of the gas purchased and the level of gas costs
collected through the operation of firm gas cost recovery mechanisms. Under
these regulated recovery mechanisms, the Company defers the difference between
actual firm gas costs and the gas cost recoveries included in revenues. Any
differences are recovered from or refunded to customers in subsequent periods.
Therefore, increases or decreases in the cost of gas associated with sales made
to firm customers have no effect on net revenues and net income.
The Company's cost of gas expense on a per therm basis, excluding the cost
and related volumes applicable to sales made outside of the Company's service
territory, decreased to 36.71 cents in 1999 from 38.95 cents in 1998. The
decrease resulted primarily from a decrease in the cost of gas per therm
recovered from customers, reflecting lower commodity gas prices for most of the
current year. The commodity cost of gas invoiced to the Company was 23.40 cents
and 28.13 cents per therm for 1999 and 1998, respectively. This decrease
reflects the lower market prices incurred during the winter months of fiscal
year 1999, primarily from lower demand due to warm weather.
1998 vs. 1997.
Gas Delivered to Firm Customers. Firm therm deliveries in fiscal year 1998
decreased by 47.7 million, or 4.3% lower than 1997 deliveries. This decline was
due to 5.5% warmer weather in 1998, partially offset by a 2.6% increase in
customer meters. The lower volume of deliveries resulted in a $15.7 million
decrease in net utility revenues. Effective December 28, 1997, the State
Corporation Commission of Virginia (SCC of VA) granted a $1.4 million revenue
increase to Shenandoah Gas Company (Shenandoah), a wholly owned subsidiary. Of
that increase, $1.0 million was applicable to fiscal year 1998.
Gas Delivered to Interruptible Customers. Deliveries to interruptible
customers decreased by 16.1 million therms (4.8%) when compared to 1997. This
decrease resulted primarily from the warmer weather experienced in 1998. Net
utility revenues associated with therms delivered to this customer class
decreased by $1.8 million.
Cost of Gas. The Company's cost of gas expense on a per therm basis,
excluding the cost and related volumes applicable to sales made outside its
service territory, decreased in 1998 to 38.95 cents from the 1997 level of
41.11 cents. The decrease resulted primarily from a decrease in the cost of gas
per therm recovered from customers, reflecting lower commodity gas prices in
fiscal year 1998. The commodity cost of gas invoiced to the Company was
28.13 cents and 30.96 cents per therm for 1998 and 1997, respectively, which
reflected the lower market prices incurred during the winter months of fiscal
year 1998, primarily due to warmer weather.
OTHER UTILITY OPERATING EXPENSES
1999 vs. 1998.
Operation and maintenance expenses increased $435,000 or 0.2% in 1999. During
1999, the Company incurred $3.9 million of increased operation and maintenance
costs for technological initiatives. In addition, advertising expense rose by
$900,000. These increases were offset by: 1) a $1.6 million decline in
uncollectible accounts expense, resulting primarily from lower gross revenues in
the current year; 2) a $1.6 million pre-tax write-off of a regulatory asset
recorded in fiscal year 1998; and 3) a net decrease of $2.1 million in labor and
benefit expenses as utility employee levels declined. At September 30, 1999, the
Company had 1,931 utility employees, or 69 fewer employees (3.5%) than at
September 30, 1998.
OTHER UTILITY OPERATING EXPENSES
(Millions)
**this graph presented a breakdown of
The Company's Operating Expenses
for 1994-1999
<TABLE>
<CAPTION>
Operation & Depreciation and
Year Maintenance Taxes Amortization Total
- ---- ----------- ----- ---------------- -----
<S> <C> <C> <C> <C>
1999 204 67 60 331
1998 201 67 55 323
1997 197 75 52 324
1996 221 73 48 342
1995 195 65 46 306
1994 207 62 44 313
</TABLE>
Depreciation and amortization increased by $5.1 million, or 9.2%. The
increase in depreciation and amortization is primarily attributable to $145.4
million in capital editions needed to meet customer growth and to upgrade
existing facilities and systems. The Company's composite depreciation rate was
2.93%, unchanged from 1998. In 1999, depreciation and amortization expenses
included $1.4 million of increased amortization related to the completion of the
Company's new enterprise-wide software system. The costs associated with this
software system are being amortized on a straight-line basis over its useful
life. A full year of amortization will equal approximately $4 million, or $2.6
million more than was reflected in the 1999 results of operations.
During fiscal year 1999, Shenandoah sold its utility assets located in West
Virginia and recorded a $2.9 million pre-tax loss. The Company sold these assets
because the assets were not performing satisfactorily and the proceeds of a sale
could be reinvested more effectively elsewhere in the business.
The composition of the change in income tax expense is detailed in the
Consolidated Statements of Income Taxes on page 36.
1998 vs. 1997.
Operation and maintenance expenses increased by $3.7 million (1.9%) in 1998. The
primary factors contributing to this increase included: 1) $8.6 million of costs
associated with the Company's technology initiatives, including initiatives to
resolve Year 2000 date-sensitivity issues; and 2) a $1.6 million nonrecurring
charge to write off a regulatory asset associated with Postretirement Benefits
Other Than Pensions related to the Company's Virginia jurisdiction. Lower labor
costs, resulting from improved operating efficiencies and fewer employees,
partially offset these increased costs. At September 30, 1998, the Company had
2,000 utility employees, a decline of 59 employees (2.9%) from the level at
September 30, 1997.
Depreciation and amortization increased by $3.5 million (6.8%) in 1998
primarily because of the Company's increased investment in plant and equipment
needed to meet customer growth and to replace existing capacity. Capital
expenditures totaled $158.9 million in 1998, and the composite depreciation rate
was 2.93% compared to 2.94% in 1997.
20 1999 ANNUAL REPORT
<PAGE> 6
NON-UTILITY OPERATING RESULTS
As previously discussed, Washington Gas has three primary unregulated operating
segments: 1) energy marketing; 2) HVAC; and 3) customer financing. These
activities, plus the impact of other incidental unregulated activities,
contributed $0.13, $0.10 and $0.03 per basic and diluted average common share in
fiscal years 1999, 1998 and 1997, respectively.
These results include a number of nonrecurring transactions, including a
$1.8 million after-tax gain ($0.04 per average common share) from the sale of
undeveloped land in 1999 and after-tax gains in 1998 totaling $3.2 million
($0.07 per average common share) from the sales of certain non-utility assets
(see Note 2 to the Consolidated Financial Statements). Excluding the effect of
these nonrecurring items, the primary unregulated activities contributed $0.10,
$0.03 and $0.03, respectively, of basic and diluted earnings per average common
share in fiscal years 1999, 1998 and 1997, respectively.
The composition of the change in revenues for these non-utility operating
segments is shown in the following table:
Composition of Non-Utility Revenue Changes
<TABLE>
<CAPTION>
Increase/(Decrease)
from Prior Year
- -------------------------------------------------------------
(Millions) 1999 1998
- -------------------------------------------------------------
<S> <C> <C>
Energy Marketing $20.7 $47.9
HVAC 17.3 11.2
Customer Financing 0.6 (0.2)
Other Non-Utility (1.4) (1.0)
----- -----
$37.2 $57.9
===== =====
</TABLE>
The following discussion describes the results of operations for each of the
three reported non-utility segments.
Energy Marketing. WGEServices comprises the Company's energy marketing
segment. Established in 1997, WGEServices sells natural gas on an unregulated
competitive basis directly to residential, commercial and industrial customers.
Revenues for this segment were $103.9 million in 1999, reflecting a $20.7
million, or 24.9% increase over 1998 results.
During the course of fiscal year 1999, the energy marketing segment expanded
its customer base by over 100%. Further, WGEServices was able to increase its
volumes delivered from 26.6 billion cubic feet (bcf) in 1998 to 34.2 bcf in
1999--a 29% increase. During 1998, WGEServices increased its volumes delivered
by approximately 65% from 1997 levels. The significant increase in WGEServices'
revenues, customer base, volumes delivered and net income is attributable to
WGEServices' aggressive marketing strategies and growing customer participation
in customer choice pilot programs. In 1999, favorable market conditions
resulting from lower gas prices also contributed to the improvement in net
income.
HVAC. As previously mentioned, the Company's primary HVAC activities are
performed by two subsidiaries, ACI and WGESystems. The Company purchased ACI in
March 1998 to offer commercial customers HVAC services, including the design,
renovation and service of mechanical heating, ventilating and air conditioning
systems.
During 1999, revenues from commercial HVAC activities increased by $17.3
million from 1998, as ACI completed its first full year of operations. Net
income from these HVAC activities increased from a $0.3 million net loss in
fiscal year 1998 to net income of $1.3 million in fiscal year 1999. The net loss
from HVAC activities in fiscal year 1998 resulted from start-up losses incurred
by ACI after its acquisition by the Company.
In mid-August 1999, the Company and Thayer Capital Partners formed Primary
Investors, a holding company that will focus on investment opportunities in
after-market products and services for residential and light commercial HVAC
customers. Primary Investors had a negligible impact on consolidated net income
in fiscal year 1999.
Customer Financing. This business segment offers residential and small
commercial customers financing to purchase gas appliances and certain other
equipment. The Company sells receivables that result from these financing
arrangements to financial institutions. Revenues from the customer financing
segment rose 18.0% in fiscal year 1999 and net income from this segment
increased from $1.3 million in fiscal year 1998 to $1.7 million in fiscal year
1999. The increase in earnings from customer financing activities was due
primarily to an increase in the volume of non-utility accounts receivable sold
and lower uncollectible accounts expense during fiscal year 1999.
OTHER INCOME (EXPENSES)--NET
The "Other Income (Expenses)--Net" line shown on the Consolidated Statements of
Income includes various corporate non-operating income and expense items and
related taxes.
INTEREST EXPENSE
Total interest expense decreased by $0.7 million, or 2.0%, in 1999 and increased
by $3.6 million, or 10.5%, in 1998. The following table shows the components of
the changes in interest expense between years.
Composition of the Changes in Interest Expense
<TABLE>
<CAPTION>
Increase/(Decrease)
from Prior Year
- ---------------------------------------------------------------
(Millions) 1999 1998
- ---------------------------------------------------------------
<S> <C> <C>
Long-term debt $ 0.9 $3.7
Short-term debt (0.8) --
Other (0.8) (0.1)
----- ----
$(0.7) $3.6
===== ====
</TABLE>
1999 vs. 1998.
Long-Term Debt. The increase in interest on long-term debt of $0.9 million
primarily resulted from a $30.8 million rise in the average amount of long-term
debt outstanding, partially offset by a 0.25 percentage point decline in the
weighted-average cost of such debt. The embedded cost of long-term debt at
September 30, 1999 was 6.8%, compared to 6.9% at September 30, 1998. The
retirement of $43.0 million of First Mortgage Bonds (FMBs) in fiscal year 1999
($39.0 million at 8 3/4% and $4.0 million at 8 5/8%), combined with lower rates
for Medium-Term Notes (MTNs) issued during fiscal year 1999, primarily explains
the decline in the embedded cost of long-term debt.
Short-Term Debt. The $0.8 million decrease in interest on short-term debt
results from a $10.4 million decline in the average amount of short-term debt
outstanding and a 0.43 percentage point decrease in the weighted-average cost of
such debt. See "Short-Term Cash Requirements and Related Financing" for a
discussion of fluctuations in short-term debt balances.
1999 ANNUAL REPORT 21
<PAGE> 7
Other. Other interest expense decreased by $0.8 million, reflecting an
increase in the accrual for an allowance for funds used during construction,
primarily associated with the installation of an enterprise-wide software system
in 1999.
1998 vs. 1997.
Long-Term Debt. The interest expense increase on long-term debt of $3.7 million
in 1998 was primarily due to a $62.0 million rise in the average amount of
long-term debt outstanding, partially offset by a 0.2 percentage point decrease
in the weighted-average cost of such debt. The Company's embedded cost of
long-term debt was 6.9% at September 30, 1998, compared to 7.1% at September 30,
1997. The decline in the embedded cost of long-term debt was primarily due to a
partial retirement of $11.0 million of 8 3/4% FMBs in February 1998 and lower
rates for new MTNs issued.
Short-Term Debt. Interest on short-term debt was essentially the same as
1997, reflecting a $1.8 million decrease in the average amount of short-term
debt outstanding, offset by a 0.2 percentage point increase in the
weighted-average cost of such debt.
LIQUIDITY AND CAPITAL RESOURCES
The Company has a goal to maintain its common equity ratio in the mid-50% range
of total capital. In addition, the Company has a general policy to repay
short-term debt in the spring, because a significant portion of the Company's
current assets is converted into cash at the end of the heating season.
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, 1999, total capitalization,
including current maturities of long-term debt, was comprised of 56.1% common
equity, 2.3% preferred stock and 41.6% long-term debt.
CAPITALIZATION
(INCLUDING CURRENT MATURITIES OF LONG-TERM DEBT)
(Millions)
**this graph presented a breakdown of the Company's
capital structure for 1994-1999
<TABLE>
<CAPTION>
Long-Term
Debt Including
Common Preferred Current
Year Equity Stock Maturities Total
- ---- ------ --------- -------------- -----
<S> <C> <C> <C> <C>
1999 684 28 508 1,220
1998 608 28 493 1,129
1997 589 28 453 1,070
1996 559 28 362 949
1995 513 28 382 923
1994 486 28 351 865
</TABLE>
SHORT-TERM CASH REQUIREMENTS AND RELATED FINANCING
The Company's business is very weather-sensitive and seasonal. In 1999, 75% of
the total therms delivered in the Company's franchise area (excluding deliveries
to two electric generation facilities) were delivered in the first and second
fiscal quarters. This weather sensitivity causes short-term cash requirements to
vary significantly during the year. Cash requirements peak in the fall and
winter months when accounts receivable, accrued utility revenues and storage gas
are at 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 a component of the cost of gas
recovered from customers.
Variations in the timing of collections of gas costs under the Company's gas
cost recovery mechanisms and the level of refunds from pipeline companies that
will be returned to customers can significantly affect short-term cash
requirements. At September 30, 1999, the Company had a $6.2 million net
over-collection of gas costs, compared to a $4.3 million net under-collection at
September 30, 1998. Amounts that are under-collected and over-collected are
reflected in the captions "Gas costs due from customers" and "Gas costs due to
customers" in the Consolidated Balance Sheets. Most of the current balances will
be collected from, or returned to, customers in fiscal year 2000. At September
30, 1999, refunds received from pipelines that are being returned to the
Company's customers totaled $2.2 million, compared to $1.4 million at September
30, 1998.
The Company uses short-term debt in the form of commercial paper and
short-term bank loans to fund seasonal requirements. Alternate sources include
unsecured lines of credit, some of which are seasonal, and $160 million in a
revolving credit agreement maintained with a group of banks. In addition, two of
the Company's subsidiaries each have $5 million of unsecured lines of credit
under revolving credit agreements. The Company can activate these financing
options to support or replace the Company's commercial paper. Additional
information regarding the Company's short-term borrowing capabilities is
included in Note 3 to the Consolidated Financial Statements.
At September 30, 1999, the Company had notes payable outstanding of $113.1
million, compared to $124.9 million outstanding at September 30, 1998. At
September 30, 1999, current maturities of long-term debt were $1.4 million.
LONG-TERM CASH REQUIREMENTS AND RELATED FINANCING
The Company's long-term cash requirements are primarily dependent upon the level
of capital expenditures, long-term debt maturity requirements and decisions to
refinance long-term debt. The majority of the Company's capital expenditures are
devoted to adding new customers in its existing service area. At September 30,
1999, the Company was authorized to issue up to $175 million of long-term debt
over approximately two years under an existing shelf registration. The nature of
the Company's long-term debt is discussed further in Note 4 to the Consolidated
Financial Statements.
Effective August 1, 1999, shares issued through the DRP and the Employee
Savings Plans are being purchased on the open market, rather than being issued
as new shares. On November 12, 1998, the Company publicly sold two million
shares of common stock at $25.0625 per share (see Note 5 to the Consolidated
Financial Statements). On November 18, 1998, the underwriters involved in the
offering exercised their option to purchase 300,000 additional shares from the
Company at the same price per share. Net proceeds from the sale totaling
22 1999 ANNUAL REPORT
<PAGE> 8
$55.7 million are being used for general corporate purposes, including capital
expenditures and working capital requirements.
1999.
Cash Flow from Operating Activities. In 1999, net cash provided by operating
activities was $152.7 million, an improvement of $30.4 million from the 1998
level. The improvement was brought about by: 1) lower funds used to support
accounts receivable and accrued utility revenues; and 2) increased sources of
cash provided by accounts payable resulting from the timing of payments related
to gas purchases. Partially offsetting these improvements were: 1) higher funds
used to support storage gas balances due to a greater level of gas volumes in
storage at higher prices; and 2) lower funds provided by customer deposits and
advance payments.
Cash Flow from Financing Activities. During fiscal year 1999, the Company
raised $55.7 million through the sale of 2.3 million shares of common stock. In
addition, the Company raised $8.6 million from 342,000 shares issued through the
DRP and the Employee Savings Plans.
The long-term debt issued in the current year of $80.8 million included
$75.0 million of MTNs issued at a weighted-average coupon rate of 6.44% along
with project financing of approximately $5.3 million. The terms of the unsecured
MTNs issued during fiscal year 1999 are discussed in Note 4 to the Consolidated
Financial Statements. During 1999, the Company retired $21.7 million of MTNs
with coupon rates ranging from 6.50% to 7.97%, $4.0 million of 8 5/8% Series
FMBs and $39.0 million of 8 3/4% Series FMBs.
Cash Flow from Investing Activities. Capital expenditures for 1999 totaled
$158.7 million. New business expenditures, which result in additional therm
deliveries and include amounts invested to convert customers from other energy
sources, equaled $83.6 million, or 52.7% of the total. Other capital
expenditures included approximately $21.0 million of expenditures relating to
the purchase and installation of enterprise-wide software to replace the
financial, human resources and supply chain systems. In addition, other
investing activities included $7.5 million that the Company has invested in
Primary Investors. By the end of fiscal year 1999, customer meters rose to
846,381, an increase of 26,662, or 3.25% over the level at the end of fiscal
year 1998.
As previously discussed in the "Results of Operations" section of this
management's discussion and analysis, the Company received $4.1 million from the
sale of undeveloped land in the fourth quarter of 1999 by a subsidiary of the
Company.
During 1999, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $82.5 million, representing 52.0% of capital
expenditures.
1998.
Cash Flow from Operating Activities. In 1998, net cash provided by operating
activities amounted to $122.3 million, a decrease of $33.0 million from the 1997
level. The decline primarily resulted from: 1) a decrease in gas cost
collections from customers; 2) lower net income, adjusted for noncash items; and
3) a decrease in accounts payable balances, primarily from lower gas costs.
Cash Flow from Financing Activities. The Company raised $5.3 million through
the DRP and Employee Savings Plans in fiscal year 1998. During the first quarter
of fiscal year 1998, the Company paid $2.3 million to repurchase 88,700 shares
of common stock for the Company's stock-based compensation plans.
The long-term debt issued in 1998 of $72.2 million included MTNs issued at a
weighted-average interest rate of 6.72%. In February 1998, the Company used the
proceeds of a $12 million MTN issuance to retire $11 million of 8 3/4% Series
FMBs. The Company paid a premium of $0.5 million on the redemption. Additional
retirements of long-term debt in 1998 included $18.8 million of MTNs with coupon
rates ranging from 6.43% to 8.00%, and $4.0 million of 8 5/8% Series FMBs.
Cash Flow from Investing Activities. Capital expenditures for 1998 totaled
$158.9 million. New business expenditures totaled $87.4 million, or 55.0% of the
total. Other capital expenditures included expenditures of $19 million for the
purchase and installation of the enterprise-wide software system previously
discussed. By the end of fiscal year 1998, customer meters rose to 819,719, an
increase of 20,980, or 2.6% over the level at the end of fiscal year 1997.
During 1998, the Company received $1.6 million from the sale of investments
in certain venture capital funds. As further discussed in Note 2 to the
Consolidated Financial Statements, the Company sold all of its retail propane
assets for $4.1 million, recognizing an after-tax gain of $1.6 million.
As further discussed in Note 2 to the Consolidated Financial Statements, the
Company purchased ACI with $3.0 million in cash and $2.0 million of debt
financing that is being repaid in monthly installments over a two-year period,
ending March 2000.
During 1998, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $83.6 million, representing 52.6% of capital
expenditures.
1997.
Cash Flow from Operating Activities. In 1997, net cash provided by operating
activities amounted to $155.3 million, an increase of $95.3 million from the
1996 level. The improvement was brought about by: 1) increased collections of
gas costs from customers; 2) higher costs for gas storage withdrawals in 1997,
combined with lower levels of storage gas injections due to the warmer weather
in 1997; and 3) customer refunds in 1996 of over-collections from the
implementation of an interim rate increase. Partially offsetting these sources
of cash were greater funds supporting accounts receivable primarily from higher
gas costs and a decrease in cash provided by accounts payable primarily due to
payments made during 1997 of amounts associated with the redesign of the
Company's organization.
Cash Flow from Financing Activities. The long-term debt issued in fiscal
year 1997 of $125.8 million included MTNs issued at a weighted-average interest
rate of 6.60%. Proceeds from the MTNs issued were used to retire $27.5 million
of 8 5/8% Series FMBs in March 1997, $8.0 million of maturing MTNs and for other
corporate purposes.
Cash Flow from Investing Activities. Capital expenditures for 1997 totaled
$139.9 million. New business expenditures totaled $89.3 million, or 63.8% of the
total. By the end of fiscal year 1997, customer meters rose to 798,739, an
increase of 26,458, or 3.4% over the level at the end of fiscal year 1996.
During 1997, the sum of net income and noncash charges, less dividends on
common and preferred stock, totaled $94.5 million, representing 67.6% of capital
expenditures.
1999 ANNUAL REPORT 23
<PAGE> 9
SALE OF ACCOUNTS RECEIVABLE
During 1999, the Company augmented cash flow by selling $28.6 million of certain
non-utility accounts receivable from the Company's customer financing segment to
commercial banks. Similar sales of non-utility accounts receivable in 1998 and
1997 amounted to $27.2 million and $33.0 million, respectively. For further
discussion of the Company's sales of non-utility accounts receivable, see Note
10 to the Consolidated Financial Statements.
LONG-TERM MATURITIES
The amount of maturities on long-term debt for the ensuing five-year period is
included in Note 4 to the Consolidated Financial Statements.
SECURITY RATINGS
Shown below are the ratings on the Company's debt instruments at September 30,
1999. The Company has no debt outstanding under its Mortgage at September 30,
1999.
Unsecured Medium-Term Notes
Fitch IBCA, Inc. AA-
Moody's Investors Service Aa2
Standard & Poor's Corporation AA-
Commercial Paper
Fitch IBCA, Inc. F1+
Moody's Investors Service P-1
Standard & Poor's Corporation A-1+
CAPITAL EXPENDITURES
The Company's actual capital expenditures for fiscal years 1997, 1998 and 1999
and projected capital expenditures for fiscal years 2000 through 2004 are shown
in the following table. This table does not include the Company's commitment to
invest up to $17.5 million of additional funds during the next five years in
Primary Investors (see the "Non-Utility Operating Results" section of this
management's discussion and analysis). The Company believes that the combination
of available internal and external sources of funds will be adequate to meet its
requirements.
<TABLE>
<CAPTION>
Capital Expenditures
Actual Projected
- ----------------------------------------------------------------------------------------------------------------------
(Millions) 1997 1998 1999 2000 2001 2002 2003 2004 Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
New Business $ 89.3 $ 87.4 $ 83.6 $ 70.7 $ 72.1 $ 60.5 $ 61.2 $ 67.7 $332.2
Replacements 36.4 36.2 37.5 34.5 35.7 36.3 37.3 38.2 182.0
Other 14.2 35.3 37.6 20.1 18.5 17.7 16.8 20.6 93.7
------ ------ ------ ------ ------ ------ ------ ------ ------
Total $139.9 $158.9 $158.7 $125.3 $126.3 $114.5 $115.3 $126.5 $607.9
====== ====== ====== ====== ====== ====== ====== ====== ======
</TABLE>
COMPETITION
COMPETITION WITH OTHER ENERGY PRODUCTS
In its core utility business, the Company faces competition based on customers'
preferences for natural gas compared to other energy products and the
comparative prices of those products. Currently, the most significant product
competition occurs between natural gas and electricity in the residential
market. The residential market represents a substantial proportion of the
Company's net income. In its service territory, the Company continues to attract
the majority of the new residential construction market. The Company believes
that consumers' continuing preference for natural gas allows it to maintain a
strong presence.
Currently, the Company generally maintains a price advantage over
electricity in its service area. However, as discussed further below,
restructuring in both the natural gas and electric industries is leading to
changes in traditional pricing models. As part of the electric industry
restructuring effort, certain business segments are moving toward market-based
pricing, with third-party providers of electricity participating in retail
markets. Electric restructuring may result in lower comparative pricing for
electric service and other alternative energy sources, including natural gas.
These changes will result in increased competition for the Company.
In the interruptible market, customers must be capable of using a fuel other
than natural gas when demand by the Company's firm customers peaks. Fuel oil is
the most significant competing energy alternative to natural gas. The Company's
success in this market depends largely on the relationship between gas and oil
prices. Because the natural gas marketplace is primarily domestic, the
relationship between supply and demand generally has the greatest impact on
natural gas prices. Because a large portion of oil comes from foreign sources,
political events can have significant influences on oil prices.
DEREGULATION
In 1978, the Natural Gas Policy Act was enacted. That act gradually replaced
regulated wellhead prices with natural gas prices that are market driven. Since
1978, regulators and legislators have instituted an increasing number of changes
aimed at encouraging competition in the utility industry, whenever it is
economically beneficial to consumers.
Historically, and for most current customers of the regulated utility, the
Company provides a "bundled" service that includes two primary functions: 1) the
core utility, or delivery, function, which involves delivering the gas and
providing customers with services, such as meter reading, bill preparation and
responding to customer telephone inquiries; and 2) the merchant function, which
involves supplying the natural gas commodity.
As regulatory reforms continue, the merchant and the delivery functions are
now becoming increasingly separated or "unbundled" from one another at the
regulated utility level. Deregulation initiatives to date have been directed at
the merchant function.
24 1999 ANNUAL REPORT
<PAGE> 10
Customer choice pilot programs are underway in each of the Company's
jurisdictions that give customers the opportunity to select an unregulated
supplier from whom to purchase their natural gas commodity on a competitive
basis. At the present time, customers may also choose to continue to purchase
their natural gas commodity from the regulated utility. The transition toward
competitive sales of the natural gas commodity provides the Company with
significant opportunities to expand its operations and further improve its
profitability in this competitive market. However, participating in this rapidly
evolving marketplace also poses new risks and challenges that must be addressed
in the Company's current and future strategies. The following sections discuss
strategies the Company is undertaking to address these changes proactively and
to minimize its risk exposure in the years ahead.
The Gas Delivery Function
The gas delivery function, the Company's core business, continues to be
regulated by local regulatory commissions. In developing this core business, the
Company has invested over $2 billion to construct a safe, reliable and
economical gas distribution system.
Because of the high cost, safety and environmental considerations associated
with building and operating a duplicate distribution system, the Company
believes there will continue to be only one owner and operator of the natural
gas distribution system in its franchise area for the foreseeable future. In
addition, the Company believes that the bypass of its facilities by other
potential delivery service providers is unlikely to become a significant threat,
primarily because of the nature of its customer base and the distance of most
customers from interstate pipelines.
The Company expects that local regulatory commissions will continue
functioning as surrogates for competition by setting the prices and the terms
and conditions for delivery service. Further, the Company believes that local
regulatory commissions will continue to allow it the opportunity to earn a fair
rate of return on the capital invested in its distribution system and to recover
reasonable operating expenses. The Company plans to continue constructing,
operating and maintaining its natural gas distribution system.
The Company believes there will not be any change in the near future of the
risk profile of the regulated utility. The sale of the gas commodity by the
utility has historically been a cost that is simply passed through to customers.
Therefore, the extent to which the regulated utility no longer sells the natural
gas commodity, because unregulated marketers are selling it, will not affect the
profitability of the regulated utility.
The Merchant Function and Natural Gas Unbundling
Historically, the Company purchased natural gas for its customers from
producers, and entered into contracts with interstate pipeline companies to have
the gas delivered to its distribution system.
In 1995, Washington Gas became one of the first companies in the nation to
implement a customer choice pilot program for the purchase of natural gas on an
unregulated basis. This change in the historical model gave participants the
opportunity to select a supplier from whom they could purchase the natural gas
commodity. The Company introduced its first pilot program in Maryland that year
and subsequently established similar pilot programs in Virginia and the District
of Columbia. One purpose of the programs was to test customers' acceptance and
reaction to choice. Therefore, the participation in these programs has been
voluntary and the number of participants has been limited by program design.
While participation in the Company's programs varies by jurisdiction,
customers have begun to select their gas commodity supplier. Out of the more
than 300,000 customers eligible to participate in these programs at September
30, 1999, over 100,000 customers have already elected to purchase the natural
gas commodity from an unregulated third-party supplier.
In the years ahead, the Company expects that these pilot programs will be
expanded gradually to include all natural gas customers. Ultimately, the Company
expects the regulated utility will play a much smaller role in the merchant
function and may eventually exit the merchant function as customers buy natural
gas from unregulated marketers. During this transition period, the Company will
continue to have certain obligations under long-term contracts to purchase
natural gas from producers and transportation capacity from interstate pipeline
companies (see Note 10 to the Consolidated Financial Statements). Accordingly,
the Company's strategy focuses on recovering contractual costs and maximizing
the value of contractual assets.
Currently, the regulated utility includes the cost of the natural gas
commodity and pipeline services in the purchased gas costs that are included in
firm customers' rates, subject to regulatory review. The Company's
jurisdictional tariffs contain gas cost mechanisms that provide for the recovery
of the actual invoice cost of gas applicable to firm customers. The Company
believes it prudently entered into its gas contracts and that the costs being
incurred should be recoverable from customers. If future unbundling or other
initiatives remove the current gas cost recovery provisions, the Company could
suffer adverse impacts to the extent its gas costs are not competitive and there
are no other satisfactory regulatory mechanisms available to recover any costs
that may exceed market prices.
The Company currently has recovery mechanisms for such potentially stranded
costs in Maryland and the District of Columbia. In an interim ruling addressing
the Company's request for specific treatment of potential stranded costs, the
SCC of VA deferred consideration of the recovery of any substantiated stranded
costs to a future base rate proceeding. In the event that a regulatory body
disallows the recovery of such costs, they would be borne by shareholders.
To minimize its exposure to long-term fixed cost contracting risk during the
transition period, the Company is not currently renewing expiring long-term gas
commodity and pipeline transportation and storage contracts. As these contracts
expire, the Company is entering into flexible short-term purchasing arrangements
when gas demand justifies additional resources. By utilizing this strategy, the
Company is mitigating its exposure to long-term commitments, while continuing to
ensure reliable and competitively priced gas for its customers that continue to
buy the natural gas commodity from the regulated utility.
To maximize the value of its contractual assets, the Company has entered
into contracts with unregulated marketers that make use of the Company's firm
storage and transportation rights to meet the Company's city-gate delivery needs
and to make
1999 ANNUAL REPORT 25
<PAGE> 11
off-system sales when such storage and transportation rights are underutilized.
The Company continues to pay the fixed charges associated with the firm storage
and transportation contracts used to make sales.
As local distribution companies' role in the merchant function decreases
over time, opportunities emerge for unregulated natural gas providers. In the
deregulated marketplace, third-party suppliers have profit-making opportunities,
but also assume the risk of loss.
Recognizing the opportunity to improve its profitability, the Company
established WGEServices, an unregulated gas marketing subsidiary, in 1997. To
date, WGEServices has attracted customer choice participants both inside and
outside the Company's traditional service area. Since it was established,
WGEServices has grown its unregulated customer base to include nearly 65,000
residential, commercial, industrial and governmental customers. Gross revenues
in 1999 were $103.9 million and net income was $1.6 million. The Company
believes that the customer choice programs will continue to expand, as well as
WGEServices' participation in these programs.
The regulatory process buffers utilities somewhat from certain types of
risks. These protections do not, however, apply to unregulated marketers such as
WGEServices. Thus, while WGEServices has a significant potential for continued
growth, it must carefully manage the associated risks in order to be successful.
WGEServices must compete with other third-party suppliers in order to sell
the natural gas commodity to customers. The prices WGEServices charges for the
natural gas commodity must be competitive with those charged not only by other
third-party suppliers, but also with those charged by Washington Gas as part of
its continued bundled service. WGEServices must also spend considerable
resources to attract new customers and retain its existing customers.
Consequently, operating margins for WGEServices tend to be low.
In addition, WGEServices faces supply-side risks. To minimize its
supply-side risks, WGEServices has a strategy to manage its natural gas contract
portfolio in a manner that closely aligns the volumes of gas it purchases with
firm commitments from customers to purchase this gas. WGEServices purchases its
gas from a number of wholesale suppliers in order to avoid relying on any single
provider for its natural gas supply. Similarly, WGEServices' dependency on any
one customer or group of customers is limited.
Electric Unbundling
Customer choice programs are not unique to the natural gas industry. Choice for
electric customers has been legislated or is being considered in each
jurisdiction in which the Company operates. These programs allow for customers
to select their electric supplier as soon as July 2000, with phase-in periods
through 2004.
As local regulatory commissions move forward on electric deregulation
initiatives, the Company plans to take advantage of the new opportunities
provided by deregulation by further diversifying its products and services.
WGEServices is preparing to sell electricity to customers in the electric
customer choice programs that will soon be implemented in the areas it currently
serves. It intends to serve the same diversified customer base that it serves in
its unregulated gas marketing business.
Potential for Further Unbundling
Currently, the Company provides customer services, such as preparing bills,
reading meters and responding to customer inquiries, as part of its core utility
function. Unregulated third-party marketers have the option to assume
responsibility for bill preparation and customer collections. In addition to
billing and collecting from customers for the natural gas commodity, third-party
marketers' bills may include natural gas delivery charges due the regulated
utility, which are subsequently remitted to Washington Gas.
Although the Company still provides most services on a bundled basis, the
potential exists for future deregulation initiatives to separate these services
from the core utility function. In that case, customers could choose to have
unregulated competitors provide these services.
The Company continues to improve quality and efficiencies and to reduce the
cost of performing these functions with a goal of achieving market level
performance in order to be competitive. As the functions become unbundled, the
Company will continue to review its role in that marketplace.
OTHER FACTORS AFFECTING THE COMPANY
INDUSTRY CONSOLIDATION AND CORPORATE STRUCTURE
The energy industry, much like other industries that are becoming increasingly
deregulated and more competitive, has seen a number of consolidations,
combinations, disaggregations and other strategic alliances and restructuring.
This is being driven, in part, as energy companies seek to offer a broader range
of energy services to compete more effectively in attracting and retaining
customers. For example, affiliations with other operating utilities could
potentially result in economies and synergies, and could provide a means to
offer customers a more complete range of energy services. Consolidation will
present combining entities with the challenges of remaining focused on the
customer and integrating different organizations. Others in the energy industry
are discontinuing operations in certain portions of the energy industry or
divesting portions of their business and facilities.
The Company, from time-to-time, performs studies, and in some cases holds
discussions regarding utility and energy-related investments and transactions
with other companies. The ultimate impact on the Company of any such investments
and transactions that may occur cannot be determined at this time. The Company
has studied changing its corporate structure to clarify the separation of
regulated from unregulated operations, for business and regulatory reasons. One
structural option the Company is pursuing is the formation of a parent holding
company like that of many other utilities.
REGULATORY MATTERS
Requests for a modification to existing rates are based on increased investment
in plant and equipment, higher operating expenses and the need to earn an
adequate return on invested capital. In July 1998, the SCC of VA granted the
Company's distribution subsidiary, Shenandoah Gas Company, an increase in annual
revenues of $1.4 million, effective December 28, 1997. The Company's base rates
did not change in any of its other major jurisdictions in 1999 and have not
changed during the past five years. A summary of major rate applications and
results is shown in the following table.
26 1999 ANNUAL REPORT
<PAGE> 12
Summary of Major Rate Applications and Results
<TABLE>
<CAPTION>
Increase in
Annual Revenues Allowed
(Millions) Return on
Test Year ------------------------- Common
Jurisdiction Effective Date 12 Mos. Ended Requested Granted 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.
INCENTIVE RATE PLAN PROPOSAL
On May 17, 1999, the Company filed an application for an Incentive Rate Plan
with the Public Service Commission of Maryland (PSC of MD). The application
requested that the Company's rates be frozen at current levels for five years
from the date of approval. In addition to the rate freeze, the plan proposes a
sharing mechanism when the Company's earnings on its Maryland business exceeds a
12% return on equity (ROE), with the customers receiving 50% and the Company
retaining 50% of the excess.
The proposal provides for a change in the 12% benchmark return on equity
when the twelve-month average of 30-year U.S. Treasury bonds moves by more than
100 basis points in either direction. The proposal also allows for adjustments
to rates due to circumstances beyond the Company's control, such as changes in
tax laws, legislative mandates, Financial Accounting Standards Board or
Securities and Exchange Commission accounting modifications or regulatory
changes. The proposal provides the Company with the opportunity to adjust rates,
subject to PSC of MD review and refund, should its Maryland weather-normalized
ROE drop below 8.5%. Finally, the proposal maintains the gas cost mechanisms
that provide for the recovery of actual costs of gas from firm customers.
The Company believes that if the PSC of MD approves the proposal, Maryland
customers would receive significant protection from the risk of inflationary
increases for five years. The Company would also have an additional incentive to
increase its operational efficiency and reduce costs in order to earn a greater
return for its shareholders.
Under this proposal, the Company has an opportunity to increase its earnings
beyond its current 11.50% allowed return on equity. However, this incentive
proposal presents certain risks for the Company since the impact and the risk of
cost increases would almost completely be borne by the Company. The Company
believes that the incentive rate plan it has proposed and the efficiencies it
can derive represent an appropriate balance of the interests of its customers
and its shareholders.
Settlement discussions are currently underway among PSC of MD staff,
intervenor groups and the Company. If successful, the results of these
settlement discussions will be presented to the PSC of MD for its approval.
However, a decision is not expected for the fiscal year 2000 heating season.
YEAR 2000
The millennial change to the Year 2000 could affect the Company's software
programs and computing infrastructure that use two-digit years to define the
applicable year, rather than four-digit years. As such, they may recognize a
date using "00" as being the year 1900 rather than the year 2000. This could
result in the computer or device shutting down, performing incorrect
computations or performing inconsistently.
In 1996, the Company began a structured program to address Year 2000 issues.
It has been implementing individual strategies targeted at the specific nature
of Year 2000 issues in each of the following areas: 1) business-application
systems including, but not limited to, the Company's customer service,
operations and financial systems and end-user applications; 2) embedded systems,
including equipment that operates such items as the Company's storage and
distribution system, meters, telecommunications, fleet and buildings; 3) vendor
and supplier relationships; 4) communications with customers; 5) business
continuity management planning; and 6) independent verification and validation.
To implement this comprehensive Year 2000 program, the Company established a
Year 2000 Project Office, chaired by the Vice President and Chief Information
Officer who reports directly to the Chairman and Chief Executive Officer. The
multi-disciplinary project office includes executive management and employees
with expertise from various disciplines including, but not limited to,
information technology, engineering, finance, communications, internal audit,
facilities management, procurement, operations, law and human resources. In
addition, the Company has utilized the expertise of outside consultants to
assist in the implementation of the Year 2000 program in such areas as
business-application system remediation, business-application system
replacement, embedded systems inventory and analysis, business continuity
management planning, and independent verification and validation.
Business Application Systems
In March 1997, the Company completed its assessment of all its
business-application systems. It has resolved Year 2000 issues through
remediation of 18 systems to recognize the turn of the century and the
replacement of 21 systems with new systems that provide additional business
management information and recognize four-digit years. The Company has completed
modifications to all 18 of the business applications
1999 ANNUAL REPORT 27
<PAGE> 13
targeted for remediation. Thus, the applications targeted for remediation have
been remediated, tested and placed back into a Year 2000 operational
environment.
The Company used in-house staff to test all remediated applications and used
a testing procedure commonly known as trace-based testing to test modified
business applications for Year 2000 functionality. This method first captures
current processing steps and relevant data, which are run prior to remediation
(baseline test) and again after remediation (regression test). This process is
intended to identify any business rules that may have changed during the
remediation effort and to confirm that only date processes have been changed.
Once the regression test was successfully completed, the Company used automated
test software tools to perform additional applicable future date tests for each
system.
The Company installed an enterprise-wide software system that replaced 19
business application systems, including its financial, human resources and
supply chain systems. Two other systems have been replaced with systems not
included in the enterprise-wide software initiative. These 21 business
applications represent approximately one-half of the business application
software code requiring remediation or replacement. The Company has completed
the replacement of all critical and important business applications.
During the fourth quarter of fiscal year 1998, the Company completed a
comprehensive, prioritized inventory of end-user applications (i.e., PC-based
databases) and has implemented, replaced or remediated these applications, as
necessary. The Company has completed the replacement or remediation and testing
of all critical end-user applications.
Embedded Systems
The Company has performed a comprehensive inventory of its embedded systems at
the component level. This inventory identified several hundred components that
were potentially date-sensitive. The Company has contacted all manufacturers of
those components that it has identified as critical or important to its
operations. Approximately 3% of the date-sensitive components that the Company
has identified were non-compliant based on information provided by the
manufacturers. All critical and important components have been remediated,
tested and placed back into production.
Vendor and Supplier Relationships
The Company has contacted in writing or through face-to-face discussions all
vendors and suppliers of products and services that it considers critical or
important to its operation. These contacts include providers of interstate
transportation capacity and storage, natural gas suppliers, financial
institutions and electric, telecommunications and water companies. The Company
has evaluated their responses and continues the process of following up with the
vendors and suppliers either through meetings or by letter. The Company
recognizes there are no practical alternatives for external infrastructure such
as electric, telecommunications and water services, suppliers of natural gas and
providers of interstate transportation capacity and storage to deliver natural
gas to the Company's distribution system. However, based upon the Company's
communications with these suppliers, the Company expects these providers to be
ready to provide service at the turn of the century and beyond.
Customer Communications
The Company is communicating with its major interruptible customers to inform
them about the potential vulnerability of embedded boiler and plant control
systems. Last year the Company informed them that they should assess the need to
include potential remediation and/or replacement of these systems as part of
their Year 2000 programs to ensure their ability to switch to an alternate fuel
source, as required by applicable tariffs and contracts, if called on to do so.
In the summer of 1999, the Company informed its interruptible customers that all
interruptible sales and interruptible delivery service customers will be
required to switch to their alternate fuel sources on the morning of December
31, 1999.
In addition, the Company is explaining its Year 2000 efforts to customers
through individual, community and association presentations; through responses
to written inquiries; through brochures explaining its program, which were
mailed to customers; and through its website.
Year 2000 Risks and Business Continuity Planning
With respect to its internal operations, over which the Company has direct
control, the Company believes the most significant potential risks are: 1) its
ability to use electronic devices to control and operate its distribution
system; 2) its ability to render timely bills to its customers; 3) its ability
to enforce tariffs and contracts applicable to interruptible customers; and 4)
its ability to maintain continuous operation of its computer systems. The
Company's Year 2000 program addresses each of these risks and the remediation or
replacement of these systems is essentially complete. In the event that any Year
2000-related problems may occur, the Company's continuity plan will outline
alternatives to mitigate the impact of such failures, to the extent possible.
The Company relies on the suppliers of natural gas and interstate
transportation and storage capacity to deliver natural gas to the Company's
distribution system. The external infrastructure, including electric,
telecommunications and water services, is necessary for the Company's basic
operation, as well as the operations of many of its customers. Should any of
these critical vendors fail, the impact of any such failure could become a
significant challenge to the Company's ability to meet the demands of its
customers, to operate its distribution system and to communicate with its
customers. It could also have a material adverse financial impact including, but
not limited to, lost revenues, increased operating costs and claims from
customers related to business interruptions. The Company has no way of ensuring
that those vendors or suppliers mentioned above, for which there are no viable
options, will be timely Year 2000 compliant.
As part of its normal business practice, the Company maintains plans to
follow during emergency circumstances. These plans are being used as a basis to
build the Company's continuity plan for potential Year 2000-related problems. As
part of its contingency planning effort, the Company has performed tabletop
exercises to validate this plan. The Company will continue performing tabletop
exercises and drills, which are expected to continue through the end of 1999.
The Company maintains and operates a command center that is activated during
emergency circumstances. The Company will manage specific Year 2000 continuity
operations from the command center during the millennium change, as well as at
28 1999 ANNUAL REPORT
<PAGE> 14
other points in time on an as-needed basis. The Company has informed its
employees that every employee will be expected to work or be available to work
between December 27, 1999, and January 7, 2000, and between February 22, 2000,
and March 7, 2000.
Because of the interconnected nature of potential Year 2000-related
problems, the Company recognizes that effective continuity planning must focus
on both internal and external operations. Therefore, the Company has been in
contact with and will work with federal, state and local governmental agencies,
as well as local organizations and other utilities as it completes its planning
effort.
The Company believes that its work will serve to reduce the risk that its
internal systems will fail for Year 2000 reasons. However, the continuity plan
cannot fully offset interrupted delivery to the Company's distribution system of
natural gas by the producers of natural gas and providers of interstate
transportation capacity or the impact on operations of failures of electric,
telecommunications and water services.
Independent Verification and Validation
The Company worked with external consultants to verify and validate the
Company's Year 2000 remediation and replacement strategies and results for both
business applications and embedded systems.
To verify and validate the Company's remediation efforts of its business
applications, the consultants reviewed all remediated business applications to
determine that the code was remediated correctly. The consultants have reviewed
the compliance statements received from the manufacturers of the critical and
important embedded system components and, where possible, developed strategies
and testing procedures to verify the compliance statements. The Company has
independently tested all of those critical and important embedded systems that
it has determined it can meaningfully test.
Financial Implications
From program inception through December 31, 1999, the Company expects to incur
non-recurring expenses of approximately $12 million for: 1) business-application
systems remediation; 2) embedded systems replacement; 3) end-user applications
remediation and replacement; 4) independent verification and validation; and 5)
certain costs associated with the replacement of certain existing business
systems. Over the same period, the Company expects to capitalize costs of
approximately $45 million to:1) replace certain existing business-application
software systems with new systems that will be Year 2000 operational and provide
additional management information; and 2) implement business continuity
initiatives identified by the Company.
The following table reflects the amounts charged to expense and capitalized
for the fiscal years ending September 30, 1999, 1998 and 1997 for
business-application systems remediation, embedded systems replacement, end-user
applications remediation and replacement, independent verification and
validation costs and business continuity initiatives.
<TABLE>
<CAPTION>
- -----------------------------------------------------------
(Millions) 1999 1998 1997 Total
- -----------------------------------------------------------
<S> <C> <C> <C> <C>
Expense $ 2 $ 1 $ 1 $ 4
Capital $ 3 $ 1 $ - $ 4
</TABLE>
The following table reflects the amounts charged to expense and capitalized
for the fiscal years ending September 30, 1999, 1998 and 1997 for
business-application software systems replacement.
<TABLE>
<CAPTION>
- -----------------------------------------------------------
(Millions) 1999 1998 1997 Total
- -----------------------------------------------------------
<S> <C> <C> <C> <C>
Expense $ 4 $ 4 $ - $ 8
Capital $21 $19 $ - $40
</TABLE>
Through September 30, 1999, the Company has incurred $12 million or 100% of
the estimated costs it expects to expense for its Year 2000 strategies through
December 31, 1999. Additionally, through September 30, 1999, the Company has
capitalized $44 million or 98% of the estimated costs it expected to incur to
replace certain existing business-application software systems and embedded
systems, and to implement business continuity initiatives through December 31,
1999. The Company expects to incur the remaining expenditures by December 31,
1999.
Each of the components of the Company's Year 2000 program is progressing,
and the Company believes it is taking all reasonable steps necessary to be able
to operate successfully through and beyond the turn of the century.
LABOR UNION NEGOTIATIONS
A contract with the Office and Professional Employees International Union Local
2 expires on March 31, 2000. That contract covers 384 office workers or 20% of
the Company's utility workforce. Also during fiscal year 2000, two contracts
expire with the Teamsters Local 96 (Teamsters) labor union. The first Teamsters
contract, which covers 791 field employees or 41% of the Company's utility
workforce, will expire on May 31, 2000. The second Teamsters contract, which
covers 27 field and office employees or 68% of Shenandoah's workforce, will
expire on July 31, 2000. In addition, two contracts expire with the
International Brotherhood of Electrical Workers Local 1900 (IBEW). The first
IBEW contract, which covers 21 production and maintenance workers or 1% of the
Company's utility workforce, expires on July 31, 2000. The second IBEW contract,
which covers 16 clerical employees or less than 1% of the Company's utility
workforce will expire on October 31, 2000.
At appropriate times during fiscal year 2000, the Company will enter into
good faith negotiations with each union with the intention of reaching a timely
and reasonable agreement with each union. In any event, the Company will have
contingency plans in place to ensure that its customers continue receiving safe
and reliable service.
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.
ACCOUNTING FOR REGULATORY MATTERS
As the industry continues to address competitive market issues, the
cost-of-service regulation used to compensate the Company for the cost of its
regulated operations will continue to evolve. Non-traditional ratemaking
initiatives and market-based pricing of products and services could have
additional financial implications for the Company.
The Company records the results of its regulated activities in accordance
with Statement of Financial Accounting Standards No. 71, Accounting for the
Effects of Certain Types of Regulation (SFAS No. 71). In certain circumstances,
SFAS No. 71 allows
1999 ANNUAL REPORT 29
<PAGE> 15
entities whose rates are determined by third-party regulators to defer costs as
"regulatory" assets in the balance sheet to the extent that these costs are
expected to be recovered in future rates.
As deregulation and competitive initiatives increasingly impact the Company,
however, SFAS No. 71 may no longer apply to all or part of the Company's
regulated operations in future years. Such Company operations would be subject
to the same accounting standards that apply to unregulated entities. In effect,
the Company could be required to write off certain regulatory assets that had
been deferred in prior period Consolidated Balance Sheets and charge these costs
to expenses at the time it is determined that the provisions of SFAS No. 71 no
longer apply. The composition of regulatory assets is shown in Note 1 to the
Consolidated Financial Statements. While it believes that SFAS No. 71 continues
to apply to its regulated operations, the changing nature of the Company's
business requires it to continually assess the impact of those changes on its
accounting policies.
ECONOMIC CONDITIONS
The Company and its subsidiaries operate in one of the fastest growing regions
in the nation. The continued prosperity of this region has allowed the Company
to expand its regulated delivery service customer base at more than twice the
national average during the past five years. In addition, this economy has
provided a robust market for the Company's subsidiaries to market the natural
gas commodity and other energy-related goods and services. A downturn in the
economy of the region in which the Company operates, which cannot be predicted
with accuracy, would likely adversely affect the Company's ability to grow its
regulated utility and other businesses at the same rate that they otherwise
could grow.
INFLATION
From time-to-time, the Company seeks approval for rate increases from its
regulatory commissions to help the Company cope with the effects of inflation on
its capital investment and returns. 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 costs of
its investment and earn a return thereon after replacement of the facilities
occurs.
MARKET RISK
Interest Rate Risk Exposure Related to Other Financial Instruments
At September 30, 1999, the Company had fixed-rate medium-term notes, and other
long-term debt aggregating $506.1 million in principal amount and having a fair
value of $487.9 million. Fair value is defined as the present value of the debt
securities' future cash flows discounted at interest rates that reflect market
conditions as of September 30, 1999. While these are fixed-rate instruments and,
therefore, do not expose the Company to the risk of earnings loss due to changes
in market interest rates, they are subject to changes in fair value as market
interest rates change. A total of $36 million, or approximately 7% of the
Company's outstanding medium-term notes have call options that enable the
Company to mitigate this market risk through the early redemption of those debt
instruments. Likewise, a total of $40 million, or 8% of the Company's
medium-term notes have put options that allow the holders of debt to mitigate
market risk through the early redemption of those debt instruments.
Using sensitivity analysis to measure this market risk exposure, the Company
estimates that the fair value of its long-term debt would increase by
approximately $22 million if interest rates were to decline by 10%. The Company
also estimates that the fair value of its long-term debt would decrease by
approximately $20 million if interest rates were to increase by 10%. In general,
such an increase or decrease in fair value would impact earnings and cash flows
only if the Company were to reacquire all or a portion of these instruments in
the open market prior to their maturity.
Price Risk Related to Gas Marketing Operations
The Company's subsidiary, WGEServices, performs the Company's gas marketing
activities. In the course of its business, WGEServices makes fixed-price sales
commitments to customers. WGEServices purchases the corresponding physical
supplies at fixed prices to lock in margins. WGEServices has exposure to changes
in gas prices related to the volumetric differences between the purchase
commitments and sales commitments. The risk associated with gas price
fluctuations is managed by closely matching purchases from suppliers with sales
commitments to customers. At September 30, 1999, WGEServices' open position was
not material to the Company's financial position or results of operations.
30 1999 ANNUAL REPORT
<PAGE> 16
WASHINGTON GAS LIGHT COMPANY
Consolidated Statements of Income
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Years Ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data)
<S> <C> <C> <C>
UTILITY OPERATIONS
OPERATING REVENUES (Note 1) $ 972,120 $ 1,040,618 $ 1,055,754
Less: Cost of gas (Note 1) 505,346 575,786 572,925
Revenue taxes 34,793 39,659 43,719
--------- ----------- -----------
NET REVENUES 431,981 425,173 439,110
--------- ----------- -----------
OTHER OPERATING EXPENSES
Operation 165,605 162,336 160,193
Maintenance 35,624 38,458 36,857
Depreciation and amortization (Note 1) 59,940 54,875 51,363
General taxes 28,125 29,519 27,558
Loss on sale of utility property (Note 2) 2,927 -- --
Income taxes (See Statements of Income Taxes and Note 6) 38,606 38,006 47,864
--------- ----------- -----------
330,827 323,194 323,835
--------- ----------- -----------
Utility Operating Income 101,154 101,979 115,275
========= =========== ===========
NON-UTILITY OPERATIONS
OPERATING REVENUES (Note 1)
Energy marketing 103,851 83,176 35,308
Heating, ventilating and air conditioning 31,154 13,815 2,653
Customer financing 3,779 3,206 3,373
Other non-utility 1,258 2,637 3,592
--------- ----------- -----------
140,042 102,834 44,926
--------- ----------- -----------
OTHER OPERATING EXPENSES (INCOME)
Non-utility operating expenses 132,505 100,537 42,618
Gains on sales of non-utility assets (Note 2) (2,979) (4,103) --
Income taxes (See Statements of Income Taxes and Note 6) 3,913 1,656 772
--------- ----------- -----------
133,439 98,090 43,390
--------- ----------- -----------
Non-Utility Operating Income 6,603 4,744 1,536
========= =========== ===========
TOTAL OPERATING INCOME 107,757 106,723 116,811
Other Income (Expenses)--Net (2,018) (375) (650)
--------- ----------- -----------
INCOME BEFORE INTEREST EXPENSE 105,739 106,348 116,161
--------- ----------- -----------
INTEREST EXPENSE
Interest on long-term debt 34,728 33,859 30,135
Other 2,243 3,860 4,007
--------- ----------- -----------
36,971 37,719 34,142
--------- ----------- -----------
NET INCOME 68,768 68,629 82,019
DIVIDENDS ON PREFERRED STOCK 1,331 1,331 1,331
--------- ----------- -----------
NET INCOME APPLICABLE TO COMMON STOCK $ 67,437 $ 67,298 $ 80,688
========= =========== ===========
AVERAGE COMMON SHARES OUTSTANDING 45,984 43,691 43,706
========= =========== ===========
EARNINGS PER AVERAGE COMMON SHARE--
BASIC & DILUTED (Note 5) $ 1.47 $ 1.54 $ 1.85
========= =========== ===========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
1999 ANNUAL REPORT 31
<PAGE> 17
WASHINGTON GAS LIGHT COMPANY
Consolidated Balance Sheets
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
September 30, 1999 1998
- ----------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Notes 1 and 4)
At original cost $ 2,114,071 $ 1,992,770
Accumulated depreciation and amortization (711,329) (673,269)
----------- -----------
1,402,742 1,319,501
----------- -----------
CURRENT ASSETS
Cash and cash equivalents 26,935 17,876
Accounts receivable 74,295 92,178
Gas costs due from customers (Note 1) 5,127 9,921
Allowance for doubtful accounts (6,626) (9,078)
Accrued utility revenues (Note 1) 17,141 16,304
Materials and supplies--principally at average cost 17,207 15,607
Storage gas--at cost (first-in, first-out) 80,481 76,338
Deferred income taxes (See Statements of Income Taxes and Note 6) 19,662 16,337
Other prepayments--principally taxes 14,888 13,864
Other 648 849
----------- -----------
249,758 250,196
----------- -----------
DEFERRED CHARGES AND OTHER ASSETS
Regulatory assets (Note 1) 84,278 95,352
Other 29,946 17,384
----------- -----------
114,224 112,736
----------- -----------
Total Assets $ 1,766,724 $ 1,682,433
=========== ===========
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Statements of Capitalization and Common
Shareholders' Equity)
Common shareholders' equity (Notes 5 and 8) $ 684,034 $ 607,755
Preferred stock 28,420 28,424
Long-term debt (Note 4) 506,084 428,641
----------- -----------
1,218,538 1,064,820
----------- -----------
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4) 1,431 64,106
Notes payable (Note 3) 113,067 124,943
Accounts payable 108,284 103,243
Wages payable 9,824 13,527
Dividends declared 14,507 13,485
Customer deposits and advance payments 15,853 19,454
Gas costs due to customers (Note 1) 11,321 5,671
Other 10,839 11,783
----------- -----------
285,126 356,212
----------- -----------
DEFERRED CREDITS
Unamortized investment tax credits 19,439 20,493
Deferred income taxes (See Statements of Income Taxes and Note 6) 156,495 145,519
Other (Notes 1, 7, 9 and 10) 87,126 95,389
----------- -----------
263,060 261,401
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10)
Total Capitalization and Liabilities $ 1,766,724 $ 1,682,433
=========== ===========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
32 1999 ANNUAL REPORT
<PAGE> 18
WASHINGTON GAS LIGHT COMPANY
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
Years Ended September 30, 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------------------
(Thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 68,768 $ 68,629 $ 82,019
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH
PROVIDED BY OPERATING ACTIVITIES
Depreciation and amortization (a) 66,247 60,291 56,886
Deferred income taxes--net 9,576 11,055 10,434
Amortization of investment tax credits (1,054) (934) (954)
Allowance for funds used during construction (1,642) (815) (411)
Other noncash credits--net, including gains and
losses on investing activities (2,719) (1,406) (1,444)
--------- --------- ---------
139,176 136,820 146,530
CHANGES IN ASSETS AND LIABILITIES--
NET OF ACQUISITIONS AND DISPOSITIONS (Note 2)
Accounts receivable and accrued utility revenues 13,922 (18,637) (18,351)
Gas costs due from/to customers--net 9,790 2,777 19,594
Storage gas (4,143) 4,734 2,757
Other prepayments--principally taxes (1,024) (1,894) (1,860)
Accounts payable 5,036 215 8,191
Wages payable (3,703) (63) (718)
Customer deposits and advance payments (3,505) 2,792 3,665
Deferred purchased gas costs--net 1,713 897 1,543
Other--net (4,535) (5,329) (6,086)
--------- --------- ---------
Net Cash Provided by Operating Activities 152,727 122,312 155,265
--------- --------- ---------
FINANCING ACTIVITIES
Common stock issued 64,266 5,279 312
Common stock repurchased -- (2,340) --
Long-term debt issued 80,823 72,166 125,812
Long-term debt retired (66,193) (34,537) (35,555)
Premium on long-term debt retired -- (493) (1,422)
Debt issuance costs (588) (494) (462)
Notes payable--net of effects from purchase of ACI (Note 2) (11,876) 55,698 (47,378)
Dividends on common and preferred stock (56,631) (53,228) (52,033)
--------- --------- ---------
Net Cash Provided by (Used in) Financing Activities 9,801 42,051 (10,726)
--------- --------- ---------
INVESTING ACTIVITIES
Capital expenditures (158,733) (158,874) (139,871)
Net proceeds from sales of:
West Virginia utility assets (Note 2) 12,559 -- --
Undeveloped land (Note 2) 4,073 -- --
Venture funds -- 1,619 --
Retail propane assets (Note 2) -- 4,050 --
ACI purchase--net of cash acquired (Note 2) -- (2,990) --
Investment in limited liability company (Note 2) (7,500) -- --
Other investing activities (3,868) -- 451
--------- --------- ---------
Net Cash Used in Investing Activities (153,469) (156,195) (139,420)
--------- --------- ---------
INCREASE IN CASH AND CASH EQUIVALENTS (b) 9,059 8,168 5,119
Cash and Cash Equivalents at Beginning of Year (b) 17,876 9,708 4,589
--------- --------- ---------
Cash and Cash Equivalents at End of Year (b) $ 26,935 $ 17,876 $ 9,708
========= ========= =========
(a) Includes amounts charged to other accounts
(b) Cash equivalents are highly liquid investments with a maturity of three
months or less when purchased.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Income taxes paid $ 29,519 $ 32,925 $ 37,494
Interest paid $ 38,685 $ 37,811 $ 33,662
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
1999 ANNUAL REPORT 33
<PAGE> 19
WASHINGTON GAS LIGHT COMPANY
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
September 30, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C>
COMMON SHAREHOLDERS' EQUITY (See Statements
of Common Shareholders' Equity and
Notes 5 and 8)
Common stock, $1 par value, authorized 80,000,000 shares,
issued 46,596,737 and 43,954,658 shares, respectively $ 46,597 $ 43,955
Paid-in capital 372,453 310,477
Retained earnings 269,430 258,315
Deferred compensation (1,190) (1,948)
Treasury stock--at cost, 123,393 and 115,205 shares,
respectively (3,256) (3,044)
----------- ----------
Total Common Shareholders' Equity 684,034 56.1% 607,755 57.1%
----------- --------- ---------- ---------
PREFERRED STOCK without par value, 1,500,000 shares authorized
Shares issued and outstanding
$4.80 series, 150,000 shares 15,000 15,000
$4.25 series, 70,600 shares 7,173 7,173
$5.00 series, 60,000 shares 6,000 6,000
$4.36 convertible series, 1,901 and 1,942 shares,
respectively 190 194
$4.60 convertible series, 569 shares 57 57
----------- ----------
Total Preferred Stock 28,420 2.4 28,424 2.7
----------- --------- ---------- ---------
LONG-TERM DEBT (Note 4)
First Mortgage Bonds
85/8% series due March 1, 2017 -- 4,000
83/4% series due July 1, 2019 -- 39,000
----------- ----------
-- 43,000
----------- ----------
Unsecured Medium-Term Notes
Due fiscal year 1999, 6.50% to 7.97% -- 21,700
Due fiscal year 2002, 6.90% to 7.56% 42,600 42,600
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 2009, 5.49% to 6.92% 75,000 --
Due fiscal year 2022, 6.94% to 6.95% 5,000 5,000
Due fiscal year 2023, 6.50% to 7.04% 50,000 50,000
Due fiscal year 2024, 6.95% 36,000 36,000
Due fiscal year 2025, 6.50% to 7.76% 40,000 40,000
Due fiscal year 2026, 6.15% 50,000 50,000
Due fiscal year 2027, 6.40% to 6.82% 125,000 125,000
Due fiscal year 2028, 6.57% to 6.85% 52,000 52,000
----------- ---------
500,700 447,400
---------- ---------
Other long-term debt 7,410 3,086
Unamortized premium (discount)--net (595) (739)
Less current maturities 1,431 64,106
----------- ----------
Total Long-Term Debt 506,084 41.5 428,641 40.2
----------- --------- ---------- ---------
Total Capitalization $ 1,218,538 100.0% $1,064,820 100.0%
=========== ========= ========== =========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
34 1999 ANNUAL REPORT
<PAGE> 20
WASHINGTON GAS LIGHT COMPANY
Consolidated Statements of Common Shareholders' Equity
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------------------
Common Stock Issued
------------------------ Paid-in Retained Deferred Treasury
Shares Amount Capital Earnings Compensation Stock Total
- ---------------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SEPTEMBER 30, 1996 43,726,853 $43,727 $ 304,691 $ 213,626 $(2,697) $ (538) $558,809
Net income -- -- -- 82,019 -- -- 82,019
Common stock expense -- -- (3) -- -- -- (3)
Deferred compensation -- -- 128 -- 675 (478) 325
Director compensation plan -- -- -- -- -- 33 33
Dividend reinvestment plan 7,861 8 166 -- -- -- 174
Employee savings plans 6,356 6 132 -- -- -- 138
Conversion of preferred stock 1,078 1 9 -- -- -- 10
Dividends declared:
Common stock
($1.170 per share) -- -- -- (51,139) -- -- (51,139)
Preferred stock -- -- -- (1,331) -- -- (1,331)
---------- ------- --------- --------- ------ ------- --------
BALANCE SEPTEMBER 30, 1997 43,742,148 43,742 305,123 243,175 (2,022) (983) 589,035
Net income -- -- -- 68,629 -- -- 68,629
Deferred compensation -- -- 255 -- 74 100 429
Director compensation plan -- -- 21 -- -- 82 103
Dividend reinvestment plan 188,812 189 4,500 -- -- -- 4,689
Employee savings plans 23,090 23 573 -- -- 97 693
Conversion of preferred stock 608 1 5 -- -- -- 6
Common stock repurchased -- -- -- -- -- (2,340) (2,340)
Dividends declared:
Common stock
($1.195 per share) -- -- -- (52,158) -- -- (52,158)
Preferred stock -- -- -- (1,331) -- -- (1,331)
---------- ------- --------- --------- ------ ------- --------
BALANCE SEPTEMBER 30, 1998 43,954,658 43,955 310,477 258,315 (1,948) (3,044) 607,755
Net income -- -- -- 68,768 -- -- 68,768
Common stock issued 2,300,000 2,300 55,344 -- -- -- 57,644
Common stock expense -- -- (1,953) -- -- -- (1,953)
Stock-based compensation -- -- 348 -- 758 (212) 894
Dividend reinvestment plan 273,464 274 6,620 -- -- -- 6,894
Employee savings plans 68,196 68 1,613 -- -- -- 1,681
Conversion of preferred stock 419 -- 4 -- -- -- 4
Dividends declared:
Common stock
($1.215 per share) -- -- -- (56,322) -- -- (56,322)
Preferred stock -- -- -- (1,331) -- -- (1,331)
---------- ------- --------- --------- ------ ------- --------
BALANCE SEPTEMBER 30, 1999 46,596,737 $46,597 $ 372,453 $ 269,430 $(1,190) $(3,256) $684,034
========== ======= ========= ========= ====== ======= ========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
1999 ANNUAL REPORT 35
<PAGE> 21
WASHINGTON GAS LIGHT COMPANY
Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
Years Ended September 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
(Dollars in Thousands)
<S> <C> <C> <C>
INCOME TAX EXPENSE (Note 6)
Charged to other utility operating expenses
Current $ 30,215 $ 28,226 $ 39,674
-------- -------- --------
Deferred
Accelerated depreciation 12,832 11,550 10,438
Losses/gains on reacquired debt (235) 556 233
Deferred gas costs (6,987) 473 (4,283)
Pensions and other employee benefit costs 1,912 879 1,472
Demand-side management costs (604) (414) 281
Inventory overheads 83 (962) (562)
Other 2,444 (1,368) 1,565
-------- -------- --------
Total Deferred Income Tax Expense 9,445 10,714 9,144
-------- -------- --------
Amortization of investment tax credits (1,054) (934) (954)
-------- -------- --------
38,606 38,006 47,864
-------- -------- --------
Charged to other non-utility operating expenses
Current 3,409 1,607 (6)
Deferred 504 49 778
-------- -------- --------
3,913 1,656 772
-------- -------- --------
Charged to other income (expenses)--net
Current (570) (148) (707)
Deferred (373) 292 512
-------- -------- --------
(943) 144 (195)
-------- -------- --------
Total Income Tax Expense $ 41,576 $ 39,806 $ 48,441
======== ======== ========
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
YEARS ENDED SEPTEMBER 30, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
RECONCILIATION BETWEEN THE STATUTORY FEDERAL
INCOME TAX RATE AND THE EFFECTIVE INCOME TAX RATE
Income tax at statutory federal income tax rate $38,620 35.00% $37,952 35.00% $45,661 35.00%
Increases (decreases) in tax resulting from
Accelerated depreciation less amount deferred 2,874 2.60 2,655 2.44 2,639 2.02
Amortization of investment tax credits (1,054) (0.95) (934) (0.86) (954) (0.73)
Cost of removal (879) (0.80) (566) (0.52) (588) (0.45)
State income taxes 1,721 1.56 1,840 1.70 2,036 1.56
Other items--net 294 0.27 (1,141) (1.05) (353) (0.27)
------- ----- ------- ----- ------- -----
Income Tax Expense and Effective Tax Rate $41,576 37.68% $39,806 36.71% $48,441 37.13%
======= ===== ======= ===== ======= =====
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------
September 30, 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
ACCUMULATED DEFERRED INCOME TAXES CURRENT NON-CURRENT Current Non-current
------- ----------- ------- -----------
<S> <C> <C> <C> <C>
Deferred Income Tax Assets
Pensions and other employee benefit costs $ 3,496 $ 2,992 $ 5,038 $ 3,384
Uncollectible accounts 1,046 -- 2,131 --
Inventory overheads 10,835 -- 10,921 --
Valuation allowance -- (943) -- (943)
Other 602 9,439 878 12,432
-------- --------- ------- ---------
Total Assets 15,979 11,488 18,968 14,873
-------- --------- ------- ---------
Deferred Income Tax Liabilities
Accelerated depreciation -- 143,310 -- 132,080
Losses/gains on reacquired debt -- 3,431 -- 3,669
Construction overheads -- 2,583 -- 2,748
Income taxes recoverable through future rates -- 13,236 -- 15,161
Deferred gas costs (3,683) 600 2,631 1,273
Demand-side management costs -- 7,081 -- 7,516
Other -- (2,258) -- (2,055)
-------- --------- ------- ---------
Total Liabilities (3,683) 167,983 2,631 160,392
-------- --------- ------- ---------
Net Accumulated Deferred Income
Tax Assets (Liabilities) $ 19,662 $(156,495) $16,337 $(145,519)
======== ========= ======= =========
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral part
of these consolidated statements.
36 1999 ANNUAL REPORT
<PAGE> 22
WASHINGTON GAS LIGHT COMPANY
Notes to Consolidated Financial Statements
1. ACCOUNTING POLICIES
NATURE OF OPERATIONS
Washington Gas Light Company (Washington Gas or the Company) is a public utility
that delivers and sells natural gas to customers in Washington, D.C. and parts
of Maryland and Virginia. The Company also has two wholly owned regulated
subsidiaries. One regulated subsidiary is a distribution company that serves the
northern Shenandoah Valley of Virginia. The other regulated subsidiary operates
an underground gas storage field on the Company's behalf. At September 30, 1999,
the Company and its distribution subsidiary served nearly 850,000 customer
meters. Deliveries to firm customers accounted for 71% of the Company's total
therm deliveries in fiscal year 1999. The Company is not dependent on one
customer or group of customers.
Most of the Company's unregulated operations are organized under a wholly
owned subsidiary, Washington Gas Resources Corp. (WGR). These unregulated
operations include energy marketing; heating, ventilating and air conditioning
(HVAC) services; and financing of certain gas appliances on behalf of customers.
CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
its subsidiaries. All significant intercompany transactions have been
eliminated. The Company's 50% investment in a limited liability corporation is
accounted for using the equity method. 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
In accordance with generally accepted accounting principles, management makes
certain estimates and assumptions regarding: 1) reported amounts of assets and
liabilities; 2) disclosure of contingent assets and liabilities at the date of
the financial statements; and 3) 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. These standards set specific generally accepted
accounting principles for companies whose rates are determined by independent
third-party regulators. Through the rate-setting process, regulators often make
decisions, the economics of which require companies to record costs as expenses
in different timeframes than may be appropriate for other unregulated
enterprises. When this situation occurs, the associated costs are deferred as
assets (regulatory assets) on the balance sheet and recorded as expenses on the
income statement as revenues are collected through customers' rates. Further,
regulators can also 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). At September 30, 1999 and
1998, the following regulatory assets and liabilities are reflected on the
Company's Consolidated Balance Sheets. These amounts will be recognized as
revenues and expenses in future periods when they are reflected in customers'
rates.
<TABLE>
<CAPTION>
ASSETS LIABILITIES
- -------------------------------------------------------------
(Millions) 1999 1998 1999 1998
- -------------------------------------------------------------
<S> <C> <C> <C> <C>
Income tax-related amounts
due from/to customers
(Note 6) $33.7 $ 36.2 $20.5 $21.1
Demand-side management
costs 19.3 21.4 -- 0.8
Other postretirement benefit
costs (Note 7) 11.3 11.8 -- --
Losses on reacquired debt 9.2 9.9 -- --
Gas costs due from customers 5.1 9.9 -- --
Gas costs due to customers -- -- 11.3 5.7
Environmental response costs
(Note 9) 6.9 8.5 -- --
Transition costs (Note 10) 0.8 3.7 -- --
Purchased gas costs 1.8 3.6 -- --
Refunds due to customers -- -- 2.2 1.4
Other 1.3 0.3 5.8 4.6
----- ------ ----- -----
Total $89.4 $105.3 $39.8 $33.6
===== ====== ===== =====
</TABLE>
As required by SFAS No. 71, the Company monitors the regulatory and
competitive environment in which it operates to determine whether the recovery
of its regulatory assets continues to be probable. If the Company were to
determine that recovery of these costs is not probable, it would write off the
asset against earnings. At present, the Company believes that the provisions of
SFAS No. 71 continue to apply to its regulated operations.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is stated at original cost, including labor,
materials, taxes and overhead. The Company capitalizes an Allowance for Funds
Used During Construction (AFUDC) as a component of construction overhead. The
Company capitalized AFUDC of $1,642,000, $815,000 and $411,000 in 1999, 1998 and
1997, respectively.
When depreciable utility plant and equipment is retired, the Company charges
the associated original cost, net of removal costs and salvage value to
accumulated depreciation. Maintenance and repairs are charged to operating
expenses, except those charges applicable to transportation and power-operated
equipment, which are allocated to operating expenses, construction and other
accounts based on the use of such equipment. Betterments and renewals are
capitalized. Depreciation applicable to the Company's gas plant in service is
calculated primarily on a straight-line remaining life basis. The composite
depreciation rate was 2.93% for 1999 and 1998 and 2.94% for 1997. The Company
periodically reviews the adequacy of its depreciation rates by considering
estimated remaining lives and other factors.
1999 ANNUAL REPORT 37
<PAGE> 23
REVENUE AND COST RECOGNITION
Included in Utility Operating Income
Revenues. For regulated deliveries of natural gas, the Company reads meters
and bills customers on a cycle basis. It accrues revenues for gas delivered,
but not yet billed.
Cost of Gas. The Company's jurisdictional tariffs contain gas cost
mechanisms that provide for the recovery of the invoice cost of gas applicable
to firm customers. Under these mechanisms, the Company periodically adjusts its
firm customers' rates to reflect increases and decreases in the invoice cost of
gas. Annually, the Company reconciles the differences between the total gas
costs collected from firm customers and the invoice cost of gas. Any excess or
deficiency is deferred and subsequently either recovered from, or refunded to,
customers over the following twelve-month period. The "Gas costs due from
customers" and "Gas costs due to customers" captions, reported in the
Consolidated Balance Sheets, reflect amounts related to these reconciliations.
Included in Non-Utility Operating Income
Energy Marketing. Washington Gas Energy Services (WGEServices), the
Company's gas marketing subsidiary, sells natural gas to residential, commercial
and industrial customers both inside and outside of the Company's traditional
service territory on an unregulated basis. Customer contracts provide for
WGEServices to bill customers based on: 1) quantities delivered to the entry
point of the local utility's distribution system; or 2) metered customer usage.
WGEServices recognizes revenues based on the amounts to be billed to customers,
plus an accrual for gas delivered but not yet billed.
WGEServices purchases gas for delivery to the entry point of the local
utility's distribution system; however, the amounts actually delivered to
customers may differ from the amounts purchased. For sales contracts based on
quantities delivered to the entry point of the local utility's distribution
system, WGEServices records gas costs based on the cost of gas delivered to the
local utility's distribution system. For sales contracts based on customers'
metered usage, WGEServices estimates gas costs using the margin inherent in the
contracts applied to the volumes used. Any differences between the invoiced gas
costs and the costs recorded as expenses are deferred until the full contract
volumes are delivered to customers.
Heating, Ventilating and Air Conditioning. The Company's unregulated
subsidiaries, American Combustion Industries, Inc. (ACI) and Washington Gas
Energy Systems (WGESystems), design and renovate mechanical HVAC systems. As
part of their businesses, ACI and WGESystems enter into construction contracts.
The income for contract terms of one or more years in duration is recognized
using the percentage-of-completion method. For all other contracts, these
subsidiaries use the completed contract method.
RATE REFUNDS DUE TO CUSTOMERS
The Company records a provision for rate refunds based on the difference between
the amount it collects in rates subject to refund and the amount it expects to
recover pending a final regulatory decision. At September 30, 1999, the Company
was not collecting any rates subject to refund.
REACQUISITION OF LONG-TERM DEBT
Gains or losses resulting from the reacquisition of long-term debt are deferred
for financial reporting purposes and amortized over future periods as
adjustments to interest expense in accordance with established regulatory
practice. No long-term reacquisition gains or losses were realized during fiscal
year 1999. However, the Company realized and deferred losses of $0.5 million and
$1.7 million in 1998 and 1997, respectively. For income tax purposes, the
Company recognizes these gains and losses when the debt is legally retired.
DERIVATIVE ACTIVITIES
The Company's derivative activities currently encompass hedge transactions
designed to manage interest rate risk associated with planned issuances of
Medium-Term Notes (MTNs). The Company's interest costs associated with issuing
MTNs reflect spreads over comparable maturity U.S. Treasury yields that take
into account credit quality, maturity and other factors. During fiscal years
1999 and 1998, in order to lock in the U.S. Treasury yield for planned issuances
of MTNs, the Company entered into fixed-price agreements for the forward sale of
U.S. Treasury securities. The Company accounts for these forward sales as hedges
of anticipated transactions in accordance with Statement of Financial Accounting
Standards No. 80, Accounting for Futures Contracts (SFAS No. 80). The Company
settles hedge transactions when it issues MTNs and recognizes the related gains
and losses as MTN issuance costs. Should the Company terminate a hedge agreement
without issuing MTNs, the gain or loss would be immediately recognized in
earnings. See Note 4 for additional discussion of interest rate hedges.
NEW ACCOUNTING STANDARDS
Beginning with the first quarter of fiscal year 2001, the Company is scheduled
to adopt Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities (SFAS No. 133), as amended. That
statement requires that derivative instruments, including certain derivative
instruments embedded in other contracts, be recorded at fair value as either an
asset or a liability. Changes in the derivative's fair value must be recognized
in earnings, unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. Further,
companies must formally document, designate and assess the effectiveness of
transactions that receive hedge accounting. The Company is assessing the impact
of SFAS No. 133 on its financial condition and results of operations and is
unable to predict its impact at this time.
In November 1998, the Emerging Issues Task Force (EITF) of the Financial
Accounting Standards Board reached a consensus related to EITF Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. That consensus requires that specific energy trading contracts must
be presented at fair value with periodic gains and losses included in earnings.
At the present time, EITF Issue No. 98-10 is not applicable to the Company's
operations.
38 1999 ANNUAL REPORT
<PAGE> 24
2. ACQUISITIONS AND DISPOSITIONS
HEATING, VENTILATING AND AIR CONDITIONING SUBSIDIARY
In March 1998, WGR acquired a 100% interest in American Combustion, Inc. and
American Combustion Industries, Inc. The Company purchased these companies with
$3.0 million in cash and the issuance of a $2.0 million promissory note, which
is being repaid in monthly installments over two years ending March 2000. The
Company accounted for the acquisition using the purchase method of accounting
and recognized the excess of the purchase price over net assets acquired as
goodwill. The Company is amortizing this goodwill on a straight-line basis over
fifteen years. The Consolidated Financial Statements include these subsidiaries'
accounts from the acquisition date. On March 30, 1999, American Combustion, Inc.
was merged into American Combustion Industries, Inc. (ACI).
SHENANDOAH GAS OPERATIONS
Effective July 1, 1999, the Company's regulated distribution subsidiary,
Shenandoah Gas Company (Shenandoah), finalized the sale of its natural gas
utility assets located in West Virginia. The Company recorded a non-recurring
$2.9 million pre-tax loss ($1.9 million after-tax or $0.04 per average common
share) related to the sale.
The purchaser is serving Shenandoah's former 3,800 natural gas customers in
Martinsburg and Berkeley County, West Virginia. To ensure continued natural gas
service in the Eastern Panhandle of West Virginia, Shenandoah provides natural
gas transportation service to the purchaser. Shenandoah continues to provide
natural gas utility service to its nearly 11,000 customers in the northern
Shenandoah Valley of Virginia.
During fiscal years 1999 and 1998, Shenandoah's natural gas therm deliveries
in West Virginia represented less than 2% of the Company's consolidated natural
gas therm deliveries and less than 1% of associated consolidated revenues.
Shenandoah's West Virginia operations did not contribute a material amount to
the Company's net income in either 1999 or 1998.
On September 29, 1999, the Company's Board of Directors authorized a merger
of Shenandoah into Washington Gas to form a single corporation for the regulated
distribution of natural gas. An application was filed on October 5, 1999 with
the State Corporation Commission of Virginia (SCC of VA) to begin the merger
process.
LIMITED LIABILITY COMPANY
In August 1999, the Company and Thayer Capital Partners (Thayer) formed Primary
Investors, LLC (Primary Investors), a limited liability company. Primary
Investors, through its wholly owned subsidiary, Primary Service Group, LLC
(PSG), will focus on investment opportunities in after-market products and
services for the heating, ventilating and air conditioning industry. PSG will
sell, install, repair and maintain HVAC equipment in the residential and light
commercial markets. Initially, PSG is entering this business by acquiring and
expanding companies that currently provide HVAC-oriented products and services
in the District of Columbia, and parts of Maryland and Virginia.
The Company and Thayer each owns 50% of Primary Investors and an equal
number of representatives from the Company and Thayer serve on Primary
Investors' Board of Directors. As a co-investor, the Company has initially
committed to invest up to $25 million of equity capital in Primary Investors.
The Company invested $7.5 million in Primary Investors through September 30,
1999. The results of Primary Investors since its formation are reflected in the
Consolidated Financial Statements using the equity method of accounting and were
immaterial.
SALE OF REAL ESTATE
In July 1999, the Company's unregulated subsidiary, Brandywood Estates, Inc.,
sold approximately 1,000 acres of undeveloped land in Prince George's County,
Maryland. As a result of this transaction, the Company recognized a
non-recurring pre-tax gain of $3.0 million ($1.8 million after-tax or $0.04 per
average common share) during fiscal year 1999.
RETAIL PROPANE ASSETS
In May 1998, the Company sold all of its retail propane assets for $4.1 million,
recognizing a pre-tax gain of $2.5 million ($1.6 million after-tax). In fiscal
year 1997, net income from propane sales amounted to less than one-half of 1% of
the Company's total net income.
3. SHORT-TERM DEBT
The Company satisfies its short-term financing requirements through the sale of
commercial paper or bank borrowings. The Company maintains credit lines and a
revolving credit agreement to support its outstanding commercial paper and to
permit short-term borrowing flexibility. The table below summarizes the major
terms of financing agreements of the Company at September 30, 1999.
<TABLE>
<CAPTION>
Commitment or
Description/ Facility Fees
Amount of Credit per Annum Expiration Date
- -------------------------------------------------------------------
Permanent Lines of Credit
<S> <C> <C>
$ 5 million 0.07% June 28, 2000
$ 10 million 0.04% June 30, 2000
$ 10 million 0.07% June 30, 2000
Seasonal Lines of Credit
$ 5 million 0.07% June 30, 2000
if activated
$ 10 million 0.07% April 30, 2000
if activated
Revolving Credit Agreement
$160 million 0.06% May 21, 2000
$ 5 million 0.15% January 31, 2000
$ 5 million None March 31, 2000
</TABLE>
At September 30, 1999, the permanent and seasonal lines of credit were
unused. The seasonal lines of credit became available on October 1, 1999 and are
available during most of the heating season.
A group of banks provides the regulated utility segment with a $160 million
short-term revolving line of credit. The Company can reduce the amount of the
commitment at its option. Under the agreement, the banks apply the facility fees
to the daily average amount of the commitment outstanding. The agreement expires
on May 21, 2000, but allows the Company
1999 ANNUAL REPORT 39
<PAGE> 25
one extension by mutual agreement, with a termination date of May 19, 2001. At
September 30, 1999, this revolving credit agreement was unused.
Collectively, the borrowing options under the permanent and seasonal lines
of credit and the $160 million revolving credit agreement discussed in the prior
paragraph include the prime lending rate, rates based on certificates of deposit
and London Interbank Offered Rates (LIBOR).
Two Company subsidiaries, WGEServices and ACI, each have a $5 million
revolving line of credit, which expire on January 31, 2000 and March 31, 2000,
respectively. Both of these revolving lines of credit are based on LIBOR rates,
plus a fixed-percent increment. WGEServices' line of credit was unused at
September 30, 1999. At September 30, 1999, ACI had $2.4 million of debt
outstanding under its revolving credit agreement at a weighted-average interest
rate of 8.13%.
At September 30, 1999, the Company and its subsidiaries had $113.1 million
in short-term debt outstanding, excluding current maturities of long-term debt,
at a weighted-average cost of 5.57%. At September 30, 1998, the Company had
$124.9 million in short-term debt outstanding, excluding current maturities of
long-term debt, at a weighted-average cost of 5.71%.
4. LONG-TERM DEBT
FIRST MORTGAGE BONDS
The Company's Mortgage dated January 1, 1933 (Mortgage), as supplemented and
amended, securing any First Mortgage Bonds (FMBs) issued by the Company,
constitutes a direct lien on substantially all property and franchises owned by
the Company, other than expressly excepted property. At September 30, 1998, the
Company had $43.0 million of FMBs outstanding. These FMBs were retired during
fiscal year 1999 and the Company has no debt outstanding under the Mortgage at
September 30, 1999.
UNSECURED MEDIUM-TERM NOTES
The Company issues unsecured MTNs whose terms are individually set as to
interest rate, maturity and any call or put option. These notes can have
maturity dates of one or more years from date of issuance. The Company cannot
issue any FMBs under its Mortgage without making effective provision whereby any
outstanding MTNs shall be secured equally and ratably with any and all other
obligations and indebtedness secured by the Mortgage. At September 30, 1999 and
1998, the weighted-average interest rate on all outstanding MTNs was 6.70% and
6.77%, respectively.
As summarized in the following table, the Company issued $75 million of MTNs
in fiscal year 1999. As indicated below, the terms of certain MTNs provide the
Company with an option to redeem the MTNs at any time, in whole or in part, at
the greater of: 1) par value; or 2) the price implied in the yield to maturity,
plus 15 basis points of a comparable-maturity U.S. Treasury security. Both MTNs
that were issued during fiscal year 1999 will mature in fiscal year 2009.
<TABLE>
<CAPTION>
Amount of Redeemable
Date Issuance Coupon Prior To
Issued (Millions) Rate Maturity
- ------------------------------------------------------------
<S> <C> <C> <C>
October 1998 $25 5.49% No
July 1999 50 6.92% Yes
----
Total $75
====
</TABLE>
INTEREST RATE HEDGES
At September 30, 1999, the Company had no interest rate hedge agreements
outstanding in connection with planned issuances of MTNs. However, at September
30, 1998, the Company had two interest rate hedge agreements outstanding. As
described in Note 1, the Company accounted for these agreements as hedges of
anticipated transactions in accordance with SFAS No. 80.
On June 15, 1998, in order to lock in the Treasury yield for the anticipated
issuance of $25 million of 10-year MTNs in November 1998, the Company entered
into an agreement that reflected the forward sale of $24.9 million of 10-year
U.S. Treasury notes at a fixed price to be paid on November 3, 1998. The Company
unwound its hedge position concurrent with the issuance of $25 million of MTNs
in October 1998. The notes have a 10-year nominal life and a coupon rate of
5.49%. The $2.1 million that the Company paid associated with the settlement of
this hedge agreement was recorded to unamortized debt issuance costs in October
1998 and is being amortized over the life of the MTNs. The effective cost of the
debt was 6.74%.
On September 2, 1998, in order to lock in the Treasury yield for an
anticipated $39 million MTN issuance related to the refunding of $39 million of
8 3/4% FMBs on July 1, 1999, the Company entered into an agreement that
reflected the forward sale of $40 million of 10-year U.S. Treasury notes at a
fixed price to be paid on July 1, 1999. The Company unwound its hedge position
concurrent with the issuance of $50 million of MTNs in early July 1999. The
Company received $2.0 million associated with the settlement of this hedge
agreement, which it recorded as a reduction to unamortized debt issuance cost.
This benefit is being amortized over the life of the MTNs. The effective cost
of the debt was 6.31%.
LONG-TERM DEBT MATURITIES
The amount of maturities on long-term debt for the ensuing five-year period at
September 30, 1999 is $1.4 million in 2000, $1.7 million in 2001, $49.0 million
in 2002, $36.5 million in 2003, and $40.9 million in 2004.
5. COMMON STOCK AND EARNINGS PER SHARE
SALE OF COMMON STOCK
On November 12, 1998, the Company publicly sold 2 million shares of common stock
at $25.0625 per share. On November 18, 1998, the underwriters involved in the
offering exercised their option to purchase 300,000 additional shares from the
Company at the same price per share. Net proceeds of $55.7 million from the sale
are being used for general corporate purposes, including capital expenditures.
COMMON STOCK OUTSTANDING
Shares of common stock outstanding, net of treasury stock, were 46,473,344 at
September 30, 1999; 43,839,453 at September 30, 1998; and 43,699,516 at
September 30, 1997.
COMMON STOCK RESERVES
At September 30, 1999, there were 2,071,116 authorized, but unissued, shares of
common stock reserved as follows:
40 1999 ANNUAL REPORT
<PAGE> 26
<TABLE>
<S> <C>
Incentive Compensation Plans 1,391,050
Dividend Reinvestment and Common
Stock Purchase Plan 473,478
Employee Savings Plans 137,196
Directors' Stock Compensation Plan 27,483
Conversion of Convertible Preferred Stock 41,909
----------
Total Common Stock Reserves 2,071,116
==========
</TABLE>
The Company's stock-based incentive compensation plans are discussed in
Note 8.
EARNINGS PER SHARE
Basic earnings per share (EPS) is computed by dividing net income applicable to
common stock by the weighted-average number of common shares outstanding during
the period. Diluted EPS assumes the conversion of convertible preferred stock
and the issuance of common shares pursuant to stock-based compensation plans at
the beginning of the applicable fiscal year. The following table shows the
computation of the Company's basic and diluted EPS for 1999, 1998 and 1997,
respectively.
<TABLE>
<CAPTION>
Net Per Share
(Thousands, Except Per Share Data) Income Shares Amount
- -----------------------------------------------------------------------------------------------------------------------
For the Year Ended September 30, 1999
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
BASIC EPS:
Net Income Applicable to Common Stock $67,437 45,984 $1.47
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible Preferred Stock, Assuming
Conversion on October 1, 1998 11 26
Stock-Based Compensation Plans -- 13
-------- -------
DILUTED EPS:
Net Income Applicable to Common Stock Plus Assumed Conversions $67,448 46,023 $1.47
======== ======= ======
- -----------------------------------------------------------------------------------------------------------------------
For the Year Ended September 30, 1998
- -----------------------------------------------------------------------------------------------------------------------
BASIC EPS:
Net Income Applicable to Common Stock $67,298 43,691 $1.54
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible Preferred Stock, Assuming
Conversion on October 1, 1997 11 26
-------- -------
DILUTED EPS:
Net Income Applicable to Common Stock Plus Assumed Conversions $67,309 43,717 $1.54
======== ======= ======
- -----------------------------------------------------------------------------------------------------------------------
For the Year Ended September 30, 1997
- -----------------------------------------------------------------------------------------------------------------------
BASIC EPS:
Net Income Applicable to Common Stock $80,688 43,706 $1.85
Effect of Dilutive Securities:
$4.60 and $4.36 Convertible Preferred Stock, Assuming
Conversion on October 1, 1996 11 27
-------- -------
DILUTED EPS:
Net Income Applicable to Common Stock Plus Assumed Conversions $80,699 43,733 $1.85
======== ======= ======
</TABLE>
6. INCOME TAXES
The Company and its subsidiaries file a consolidated Federal income tax return.
The Company's Federal income tax returns for all years through September 30,
1996 have been reviewed and closed or closed without review by the Internal
Revenue Service.
The Company is amortizing investment tax credits as credits to income over
the estimated service lives of the related properties.
The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS No.
109). Under SFAS No. 109, deferred income taxes are recognized for all temporary
differences between the financial statement and tax basis of assets and
liabilities at currently enacted income tax rates.
SFAS No. 109 requires recognition of the additional deferred income tax
assets and liabilities for temporary differences for which deferred income tax
treatment is 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 payable to customers through the ratemaking process. The Company's regulatory
assets and liabilities associated with income taxes due from and to customers at
September 30, 1999 and 1998 are shown in Note 1. Amounts applicable to income
taxes due from and due to customers primarily represent differences between the
book and tax bases of net utility plant in service.
The Consolidated Statements of Income Taxes on page 36 provide the
following: 1) the components of income tax expense;
1999 ANNUAL REPORT 41
<PAGE> 27
2) a reconciliation between the statutory Federal income tax rate and the
effective income tax rate; and 3) the components of accumulated deferred income
tax assets and liabilities at September 30, 1999 and 1998.
7. POSTEMPLOYMENT BENEFITS
The Company and its subsidiaries offer defined-contribution savings plans to
eligible employees, covering all employee groups. Designed to provide employees
with an incentive to save and invest regularly, these plans allow participants
to defer 1% to 14% of their salaries for investment in various alternatives. The
employer contribution, which varies by plan, ranges from 25% of the first 1.25%,
to 100% of the first 4%, of employees' pre-tax contributions. For plans that
allow employees to make after-tax contributions, the employer contribution
equals 100% of the first 2% and 50% of the next 2% of employees' after-tax
contributions. During 1999, 1998 and 1997, the Company contributed $2.2 million
per year to the plans.
The Company maintains a qualified, trusteed, noncontributory defined benefit
pension plan covering all active and vested former employees of the Company and
its utility subsidiaries. Executive officers also participate in a nonfunded
supplemental executive retirement plan (SERP). A trust has been established for
the future funding of the SERP liability. To the extent allowable by law, the
Company funds pension costs accrued for the qualified plan.
The Company provides certain healthcare 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.
The following is certain information about the Company's postemployment
benefits:
<TABLE>
<CAPTION>
Pension Benefits Health & Life Benefits
- -----------------------------------------------------------------------------------------------------
(Millions) 1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Years Ended September 30,
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 495.4 $ 428.6 $ 224.6 $ 198.1
Service cost 9.7 9.3 5.0 4.5
Interest cost 31.5 32.2 14.3 14.5
Amendment -- 12.8 -- --
Actuarial (gain) loss (46.8) 38.3 (28.0) 15.6
Benefits paid (30.0) (25.8) (9.4) (8.1)
------- ------- ------- -------
Benefit obligation at end of year 459.8 495.4 206.5 224.6
------- ------- ------- -------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year 631.2 591.4 83.5 66.4
Actual return on plan assets 89.8 67.0 2.9 4.2
Company contributions 3.9 0.8 22.0 21.0
Expenses (2.0) (2.2) -- --
Benefits paid (30.0) (25.8) (9.4) (8.1)
------- ------- ------- -------
Fair value of plan assets at end of year 692.9 631.2 99.0 83.5
------- ------- ------- -------
FUNDED STATUS
Funded status of the plan 233.1 135.8 (107.5) (141.1)
Unrecognized actuarial net gains (263.6) (171.0) (47.5) (23.6)
Unrecognized prior service cost 24.4 26.5 -- --
Unrecognized transition (assets) obligation (5.3) (7.8) 133.5 143.0
------- ------- ------- -------
Accrued benefit cost $ (11.4) $ (16.5) $ (21.5) $ (21.7)
======= ======= ======= =======
TOTAL AMOUNTS RECOGNIZED IN BALANCE SHEET
Accrued benefit liability $ (16.1) $ (21.9) $ (21.5) $ (21.7)
Intangible asset 4.7 5.4 -- --
------- ------- ------- -------
Total recognized $ (11.4) $ (16.5) $ (21.5) $ (21.7)
======= ======= ======= =======
<CAPTION>
Pension Benefits Health & Life Benefits
- -----------------------------------------------------------------------------------------------------
Assumptions as of September 30, 1999 1998 1999 1998
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Discount rate 7.50% 6.50% 7.50% 6.50%
Expected return on plan assets 8.25% 8.25% 8.25% 8.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
</TABLE>
42 1999 ANNUAL REPORT
<PAGE> 28
The assumed healthcare cost trend rates for fiscal year 2000 for Medicare
eligible and non-Medicare eligible retirees are 6.50% and 7.58%, respectively;
these rates are expected to decrease gradually to 5.50% and 5.75%, respectively,
in 2003 and remain at those levels thereafter.
<TABLE>
<CAPTION>
Pension Benefits Health & Life Benefits
- ------------------------------------------------------------------------------------------------------------------------
(Millions) 1999 1998 1997 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 9.7 $ 9.3 $ 7.8 $ 5.0 $ 4.5 $ 4.6
Interest cost 31.5 32.2 28.7 14.3 14.5 15.1
Expected return on plan assets (41.6) (38.7) (35.7) (6.3) (5.1) (3.8)
Recognized prior service cost 2.1 2.1 1.0 -- -- --
Recognized actuarial gain (0.4) (2.3) (3.8) (0.7) (2.0) (1.2)
Amortization of transition obligation (2.5) (2.4) (2.4) 9.5 9.6 9.5
------ ------ ------ ----- ----- -----
Net periodic benefit cost (1.2) 0.2 (4.4) 21.8 21.5 24.2
Amount capitalized as construction cost 0.8 0.4 1.2 (4.4) (4.2) (4.8)
Amount deferred as a regulatory asset--net 0.9 0.6 1.4 0.5 1.5 (0.7)
------ ------ ------ ----- ----- -----
Amount charged to expense $ 0.5 $ 1.2 $ (1.8) $17.9 $18.8 $18.7
====== ====== ====== ===== ===== =====
</TABLE>
The projected benefit obligation and accumulated benefit obligation for the
Company's nonfunded supplemental executive retirement plan, which has
accumulated benefits in excess of plan assets, were $17.0 million and $14.9
million, respectively, as of September 30, 1999 and $19.4 million and $17.0
million, respectively, as of September 30, 1998. The plan has no assets.
The assumed healthcare trend rate has a significant effect on the amounts
reported for the healthcare plans. A one-percentage-point change in the assumed
healthcare trend rate would have the following effects:
<TABLE>
<CAPTION>
1-Percentage- 1-Percentage-
(Millions) Point Increase Point Decrease
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Increase (decrease) total service and interest cost components $ 2.4 $ (2.1)
Increase (decrease) postretirement obligation $27.0 $(23.5)
</TABLE>
Almost all of the estimated postretirement benefit costs and the transition
obligation are applicable to the Company's regulated activities. The Public
Service Commission of the District of Columbia (PSC of DC) granted the Company's
recovery of postretirement benefit costs determined in accordance with generally
accepted accounting principles (GAAP) through a five-year phase-in plan that
ended September 30, 1998. The Company deferred the difference generated during
the phase-in period as a regulatory asset. Effective October 1, 1998, the PSC of
DC granted the Company full recovery of costs determined under GAAP plus a
fifteen-year amortization of the regulatory asset established during the
phase-in period. In an order dated September 28, 1995, the SCC of VA issued a
generic order that allowed the Company to recover most costs determined under
GAAP in rates over twenty years. The SCC of VA, however, set a forty-year
recovery period of the transition obligation. As prescribed by GAAP, the Company
is amortizing these costs over a twenty-year period. 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.
Postretirement benefit costs deferred as a regulatory asset at September 30,
1999 were $11.3 million. The Company expects these costs will be recovered over
a twenty-year period that began October 1, 1993.
The Company is required by each regulatory commission having jurisdiction
over it 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 1999, 1998 and 1997. To the extent the income in the trusts
is taxable, the income tax rate associated with the taxable portion of this
return is assumed to be 39.6%.
8. STOCK-BASED COMPENSATION
The Company periodically provides compensation in the form of common stock to
certain employees and Company directors. The stock-based compensation plans are
designed to promote the Company's long-term success by attracting, recruiting
and retaining key employees, and giving certain employees and Company directors
an ownership interest in the Company, thereby promoting a closer identity of
interests between such persons and the Company's stockholders. Under Statement
of Financial Accounting Standards No. 123, Accounting for Stock-based
Compensation(SFAS No. 123), the Company applies Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees (APB No. 25) and
related interpretations in accounting for its stock-based compensation plans.
The Company's stock-based compensation arrangements are discussed more fully
below.
STOCK-BASED COMPENSATION FOR KEY EMPLOYEES
The Company has granted restricted stock to participants in the Long-Term
Incentive Compensation Plan (LTICP) and to
1999 ANNUAL REPORT 43
<PAGE> 29
certain other employees. These shares are subject to restrictions on vesting,
sale and transferability. Restrictions lapse with the passage of time. The
Company holds the certificates for restricted stock until the employees are
fully vested. In the interim, the participants receive full dividend and voting
rights.
The LTICP expired on June 27, 1999 and was replaced with the 1999 Incentive
Compensation Plan (1999 Plan). Approved by the stockholders in February 1999,
the 1999 Plan allows the Company to grant up to 1,000,000 shares of common stock
to officers and key employees. Under the 1999 Plan, the Company may impose
performance goals, which if unattained, may result in participants forfeiting
all or part of the award.
On March 31, 1999, the Company granted 45,702 performance shares under the
1999 Plan. A total of 15,802 performance shares will potentially vest after 18
months and 29,900 shares will potentially vest after 30 months. At the end of
the vesting periods, the ultimate amount of performance shares issued to the
recipients will be adjusted upward or downward based on the Company's total
shareholder return relative to a selected peer company group.
In accordance with APB No. 25, the Company recognizes estimated compensation
expenses for restricted stock and performance shares ratably over the vesting
periods of the shares. The following table discloses the number of shares
granted and outstanding under the LTICP and 1999 Plan, as well as the associated
weighted-average fair value at grant dates and compensation expense recognized
during each reporting period.
<TABLE>
<CAPTION>
1999
LTICP Plan
- --------------------------------------------------------------
1999 1998 1997 1999
- --------------------------------------------------------------
<S> <C> <C> <C> <C>
Shares granted -- 32,350 17,850 45,702
Shares out-
standing at
end of period 86,510 116,380 139,915 45,702
Weighted-
average fair
value on
grant dates $ -- $ 27.21 $ 22.16 $ 22.63
Compensation
expense
recognized $758,000 $955,000 $952,000 $303,000
</TABLE>
On March 31, 1999, the Company also granted 99,465 nonqualified stock
options under the 1999 Plan, all of which were outstanding at September 30,
1999. All stock options granted in 1999 had an exercise price of $22.63, which
was equal to the fair market value on the date of grant. No compensation cost
has been recognized in the Consolidated Statements of Income for the stock
option grants. These stock options vest three years after the date of the grant
and expire on the tenth anniversary of the grant date. The fair market value of
the stock options was $3.85 on the grant date, which was estimated using the
Black-Scholes option-pricing model with the following assumptions used for the
grants made in 1999: 1) dividend yield of 4.8%; 2) expected stock-price
volatility of 24%; 3) risk-free interest rate of 6.3%; and 4) expected option
life of three years. No options expired, were exercised or were forfeited during
fiscal year 1999.
If compensation expense for the Company's stock option grants had been
determined based on the fair value at the grant dates for those awards,
consistent with the method prescribed by SFAS No. 123, the Company's net income
and earnings per share would have been reduced to the amounts shown in the
following pro forma table.
<TABLE>
<CAPTION>
Year Ended
September 30, 1999 As reported Pro forma
- --------------------------------------------------------------------
<S> <C> <C>
Net income ($000) $68,768 $68,727
Net income applicable to
common stock ($000) $67,437 $67,396
Earnings per average common share:
Basic $ 1.47 $ 1.47
Diluted $ 1.47 $ 1.46
</TABLE>
Since nonqualified options were not granted before 1999, there is no pro
forma effect on net income for 1998 and 1997.
STOCK GRANTS TO DIRECTORS
Non-employee directors receive a portion of their annual retainer fee in the
form of common stock through the Directors' Stock Compensation Plan. Shares
granted to directors totaled 5,600, 3,725 and 1,589 in 1999, 1998 and 1997,
respectively. For those periods, the fair value of the stock on the grant dates
was $25.49, $27.31 and $21.94, respectively. Shares awarded to the participants:
1) are immediately vested and nonforfeitable; 2) may be sold or transferred; and
3) have voting and dividend rights.
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 timeframe to control
environmental impacts.
Estimates of liabilities for environmental response costs are difficult to
determine with precision because of the factors that can affect their ultimate
level. These factors include, but are not limited to: 1) the complexity of the
site; 2) changes in environmental laws and regulations at the federal, state and
local levels; 3) the number of regulatory agencies or other parties involved; 4)
new technology that renders previous technology obsolete or experience with
existing technology that proves ineffective; 5) the ultimate selection of
technology; 6) the level of remediation required; and 7) variations between the
estimated number of years that must be devoted to respond to an environmentally
contaminated site as compared to the actual number of years required.
The Company has identified up to ten sites where the Company, its
subsidiaries, or their predecessors may have operated manufactured gas plants
(MGPs). The Company last used any such plant in 1984. In connection with these
operations, the Company is aware that certain by-products of the gas
manufacturing process are present at or near some former sites and may be
present at others.
At one of the former MGP sites, studies show the presence of coal tar under
the site and an adjoining property. The Company's risk assessment study
performed on the site shows that there is no unacceptable risk to human health
or the environment. The Company has taken steps to control the movement of
contaminants into an adjacent river by installing a water treatment system that
removes and treats contaminated groundwater
44 1999 ANNUAL REPORT
<PAGE> 30
at the site. The Company completed a feasibility study of remedial alternatives
in fiscal year 1998 and submitted its recommended remedial action plan to the
appropriate governmental agencies. Both the U.S. Environmental Protection Agency
and the local environmental agency have approved the Company's remediation plan.
At a second former MGP site, tests identified tar products under the
property. However, a risk assessment showed that there was no unacceptable risk
to human health or the environment. The Company designed and installed a
state-approved treatment and recovery system to recover free tar and continues
to recover minimal volumes of tar products from pumping. The Company will
continue to pump tar, monitor the site and provide annual activity reports to
the state's Department of the Environment.
At a third former MGP site, initial studies determined that tar products are
present under the property, but a risk assessment showed that there was no
unacceptable risk to human health or the environment. The Company completed and
submitted a remedial investigation/feasibility study to the appropriate state
regulatory agency. The Company has yet to receive any response from the state
regarding its submission, but continues to monitor the site.
At a fourth former MGP site and on an adjacent parcel of land, the Company
has applied for the state voluntary closure program, which will require some
additional study to determine ultimate resolution.
At a fifth former MGP site, a treatment system for contaminated groundwater
has been operating for nine years. The Company believes, at this time, that no
additional action other than water treatment will be necessary.
At a sixth former MGP site, a local government has notified the Company
about the detection of a substance in an adjacent river that may be related to
this site. This same local government owned and operated the MGP for the
majority of the life of the plant. The local government sold the MGP to a
company, which was subsequently merged into Washington Gas. Washington Gas
retired the MGP many years ago. In addition, the Company is aware that the local
government has had communications about this condition with federal
environmental authorities. At this time, the extent and nature of the
contamination and the Company's related obligation, if any, to perform
remediation cannot be determined. The Company hopes to have discussions with the
local government and may participate in studies to assess the extent and nature
of contamination as well as the need for appropriate remediation.
Through September 30, 1999, the Company had paid $11.0 million for
environmental response costs. The Company has recorded a liability of $8.7
million on an undiscounted basis at September 30, 1999 related to future
environmental response costs. This estimate is primarily composed of the minimum
liabilities associated with a range of environmental response costs expected to
be incurred at five of the six sites described above. The Company estimates the
maximum liability associated with these sites to be approximately $20.3 million
at September 30, 1999. 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
(2 to 25 years) and the extent of remediation that may be required.
The Company believes, at this time, that no remediation of any of the
remaining four sites will be necessary.
Regulatory orders issued by the PSC of MD allow the Company to recover the
costs associated with the sites applicable to Maryland over periods ranging from
five to thirty years. Rate orders issued by the PSC of DC allow the Company a
three-year recovery of prudently incurred environmental response costs and allow
the Company to defer additional costs incurred between rate cases. At September
30, 1999, there is no environmental regulatory asset subject to recovery in
Virginia. The Public Service Commission of West Virginia has allowed a Company
subsidiary to recover certain environmental response costs. As discussed in Note
2, the Company sold substantially all of this subsidiary's assets that were
located in West Virginia in 1999. The purchaser of these properties is including
the environmental response cost recovery in its rates, then remitting these
recoveries to the Company on a quarterly basis through November 2001.
At September 30, 1999, the Company has recorded a regulatory asset of $6.9
million for the portion of environmental response costs it believes are
recoverable in rates. Based on existing knowledge, the Company does not expect
that the ultimate impact of these matters will have a materially adverse effect
on its financial condition or results of operations.
10. COMMITMENTS AND CONTINGENCIES
The Company is involved in certain legal and administrative proceedings
incidental to its business. In the opinion of management, the Company has
recorded adequate provisions for probable losses related to these proceedings.
Management does not expect that the final resolution of these matters will have
a materially adverse effect on the Company's financial position or results of
operations.
TRANSFERS AND SERVICING OF FINANCIAL ASSETS
The Company has extended credit to certain residential and small commercial
customers to purchase gas appliances and equipment and energy conservation
products. The Company transfers with recourse certain of these accounts
receivable to commercial banks. Effective for transfers after December 31, 1996,
the Company accounts for these transfers in accordance with Statement of
Financial Accounting Standards No. 125, Accounting for Transfers and Servicing
of Financial Assets and Extinguishment of Liabilities (SFAS No. 125), which
supersedes Statement of Financial Accounting Standards No. 77, Reporting by
Transferors for Transfers of Receivables with Recourse (SFAS No. 77).
The Company's transfers of receivables with recourse totaled $28.6 million,
$27.2 million and $33.0 million in 1999, 1998 and 1997, respectively. The
transfers after December 31, 1996 were recognized as sales in accordance with
SFAS No. 125 and in accordance with SFAS No. 77 for prior sales. Under the sales
agreements with the banks, the Company acts as an agent for the bank and
services the receivables. At September 30, 1999, the Company had a $1.8 million
receivable representing the present value of estimated future net cash flows
related to these sales. The Company has also recognized a liability related to
its estimated recourse obligation for sales of receivables since December 31,
1996.
1999 ANNUAL REPORT 45
<PAGE> 31
Receivables transferred with recourse are considered financial instruments
with off-balance sheet risk. At September 30, 1999, the Company's exposure to
credit loss in the event of non-performance by customers is $46.4 million,
represented by the $47.7 million balance of transferred receivables that remain
outstanding, less the recourse obligation of $0.2 million (for transfers after
December 31, 1996) and a provision for uncollectible accounts of $1.1 million
(for transfers prior to January 1, 1997).
NATURAL GAS CONTRACTS
Regulated Operations
The Company has 11 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 2001 to 2003. At September 30, 1999, the Company is required to make total
fixed payments and premiums under these natural gas purchase contracts of
approximately $15.4 million. At September 30, 1999, the Company also has service
agreements with four pipeline companies that serve the Company directly and
three upstream pipelines that provide for firm transportation and storage
services. These agreements, which have expiration dates ranging from fiscal
years 2001 to 2016, require the Company to pay fixed monthly charges. The
aggregate amount of required payments under the pipeline service agreements
totals approximately $656.2 million at September 30, 1999.
The following table summarizes the estimated payments that the Company will
make under its natural gas purchase and pipeline transportation contracts during
the next five years.
<TABLE>
<CAPTION>
(Millions) 2000 2001 2002 2003 2004 Total
- ---------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas
Purchase
Contracts $ 6.4 $ 4.6 $ 2.6 $ 1.8 $ -- $ 15.4
Pipeline
Contracts 94.6 92.0 81.5 75.2 69.9 413.2
------ ----- ----- ----- ------ ------
Total $101.0 $96.6 $84.1 $77.0 $69.9 $428.6
====== ===== ===== ===== ====== ======
</TABLE>
Currently, the Company recovers the costs incurred under these natural gas
purchase contracts as part of the cost of gas through the gas cost recovery
mechanisms included in the Company's retail rate schedules in each of its
jurisdictions. However, the timing and extent of the Company's initiatives to
separate the purchase and sale of natural gas from the delivery of gas could
cause its gas supply commitments to be in excess of its continued sales
obligations.
In its District of Columbia and Maryland jurisdictions, the Company has rate
provisions that would allow it to continue to recover potential excess
commitments in rates. The SCC of VA has not yet issued any definitive ruling on
the recovery of any potential excess commitments. The Company is actively
managing its supply portfolio to ensure its sales and supply obligations remain
balanced. To the extent the Company determines that competition or changing
regulation would cause it to discontinue recovery of these costs in rates, it
would be required to charge them to expense without any corresponding revenue
recovery. If this were to occur and depending upon the timing of the occurrence,
the impacts on the Company's financial position and results of operations would
likely be significant.
Unregulated Operations
WGEServices, the Company's gas marketing subsidiary, has contracts to purchase
fixed quantities of natural gas with terms of up to 24 months. Purchase
contracts are designed to match the duration of WGEServices' sales commitments
and to effectively lock in a margin on gas sales over the terms of existing
sales contracts.
At any point in time, WGEServices may have a difference between the volumes
of natural gas committed to its customers and the volumes of purchase
commitments. WGEServices' open position at September 30, 1999 was not material
to the Company's financial position and results of operations.
FERC ORDER NO. 636 AND TRANSITION COSTS
In November 1993, the Federal Energy Regulatory Commission (FERC) implemented
Order No. 636 (Order). The Order removed the merchant function from interstate
pipeline companies' operations and required them to provide storage and
transportation services to gas shippers, such as the Company.
The pipeline companies have incurred, and will continue to incur, certain
costs, known as transition costs, in connection with the implementation of the
Order. Transition costs that the FERC considers to have been prudent when
incurred can be recovered from customers of the pipelines, such as the Company.
Through September 30, 1999, the Company had paid $50.8 million in such costs to
six pipeline companies and currently estimates that additional transition costs
to be assigned to the Company will be at least $0.8 million. The Company has
recorded a liability on the balance sheet at September 30, 1999 in this amount.
The total level of transition costs that will ultimately be incurred by the
Company and reflected in the financial statements cannot be estimated at this
time. This is because either the costs have yet to be incurred by the applicable
pipeline companies, or the level of costs may be affected by requests pending or
future filings with FERC.
The Company is currently collecting transition costs paid to the pipeline
companies through the gas cost recovery mechanisms of the Company's retail rate
schedules. At September 30, 1999, the Company had recorded a regulatory asset of
$0.8 million for amounts yet to be recovered from its customers.
VIRGINIA REGULATORY MATTERS
In those years when the Company does not request a modification of its basic
rates, the Company is required to make a filing (referred to as the Company's
Annual Information Filing) with
46 1999 ANNUAL REPORT
<PAGE> 32
the SCC of VA that provides Commission staff the basis to assess the
reasonableness of the Company's rates on a prospective basis and to make a
recommendation to the Commission.
On September 25, 1998, the staff of the SCC of VA recommended that the
Company eliminate a regulatory asset associated with implementation of SFAS No.
106. The Company concluded that the Virginia regulatory asset related to the
implementation of SFAS No. 106 did not meet the conditions for continued
deferral under SFAS No. 71. Therefore, in the fourth quarter of fiscal year
1998, the Company recorded a $1.6 million charge to write-off the Virginia
regulatory asset related to the implementation of SFAS No. 106.
The Company believes, in accordance with SFAS No. 71, that its regulatory
assets recorded as of September 30, 1999 applicable to operations in Virginia
are probable of future recovery.
MARYLAND REGULATORY MATTERS
On May 17, 1999, the Company filed an application for an Incentive Rate Plan
with the PSC of MD. The application requested that the Company's rates be frozen
at current levels for five years from the date of approval. In addition to the
rate freeze, the plan proposes a sharing mechanism for net income when the
Company's earnings on its Maryland business exceeds a 12% return on equity
(ROE), with the customers receiving 50% and the Company retaining 50% of the
excess. The proposal provides for a change in the 12% benchmark ROE when the
twelve-month average for 30-year U.S. Treasuries moves by more than 100 basis
points in either direction. The proposal also allows for adjustments to rates
due to circumstances beyond the Company's control, such as changes in tax laws,
legislative mandates, Financial Accounting Standards Board or Securities and
Exchange Commission accounting modifications, or new or increased regulatory
requirements. The proposed plan provides the Company with the opportunity to
adjust rates, subject to PSC of MD review and refund, should its Maryland
weather-normalized ROE drop below 8.5%. Finally, the proposal maintains the gas
cost mechanisms that provide for the recovery of actual costs of gas from firm
customers. The Company cannot predict the outcome of the proposal it filed and
does not believe that any changes that may result from this will be effective
before July 1, 2000.
11. 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, 1999 and 1998. The fair
value of a financial instrument is the amount at which the instrument could be
exchanged in a current transaction between willing parties.
<TABLE>
<CAPTION>
1999 1998
- -------------------------------------------------------------
Carrying Fair Carrying Fair
(Millions) Amount Value Amount Value
- -------------------------------------------------------------
<S> <C> <C> <C> <C>
Current assets $116.9 $116.9 $127.2 $127.2
Current liabilities 277.8 277.8 345.0 345.0
Long-term debt 506.1 487.9 428.6 462.2
</TABLE>
Financial instruments included in current assets are cash and cash
equivalents, net accounts receivable, accrued utility revenues and other
miscellaneous receivables. Financial instruments included in current liabilities
are total current liabilities from the Consolidated Balance Sheets excluding
capital lease obligations and accrued vacation costs. The carrying amount of the
financial instruments included in current assets and current liabilities
approximates fair value because of the short maturity of these instruments. The
fair value of long-term debt was estimated based on the quoted market prices of
U.S. Treasury issues having a similar term to maturity, adjusted for the
Company's credit quality and the present value of future cash flows.
12. OPERATING SEGMENT REPORTING
In fiscal year 1999, the Company adopted Statement of Financial Accounting
Standards No. 131, Disclosures about Segments of an Enterprise and Related
Information (SFAS No. 131). SFAS No. 131 introduces a new model, called the
"management approach," to identify and report on the operating segments of a
business enterprise. Operating segments are revenue-generating components of an
enterprise for which separate financial information is produced internally that
management regularly uses to make operating decisions and assess performance.
The Company reports four operating segments: 1) regulated utility; 2) energy
marketing; 3) HVAC; and 4) customer financing for natural gas appliances and
certain energy-related equipment.
With over 95% of the Company's assets, the regulated utility segment is the
Company's core business. The regulated utility segment provides regulated gas
distribution services, including the purchase and delivery of natural gas, meter
reading, bill preparation and responding to customer inquiries. The regulated
utility segment serves residential, commercial and industrial customers in
metropolitan Washington, D.C. and parts of Maryland and Virginia. In addition,
the regulated utility segment also includes the operation of an underground
natural gas storage facility regulated by FERC.
The energy marketing segment sells natural gas directly to customers, both
inside and outside the Company's traditional service territory, in competition
with unregulated gas marketers. The HVAC segment designs, renovates and services
mechanical heating, ventilating and air conditioning systems for commercial and
residential customers. The customer financing segment provides financing for
consumer purchases of natural gas appliances and certain energy-related
equipment.
The accounting policies of the reported segments are the same as those
described in Note 1. While net income or loss is the primary criteria for
measuring a segment's performance, the Company also evaluates segments based on
other relevant factors, such as penetration into their respective markets.
Operating segment information is presented in the following table.
1999 ANNUAL REPORT 47
<PAGE> 33
<TABLE>
<CAPTION>
Non-Utility Operations
--------------------------------------------------------
Regulated Energy Customer Other Eliminations/
(Thousands) Utility Marketing HVAC Financing Activities Total Reclassifications Consolidated
- ---------------------------------------------------------------------------------------------------------------------------------
YEAR ENDED SEPTEMBER 30, 1999
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
TOTAL REVENUES $ 972,120 $103,851 $31,154 $3,779 $ 1,258 $140,042 $ -- $1,112,162
DEPRECIATION AND
AMORTIZATION 59,940 26 177 -- -- 203 -- 60,143
OTHER OPERATING
EXPENSES 772,420 101,492 28,485 790 (1,444) 129,323 -- 901,743
INCOME TAX EXPENSE
(BENEFIT) 38,606 764 972 1,100 1,077 3,913 (943) 41,576
NET INTEREST EXPENSE 36,533 5 279 150 4 438 -- 36,971
NET INCOME (LOSS) 64,621 1,564 1,241 1,739 1,621 6,165 (2,018) 68,768
TOTAL ASSETS 1,698,143 32,107 20,560 12,270 239 65,176 3,405 1,766,724
CAPITAL EXPENDITURES 158,190 38 505 -- -- 543 -- 158,733
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30, 1998
- ----------------------------------------------------------------------------------------------------------------------------------
Total Revenues $1,040,618 $ 83,176 $13,815 $3,206 $ 2,637 $102,834 $ -- $1,143,452
Depreciation and
Amortization 54,875 26 99 -- 73 198 -- 55,073
Other Operating
Expenses 845,758 82,702 14,083 984 (1,533) 96,236 -- 941,994
Income Tax Expense
(Benefit) 38,006 173 (160) 803 840 1,656 144 39,806
Net Interest Expense 37,428 (13) 98 149 57 291 -- 37,719
Net Income (Loss) 64,551 289 (305) 1,269 3,200 4,453 (375) 68,629
Total Assets 1,649,247 20,260 11,863 3,101 641 35,865 (2,679) 1,682,433
Capital Expenditures 156,383 34 2,457 -- -- 2,491 158,874
- ---------------------------------------------------------------------------------------------------------------------------------
Year Ended September 30, 1997
- ---------------------------------------------------------------------------------------------------------------------------------
Total Revenues $1,055,754 $ 35,308 $ 2,653 $3,373 $ 3,592 $ 44,926 $ -- $1,100,680
Depreciation and
Amortization 51,363 19 -- -- 119 138 -- 51,501
Other Operating
Expenses 841,252 34,547 2,136 1,810 3,987 42,480 -- 883,732
Income Tax Expense
(Benefit) 47,864 256 200 495 (179) 772 (195) 48,441
Net Interest Expense 33,920 23 -- 147 52 222 -- 34,142
Net Income (Loss) 81,354 462 318 922 (387) 1,315 (650) 82,019
Total Assets 1,537,639 10,191 255 2,205 1,163 13,814 579 1,552,032
Capital Expenditures 139,871 -- -- -- -- -- -- 139,871
</TABLE>
48 1999 ANNUAL REPORT
<PAGE> 34
WASHINGTON GAS LIGHT COMPANY
Management's Responsibility for Financial Statements
The presentation of financial data that accurately and fairly reflects the
results of operations and financial position of the Company is one of
management's stewardship obligations to its shareholders. Management has
prepared the accompanying financial statements in accordance with generally
accepted accounting principles, including the estimates and judgments made by
management which are necessary to prepare the statements in accordance with such
principles. To assure the integrity of the underlying financial records
supporting the financial statements, management maintains a system of internal
accounting controls sufficient to provide reasonable assurances at reasonable
costs that assets are properly safeguarded and accounted for and are utilized
only in accordance with management's authorization.
The system of internal accounting controls is augmented by the Company's
internal audit department, which has unrestricted access to all levels of
Company management. In addition, the internal auditor meets periodically with
the Audit Review Committee of the Board of Directors to discuss, among other
things, the Company's system of internal accounting controls and the adequacy of
the internal audit program. The report of the Audit Review Committee appears
below.
As discussed in its report, the Audit Review Committee also meets
periodically with Arthur Andersen LLP, the Company's independent public
accountants, with and without management present, to discuss the results of
Arthur Andersen LLP's audit of the Company's financial statements. The report of
Arthur Andersen LLP appears on the following page.
/s/ JAMES H. DEGRAFFENREIDT, JR
James H. DeGraffenreidt, Jr., Chairman of the Board and
Chief Executive Officer
/s/ FREDERIC M. KLINE
Frederic M. Kline, Vice President and Chief Financial Officer
Report of the Audit Review Committee
The Audit Review Committee of the Board of Directors of Washington Gas Light
Company is comprised of four directors who are not employees of the Company:
Karen Hastie Williams (Chair), Fred J. Brinkman, Daniel J. Callahan, III and
Orlando W. Darden. The committee held five meetings during fiscal year 1999.
The Audit Review Committee oversees Washington Gas Light Company's financial
reporting process on behalf of Washington Gas Light Company's Board of
Directors. The committee maintains a charter that outlines its responsibilities
and modifies the charter from time-to-time, as it deems appropriate. 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 the overall quality of the Company's financial reporting.
The committee met separately with the Company's internal auditor and independent
public accountants, with and without management present, to discuss the results
of their audits and their evaluation of the Company's internal controls. The
meetings also were designed to facilitate and encourage any private
communication between the committee and the internal auditor or independent
public accountants.
/s/ KAREN HASTIE WILLIAMS
Karen Hastie Williams, Chair, Audit Review Committee
1999 ANNUAL REPORT 49
<PAGE> 35
WASHINGTON GAS LIGHT COMPANY
Report of Independent Public Accountants
To the Shareholders and Board of Directors of Washington Gas Light Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Washington Gas Light Company (a District of
Columbia and Virginia corporation) and subsidiaries as of September 30, 1999 and
1998, 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, 1999. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated 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, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended September 30, 1999, in conformity with generally accepted
accounting principles.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Vienna, VA
October 25, 1999
50 1999 ANNUAL REPORT
<PAGE> 36
WASHINGTON GAS LIGHT COMPANY
Supplementary Financial Information (Unaudited)
QUARTERLY FINANCIAL INFORMATION
In the opinion of the Company, the quarterly financial information shown below
includes all adjustments necessary for a fair presentation of such periods. Due
to the seasonal nature of the Company's business, there are substantial
variations in operations reported on a quarterly basis.
<TABLE>
<CAPTION>
Quarter Ended
- ----------------------------------------------------------------------------------------------------------------------
(Thousands, Except Per Share Data) Dec. 31 March 31 June 30 Sept. 30
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FISCAL YEAR 1999
Operating revenues (a) $328,875 $447,418 $175,297 $160,572
Operating income (loss) (a) 35,686 74,601 2,162 (4,692)
Net income (loss) 24,915 64,844 (6,764) (14,227)
Earnings (loss) per average share of common
stock-basic & diluted (b) 0.55 1.39 (0.15) (0.31)
FISCAL YEAR 1998
Operating revenues (a) $395,068 $420,678 $179,222 $148,484
Operating income (loss) (a) 47,939 61,728 1,727 (4,671)
Net income (loss) 38,123 53,729 (7,022) (16,201)
Earnings (loss) per average share of common
stock-basic & diluted (b) 0.87 1.22 (0.17) (0.38)
</TABLE>
(a) Amounts reported for prior quarters have been adjusted, primarily to include
the non-utility operating segments. Previously, the revenues and operating
income from the Company's non-utility segments were reported as part of the
"Other Income (Loss)--Net" category on the Consolidated Statements of Income.
(b) The sum of these amounts may not equal the annual amount because the
quarterly calculations are based on varying numbers of common shares
outstanding.
<TABLE>
<CAPTION>
COMMON STOCK PRICE RANGE AND DIVIDENDS PAID
- -----------------------------------------------------------------------------------------------
Dividends Paid Dividend
High Low Per Share Payment Date
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FISCAL YEAR 1999
Fourth quarter $28 7/8 $25 $0.305 8/1/99
Third quarter 27 1/16 21 0.305 5/1/99
Second quarter 27 3/8 21 5/16 0.300 2/1/99
First quarter 28 3/4 24 15/16 0.300 11/1/98
FISCAL YEAR 1998
Fourth quarter $27 7/8 $23 1/16 $0.300 8/1/98
Third quarter 28 1/4 24 3/4 0.300 5/1/98
Second quarter 30 3/4 25 9/16 0.295 2/1/98
First quarter 31 3/8 23 13/16 0.295 11/1/97
</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, 1999, the Company had 21,565 common
shareholders of record.
1999 ANNUAL REPORT 51
<PAGE> 1
Exhibit 21
WASHINGTON GAS LIGHT COMPANY
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
Percent of
Voting
Securities State of
Owned Incorporation
----- -------------
<S> <C> <C>
Subsidiaries of Washington Gas Light
Company (Parent) -
Shenandoah Gas Company 100% Virginia
Hampshire Gas Company 100% West Virginia
Crab Run Gas Company 100% Virginia
Washington Gas Resources Corp. a/ 100% Delaware
Virginia Intrastate Pipeline Company c/ 100% Virginia
a/ Subsidiary companies of Washington
Gas Resources Corp. -
American Combustion Industries, Inc. 100% Maryland
Washington Gas Energy Services, Inc. b/ 100% Delaware
Washington Gas Consumer Services, Inc. 100% Delaware
b/ Subsidiary companies of Washington
Gas Energy Services, Inc. -
Washington Gas Energy Systems, Inc. 100% Delaware
Brandywood Estates, Inc. 100% Maryland
Advanced Marketing Concepts, Inc. c/ 100% Delaware
c/ Inactive
</TABLE>
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports included or incorporated by reference in this Form 10-K, into the
Company's previously filed Registration Statements File Nos. 33-61199,
333-01469, 333-01471, 333-16181, 333-18965, 333-79465, and 333-83185.
ARTHUR ANDERSEN LLP
Vienna, VA
December 16, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, BALANCE SHEETS AND STATEMENTS OF CASH
FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,401,025
<OTHER-PROPERTY-AND-INVEST> 1,717
<TOTAL-CURRENT-ASSETS> 249,758
<TOTAL-DEFERRED-CHARGES> 114,224
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,766,724
<COMMON> 46,597
<CAPITAL-SURPLUS-PAID-IN> 368,007
<RETAINED-EARNINGS> 269,430
<TOTAL-COMMON-STOCKHOLDERS-EQ> 684,034
0
28,420
<LONG-TERM-DEBT-NET> 506,084<F1>
<SHORT-TERM-NOTES> 48,957<F2>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 64,110<F2>
<LONG-TERM-DEBT-CURRENT-PORT> 1,431
0
<CAPITAL-LEASE-OBLIGATIONS> 540
<LEASES-CURRENT> 540
<OTHER-ITEMS-CAPITAL-AND-LIAB> 433,148
<TOT-CAPITALIZATION-AND-LIAB> 1,766,724
<GROSS-OPERATING-REVENUE> 1,112,162<F3>
<INCOME-TAX-EXPENSE> 42,519<F3>
<OTHER-OPERATING-EXPENSES> 961,886<F3>
<TOTAL-OPERATING-EXPENSES> 1,004,405
<OPERATING-INCOME-LOSS> 107,757
<OTHER-INCOME-NET> (2,018)
<INCOME-BEFORE-INTEREST-EXPEN> 105,739
<TOTAL-INTEREST-EXPENSE> 36,971
<NET-INCOME> 68,768
1,331
<EARNINGS-AVAILABLE-FOR-COMM> 67,437
<COMMON-STOCK-DIVIDENDS> 56,322
<TOTAL-INTEREST-ON-BONDS> 36,971<F4>
<CASH-FLOW-OPERATIONS> 152,727
<EPS-BASIC> 1.47
<EPS-DILUTED> 1.47
<FN>
<F1>REPRESENTS TOTAL LONG-TERM DEBT INCLUDING $500,700 IN UNSECURED
MEDIUM-TERM NOTES, $5,979 IN OTHER LONG-TERM DEBT AND ($595) IN UNAMORTIZED
PREMIUM AND DISCOUNT-NET.
<F2>TOTAL OF SHORT-TERM NOTES PAYABLE AND COMMERCIAL PAPER TIES TO BALANCE
SHEET CAPTION ENTITLED NOTES PAYABLE.
<F3>INCLUDES UTILITY AND NON-UTILITY.
<F4>REPRESENTS TOTAL INTEREST EXPENSE, PER CONSOLIDATED STATEMENTS OF INCOME.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, BALANCE SHEETS AND STATEMENTS OF CASH
FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,316,925
<OTHER-PROPERTY-AND-INVEST> 2,576
<TOTAL-CURRENT-ASSETS> 250,196
<TOTAL-DEFERRED-CHARGES> 112,736
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,682,433
<COMMON> 43,955
<CAPITAL-SURPLUS-PAID-IN> 305,485
<RETAINED-EARNINGS> 258,315
<TOTAL-COMMON-STOCKHOLDERS-EQ> 607,755
0
28,424
<LONG-TERM-DEBT-NET> 428,641<F1>
<SHORT-TERM-NOTES> 57,190<F2>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 67,753<F2>
<LONG-TERM-DEBT-CURRENT-PORT> 64,106
0
<CAPITAL-LEASE-OBLIGATIONS> 834
<LEASES-CURRENT> 546
<OTHER-ITEMS-CAPITAL-AND-LIAB> 427,730
<TOT-CAPITALIZATION-AND-LIAB> 1,682,433
<GROSS-OPERATING-REVENUE> 1,143,452<F3>
<INCOME-TAX-EXPENSE> 39,662<F3>
<OTHER-OPERATING-EXPENSES> 997,067<F3>
<TOTAL-OPERATING-EXPENSES> 1,036,729
<OPERATING-INCOME-LOSS> 106,723
<OTHER-INCOME-NET> (375)
<INCOME-BEFORE-INTEREST-EXPEN> 106,348
<TOTAL-INTEREST-EXPENSE> 37,719
<NET-INCOME> 68,629
1,331
<EARNINGS-AVAILABLE-FOR-COMM> 67,298
<COMMON-STOCK-DIVIDENDS> 52,158
<TOTAL-INTEREST-ON-BONDS> 37,719<F4>
<CASH-FLOW-OPERATIONS> 122,312
<EPS-BASIC> 1.54
<EPS-DILUTED> 1.54
<FN>
<F1>REPRESENTS TOTAL LONG-TERM DEBT INCLUDING $2,000 IN FIRST MORTGAGE BONDS,
$425,700 IN UNSECURED MEDIUM-TERM NOTES, $1,680 IN OTHER LONG-TERM DEBT AND
$(739) IN UNAMORTIZED PREMIUM AND DISCOUNT-NET.
<F2>TOTAL OF SHORT-TERM NOTES PAYABLE AND COMMERCIAL PAPER TIES TO BALANCE
SHEET CAPTION ENTITLED NOTES PAYABLE.
<F3>INCLUDES UTILITY AND NON-UTILITY.
<F4>REPRESENTS TOTAL INTEREST EXPENSE, PER CONSOLIDATED STATEMENTS OF INCOME.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, BALANCE SHEETS AND STATEMENTS OF CASH
FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1997
<PERIOD-START> OCT-01-1996
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,214,016
<OTHER-PROPERTY-AND-INVEST> 3,121
<TOTAL-CURRENT-ASSETS> 219,974
<TOTAL-DEFERRED-CHARGES> 114,921
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,552,032
<COMMON> 43,742
<CAPITAL-SURPLUS-PAID-IN> 302,118
<RETAINED-EARNINGS> 243,175
<TOTAL-COMMON-STOCKHOLDERS-EQ> 589,035
0
28,430
<LONG-TERM-DEBT-NET> 431,575<F1>
<SHORT-TERM-NOTES> 19,200<F2>
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 48,700<F2>
<LONG-TERM-DEBT-CURRENT-PORT> 20,862
0
<CAPITAL-LEASE-OBLIGATIONS> 1,289
<LEASES-CURRENT> 495
<OTHER-ITEMS-CAPITAL-AND-LIAB> 412,941
<TOT-CAPITALIZATION-AND-LIAB> 1,552,032
<GROSS-OPERATING-REVENUE> 1,100,680<F3>
<INCOME-TAX-EXPENSE> 48,636<F3>
<OTHER-OPERATING-EXPENSES> 935,233<F3>
<TOTAL-OPERATING-EXPENSES> 983,869
<OPERATING-INCOME-LOSS> 116,811
<OTHER-INCOME-NET> (650)
<INCOME-BEFORE-INTEREST-EXPEN> 116,161
<TOTAL-INTEREST-EXPENSE> 34,142
<NET-INCOME> 82,019
1,331
<EARNINGS-AVAILABLE-FOR-COMM> 80,688
<COMMON-STOCK-DIVIDENDS> 51,139
<TOTAL-INTEREST-ON-BONDS> 34,142<F4>
<CASH-FLOW-OPERATIONS> 155,265
<EPS-BASIC> 1.85
<EPS-DILUTED> 1.85
<FN>
<F1>REPRESENTS TOTAL LONG-TERM DEBT INCLUDING $56,000 IN FIRST MORTGAGE BONDS,
$375,400 IN UNSECURED MEDIUM-TERM NOTES, $890 IN OTHER LONG-TERM DEBT AND
$(715) IN UNAMORTIZED PREMIUM AND DISCOUNT-NET.
<F2>TOTAL OF SHORT-TERM NOTES PAYABLE AND COMMERCIAL PAPER TIES TO BALANCE
SHEET CAPTION ENTITLED NOTES PAYABLE.
<F3>INCLUDES UTILITY AND NON-UTILITY.
<F4>REPRESENTS TOTAL INTEREST EXPENSE, PER CONSOLIDATED STATEMENTS OF INCOME.
</FN>
</TABLE>
