SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended September 30, 2005

Indicate by check mark whether each 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 registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes    X     No      

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ 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 ]

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12-b of the Act):

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act):

Yes         No    X  

The aggregate market value of the voting common equity held by non-affiliates of the registrant, WGL Holdings, Inc., amounted to $1,501,588,514 as of March 31, 2005.

WGL Holdings, Inc. common stock, no par value outstanding as of October 31, 2005: 48,753,828 shares.

All of the outstanding shares of common stock ($1 par value) of Washington Gas Light Company were held by WGL Holdings, Inc. as of October 31, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of WGL Holdings, Inc.’s definitive Proxy Statement and Washington Gas Light Company’s definitive Information Statement in connection with the 2006 Annual Meeting of Shareholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A and 14C not later than 120 days after September 30, 2005, are incorporated in Part III of this report.

WGL Holdings, Inc.

Washington Gas Light Company

For the Fiscal Year Ended September 30, 2005

Table of Contents

Washington Gas Light Company

INTRODUCTION

FILING FORMAT

       This Annual Report on Form 10-K is a combined report being filed by two separate registrants: WGL Holdings, Inc. (WGL Holdings or the Company) and Washington Gas Light Company (Washington Gas or the regulated utility). Except where the content clearly indicates otherwise, any reference in the report to “WGL Holdings” or “the Company” is to the consolidated entity of WGL Holdings and all of its subsidiaries, including Washington Gas which is a distinct registrant that is a wholly owned subsidiary of WGL Holdings.

      The Management’s Discussion and Analysis of Financial Condition and Results of Operations (Management’s Discussion) included under Item 7 herein, is divided into the following two major sections:

      Included herein under Item 8 are Consolidated Financial Statements of WGL Holdings and the Financial Statements of Washington Gas. Also included herein are the Notes to Consolidated Financial Statements that are presented on a combined basis for both WGL Holdings and Washington Gas.

      The Management’s Discussion for both WGL Holdings and Washington Gas should be read in conjunction with the respective company’s financial statements and the combined Notes to Consolidated Financial Statements thereto.

      Unless otherwise noted, earnings per share amounts are presented herein on a diluted basis, and are based on weighted average common and common equivalent shares outstanding.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

       Certain matters discussed in this report, excluding historical information, include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the outlook for earnings, revenues and other future financial business performance or strategies and expectations. Forward-looking statements are typically identified by words such as, but not limited to, “estimates,” “expects,” “anticipates,” “intends,” “believes,” “plans,” and similar expressions, or future or conditional verbs such as “will,” “may,” “should,” “would,” and “could.” Although the registrants, WGL Holdings and Washington Gas, believe such forward-looking statements are based on reasonable assumptions, they cannot give assurance that every objective will be achieved. Forward-looking statements speak only as of today, and the registrants assume no duty to update them. The following factors, among others, could cause actual results to differ materially from forward-looking statements or historical performance:

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      The outcome of negotiations and discussions that the registrants may hold with other parties from time to time regarding utility and energy-related investments and strategic transactions that are both recurring and non-recurring may also affect future performance. All such factors are difficult to predict accurately and are generally beyond the direct control of the registrants. Accordingly, while they believe that the assumptions are reasonable, the registrants 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 registrants’ business as described in this Annual Report on Form 10-K. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

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      As of September 30, 2005, the Company had 1.012 million active customer meters. Active customer meters reflect all natural gas meters connected to the Washington Gas distribution system, excluding those meters that are not currently receiving service due to disconnection. The following table lists the number of active customer meters served and therms delivered by jurisdiction as of and for the year ended September 30, 2005. A therm of gas contains 100,000 British Thermal Units of heat, the heat content of approximately 100 cubic feet of natural gas. Ten million therms equal approximately one billion cubic feet (bcf) of natural gas.

      Of the 1.644 billion therms delivered in fiscal year 2005, 855.6 million therms, or 52.1 percent, were sold and delivered by Washington Gas and 787.9 million therms, or 47.9 percent, were delivered by Washington Gas to various customers that acquired their natural gas from competitive natural gas suppliers described as third-party marketers. Of the total therms delivered by Washington Gas, 78.0 percent was delivered to firm residential and commercial customers, 17.5 percent was delivered to interruptible customers, and the remaining 4.5 percent was delivered to customers that use natural gas to generate electricity either under an interruptible or special firm contract. To be eligible to receive interruptible service, a customer must be capable of using an alternate fuel as a substitute for natural gas in the event that Washington Gas determines that their service must be interrupted to accommodate firm customers’ needs during periods of peak demand.

      Crab Run —is an exploration and production company whose assets are managed by an Oklahoma-based limited partnership in which Crab Run is a limited partner. At September 30, 2005, Crab Run’s investment in this partnership was not material. WGL Holdings’ investment in this subsidiary also is not material, and the Company expects that future investments in Crab Run will be minimal.

      Hampshire —is a regulated utility that operates an underground natural gas storage facility in Hampshire County, West Virginia. Washington Gas purchases all of the storage services of Hampshire. Washington Gas includes the cost of these services in the bills sent to its customers. Hampshire is regulated under a cost of service tariff by the FERC.

      Washington Gas Resources —owns the Company’s unregulated subsidiaries. The subsidiaries of Washington Gas Resources, as described below, include Washington Gas Energy Services, Inc. (WGEServices), American Combustion Industries, Inc. (ACI), Washington Gas Energy Systems, Inc. (WGESystems), WG Maritime Plaza I, Inc. (WG Maritime) and Washington Gas Credit Corporation (Credit Corp.).

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INDUSTRY SEGMENTS

       WGL Holdings, through its subsidiaries, sells and delivers natural gas and provides a variety of energy-related products and services to customers primarily in Washington, D.C. and the surrounding metropolitan areas in Maryland and Virginia. The Company’s core subsidiary, Washington Gas, is involved in the distribution and sale of natural gas that is primarily regulated by state regulatory commissions. In response to changes in federal and state regulation, the Company offers competitively priced natural gas and electricity to customers through WGEServices, its unregulated retail energy-marketing subsidiary. The Company also offers energy-related products and services that are closely related to its core business. The majority of these energy-related activities are performed by wholly owned subsidiaries of Washington Gas Resources.

      WGL Holdings has three operating segments: 1) regulated utility; 2) retail energy-marketing; and 3) commercial HVAC products and services. These three segments are described below. Transactions not specifically identifiable in one of these three segments are accumulated and reported in the category “Other Activities.”

     Regulated Utility

       With approximately 94 percent of the Company’s consolidated total assets, the regulated utility segment (consisting of Washington Gas and Hampshire) delivers natural gas to retail customers in accordance with tariffs approved by the District of Columbia, Maryland and Virginia regulatory commissions that have jurisdiction over Washington Gas’ rates. These rates are intended to provide the regulated utility with an opportunity to earn a just and reasonable rate of return on the investment devoted to the delivery of natural gas to customers. Washington Gas also sells natural gas to customers who have not elected to purchase natural gas from unregulated third-party marketers. The regulated utility does not earn a profit or incur a loss when it sells the natural gas commodity because utility customers are charged for the natural gas commodity at the same cost that the regulated utility incurs. At September 30, 2005, the regulated utility was selling and delivering the natural gas commodity to 84.9 percent of its customers. The remaining 15.1 percent of Washington Gas’ customers utilized the delivery services of Washington Gas for delivery of the natural gas commodity purchased from third-party marketers, one of which is WGEServices. During fiscal years ended September 30, 2005, 2004 and 2003, the regulated utility segment reported total operating revenues of $1.4 billion, $1.3 billion and $1.3 billion, respectively, representing 64.2 percent, 61.9 percent and 63.6 percent, respectively, of consolidated total operating revenues. Factors critical to the success of the regulated utility include: (i)  operating a safe and reliable natural gas distribution system;

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(ii)  having sufficient natural gas supplies to serve the demand of its customers; (iii)  being competitive with other sources of energy such as electricity, fuel oil and propane; and (iv)  recovering the costs and expenses of this business in the rates it charges to customers. These costs and expenses include a just and reasonable rate of return on invested capital as authorized by the regulatory commissions having jurisdiction over the regulated utility’s rates. Hampshire, regulated by the FERC, is also part of the Company’s regulated utility segment. Hampshire operates an underground natural gas storage facility that provides services exclusively to Washington Gas. Hampshire operates under a “pass-through” cost of service-based tariff approved by the FERC, and adjusts its billing rates to Washington Gas on a periodic basis to account for changes in its investment in utility plant and associated expenses.

     Retail Energy-Marketing

       WGEServices, a wholly owned subsidiary of Washington Gas Resources, competes with other third-party marketers by selling natural gas and electricity directly to residential, commercial and industrial customers, both inside and outside of the regulated utility’s traditional service territory. WGEServices does not own or operate any natural gas or electric generation, production, transmission or distribution assets. Rather, it sells natural gas and electricity with the objective of earning a profit, and these commodities are delivered to retail customers through the assets owned by regulated utilities such as Washington Gas or other unaffiliated natural gas or electric utilities. Factors critical to the success of the retail energy-marketing business are: (i)  managing the market risk of the difference between the sales price committed to customers under sales contracts and the cost of natural gas and electricity needed to satisfy these sales commitments; (ii)  managing credit risks associated with customers of and suppliers to this segment; (iii)  having sufficient deliverability of natural gas and electric supplies to serve the demand of its customers which can be affected by the ability of natural gas producers, pipeline gatherers, natural gas processors, interstate pipelines and suppliers of electricity to deliver the respective commodities; and (iv)  controlling the level of selling, general and administrative expenses, including customer acquisition expenses.

     Commercial HVAC

       Two wholly owned subsidiaries of Washington Gas Resources, ACI and WGESystems, provide turnkey, design-build and renovation projects, and maintenance services to the commercial and government markets. There are many competitors in this business segment. The commercial HVAC operations focus on retrofitting the mechanical, electrical and energy-related systems of a large number of aging commercial and government structures, primarily in the District of Columbia and portions of Maryland and Virginia. Factors critical to the success of the commercial HVAC business include: (i)  generating adequate revenue from the government and private sectors in the new construction and retrofit markets; (ii)  building a stable base of service relationships; (iii)  estimating and managing fixed-price contracts; and (iv)  controlling selling, general and administrative expenses.

      For a further discussion of segment financial results, see Note 16 of the Notes to Consolidated Financial Statements.

RATES AND REGULATORY MATTERS

       Washington Gas is regulated by the Public Service Commission of the District of Columbia (PSC of DC), the Public Service Commission of Maryland (PSC of MD) and the State Corporation Commission of Virginia (SCC of VA). Hampshire is regulated by the FERC. The following section, “General Regulatory Matters,” is a discussion of general regulatory issues, and the section entitled “Jurisdictional Rates and Regulatory Matters” is a discussion of information regarding each commission and recent regulatory proceedings.

     General Regulatory Matters

       Regulated Service to Firm Customers. In the District of Columbia jurisdiction, the rate schedules for firm delivery service are based upon: (i)  a flat volumetric charge for the delivery of each therm of natural

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gas consumed and (ii)  a fixed customer charge designed to recover certain fixed costs associated with maintaining facilities located on the customer’s property, as well as certain other costs that do not vary with the amount of natural gas consumed by customers. Non-residential firm customers in the District of Columbia also pay a peak-usage charge designed to recover the cost to serve customers during peak periods. In the Maryland and Virginia jurisdictions, the rate schedules for firm delivery service comprise a fixed charge per customer and a variable volumetric rate structured as a declining rate based on increasing blocks of volumes. Declining block rates have the effect of minimizing fluctuations in net revenue that otherwise would result from deviations from normal weather.

      The tariff provisions for firm sales service customers in each Washington Gas jurisdiction contain gas cost recovery mechanisms that provide for the recovery of the invoice cost of natural gas, including the cost to transport the gas commodity to Washington Gas’ city gate, applicable to firm customers. Under these mechanisms, firm customer rates are adjusted periodically to reflect increases and decreases in the actual cost of gas. Moreover, provisions in each jurisdiction provide for an annual reconciliation of gas costs collected from firm customers to the applicable invoice cost of gas paid to natural gas suppliers, as well as the invoice cost of transportation paid to pipeline companies, on behalf of these customers. Differences between the amount collected from customers and what is paid to suppliers for natural gas are collected from or refunded to customers over subsequent periods. Washington Gas receives from or pays to its customers in the District of Columbia and Virginia, at short-term interest rates, carrying costs associated with under- or over-collected gas costs recovered from its customers.

      Regulated Service to Interruptible Customers. Interruptible service is a delivery service to certain qualified customers where the delivery can be “interrupted” under certain conditions. To qualify for interruptible service, customers must be capable of either substituting an alternate fuel for natural gas or operating without utilizing natural gas should Washington Gas determine that it must interrupt service temporarily to meet 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 limited by margin-sharing arrangements that are included in Washington Gas’ rate designs in the District of Columbia, in Maryland through September 30, 2005 and, to a much smaller extent, in Virginia. In the District of Columbia, Washington Gas shares a majority of the margins earned on interruptible gas sales and deliveries with firm customers after a gross margin threshold is reached. A portion of the fixed costs for servicing interruptible customers is collected through the firm customers’ rate design. In the Virginia jurisdiction, rates for customers using interruptible delivery service are based on a traditional cost of service approach, and Washington Gas retains all revenues from interruptible delivery service. However, for a few customers who have been grandfathered into a bundled sales and delivery service with a previously approved bundled interruptible rate design, there is some sharing of those revenues with firm customers, but the volumes are small and the amounts of revenues are not material to the financial statements or results of operations. Prior to October 1, 2005, interruptible customers in the Maryland jurisdiction had similar margin-sharing arrangements as described above for interruptible customers in the District of Columbia. Effective October 1, 2005, pursuant to implementing a revenue normalization adjustment mechanism approved by the PSC of MD, rates for interruptible customers in Maryland are based on a traditional cost of service approach, and Washington Gas retains a defined amount above a pre-approved margin threshold level (refer to the section entitled “Jurisdictional Rates and Regulatory Matters— Maryland Jurisdiction” ).

      Natural Gas Unbundling. For the majority of its business, the price that Washington Gas charges its customers is based on the combination of the cost it incurs for the natural gas commodity, including charges for interstate pipeline services, and a charge for delivering natural gas to its customers. Although most of Washington Gas’ revenue is generated from the sale and delivery of natural gas on this combined or “bundled” basis, federal and state regulation allows for the separation or “unbundling” of the sale of the natural gas commodity from the delivery of gas on the regulated utility’s distribution system (delivery service). Gross margins generated by the regulated utility from deliveries of customer-owned gas are equivalent to those earned on bundled gas service because the regulated utility is only allowed to charge its customers the cost it pays for the natural gas commodity and related charges for interstate pipeline

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services. Therefore, Washington Gas does not experience any loss of margins when customers choose to purchase the natural gas commodity from unregulated third-party marketers.

      Throughout the Washington Gas service area, all customers may choose to purchase natural gas from a variety of unregulated third-party marketers, including WGEServices, an affiliated natural gas and electricity retail marketer. When customers select an unregulated third-party marketer as their gas supplier, Washington Gas continues to charge these customers to deliver natural gas through its distribution system. The status of the unbundling programs in the regulated utility’s major jurisdictions as of September 30, 2005 is discussed further in the section entitled “Competition” included herein.

      WGEServices sells natural gas, as an unregulated third-party marketer, to both firm and interruptible customers in each Washington Gas jurisdiction. Washington Gas provides delivery service for those customers of WGEServices that reside in its jurisdiction. In addition, WGEServices sells to other areas in Maryland and Virginia that are outside of the regulated utility’s jurisdictional service area. As an unregulated third-party marketer in a competitive market, WGEServices retains the full amount of margins generated on sales of the natural gas commodity, but also has the potential to incur a loss from sales of this commodity.

     Jurisdictional Rates and Regulatory Matters

       A description of each commission under which Washington Gas is regulated and a discussion of regulatory matters in each jurisdiction are presented below. Also see the section entitled “Regulatory Matters” in Management’s Discussion for a table that summarizes Washington Gas’ major rate applications and results thereof.

          District of Columbia Jurisdiction

      The PSC of DC consists of three full-time members who are appointed by the Mayor with the advice and consent of 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. The PSC of DC has no required period of time by which it must decide decisions for modifications to base rates charged by Washington Gas to its customers.

          Rate Case and Other Regulatory Activities

      On February 7, 2003, Washington Gas filed an application with the PSC of DC to increase base rates. The request sought to increase overall annual revenues in the District of Columbia by approximately $14.1 million, later revised to $18.8 million on May 2, 2003. The application requested a return on common equity of 12.25 percent and an overall rate of return of 9.25 percent.

      On November 10, 2003, the PSC of DC issued a Final Order authorizing Washington Gas to increase its annual revenues by $5.4 million, reflecting an overall rate of return of 8.42 percent and a return on common equity of 10.60 percent. The new rates went into effect for service rendered on and after November 24, 2003.

      The $5.4 million annual revenue increase described in the Final Order included a reduction for the effect of a $6.5 million lower level of pension and other post-retirement benefit costs that previously had been deferred on the balance sheet of Washington Gas as a regulatory liability. This regulatory deferral mechanism (or “tracker”), which has been in effect in the District of Columbia for several years, is designed to ensure that the variation in these annual costs, when compared to the levels collected from customers, does not affect net income. Therefore, the effect of the Final Order’s reduction of annual revenues for lower pension and other post-retirement benefit costs requires an accounting adjustment that reduces both the regulatory liability on the balance sheet and operation and maintenance expenses on the statement of income. Additionally, the $5.4 million annual revenue increase in the Final Order also included an increase in certain expenses that are also subject to the regulatory deferral mechanism treatment that equates to approximately $800,000 per year. Accordingly, the total annualized effect of the Final Order on Washington

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Gas’ pre-tax income results in an increase of approximately $11.1 million, which equates to diluted earnings per share of approximately $0.14, based on weighted average common and common equivalent shares outstanding for the fiscal year ended September 30, 2005.

      In a March 28, 2003 Final Order, the PSC of DC upheld a previous ruling that approved, among other things, a methodology for sharing with customers 50 percent of annual ground lease and development fee revenues that Washington Gas received from Maritime Plaza, a commercial development project constructed on land owned by Washington Gas. On May 23, 2003, the District of Columbia Office of the People’s Counsel (DC OPC) filed an appeal with the District of Columbia Court of Appeals (DC Court of Appeals) seeking to overturn this portion of the March 28, 2003 ruling by the PSC of DC. On March 18, 2004, the DC Court of Appeals ordered, among other things, the PSC of DC to provide an explanation of its decision to approve the allocation methodology for sharing with customers the ground lease and development fee revenues attributable to the Maritime Plaza development project. The PSC of DC issued a subsequent order requiring both the DC OPC and Washington Gas to file testimony addressing the allocation issue. On October 12, 2004, Washington Gas filed testimony before the PSC of DC that it believes supports the allocation methodology that was approved in the PSC of DC’s initial order. The DC OPC filed opposing testimony on the same date. Rebuttal testimony was filed on November 19, 2004 by the DC OPC and Washington Gas. The PSC of DC issued a Final Order on April 4, 2005 that required Washington Gas and the DC OPC to file supplemental testimony on April 25, 2005. The PSC of DC held a one-day evidentiary hearing on October 25, 2005. Washington Gas and the DC OPC filed initial briefs on December 2, 2005, and must file reply briefs on December 16, 2005. Management cannot predict the final outcome of this matter; however, it believes that the likely outcome will not have a material impact on Washington Gas’ financial statements.

     Maryland Jurisdiction

      The PSC of MD consists of five full-time members who are appointed by the Governor with the advice and consent of 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.

      Washington Gas is required to give 30 days’ notice before filing for a rate increase. The PSC of MD may initially suspend the proposed increase for 150 days following 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, the requested rates become effective subject to refund.

     Rate Case and Other Regulatory Activities

      On March 31, 2003, Washington Gas filed an application with the PSC of MD to increase rates in Maryland. The application requested an increase to overall annual revenues by approximately $35.1 million, later revised to $27.2 million on June 16, 2003, with a return on common equity of 12.25 percent and an overall rate of return of 9.39 percent. The requested level of the revenue increase included $8.7 million related to increased depreciation expense.

      On October 31, 2003, the PSC of MD issued a Final Order, granting Washington Gas a $2.9 million increase in annual revenues based on an overall rate of return of 8.61 percent and a return on common equity of 10.75 percent. These rates went into effect for services rendered on and after November 6, 2003. The Final Order excluded the effect of Washington Gas’ request for an $8.7 million increase in annual revenues for depreciation expense, which was decided in a separate proceeding. The Final Order did provide for adjusted revenues that correspond to an update of Washington Gas’ depreciation rates upon the outcome of the separate proceeding. The Final Order also established a separate proceeding to review rates for service to interruptible customers.

      On March 25, 2004, a Hearing Examiner of the PSC of MD issued a proposed Order granting an increase of $1.1 million in annual revenues to reflect new depreciation rates and higher depreciation expense effective on July 1, 2004. This proposed Order was appealed by various parties, including Washington Gas. On June 18, 2004, the PSC of MD denied all appeals and upheld the findings of the

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Hearing Examiner. Washington Gas implemented the new depreciation rates on July 1, 2004, and increased base rates to reflect the increased depreciation expense, as permitted by the PSC of MD’s October 31, 2003 Final Order.

      On April 28, 2005, Washington Gas filed a request for an Accounting Order with the PSC of MD in connection with the rehabilitation project being performed in a portion of Prince George’s County, Maryland to address an increase in natural gas leaks (refer to the section entitled “Operating Issues in Prince George’s County, Maryland” included herein). Pursuant to this filing, Washington Gas specifically requested that the PSC of MD issue an Accounting Order to ratify Washington Gas’ interpretation of the applicable regulatory guidelines regarding the accounting treatment of the estimated $13 million of costs to encapsulate couplings on mains in the affected areas of Prince George’s County which, according to Washington Gas’ interpretation, should be recorded as capital expenditures. After considering this matter at the June 1, 2005 Administrative Meeting of the PSC of MD, the PSC of MD granted Washington Gas’ request for an Accounting Order with the understanding that the accounting treatment will not be determinative of future ratemaking treatment, and the PSC of MD retains jurisdiction to adopt any ratemaking treatment it deems appropriate.

      On July 6, 2005, a Hearing Examiner of the PSC of MD issued a Proposed Order to accept an unopposed Stipulation and Agreement (Stipulation), filed by Washington Gas and three other participants with the PSC of MD on May 18, 2005. On August 8, 2005, the Stipulation included in the Proposed Order became final. The Stipulation resolves outstanding issues from a Final Order issued by the PSC of MD on October 31, 2003, regarding the manner in which interruptible transportation service is charged to Maryland customers (refer to the section above entitled “Regulated Service to Interruptible Customers” for a discussion of this interruptible transportation service). The Stipulation also requested approval by the PSC of MD of a revenue normalization adjustment (RNA) mechanism, a billing adjustment mechanism that is designed to stabilize the level of distribution charge revenues received from customers as a result of deviations in customer usage caused by variations in weather from normal levels, and other matters such as conservation. The Stipulation also allows for the impact of the RNA on Washington Gas’ risk and rate of return to be evaluated in the next rate case. The RNA became effective on October 1, 2005, which is the beginning of the Company’s fiscal year 2006.

     Virginia Jurisdiction

      The SCC of VA consists of three full-time members who are elected by the General Assembly of Virginia. Each commissioner has a six-year term with no limitation on the number of terms that can be served.

      Either of two methods may be used to request a modification of existing rates. First, Washington Gas may file an application for a general rate increase in which it may propose new adjustments to the cost of service that are different from those previously approved for Washington Gas by the SCC of VA, as well as a revised return on equity. The proposed rates under this process may take effect 150 days after the filing, subject to refund pending the outcome of the SCC of VA’s action on the application. Second, an expedited rate case procedure is available which provides that proposed rate increases may be effective 30 days after the filing date, also subject to refund. Under the expedited rate case procedure, Washington Gas may not propose any new adjustments for issues not previously approved in its last general rate case, or a change in its return on common equity from the level authorized in its last general rate case. Once filed, other parties may propose new adjustments or a change in the cost of capital from the level authorized in its last general rate case. The expedited rate case procedure may not be available if the SCC of VA decides that there has been a substantial change in circumstances since the last general rate case filed by Washington Gas.

     Rate Case and Other Regulatory Activities

      On June 14, 2002, Washington Gas filed an application with the SCC of VA to increase annual revenues in Virginia. The Shenandoah Gas Division of Washington Gas was included in the application. The

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application requested an increase in overall annual revenues of approximately $23.8 million. Washington Gas requested an overall rate of return of 9.42 percent and a return on common equity of 12.25 percent versus the then currently authorized return on common equity of 11.50 percent for Washington Gas and 10.70 percent for the Shenandoah Gas Division.

      Under the regulations of the SCC of VA, Washington Gas placed the proposed general revenue increase into effect on November 12, 2002, subject to refund, pending the SCC of VA’s final decision in the proceeding. From that time until a refund was made, as discussed below, Washington Gas recorded a provision for rate refunds representing the estimated refund required based on management’s judgment of the rate case outcome.

      On December 18, 2003, the SCC of VA issued a Final Order that granted Washington Gas an annual revenue increase of $10.8 million, and reduced the annual revenues of the Shenandoah Gas Division of Washington Gas by $867,000. The combination of this increase in the rates of Washington Gas and the reduction in the rates of the Shenandoah Gas Division of Washington Gas yields a net increase in annual revenues of $9.9 million. The Final Order allowed a rate of return on common equity of 10.50 percent and an overall rate of return of 8.44 percent.

      Refunds to customers, with interest, were made pursuant to the Final Order during the quarter ended March 31, 2004. The difference between the amount refunded to customers and the amount of the provision for rate refunds previously recorded by Washington Gas was not material. Accordingly, this refund had no material effect on earnings for the fiscal year ended September 30, 2004.

      In the Final Order, the SCC of VA ordered that the implementation date of new depreciation rates should be January 1, 2002, as opposed to November 12, 2002, as originally requested and implemented by Washington Gas. This required Washington Gas to record additional depreciation expense in fiscal year 2004 of approximately $3.5 million, on a pre-tax basis, that related to the period from January 1, 2002 through November 11, 2002.

      The SCC of VA also ordered Washington Gas to reduce its rate base related to net utility plant by $28 million, which is net of accumulated deferred income taxes of $14 million, and to establish an equivalent regulatory asset that the Company has done for regulatory accounting purposes only. This regulatory asset represents the difference between the accumulated reserve for depreciation recorded on the books of Washington Gas and a theoretical reserve that was derived by the Staff of the SCC of VA (VA Staff) as part of its review of Washington Gas’ depreciation rates, less accumulated deferred income taxes. This regulatory asset is being amortized, for regulatory accounting purposes only, as a component of depreciation expense over 32 years pursuant to the Final Order. The SCC of VA provided for both a return on, and a return of, this regulatory asset established for regulatory accounting purposes.

      In approving the treatment described in the preceding paragraph, the SCC of VA further ordered that an annual “earnings test” be performed to determine if Washington Gas has earned in excess of its allowed rate of return on common equity for its Virginia operations. The current procedure for performing this earnings test does not normalize the actual return on equity for the effect of weather over the applicable twelve-month period. To the extent that Washington Gas earns in excess of its allowed return on equity in any annual earnings test period, Washington Gas is required to increase depreciation expense (after considering the impact of income tax benefits) and increase the accumulated reserve for depreciation for the amount of the actual earnings in excess of the earnings produced by the 10.50 percent allowed return on equity. Under the SCC of VA’s requirements for performing earnings tests, if weather is warmer than normal in a particular annual earnings test period, Washington Gas is not allowed to restore any amount of earnings previously eliminated as a result of this earnings test. These annual earnings tests will continue to be performed until the $28 million difference between the accumulated reserve for depreciation recorded on Washington Gas’ books and the theoretical reserve derived by the VA Staff, net of accumulated deferred income taxes, is eliminated or the level of the regulatory asset established for regulatory accounting purposes is adjusted as a result of a future depreciation study.

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      On March 17, 2005, the VA Staff filed a report with the SCC of VA in connection with Washington Gas’ earnings test for the twelve-month period ended December 31, 2003. The VA Staff’s report concluded that Washington Gas did not earn in excess of its allowed return on equity during this period, and recommended that Washington Gas not be required to record any additional depreciation expense related to its earnings for the twelve-month period ended December 31, 2003. On April 26, 2005, the SCC of VA issued an Order that concurred with the VA Staff’s recommendation. As a result, Washington Gas reversed $1.0 million of depreciation expense, on a pre-tax basis, in fiscal year 2005 that had been previously recorded in fiscal year 2004 related to this earnings test.

      On October 19, 2005, the VA Staff filed a report with the SCC of VA in connection with Washington Gas’ earnings test for the twelve-month period ended December 31, 2004. The VA Staff’s report concluded that Washington Gas did not earn in excess of its allowed return on equity during this period, and recommended that Washington Gas not be required to record any additional depreciation expense related to its earnings for the twelve-month period ended December 31, 2004. A Final Order from the SCC of VA in this proceeding is expected during the first quarter of fiscal year 2006.

      On January 27, 2004, Washington Gas filed an expedited rate case with the SCC of VA to increase annual revenues in Virginia by $19.6 million, with an overall rate of return of 8.70 percent and a 10.50 percent return on equity. On February 26, 2004, based upon expedited rate case filing procedures, Washington Gas placed the proposed revenue increase into effect, subject to refund, pending the SCC of VA’s final decision in the proceeding.

      On September 15, 2004, six participants in the rate case, including Washington Gas and the VA Staff, submitted a proposed Stipulation to the SCC of VA. On September 27, 2004, the SCC of VA issued a Final Order approving the Stipulation as filed. The Stipulation resolved all issues related to Washington Gas’ January 27, 2004 expedited rate case application filed with the SCC of VA.

      The approved Stipulation permitted no change in Washington Gas’ annual base revenues, and for Washington Gas to maintain its allowed rate of return on common equity of 10.50 percent and overall rate of return of 8.44 percent that had been approved by the December 18, 2003 Final Order as previously discussed. Accordingly, refunds to customers, with interest, were made during the December 2004 billing cycle for the amount of the proposed annual revenue increase that had been collected since February 26, 2004. Based on the terms of the Stipulation, Washington Gas implemented billing rates commencing October 4, 2004 that reflected the level of annual revenues determined in the December 18, 2003 Final Order, and implemented the agreed upon changes in rate design that were contained in the Stipulation. The Company’s financial results for fiscal year 2004 reflect the increased rates put into effect on February 26, 2004, offset by a provision for rate refunds equal to the full amount of revenues that had been collected subject to refund through the fiscal year ended September 30, 2004. Accordingly, there was no effect on earnings for fiscal year 2004 or 2005 for the rates initially put into effect in February 2004.

      The Stipulation also provided for a one-time credit to all Virginia customers of $3.2 million for certain regulatory liabilities that were previously recorded by Washington Gas. This one-time credit was made to customers during the January 2005 billing cycle. Providing this credit to customers did not have an effect on the earnings of the Company or Washington Gas for the fiscal year ended September 30, 2005. The Stipulation also required Washington Gas to file with the SCC of VA annual earnings test calculations based on a twelve-month period ended December 31; such calculations are being estimated by Washington Gas quarterly, and when appropriate, accounting adjustments are being recorded.

      On January 31, 2005, Washington Gas filed a proposed Weather Normalization Adjustment clause (WNA) with the SCC of VA to be implemented as an experimental pilot program. The proposed WNA was intended to reduce the effect of weather volatility from normal levels both on customers’ bills and on the earnings of Washington Gas. The proposed implementation date of the WNA by Washington Gas was January 1, 2006, with the first adjustments to customer bills in November 2006 based on a calculation for the eight months ended August 2006. All other parties to the case took positions in opposition to the Company’s WNA filing, including recommendations that a base rate proceeding was a more appropriate forum for a WNA to be considered.

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      On October 6, 2005, after hearings had been held on this matter, a Hearing Examiner of the SCC of VA issued a report on the Company’s application for the proposed WNA. The Hearing Examiner recommended to the SCC of VA that Washington Gas’ application to implement its proposed WNA be denied. On December 1, 2005, the SCC of VA denied Washington Gas’ request to implement its proposed WNA. Washington Gas is permitted to file a subsequent request with the SCC of VA for a WNA in the context of a general rate proceeding.

UTILITY GAS SUPPLY AND PIPELINE TRANSPORTATION AND STORAGE CAPACITY

     Supply and Capacity Requirements

       Washington Gas arranges to have natural gas delivered to the entry points of its distribution system (city gates or gate station) using the delivery capacity of interstate pipeline companies, and also uses on-system peaking facilities to meet requirements. Washington Gas acquires interstate pipeline natural gas delivery and storage capacity on a system-wide basis on the different interstate pipelines to provide the greatest amount of flexibility to meet the diverse demand characteristics of its customer base. Washington Gas’ supply and capacity plan is based on forecasted system requirements, and takes into account estimated load growth by type of customer, attrition, conservation, demand by gate station, interstate pipeline and storage capacity and contractual limitations and the forecasted movement of customers between sales service and delivery service.

      Pursuant to FERC Order No. 636, interstate pipeline companies are required to provide transportation and storage services to natural gas shippers, such as Washington Gas. At September 30, 2005, Washington Gas had service agreements with four pipeline companies that provided direct service for firm transportation and/or storage services. These contracts have expiration dates ranging from fiscal years 2006 to 2024.

      Washington Gas is responsible for acquiring both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. As such, Washington Gas must contract for reliable and adequate delivery capacity to its distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, its own on-system natural gas peaking facilities, as well as the characteristics of its customer base. Washington Gas’ contracting activities take into account customers’ tendencies to switch between sales and delivery service; however, short-term contractual arrangements required to manage such customer choice diversity may not be available in future periods under conditions of capacity constraints. Washington Gas has adopted a diversified portfolio approach designed to satisfy the supply and deliverability requirements of its customers, using multiple supply points, dependable interstate pipeline transportation and storage arrangements, and its own substantial storage and peaking capabilities to meet its customers’ demands. Washington Gas anticipates enhancing its peaking capacity by constructing a liquefied natural gas (LNG) peaking facility that is expected to be completed and placed in service by the 2008-2009 winter heating season. Washington Gas’ proposed location for this peaking facility is being opposed by certain external parties. The opponents have not presented any technical support for their positions. The Company cannot predict that this facility will be built as planned. However, Washington Gas has an alternate plan to satisfy its customer requirements, that although significantly more expensive for customers, could be utilized to meet peak day demand requirements (refer to the section entitled “Liquidity and Capital Resources—Capital Expenditures” in Management’s Discussion included under Item 7 of this report for a further discussion of this construction project).

      Local distribution companies, such as Washington Gas, along with other participants in the energy industry have raised concerns regarding the gradual depletion in the availability of additional interstate pipeline and storage capacity. Depleting pipeline and storage capacity is a business issue that must be managed by Washington Gas, whose customer base has grown at an annual rate of two to three percent. This rate of growth is expected to continue. The increased number of electric generation facilities that exist and are planned in the near future for the mid-Atlantic region and upstream of the mid-Atlantic region that are fueled by natural gas exacerbates concerns associated with the availability of pipeline and storage capacity. These facilities, which utilize significant pipeline and storage capacity, may ultimately affect

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deliverability and flexibility of natural gas delivery into the region. Due to the reluctance on the part of both marketers and some local distribution companies in committing to long-term pipeline contracts, pipeline infrastructure improvements have been limited despite the fact that the major pipelines serving the Washington Gas system are fully subscribed. In response to growing concerns, interstate pipelines have begun the process of offering infrastructure improvements that will expand pipeline and storage capacity in the mid-Atlantic region. These improvement projects, funded through incremental demand charges by the participating entities, require a minimum of two to three years to complete the planning, solicitation of interest, regulatory approval and construction. Recent projects to expand firm transportation and/or storage capacity completed or in progress, are outlined below:

      Washington Gas will continue to monitor other opportunities to acquire or participate in obtaining additional pipeline and storage capacity that will improve or maintain the high level of service expected by its customer base.

     Sources of Natural Gas

       Annual Sendout. As reflected in the table below, there were six sources of delivery through which the regulated utility received natural gas to satisfy the sendout requirements in pipeline year 2005 (November 1, 2004 through October 31, 2005), and from which supplies can be received in pipeline year 2006 (November 1, 2005 through October 31, 2006). Firm transportation denotes gas transported directly to the entry point of Washington Gas’ distribution system in contractually viable volumes. Transportation storage denotes volumes stored by a pipeline during the summer injection season for withdrawal and delivery to the Washington Gas distribution system during the heating season to meet load requirements. Peak load requirements are met by: (i) underground natural gas storage at the Hampshire storage field in Hampshire County, West Virginia; (ii) the local production of propane air plants located at Washington Gas-

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owned facilities in Rockville, Maryland (Rockville Station) and in Springfield, Virginia (Ravensworth Station) and (iii) other peak-shaving sources. Unregulated third-party marketers acquire interstate pipeline and storage capacity and the natural gas commodity on behalf of Washington Gas’ delivery service customers, some of which may be provided through transportation, storage and peaking resources provided by Washington Gas to unregulated third-party marketers under tariffs approved by the three public service commissions. These marketers have natural gas delivered to the entry point of Washington Gas’ delivery system on behalf of those utility customers that have decided to acquire their natural gas commodity on an unbundled basis, as previously discussed.

      During pipeline year 2005 (November 1, 2004 through October 31, 2005), total sendout on the system was 1.676 billion therms, as compared to total sendout of 1.673 billion therms during pipeline year 2004. This excludes the sendout of sales and deliveries of natural gas used for electric generation. The decrease in 2005 was the result of weather in pipeline year 2005 that was warmer than pipeline year 2004. The sendout for pipeline year 2006 is estimated at 1.681 billion 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 2005 and those projected for pipeline year 2006 are shown in the following table.

      Design Day Sendout. The effectiveness of Washington Gas’ 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 natural gas distribution system during a 24-hour period assuming a five-degree Fahrenheit average temperature. Washington Gas assumes that all interruptible customers will be curtailed on the design day. Washington Gas’ current design day demand forecast for the 2005-2006 winter season is 17.7 million therms, and Washington Gas’ projected sources of delivery for design day sendout is 18.6 million therms. This provides a reserve margin of approximately 5.1 percent. Washington Gas is currently capable of meeting 72 percent of its design day requirements with storage and peaking capabilities. Optimal utilization of storage and peaking facilities on Washington Gas’ design day reduces the dependency on firm transportation and reduces pipeline capacity costs. The following table reflects the sources of delivery that are projected to be used to satisfy the design day sendout estimate for pipeline year 2006.

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      Gulf Coast Natural Gas Supply Issues. Since the late summer of 2005, the Gulf Coast region has experienced a major disruption of natural gas production and processing due to hurricanes Katrina, Rita and Wilma. Such natural gas production and processing disruptions have resulted in a significant reduction of the normal 10 billion cubic feet of natural gas per day available to be delivered from the Gulf Coast region. Current forecasts (by the Federal Government and other public information from various energy sources that are monitoring the status of gas flowing from the Gulf Coast) suggest a resumption to near normal levels of natural gas production and processing during the course of the 2005-2006 winter heating season, but they are not specific as to a scheduled timeframe nor the expected volume. Based on its evaluation of these forecasts, Washington Gas currently estimates that only approximately 70 to 80 percent of the pre-hurricane natural gas production and processing from the Gulf Coast region will be available for the 2005-2006 winter heating season.

      As discussed above, the sources of Washington Gas’ natural gas supply for annual, seasonal and design day delivery include firm transportation gas purchased and delivered through four interstate pipelines, gas in storage (stored in facilities that are both company-owned and leased from the interstate pipelines), various peaking facilities, and unregulated third-party marketers. Washington Gas has already delivered and injected into storage sufficient quantities of gas to maximize the availability of natural gas from its storage resources to meet customer demand for the 2005-2006 winter heating season. Washington Gas is also prepared with sufficient gas inventories in its local and contracted third-party peaking resources to attempt to satisfy this demand.

      Historically, more than 85 percent of Washington Gas’ firm transportation natural gas purchased and delivered through its contracted interstate pipeline services has been supplied from the Gulf Coast, traditionally a region where gas supply has been readily available on a daily basis. Immediately following hurricanes Katrina, Rita and Wilma, the amount of natural gas available to be introduced into the interstate pipelines in the Gulf Coast region was curtailed and allocated among the various shippers, including Washington Gas, that use interstate pipelines. To date, Washington Gas has continued to meet its customers’ daily natural gas requirements and has achieved its required storage inventory balances through natural gas purchases subsequent to the hurricanes. However, customer demand for natural gas in the mid-Atlantic and Northeast regions has not yet increased to reflect the demand of the upcoming winter heating season. Washington Gas believes that the Gulf Coast natural gas supply to be transported through its contracted interstate pipeline services for the 2005-2006 winter heating season may be subject to certain limitations. Those limitations will be a function of customer demand (colder-than-normal weather) and the degree to which natural gas production and processing actually resume at normal operational capabilities.

      Based on this view, Washington Gas has modified the composition of its natural gas portfolio by updating its traditional purchasing plan for the 2005-2006 winter heating season to include a significantly higher percentage of natural gas supply that is produced from sources outside of the Gulf Coast region. For the 2005-2006 winter heating season, Washington Gas estimates that approximately 60 percent (rather than the traditional 85 percent) of its firm transportation natural gas purchases and deliveries will come from the Gulf Coast region. Washington Gas anticipates that it will rely upon other sources outside the Gulf Coast region for the remaining 40 percent of these purchases, including natural gas from the Appalachian and Canadian regions, as well as increased levels of vaporized LNG through the Dominion Cove Point (Dominion or Cove Point) LNG terminal. These natural gas supplies will be delivered to Washington Gas’ distribution system utilizing existing interstate pipeline resources under contract to Washington Gas that have transportation paths that support natural gas deliveries outside the Gulf Coast region.

      Assuming the current forecast for the resumption of Gulf Coast natural gas production and processing is accurate, Washington Gas currently estimates that the quantity of alternative sources of supply that it has included in its natural gas portfolio for the 2005-2006 winter heating season will be sufficient to replace the loss of its traditional Gulf Coast natural gas supply due to ongoing, but slowly diminishing limitations in Gulf Coast natural gas production and processing. This estimate includes the natural gas volumes that are the responsibility of unregulated third-party marketers in the regulated utility’s jurisdictional retail unbundling programs. Washington Gas, as a provider of last resort, is ultimately responsible for serving its firm customers (both bundled and unbundled), and has incorporated that responsibility into its estimate.

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      Conversely, if Gulf Coast natural gas production and processing constraints remain at reduced levels of deliverability, then Washington Gas, under normal or colder-than-normal weather conditions during its 2005-2006 winter heating season, may need to implement contingency plans in order to maximize the number of customers served under such conditions. Contingency plans include requests to conserve to the general population and targeted curtailments to specific sections of the system, consistent with curtailment tariffs approved by regulators in each of its three jurisdictions. If requests to conserve are issued by Washington Gas or curtailments of supply result, the deliveries of natural gas that will be made by Washington Gas will be lower than the levels that would otherwise be expected. If this occurs, the Company’s net revenues and net income would be adversely affected by lower deliveries of natural gas, an amount that management cannot estimate.

      Beyond the 2005-2006 winter heating season, Washington Gas will seek to maintain diversification of its natural gas portfolio that incorporates other sources of supply outside the Gulf Coast region. This will help Washington Gas to meet customer demand despite unforeseen future supply issues that may arise similar to those resulting from weather events in the Gulf Coast region.

     Rising Natural Gas Prices

       Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. As discussed above, the hurricanes in the Gulf Coast region during the late summer and early fall seasons of 2005 significantly reduced the current and anticipated availability of natural gas supply, causing a dramatic rise in natural gas prices during the fourth quarter of fiscal year 2005. The higher natural gas prices will result in significant increases in bills to customers during the upcoming 2005-2006 winter heating season. Under its regulated gas cost recovery mechanisms, Washington Gas records cost of gas expense equal to the cost of gas recovered in revenues from customers. Accordingly, an increase in the cost of gas due to an increase in the purchase price of the natural gas commodity generally has no direct effect on the regulated utility’s net revenues and net income. However, net income may be reduced primarily due to higher expenses that may be incurred for uncollectible customer accounts, as well as lower volumes of natural gas deliveries to firm customers that may result due to lower natural gas consumption caused by customer conservation. Increases in the price of natural gas also can affect the Company’s operating cash flows, as well as the competitiveness of natural gas as an energy source (refer to the section entitled “Competition— Competition with Other Energy Products” included herein).

     Changes in Natural Gas Consumption

       Natural gas supply requirements may be affected by changes in natural gas consumption by customers. Natural gas usage per customer may decline as customers change their consumption patterns in response to: (i) more volatile and higher natural gas prices, as discussed above, and (ii) customers’ replacement of older, less efficient gas appliances with more efficient appliances. In each jurisdiction in which Washington Gas operates, changes in customer usage profiles have been reflected in recent rate case proceedings where rates have been adjusted to reflect current customer usage. In both the District of Columbia and Virginia jurisdictions, changes in customer usage by existing customers that occur subsequent to these recent rate case proceedings will have the effect of reducing revenues, which is offset by the favorable effect of adding new customers. Effective October 1, 2005, pursuant to a revenue normalization adjustment mechanism approved by the PSC of MD, changes in customer usage by existing customers that occur subsequent to recent rate case proceedings in the Maryland jurisdiction generally will not reduce revenues, but rather will have the effect of stabilizing the level of distribution charge revenues received from customers on a monthly basis (refer to the section entitled “Jurisdictional Rates and Regulatory Matters— Maryland Jurisdiction” for a further discussion of this billing adjustment mechanism).

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COMPETITION

     Competition with Other Energy Products

       The regulated utility faces competition based on customers’ preference for natural gas compared to other energy products and the comparative prices of those products. The most significant product competition occurs between natural gas and electricity in the residential market. The residential market generates a significant portion of the regulated utility’s net income. In its service territory, Washington Gas continues to attract the majority of the new residential construction market. Consumers’ continuing preference for natural gas allows Washington Gas to maintain a strong market presence.

      The regulated utility has generally maintained a price advantage over electricity in its service area for traditional uses of energy such as heating, water heating and cooking. However, price volatility in the wholesale natural gas commodity market has resulted in significant increases in the cost of natural gas billed to customers (refer to the section entitled “Gas Supply and Capacity— Rising Natural Gas Prices” included herein). Such increases have resulted in the elimination of the traditional price advantage of natural gas. Price advantages that electricity has are also partially caused by artificial price caps on electricity sold by electric utilities. These price caps change in June of each year in Maryland and the District of Columbia, and will expire in December 2010 in Virginia. The cost of generating electricity is affected by the cost of fuel used to generate electricity. As the prices of those fuels rise and existing supply contracts for those fuels between electric generators and fuel suppliers expire, the price of electricity may rise in relation to the current price for natural gas. Furthermore, as discussed 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 marketers of electricity participating in retail markets. Electric industry restructuring may result in lower comparative pricing for electric service and other alternative energy sources, including natural gas. These changes could result in increased competition for the regulated utility.

      In the interruptible market, the regulated utility’s customers must be capable of using a fuel other than natural gas when demand peaks for the regulated utility’s firm customers. In the interruptible market, fuel oil is the prevalent energy alternative to natural gas. The regulated utility’s success in this market depends largely on the relationship between natural gas and oil prices. The supply of natural gas primarily is derived from domestic sources, and the relationship between supply and demand generally has the greatest impact on natural gas prices. As a large portion of oil comes from foreign sources, political events can have significant influences on oil supplies and, accordingly, oil prices. The introduction of non-domestic supplies of LNG into the United States natural gas market may affect supply levels and have an impact on natural gas prices. To date, the effect of LNG on supply levels has been minimal.

     Deregulation

       In each of the jurisdictions (the District of Columbia, Maryland and Virginia) served by the Company’s regulated utility, regulators and utilities have implemented customer choice programs. These programs allow customers to choose to purchase their natural gas and/or electric commodity from unregulated third-party marketers, rather than purchasing these commodities as part of a bundled service from the local utility. When customers choose to purchase their natural gas commodity from unregulated third-party marketers on an unbundled basis, there is no effect on the regulated utility’s net revenues or net income since Washington Gas charges its customers the cost of gas without any mark-up. However, these customer choice programs provide unregulated third-party marketers, such as WGEServices, with opportunities to profit from the sale of the natural gas commodity or electricity in competitive markets. It also enables customers to have competitive choices for natural gas and electricity. Participating in this evolving marketplace also poses risks and challenges that must be addressed in the Company’s current and future strategies.

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     The Natural Gas Delivery Function

       The natural gas delivery function, the core business of the Company’s regulated utility, continues to be regulated by local regulatory commissions. In developing this core business, Washington Gas has invested nearly $2.8 billion as of September 30, 2005 to construct and operate a safe and reliable natural gas distribution system. Because of the high fixed costs and significant safety and environmental considerations associated with building and operating a distribution system, it is expected that there will continue to be only one owner and operator of a natural gas distribution system in the regulated utility’s current franchise area for the foreseeable future. The nature of Washington Gas’ customer base and the distance of most customers from interstate pipelines mitigate the threat of bypass of its facilities by other potential delivery service providers.

      Washington Gas expects that local regulatory commissions will continue to set the prices and terms for delivery service that give it an opportunity to earn a just and reasonable rate of return on the capital invested in its distribution system and to recover reasonable operating expenses. Washington Gas plans to continue constructing, operating and maintaining its natural gas distribution system, and will incur costs necessary to ensure the safety and reliability of its system and that operating issues are addressed in a timely and adequate manner.

     The Merchant Function and Natural Gas Unbundling

       At September 30, 2005, customer choice programs for natural gas customers were available to all of Washington Gas’ regulated utility customers in the District of Columbia, Maryland and Virginia. Of the 1.012 million active customers at September 30, 2005, approximately 152,000 customers purchased their natural gas commodity from unregulated third-party marketers. The following table provides the status of natural gas unbundling in the regulated utility’s major jurisdictions at September 30, 2005. The percentage of the regulated utility’s customers who chose to purchase natural gas from a third-party marketer, including WGEServices, is reflected in the following table.

Status of Customer Choice Programs

At September 30, 2005

      Ultimately, regulators may decide that the Company should exit the merchant function and that all customers should choose to buy natural gas from unregulated third-party marketers. Washington Gas continues to have certain obligations to purchase natural gas from producers and transportation capacity from interstate pipeline companies. Accordingly, the strategy of Washington Gas focuses on managing

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efficiently the portfolio of contractual resources, recovering contractual costs and maximizing the value of contractual assets. As of September 30, 2005, 152,000 customers chose to purchase natural gas from a third-party marketer compared to 181,000 customers as of September 30, 2004.

      Washington Gas actively manages its supply portfolio to balance its sales, delivery and supply obligations. Currently, the regulated utility includes the cost of the natural gas commodity and interstate pipeline services in the purchased gas costs that it includes in firm customers’ rates, subject to regulatory review. The regulated utility’s jurisdictional tariffs contain gas cost mechanisms that allow it to recover the invoice cost of gas, including both the commodity cost of gas and the interstate pipeline services, applicable to firm customers. Additionally as described below, these same tariffs provide for the assignment and recovery of certain capacity and peaking services from the third-party marketers that serve delivery service customers. Washington Gas 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, Washington Gas could be adversely impacted to the extent it incurs non-competitive gas costs without other satisfactory regulatory mechanisms available to recover any costs that may exceed market prices. Washington Gas currently has recovery mechanisms for such potentially stranded costs in the District of Columbia, Maryland and Virginia.

      If Washington Gas were to determine that competition or changing regulation stemming from future unbundling or other initiatives would preclude it from recovering these costs in rates, these costs would be charged to expense without any corresponding revenue recovery. Depending upon the timing, the effect of such a charge on Washington Gas’ financial position and results of operations would likely be significant. If a regulatory body were to disallow the recovery of such costs under a traditional regulatory framework, these costs would be borne by shareholders unless the regulatory body would grant rate relief for such costs in the form of transitioning from bundled to unbundled deregulated services that have been traditionally paid by all customers.

      To minimize its exposure to contract risks, Washington Gas has mechanisms in its customer choice programs that enable it to assign to participating third-party marketers 100 percent of the storage and peak winter capacity resources that were dedicated to serving bundled service customers when those customers elected a third-party marketer. Additionally, Washington Gas currently has mechanisms approved by each of its local commissions to assign certain percentages of transportation capacity resources. Washington Gas continually updates its forecasts of customer growth and the associated requirements for pipeline transportation, storage and peaking resources. Washington Gas is generally renewing pipeline transportation and storage capacity contracts to meet its forecasts of increased customer gas requirements and to comply with regulatory mechanisms to provide for or make available such resources to marketers serving customers in the customer choice programs.

      To maximize the value of its contractual assets, the regulated utility has entered into contracts with unregulated third-party marketers that make use of the regulated utility’s firm storage and transportation rights to meet the regulated utility’s city gate delivery needs and to make off-system sales when such storage and transportation rights are under-utilized. The regulated utility continues to pay the fixed charges associated with the firm storage and transportation contracts used to make sales.

UNREGULATED RETAIL ENERGY-MARKETING OF NATURAL GAS AND ELECTRICITY

       As the role of regulated utilities in the merchant function may decrease over time, opportunities emerge for unregulated natural gas and electric providers. In the deregulated marketplace, third-party marketers have profit-making opportunities, but also assume the risk of loss.

      In fiscal year 1997, the Company established WGEServices as an unregulated retail energy-marketing subsidiary. WGEServices sells natural gas and electricity to residential, commercial and industrial customers inside and outside of the Washington Gas service area. At September 30, 2005, 2004 and 2003, WGEServices had natural gas customers totaling approximately 144,800, 150,800 and 153,400, respectively. WGEServices had electric customers totaling approximately 36,200, 44,500 and 76,000 at

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September 30, 2005, 2004 and 2003, respectively. WGEServices’ gross revenues for fiscal years 2005, 2004 and 2003 were $773.0 million, $789.9 million and $726.2 million, respectively. WGEServices’ net income was $22.3 million, $8.3 million and $3.7 million for fiscal years 2005, 2004 and 2003, respectively.

      Assuming normal weather, the regulatory process results in relatively stable earnings for the regulated utility; however, there can be significant volatility for unregulated third-party marketers such as WGEServices. During fiscal year 2005, WGEServices earned higher than historical gross margins on its natural gas sales, reflecting various factors including the utilization of greater volumes of lower cost storage inventory to supply customers compared to the prior fiscal year, and a greater spread between the cost of that storage gas and retail prices charged to customers during the current fiscal year in relation to the prior fiscal year. This improvement was further enhanced by: (i) changes in the mark-to-market valuation associated with derivatives contracts used in WGEServices’ gas supply portfolio to reduce the risk of variations in demand caused by weather; (ii) utilizing multiple supply options combined with differing weather patterns during the winter to enhance margins from customer s and (iii) reduced expenses related to the termination of certain contracts for the forward purchase of natural gas in connection with the major disruption of natural gas production and processing caused by hurricanes in the Gulf Coast region during the late summer and early fall of 2005 (refer to the section entitled “Sources of Natural Gas— Gulf Coast Natural Gas Supply Issues” included herein). The conditions that gave rise to the significant increase in earnings of WGEServices in fiscal year 2005 are not expected to result in a similar level of net income in fiscal year 2006.

     Natural Gas Supply

       WGEServices competes with other third-party marketers to sell the unregulated natural gas commodity to customers. Marketers of the natural gas commodity compete largely on price, and gross margins are relatively small. Consequently, operating margins for the sale of unregulated natural gas are typically lower than those earned by the regulated utility.

      In addition, WGEServices faces risks associated with its gas supply. At any point in time, WGEServices may experience a difference between contracted gas purchase quantities and contractual gas sales commitments. To minimize this risk, WGEServices manages its natural gas contract portfolio by closely matching the timing of gas purchases from suppliers with sales commitments to customers. WGEServices also purchases its gas from a number of wholesale suppliers in order to avoid relying on any single provider for its natural gas supply. Additionally, WGEServices maintains gas storage inventory that is assigned to it by natural gas utilities such as Washington Gas. This storage inventory enables WGEServices to meet daily and monthly fluctuations in demand caused by variations in weather from normal. WGEServices may, from time to time, enter into derivative contracts, including weather derivatives, in order to balance its sales commitments with the amount of gas it must purchase to satisfy those commitments, or for purposes of fixing the price at which WGEServices may have to purchase or sell gas. WGEServices has a risk management policy in place and periodically reassesses its policy to determine its adequacy to mitigate risks in changing markets. For a further discussion about WGEServices’ exposure to and management of market risks, refer to the section entitled “Market Risk” included in Management’s Discussion.

      WGEServices purchases a portion of its natural gas supply from the Gulf Coast region for delivery into interstate pipeline systems on which WGEServices holds transportation contracts. Purchase commitments from certain of WGEServices’ Gulf Coast-based natural gas suppliers have been interrupted by the recent supply shortage in the Gulf Coast region as a result of weather events during the fall 2005 season. In September 2005, two of WGEServices’ fixed-price supply contracts for the forward purchase of Gulf Coast-based natural gas were terminated due to the natural gas suppliers’ expected inability to fulfill contractual supply obligations to WGEServices. In consideration of the contract terminations, the suppliers agreed to pay a fee to the energy-marketing business representing the difference between the fixed price and volume of gas under contract and the then market price for forward delivery of the same volume of gas that was purchased by the energy-marketing business to replace the contractual shortfall. In October 2005,

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WGEServices used these fees to replace the gas that was not delivered under the terminated contracts. All of WGEServices’ contracted natural gas supplies from the Gulf Coast region have, however, been flowing as contracted since November 1, 2005, and to date, WGEServices has continued to meet its customers’ daily natural gas requirements and has achieved its required storage inventory balances through natural gas purchases subsequent to the hurricanes.

      In meeting its natural gas supply needs for the 2005-2006 winter heating season and beyond, WGEServices expects to continue to rely on a diverse set of supply sources, including city-gate delivered supplies, natural gas in storage and LNG from the Cove Point terminal.

      Assuming normal weather, WGEServices believes it has adequate natural gas supply to meet the demand of its retail customers under contract for the upcoming winter heating season. Should any suppliers of WGEServices fail to deliver natural gas under existing contracts due to the continuation of supply disruptions in the Gulf Coast region, WGEServices may be financially exposed for the difference between the price at which WGEServices has contracted to buy natural gas, and the replacement cost of the gas that may need to be purchased to serve its customers. Should colder-than-normal weather be experienced in the geographic areas served by WGEServices, the energy-marketing business could be required to secure additional natural gas supplies at unfavorable prices to meet the needs of its customers.

      If WGEServices is unable to secure adequate supplies of natural gas to meet the needs of its retail customers, either due to the failure of its suppliers to deliver gas or the inability to secure additional quantities of natural gas in cold weather, WGEServices may be required to return customers to the bundled services of regulated utilities. If such returns can be managed within standard regulated time frames for returning customers to the utility, WGEServices’ losses would be limited to future margins on returned customers. Should supply limitations be so severe that WGEServices could not supply its customers within those time frames, WGEServices could be exposed to significant penalties by the utility companies.

      WGEServices may be negatively affected by the indirect effects of significant increases in the wholesale price of natural gas that resulted from the Gulf Coast natural gas supply shortage. Although WGEServices’ risk management policies and procedures are designed to minimize the risk that WGEServices’ natural gas purchases and the related sales commitments do not closely match, higher gas prices increase the costs associated with uncollectible accounts, borrowing costs, certain fees paid to public service commissions and other costs. To the extent that these costs cannot be recovered from retail customers in higher rates due to competitive factors, WGEServices’ operating results would be negatively affected.

     Electricity Supply

       Customer choice programs for electric customers have been implemented in each jurisdiction in which the regulated utility operates. Similar to the natural gas industry, participants in these programs can choose either to continue purchasing bundled electricity service from their local electric distribution utility or to purchase electricity from a third-party marketer. WGEServices competes with other third-party marketers to sell electric supply services to customers. Marketers of electric supply service compete largely on price, and gross margins are relatively small.

      Future opportunities to add new electric customers may continue to be limited by the relationship between electric Standard Offer Service (SOS) rates offered by local electric utilities and market prices for electricity. Certain SOS rates in WGEServices’ market area continue to be below current market prices. In certain cases, electric utilities have entered into wholesale contracts to supply their SOS customers, prior to an increase in fuel prices required to generate electricity. In other cases, electric utilities continue to provide service under previously established rates that are capped. SOS rates in Maryland and the District of Columbia will, however, continue to be reset to market rates through annual procurement processes, and may offer future opportunities to build the electric customer base for WGEServices.

      Full Requirements Supply. For a portion of its electricity supply, WGEServices purchases full requirements from wholesale electricity suppliers under master purchase and sale agreements, including electric energy, capacity and certain ancillary services, for resale to retail electric customers. Full

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requirements wholesale suppliers assume the risk for any volume and price risks associated with sales made by WGEServices. WGEServices’ principal supplier of full requirements electricity is Mirant Americas Energy Marketing L.P. (MAEM), which is an indirect wholly owned subsidiary of Mirant Corporation (Mirant). Although the full requirements agreement eliminates the electric supply risk that is associated with changes in demand, the benefits of this contractual provision are only realized to the extent MAEM performs its delivery function. During fiscal years 2005 and 2004, to reduce its reliance upon a single supplier, WGEServices entered into separate master purchase and sale agreements under which it purchases full requirements services from other wholesale electricity suppliers. Electric suppliers other than MAEM accounted for approximately ten percent of WGEServices’ full requirements electric purchases for fiscal year 2005. WGEServices does not own or operate any electric generation, electric transmission or electric distribution assets.

      On July 14, 2003, Mirant and substantially all of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. MAEM, WGEServices’ principal supplier of electricity, was included in these bankruptcy filings. As of October 18, 2005, MAEM had completed performance on all of its supply obligations to WGEServices under contracts entered into prior to the bankruptcy. These pre-bankruptcy petition contracts expired on or before October 18, 2005.

      Non-Full Requirements Supply. In order to improve its competitive position and to further diversify its electricity supply sources, commencing in the second half of fiscal year 2005, WGEServices began procuring electricity supply under contract structures other than full requirements contracts. WGEServices assembled the various components of supply, including electric energy, capacity, ancillary services and transmission service from multiple suppliers to match its customer requirements. This new strategy also reduces the potential credit exposure that WGEServices otherwise faced when dealing almost exclusively with MAEM.

      Under this purchasing approach, WGEServices assumes the responsibility of matching its customer requirements with its supply purchases. To the extent WGEServices is not able to match its customer requirements relatively closely with its supply purchases, it is exposed to electricity commodity price risk on the unmatched portion of its portfolio. WGEServices’ electric business also is exposed to fluctuations in weather. These non-full requirements purchases generally are made under fixed-volume contracts that are based on certain weather assumptions. If there are significant deviations in weather from these assumptions, WGEServices could be exposed to hourly price and volume risk that can negatively impact gross margins. At September 30, 2005, 44 percent of the WGEServices electric supply portfolio was provided under non-full requirements contracts. (refer to the section entitled “Market Risk— Price Risk Related to Retail Energy-Marketing Operations” included in Management’s Discussion).

POTENTIAL FOR FURTHER UNBUNDLING

       Currently, the Company’s regulated utility 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 they subsequently remit to Washington Gas. Although Washington Gas still provides most customer 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.

      To remain competitive, the Company continuously strives to improve quality and efficiency and to reduce costs to achieve market-level performance. Accordingly, the Company will continue to look for opportunities to profit from further unbundling.

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OPERATING ISSUES IN PRINCE GEORGE’S COUNTY, MARYLAND

       On April 1, 2005, Washington Gas reported a significant increase in the number of natural gas leaks on its distribution system in a portion of Prince George’s County, Maryland. Washington Gas determined that these leaks resulted from the shrinkage of seals located in mechanical couplings that connect sections of distribution mains and services. Given the increase in the number of gas leaks, Washington Gas announced that it would replace gas service lines and rehabilitate gas mains that contain the applicable mechanical couplings in the affected area of the distribution system in Prince George’s County (the rehabilitation project). Washington Gas also indicated that it was investigating the reasons for the degradation of the seals in the couplings that were causing the increase in gas leaks in the affected area of Prince George’s County.

      On April 22, 2005, Washington Gas announced its plan to address all leaks in the affected area within approximately six months of their being identified. Washington Gas indicated that it expected to rehabilitate or replace all other applicable coupled service lines and distribution mains in the affected area of Prince George’s County area by the end of December 2007, even if no leaks have been detected.

      The current cost estimate for the rehabilitation project is $144 million. This is a significant increase in planned capital expenditures in fiscal years 2006 through 2008 (refer to the “Liquidity and Capital Resources— Capital Expenditures” section of Management’s Discussion for a table of projected capital expenditures). This current cost estimate does not consider any changes in costs associated with potential remediation steps discussed below. The actual costs that are being incurred for the work associated with this project could differ materially from the cost estimates discussed herein. However, Washington Gas has the financial resources necessary to fund this project due to its current strong cash position, and the financing options it has available.

      Mechanical couplings identical to the couplings in Prince George’s County are located in other portions of Washington Gas’ distribution system, including Virginia, other areas of Maryland, and the District of Columbia. These mechanical couplings were routinely installed on the Washington Gas system from the 1940’s to the early 1970’s. To date, Washington Gas has not experienced any pattern of leaks in these other areas that is comparable to the leak pattern encountered in the affected area of Prince George’s County.

      Management of Washington Gas considers the costs to be incurred related to this matter necessary to provide safe and reliable utility service. Management anticipates that costs such as these eventually will be recognized in the ratemaking process as reasonable. Washington Gas has not yet requested recovery of these costs. However, Washington Gas is considering the effect of these capital expenditures on its ability to earn its allowed rate of return in Maryland, and is evaluating the most appropriate options to enable full and timely recovery of, and return on, the amounts to be expended. There can be no prediction at this time that recovery in rates will be allowed or at what point in time such recovery may begin to be reflected in rates. Significant negative effects on earnings in future years could result if such costs are incurred and recovery in rates is not allowed.

      Washington Gas received a report dated July 1, 2005 from ENVIRON International Corporation (Environ or consultant), working with Polymer Solutions, Inc. and Akron Rubber Development Laboratory that describes the results of its investigation of the causes of the leaks of the couplings in Prince George’s County. All statements made herein regarding the report of Environ are intended to provide a summary of the material aspects of the report and should be considered in the full context of the complete report of Environ. The report of Environ should be read in conjunction with this summary for a full and more complete understanding of the issues. The report of Environ is available in its entirety on WGL Holdings’ Web site, www.wglholdings.com . The report of Environ was also filed as an exhibit to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005.

      As noted in its report, Environ conducted its investigation by: (1) gathering information regarding coupling design and materials, installation practices, leak patterns, gas compositions, geological information, and the experiences of other local distribution companies with similar equipment; (2) developing a list of plausible physical and chemical mechanisms which could contribute to the

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observed leak patterns in the field; (3) constructing a working hypothesis for the observed coupling leaks; (4) designing and conducting experiments to develop the required data to evaluate the hypothesis; and (5) reviewing the experimental data, as well as other information collected during the assignment, to make its best assessment of the most likely causes of the increased leak rate.

      The experiments conducted included exposure tests, in which various seals were immersed in different gas environments for fixed periods, with detailed dimensional, weight and hardness measurements being made before, during and after exposure. A key feature of these tests was the evaluation of a set of seals that had been exposed to a reference pipeline gas composition for a fixed period and was then switched to an LNG composition like that contained in the gas coming out of the Cove Point LNG terminal for a further period. Other sets of seals remained in the reference pipeline gas environment.

      As detailed in the study, tests were conducted on rubber seals removed from leaking and non-leaking mechanical couplings in Prince George’s County to determine an explanation for the failure rates. The investigation reviewed a number of potential causes of failures, including humidity; ground conditions; coupling design; construction techniques and skills; age; and quality and type of materials installed. Many items were ruled out or identified as possible contributors.

      Based on its study, Environ concluded that there is a combination of three contributing factors to the higher leak rates of seals on couplings. One of these is the change in the gas composition resulting from a change in the gas supply arising from the reactivation of the Cove Point terminal. The Cove Point gas has a lower concentration of heavy hydrocarbons (HHCs) than domestic natural gas. A characteristic of the rubber material comprising the seals in the couplings is the ability of the seals to both adsorb and desorb HHCs. When seals are exposed to higher levels of HHCs, they swell in size and cause a tighter seal. However, when gas is introduced that has a lower level of HHCs, the seals shrink in size and there is a greater propensity for those seals to cause the couplings to leak.

      Also considered as contributing factors to a higher failure rate for seals of this nature are the age of the couplings and the colder ground temperature during winter periods. However, both the age of the couplings and the ground temperature are common to couplings in other areas of Washington Gas’ service territory where leak patterns have not been observed like those in the affected area of Prince George’s County.

      The relevant change that explains the higher incidence of leaks in the affected area of Prince George’s County is the composition of the gas resulting from the introduction of Cove Point gas. The Cove Point gas manifests such a change in composition because, during its processing into a liquid prior to importation, certain HHCs are required to be removed. These same HHCs, which are present in domestic natural gas, had previously enabled the flexibility and sealing capability of the rubber seals during their in-service life. The higher failure rate of the rubber seals in the specific geographic area of Prince George’s County results from the proximity of Washington Gas’ gate station to the pipeline (gate stations are entrance points to Washington Gas’ distribution system from a pipeline) that receives Cove Point gas from the LNG terminal for delivery to Washington Gas.

      The Environ report also documents that the adsorption/desorption of HHCs by seal materials is a reversible process. Based on discussions between management and Environ, and examination of testing data and conclusions of another utility that had a similar experience, Washington Gas expects that it is highly possible to reverse the known condition of the seals in the affected area of Prince George’s County, and prevent the emergence of premature failures of mechanical couplings located in the affected area and elsewhere in Washington Gas’ service territory that may receive supplies of Cove Point gas and has mechanical couplings. Washington Gas has requested that the consultant recommend to Washington Gas the optimal gas composition that will cause the effect of the Cove Point gas to reverse the conditions noted to date and that will avoid premature seal shrinkage in the affected area in Prince George’s County and elsewhere on the system. After Washington Gas has received this information from the consultant on the optimal gas composition, it will evaluate its ability to achieve a gas mixture in which this optimal level can

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be attained. Until reversal in the shrinkage of seals has been demonstrated in the field, Washington Gas will continue with its current rehabilitation program in the affected area in Prince George’s County.

      The Company has continued to evaluate the causes and solutions related to the higher failure rate in seals discussed above. Data and analysis continue to confirm that changes in gas composition explain the higher failure rates.

      Washington Gas has not experienced any change in historical leak levels in parts of the system outside of the affected area of Prince George’s County. However, the volume of natural gas coming through the Cove Point pipeline may increase by 80 percent in 2008, and a large portion of that gas may come into the Washington Gas system. Such gas deliveries will come into the Washington Gas system directly from gate stations on the Cove Point pipeline as well as through gate stations on the pipelines that interconnect with Cove Point and receive large volumes of the Cove Point gas. Accordingly, Washington Gas is considering alternative approaches to address the currently affected area of Prince George’s County, as well as the potential effect of Cove Point gas on other portions of Washington Gas’ distribution system affected by the delivery of Cove Point gas in various concentrations at other gate stations.

      The first potential approach is for Dominion to condition all gas leaving the Cove Point terminal by restoring HHCs that were previously removed from the natural gas during the liquefaction process. Such an approach would require equipment to store, condition and inject HHCs at the terminal. As such, it is likely that the cost of this approach could be reflected in the rates charged by Cove Point for LNG terminal and transportation service. Such rates would be subject to the approval of the FERC. This potential approach would require no significant additional investment by Washington Gas downstream at each city gate because all natural gas coming from the Cove Point facility would be interchangeable with domestic natural gas, including gas delivered into the affected area of Prince George’s County. However, even if this approach is implemented, Washington Gas will continue to proceed with its current rehabilitation and special leak surveys of the affected area of Prince George’s County until it has been determined that the situation in the affected area of Prince George’s County has reversed itself. Washington Gas would have to obtain Dominion’s cooperation and support to implement this approach. Further investigation may conclude that this approach may be impractical due to space constraints, existing environmental agreements and other concerns.

      The second potential approach, to be implemented to serve areas that receive relatively large quantities of Cove Point gas and that have mechanically coupled pipe, is to develop a coordinated approach with Cove Point, the LNG shippers and the interconnected interstate pipelines that connect to the Cove Point line, to blend domestically produced natural gas into any stream of Cove Point gas that is distributed by the Cove Point facility and flows into the interconnected pipelines and then into Washington Gas’ distribution system. Such blending, if it can be consistently achieved at appropriate levels, will introduce HHCs present in the domestic sources of natural gas flowing on the interconnected pipelines. Additional studies are underway to confirm the blending requirements. Washington Gas will only be able to implement this approach with the cooperation of all or some of the parties mentioned above related to this approach. Further investigation may conclude that this approach may be impractical in that Dominion and other interstate pipelines may not be able to reliably blend domestically produced natural gas with the LNG in conjunction with other of Washington Gas’ interconnected pipelines. As discussed further below, Washington Gas has recently filed comments and a request for a hearing before the FERC in two Dominion Cove Point expansion certificate applications. In each case, the expansion proposed by Cove Point will introduce significantly more volumes of gas from the Cove Point terminal into the interconnected downstream pipelines.

      The third potential approach is the installation of equipment at each of the gate stations that are most likely to receive a relatively large concentration of Cove Point gas (estimated to be seven stations in total) and add HHCs into the gas stream before it is introduced into Washington Gas’ distribution system. The process of re-injecting HHCs that have been removed during the liquefaction process back into the distribution system is a normal and customary step in many LNG peak-shaving plants. Because of the high concentration of Cove Point gas being received at the gate station that serves the affected area of Prince

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George’s County, Washington Gas has begun to obtain the necessary approvals to construct such a facility to inject HHCs at this particular gate station; this facility is expected to be operational in January 2006, at an estimated additional cost of $1.6 million. Although the installation of the equipment at this gate station may reverse or partially reverse the effect of the Cove Point gas on the distribution system in the affected part of Prince George’s County and reduce the current cost estimate of $144 million, Washington Gas plans to continue the rehabilitation of the area in Prince George’s County and to continue the special leak surveys until there is appropriate evidence that the desired reversal has occurred. Washington Gas has begun the planning necessary to construct similar facilities at the other six gate stations in anticipation that Cove Point gas flowing into the interconnected pipelines may increase prior to 2008. Washington Gas may not need to construct them at all if one or a combination of the other two potential approaches discussed above is implemented; however, it appears to be increasingly unlikely that the other potential approaches will be available or practical. Washington Gas has significant control over the majority of the land, facilities and logistics required to implement this approach, subject to attaining any necessary permitting or authorizations.

      The concept of such a facility is similar in design to Washington Gas’ existing process of odorizing natural gas by injecting natural gas with a chemical that gives it its unique odor. Although small in scale, odorizing natural gas is an automated process completed at each gate station. Facilities needed for injecting HHCs would include a storage tank for the liquid, metering, pumping and injecting equipment. The estimated cost of the acquisition and installation of equipment needed to inject HHCs into the gas stream at Washington Gas gate stations is an average of $1 million at each station, for a total of $7 million at all seven gate stations at which such facilities will potentially be installed. Washington Gas expects that these facilities’ costs should be includible in the rate base upon which Washington Gas is allowed to earn an allowed rate of return. The $7 million cost does not include the cost of the HHCs which Washington Gas anticipates should be includible in its purchased gas adjustment charge.

      Washington Gas is committed to the use of natural gas from the Cove Point terminal to satisfy the needs of its customers. Washington Gas is willing to work with Dominion Cove Point LNG, the shippers who bring LNG into the Cove Point terminal and the interstate pipelines that deliver gas to Washington Gas in order to achieve and implement an appropriate solution to the issue of gas interchangeability affecting its system.

      Washington Gas is also requesting the FERC to invoke its authority for ensuring the safety and reliability of the Cove Point flowing gas through the Washington Gas distribution system. In fiscal year 2005, Dominion requested authorization from the FERC to expand the capacity of its Cove Point LNG terminal. This proposed expansion, if approved, could increase the exposure of other areas within the Washington Gas distribution system to Cove Point gas that may be either minimally blended with pipeline supply or unblended, thereby potentially affecting the safety of the distribution system. On November 2, 2005, Washington Gas filed a protest, a request for an evidentiary hearing, and other requests with the FERC relating to the proposed expansion of the Cove Point LNG terminal. In its protest, Washington Gas requested that the FERC deny Dominion’s request to expand the Cove Point LNG terminal until it has demonstrated that the Cove Point gas is of such quality that it is fully interchangeable with the natural gas historically received by Washington Gas, and that Cove Point gas will not cause harm to its customers or to the infrastructure of Washington Gas’ distribution system. On November 15, 2005, Cove Point filed a request with the FERC to reject Washington Gas’ November 2, 2005 protest. On November 17, 2005, Statoil Natural Gas LLC, BP Energy Company and Shell NA LNG (collectively referred to as the “LTD-1 Shippers”) filed a joint request to the FERC to reject the protest. On November 30, 2005 and December 2, 2005, Washington Gas filed responses to the FERC opposing the requests of Cove Point and LTD-1 Shippers. The Maryland Office of the People’s Counsel and the PSC of MD have filed with the FERC in support of Washington Gas’ request for an evidentiary hearing in order to resolve the issues raised.

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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 effects. Almost all of the environmental liabilities the Company and its subsidiaries have recorded are for costs expected to be incurred to remediate sites where the Company or a predecessor affiliate operated manufactured gas plants (MGP). Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to the following:

      Washington Gas has identified up to ten sites where it or its predecessors may have operated MGPs. Washington Gas last used any such plant in 1984. In connection with these operations, Washington Gas is aware that coal tar and certain other by-products of the gas manufacturing process are present at or near some former sites, and may be present at others. Washington Gas does not believe that any of the sites present any unacceptable risk to human health or the environment.

      At one of the former MGP sites, studies show the presence of coal tar under the site and an adjoining property. Washington Gas 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. Washington Gas received approval from governmental authorities for a comprehensive remediation plan for the majority of the site that will allow commercial development of Washington Gas’ property. Washington Gas has entered into an agreement with a national developer for the development of this site in phases. The first two phases have been completed, with Washington Gas retaining a ground lease on each phase. The owner of the affected adjoining property has developed a final remediation plan for that portion of the site, and Washington Gas will negotiate an agreement with the owner to perform the remediation.

      At a second former MGP site and on an adjacent parcel of land, Washington Gas developed a “monitoring-only” remediation plan for the site. This remediation plan received approval under a state voluntary closure program.

      Washington Gas does not expect that the ultimate impact of these matters will have a material adverse effect on its capital expenditures, earnings or competitive position. Washington Gas believes, at this time, that the appropriate remediation has been or is being undertaken, or that no remediation is necessary at the remaining eight sites. See Note 13 of the Notes to Consolidated Financial Statements for a further discussion of environmental response costs.

OTHER INFORMATION ABOUT THE BUSINESS

       The regulated utility is not dependent upon a single customer or group of customers such that the loss of any one or more of such customers would have a significant adverse effect on the regulated utility. As previously discussed, Washington Gas served over one million customers at September 30, 2005. The Company’s energy-marketing segment is not heavily dependent on any one customer or group of

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customers. The commercial HVAC segment derived approximately 42 percent and 44 percent of revenues from one customer, the Federal Government, in fiscal years 2005 and 2004, respectively.

      The Company’s utility business is weather-sensitive and seasonal 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 2005, 77 percent of the total therms delivered in the regulated utility’s franchise area, excluding deliveries for electric generation occurred in the regulated utility’s first and second fiscal quarters. The Company’s utility earnings are typically generated during these two quarters and the regulated utility historically incurs net losses in the third and fourth fiscal quarters. The timing and level of approved rate increases can affect the results of operations. The seasonal nature of the regulated utility’s business creates large variations in short-term cash requirements, primarily due to the fluctuations in the level of customer accounts receivable, accrued utility revenues and storage gas inventories. Washington Gas finances these seasonal requirements primarily through the sale of commercial paper and unsecured short-term bank loans.

      The operations of WGEServices are also seasonal, with large amounts of electricity being sold in the summer months and large amounts of natural gas being sold in the winter months. Working capital requirements vary significantly during the year, and these variations are financed primarily through the Company’s issuance of commercial paper and unsecured short-term bank loans.

      The Company’s research and development costs during fiscal years 2005, 2004 and 2003 were not material.

      At September 30, 2005, the Company and its wholly owned subsidiaries had 1,868 employees comprising 1,650 utility and 218 non-utility employees.

      The Company’s Code of Conduct, Corporate Governance Guidelines, and charters for the Governance, Audit and Human Resources committees of the Board of Directors are available on the corporate Web site www.wglholdings.com . Copies also may be obtained by request to the Corporate Secretary at WGL Holdings, Inc., 101 Constitution Ave., N.W., Washington, D.C. 20080. The Company makes available free of charge on its corporate Web site, its annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and any amendments thereto, as soon as reasonably practicable after such reports have been electronically filed with or furnished to the Securities and Exchange Commission (SEC). Additional information about WGL Holdings is also available on its Web site. The Company’s Chairman and Chief Executive Officer certified to the New York Stock Exchange (NYSE) on March 1, 2005 that, as of that date, he was unaware of any violation by the Company of the NYSE’s corporate governance listing standards.

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EXECUTIVE OFFICERS OF THE REGISTRANTS

       The names, ages and positions of the executive officers of the registrants at October 1, 2005, are listed below along with their business experience during the past five years. The age of each officer listed is as of the date of filing of this report. There is no family relationship among the officers.

      Unless otherwise indicated, all officers have served continuously since the dates indicated, and all positions are executive officers listed with Washington Gas Light Company.

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Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

Management’s Discussion Table of Contents

EXECUTIVE OVERVIEW

       Introduction

       WGL Holdings , through its wholly owned subsidiaries, sells and delivers natural gas and provides a variety of energy-related products and services to customers primarily in Washington, D.C. and the surrounding metropolitan areas in Maryland and Virginia. The Company’s core subsidiary, Washington Gas , is involved in the delivery and sale of natural gas that primarily is regulated by state regulatory commissions. Through the wholly owned, unregulated subsidiaries of Washington Gas Resources Corporation (Washington Gas Resources), the Company also offers energy-related products and services that are related to its core business. In response to changes in federal and state regulation, the Company offers competitively priced natural gas and electricity to customers through Washington Gas Energy Services ( WGEServices ), its unregulated retail energy-marketing subsidiary.

      WGL Holdings has three operating segments that are described below:

      Transactions not specifically identifiable in one of the above three segments are accumulated and reported in the category “Other Activities.”

      Regulated Utility. With approximately 94 percent of the Company’s consolidated total assets, the regulated utility segment (consisting of Washington Gas and Hampshire Gas Company) delivers natural gas to retail customers in accordance with tariffs approved by the District of Columbia, Maryland and Virginia regulatory commissions that have jurisdiction over Washington Gas’ rates. These rates are intended to provide the regulated utility with an opportunity to earn a just and reasonable rate of return on the investment devoted to the delivery of natural gas to customers. Washington Gas also sells natural gas to customers who have not elected to purchase natural gas from unregulated third-party marketers . The regulated utility does not earn a profit or incur a loss when it sells the natural gas commodity because utility customers are charged for the natural gas commodity at the same cost that the regulated utility incurs. At September 30, 2005, the regulated utility was selling and delivering the natural gas commodity to 84.9 percent of its customers. The remaining 15.1 percent of Washington Gas’ customers utilized the delivery services of Washington Gas for delivery of the natural gas commodity purchased from

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Financial Condition and Results of Operations (continued)

unregulated third-party marketers, one of which is WGEServices. Factors critical to the success of the regulated utility include: (i) operating a safe and reliable natural gas distribution system; (ii) having sufficient natural gas supplies to serve the demand of its customers; (iii)  being competitive with other sources of energy such as electricity, fuel oil and propane and (iv) being able to recover the costs and expenses of this business in the rates it charges to customers. These costs and expenses include a just and reasonable rate of return on invested capital as authorized by the regulatory commissions having jurisdiction over the regulated utility’s rates. Hampshire Gas Company (Hampshire), a wholly owned subsidiary of WGL Holdings, operates an underground natural gas storage facility that is regulated by the Federal Energy Regulatory Commission (FERC). Washington Gas purchases all of the storage services of Hampshire and includes the cost of these services in the bills sent to its customers. Hampshire operates under a “pass-through” cost of service-based tariff approved by the FERC, and adjusts its billing rates to Washington Gas on a periodic basis to account for changes in its investment in utility plant and associated expenses.

      Retail Energy-Marketing. WGEServices, a wholly owned subsidiary of Washington Gas Resources, competes with other unregulated third-party marketers by selling natural gas and electricity directly to residential, commercial and industrial customers, both inside and outside of the regulated utility’s traditional service territory. WGEServices does not own or operate any natural gas or electric generation, production, transmission or distribution assets. Rather, it sells natural gas and electricity with the objective of earning a profit, and these commodities are delivered to retail customers through the assets owned by regulated utilities, such as Washington Gas or other unaffiliated natural gas or electric utilities. Factors critical to the success of the retail energy-marketing business are: (i) managing the market risk of the difference between the sales price committed to customers under sales contracts and the cost of natural gas and electricity needed to satisfy these sales commitments; (ii) managing credit risks associated with customers of and suppliers to this segment; (iii) having sufficient deliverability of natural gas and electric supplies to serve the demand of its customers which can be affected by the ability of natural gas producers, pipeline gatherers, natural gas processors, interstate pipelines and suppliers of electricity to deliver the respective commodities and (iv)  controlling the level of selling, general and administrative expenses, including customer acquisition expenses.

      Commercial HVAC. Two wholly owned subsidiaries of Washington Gas Resources, American Combustion Industries, Inc. ( ACI ) and Washington Gas Energy Systems, Inc. ( WGESystems ), provide turnkey, design-build and renovation projects, and maintenance services to the commercial and government markets. The commercial HVAC operations focus on retrofitting the mechanical, electrical and energy-related systems of a large number of aging commercial and government structures, primarily in the District of Columbia and portions of Maryland and Virginia. Factors critical to the success of the commercial HVAC business include: (i) generating adequate revenue from the government and private sectors in the new construction and retrofit markets; (ii) building a stable base of service relationships; (iii) estimating and managing fixed-price contracts and (iv) controlling selling, general and administrative expenses.

      Refer to the Business section under Item 1 of this report for a further discussion of the Company’s regulated utility and unregulated businesses. For a further discussion of the Company’s financial performance by operating segment, refer to Note 16 of the Notes to Consolidated Financial Statements.

       Key Indicators of Financial Condition and Operating Performance

       Management believes that the following are key indicators for monitoring the Company’s financial condition and operating performance:

      Return on Average Common Equity. This measure is calculated by dividing twelve months ended net income (applicable to common stock) by average common shareholders’ equity. For the regulated utility, management compares the actual return on common equity with the return on common equity that is allowed to be earned by regulators and the return on equity that is necessary for the Company to compensate investors sufficiently and be able to continue to attract capital.

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      Common Equity Ratio. This ratio is calculated by dividing total common shareholders’ equity by the sum of common shareholders’ equity, preferred stock and long-term debt (including current maturities). Maintaining this ratio in the mid-50 percent range affords the Company financial flexibility and access to long-term capital at relatively low costs. Refer to the section entitled “Liquidity and Capital Resources—General Factors Affecting Liquidity” included herein for a discussion of the Company’s capital structure.

PRIMARY FACTORS AFFECTING WGL HOLDINGS AND WASHINGTON GAS

       The following is a summary discussion of the primary factors that affect the operations and/or financial performance of the regulated and unregulated businesses of WGL Holdings and Washington Gas. Refer to the section entitled “Business” under Item 1 of this report for a more detailed discussion of these and other related factors that affect the operations and/or financial performance of WGL Holdings and Washington Gas.

       Weather Conditions and Weather Patterns

       The Company’s regulated utility operations are weather sensitive, with a significant portion of its revenues derived from the delivery of natural gas to residential and commercial heating customers during the winter season. Generally, weather conditions directly influence the volume of natural gas delivered by the regulated utility. However, weather patterns may become erratic during “shoulder” months within the Company’s fiscal year in which the Company is going into or coming out of the primary portion of its winter heating season. During the shoulder months within quarters ending December 31 (particularly in October and November) and within quarters ending June 30 (particularly in April and May), customer heating usage may not correlate highly with the level of recorded heating degree days during those months when weather patterns experienced are not consistently cold or warm.

      The regulated utility’s rates are determined on the basis of expected normal weather conditions. As such, deviations in weather from normal levels can affect the Company’s financial performance. Prior to October 1, 2005, Washington Gas did not have a ratemaking provision in any of its jurisdictions that allowed for revenues to be adjusted for the difference between actual weather conditions in a particular year and the expected normal weather conditions that are used to establish rates. Instead, the regulated utility had a five-year weather insurance policy designed to protect against a portion of warmer-than-normal weather for all of its jurisdictions. This weather insurance policy expired on September 30, 2005.

      During fiscal year 2005, Washington Gas initiated efforts to obtain ratemaking provisions in Maryland and Virginia that are designed to moderate the volatility of its revenues and customers’ monthly billing due to variations in weather from normal levels. In August 2005, Washington Gas received approval from the Public Service Commission of Maryland ( PSC of MD ) to implement a Revenue Normalization Adjustment mechanism (RNA), a billing adjustment mechanism that is designed to stabilize the level of distribution charge revenues received from Maryland customers as a result of deviations in customer usage caused by variations in weather from normal levels and other matters such as conservation. The RNA became effective on October 1, 2005, which is the start of the Company’s fiscal year 2006.

      Additionally, in January 2005, Washington Gas filed a proposed Weather Normalization Adjustment clause (WNA) with the State Corporation Commission of Virginia ( SCC of VA ) to be implemented as an experimental pilot program. The WNA was intended to reduce the effect of weather volatility from normal levels both on customers’ bills and on the earnings of Washington Gas. On December 1, 2005, the SCC of VA denied Washington Gas’ request to implement the proposed WNA, but will permit the regulated utility to file a subsequent request for the WNA in the context of a general rate proceeding (refer to the section entitled “Rates and Regulatory Matters” under Item 1 of this report). On December 8, 2005, Washington Gas purchased a weather derivative as another form of weather protection to mitigate warmer-than-normal weather in Virginia.

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      Washington Gas has not sought a similar ratemaking provision with the Public Service Commission of the District of Columbia ( PSC of DC ). However, effective October 1, 2005, the regulated utility obtained a new three-year weather insurance policy designed to protect against nearly all of the effects of warmer-than-normal weather in the District of Columbia.

      The financial results of the Company’s energy-marketing subsidiary, WGEServices, also are affected by deviations in weather from normal levels. Since WGEServices sells both natural gas and electricity, WGEServices’ financial results may fluctuate due to deviations in weather from fiscal year to fiscal year during the winter heating and summer cooling seasons.

      Refer to the section entitled “Weather Risk” included herein for a further discussion of the Company’s weather protection mechanisms.

       Regulatory Environment and Regulatory Decisions

       Washington Gas is regulated by the PSC of DC, the PSC of MD and the SCC of VA. Hampshire is regulated by the FERC. These regulatory commissions set the rates in their respective jurisdictions that Washington Gas can charge customers for its rate-regulated services. Changes in these rates as ordered by regulatory commissions affect the Company’s financial performance.

      Washington Gas expects that regulatory commissions will continue to set the prices and terms for delivery service that give it an opportunity to earn a just and reasonable rate of return on the capital invested in its distribution system and to recover reasonable operating expenses.

      WGL Holdings is a registered holding company as defined by the Public Utilities Holding Company Act of 1935 (PUHCA). On August 8, 2005, the President of the United States of America signed the Energy Policy Act of 2005 (EPA 2005), which authorizes many broad energy policy provisions including significant funding for consumers and business for energy related activities, energy related tax credits, accelerated depreciation for certain natural gas utility infrastructure investments and which contains the repeal of the PUHCA. The effective date of the repeal is February 8, 2006. The Company continues to evaluate the EPA 2005, but it expects to benefit from provisions embedded in the legislation that will support the Company’s efforts to promote energy efficiency in a manner that benefits customers and shareholders (refer to the section entitled “Business” under Item 1 of this report for a detailed discussion of this matter).

       Gas Supply and Pipeline Transportation and Storage Capacity

       Natural Gas Supply and Capacity Requirements. Washington Gas is responsible for acquiring both sufficient natural gas supplies and interstate pipeline and storage capacity to meet customer requirements. As such, Washington Gas must contract for reliable and adequate delivery capacity to its distribution system, while considering the dynamics of the interstate pipeline and storage capacity market, its own on-system peaking facilities, as well as the characteristics of its customer base.

      Local distribution companies, such as Washington Gas, along with other participants in the energy industry, have raised concerns regarding the gradual depletion in the availability of additional interstate pipeline and storage capacity. Depleting pipeline and storage capacity is a business issue that must be managed by Washington Gas, whose customer base has grown at an annual rate between two and three percent. This rate of growth is expected to continue. To help maintain the adequacy of pipeline and storage capacity for its growing customer base, Washington Gas has contracted with various interstate pipeline and storage companies for the acquisition of additional existing capacity, as well as the construction of new capacity, for firm transportation and storage services to Washington Gas. One recent project involving Washington Gas for the construction of new firm transportation and storage services was completed and placed into service for the 2004-2005 winter heating season, adding 250,000 therms of daily transportation capacity, 400,000 therms of daily storage transportation capacity and 28 million therms of annual storage inventory for Washington Gas. Washington Gas is involved in other capacity expansion projects that are expected to be placed into service during fiscal years 2006-2010. Washington Gas will continue to monitor

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other opportunities to acquire or participate in obtaining additional pipeline and storage capacity that will improve or maintain the high level of service expected by its customer base.

      Gulf Coast Natural Gas Supply Issues. Since the late summer of 2005, the Gulf Coast region has experienced a major disruption of natural gas production and processing due to hurricanes Katrina, Rita and Wilma. Such natural gas production and processing disruptions have resulted in a significant reduction of the normal 10 billion cubic feet of natural gas per day available to be delivered from the Gulf Coast region. Current forecasts (by the Federal Government and other public information from various energy sources that are monitoring the status of gas flowing from the Gulf Coast) suggest a resumption to near normal levels of natural gas production and processing during the course of the 2005-2006 winter heating season, but they are not specific as to a scheduled timeframe nor the expected volume. Based on its evaluation of these forecasts, Washington Gas currently estimates that only approximately 70 to 80 percent of the pre-hurricane natural gas production and processing from the Gulf Coast region will be available for the 2005-2006 winter heating season.

      The sources of Washington Gas’ natural gas supply for annual, seasonal, and design day delivery include firm transportation gas purchased and delivered through four interstate pipelines, gas in storage (stored in facilities that are both company-owned and leased from the interstate pipelines), various peaking facilities, and unregulated third-party marketers. Washington Gas has already delivered and injected into storage sufficient quantities of gas to maximize the availability of natural gas from its storage resources to meet customer demand for the 2005-2006 winter heating season. Washington Gas is also prepared with sufficient gas inventories in its local and contracted third-party peaking resources to attempt to satisfy this demand.

      Historically, more than 85 percent of Washington Gas’ firm transportation natural gas purchased and delivered through its contracted interstate pipeline services has been supplied from the Gulf Coast, traditionally a region where gas supply has been readily available on a daily basis. Immediately following hurricanes Katrina, Rita and Wilma, the amount of natural gas available to be introduced into the interstate pipelines in the Gulf Coast region was curtailed and allocated among the various shippers, including Washington Gas, that use interstate pipelines. To date, Washington Gas has continued to meet its customers’ daily natural gas requirements and has achieved its required storage inventory balances through natural gas purchases subsequent to the hurricanes. However, customer demand for natural gas in the mid-Atlantic and Northeast regions has not yet increased to reflect the demand of the upcoming winter heating season. Washington Gas believes that the Gulf Coast natural gas supply to be transported through its contracted interstate pipeline services for the 2005-2006 winter heating season may be subject to certain limitations. Those limitations will be a function of customer demand (colder-than-normal weather) and the degree to which natural gas production and processing actually resume at normal operational capabilities.

      Based on this view, Washington Gas has modified the composition of its natural gas portfolio by updating its traditional purchasing plan for the 2005-2006 winter heating season to include a significantly higher percentage of natural gas supply that is produced from sources outside of the Gulf Coast region. For the 2005-2006 winter heating season, Washington Gas estimates that approximately 60 percent (rather than the traditional 85 percent) of its firm transportation natural gas purchases and deliveries will come from the Gulf Coast region. Washington Gas anticipates that it will rely upon other sources outside the Gulf Coast region for the remaining 40 percent of these purchases, including natural gas from the Appalachian and Canadian regions, as well as increased levels of vaporized liquefied natural gas (LNG) through the Dominion Cove Point (Dominion or Cove Point) LNG terminal. These natural gas supplies will be delivered to Washington Gas’ distribution system utilizing existing interstate pipeline resources under contract to Washington Gas that have transportation paths that support natural gas deliveries outside the Gulf Coast region.

      Assuming the current forecast for the resumption of Gulf Coast natural gas production and processing is accurate, Washington Gas currently estimates that the quantity of alternative sources of supply that it has included in its natural gas portfolio for the 2005-2006 winter heating season will be sufficient to replace

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the loss of its traditional Gulf Coast natural gas supply due to ongoing, but slowly diminishing limitations in Gulf Coast natural gas production and processing. This estimate includes the natural gas volumes that are the responsibility of unregulated third-party marketers in the regulated utility’s jurisdictional retail unbundling programs. Washington Gas, as a provider of last resort, is ultimately responsible for serving its firm customers (both bundled and unbundled), and has incorporated that responsibility into its estimate.

      Conversely, if Gulf Coast natural gas production and processing constraints remain at reduced levels of deliverability, then Washington Gas, under normal or colder-than-normal weather conditions during its 2005-2006 winter heating season, may need to implement contingency plans in order to maximize the number of customers served under such conditions. Contingency plans include requests to conserve to the general population and targeted curtailments to specific sections of the system, consistent with curtailment tariffs approved by regulators in each of its three jurisdictions. If requests to conserve are issued by Washington Gas or curtailments of supply result, the deliveries of natural gas that will be made by Washington Gas will be lower than the levels that would otherwise be expected. If this occurs, the Company’s net revenues and net income would be adversely affected by lower deliveries of natural gas, an amount that management cannot estimate.

      Beyond the 2005-2006 winter heating season, Washington Gas will seek to maintain diversification of its natural gas portfolio that incorporates other sources of supply outside the Gulf Coast region. This will help Washington Gas to meet customer demand despite unforeseen future supply issues that may arise similar to those as a result of the weather events in the Gulf Coast region.

      WGEServices also purchases a portion of its natural gas supply from the Gulf Coast region. Purchase commitments from certain of WGEServices’ Gulf Coast-based natural gas suppliers have been interrupted by the recent supply shortage in the Gulf Coast region caused by weather events during the 2005 fall season. All of WGEServices’ contracted natural gas supplies from the Gulf Coast region have, however, been flowing as contracted since November 1, 2005, and to date, WGEServices has continued to meet its customers’ daily natural gas requirements, and has achieved its required storage inventory balances through natural gas purchases subsequent to the hurricanes. In meeting its natural gas supply needs for the 2005-2006 winter heating season and beyond, WGEServices expects to continue to rely on a diverse set of supply sources.

      Assuming normal weather, WGEServices believes it has adequate natural gas supply to meet the demand of its retail customers under contract for the upcoming winter heating season. Should any suppliers of WGEServices fail to deliver natural gas under existing contracts due to the continuation of supply disruptions in the Gulf Coast region, WGEServices may be financially exposed for the difference between the price at which WGEServices has contracted to buy natural gas, and the replacement cost of the gas that may need to be purchased to serve its customers. Should colder-than-normal weather be experienced in the geographic areas served by WGEServices, the energy-marketing business could be required to secure additional natural gas supplies at unfavorable prices to meet the needs of its customers.

      If WGEServices is unable to secure adequate supplies of natural gas to meet the needs of its retail customers, either due to the failure of its suppliers to deliver gas or the inability to secure additional quantities of natural gas in cold weather, WGEServices may be required to return customers to the bundled services of regulated utilities. If such returns can be managed within standard regulated timeframes for returning customers to the utility, WGEServices’ losses would be limited to future margins on returned customers. Should supply limitations be so severe that WGEServices could not supply its customers within those timeframes, WGEServices could be exposed to significant penalties by the utility companies.

      Refer to the section entitled Business under Item 1 of this report for a detailed discussion of this matter.

      Rising Natural Gas Prices. Increased prices of natural gas are being driven by increased demand that is exceeding the growth in available supply. As discussed above, the fall 2005 hurricane season significantly reduced the current and anticipated availability of natural gas supply from the Gulf Coast region, causing a dramatic rise in natural gas prices during the fourth quarter of fiscal year 2005. If

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continued, the higher natural gas prices may result in significant increases in the cost of gas billed to customers during the upcoming 2005-2006 winter heating season. Under its regulated gas cost recovery mechanisms, Washington Gas records cost of gas expense equal to the cost of gas recovered in revenues from customers. Accordingly, an increase in the cost of gas due to an increase in the purchase price of the natural gas commodity generally has no direct effect on the regulated utility’s net revenues and net income. However, net income may be reduced primarily due to higher expenses that may be incurred for uncollectible customer accounts, as well as lower volumes of natural gas deliveries to firm customers that may result due to lower natural gas consumption caused by customer conservation. Increases in the price of natural gas also can affect the Company’s operating cash flows, as well as the competitiveness of natural gas as an energy source.

      WGEServices may also be negatively affected by the indirect effects of significant increases in the wholesale price of natural gas that resulted from the Gulf Coast natural gas supply issues. Although WGEServices’ risk management policies and procedures are designed to minimize the risk that WGEServices’ natural gas purchases and the related sales commitments do not closely match, higher gas prices increase the costs associated with uncollectible accounts, borrowing costs, certain fees paid to public service commissions and other costs. To the extent that these costs cannot be recovered from retail customers in higher rates due to competitive factors, WGEServices’ operating results would be negatively affected.

      Changes in Natural Gas Consumption. Natural gas supply requirements may be affected by changes in natural gas consumption by customers. Natural gas usage per customer may decline as customers change their consumption patterns in response to: (i) more volatile and higher natural gas prices, as discussed above, and (ii) customers’ replacement of older, less efficient gas appliances with more efficient appliances. In each jurisdiction in which Washington Gas operates, changes in customer usage profiles have been reflected in recent rate case proceedings where rates have been adjusted to reflect current customer usage. In both the District of Columbia and Virginia jurisdictions, changes in customer usage by existing customers that occur subsequent to these recent rate case proceedings will have the effect of reducing revenues, which is offset by the favorable effect of adding new customers. Effective October 1, 2005, pursuant to the RNA approved by the PSC of MD, changes in customer usage by existing customers that occur subsequent to recent rate case proceedings in the Maryland jurisdiction generally will not reduce revenues, but rather will have the effect of stabilizing the level of distribution charge revenues received from customers on a monthly basis (for a further discussion of this regulatory matter, refer to the section entitled “Rates and Regulatory Matters” under Item 1 of this report and Note 14 of the Notes to Consolidated Financial Statements).

      Electricity Supply. Similar to the natural gas industry, electric customers may choose either to purchase bundled electricity service from their local electric distribution utility or to purchase electricity from a third-party marketer, such as WGEServices. Future opportunities to add new electric customers may be limited by the relationship between electric Standard Offer Service (SOS) rates offered by local electric utilities and market prices for electricity. Certain SOS rates in WGEServices’ market area continue to be below current market prices. In certain cases, electric utilities have entered into wholesale contracts to supply their SOS customers, prior to an increase in fuel prices required to generate electricity. In other cases, electric utilities continue to provide service under previously established rates that are capped. SOS rates in Maryland and the District of Columbia will, however, continue to be reset to market rates through annual procurements, and may offer future opportunities to build the electric customer base. Refer to the section entitled “Market Risk—Price Risk Related to Retail Energy-Marketing Operations” for a further discussion of WGEServices’ electricity supply.

       Maintaining the Safety and Reliability of the Natural Gas Distribution System

       Maintaining and improving the public safety and reliability of Washington Gas’ natural gas distribution system is the Company’s highest priority that benefits both customers and investors through lower costs and improved customer service. Washington Gas continually refines its safety practices, with a particular

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focus on design, construction, maintenance, operation, replacement, inspection and monitoring practices. Operational issues affecting the public safety and reliability of Washington Gas’ natural gas distribution system that are not responded to within a timely and adequate manner could significantly and adversely affect the future earnings and cash flows of the Company, as well as result in a loss of customer confidence. The Company believes it is responding to its operational issues in a timely and adequate manner, and has the financial resources necessary to address these issues due to its current strong cash position, and the financing options it has available.

       Competitive Environment

       Competition with Other Energy Products. The regulated utility faces competition based on customers’ preference for natural gas compared to other energy products and the comparative prices of those products. The most significant product competition occurs between natural gas and electricity in the residential market. The residential market generates a significant portion of the regulated utility’s net income. In its service territory, Washington Gas continues to attract the majority of the new residential construction market. Consumers’ continuing preference for natural gas allows Washington Gas to maintain a strong market presence.

      The regulated utility has generally maintained a price advantage over electricity in its service area for traditional uses of energy such as heating, water heating and cooking. However, price volatility in the wholesale natural gas commodity market has resulted in significant increases in the cost of natural gas billed to customers. Such increases have resulted in the elimination of the traditional price advantage of natural gas. However, electricity prices may also increase in the future as prices charged for fuel to generate electricity under existing contractual arrangements are renegotiated. Changes in the competitive position of natural gas have the potential to cause a decline in the number of natural gas customers added in future years. At the present time, the regulated utility has seen no evidence of such a decline.

      In the interruptible market, the regulated utility’s customers must be capable of using a fuel other than natural gas when demand peaks for the regulated utility’s firm customers. In the interruptible market, fuel oil is the prevalent energy alternative to natural gas. The regulated utility’s success in this market depends largely on the relationship between natural gas and oil prices. Since the supply of natural gas primarily is derived from domestic sources, the relationship between supply and demand generally has the greatest impact on natural gas prices. Since a large portion of oil comes from foreign sources, political events can have significant influences on oil supplies and, accordingly, oil prices. The introduction of non-domestic supplies of LNG into the United States natural gas market may affect supply levels and have an impact on natural gas prices. To date, the effect of LNG on supply levels has been minimal.

      Deregulation and Unbundling. In each of the jurisdictions served by the Company’s regulated utility, regulators and utilities have customer choice programs. These programs allow customers to choose to purchase their natural gas and/or electric commodity from unregulated third-party marketers, rather than purchasing these commodities as part of a bundled service from the local utility. When customers choose to purchase their natural gas commodity from unregulated third-party marketers on an unbundled basis, there is no effect on the regulated utility’s net revenues or net income since Washington Gas charges its customers the cost of gas without any mark-up. However, these customer choice programs provide unregulated third-party marketers, such as WGEServices, with opportunities to profit from the sale of the natural gas commodity or electricity in competitive markets. It also enables customers to have competitive choices for natural gas and electricity. Successfully participating in this evolving marketplace also poses risks and challenges that must continue to be addressed in the Company’s current and future strategies.

      Currently, the regulated utility includes the cost of the natural gas commodity and interstate pipeline services in the purchased gas costs that it includes in firm customers’ rates, subject to regulatory review. The regulated utility’s jurisdictional tariffs contain gas cost mechanisms that allow it to recover the invoice cost of gas, including both the commodity cost of gas and the interstate pipeline services, applicable to firm customers. If Washington Gas were to determine that competition or changing regulation stemming

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from future unbundling or other initiatives would preclude it from recovering these costs in rates, these costs would be charged to expense without any corresponding revenue recovery. Depending upon the timing, the effect of such a charge on Washington Gas’ financial position and results of operations would likely be significant. In the event that a regulatory body disallows the recovery of such costs, these costs would be borne by shareholders unless the regulatory body would grant the rate relief for such costs in the form of transitioning from bundled to unbundled deregulated services that have been traditionally paid by all customers.

      To manage this risk, Washington Gas has mechanisms in its customer choice programs that enable it to assign to participating unregulated third-party marketers 100 percent of the storage and peak winter capacity resources that were dedicated to serving bundled service customers when those customers elected an unregulated third-party marketer. Additionally, Washington Gas currently has mechanisms approved by each of its local commissions to assign certain percentages of transportation capacity resources. Washington Gas generally is renewing pipeline transportation and storage capacity contracts to meet its forecasts of increased customer gas requirements and to comply with regulatory mechanisms to provide for or make available such resources to marketers serving customers in the customer choice programs.

      Unregulated Retail Energy-Marketing. The Company’s unregulated subsidiary, WGEServices, competes with other unregulated third-party marketers to sell the natural gas commodity to customers. Marketers of the natural gas commodity compete largely on price, and gross margins are relatively small. WGEServices also competes with other unregulated third-party marketers to sell electric supply services to customers. As with natural gas, marketers of electric supply service compete largely on price, and gross margins are relatively small. WGEServices is exposed to credit and market risks associated with both its natural gas and electric supply (refer to the sections entitled “Market Risk” and “Credit Risk” included herein for a further discussion of this risk exposure and WGEServices’ management of them).

       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 effects. Washington Gas believes, at this time, that appropriate remediation has been or is being undertaken at all the relevant sites. Refer to Note 13 of the Notes to Consolidated Financial Statements for a further discussion of these matters.

       Industry Consolidation

       In recent years, the energy industry has seen a number of consolidations, combinations, disaggregations and strategic alliances. 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.

      From time to time, the Company performs studies and, in some cases, holds discussions regarding utility and energy-related investments and strategic transactions with other companies. The ultimate effect on the Company of any such investments and transactions that may occur cannot be determined at this time.

       Economic Conditions and Interest Rates

       The Company and its subsidiaries operate in one of the fastest growing regions in the nation. The continued prosperity of this region, supported by a relatively low interest-rate environment for new housing, has allowed the Company’s regulated utility to expand its regulated delivery service customer base at a rate of growth approximately twice the national industry average during the past five years. In

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addition, this economy has provided a robust market for the Company’s subsidiaries to market natural gas, electricity and other energy-related products and services. A downturn in the economy of the region in which the Company operates, or a significant increase in interest rates which cannot be predicted with accuracy, might adversely affect the Company’s ability to grow its regulated utility customer base and other businesses at the same rate they have grown in the past.

      The Company has been operating in a relatively low interest-rate environment in the recent past as it relates to long-term debt financings. Short-term interest rates had been relatively low in relation to historical levels. However, actions and communications by the Federal Reserve in the past year have resulted in increases in short-term interest rates and have signaled a likely continuation of these increases. A rise in interest rates without the recognition of the higher cost of debt in the rates charged by the regulated utility to its customers would adversely affect future earnings. A rise in short-term interest rates would negatively affect the results of operations of the Company’s retail energy-marketing segment which depends on short-term debt to finance its accounts receivable and storage gas inventories.

       Inflation/Deflation

       From time to time, the Company’s regulated utility seeks approval for rate increases from regulatory commissions to help it manage the effects of inflation on its capital investment and returns. The most significant impact of inflation is on the regulated utility’s replacement cost of plant and equipment. While the regulatory commissions, having jurisdiction over the regulated utility’s retail rates, allow depreciation only on the basis of historical cost to be recovered in rates, the Company anticipates that its regulated utility should be allowed to recover the increased costs of its investment and earn a return thereon, after replacement of the facilities occurs.

      To the extent the Company’s regulated utility experiences a sustained deflationary economic environment, actual returns on invested capital could rise and exceed returns allowed by regulators in previous regulatory proceedings. If this were to occur, it could prompt the initiation of a regulatory review to reduce the revenue of the regulated utility.

       Labor Contracts, Including Labor and Benefit Costs

       The Company has five labor contracts with three labor unions. Teamsters Local Union No. 96 (Local 96) is a local union affiliated with the International Brotherhood of Teamsters. Local 96 has a three-year labor contract with Washington Gas that began on June 1, 2004. The contract covers approximately 700 employees. The contract with the Office and Professional Employees International Union Local 2 is a three-year contract that began on April 1, 2003, and it currently covers approximately 340 members. Local 96, representing union-eligible employees in the Shenandoah Gas division of Washington Gas, has a three-year labor contract with Washington Gas that began on July 30, 2004. This contract covers 23 employees. Additionally, the Company has two three-year labor contracts with the International Brotherhood of Electrical Workers Local 1900 that, together, cover approximately 32 employees.

       Changes in Accounting Principles

       The Company cannot predict the effect of potential future changes in accounting regulations or practices, that have yet to be issued, on its operating results and financial condition. New accounting standards could be issued by the Financial Accounting Standards Board (FASB) or the Securities and Exchange Commission (SEC) that could change the way the Company records and recognizes revenues, expenses, assets and liabilities. These changes in accounting standards could affect the Company’s reported earnings.

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CRITICAL ACCOUNTING POLICIES

       Preparation of financial statements and related disclosures in compliance with Generally Accepted Accounting Principles in the United States of America (GAAP) requires the selection and the application of appropriate technical accounting rules to the relevant facts and circumstances of the Company’s operations, as well as the use of estimates by management to compile the consolidated financial statements. The application of these accounting policies involves judgment regarding estimates and projected outcomes of future events, including the likelihood of success of particular regulatory initiatives, the likelihood of realizing estimates for legal and environmental contingencies, and the probability of recovering costs and investments in both the regulated utility and non-utility operations.

      The Company has identified six critical accounting policies discussed below that require management’s judgment and estimation, where such estimates have a material effect on the consolidated financial statements.

       Accounting for Unbilled Revenue and Cost of Gas Recognition

       For regulated deliveries of natural gas, Washington Gas reads meters and bills customers on a cycle basis. It accrues revenues for gas that has been delivered but not yet billed at the end of an accounting period. In connection with making this accrual, Washington Gas must estimate the amount of gas that cannot be accounted for on its delivery system, and must estimate the amount of the unbilled revenue by jurisdiction and customer class. Such revenues are recognized as unbilled revenues that are adjusted in subsequent periods when actual meter readings are taken. A similar computation is made for WGEServices.

      The regulated utility’s jurisdictional tariffs contain mechanisms that provide for the recovery of the invoice cost of gas applicable to firm customers. Under these mechanisms, the regulated utility periodically adjusts its firm customers’ rates to reflect increases and decreases in the invoice cost of gas. Annually, the regulated utility reconciles the difference between the total gas costs collected from firm customers and the invoice cost of gas paid to suppliers. The regulated utility defers any excess or deficiency and either recovers it from, or refunds it to, customers over a subsequent twelve-month period.

       Accounting for Regulatory Operations—Regulatory Assets and Liabilities

       A significant portion of the Company’s business is subject to regulation by independent third-party regulators. As the regulated utility industry continues to address competitive market issues, the cost-of-service regulation used to compensate the Company’s regulated utility 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 long-term financial implications for the Company. Management has relied on its projection of continued regulatory oversight of its operations in order to validate the carrying cost of the regulated utility’s investment in fixed assets.

      Washington Gas accounts for its regulated operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation , which results in differences in the application of GAAP between regulated and unregulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue or expense in unregulated businesses. In certain circumstances, SFAS No. 71 allows entities whose rates are determined by third-party regulators to defer costs as “regulatory” assets on the balance sheet to the extent that the entity expects to recover these costs in future rates. Similarly, SFAS No. 71 requires that certain amounts be deferred and recorded as regulatory liabilities to the extent the regulated utility expects those amounts will be refunded to customers in future rates. Future regulatory changes or changes in the competitive environment could result in the Company and Washington Gas discontinuing the application of SFAS No. 71 for some of its businesses and require the write-off of the portion of any regulatory asset or liability that would be no longer probable of recovery or refund. In effect,

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the Company’s regulated utility could be required to write off certain regulatory assets and liabilities that had been deferred on the Consolidated Balance Sheets in prior periods, and charge or credit these amounts to income at the time it determines that the provisions of SFAS No. 71 no longer apply. If Washington Gas were required to discontinue the application of SFAS No. 71 for any of its operations, it would record an extraordinary non-cash charge or credit to income for the net book value of its regulatory assets and liabilities. Other adjustments might also be required.

      Management believes that currently available facts support the continued application of SFAS No. 71 for the Company’s regulatory activities, and that all of its regulatory assets and liabilities as of September 30, 2005 and 2004 are recoverable or refundable through the regulatory environment.

       Accounting for Income Taxes

       The Company accounts for income taxes in accordance with SFAS No. 109, Accounting for Income Taxes . Under SFAS No. 109, the Company recognizes deferred income taxes for all temporary differences between the financial statement and tax basis of assets and liabilities at currently enacted income tax rates.

      SFAS No. 109 also requires recognition of the additional deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes of the regulated utility. 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. Amounts applicable to income taxes due from and due to customers primarily represent differences between the book and tax basis of net utility plant in service. Any significant differences between management’s estimates and actual tax amounts could have a material impact on the Company’s operating results and financial condition.

       Accounting for Contingencies

       The Company accounts for contingent liabilities utilizing SFAS No. 5, Accounting for Contingencies . By their nature, the amount of the contingency and the timing of a contingent event are subject to management’s judgment of such events and management’s estimates of the amounts. Actual results related to contingencies may be difficult to predict and could differ significantly from the estimates included in reported earnings. In fiscal years 2005 and 2004, the Company was involved with regulatory contingencies with respect to rate cases in Virginia and various legal contingencies.

      On February 26, 2004, Washington Gas placed a proposed revenue increase into effect, subject to refund, pending the SCC of VA’s final decision on an expedited rate case proceeding. On September 27, 2004, the SCC of VA issued a Final Order requiring the Company to adjust its billing rates to Virginia customers to reflect the level of annual revenues approved pursuant to a December 18, 2003 Final Order of the SCC of VA. Refunds to customers, with interest, were made during the December 2004 billing cycle for the amount of the proposed annual revenue increase that had been collected since February 26, 2004. The Company’s financial results for the fiscal year ended September 30, 2004 reflected the proposed revenue increase, along with a provision for rate refunds to customers. Washington Gas initially recorded this provision for rate refunds throughout fiscal year 2004 based on management’s judgment of the future outcome, and later increased the provision in the fourth quarter of fiscal year 2004 in response to the September 27, 2004 Final Order, to reflect the full amount of revenues that had been collected subject to refund through September 30, 2004. Accordingly, there was no effect on net income for fiscal year 2004 or 2005 for the rates initially put into effect in February 2004.

      In a Final Order issued by the SCC of VA on December 18, 2003, the SCC of VA ordered, among other things, that an annual earnings test be performed to determine if Washington Gas had earned in excess of its allowed rate of return on common equity for its Virginia operations. In the fiscal year ended September 30, 2004, Washington Gas recorded additional depreciation expense of $1.0 million, on a pre-tax basis, in connection with its earnings test performed for the twelve-month period ended December 31,

Washington Gas Light Company

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

2003. In fiscal year 2005, the SCC of VA issued an Order concluding that Washington Gas did not earn in excess of its allowed rate of return on common equity for the twelve-month period ended December 31, 2003 and, therefore, was not required to record any additional depreciation expense related to earnings for that period. Accordingly, in fiscal year 2005, Washington Gas reversed the $1.0 million of depreciation expense, on a pre-tax basis, that it had previously recorded in fiscal year 2004 related to this earnings test. Any significant differences between management’s and the VA Staff’s earnings test calculations or methodology would have an effect on the Company’s operating results. For further discussion of these regulatory activities and related contingencies, see Note 14 of the Notes to Consolidated Financial Statements. The Company believes it has properly applied and recorded the necessary provisions under SFAS No. 5 associated with all material contingencies.

      ACI is engaged in binding arbitration proceedings with a general contractor. ACI claims that it was wrongfully terminated in January 2003 from completing work on behalf of the general contractor and is attempting to recover its accounts receivable. In the same matter, the general contractor has made a counterclaim against ACI for costs that it incurred to complete the project and legal fees. ACI has potential exposure for the sum of its receivable from the contractor and the amount of the counterclaim. This amount is estimated to be a maximum of $4.4 million. At the present time, the Company can not predict the outcome of the arbitration.

       Accounting for Derivative Instruments

       The Company enters into forward contracts and other related transactions for the purchase of natural gas and electricity. A majority of these contracts qualify as normal purchases and sales, and are exempt from the accounting requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities , as amended. Contracts that qualify as derivative instruments under SFAS No. 133 are recorded on the balance sheet at fair value. Changes in the fair value of derivative instruments subject to SFAS No. 71 are recorded as regulatory assets or liabilities, as discussed below, while changes in the fair value of derivative instruments not affected by rate regulation are reflected in income. Washington Gas also utilizes derivative instruments that are designed to minimize the risk of interest-rate volatility associated with planned issuances of Medium-Term Notes (MTNs).

      Management’s judgment is required in determining the appropriate accounting treatment for Washington Gas’ derivative instruments. This judgment involves various factors, including management’s ability to: (i)  designate contracts and other activities as derivative instruments subject to the accounting guidelines of SFAS No. 133; (ii)  derive the estimated fair value of its derivative instruments from period to period based on prices available from external sources and internal modeling techniques; and (iii)  determine whether or not its derivative instruments are recoverable from or refundable to customers in future periods.

      Certain of the Company’s natural gas forward contracts and other derivatives that are subject to SFAS No. 133 are valued using models developed by the Company. These models reflect, when appropriate, derivative pricing theory, formulated market inputs and forward price projections beyond the period that prices are available from market data sources. The Company derived a $23.6 million net fair value gain for these contracts at September 30, 2005, which reflects management’s best estimate.

      As previously discussed, changes in the fair value of forward contracts and other related transactions that qualify as derivative instruments under SFAS No. 133 and subject to SFAS No. 71 are recorded as regulatory assets or liabilities since they relate to activities of the regulated utility in which costs are likely to be recovered from or refunded to customers in future periods. Accordingly, changes in their fair value are recorded as regulatory assets or liabilities. Should management determine that certain of its derivative instruments are not recoverable or refundable to customers, Washington Gas’ financial results may be subject to increased volatility from period to period due to potentially significant changes in the estimated fair value of derivative instruments that may occur and be recorded to either other comprehensive income (loss) or results of operations.

Washington Gas Light Company

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

      Accounting for Pension and Other Post-Retirement Benefit Plans

      Washington Gas maintains a qualified, trusteed, non-contributory defined benefit pension plan covering all active and vested former employees of Washington Gas (qualified pension plan), and a separate unfunded supplemental retirement plan covering executive officers (SERP). Washington Gas also provides certain healthcare and life insurance benefits for retired employees. (The qualified pension plan, SERP and health and post-retirement plans are hereinafter collectively referred to as the “Plans”).

      The measurement of the Plans’ obligations and costs is dependent on a variety of factors. These factors include historical information, such as employee demographics, the level of contributions made to the Plans, and earnings on the Plans’ assets. Additionally, the Company considers the following assumptions to be critical to the measurement of the Plans’ obligations and costs. These assumptions are derived on an annual basis with the assistance of a third party actuarial firm:

      The Company determines its discount rate based on the Moody’s AA corporate bond yield as of September 30. The discount rate used to calculate the net periodic benefit obligations under the Plans was 5.50 percent and 5.75 percent for fiscal years 2005 and 2004, respectively. The discount rate used to calculate the net periodic benefit costs under the Plans was 5.75 percent, 6.00 percent and 6.50 percent for fiscal years 2005, 2004 and 2003, respectively.

      The Company determines the expected long-term rate of return by averaging the expected earnings for the target asset portfolio. In developing the Company’s expected rate of return assumption, the Company evaluates an analysis of historical actual performance and long-term return projections, which gives consideration to the Company’s asset mix and anticipated length of obligation of the Plans.

      For its qualified pension plan, the Company calculated its benefit costs using an expected long-term return on plan assets of 8.25 percent for both fiscal years 2005 and 2004, and 8.50 percent for fiscal year 2003. The expected long-term return on plan assets for the health and life benefit plan was 7.25 percent for both fiscal years 2005 and 2004, and 8.25 percent for fiscal year 2003. Historically, the expected long-term return on plan assets has been lower for the health and life benefit plan than for the qualified pension plan due to differences in the allocation of the assets in the plan trusts.

      The Company calculates the rate of compensation increase based on salary expectations for the near-term, expected inflation levels and promotional expectations. The Company assumed the rate of compensation increase for the Plans to be 4.00 percent for fiscal years 2005, 2004 and 2003.

      The healthcare cost trend rate is determined by working with insurance carriers, reviewing historical claims data for the health and life benefit plan, and analyzing market expectations. The Company assumed the initial healthcare cost trend rates related to the Accumulated Post-Retirement Benefit obligation for Medicare and non-Medicare eligible retirees to be 10.96 percent and 9.25 percent, respectively, for fiscal year 2005, as compared to 12.00 percent and 10.00 percent, respectively, for fiscal year 2004. The Company expects these rates to decrease gradually to 5.75 percent and 5.50 percent, respectively, in 2010 and remain at those levels thereafter.

Washington Gas Light Company

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

      The following table illustrates the effect of changing the critical actuarial assumptions discussed above, while holding all other assumptions constant:

      Differences between actuarial assumptions and actual plan results are deferred and amortized into cost when the accumulated differences exceed ten percent of the greater of the Projected Benefit Obligation or the market-related value of the plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.

      Refer to Note 11 of the Notes to Consolidated Financial Statements for a further discussion of the accounting for the Plans.

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

WGL HOLDINGS, INC.

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

$0.06 per share; and (iv)  a reduction in income taxes of $2.1 million, or $0.04 per share, resulting from the utilization of capital loss carryforwards associated with the Company’s non-utility activities.

      The following table summarizes the Company’s net income (loss) by operating segment for fiscal years ended September 30, 2005, 2004 and 2003.

     Regulated Utility Operating Results

       The operating results of the Company’s core regulated utility operations are the primary influence on consolidated operating results. The regulated utility operations are weather sensitive, with a significant portion of revenue coming from deliveries of natural gas to residential and commercial heating customers.

      For the fiscal year ended September 30, 2005, the regulated utility segment reported net income of $87.5 million, or $1.79 per share, compared to net income of $89.0 million, or $1.82 per share, for fiscal year 2004. This earnings comparison primarily reflects a decrease in total natural gas deliveries to firm customers of 28.7 million therms , or 2.2 percent, to 1.282 billion therms delivered during fiscal year 2005. Although natural gas deliveries fell by 2.2 percent, weather was unchanged in fiscal year 2005 when compared to the prior fiscal year. Weather for fiscal year 2005, when measured by an industry standard called heating degree days, was 5.9 percent colder than normal, and was estimated to have improved net income in fiscal year 2005 in relation to normal weather by approximately $5 million, or $0.10 per share. For fiscal year 2004, weather was 6.1 percent colder than normal, and was estimated to have improved net income by approximately $10 million, or $0.20 per share.

      The decrease in natural gas deliveries to firm customers is due, in part, to warmer weather experienced primarily during the second quarter of fiscal year 2005, the most significant period of the Company’s winter heating season. However, during other periods within fiscal year 2005, the Company experienced lower than expected natural gas deliveries because the increase in heating degree days did not correlate highly with the change in the volume of gas delivered during those periods. While weather conditions generally have a direct influence on the volume of natural gas delivered by the regulated utility, weather patterns may become erratic during “shoulder” months within the fiscal year in which the Company is going into or coming out of the primary portion of its winter heating season. During the shoulder months within quarters ending December 31 (particularly in October and November) and June 30 (particularly in April and May), customer heating usage may not correlate highly with the level of recorded heating degree days during those months when weather patterns experienced are not consistently cold or warm. Thus, as evidenced in fiscal year 2005, usage patterns may not correlate highly with the level of degree days in periods that include shoulder months.

      Favorably affecting earnings for the regulated utility segment for fiscal year 2005 was the addition of 22,043 active customer meters, an increase of 2.2 percent since the end of the prior fiscal year. The current fiscal year also benefited from the favorable effect of changes in rates charged to customers that were

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

implemented in Maryland on November 6, 2003 and in the District of Columbia on November 24, 2003, as well as $2.1 million, or $0.03 per share, of increased revenues associated with the recovery from customers of carrying costs on a higher balance of storage gas inventory that was primarily a result of higher natural gas prices. Washington Gas earns the pre-tax cost of capital on the varying levels of storage gas inventory as a result of regulatory orders in all three of its jurisdictions.

      Fiscal year 2005 earnings for the regulated utility segment also reflect a $10.6 million (pre-tax), or $0.14 per share, increase in operation and maintenance expenses. The 4.7 percent year-over-year increase in these expenses primarily reflects: (i)  $6.9 million of higher employee benefits expenses principally related to post-retirement benefit costs; (ii)  $2.1 million of higher expenses associated with performing the initial assessment of internal controls in accordance with Section 404 of the Sarbanes-Oxley Act; (iii)  $2.2 million of higher expenses for uncollectible accounts primarily due to higher natural gas prices; and (iv)  $1.9 million of higher labor-related expenses which, in part, reflect increased overtime incurred in connection with the Company-wide response to issues that arose in a portion of the Company’s distribution system in Prince George’s County, Maryland, such as special leak surveys, emergency response site visits and repairs, partially mitigated by the effect of 2.7 percent fewer employees and reduced employee severance costs. Partially offsetting the increase in these expenses was the inclusion in fiscal year 2004 of a $2.4 million accrual for unusual operational expenses that was not incurred in the current fiscal year. Further discussion of operation and maintenance expenses of the regulated utility is included herein under Management’s Discussion for Washington Gas.

      Depreciation and amortization expense for fiscal year 2005 declined by $1.7 million (pre-tax), or $0.02 per share. The lower expense is attributable, in part, to a reversal in the current fiscal year of $1.0 million of depreciation expense that was previously estimated and recorded in fiscal year 2004 related to the performance of an earnings test required by a December 18, 2003 Final Order by the SCC of VA (2003 Virginia rate order). The decline in this expense in fiscal year 2005, when compared to 2004, is also due to the inclusion in fiscal year 2004 of depreciation expense of $3.5 million (pre-tax), or $0.04 per share, applicable to the period from January 1, 2002 through November 11, 2002, that was recorded in connection with the 2003 Virginia rate order (refer to Note 14 of the Notes to Consolidated Financial Statements for a further discussion of the Company’s regulatory activities and related contingencies). The year-over-year reduction in this expense was partially offset by depreciation and amortization expense in the current fiscal year related to an increased investment in property, plant and equipment.

      The regulated utility segment also benefited in fiscal year 2005 from reduced income tax expense due to a combination of lower pre-tax income and a lower effective income tax rate. The lower income tax rate is primarily attributable to an increased non-taxable benefit in fiscal year 2005 associated with a Medicare prescription drug subsidy, and a favorable tax adjustment totaling $2.5 million. This segment incurred $3.9 million (pre-tax), or $0.05 per share, of increased general taxes, partially offset by $1.5 million (pre-tax), or $0.02 per share, of lower interest expense (refer to the section entitled “Interest Expense” included herein).

      For the fiscal year ended September 30, 2004, the regulated utility segment reported net income of $89.0 million, or $1.82 per share, compared to net income of $109.0 million, or $2.24 per share, for fiscal year 2003. This comparison reflects a decrease in total gas deliveries to firm customers of 74.6 million therms, or 5.4 percent, to 1.311 billion therms delivered during fiscal year 2004, primarily due to 11.6 percent warmer weather in fiscal year 2004 than in fiscal year 2003, partially mitigated by the addition of 30,140 active customer meters, an increase of 3.1 percent. Weather in fiscal year 2004 was 6.1 percent colder than normal, and was estimated to have improved net income in fiscal year 2004 in relation to normal weather by approximately $10 million, or $0.20 per share. During fiscal year 2003, weather was 19.8 percent colder than normal, enhancing net income by an estimated $25 million, or $0.51 per share, for that year. In addition to utility customer growth, fiscal year 2004 benefited from the impact of rate changes that were implemented in Maryland on November 6, 2003, in the District of Columbia on November 24, 2003, and the effect of approximately one and one-half months of a rate decision that became effective in Virginia in November 2002. Earnings for fiscal year 2004, when compared to the prior fiscal year, also were affected by $10.5 million, or $0.13 per share, of increased operation and maintenance expenses, and

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

$8.0 million, or $0.10 per share, of increased depreciation and amortization expense. Fiscal year 2003 also included an after-tax gain of $2.5 million, or $0.05 per share, realized from the sale of the Company’s former headquarters property, and an adjustment to income taxes that improved net income in fiscal year 2003 by $2.7 million, or $0.06 per share.

      Further discussion of the operating results of the regulated utility is included herein in the Management’s Discussion for Washington Gas.

     Non-Utility Operating Results

       The Company’s non-utility operations are comprised of two business segments: 1) retail energy-marketing and 2) commercial HVAC. Certain of the Company’s transactions are not significant enough to report as stand-alone business segments, and therefore are aggregated as “Other Activities” which are included as part of non-utility operations for purposes of segment reporting (refer to Note 16 of the Notes to Consolidated Financial Statements).

      Total net income for the Company’s non-utility operations for fiscal year 2005 was $16.0 million, or $0.32 per share, an increase of $8.3 million, or $0.16 per share, over fiscal year 2004. This increase includes $14.0 million, or $0.28 per share, of increased earnings from the retail energy-marketing segment to $22.3 million, or $0.45 per share. This was coupled with a $1.5 million, or $0.03 per share, improvement in operating results from the commercial HVAC segment to a net loss of $3.9 million, or $0.08 per share, in fiscal year 2005. Other activities included in non-utility operations for fiscal year 2005 declined $7.2 million, or $0.15 per share, from fiscal year 2004 to a net loss of $2.4 million. The results for fiscal year 2004 included an after-tax gain of $5.8 million, or $0.12 per share, from the Maritime sale.

      Non-utility operations reported total net income of $7.7 million, or $0.16 per share, for the fiscal year ended September 30, 2004, an increase of $4.4 million, or $0.10 per share, over fiscal year 2003. The retail energy-marketing segment contributed $4.5 million, or $0.09 per share, to the year-over-year improvement in earnings from non-utility operations. This improvement was substantially offset by a $4.2 million, or $0.08 per share, increased net loss incurred by the commercial HVAC segment. Earnings comparisons between fiscal years 2004 and 2003 also reflect the $5.8 million, or $0.12 per share, after-tax gain realized in fiscal year 2004 from the Maritime sale, as compared to an after-tax gain of $926,000, or $0.02 per share, realized in fiscal year 2003 from the sale of a real estate partnership interest, and a favorable adjustment to income taxes in fiscal year 2003 of $2.1 million, or $0.04 per share, resulting from the utilization of capital loss carryforwards.

      The following table depicts the composition of the changes in revenues for the non-utility business segments.

      Retail Energy-Marketing. The Company’s retail energy-marketing subsidiary, WGEServices, was established in 1997, and sells natural gas and electricity on an unregulated, competitive basis directly to residential, commercial and industrial customers.

      Retail energy-marketing revenues were $773.0 million, $789.9 million, and $726.2 million for fiscal years 2005, 2004 and 2003, respectively. WGEServices’ gas sales volumes totaled 71.4 billion cubic feet ( bcf ) in fiscal year 2005, compared to 71.7 bcf and 71.1 bcf in fiscal years 2004 and 2003, respectively. The retail energy-marketing segment had approximately 144,800, 150,800 and 153,400 natural gas customers at September 30, 2005, 2004 and 2003, respectively. WGEServices sold 2.7 billion kilowatt hours (kWh) of

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

electricity in fiscal year 2005, compared to 6.7 billion kWh and 7.5 billion kWh in fiscal years 2004 and 2003, respectively. Electricity was provided to approximately 36,200 customers at September 30, 2005, compared to 44,500 and 76,000 customers at September 30, 2004 and 2003, respectively.

      The retail energy-marketing segment reported net income of $22.3 million for fiscal year 2005, an increase over net income of $8.3 million reported for the prior fiscal year. The $14.0 million year-over-year improvement included $2.0 million (after tax) of reduced expenses related to the termination of two natural gas supply contracts, mark-to-market derivative gains of $1.8 million (after tax), and $1.2 million (after tax) related to adjustments to revenue and cost of gas that were applicable to prior years. The remainder of the year-over-year improvement in earnings for this segment was attributable to higher gross margins from the sale of natural gas and reduced expenses associated with uncollectible accounts, partially offset by lower gross margins from electric sales as the drop in sales volumes more than offset the increase in the gross margin per kilowatt hour sold.

      During fiscal year 2005, the energy-marketing segment benefited from reduced expenses in the fourth quarter of the current fiscal year of $2.0 million (after tax), or $0.04 per share, related to the termination of contracts with two suppliers for the forward purchase of natural gas. These fixed-price contracts were terminated due to the natural gas suppliers’ expected inability to fulfill contractual obligations in the first quarter of fiscal year 2006 to the energy-marketing business due to the natural gas supply shortage in the Gulf of Mexico region. In consideration of the contract termination, the suppliers agreed to pay a fee to the energy-marketing segment representing the difference between the fixed price and volume of gas under contract and the market price for forward delivery of the same volume of gas that was purchased by the energy-marketing business to replace the contractual shortfall. This fee was recorded in the fourth quarter of fiscal year 2005 as a reduction to the cost of gas included in non-utility operating expenses for the energy-marketing segment, and the higher cost of the replacement gas will be recorded in fiscal year 2006 when delivered.

      Higher gross margins from the sale of natural gas, after taking into consideration the termination fee and revenue and cost of gas adjustments discussed above, reflect significant growth in gross margins per therm in fiscal year 2005 that were slightly offset by a decline of less than one percent in natural gas sales volumes. The increased gross margins reflect the use of greater volumes of lower cost storage inventory compared to the prior fiscal year and the use of multiple supply options combined with differing weather patterns during the winter to enhance margins from customers. Increased gross margins on natural gas sales also reflect the realization of increased gains in the mark-to-market valuation associated with derivative contracts used in WGEServices’ gas supply portfolio to reduce the risk of variations in demand caused by weather. These mark-to-market gains, when compared to the prior fiscal year, increased net income by $1.8 million (after tax), or $0.04 per share (refer to the section entitled “Market Risk—Price Risk Related to Retail Energy-Marketing Operations” included herein). These mark-to-market gains were realized principally in the fourth quarter of fiscal year 2005 as a result of a sharp rise in natural gas prices during this period caused by the adverse effects of the 2005 hurricane season that resulted in a shortage of natural gas supply deliveries from the Gulf of Mexico region (refer to the section entitled “Primary Factors Affecting WGL Holdings and Washington Gas—Gas Supply and Storage Capacity” included herein for a further discussion of the gas supply shortage). The earnings improvement for this segment also reflects a benefit of $2.1 million (after tax), or $0.04 per share, in the current fiscal year for reduced expenses associated with uncollectible accounts due to enhanced recoveries of these accounts.

      Slightly tempering the earnings improvement for WGEServices was a decline in gross margins from electric sales in the current fiscal year, primarily reflecting a 59.7 percent decline in electric sales volumes that was partially offset by an increase in the gross margin per kilowatt hour sold. The decline in electric sales volumes primarily reflects changing market conditions that include intensified competition for large-volume commercial customers, and utility standard offer service rates that are being offered at attractive, below-market rates. Margins per kilowatt hour sold increased by almost 50 percent when compared to the prior fiscal year due to the non-renewal of several large-volume customers that were previously served at lower per unit margins.

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

      Looking ahead, in the near-term, future opportunities to add new electric customers may be limited. New SOS rates offered by electric utilities that went into effect in Maryland and the District of Columbia in 2005 are below current market prices. These electric utilities entered into contracts to supply their SOS customers with electricity, prior to the large increase in fuel prices. In the long-term, however, SOS rates in Maryland and the District of Columbia will be reset through annual procurements to rates that will likely reflect current market prices for fuel, and thereby are expected to offer continuing opportunities to build the electric customer base.

      Though the retail energy-marketing segment earned higher-than-historical gross margins on natural gas sales in fiscal year 2005, certain transactions that resulted in the record natural gas margins in the current fiscal year are not expected to be repeated in fiscal year 2006. These transactions along with the uncertainties regarding the availability of natural gas supply and the resulting upward pressure on natural gas prices, and the short-term outlook for electric sales, cause the Company not to foresee a continuation of the same level of profitability from the retail energy-marketing segment in fiscal year 2006 as was experienced in fiscal year 2005.

      Net income for the retail energy-marketing segment was $8.3 million, or $0.17 per share, for fiscal year 2004, an increase of $4.5 million, or $0.09 per share, over fiscal year 2003. The year-over-year improvement was attributable to higher gross margins from the sale of natural gas, partially offset by lower gross margins from the sale of electricity. Natural gas sales volumes increased by less than one percent over fiscal year 2003, however gross margins per therm sold increased 52 percent. Lower gross margins from electric sales for fiscal year 2004 resulted from an 11.8 percent decline in kilowatt hours sold due to a reduction in the number of lower-margin residential customers served based on Company decisions not to renew certain contracts, as well as a reduction in commercial customers due to intensified competition for these customers.

      Commercial HVAC. Two subsidiaries, ACI and WGESystems, offer large-scale HVAC installations and related services to commercial and government customers. These subsidiaries comprise the Company’s commercial HVAC segment.

      Revenues for the commercial HVAC segment were $32.4 million for fiscal year 2005, as compared to $30.1 million and $35.5 million for fiscal years 2004 and 2003, respectively. The growth in revenues in fiscal year 2005 compared to 2004 was due to an increase in the number of service contracts with both commercial and institutional customers. In fiscal years 2004 and 2003, this segment experienced a decrease in revenues from fiscal year 2002, reflecting a reduction in work performed on behalf of one major customer, the Federal Government, as well as a reduction in other business activity. In fiscal years 2005, 2004 and 2003, the Company generated revenues of approximately 42 percent, 44 percent and 45 percent, respectively, from the Federal Government.

      For fiscal year 2005, the commercial HVAC segment incurred a net loss of $3.9 million, or $0.08 per share, reducing its net loss by $1.5 million, or $0.03 per share, from its fiscal year 2004 net loss of $5.4 million. This improvement primarily reflects improved operating margins during the current fiscal year due to a focus on higher gross margin service work, being more selective of construction jobs that are being undertaken, and reducing selling, general and administrative expenses. Also included in operating results for fiscal year 2005 was a charge of $1.6 million, or $0.03 per share, recorded in the current fiscal year that resulted principally from the resolution of a legal contingency related to the Company’s investment in its HVAC business. The resolution of this legal contingency includes a payment of $1.0 million that increased the purchase price of ACI. This amount was recorded in the fourth quarter of fiscal year 2005 as goodwill and was immediately impaired. For fiscal year 2004, this segment incurred a net loss of $5.4 million, or $0.11 per share, as compared to a net loss of $1.2 million, or $0.03 per share, in fiscal year 2003, primarily reflecting reduced revenues, lower gross margins and, in fiscal year 2004, the recognition of a charge of $1.5 million, or $0.03 per share, for the impairment of goodwill related to this business.

      Other Non-Utility Activities. As previously discussed, some of the Company’s transactions are not significant enough on a stand-alone basis to warrant treatment as a business segment. For purposes of

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

segment reporting, these transactions are aggregated as “Other Activities” and included as part of non-utility operations (see Note 16 of the Notes to Consolidated Financial Statements).

      Results for other non-utility activities of the Company for fiscal year 2005 reflect a net loss of $2.4 million. This represents a $7.2 million, or $0.15 per share, decrease from the net income of $4.8 million reported in fiscal year 2004. This decline was primarily due to an after-tax gain of $5.8 million, or $0.12 per share, realized from the Maritime sale in fiscal year 2004. Results for other non-utility activities for fiscal year 2004 improved $4.1 million, or $0.09 per share, over fiscal year 2003, primarily due to the Maritime sale in fiscal year 2004. In fiscal year 2003, non-utility activities reported net income of $745,000 which included an after-tax gain of $926,000, or $0.02 per share, from the sale of a real estate partnership interest, and a favorable adjustment to income taxes in fiscal year 2003 of $2.1 million, or $0.04 per share, resulting from the utilization of capital loss carryforwards.

       Other Income (Expenses)— Net

       Other income (expenses)— net was an expense of $0.9 million in fiscal year 2005 compared to income of $4.7 million in fiscal year 2004. This comparison was attributable primarily to the after-tax earnings of $5.8 million realized in fiscal year 2004 from the Maritime sale.

      Other income (expenses)— net represented an improvement in income of $3.9 million in fiscal year 2004 over fiscal year 2003. This improvement was attributable primarily to the after-tax earnings from the Maritime sale in fiscal year 2004, and increased interest income earned on higher short-term investment balances. Additionally, in fiscal year 2003, the Company realized after-tax gains of $2.5 million from the sale of its headquarters property, and after-tax gains of $926,000 from the sale of a real estate partnership interest.

       Interest Expense

       Interest expense incurred by WGL Holdings and its subsidiaries was $43.5 million for the year ended September 30, 2005, a reduction of $694,000 from fiscal year 2004. Fiscal year 2004 interest expense was $44.1 million, a decline of $2.2 million from the $46.4 million level for fiscal year 2003. Long-term debt comprises primarily unsecured MTNs issued solely by Washington Gas. The weighted average cost of MTNs was 6.27 percent, 6.46 percent and 6.58 percent at September 30, 2005, 2004 and 2003, respectively. The following table shows the components of the changes in interest expense between years.

* Represents Allowance for Funds Used During Construction.

     The $694,000 decrease in WGL Holdings’ interest expense for fiscal year 2005 reflects reduced interest costs on long-term debt due to a decrease in the average balance of long-term debt outstanding, partially offset by a slight increase in the weighted average effective cost of these borrowings. Interest expense on short-term debt rose, reflecting an increase of approximately 128 basis points in the weighted average cost of short-term debt, partially offset by a lower average balance of short-term debt outstanding. Fiscal year 2005 also reflects lower other interest expense due to an $882,000 loss recorded in fiscal year 2004 related to an interest-rate swap, partially offset by interest associated with other miscellaneous items.

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

      The $2.2 million decrease in interest expense for fiscal year 2004 compared to 2003 is due primarily to reduced interest costs on long-term debt, reflecting a decrease in the average balance of long-term debt outstanding, coupled with a decrease in the weighted average effective cost of these borrowings. Fiscal year 2004 also reflects an $882,000 loss related to an interest-rate swap, partially offset by interest associated with other miscellaneous items.

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

      The Company’s retail energy-marketing subsidiary, WGEServices, has seasonal short-term cash requirements resulting from its need to purchase storage gas inventory in advance of the period in which the storage gas is sold. In addition, WGEServices must continually pay its suppliers of natural gas and electricity before it collects its accounts receivable balances resulting from these sales. WGEServices derives its funding to finance these activities from short-term debt issued by the Company.

      Both the regulated utility and the retail energy-marketing segment maintain storage gas inventory. WGEServices maintains storage gas inventory that is assigned to it by natural gas utilities such as Washington Gas. Storage gas inventories represent gas purchased from producers and are stored in facilities primarily owned by interstate pipelines. The regulated utility and retail energy-marketing subsidiary generally pay for storage gas between heating seasons and withdraw it during the heating season. Significant variations in storage gas balances between years are possible, and are caused by the price paid to producers and marketers, which is a function of market fluctuations in the price of natural gas and changing requirements for storage volumes. For the regulated utility, such costs become a component of the cost of gas recovered from customers when volumes are withdrawn from storage. In addition, the regulated utility is able to specifically earn and recover its pre-tax cost of capital related to the varying level of the storage gas inventory balance it carries in each of the three jurisdictions in which it operates.

      Variations in the timing of collections of gas costs under the regulated utility’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, 2005 and 2004, the regulated utility had a $4.4 million and $3.7 million net over-collection of gas costs, respectively. The over-collection in both fiscal years stemmed primarily from an excess of gas costs recovered from customers over gas costs paid to suppliers. Washington Gas reflects the amounts under-collected and over-collected in the captions “Gas costs due from customers” and “Gas costs due to customers,” respectively, in its Balance Sheets as current assets and current liabilities. Amounts under- or over-collected that are generated during the current business cycle are reflected as a regulatory asset or liability until September 1 of each year, at which time the accumulated amount is transferred to “Gas costs due from/to customers” as appropriate. Most of the current balance will be returned to, or collected from, customers in fiscal year 2006. At September 30, 2005 and 2004, refunds received from pipelines and to be returned to the regulated utility’s customers were not material.

      The Company and Washington Gas utilize short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal requirements. The Company’s policy is to maintain back-up bank credit facilities in an amount equal to or greater than its expected maximum commercial paper position. From April 28, 2004 to September 30, 2005, WGL Holdings and Washington Gas had revolving credit agreements with a group of commercial banks in the amount of $175 million each that were due to expire on April 27, 2007 and April 28, 2009, respectively. These credit facilities permitted WGL Holdings and Washington Gas to request and the banks to approve, an additional line of credit of $50 million and $100 million, respectively, above the original credit limit for the Company and Washington Gas. On September 30, 2005, WGL Holdings and Washington Gas each amended and restated their existing revolving credit facilities. The amended and restated credit facilities (the Amended and Restated Credit Facilities) are with a group of commercial banks, and expire on September 30, 2010. The Amended and Restated Credit Facility for WGL Holdings permits it to borrow up to $275 million, and further permits the Company to request prior to September 30, 2009, and the banks to approve, an additional line of credit of $50 million above the original credit limit, for a maximum potential total of $325 million. The Amended and Restated Credit Facility for Washington Gas permits it to borrow up to $225 million, and further permits Washington Gas to request prior to September 30, 2009, and the banks to approve, an additional line of credit of $100 million above the original credit limit, for a maximum potential total of $325 million. As of September 30, 2005, there were no outstanding borrowings under either the WGL Holdings or Washington Gas credit facilities.

      At September 30, 2005, the Company had outstanding notes payable of $40.9 million in the form of commercial paper, as compared to $95.6 million outstanding at September 30, 2004. Of the outstanding notes payable balance at September 30, 2005, $30.5 million and $10.4 million was commercial paper issued

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

by WGL Holdings and Washington Gas, respectively. Of the outstanding notes payable balance at September 30, 2004, $76.9 million and $18.7 million was commercial paper issued by WGL Holdings and Washington Gas, respectively.

      As a result of concerns about the sufficiency of the supply of natural gas and other factors during the winter of 2005-2006, the price of the natural gas commodity that is paid by the Company’s customers has risen sharply from levels experienced during the winter of 2004-2005. Customers’ bills are expected to increase dramatically in the winter of 2005-2006. The increased bills are likely to cause increased difficulty for customers to pay their bills in a timely manner or, in certain situations, to be able to pay their bills. This situation will likely cause the Company and Washington Gas to be required to finance a higher level of accounts receivable for a longer period of time, and to incur higher short-term debt levels and greater short-term debt costs to finance these receivables than would be incurred absent these circumstances.

     Long-Term Cash Requirements and Related Financing

       The Company’s long-term cash requirements primarily depend upon the level of capital expenditures, long-term debt maturity requirements and decisions to refinance long-term debt. Historically, the Company has devoted the majority of its capital expenditures to adding new regulated utility customers in its existing service area. However, as a result of recent operating issues in Prince George’s County, Maryland described later in Management’s Discussion, the Company forecasts a greater level of replacement capital expenditures over the next two and one-half years (refer to the section entitled “Capital Expenditures” included herein). At September 30, 2005, Washington Gas was authorized to issue up to $152.5 million of long-term debt under a shelf registration that was declared effective by the SEC on April 24, 2003. On May 20, 2003, Washington Gas executed a Distribution Agreement with certain financial institutions for the issuance and sale of debt securities included in the shelf registration statement.

      During the fiscal year ended September 30, 2005, Washington Gas retired a total of $60.5 million of MTNs. On March 7, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of MTNs. The MTNs redeemed were $10.0 million of 7.76 percent MTNs and $10.0 million of 7.75 percent MTNs that had a nominal maturity date in March 2025. On June 9, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of 6.50 percent MTNs that had a nominal maturity date in June 2025. Additionally, on June 20, 2005, Washington Gas retired $20.5 million of 7.45 percent MTNs that matured on the same date. Washington Gas paid the applicable accrued interest on each debt retirement date.

      In August 2005, Washington Gas replaced the retired debt, as discussed above, with $60.5 million of newly issued MTNs. On August 9, 2005, Washington Gas issued $20.0 million of 4.83 percent MTNs due August 2015 to replace the MTNs retired on March 7, 2005. On August 11, 2005, Washington Gas issued $40.5 million of 5.44 percent MTNs due August 2025 to replace the MTNs retired in June 2005. Concurrent with the issuance of the $20.0 million of 4.83 percent MTNs, Washington Gas paid $364,000 associated with the settlement of a forward-starting swap that had a notional principal amount of $20.0 million. Similarly, concurrent with the issuance of the $40.5 million of 5.44 percent MTNs, Washington Gas paid $2.2 million associated with the settlement of a forward-starting swap that had a notional principal amount of $40.5 million (refer to the section entitled “Market Risk— Interest-Rate Risk” included herein). The effective cost of the newly-issued debt, after considering the amount paid related to the two forward-starting swaps, is 5.15 percent and 5.98 percent for the $20.0 million and $40.5 million debt issuances, respectively.

      In November 2003, Washington Gas paid $37.2 million plus accrued interest to redeem $36.0 million of 6.95 percent MTNs that were due in fiscal year 2024, and replaced this debt with $37.0 million of newly-issued, 4.88 percent MTNs due in fiscal year 2014. Concurrent with the issuance of the new debt, Washington Gas received $2.6 million associated with the settlement of a forward-starting swap that had a notional principal of $37.0 million. The effective cost of the new debt, after considering the amount received related to the forward-starting swap, is 4.11 percent (refer to the section entitled “Market Risk— Interest-Rate Risk” included herein).

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

     Security Ratings

       The table below reflects the current credit ratings for the outstanding debt instruments of WGL Holdings and Washington Gas. Changes in credit ratings may affect WGL Holdings’ and Washington Gas’ cost of short-term and long-term debt and their access to the capital markets. Credit ratings can change at any time.

     Ratings Triggers and Certain Debt Covenants

       WGL Holdings and Washington Gas pay facility fees on their Amended and Restated Credit Facilities based on the long-term debt ratings of Washington Gas. In the event the long-term debt of Washington Gas is downgraded below certain levels, WGL Holdings and Washington Gas would be required to pay higher facility fees. There are five different levels of fees. The Amended and Restated Credit Facility for WGL Holdings defines its applicable fee level as one level below the level applicable to Washington Gas. Under the terms of the Amended and Restated Credit Facilities, the lowest level facility fee is six basis points and the highest is ten basis points.

      Under the terms of the Amended and Restated Credit Facilities, the ratio of consolidated indebtedness to consolidated total capitalization can not exceed 0.65 to 1.0 (65.0 percent). In addition, WGL Holdings and Washington Gas are required to inform lenders of changes in corporate existence, financial conditions, litigation and environmental warranties that might have a material adverse effect. The failure to inform the lenders’ agent of changes in these areas deemed material in nature might constitute default under the agreement. A default, if not remedied, may lead to a suspension of further loans and/or acceleration in which obligations become immediately due and payable. At September 30, 2005, the Company was in compliance with all of the covenants under its revolving credit facilities.

      Regarding certain of the regulated utility’s gas purchase and pipeline capacity agreements, if the long-term debt of Washington Gas is downgraded below BBB by Standard & Poor’s Ratings Services or below Baa2 by Moody’s Investors Service, or Washington Gas is deemed by a counterparty not to be creditworthy, the counterparty may withhold service or deliveries, or may require additional credit support.

    Cash Flows Provided By Operating Activities

       The primary drivers for the Company’s operating cash flows are cash payments received from gas customers, offset by payments made by the Company for gas costs, operation and maintenance expenses, taxes and interest costs. Current interest expense reflects the favorable effect of relatively low short-term interest rates, a condition that has begun to change as short-term interest rates have risen.

      During the first six months of the Company’s fiscal year, the Company typically generates more net income than its annual net income (net losses are normally generated in the last six months of the fiscal year) due to the significant volumes of natural gas that are delivered by the regulated utility during the winter heating season. Variations in the level of net income reported for the fiscal six-month period ended

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

March 31 may be significant because of the variability of weather and other related factors from one period in a year to the same period in the subsequent year. Generating large sales volumes during the six-month period ended March 31 increases accounts receivable from the level at September 30; likewise, accounts payable increases to pay providers of the natural gas commodity. Accounts payable for the natural gas commodity can also vary significantly from one period to the next because of the volatility in the price of natural gas. Storage gas inventories, which usually peak by November 1, are largely drawn down in the six months ended March 31, and provide a source of cash as this asset is used to satisfy winter sales demand. Gas costs due from or to customers and deferred purchased gas costs, which represent the difference between gas costs that have been paid to suppliers and what has been collected from customers, can also cause significant variations in operating cash flows from period to period.

      During the last six months of the Company’s fiscal year, after the winter heating season, the Company will generally report a seasonal net loss due to reduced demand for natural gas during this period. Additionally, many of the Company’s assets, which were generated during the winter heating season, are converted into cash. The Company generally uses this cash to reduce and sometimes eliminate short-term debt, and acquire storage gas for the next heating season.

      Net cash provided by operating activities totaled $232.5 million, $237.7 million and $144.2 million for fiscal years 2005, 2004 and 2003, respectively. A description of certain material changes in working capital from September 30, 2004 to September 30, 2005 is listed below:

      During fiscal years 2004 and 2003, storage gas inventory rose $53.0 million and $65.5 million from September 30, 2003 and 2002, respectively, due to higher natural gas costs and increased storage capacity. During fiscal year 2004, accounts payable and other accrued liabilities increased $35.9 million due to higher natural gas and electricity purchases.

    Cash Flows Used in Financing Activities

       Cash flows used in financing activities totaled $119.2 million, $132.6 million and $26.3 million for fiscal years 2005, 2004 and 2003, respectively. During fiscal year 2005, the Company decreased its notes payable by a net amount of $54.8 million, and paid common stock dividends totaling $64.0 million. Additionally during fiscal year 2005, the Company refinanced $60.5 million of long-term debt with proceeds from the issuance of $60.5 million of lower-cost, long-term debt (refer to the section entitled “Liquidity and Capital Resources— Long-Term Cash Requirements and Related Financing” included herein).

      Cash flows used in financing activities during fiscal year 2004 reflect a $71.0 million net decrease in notes payable, coupled with common stock dividend payments totaling $62.7 million. Additionally during fiscal year 2004, the Company refinanced $36.0 million of long-term debt with proceeds from the issuance of $37.0 million of lower-cost, long-term debt. During fiscal year 2003, cash flows used in financing

Part II

Item 7. Management’s Discussion and Analysis of

Financial Condition and Results of Operations (continued)

activities reflect a $75.8 million increase in notes payable. Additionally, the Company retired $41.9 million of long-term debt, and paid common stock dividends totaling $61.9 million.

      The following table reflects the issuances and retirements of long-term debt that occurred during fiscal years 2005, 2004 and 2003 (also refer to Note 5 of the Notes to Consolidated Financial Statements).