FORM 10-K
Annual Report Pursuant to Section 13 or
15(d) of the Securities Exchange Act of 1934
Commission
Exact name of registrant as specified in its charter and
States of
I.R.S.
File Number
principal office address and telephone number
Incorporation
Employer I.D. Number
WGL Holdings, Inc.
101 Constitution Ave., N.W.
Washington, D.C. 20080
(703) 750-2000
Virginia
52-2210912
Washington Gas Light Company
101 Constitution Ave., N.W.
Washington, D.C. 20080
(703) 750-4440
District of
Columbia
and Virginia
53-0162882
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:
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 the registrant is an accelerated filer (as defined in Rule 12-b of the Act):
The aggregate market value of the voting common equity held by non-affiliates of the registrant, WGL Holdings, Inc., amounted to $1,459,006,538 as of March 31, 2004.
WGL Holdings, Inc. common stock, no par value outstanding as of October 31, 2004: 48,674,581 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, 2004.
DOCUMENTS INCORPORATED BY REFERENCE
WGL Holdings, Inc.
For the Fiscal Year Ended September 30, 2004
Table of Contents
i
WGL Holdings, Inc.
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 Managements Discussion and Analysis of Financial Condition and Results of Operations (Managements Discussion) included under Item 7 herein, is divided into the following two sections:
| WGL Holdings This section describes the financial condition and results of operations of WGL Holdings and its subsidiaries on a consolidated basis. It includes discussions of WGL Holdings regulated utility and non-utility operations. The majority of WGL Holdings operations are derived from the results of its regulated utility, Washington Gas, and to a much lesser extent, the results of its non-utility operations. For more information on the Companys regulated utility operations, please refer to the Managements Discussion for Washington Gas. | |
| Washington Gas This section comprises the majority of WGL Holdings regulated utility segment. The financial condition and results of operations of Washington Gas utility operations and WGL Holdings regulated utility segment are essentially the same. Therefore, the focus of this section includes a detailed description of the results of operations of the regulated utility. |
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 Managements Discussion for both WGL Holdings and Washington Gas should be read in conjunction with the respective companys Consolidated 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, 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:
| variations in weather conditions from normal levels; | |
| changes in economic, competitive, political and regulatory conditions and developments; | |
| changes in capital and energy commodity market conditions; | |
| changes in credit ratings of debt securities of WGL Holdings or Washington Gas that may affect access to capital or the cost of debt; | |
| changes in credit market conditions and creditworthiness of customers and suppliers; | |
| changes in relevant laws and regulations, including tax, environmental and employment laws and regulations; | |
| legislative, regulatory and judicial mandates and decisions; | |
| timing and success of business and product development efforts; | |
| technological improvements; |
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| the pace of deregulation efforts and the availability of other competitive alternatives; | |
| terrorist activities; and | |
| other uncertainties. |
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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WGL Holdings, Inc.
ITEM 1. BUSINESS
INTRODUCTION
WGL Holdings is a holding company that was established on November 1, 2000 under the Public Utility Holding Company Act of 1935 . WGL Holdings owns all of the shares of common stock of Washington Gas, a regulated natural gas utility, and all of the shares of common stock of Crab Run Gas Company (Crab Run), Hampshire Gas Company (Hampshire) and Washington Gas Resources Corporation (Washington Gas Resources). Washington Gas Resources owns all of the shares of common stock of various unregulated, energy-related businesses.
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 Companys core subsidiary, Washington Gas, is engaged in the delivery and sale of natural gas that is predominantly regulated by state regulatory commissions. Through wholly owned subsidiaries of Washington Gas Resources, the Company also offers energy-related products and services that are closely related to its core business.
SUBSIDIARIES
WGL Holdings is the parent of four direct, wholly owned subsidiaries. The following paragraphs describe each subsidiary in the WGL Holdings corporate structure at September 30, 2004.
Washington Gas is a regulated public utility that delivers and sells natural gas to customers in Washington, D.C. and adjoining areas in Maryland, Virginia and several cities and towns in the northern Shenandoah Valley of Virginia. Washington Gas has been engaged in the gas distribution business for 156 years, having been originally incorporated by an Act of Congress in 1848. Washington Gas has been a domestic corporation of the Commonwealth of Virginia since 1953, and a corporation of the District of Columbia since 1957. Washington Gas serves approximately one million customers in an area having a population estimated at five million.
As of September 30, 2004, the Company had
approximately 1.02 million connected customer meters.
Connected customer meters reflect all natural gas meters
connected to the Washington Gas distribution system, including
those meters that may not be 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, 2004. Active
customer meters exclude those meters that are not currently
receiving service due to disconnection. Weather in the fiscal
year ended September 30, 2004 was 6.1 percent colder than
normal; therefore, the volumes shown below are not
representative of the volumes of natural gas that would have
been delivered if the weather had been normal. 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.
Active Customer Meters and Therms Delivered by Jurisdiction
Millions of Therms
Active Customer
Delivered
Meters as of
Fiscal Year Ended
Jurisdiction
September 30, 2004
September 30, 2004
149,529
316.1
407,795
715.3
432,738
596.4
990,062
1,627.8
Of the 1.628 billion therms delivered in fiscal year 2004, 863.7 million therms, or 53.1 percent, were sold and delivered by Washington Gas and 764.1 million therms, or 46.9 percent, were delivered to various customers that acquired their natural gas from competitive natural gas suppliers referred to as third-party marketers. Of the total therms delivered by Washington Gas, 80.5 percent was delivered to firm residential and commercial customers, 17.0 percent was delivered to interruptible customers, and the remaining 2.5 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
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interruptible service, a customer must be capable of using an alternate fuel as a substitute for natural gas in the event 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, 2004, Crab Runs 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 the vicinity of Augusta, 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 Federal Energy Regulatory Commission (FERC).
Washington Gas Resources owns the Companys unregulated subsidiaries. Washington Gas Resources subsidiaries, which are 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.). Effective April 8, 2004, the Company dissolved two of its inactive subsidiaries, Brandywood Estates, Inc. (Brandywood) and Washington Gas Consumer Services, Inc. (Consumer Services). Brandywood was a general partner with a major developer in a venture to develop 1,605 acres in Prince Georges County, Maryland. This property was sold in October 2002 after unsuccessful attempts to rezone and, subsequent to the sale, Brandywood became inactive and conducted no business. Consumer Services, created to evaluate and perform various energy-related functions, became inactive and had not conducted any business since 2001.
WGEServices is engaged in the sale of natural gas and electricity to retail customers in competition with unregulated marketers. At September 30, 2004, WGEServices served approximately 150,800 residential, commercial and industrial natural gas customers, and 44,500 electricity customers both inside and outside Washington Gas traditional service territory. WGEServices purchases natural gas and electricity for resale and does not own electric generation, transmission or distribution facilities. Natural gas and electricity sold by WGEServices are delivered through the assets owned by the regulated utilities that ultimately connect to the customers of WGEServices. Washington Gas delivers most of the natural gas sold by WGEServices. | |
ACI is a full-service mechanical contractor that offers turnkey products and services associated with the design, renovation, sale, installation and service of mechanical heating, ventilating and air conditioning (HVAC) systems. ACI serves the industrial, commercial and institutional sectors in Washington, D.C.; Baltimore, Maryland; Philadelphia, Pennsylvania; Richmond, Virginia and Northern Virginia areas. | |
WGESystems provides commercial energy services, including the design, construction and renovation of mechanical HVAC systems in the District of Columbia and parts of Virginia and Maryland. WGESystems business is complementary to that of ACI. | |
WG Maritime works with a major developer to develop a 12-acre parcel of land owned by Washington Gas in the District of Columbia. Washington Gas selected the developer to design, execute and manage the various phases of the development. The development, Maritime Plaza, is intended to be a mixed-use commercial project that will be implemented in five phases. The entire project is expected to be completed over a ten to fifteen-year period, depending on market demand. To date, Washington Gas has entered into two 99-year ground leases for the first and second phases that represent two buildings at Maritime Plaza, a commercial development project in which WG Maritime held a carried interest. In February 2004, unrelated third parties sold these two buildings and WG Maritime disposed of its carried interest. Washington Gas continues to hold ground leases on the buildings that were sold. WG Maritime may hold similar interests in the remaining phases if they are developed. | |
Credit Corp. offered financing to customers to purchase gas appliances and other energy-related equipment. This business no longer offers new loans, but continues to service its existing loan portfolio. Substantially all of the loan portfolio is expected to be fully amortized in 2005. |
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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 Companys 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 has taken the initiative to offer competitively priced natural gas and electricity to customers through 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 93 percent of the Companys consolidated total assets, the regulated utility segment (represented by 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 the regulated utility incurs. At September 30, 2004, the regulated utility was selling and delivering the natural gas commodity to 82 percent of its customers. The remaining 18 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 a subsidiary of Washington Gas Resources. During both fiscal years ended September 30, 2004 and 2003, the regulated utility segment reported total operating revenues of $1.3 billion, or 61.9 and 63.6 percent, respectively, of consolidated total operating revenues. During fiscal year 2002, the regulated utility segment reported total operating revenues of $939 million, or 59.2 percent of consolidated total operating revenues. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system, and 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 utilitys rates. Hampshire, a wholly owned subsidiary of WGL Holdings, operates an underground natural gas storage facility that provides services exclusively to Washington Gas. Hampshire is regulated by the FERC. 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 utilitys traditional service territory. WGEServices does not own or operate any natural gas or electric generation, 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 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, managing credit risks associated with customers of and suppliers to this segment, and controlling the level of selling, general and administrative costs, most notably customer acquisition costs.
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Commercial HVAC
Two wholly owned subsidiaries, ACI and WGESystems, provide turnkey, design-build and renovation projects to the commercial and government markets. There are many competitors in this business segment. The commercial HVAC operations focus on retrofitting 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 generating adequate revenue from the government and private sectors in the new construction and retrofit markets, estimating and managing fixed-price contracts, and 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 initiatives, 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 gas consumed and (ii) a fixed customer charge designed to recover certain fixed costs associated with maintaining facilities located on the customers property, as well as certain other costs that do not vary with the amount of natural gas consumed by customers. Non-residential firm customers 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 are comprised of 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 firm tariff provisions for 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 the Companys 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 and 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.
Regulated Service to Interruptible Customers. 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. Under these arrangements, except as noted below as it relates to Virginia operations, Washington Gas shares a majority of the margins earned on interruptible gas sales and deliveries to 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 class in rate design. In the Virginia jurisdiction, Washington Gas shares only margins on interruptible gas sales to firm customers; interruptible delivery service rates are based on the cost of service, and Washington Gas retains all revenues from interruptible delivery service.
Natural Gas Unbundling Initiatives. Currently, 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
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Washington Gas revenue continues to be generated from the sale and delivery of natural gas on this combined or bundled basis, regulatory initiatives have allowed for the separation or unbundling of the sale of the natural gas commodity from the delivery of gas on the regulated utilitys 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 services. Therefore, Washington Gas does not experience any loss of margins when customers choose to purchase their gas from third-party marketers.
Throughout the Washington Gas service area, all customers are eligible to participate and may choose to purchase natural gas from a variety of unregulated marketers, including WGEServices, an affiliated natural gas and electricity retail marketer. When customers select an unregulated 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 utilitys major jurisdictions as of September 30, 2004 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 in addition to other areas in Maryland and Virginia that are outside of the regulated utilitys jurisdictional service area. As an unregulated 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 Managements 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.
Rate Case Activities
In response to a Final Order of the PSC of DC that required the Company to explain why its rates should not be reduced, on June 19, 2001, Washington Gas filed with the PSC of DC an application to increase rates in the District of Columbia. The request sought to increase overall annual revenues in the District of Columbia by approximately $16.3 million, or 6.8 percent, based on a proposed return on equity of 12.25 percent. On October 29, 2002, the PSC of DC issued a Final Order for Washington Gas to decrease rates. The Final Order directed a decrease in overall annual revenues in the District of Columbia of approximately $7.5 million, and approved a return on common equity of 10.60 percent and an overall rate of return of 8.83 percent. The Final Order also modified the design of rates to collect a greater portion of annual revenues through fixed monthly charges, most notably by collecting such fixed monthly charges each month of the year.
On November 6, 2002, Washington Gas filed with the PSC of DC an Application for Reconsideration of the Order issued by the PSC of DC on October 29, 2002. Washington Gas Application for Reconsideration automatically stayed the PSC of DCs Final Order dated October 29, 2002. After reviewing the Applications for Reconsideration of Washington Gas and other parties in the case, the PSC of DC issued its Final Order on reconsideration on March 28, 2003. Along with the rate design changes and other relief described above, new rates resulting in a $5.4 million annual revenue reduction were put into place in the District of Columbia for service rendered on and after April 9, 2003.
In its March 28, 2003 ruling, the PSC of DC upheld a previous ruling that approved a methodology for sharing with customers 50 percent of asset management revenues previously received by Washington Gas. As part of this ruling, the PSC of DC also approved a methodology for sharing with customers 50 percent of annual ground lease and development fees that Washington Gas received from Maritime Plaza, a commercial development project constructed
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on land owned by Washington Gas. The rates approved by the PSC of DC reflect annual sharing of this income with customers totaling $15,000. On May 23, 2003, the District of Columbia Office of the Peoples Counsel (DC OPC) filed an appeal with the District of Columbia Court of Appeals (DC Court of Appeals) seeking to overturn these two portions of the March 28, 2003 ruling by the PSC of DC. On March 18, 2004, the DC Court of Appeals affirmed the PSC of DCs March 28, 2003 ruling with respect to the treatment of Washington Gas asset management revenues. Furthermore, the DC Court of Appeals ordered 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 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 on this matter of the allocation. On October 12, 2004, Washington Gas filed testimony before the PSC of DC that supports the allocation methodology that was approved in the PSC of DCs 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.
On February 7, 2003, Washington Gas filed with the PSC of DC an application to increase base rates above the level that had been in place since the period preceding the case filed on June 19, 2001. 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 sought 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 Final Order, among other things, reduced annual depreciation expense and collections from the currently allowed levels by approximately $300,000. 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 had been previously 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 Orders 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 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, 2004.
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 when filing for a rate increase. The PSC of MD may initially suspend the proposed increase for 150 days beyond the 30-day notice period and then has the option to extend the suspension for an additional 30 days. If action has not been taken after 210 days, rates become effective subject to refund.
Rate Case Activities
On March 28, 2002, Washington Gas filed an application with the PSC of MD requesting an increase in revenues of approximately $31.4 million or 9.3 percent. The original request included a 12.5 percent return on common equity or 9.67 percent overall rate of return on a year-end rate base, coupled with an incentive rate plan.
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On April 26, 2002, the PSC of MD issued a ruling that established two separate phases for the purpose of considering and resolving specific issues that were stated at that time. In Phase I, the PSC of MD would review Washington Gas base rate case, its proposal regarding incentive rates and a number of other issues associated with Washington Gas proposed tariffs and rates. During Phase II, the PSC of MD would review issues regarding Washington Gas proposal for serving as the supplier/provider of last resort for natural gas services.
On August 6, 2002, an uncontested settlement agreement on Phase I of the case, as revised, was filed with the PSC of MD. The settlement provided for an increase of $9.25 million in annual non-gas operating revenues. The settlement did not indicate the allowed return on common equity for the purpose of determining the amount of the settlement. On September 27, 2002, the PSC of MD issued a Final Order approving the settlement agreement without modification. The increase in revenues became effective for meter readings of Maryland customers on and after September 30, 2002.
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.
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 Hearing Examiner. Washington Gas implemented the new depreciation rates on July 1, 2004.
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 have not previously been approved by the Commission, as well as a revised return on equity. The rates under this process may take effect 150 days after the filing, subject to refund pending the outcome of the SCC of VAs action on the application. Second, an expedited rate case procedure is available which provides that 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 the 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 and/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 should the SCC of VA decide that there has been a substantial change in circumstances since the Companys last general rate case.
Rate Case 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 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.
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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 VAs 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 managements judgment of the rate case outcome.
On December 18, 2003, the SCC of VA issued a Final Order in this proceeding which 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 the quarter ended December 31, 2003 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 VAs 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. This annual earnings test shall 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.
On January 7, 2004, Washington Gas filed a Petition for Reconsideration of Commission Final Order (the Petition) with the SCC of VA requesting that the SCC of VA reconsider certain portions of the December 18, 2003 Final Order, most notably those dealing with depreciation issues. On January 23, 2004, the SCC of VA rejected the Petition. On April 15, 2004, Washington Gas filed a Petition for Appeal with the Supreme Court of Virginia seeking its review of the SCC of VAs Final Order. A hearing was held on September 13, 2004. On October 8, 2004, the Supreme Court of Virginia issued an opinion affirming the SCC of VAs Final Order dated December 18, 2003.
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During fiscal year ended September 30, 2004, Washington Gas recorded additional depreciation expense of $1.0 million in connection with earnings tests performed. The amount recorded could change if the SCC of VA differs with managements calculations or methodology.
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 VAs final decision in the proceeding.
On August 20, 2004, the VA Staff filed testimony in response to Washington Gas proposed rate application. The testimony of the VA Staff, which was based upon updated financial information for revenues, rate base, labor expenses and other matters through March 31, 2004, proposed a reduction in Washington Gas annual revenues of $6.5 million reflecting, among other proposed adjustments, a recommendation to lower the overall rate of return to 8.28 percent and the return on common equity to 9.70 percent. Also, in connection with an earnings test calculation performed by the VA Staff for the twelve-month period ending June 30, 2003, the VA Staff proposed that Washington Gas be required to record additional depreciation expense of $6.1 million (pre-tax), along with a corresponding increase to the accumulated reserve for depreciation.
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.
Under the Stipulation, Washington Gas will not change its annual base revenues, and will maintain the allowed rate of return on common equity of 10.50 percent and the overall rate of return of 8.44 percent as approved by the December 18, 2003 Final Order as previously discussed. Refunds to customers, with interest, are being made during the December 2004 billing cycle for the amount of the proposed annual revenue increase that has been collected since February 26, 2004. Based on the terms of the Stipulation, the Company implemented billing rates commencing October 4, 2004 that reflect the level of annual revenues determined in the December 18, 2003 Final Order, and implemented the agreed upon changes in rate design that are contained in the Stipulation.
The Stipulation also provides for a one-time credit to all Virginia customers of $3.2 million for certain liabilities that were previously recorded by Washington Gas. This one-time credit will be made to customers during the January 2005 billing cycle. Providing this credit to customers does not have an effect on earnings of Washington Gas. Under the Stipulation, Washington Gas is required to file with the SCC of VA, on or before December 27, 2004, an earnings test calculation for the twelve-month period ended December 31, 2003. Future annual earnings test calculations will be estimated by the Company quarterly, and when appropriate, accounting adjustments will be recorded. In accordance with the Stipulation, Washington Gas agrees that it will not file an application with the SCC of VA to increase its base rates such that the proposed increased rates would become effective, on an interim basis, before January 1, 2006.
The Companys financial results for the nine months ended June 30, 2004 reflected a provision for rate refunds to customers based on the difference between the amount the Company had collected in rates subject to refund through June 30, 2004, and the amount that the Company had expected to be realized from the final outcome of the rate case filed in January 2004, based on managements judgment at that time. The amount of the proposed revenue increase that had been included in net income for the nine months ended June 30, 2004, after considering the provision for rate refunds, was $2.2 million (pre-tax), or $0.03 per diluted average common share. After taking into consideration the Stipulation discussed above, Washington Gas increased its provision for rate refunds in the quarter ended September 30, 2004 to the full amount of revenues that had been collected subject to refund through the fiscal year ended September 30, 2004. The increased provision eliminated the $0.03 per diluted average common share that was previously included in net income for the nine months ended June 30, 2004. After the additional provision for rate refunds was recorded in the quarter ended September 30, 2004, there was no effect on fiscal year 2004, nor will there be any effect on fiscal year 2005 earnings for the rates initially put into effect in February 2004.
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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 utilitys net income. In its service territory, Washington Gas continues to attract the majority of the new residential construction market. The Company believes that 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 CapacityRising Natural Gas Prices ). Such increases have resulted in significant reductions to or the elimination of the traditional price advantage of natural gas. Price advantages that electricity may currently have are also partially caused by artificial price caps. These price caps expired in June 2004 in Maryland, and will expire in February 2005 in the District of Columbia, and in December 2010 in Virginia. As these price caps expire, comparisons may change. 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 utilitys customers must be capable of using a fuel other than natural gas when demand peaks for the regulated utilitys firm customers. In the interruptible market, fuel oil is the prevalent energy alternative to natural gas. The regulated utilitys 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 anticipated introduction of non-domestic supplies of liquefied natural gas into the United States natural gas market may affect supply levels and have an impact on natural gas prices. To date, the effect of liquefied natural gas on supply levels has been minimal.
Deregulation
In each of the jurisdictions (the District of Columbia, Maryland and Virginia) served by the Companys regulated utility, regulators and utilities have implemented customer choice programs. These programs provide customers with an opportunity to choose to purchase their natural gas and/or electric commodity from 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 third-party marketers on an unbundled basis, there is no effect on the regulated utilitys 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 Companys current and future strategies.
The Natural Gas Delivery Function
The natural gas delivery function, the core business of the Companys regulated utility, continues to be regulated by local regulatory commissions. In developing this core business, Washington Gas invested $2.6 billion as of September 30, 2004 to construct and operate a safe, reliable and economical 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
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distribution system in the regulated utilitys 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. The Company does not foresee any significant near-term changes in the regulated utilitys risk profile.
The Merchant Function and Natural Gas Unbundling
At September 30, 2004, 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 approximately 990,000
active customers at September 30, 2004, approximately
181,000 customers purchased their natural gas commodity from
unregulated third-party marketers. The following table provides
the status of natural gas unbundling in the regulated
utilitys major jurisdictions at September 30, 2004.
The number and percentage of customers reflected in this table
include all customers who chose to purchase natural gas from a
third-party marketer, including WGEServices.
Status of Customer Choice Programs
Jurisdiction
Customer Class
Eligible Customers
Total
% Participating
Firm:
Residential
135,907
12
%
Commercial
13,387
31
%
Interruptible
235
77
%
Firm:
Residential
378,897
20
%
Commercial
28,638
41
%
Interruptible
260
100
%
Firm:
Residential
406,963
16
%
Commercial
25,539
28
%
Interruptible
236
86
%
990,062
18
%
Ultimately, the regulators may decide that the Company should exit the merchant function and that all customers should choose to buy natural gas from unregulated 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 efficiently the portfolio of contractual resources, recovering contractual costs and maximizing the value of contractual assets. Of the 18 percent of customers who chose to purchase natural gas from a third-party marketer in fiscal year 2004, 14 percent were customers of WGEServices. This compares to 21 percent of customers who chose a third-party marketer in fiscal year 2003, of which 15 percent represented customers of WGEServices.
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 utilitys 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
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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, these costs would be borne by shareholders.
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 marketers that make use of the regulated utilitys firm storage and transportation rights to meet the regulated utilitys 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 regulated utilitys role 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.
The Company established WGEServices in fiscal year 1997, 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, 2004, WGEServices had approximately 150,800 natural gas customers and 44,500 electric customers, compared to 153,400 natural gas customers and 76,000 electric customers at September 30, 2003, and 155,000 natural gas customers and 66,000 electric customers at September 30, 2002. WGEServices gross revenues for fiscal years 2004, 2003 and 2002 were $789.9 million, $726.2 million and $595.9 million, respectively. WGEServices net income was $8.3 million, $3.7 million and $5.0 million for fiscal years 2004, 2003 and 2002, 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 the volatility experienced by WGEServices during fiscal years 2004 and 2003 related to natural gas sales. Gross margins from natural gas sales were reduced in fiscal year 2003 in comparison to fiscal year 2002 due to the colder-than-normal weather experienced during the 2002-2003 winter heating season that resulted in the need to make additional purchases of natural gas at higher prices in the spot market in order to meet commitments to customers. During fiscal year 2004, WGEServices earned higher-than-historical gross margins on its natural gas sales, reflecting additional business that was secured in the form of large government and commercial customers. Additionally, the current fiscal year reflects the full-scale operation of a regional Liquefied Natural Gas importation facility that introduced large volumes of gas into the local market, putting downward pressure on WGEServices gas supply costs. The conditions that gave rise to the significant increase in earnings of WGEServices in fiscal year 2004 are not expected to recur in fiscal year 2005; accordingly, earnings in fiscal year 2005 are expected to be lower than they were in fiscal year 2004.
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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 enters into derivative contracts 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 Managements Discussion.
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 be limited in the near term. New Standard Offer Service (SOS) rates that went into effect in July 2004 for a Maryland electric utility that WGEServices directly competes with are below current market prices. This electric utility entered into contracts to supply its SOS customers with electricity in February 2004, prior to a surge in fuel prices required to generate electricity. SOS rates in Maryland and the District of Columbia will continue to be reset to market rates through annual procurements, and thereby are expected to offer continuing opportunities to build the electric customer base.
WGEServices entered into a master purchase and sale agreement in April 2000 with a wholesale energy marketer, Mirant Americas Energy Marketing L.P. (MAEM), which is an indirect wholly owned subsidiary of Mirant Corporation (Mirant). WGEServices purchases full requirements services from MAEM, including electric energy, capacity and certain ancillary services, for resale to retail electric customers. 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. To reduce dependency on a single supplier, during fiscal year 2004, WGEServices entered into separate master purchase and sale agreements under which it purchases full requirements services from three new wholesale electricity suppliers. Electric suppliers other than MAEM accounted for less than ten percent of WGEServices electricity purchases for fiscal year 2004. 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. Since the bankruptcy filing, MAEM has continued to honor its supply obligations to WGEServices. Future performance by MAEM may be subject to further developments in the bankruptcy proceedings (refer to the section entitled Market Risk included in Managements Discussion).
POTENTIAL FOR FURTHER UNBUNDLING
Currently, the Companys 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
15
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.
GAS SUPPLY AND 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 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, that are comparable to the services it received prior to the implementation of the order. At September 30, 2004, 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 2005 to 2024.
Washington Gas is responsible for acquiring both sufficient natural gas supplies and interstate pipeline 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 capacity market, its own on-system 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. The Company anticipates enhancing its peaking capacity by constructing a liquefied natural gas peaking facility that is expected to be completed and placed in service by the 2008-2009 winter heating season.
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 capacity. Depleting pipeline 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 co-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 capacity. These facilities, which significantly utilize pipeline capacity, may ultimately affect 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 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 for the planning, solicitation of interest, regulatory approval and construction of new pipelines. Washington Gas contracted with an interstate pipeline company, Dominion Transmission, Inc. (DTI), under which DTI constructed additional capacity for
16
firm transportation and storage services to Washington Gas. Approved by the FERC, this pipeline construction project was completed and placed in service for the 2004-2005 winter heating season. Washington Gas will continue to monitor other opportunities to acquire or participate in obtaining additional pipeline capacity that will improve or maintain the high level of service expected by its customer base.
Sources of Natural Gas
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 2004 (November 1, 2003 through October 31, 2004), and from which supplies can be received in pipeline year 2005 (November 1, 2004 through October 31, 2005). 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 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-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 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 2004 (November 1, 2003
through October 31, 2004), total sendout on the system was
1.673 billion therms as compared to total sendout of
1.754 billion therms during pipeline year 2003. This excludes
the sendout of sales and deliveries of natural gas used for
electric generation. The decrease in 2004 was the result of
weather in pipeline year 2004 that was warmer than pipeline year
2003. The sendout for pipeline year 2005 is estimated at
1.653 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 2004
and those projected for pipeline year 2005 are shown in the
following table.
Sources of Delivery for Annual Sendout
(In millions of therms)
Pipeline Year
Sources of Delivery
Actual 2004
Projected 2005
705
684
217
231
13
14
1
9
8
41
729
674
1,673
1,653
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 2004-2005 winter season is 17.4 million therms, and Washington Gas projected sources of delivery for design day sendout is 18.7 million therms. This provides a reserve margin of approximately 7.5 percent. Washington Gas is currently capable of meeting 77 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 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 2005.
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Projected Sources of Delivery for Design Day Sendout
(In millions of therms)
Pipeline Year 2005
Sources of Delivery
Volumes
Percent
5.4
29%
5.4
29%
6.7
36%
1.2
6%
18.7
100%
Washington Gas believes the combination of the natural gas supply it can purchase under short-term contracts, its existing and planned peaking supplies, and the capacity held under contract on the interstate pipelines is sufficient to satisfy the needs of existing customers and allow for growth in future years.
Rising Natural Gas Prices
Increased prices for natural gas are being driven by increased demand that is exceeding the growth in available supply. Although this has put upward pressure on natural gas prices and the competitiveness of natural gas as an energy source, the Company believes it will be able to fully meet its current customers demand for natural gas and to grow its customer base in the future.
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. 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.
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:
| the complexity of the site; | |
| changes in environmental laws and regulations at the federal, state and local levels; | |
| the number of regulatory agencies or other parties involved; | |
| new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; | |
| the ultimate selection of technology; | |
| the level of remediation required; and | |
| variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site. |
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
18
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. Washington Gas is working with the owner of the affected adjoining property to adopt a remediation plan for that portion of the site.
At a second former MGP site and on an adjacent parcel of land, Washington Gas made application under a state voluntary closure program. Washington Gas developed a monitoring-only remediation plan for the site for which it received state approval during fiscal year 2004. Accordingly, the Company reduced its liability in fiscal year 2004 for estimated environmental response costs related to this matter.
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. Large customers are generally on interruptible rate schedules, and margin-sharing arrangements generally limit the effects of variations in interruptible customer usage on net income. As previously discussed, Washington Gas served approximately one million customers at September 30, 2004. The Companys energy-marketing segment is not heavily dependent on any one customer or group of customers. The commercial HVAC segment derived approximately 44 percent and 45 percent of revenues from one customer, the Federal Government, in fiscal years 2004 and 2003, respectively.
The Companys 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 2004, approximately 77 percent of the total therms delivered in the regulated utilitys franchise area, excluding deliveries for electric generation, occurred in the regulated utilitys first and second fiscal quarters. The Companys 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 utilitys 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 through the Companys issuance of commercial paper.
The Companys research and development costs during fiscal years 2004, 2003 and 2002 were not material.
19
At September 30, 2004, the Company and its wholly owned subsidiaries had 1,914 employees comprised of 1,695 utility and 219 non-utility employees.
The Companys 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, DC 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, 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 Exchange Commission (SEC). Additional information about WGL Holdings is also available on its Web site. The Companys Chairman and Chief Executive Officer certified to the New York Stock Exchange (NYSE) on March 18, 2004 that, as of that date, he was unaware of any violation by the Company of the NYSEs corporate governance listing standards.
20
WGL Holdings, Inc.
ITEM 2. PROPERTIES
At September 30, 2004, WGL Holdings and its subsidiaries provided services in various areas of Virginia, the District of Columbia and Maryland, and held certificates of convenience and necessity, licenses and permits necessary to maintain and operate their respective properties and businesses. The regulated utility segment is the only segment where property, plant and equipment is a significant asset.
Property, plant and equipment are stated at original cost, including labor, materials, taxes and overhead. Washington Gas calculates depreciation applicable to its utility gas plant in service primarily using a straight-line method over the estimated remaining life of the plant. The composite depreciation and amortization rate of the regulated utility during fiscal years 2004, 2003 and 2002 was 3.48 percent, 3.20 percent and 2.93 percent, respectively, which included an allowance for estimated accrued non-legal asset removal costs (see Note 1 of the Notes to Consolidated Financial Statements).
At September 30, 2004, the regulated utility segment had approximately 625 miles of transmission mains, 11,295 miles of distribution mains, and 13,089 miles of distribution services. The regulated utility has the storage capacity for approximately 15 million gallons of propane for peak shaving.
Washington Gas owns approximately 40 acres of land and a building (built in 1970) at 6801 Industrial Road in Springfield, Virginia. The Springfield site performs both operating and certain administrative functions of the regulated utility. Washington Gas also holds title to land and buildings used as substations for its utility operations.
Washington Gas also has peaking facilities to enhance deliverability in periods of peak demand in the winter that consist of propane air plants in Springfield, Virginia (Ravensworth Station), and Rockville, Maryland (Rockville Station). Hampshire operates an underground natural gas storage field in Hampshire County, West Virginia. Hampshire accesses the storage field through 12 storage wells that are connected to an 18-mile pipeline gathering system. Hampshire also operates a compressor station for injection of gas into storage. For pipeline year 2005, management estimates that the Hampshire storage facility has the capacity to supply approximately 2.0 billion cubic feet of natural gas to the regulated utilitys system for meeting seasonal demands.
Washington Gas owns a 12-acre parcel of land located in Southeast Washington, D.C. Washington Gas entered into an agreement with a national developer in February 2000 to develop this land in phases. The first two phases have been developed, with Washington Gas retaining a ground lease on each phase. See the sections entitled Subsidiaries and Environmental Matters under Item 1 of this report for a discussion regarding WG Maritime and for additional information regarding this development.
Facilities utilized by the retail energy-marketing and commercial HVAC segments are located in the Washington, D.C. metropolitan area and are leased.
The Mortgage of Washington Gas dated January 1, 1933 (Mortgage), as supplemented and amended, securing any First Mortgage Bonds (FMBs) it issues, constitutes a direct lien on substantially all property and franchises owned by the regulated utility other than a small amount of property that is expressly excluded. At September 30, 2004 and 2003, no debt was outstanding under the Mortgage.
Washington Gas executed a supplemental indenture to its unsecured Medium-Term Note (MTN) Indenture on September 1, 1993, providing that Washington Gas will not issue any FMBs under its Mortgage without securing all MTNs with all other debt secured by the Mortgage.
21
WGL Holdings, Inc.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
22
EXECUTIVE OFFICERS OF THE REGISTRANTS
The names, ages and positions of the executive officers of the registrants at September 30, 2004, 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.
Executive Officers
Date Elected or
Name, Age and Position with the registrants
Appointed
January 24, 2004
January 24, 2004
October 31, 2000
July 3, 2000
March 3, 2000
January 31, 1996
April 29, 2002
July 1, 2001
July 1, 2001
October 1, 1998
March 31, 1999
October 1, 2001
October 1, 2001
October 31, 2000
July 1, 2000
January 13, 2000
December 1, 1998
January 13, 2000
March 31, 1999
January 13, 2000
March 31, 1999
October 1, 2001
November 13, 2000
April 3, 2000
April 28, 1997
23
Executive Officers | |||
|
|||
Date Elected or | |||
Name, Age and Position with the registrants | Appointed | ||
|
|||
Terry D. McCallister,
Age 49 (1,3)
|
|||
President and Chief Operating Officer
|
October 1, 2001 | ||
President and Chief Operating Officer of WGL
Holdings, Inc.
|
October 1, 2001 | ||
Vice President (operations and gas transportation)
|
June 28, 2000 | ||
Vice President (operations)
|
April 3, 2000 | ||
Mark P. OFlynn,
Age 54 (1,4)
|
|||
Controller
|
February 18, 2002 | ||
Controller of WGL Holdings, Inc.
|
February 18, 2002 | ||
Douglas V. Pope,
Age
59 (1)
|
|||
Secretary of WGL Holdings, Inc.
|
January 13, 2000 | ||
Secretary
|
July 25, 1979 | ||
Roberta W. Sims,
Age
50
|
|||
Vice President (corporate relations and
communications)
|
January 31, 1996 | ||
William Zeigler, Jr.,
Age 59 (5)
|
|||
Vice President (human resources and
organizational development)
|
February 1, 2004 | ||
Division Head (organizational development)
|
February 10, 2003 | ||
James B. White,
Age
54
|
|||
Vice President (customer service)
|
October 14, 2002 | ||
Vice President (business development)
|
February 21, 1996 | ||
|
(1) | Executive Officer of both WGL Holdings, Inc. and Washington Gas Light Company. | |
(2) | Mr. Bonner has previously served in executive positions in gas supply, customer services, operations and engineering at South Jersey Gas Company, Philadelphia Gas Works and Boston Gas Company. | |
(3) | Mr. McCallister was previously employed by Southern Natural Gas Company, a subsidiary of Sonat, Inc., where he served as Vice President and Director of Operations. Prior to working for Southern Natural Gas Company, a gas utility, he held various leadership positions with Atlantic Richfield Company, a fully integrated international oil and gas exploration, production, refining and marketing company. | |
(4) | Mr. OFlynn has more than 30 years of experience in various finance positions with natural gas and electric utilities. He has previous experience as a CFO, controller and treasurer of utility companies that were SEC registrants. | |
(5) | Mr. Zeigler was previously employed by Ernst & Young LLP (E&Y) where he served as National Director of Leadership and Organizational Change. Prior to joining E&Y, Mr. Zeigler was Senior Director, Organization Development and Training with Praxair, Inc. of Danbury, CT. |
24
WGL Holdings, Inc.
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
At October 31, 2004, WGL Holdings had 16,805 common shareholders of record. During fiscal years 2004 and 2003, WGL Holdings common stock was listed for trading on the New York Stock Exchange and was shown as WGL Hold or WGL Hldgs in newspapers. The Company did not purchase any of its outstanding common stock during fiscal years 2004 and 2003. The table below shows quarterly price ranges and quarterly dividends paid for fiscal years ended September 30, 2004 and 2003.
25
WGL Holdings, Inc.
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL AND OPERATIONS
DATA
(a)
(In thousands, except per share data)
Years Ended September 30,
2004
2003
2002
2001
2000
$
1,267,948
$
1,301,057
$
925,131
$
1,446,456
$
1,031,105
668,968
696,561
459,149
904,416
552,579
50,079
40,465
27,549
40,616
35,598
$
548,901
$
564,031
$
438,433
$
501,424
$
442,928
$
226,751
$
216,255
$
205,061
$
194,469
$
177,504
$
821,655
$
763,191
$
659,671
$
493,063
$
218,087
$
96,637
$
112,342
$
39,121
$
82,445
$
83,251
$
1.99
$
2.31
$
0.81
$
1.75
$
1.79
$
1.98
$
2.30
$
0.80
$
1.75
$
1.79
$
853,424
$
818,218
$
766,403
$
788,253
$
711,496
28,173
28,173
28,173
28,173
28,173
590,164
636,650
667,951
584,370
559,724
$
1,471,761
$
1,483,041
$
1,462,527
$
1,400,796
$
1,299,393
$
2,504,908
$
2,436,052
$
2,339,146
$
2,292,999
$
2,139,989
$
1,915,551
$
1,874,923
$
1,832,325
$
1,731,633
$
1,660,280
$
113,439
$
129,083
$
162,383
$
130,215
$
124,067
$
590,164
$
636,650
$
667,951
$
584,370
$
559,724
$
1.30
$
1.28
$
1.27
$
1.26
$
1.24
$
1.2950
$
1.2775
$
1.2675
$
1.2550
$
1.2350
$
17.54
$
16.83
$
15.78
$
16.24
$
15.31
11.6
%
14.2
%
5.0
%
11.0
%
11.9
%
7.4
%
7.6
%
8.0
%
7.7
%
8.1
%
65.1
%
55.3
%
156.5
%
71.7
%
69.0
%
48,653
48,612
48,565
48,543
46,470
UTILITY GAS SALES AND DELIVERIES
(thousands of therms)
629,728
648,809
509,243
634,949
557,825
226,407
239,628
193,917
258,546
240,239
7,626
12,163
10,646
11,927
27,627
863,761
900,600
713,806
905,422
825,691
454,549
496,889
346,910
365,262
306,933
268,483
257,799
277,367
251,039
262,923
41,052
67,245
169,210
165,918
211,928
764,084
821,933
793,487
782,219
781,784
1,627,845
1,722,533
1,507,293
1,687,641
1,607,475
990,062
959,922
939,291
903,789
875,817
29,438
26,167
31,205
32,188
30,063
4,024
4,550
3,304
4,314
3,637
6.1
%
19.8
%
(13.4
)%
13.1
%
(5.0
)%
(a) | Results presented for fiscal year 2000 reflect the consolidated operations of Washington Gas Light Company and its subsidiaries. |
26
WGL Holdings, Inc.
Washington Gas Light Company
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
This Managements Discussion and Analysis of Financial Condition and Results of Operations (Managements Discussion) analyzes the financial condition, results of operations and cash flows of WGL Holdings, Inc. (WGL Holdings or the Company) and its subsidiaries. It also includes managements analysis of the Companys past financial results and potential factors that may affect future results, potential future risks and approaches that may be used to manage them.
Managements discussion is divided into the following two major sections:
| WGL Holdings This section describes the financial condition and results of operations of WGL Holdings and its subsidiaries on a consolidated basis. It includes discussions of WGL Holdings regulated utility and non-utility operations. The majority of WGL Holdings operations are derived from the results of its regulated utility, Washington Gas Light Company (Washington Gas), and to a much lesser extent, the results of its non-utility operations. For more information on the Companys regulated utility operations, please refer to the Managements Discussion for Washington Gas. | |
| Washington Gas This section comprises the majority of WGL Holdings regulated utility segment. The financial condition and results of operations of Washington Gas utility operations and WGL Holdings regulated utility segment are essentially the same. |
Both of the major sections of Managements DiscussionWGL Holdings and Washington Gasshould be read to obtain an understanding of the Companys operations and financial performance. Managements Discussion also should be read in conjunction with the respective companys Consolidated Financial Statements and the combined Notes to Consolidated Financial Statements thereto.
The Glossary of Key Terms included in this Annual Report on Form 10-K defines certain terms used in this Managements Discussion. Bold Italics indicate the first reference to a term defined in the Glossary of Key Terms.
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.
Managements Discussion Table of Contents
Page | |||||
|
|||||
Executive Overview
|
28 | ||||
Primary Factors Affecting WGL Holdings and
Washington Gas
|
29 | ||||
Critical Accounting Policies
|
33 | ||||
WGL Holdings, Inc.
|
|||||
Results of Operations
|
36 | ||||
Liquidity and Capital Resources
|
41 | ||||
Credit Risk
|
49 | ||||
Market Risk
|
49 | ||||
Washington Gas Light Company
|
|||||
Results of Operations
|
53 | ||||
Liquidity and Capital Resources
|
57 | ||||
Regulatory Matters
|
58 |
27
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 Companys 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 closely related to its core business. In response to changes in federal and state regulation, the Company has taken the initiative to offer competitively priced natural gas and electricity to customers through its unregulated retail energy-marketing subsidiary.
WGL Holdings has three operating segments that are described below:
| regulated utility; | |
| retail energy-marketing; and | |
| commercial heating, ventilating and air conditioning ( HVAC ) products and services. |
Transactions not specifically identifiable in one of the above three segments are accumulated and reported in the category Other Activities.
Regulated Utility. With approximately 93 percent of the Companys consolidated total assets, the regulated utility segment (represented by Washington Gas and Hampshire Gas Company (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 the regulated utility incurs. At September 30, 2004, the regulated utility was selling and delivering the natural gas commodity to 82 percent of its customers. The remaining 18 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 a subsidiary of Washington Gas Resources. Factors critical to the success of the regulated utility include operating a safe, reliable natural gas distribution system, and 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 utilitys rates. 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. Washington Gas Energy Services, Inc. ( 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 utilitys traditional service territory. WGEServices does not own or operate any natural gas or electric generation, 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 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, managing credit risks associated with customers of and suppliers to this segment, and controlling the level of selling, general and administrative costs, most notably customer acquisition costs.
28
Commercial HVAC. Two wholly owned subsidiaries, American Combustion Industries, Inc. ( ACI ) and Washington Gas Energy Systems, Inc. ( WGESystems ), provide turnkey, design-build and renovation projects to the commercial and government markets. As a result of a restructuring agreement on September 20, 2002 and a final closing on October 15, 2002 between the Company and a 50-percent investor, the Company no longer has any investment in or any financial commitment to its former residential HVAC investment.
The commercial HVAC operations focus on retrofitting 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 generating adequate revenue from the government and private sectors in the new construction and retrofit markets, estimating and managing fixed-price contracts and controlling selling, general and administrative expenses.
Refer to the Business section under Item 1 of this report for a further discussion of the Companys regulated utility and unregulated businesses. For a further discussion of the Companys 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 Companys financial condition and operating performance:
Return on Average Common Equity. This measure is calculated by dividing 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.
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 Liquidity and Capital ResourcesGeneral Factors Affecting Liquidity section of Managements Discussion for a discussion of the Companys 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 Business section 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
The Companys 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. Weather conditions directly influence the volume of natural gas delivered by the regulated utility. The regulated utilitys rates are determined on the basis of expected normal weather conditions. As such, deviations in weather from normal levels can affect the Companys financial performance. Washington Gas does not have a ratemaking provision that allows 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. However, the regulated utility does have a weather insurance policy designed to protect against a portion of warmer-than-normal weather (refer to Market Risk included herein for a further discussion of this weather insurance policy).
The financial results of the Companys 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.
29
Regulatory Environment
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. 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 Companys 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.
Gas Supply and Storage Capacity
Natural Gas Supply and Capacity Requirements. Washington Gas is responsible for acquiring both sufficient natural gas supplies and interstate pipeline 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 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 capacity. Depleting pipeline 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. To help maintain the adequacy of pipeline capacity for its growing customer base, Washington Gas contracted with an interstate pipeline company to construct additional capacity for firm transportation and storage services to Washington Gas. This pipeline construction project was completed and placed in service for the 2004-2005 winter heating season. Washington Gas will continue to monitor other opportunities to acquire or participate in obtaining additional pipeline capacity that will improve or maintain the high level of service expected by its customer base.
Washington Gas believes the combination of the natural gas supply it can purchase under short-term contracts, its existing and planned peaking supplies and the capacity held under contract on the interstate pipelines is sufficient to satisfy the needs of existing customers and allow for growth in future years. Washington Gas anticipates enhancing its peaking capacity through the construction of a liquefied natural gas peaking facility (refer to Liquidity and Capital Resources Capital Expenditures for a further discussion of this matter).
Rising Natural Gas Prices. Recently there have been significant increases in the price of natural gas; the price of natural gas remains volatile. Price increases have been driven by an increased demand for natural gas that is exceeding the growth in available supply each year. Washington Gas believes that there will be sufficient supplies of natural gas to fully meet current customers demand for natural gas and to grow its customer base in the future. Price increases, however, have resulted in significant increases in the cost of natural gas billed to customers that, if continued, could shift customers preference away from natural gas and towards other energy sources such as electricity. Price increases could also make it more difficult for customers to pay their bills and thereby could increase the regulated utilitys level of bad debt expense.
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. 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.
30
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 utilitys net income. In its service territory, Washington Gas continues to attract the majority of the new residential construction market. The Company believes that consumers continuing preference for natural gas allows Washington Gas to maintain a strong market presence.
In the interruptible market, the regulated utilitys customers must be capable of using a fuel other than natural gas when demand peaks for the regulated utilitys firm customers. In the interruptible market, fuel oil is the prevalent energy alternative to natural gas. The regulated utilitys 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 anticipated introduction of non-domestic supplies of liquefied natural gas into the United States natural gas market may affect supply levels and have an impact on natural gas prices. To date, the effect of liquefied natural gas on supply levels has been minimal.
Deregulation and Unbundling. In each of the jurisdictions served by the Companys regulated utility, regulators and utilities have implemented customer choice programs. These programs provide customers with an opportunity to choose to purchase their natural gas and/or electric commodity from 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 third-party marketers on an unbundled basis, there is no effect on the regulated utilitys 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 Companys 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 utilitys 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 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.
To manage this risk, 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 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 Companys unregulated subsidiary, 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. WGEServices also competes with other 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 market risks associated with its gas supply, as well as credit risks associated with both its gas and electric suppliers. See Market Risk and Credit Risk included herein for a further discussion of this risk exposure and WGEServices management of them.
31
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 Companys regulated utility to expand its regulated delivery service customer base at a rate of growth well over twice the national industry average during the past five years. In addition, this economy has provided a robust market for the Companys 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 Companys 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 short- and long-term debt financings. 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 Companys 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 Companys 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 utilitys replacement cost of plant and equipment. While the regulatory commissions, having jurisdiction over the regulated utilitys 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 Companys 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), AFL-CIO, is a local union affiliated with the International Brotherhood of Teamsters. On June 1, 2004, Local 96 signed a new three-year labor contract with Washington Gas, replacing its previous labor contract that expired on May 31, 2004. The contract covers approximately 700 employees. The provisions of the new labor contract include general wage increases of 3.5 percent per year on June 2, 2004, June 1, 2005 and June 1, 2006. Additionally, the contract contains a
32
provision that Washington Gas will not lay off any full-time, Local 96-eligible employee who was employed by Washington Gas on the date of contract ratification. Increases in contributions by employees for medical and prescription drug benefit co-pays are also included in the labor contract.
On July 30, 2004, Local 96, representing union-eligible employees in the Shenandoah Gas division, signed a three-year labor contract with Washington Gas. This contract covers 23 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. Additionally, the Company has two three-year labor contracts with the International Brotherhood of Electrical Workers Local 1900 that together cover approximately 32 employees.
Potential Changes in Accounting Principles
The Company cannot predict the effect of potential future changes in accounting regulations or practices in general 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 Companys reported earnings or increase its liabilities.
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 Companys 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 five critical accounting policies discussed below that require managements judgment and estimation, where such estimates have a material effect on the consolidated financial statements.
Accounting for Utility 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. Such revenues are recognized as unbilled revenues that are adjusted in subsequent periods when actual meter readings are taken.
The regulated utilitys 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. 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 Companys business is subject to regulation. As the regulated utility industry continues to address competitive market issues, the cost-of-service regulation used to compensate the Companys 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 utilitys investment in fixed assets.
Washington Gas accounts for its regulated activities 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 non-regulated businesses. SFAS No. 71 requires the recording of regulatory
33
assets and liabilities for certain transactions that would have been treated as revenue and 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. 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, the Companys regulated utility could be required to write off certain regulatory assets that had been deferred on the Consolidated Balance Sheets in prior periods, and charge these costs to expense at the time it determines that the provisions of SFAS No. 71 no longer apply. If WGL Holdings or 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 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 Companys regulatory activities, and that all of its regulatory assets and liabilities as of September 30, 2004 and 2003 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 managements estimates and actual tax amounts could have a material impact on the Companys operating results and financial condition.
Accounting for Contingencies
The Company recognizes 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 managements judgment of such events and managements 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 2004 and 2003, the Company was involved with regulatory contingencies with respect to pending rate cases in Virginia.
Under the regulations of the SCC of VA, Washington Gas placed a proposed revenue increase into effect November 12, 2002, subject to refund pending the SCC of VAs final decision on a rate case proceeding. Washington Gas financial results for fiscal year 2003 reflected the proposed revenue increase, along with a provision for rate refunds to customers based on the difference between the amount Washington Gas had collected in rates subject to refund during fiscal year 2003 and the estimated amount management expected to recover based on the final outcome of the rate case proceeding. On December 18, 2003, a Final Order was issued by the SCC of VA which approved an increase in rates that approximated the amount that management had estimated would be derived from this case. 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.
On February 26, 2004, Washington Gas placed a proposed revenue increase into effect, subject to refund, pending the SCC of VAs 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 the December 18, 2003 Final Order of the SCC of VA. Refunds to customers, with interest, are being made in the December 2004 billing cycle for the amount of the proposed annual revenue increase
34
that had been collected since February 26, 2004. The Companys financial results for the nine months ended June 30, 2004 reflected the proposed revenue increase, along with a provision for rate refunds to customers based on managements judgment at that time. In response to the September 27, 2004 Final Order, Washington Gas increased its provision for rate refunds in the quarter ended September 30, 2004 to the full amount of revenues that had been collected subject to refund through September 30, 2004. The increased provision eliminated the revenue increase of $2.2 million (pre-tax) that was previously included in net income for the nine months ended June 30, 2004. After the additional provision for rate refunds was recorded in the quarter ended September 30, 2004, there was no effect on fiscal year 2004, nor will there be any effect on fiscal year 2005 earnings for the rates put into effect subject to refund in February 2004.
In the December 18, 2003 Final Order, 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. During fiscal year ended September 30, 2004, Washington Gas recorded additional depreciation expense of $1.0 million in connection with earnings tests performed. The amount recorded could change if the VA Staff differs with managements calculations or methodology.
For further discussion of these regulatory activities and related contingencies, see Note 14 of the Notes to Consolidated Financial Statements.
Accounting for Derivative Instruments
The Company enters into forward contracts and other related transactions for the purchase of natural gas. 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 interest-rate risk associated with planned issuances of Medium-Term Notes (MTNs).
Managements judgment is required in determining the appropriate accounting treatment for Washington Gas derivative instruments. This judgment involves various factors, including managements 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 Companys natural gas forward contracts 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 fair value derived for these contracts reflects managements 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 whose 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 net income.
35
WGL HOLDINGS, INC.
RESULTS OF OPERATIONS
Summary
Results
WGL Holdings reported net income of
$96.6 million, or $1.98 per share, for the fiscal year
ended September 30, 2004, as compared to net income of
$112.3 million, or $2.30 per share, and $39.1 million,
or $0.80 per share, for the fiscal years ended
September 30, 2003 and 2002, respectively. The Company
earned returns of 11.6 percent, 14.2 percent and
5.0 percent, respectively, on average common equity during
each of these three fiscal years.
The operating results of the Companys core
regulated utility operations are the primary influence on
overall consolidated operating results. Weather for fiscal year
2004, when measured by an industry standard called heating
degree days
, 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 $10 million, or $0.20
per share. During fiscal year 2003, weather was
19.8 percent colder than normal, contributing an estimated
$25 million, or $0.51 per share, to net income for that
year. Earnings comparisons between the current and prior fiscal
year also reflect continued customer growth and the impact of
favorable rate decisions, which together increased net income by
an estimated $0.22 per share. Earnings from the Companys
major non-utility operations improved slightly, with the
Companys retail energy-marketing segment increasing its
net income over the prior fiscal year by $4.5 million to
$8.3 million. This improvement was mostly offset by a
$4.2 million increased net loss incurred by the
Companys commercial HVAC segment, in which its net loss
increased from $1.2 million in fiscal year 2003 to
$5.4 million in fiscal year 2004. Operating results for
fiscal year 2004 also reflect increased utility operation and
maintenance expenses and higher depreciation and amortization
expense.
Earnings comparisons between fiscal years 2004
and 2003 also reflect the following transactions related to the
Companys utility and non-utility segments. Fiscal year
2004 included:
(i)
an after-tax gain of
$5.8 million, or $0.12 per share, from the sale of two
buildings by a third party in a commercial development project
in which the Company held a carried interest accounted for under
the equity method (Maritime sale),
(ii)
the recognition
of additional depreciation expense of $3.5 million
(pre-tax), or $0.04 per share, which related to a prior period
and was recorded in connection with a Virginia rate order, and
(iii)
a charge of $1.5 million, or $0.03 per share,
for an impairment of goodwill related to the Companys
investment in its HVAC business. Fiscal year 2003 included:
(i)
an after-tax gain of $2.5 million, or $0.05 per
share, from the sale of the Companys former headquarters
property,
(ii)
an after-tax gain of $926,000, or $0.02
per share, from the sale of a real estate partnership interest,
(iii)
a favorable income tax adjustment of
$2.7 million, or $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 Companys non-utility
activities.
Net income for fiscal year 2003 of
$112.3 million, or $2.30 per share, more than doubled the
Companys net income reported for fiscal year 2002. The
significant earnings improvement for fiscal year 2003 was
attributable primarily to 37.7 percent colder weather as
compared to fiscal year 2002, as well as customer growth, the
favorable impact of new retail rates in Maryland and Virginia and a new rate design in
the District of Columbia. The Companys non-utility
operations also contributed to the favorable earnings comparison
for fiscal year 2003, primarily due to after-tax charges
included in fiscal year 2002 totaling $18.0 million, or
$0.37 per share, associated with the Companys former
co-investment in a residential HVAC business and a consumer
finance business that is no longer making new loans.
Additionally, fiscal year 2003 benefited from after-tax gains
from asset sales and favorable tax adjustments, as mentioned
above.
36
The following table summarizes the Companys
net income (loss) by operating segment for fiscal years
ended September 30, 2004, 2003 and 2002.
Regulated
Utility Operating Results
The Companys 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, 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
warmer weather in the current fiscal year than in fiscal year
2003, partially mitigated by increased customers. Weather was
11.6 percent warmer in the current fiscal year than in the
prior fiscal year.
Fiscal year 2004 earnings of the regulated
utility segment benefited from the addition of 30,140 active
customer meters, an increase of 3.1 percent. Further
contributing to earnings for the current fiscal year was 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 the rate decision that became effective in
Virginia in November 2002.
As discussed earlier in
Critical
Accounting Policies Accounting for Contingencies,
a Virginia rate increase also went into effect on
February 26, 2004, subject to refund, pending a final
decision by the SCC of VA on an expedited rate case application
that Washington Gas filed on January 27, 2004. The SCC of
VA issued a Final Order on September 27, 2004 approving a
proposed Stipulation filed by Washington Gas and other
participants to resolve all issues related to the expedited rate
case. The Stipulation resulted in no change to the level of
revenues that the Company had previously been allowed to
collect. A provision for rate refunds was recorded at
September 30, 2004 equivalent to the revenues that the
Company had collected in fiscal year 2004, subject to refund.
Accordingly, there was no effect of this rate case on earnings
in fiscal year 2004.
Fiscal year 2004 earnings for the regulated
utility segment also reflect $10.5 million of increased
operation and maintenance expenses. The increase in these
expenses reflects, among other things, an accrual of
$2.4 million for operational expenses recorded in the
current fiscal year for which the Company ultimately may be
partially or fully reimbursed; the potential reimbursement was
not accrued as a receivable as of September 30, 2004.
Additionally, this increase reflects increased costs associated
with employee benefits, employee severance, information
technology improvements and other miscellaneous items. Partially
offsetting these increases were lower uncollectible accounts
expense, and $2.7 million of lower costs associated with
post-retirement benefits other than pensions as a result of a
law enacted in December 2003 that entitles the Company to a
federal subsidy for sponsoring a retiree health care benefit
plan with a prescription drug benefit that is at least
actuarially equivalent to the benefit to be provided under
37
Medicare. The effect of this subsidy was applied
retroactively to January 1, 2004 in accordance with new
accounting guidelines issued in May 2004 by the FASB (refer to
Notes 1 and 11 of the Notes to Consolidated Financial Statements
for a further discussion of the accounting for the Medicare
subsidy). Further discussion of operation and maintenance
expenses of the regulated utility is included herein under
Managements Discussion for Washington Gas.
The regulated utility segment also incurred
$8.0 million of higher depreciation and amortization
expense for fiscal year 2004 when compared to 2003. This higher
expense was attributable to increased plant investment, as well
as the effect of the December 18, 2003 Final Order issued
by the SCC of VA. In connection with the Final Order, the
Company recorded additional depreciation expense of
$3.5 million (pre-tax), or $0.04 per share, to implement
higher depreciation rates applicable to the period from
January 1, 2002 through November 11, 2002.
Additionally, the Company recorded $1.0 million of
additional depreciation expense in fiscal year 2004 related to
the performance of earnings tests as required by the Final Order
in Virginia (refer to Note 14 of the Notes to Consolidated
Financial Statements for a further discussion of the
Companys regulatory activities and related contingencies).
In fiscal year 2003, the regulated utility
segment reported net income of $109.0 million, or $2.24 per
share, an increase of $57.3 million, or $1.18 per share,
over fiscal year 2002. This significant increase primarily
reflects a 31.9 percent increase in total gas deliveries to
firm customers that grew to 1.385 billion therms during
fiscal year 2003 due to colder weather, as well as the addition
of 20,631 active customer meters during the 2003 fiscal year.
Weather for fiscal year 2003 was 37.7 percent colder than
fiscal year 2002. Weather was 19.8 percent colder than
normal in fiscal year 2003. This compared to 13.4 percent
warmer-than-normal weather for fiscal year 2002 which reduced
net income in that year by an estimated $19 million, or
$0.39 per share (after considering an $8.7 million, or
$0.18 per share, benefit derived from a weather insurance
policy). Increased earnings for the utility segment in fiscal
year 2003 also was attributable to new retail rates put into
effect in Maryland on September 30, 2002 and in Virginia on
November 12, 2002, as well as the impact of a new rate
design in the District of Columbia that enabled a greater
recovery of fixed charges in the summer months beginning in
fiscal year 2003, despite an annual revenue reduction enacted by
the PSC of DC that became effective in April 2003. Tempering
these earnings improvements were $11.2 million of increased
operation and maintenance expenses and $10.6 million of
increased depreciation and amortization expense.
Earnings comparisons for the utility segment for
fiscal years 2004, 2003 and 2002 also were affected by an
after-tax gain realized in fiscal year 2003 of
$2.5 million, or $0.05 per share, as reflected in
Other income (expense) net, from the sale of
the Companys 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. Fiscal year
2002 also included a loss of $1.7 million, or $0.04 per
share, associated with a transaction with a bankrupt energy
trader.
Further discussion of the operating results of
the regulated utility is included herein in the
Managements Discussion for Washington Gas.
Non-Utility
Operating Results
The Companys non-utility operations are
comprised of two business segments: 1) retail
energy-marketing and 2) commercial HVAC. Certain of the
Companys 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 Companys
non-utility operations for fiscal year 2004 was
$7.7 million, or $0.16 per share, an improvement of
$4.4 million, or $0.10 per share, over fiscal year 2003.
Earnings for the current fiscal year were favorably affected by
the realization in fiscal year 2004 of an after-tax gain of
$5.8 million, or $0.12 per share, from the Maritime sale.
In fiscal year 2003, the Company realized an after-tax gain of
$926,000, or $0.02 per share, from the sale of a real estate
partnership interest, and benefited from a favorable adjustment
to income taxes of $2.1 million, or $0.04 per share,
resulting from the utilization of capital loss carryforwards.
With respect to the Companys two non-utility business
segments, 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, offset by a
$4.2 million, or $0.08 per share, increased net loss
incurred by the commercial HVAC segment.
38
Non-utility operations reported net income of
$3.3 million, or $0.06 per share, for fiscal year ended
September 30, 2003, as compared to a net loss of
$12.6 million, or $0.26 per share, for fiscal year 2002.
This significant improvement of $15.9 million, or $0.32 per
share, was primarily attributable to after-tax charges totaling
$18.0 million, or $0.37 per share, that were recorded in
fiscal year 2002 for which there were not similar charges
recorded in fiscal year 2003. These charges included a
$3.5 million, or $0.07 per share, after-tax operating loss
and a $9.4 million, or $0.19 per share, after-tax
impairment provision associated with the Companys former
50-percent equity investment in Primary Investors, a residential
HVAC business. Additionally included in fiscal year 2002 was a
$5.1 million, or $0.11 per share, after-tax loan loss
provision associated with a consumer finance business, which has
stopped accepting new loans.
The following table depicts the composition of
the changes in revenues for the non-utility business segments.
Retail Energy-Marketing.
The Companys 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.
Revenues for this segment have grown over the
past three years. Retail energy-marketing revenues were
$789.9 million, $726.2 million, and $595.9 million for
fiscal years 2004, 2003 and 2002, respectively.
WGEServices gas sales volumes totaled 71.7 billion
cubic feet (
bcf
) in fiscal year 2004, compared to
71.1 bcf and 61.0 bcf in fiscal years 2003 and 2002,
respectively. The retail energy-marketing segment had
approximately 150,800, 153,400 and 155,000 natural gas customers
at September 30, 2004, 2003 and 2002, respectively.
WGEServices sold 6.7 billion kilowatt hours (kwh) of
electricity in fiscal year 2004, compared to 7.5 billion
kwh and 6.5 billion kwh in fiscal years 2003 and 2002,
respectively. Electricity was provided to approximately 44,500
customers at September 30, 2004, compared to 76,000 and
66,000 customers at September 30, 2003 and 2002,
respectively.
The retail energy-marketing segment reported
record net income of $8.3 million, or $0.17 per share, for
fiscal year 2004, more than double its net income for fiscal
year 2003. This segments year-over-year improvement of
$4.5 million, or $0.09 per share, reflects 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.
Gross margins from natural gas sales were reduced in fiscal year
2003 in comparison to fiscal year 2002 due to the
colder-than-normal weather experienced during the 2002-2003
winter heating season that resulted in the need to make
additional purchases of natural gas at higher prices in the spot
market in order to meet commitments to customers. During fiscal
year 2004, WGEServices earned higher-than-historical gross
margins on its natural gas sales, reflecting additional business
that was secured in the form of large government and commercial
customers. Additionally, the current fiscal year reflects the
full-scale operation of a regional liquefied natural gas
importation facility that introduced large volumes of gas into
the local market, putting downward pressure on WGEServices
gas supply costs.
Lower gross margins from electric sales for the
current fiscal year 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. Lower gross margins
also reflect a reduction in commercial customers as competition
for large commercial customers intensified and as rising energy
prices encouraged some electric customers to return to
below-market standard offer service provided by the incumbent
electric utility. Looking ahead, in the near-term, future
opportunities to add new electric customers may be limited. New
Standard Offer Service (SOS) rates that went into effect in July
2004 for Maryland electric utilities are below current market
prices. These electric utilities entered into contracts to
supply their SOS customers with electricity in February 2004,
prior to a large surge in fuel prices. In the long-term,
however, SOS rates in Maryland, and soon in the District of
Columbia, will be
39
reset to market rates through annual
procurements, and thereby are expected to offer continuing
opportunities to build the electric customer base.
Given the higher-than-historical gross margins on
natural gas sales earned in fiscal year 2004 that may not be
repeated in fiscal year 2005, coupled with the uncertainties
regarding the short-term outlook for electric sales, the Company
does not foresee a continuation of the same level of
profitability from the retail energy-marketing segment in fiscal
year 2005 as was experienced in fiscal year 2004.
Net income for the retail energy-marketing
segment was $3.7 million for fiscal year 2003, or $0.08 per
share, as compared to net income of $5.0 million, or $0.10 per
share, for fiscal year 2002. The decline in fiscal year 2003 was
largely caused by a rapid rise in natural gas prices that
occurred in late February and early March of fiscal year 2003
that was more extreme than the planning parameters prescribed
in the Companys risk management policy. Consequently, the
colder-than-normal weather experienced in fiscal year 2003
resulted in the need to make additional purchases of natural gas
in the spot market at a cost above its retail selling price to
meet its commitments to customers, thereby reducing gross
margins. Gross margins from electricity sales increased due to a
16 percent increase in volumes sold, and a 29 percent
higher gross margin per kilowatt-hour.
Commercial HVAC .
Two subsidiaries, ACI and
WGESystems, offer large-scale HVAC installations and related
services to commercial and government customers. These
subsidiaries comprise the Companys commercial HVAC segment.
Revenues for the commercial HVAC segment were
$30.1 million for fiscal year 2004, as compared to
$35.5 million and $61.9 million for fiscal years 2003
and 2002, respectively. This comparison reflects the reduction
in work performed on behalf of one major customer, the Federal
Government, as well as an overall decrease in business activity.
In fiscal year 2004, 2003 and 2002, the Company generated
revenues of approximately 44 percent, 45 percent and
79 percent, respectively, from the Federal Government. 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
and net income of $4.0 million, or $0.08 per share, in
fiscal year 2002. These comparisons primarily reflect 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 the
Companys investment in this business.
Other Non-Utility Activities.
As previously discussed, some of
the Companys transactions are not significant enough on a
stand-alone basis to warrant treatment as a business segment.
For purposes of 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 2004 reflect a $4.1 million
improvement in net income over fiscal year 2003, primarily due
to the inclusion in the current fiscal year of the after-tax
earnings of $5.8 million, or $0.12 per share, realized from
the Maritime sale. In fiscal year 2003, the Company realized an
after-tax gain of $926,000, or $0.02 per share, from the sale of
a real estate partnership interest, and benefited from a
favorable adjustment to income taxes of $2.1 million, or
$0.04 per share, resulting from the utilization of capital loss
carryforwards.
Operating results from other non-utility
activities for fiscal year 2003 improved $9.4 million, or
$0.19 per share, over fiscal year 2002 due primarily to a
$5.1 million, or $0.11 per share, loan loss provision
recorded in fiscal year 2002 associated with a consumer finance
business that has stopped accepting new loans. Favorably
affecting fiscal year 2003 results were the after-tax gain of
$926,000, or $0.02 per share from the sale of the real estate
partnership, and the favorable tax adjustment of
$2.1 million, or $0.04 per share.
Other
Income (Expenses) Net
Other income (expenses) net improved by
$2.4 million in fiscal year 2004 over fiscal year 2003. The
improvement in income was attributable primarily to the
after-tax earnings of $5.8 million realized in the current
fiscal year from the Maritime sale, and increased interest
income earned on higher short-term investment balances,
partially offset by other charges. In fiscal year 2003, the
Company realized after-tax gains of $2.5 million from the
sale of its headquarters property and $926,000 from the sale of
a real estate partnership interest.
40
Other income (expense) net improved by
$450,000 in fiscal year 2003 over fiscal year 2002. This
improvement was primarily the result of after-tax gains of
$2.5 million and $926,000 realized from the real estate
sales, as discussed above. The favorable comparison over fiscal
year 2002 was also attributable to the inclusion in 2002 of
$3.9 million of after-tax expenses related to uncollectible
accounts, as well as an after-tax loss of $1.7 million
associated with a transaction with a bankrupt energy trader.
Substantially all of these improvements were offset by
$8.7 million of after-tax benefits recorded in fiscal year
2002 for the proceeds from a weather insurance policy. There
were no weather insurance proceeds recorded in fiscal years 2003
and 2004.
Interest
Expense
Interest expense incurred by WGL Holdings and its
subsidiaries of $44.1 million for the year ended
September 30, 2004 decreased $2.2 million from fiscal
year 2003, and increased $504,000 in fiscal year 2003 over 2002. MTNs, that comprise substantially
all of the Companys long-term debt, had a weighted average cost
of 6.46 percent,
6.58 percent and 6.70 percent at September 30, 2004,
2003 and 2002, respectively. The following table shows the
components of the changes in interest expense between years.
The $2.2 million decrease in WGL
Holdings interest expense for fiscal year 2004 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
cost of these borrowings.
The increase in interest expense for fiscal year
2003 compared to 2002 primarily stems from increased interest
costs on long-term debt due to an increase in the average
balance of long-term debt outstanding, partially offset by a
decrease in the weighted average cost of these borrowings.
Reduced interest costs related to short-term borrowings for
fiscal year 2003 when compared to 2002 reflects a decrease in
the average balance outstanding, combined with a decrease in the
weighted average cost of short-term debt.
LIQUIDITY AND CAPITAL
RESOURCES
General
Factors Affecting Liquidity
It is important for the Company to have access to
short-term debt markets to maintain satisfactory liquidity to
operate its businesses on a near-term basis. Acquisition of
natural gas, electricity, pipeline capacity, and the need to
finance accounts receivable are the most significant short-term
financing requirements of the Company. The need for long-term
capital is driven primarily by capital expenditures and
maturities of long-term debt.
Significant swings can take place in the level of
short-term debt required by the Company due primarily to changes
in the price and volume of natural gas and electricity purchased
to satisfy customer demand, and also due to seasonal cash
collections on accounts receivable. Backup financing to the
Companys commercial paper program in the form of revolving
credit agreements enables the Company to maintain access to
short-term debt markets. The ability of the Company to obtain
such financing depends on its credit ratings, which are greatly
affected by the Companys financial performance and the
liquidity of financial markets. Also potentially affecting
access to short-term debt capital is the nature of any
restrictions that might be placed upon the Company such as
ratings triggers or a requirement to provide creditors with
additional credit support in the event of a determination of
insufficient creditworthiness.
41
The ability to procure sufficient levels of
long-term capital at reasonable costs is determined by the level
of the Companys capital expenditure requirements, its
financial performance, and the effect of these factors on its
credit ratings and investment alternatives available to
investors.
The Company has a goal to maintain its common
equity ratio in the mid-50 percent range of total consolidated
capital. In addition, the Company typically reduces short-term
debt balances in the spring because a significant portion of the
Companys current assets is converted into cash at the end
of the winter heating season. Accomplishing these capital
structure objectives and maintaining sufficient cash flow are
necessary to maintain attractive credit ratings for the Company
and Washington Gas, and to allow access to capital at reasonable
costs. As of September 30, 2004, total consolidated
capitalization, including current maturities of long-term debt
and excluding notes payable, comprised 55.7 percent common
equity, 1.8 percent preferred stock and 42.5 percent
long-term debt. The cash flow requirements of the Company and
the ability to provide satisfactory resources to satisfy those
requirements are primarily influenced by the activities of
Washington Gas and to a lesser extent the non-utility operations.
The Company believes it has sufficient liquidity
to satisfy its financial obligations. At September 30,
2004, the Company did not have any restrictions on its cash
balances that would affect the payment of common or preferred
stock dividends by WGL Holdings or Washington Gas.
Short-Term
Cash Requirements and Related Financing
The regulated utilitys business is weather
sensitive and seasonal, causing short-term cash requirements to
vary significantly during the year. Over 75 percent of the
total therms delivered in the regulated utilitys
service area
(excluding deliveries to two electric
generation facilities) occur during the first and second fiscal
quarters. Cash requirements peak in the fall and winter months
when accounts receivable, accrued utility revenues and storage
gas inventories are at their highest levels. After the winter
heating season, many of these assets are converted into cash,
which the Company generally uses to reduce and sometimes
eliminate short-term debt and acquire storage gas for the next
heating season.
The Companys 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.
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 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 usually
caused by the price paid to producers and marketers, which is a
function of short-term market fluctuations in gas costs. 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 utilitys 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, 2004, the
regulated utility had a $3.7 million net over-collection of
gas costs compared to a $3.8 million under-collection at
September 30, 2003. The change from the prior year was
primarily due to the collection of the balance at
September 30, 2003 during fiscal year 2004, coupled with 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. Most of
the current balance will be collected from, or returned to
customers, in fiscal year 2005. At September 30, 2004 and
2003, refunds received from pipelines and to be returned to the
regulated utilitys customers were not material.
42
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 Companys
policy is to maintain back-up bank credit facilities in an
amount equal to or greater than its expected maximum commercial
paper position. Effective April 28, 2004, Washington Gas
and WGL Holdings entered into new credit agreements with a group
of banks in the amount of $175 million each for Washington
Gas and WGL Holdings. The credit facility for Washington Gas
expires on April 28, 2009, and permits the regulated
utility to request until April 28, 2005, and the banks to
approve, an additional line of credit of $100 million above
the original credit limit, for a maximum potential total of
$275 million. The WGL Holdings credit facility
expires on April 27, 2007, and permits the Company to
request until April 28, 2005, and the banks to approve, an
additional line of credit of $50 million above the original
credit limit, for a maximum potential total of
$225 million. As of September 30, 2004, there was no
amount outstanding under either the Washington Gas or WGL
Holdings credit facility.
At September 30, 2004, the Company had
outstanding notes payable through the issuance of commercial
paper of $95.6 million as compared to $166.7 million
outstanding at September 30, 2003. The decrease in notes
payable was primarily attributable to improved operating cash
flows generated by the Companys regulated utility during
the fiscal year ended September 30, 2004, which reduced the
Companys need for short-term borrowings to fund its
working capital requirements.
Long-Term
Cash Requirements and Related Financing
The Companys long-term cash requirements
primarily depend upon the level of capital expenditures,
long-term debt maturity requirements and decisions to refinance
long-term debt. The Company devotes the majority of its capital
expenditures to adding new regulated utility customers in its
existing service area. At September 30, 2004, Washington
Gas was authorized to issue up to $213.0 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.
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.
The effective cost of the new debt, after considering a gain
associated with a derivative instrument entered into in
connection with this debt, was 4.11 percent (refer to
Market Risk Interest-Rate Risk
included
herein).
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 the
Companys cost of short-term and long-term debt and its
access to the credit markets.
On June 4, 2004, Moodys Investors
Service (Moodys) lowered the commercial paper rating of
WGL Holdings from Prime-2 to Prime-3. On June 29, 2004,
Moodys lowered the commercial paper rating of WGL Holdings
from Prime-3 to Not-Prime. Additionally on June 29, 2004,
Moodys affirmed the Prime-1 commercial paper rating and A2
long-term debt rating and stable outlook of Washington Gas. On
July 1, 2004, Fitch Ratings affirmed its credit ratings of
43
WGL Holdings and Washington Gas, stating that the
rating outlook for both companies is stable. On July 2,
2004, Standard & Poors Ratings Services
(Standard & Poors) lowered its commercial paper
ratings of WGL Holdings and Washington Gas from A-1+ to A-1.
Standard & Poors affirmed its corporate credit ratings
of WGL Holdings and Washington Gas at AA-, but revised its
outlook on the long-term ratings from stable to negative.
To date, these ratings actions have had a minimal
impact on the Company. Although interest rates being charged to
WGL Holdings for commercial paper rose since the ratings
actions, there continues to be adequate demand for the
Companys commercial paper.
Ratings Triggers and Certain Debt Covenants
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 on their
revolving credit agreements.
WGL Holdings and Washington Gas pay facility fees
on their revolving credit agreements based on the long-term debt
ratings of Washington Gas. There are five different levels of
fees. WGL Holdings fees are always at the next highest fee
level than the level at which Washington Gas pays its fees. If
Washington Gas is at level one, the lowest fee level and a level
that implies a credit rating for Washington Gas of at least Aa3
from Moodys and AA- from Standard & Poors,
Washington Gas pays eight basis points and WGL Holdings pays nine basis
points. If Washington Gas is at level four, Washington Gas pays
12.5 basis points and WGL Holdings pays 15 basis points.
Under the revolving credit
agreements, the ratio of consolidated indebtedness to
consolidated total capitalization can not exceed 0.65 to 1.0
(65.0 percent), and, for WGL Holdings, the ratio of
earnings before interest and taxes to interest expense can not
fall below 2.25 to 1.0 (2.25 times). Under the terms of the
revolving credit agreements, 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.
Regarding certain of the regulated utilitys
gas purchase and pipeline capacity agreements, if the long-term
debt of Washington Gas is downgraded below BBB by Standard &
Poors or below Baa2 by Moodys, 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.
Contractual Obligations, Off-Balance Sheet Arrangements
and Other Commercial Commitments
Contractual Obligations.
WGL Holdings has certain
contractual obligations that extend beyond fiscal year 2004.
These commitments include long-term debt, lease obligations and
unconditional purchase obligations for
44
pipeline capacity, transportation and storage
services, and certain natural gas and electricity commodity
commitments. The estimated obligations as of September 30,
2004 for future fiscal years are shown below.
The table above reflects fixed and variable
obligations estimated on the basis of normal weather and average
customer usage. These estimates reflect likely purchases
under various contracts, and may differ from minimum future
contractual commitments disclosed in Note 14 of the Notes
to Consolidated Financial Statements.
When a customer selects a third-party marketer to
provide natural gas supply, Washington Gas generally assigns
pipeline and storage capacity to third-party marketers to
deliver natural gas to Washington Gas city gate. In order to
provide the gas commodity to customers who do not select a
third-party marketer, Washington Gas has a commodity acquisition
plan to acquire the natural gas supply to serve the customer. In
connection with this plan, Washington Gas utilizes an Asset
Manager to acquire the necessary supply to serve these
customers. Washington Gas commitment to the Asset Manager
is to purchase gas supply through April 30, 2005 at a
market price that is tied to various public indices for natural
gas. The contract commitment is related to customer demand,
there are no minimum bill commitments, and no amount is included
in the table above for these contracts.
For commitments related to the Companys
pension and post-retirement benefit plans, during fiscal year
2005, the Company does not expect to make any contributions to
its qualified, trusteed, non-contributory defined benefit
pension plan covering all active and vested former employees of
Washington Gas. The Company expects to make payments totaling
$1.3 million in fiscal year 2005 on behalf of participants in its non-funded
Supplemental Executive Retirement Plan.
The Company expects to contribute $34.0 million to its
health and life insurance benefit plans during fiscal year 2005.
For a further discussion of the Companys pension and
post-retirement benefit plans, refer to Note 11 of the
Notes to Consolidated Financial Statements.
Sales and Repurchases of Accounts
Receivable.
In fiscal year 2002,
the Company stopped making new loans associated with its
consumer financing operations. This operation was limited to
servicing existing loans.
45
Accordingly, the cash generated from the consumer
financing operation was limited to collection of principal and
interest for existing loans that reduced the balances in loan
pools that previously were created for sale to commercial banks.
Pursuant to the terms under which these loan pools were sold,
the Company repurchased certain of these loans from the
commercial banks totaling $3.2 million, $3.2 million
and $11.3 million for fiscal years 2004, 2003 and 2002,
respectively (refer to Note 14 of the Notes to Consolidated
Financial Statements).
Financial Guarantees.
WGL Holdings has guaranteed
payments for certain purchases of natural gas and electricity on
behalf of the retail energy-marketing segment. At
September 30, 2004, these guarantees totaled
$218.9 million. Termination of these guarantees is
coincident with the satisfaction of all obligations of
WGEServices covered by the guarantees. WGL Holdings also had
guarantees totaling $6.0 million at September 30, 2004
that were made on behalf of certain of its non-utility
subsidiaries associated with their banking transactions. For all
of its financial guarantees, WGL Holdings may cancel any or all
future obligations imposed by the guarantees upon written notice
to the counterparty, but WGL Holdings would continue to be
responsible for the obligations that had been created under the
guarantees prior to the effective date of the cancellation.
Construction Project Financing.
In October 2000, Washington Gas
contracted with the U.S. General Services Administration
(GSA) to construct certain facilities at the GSA central
plant in Washington, D.C. Payments to Washington Gas for this
construction were to be made by the GSA over a 15-year period.
In November 2000, Washington Gas and General Electric Capital
Assurance Company (GEFA) entered into a long-term financing
arrangement, whereby GEFA funded this construction project. As
part of this financing arrangement, Washington Gas assigned to
GEFA the 15-year stream of payments due from the GSA. The amount
of this long-term financing arrangement, including change
orders, origination fees and capitalized finance charges was
$69.4 million. As the long-term financing from GEFA was
funded, Washington Gas established a note receivable
representing the GSAs obligation to remit principal and
interest. Upon completion and acceptance of phases of the
construction project, Washington Gas accounts for the transfer
of the financed asset as an extinguishment of long-term debt and
removes both the note receivable and long-term financing from
its financial statements. As of September 30, 2004,
construction of these facilities was substantially complete.
Work on the construction project that has not been completed or
accepted by the GSA was valued at $15.6 million, which
represents an obligation on Washington Gas Balance Sheet
at September 30, 2004. At any time before the contract with
the GSA is fully accepted, should there be a contract default,
such as, among other things, non-payment by the GSA, GEFA may
call on Washington Gas to fund the entire unpaid principal in
exchange for which Washington Gas would receive the right to the
stream of repayments from the GSA. Once final acceptance by the
GSA is made, GEFA will have no recourse against the Company
related to this long-term debt. As of September 30, 2004,
the GSA had made all required payments under this long-term
financing arrangement, and the remaining unpaid principal
balance was $63.8 million.
Cash Flows Provided By Operating Activities
The primary drivers for the Companys
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 could
change rapidly.
During the first six months of the Companys
fiscal year, the Company generates a large portion of its annual
net income 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
six-month period ended March 31 may be significant because
of the variability of weather from one period in a year to the
same period in a 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 and pipeline capacity. 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. Since payments for natural gas and pipeline
capacity need to be made to suppliers before accounts receivable
are collected from customers, the Company increases its
short-term debt financing between September 30 and
March 31. 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, as well as deferred purchased gas costs, which
represent the
46
difference between gas costs that have been paid
to suppliers in the past and what has been collected from
customers for these gas costs, can also cause significant
variations in cash flows from period to period.
During the last six months of the Companys
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
Companys assets, which were increased during the 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
$242.6 million, $143.8 million, and
$205.3 million for fiscal years 2004, 2003 and 2002,
respectively. A description of certain material changes in cash
flow from operating activities from September 30, 2003 to
September 30, 2004 is listed below:
During fiscal year 2003, storage gas inventory
rose $65.5 million from September 30, 2002, primarily
due to a dramatic rise in the price of natural gas. During
fiscal year 2002, cash flows provided by operating activities
were impacted by a $56.1 million decrease in gas costs due
from/to customers net due to gas costs that were paid to
suppliers but unrecovered from customers in fiscal
year 2001, that subsequently were recovered from customers
during fiscal year 2002. Additionally, fiscal
year 2002 reflects a reduction of $36.7 million in
storage gas inventory.
Cash Flows Used in Financing Activities
Cash flows used in financing activities totaled
$132.6 million, $26.3 million and $17.3 million
for fiscal years 2004, 2003 and 2002, respectively. During
fiscal year 2004, a decrease in notes payable of
$71.0 million was a primary use of cash. This decrease was
primarily attributable to improved operating cash flows
generated by the Companys regulated utility during fiscal
year 2004, which reduced the Companys need for short-term
borrowings to fund its working capital requirements. The
decrease in notes payable was coupled with a common stock
dividend payment of $62.7 million. Additionally during
fiscal year 2004, the Company refinanced $36.0 million of
long-term debt with the proceeds of a $37.0 million
lower-cost, long-term debt issue (refer to
Liquidity and
Capital Resources Long-Term Cash Requirements and Related
Financing
included herein).
Cash flows used in financing activities during
fiscal year 2003 reflect a $75.8 million increase in notes
payable primarily to fund the Companys increased working
capital requirements. Additionally, the Company retired
$41.9 million of long-term debt and paid a common stock
dividend of $61.9 million. In fiscal year 2002, the
Company issued $130.4 million of long-term debt, retired
$42.9 million of long-term debt and paid common stock
dividends totaling $61.4 million. Notes payable decreased
$43.2 million during fiscal year 2002, primarily due
to a decrease in the Companys working capital requirements.
47
The following table reflects the issuances and
retirements of long-term debt that occurred during fiscal
years 2004, 2003 and 2002 (also refer to Note 5 of the
Notes to Consolidated Financial Statements).
Cash Flows Used In Investing Activities
Net cash flows used in investing activities
totaled $107.8 million, $115.6 million and
$197.6 million during fiscal years 2004, 2003 and 2002,
respectively. In fiscal year 2004, $112.8 million was
utilized for capital expenditures made on behalf of the
regulated utility. Additionally, cash proceeds of
$6.4 million (pre-tax) were derived from the Maritime sale.
In fiscal years 2003 and 2002, $128.5 million and
$161.2 million, respectively, were utilized for capital
expenditures made on behalf of the regulated utility. Additionally,
fiscal year 2003 included cash proceeds of $16.0 million
related to the sale of the Companys former headquarters
property and $5.3 million from the sale of an interest in a
land development venture. Other investing activities for fiscal
year 2002 included the investment in certain construction
projects on behalf of the Companys commercial HVAC
business.
Capital Expenditures
The following table depicts the Companys
actual capital expenditures for fiscal years 2002, 2003 and
2004, and projected capital expenditures for fiscal years 2005
through 2009. The Companys capital expenditure program
includes investments to extend service to new areas, and to
ensure safe, reliable and improved service. The decrease in
capital expenditures in fiscal year 2004 from 2003 was
primarily attributable to the fact that fiscal year 2003
included a greater number of expenditures related to information
technology improvements that were necessary to improve
operational efficiencies than were incurred in fiscal
year 2004. The 2005 to 2009 projected period includes
$328.5 million for continued growth to serve new customers
and $177.8 million primarily for replacement and betterment
of existing capacity. The projected period also reflects
$164.4 million of other expenditures, which includes
general plant, as well as the anticipated construction of a
liquefied natural gas peaking facility, estimated to cost
approximately $60 million, that will enhance the
operational capacity of the entire natural gas distribution
system. The Company believes that the combination of available
internal and external sources of funds will be adequate to fund
these capital expenditures.
48
CREDIT RISK
Regulated Utility Operations
Certain suppliers that sell gas to Washington Gas
have either relatively low credit ratings or are not rated by
major credit rating agencies. In the event of a suppliers
failure to deliver contracted volumes of gas, the regulated
utility may need to replace those volumes at prevailing market
prices, which may be higher than the original transaction
prices, and pass these costs through to its sales customers
under the purchased gas cost adjustment mechanisms (refer to
Market Risk Price Risk Related to Regulated
Utility Operations
included herein). To manage this
supplier credit risk, Washington Gas screens suppliers
creditworthiness and asks suppliers as necessary for financial
assurances, including letters of credit, parental guarantees,
and surety bonds to mitigate adverse price exposures that could
occur if a supplier defaults.
Retail Energy-Marketing Operations
Natural Gas.
Similar to the regulated utility,
certain suppliers that sell gas to WGEServices have either
relatively low credit ratings or are not rated by major credit
rating agencies. Depending on the future ability of these
suppliers to deliver natural gas under existing contracts,
WGEServices could be financially exposed for the difference
between the price at which WGEServices has contracted to buy
natural gas, and the cost of any replacement natural gas that
may need to be purchased. WGEServices has a wholesale supplier
credit policy that is designed to mitigate wholesale credit
risks through a requirement for credit enhancements. Per the
terms of this policy, WGEServices has obtained credit
enhancements from certain of its gas suppliers.
Electricity.
For a discussion of the credit
risk associated with WGEServices electricity suppliers,
refer to
Market Risk Price Risk Related to Retail
Energy-Marketing Operations
included herein.
MARKET RISK
The Company is exposed to various forms of market
risk including commodity price risk, weather risk and
interest-rate risk. The following discussion describes these
risks and the Companys management of them.
Price Risk Related to Regulated Utility Operations
Washington Gas actively manages its gas supply
portfolio to balance its sales and delivery obligations. The
regulated utility includes the cost of the natural gas commodity
and pipeline services in the purchased gas costs that it
includes in firm customers rates, subject to regulatory
review. The regulated utilitys jurisdictional tariffs
contain gas cost mechanisms that allow it to recover the invoice
cost of gas applicable to firm customers.
In order to mitigate commodity price risk for its
firm customers, Washington Gas has specific regulatory approval
in the District of Columbia, Maryland and Virginia to hedge
transactions with option contracts for a limited portion of its
natural gas purchases. Three types of hedge instruments were
approved for the Companys use:
(i)
forward gas
purchases at a fixed price;
(ii)
purchases of call
options that effectively cap the cost of gas and
(iii)
a combination of call options purchased and
put options sold that limits gas price exposure within a narrow
band. Additionally, the Company purchases gas under contracts
that provide for volumetric variability. Certain of these
contracts are required to be recorded at fair value (refer to
Note 6 of the Notes to Consolidated Financial Statements
for a discussion of the accounting for these derivative
instruments). At September 30, 2004 and 2003, the Company
recorded a payable on its balance sheet reflecting a fair value
loss of $8.2 million and $3.3 million, respectively,
related to its variable gas purchase contracts, with a
corresponding amount recorded as a regulatory asset in
accordance with regulatory accounting requirements for a
recoverable cost in each jurisdiction.
The regulated utility also mitigates price risk
by injecting natural gas into storage during the summer months
when prices are generally lower and less volatile, and withdraws
that gas during the winter heating season when prices are
generally higher and more volatile.
49
Price Risk Related to Retail Energy-Marketing
Operations
The Companys retail energy-marketing
subsidiary, WGEServices, sells natural gas and electricity to
retail customers at both fixed prices and indexed prices. The
Company must manage daily and seasonal demand fluctuations for
these products. The volume and price risks are evaluated and
measured separately for natural gas and electricity.
Natural Gas.
WGEServices is exposed to market
risk to the extent it does not closely match the timing and
volume of natural gas it purchases with the related fixed price
or indexed purchase commitments. WGEServices risk
management policies and procedures are designed to minimize
these risks. WGEServices also faces risk in that approximately
60 percent of its annual natural gas sales volumes are
subject to variations in customer demand caused by fluctuations
in weather. Purchases of natural gas to fulfill retail sales
commitments are made generally under fixed-volume contracts that
are based on normal weather assumptions. If there is a
significant deviation from normal weather that causes purchase
commitments to differ significantly from sales levels,
WGEServices may be required to buy incremental natural gas or
sell excess natural gas at prices that negatively impact gross
margins. WGEServices also manages this volumetric risk by using
storage gas inventory and peaking services offered to marketers
by the regulated utilities that provide delivery service for
WGEServices customers. WGEServices also manages price risk
through the use of derivative instruments.
At September 30, 2004 and 2003, all of
WGEServices derivatives were valued at $719,000 and
$188,000, respectively. For these derivatives, WGEServices
recorded net gains of $892,000 and $221,000 for the fiscal years
ended September 30, 2004 and 2003, respectively, and
recorded a net loss of $323,000 for the fiscal year ended
September 30, 2002.
Electricity.
For its electric business,
WGEServices has significantly limited its volumetric and price
risks by purchasing full requirements supply from wholesale
electricity suppliers under master purchase and sale agreements.
WGEServices principal supplier of electricity is Mirant
Americas Energy Marketing L.P. (MAEM), an indirect wholly
owned subsidiary of Mirant Corporation (Mirant). WGEServices
purchases full requirements services from MAEM, including
electric energy, capacity and certain ancillary services, for
resale to retail electric customers. MAEM assumes the risk for
any volume and price risks associated with sales made by
WGEServices.
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 was included in these bankruptcy filings. Future
performance by MAEM may be subject to further developments in
the bankruptcy proceedings. The performance risk associated with
the pre-bankruptcy petition MAEM contracts is mitigated through
a Security and Escrow agreement entered into between WGEServices
and MAEM prior to the bankruptcy filing. Under the Security and
Escrow agreement, WGEServices has access to collateral that is
intended to cover the difference between the current market
price of electricity and the price at which WGEServices has
contracted to buy electricity. In the opinion of counsel to the
Company, WGEServices has the contractual right to draw on the
escrow funds in the account (which totaled $3.0 million and
$30.0 million as of September 30, 2004 and 2003,
respectively) if the pre-bankruptcy petition contracts between
WGEServices and MAEM are terminated. The amount of
WGEServices exposure in the event of termination of these
contracts between WGEServices and MAEM is estimated to be less
than the amount of collateral included in the escrow account.
This estimate of WGEServices exposure to contract
termination is based upon acquiring supply, priced at forward
electricity prices through the expiration of the existing sales
contracts or until WGEServices exercises certain damage
limitation provisions of its customers sales contracts.
The actual exposure for WGEServices may differ from the estimate
due to changes in timing of any contract termination, deviations
from normal weather, changes in future market conditions, or
other factors.
Since the bankruptcy filing, MAEM has continued
to honor its supply obligations to WGEServices. All obligations
to WGEServices under the pre-bankruptcy petition MAEM contracts
expire by the end of October 2005, with the majority of
these obligations expiring by December 2004. In
October 2003, WGEServices and MAEM signed a post-bankruptcy
petition contract that enables WGEServices to renew expiring
contracts with its current electric customers and to make
purchases for new customers. These post-bankruptcy petition
contracts include provisions that allow WGEServices to net
payables to MAEM against any damages that might result from
default on the part of MAEM, and allow WGEServices to request
collateral under certain situations.
50
WGEServices has made efforts to reduce its
reliance on a single supplier. During fiscal year 2004,
WGEServices entered into separate master purchase and sale
agreements under which it purchases full requirements services
from three new wholesale electricity suppliers. These new
electric supplier contracts either have investment grade credit
ratings or provide guarantees from companies with investment
grade credit ratings. Electric suppliers other than MAEM
accounted for less than ten percent of WGEServices
electric purchases for fiscal year 2004.
Value-At-Risk.
WGEServices also measures the
market risk of its energy commodity portfolio and employs risk
control mechanisms to measure and determine mitigating steps
related to market risk including the determination and review of
value-at-risk. Value-at-risk is an estimate of the maximum loss
that can be expected at some level of probability if a portfolio
is held for a given time period. For the natural gas portfolio,
based on a 95 percent confidence interval,
WGEServices value-at-risk at September 30, 2004 was
approximately $135,000 for a one-day holding period. WGEServices
also calculates the value of its open position related to
natural gas, which measures the amount of additional
transactions that would be required to close the volumetric
differential between its purchase and sales commitments. As of
September 30, 2004, WGEServices would have had to increase
its forward purchase commitments by approximately
$4.2 million to close its open position.
Weather Risk
The Company is exposed to various forms of
weather risk in both of its regulated utility and unregulated
businesses. For the regulated utility, a large portion of the
Companys revenues is volume driven and its current rates
are based upon an assumption of normal weather. Variations from
normal weather will cause the Companys earnings to
increase or decrease, depending on the weather pattern. The
financial results of the Companys non-regulated
energy-marketing business, WGEServices, are also affected by
variations from normal weather in the winter relating to its gas
sales, and in the summer relating to its electricity sales. The
Company manages weather risk with a weather insurance policy for
the regulated utility and a weather hedge for WGEServices, as
discussed below.
Weather Insurance.
In October 2000, Washington
Gas purchased a weather insurance policy in order to minimize
the impact of warmer-than-normal weather on the Companys
financial results. The policy has a five-year term that ends
September 30, 2005. During fiscal year 2005, the Company
will evaluate the possibility of obtaining weather insurance when the
current policy expires.
The policy covers a portion of Washington
Gas estimated net revenue exposure to variations in
heating degree days (HDDs). The insurance policy defines a
heating degree day as the greater of (
i
) 65 degrees
Fahrenheit less the average of the daily high and daily low
temperatures in degrees Fahrenheit as measured at Washington
Reagan National Airport, or (
ii
) zero. For insurance
policy purposes, neither average temperatures nor HDDs are
rounded.
Income is provided in the amount of $32,000 for
each such HDD below 3,815 per fiscal year up to a maximum of
515 HDDs, subject to certain limitations. Over the
five-year term of the policy, Washington Gas cannot be paid for
more than 1,295 HDDs. For fiscal year 2005, the fifth and
last year of the policy, the full coverage of 515 HDDs is
available. Additionally, the policy provides for a one-time
payment to Washington Gas at the end of the policy term if, over
its five-year term, HDDs average less than 4,000 per year. The
maximum remaining one-time payment Washington Gas may receive is
an additional $928,000 (pre-tax). Other than the cost of the
insurance, Washington Gas pays nothing if weather is colder than
normal. No payments were received in connection with fiscal
years 2004 or 2003 due to the colder-than-normal weather. During
fiscal year 2002, weather was 13.4 percent warmer than
normal, resulting in 462 HDDs that were covered by the
policy. As a result, Washington Gas recorded pre-tax income in
fiscal year 2002 due to its receipt of a pre-tax payment of
$14.8 million ($8.7 million after income taxes) in October 2002, which offset about
30 percent of the estimated financial effect of the
years warmer-than-normal weather. The policys
pre-tax annual cost was $4.25 million for fiscal
years 2004, 2003 and 2002, and will continue at this level
for fiscal year 2005. No portion of the cost or benefit of
this policy is considered in the regulatory process. A further
description of the accounting for weather insurance may be found
in Note 1 of the Notes to Consolidated Financial Statements.
When Washington Gas reports HDDs, it computes
HDDs using a method different from that used for insurance
policy purposes. Washington Gas method rounds the average
of the high and low temperatures to the nearest whole degree
prior to subtracting that average from 65 degrees. As a
result, for each fiscal year in the five-year policy period, the
number of HDDs computed for insurance purposes will almost
certainly be greater than the number of HDDs reported by
Washington Gas. Therefore, the insurance policy computation will
indicate colder weather than
51
Washington Gas computation, and the annual
benefit received will be lower than might be expected if
Washington Gas measure of HDDs were used. For example,
the fiscal year 2004 HDD total for insurance purposes was
4,083, but was 4,024 under Washington Gas method.
HDD Hedge.
WGEServices utilizes HDD hedges to
manage its risk for natural gas customers who participate in a
program that allows them to pay a fixed amount for their gas
requirements regardless of the amount of gas consumed. These
hedges cover a portion of WGEServices estimated net
revenue exposure to variations in HDDs. For fiscal year 2004,
the Company recorded, net of premium costs, a net loss of $114,000 related to these
hedges, and a net gain of $372,000 for fiscal year 2003. No
such gain or loss was recorded in fiscal year 2002.
Interest-Rate Risk
The Company and Washington Gas are exposed to
interest-rate risk associated with its debt financing costs.
Management of this risk is discussed below.
Long-Term Debt.
At September 30, 2004, the
regulated utility had fixed-rate MTNs and other long-term debt
aggregating $590.2 million in principal amount, excluding
current maturities and unamortized discounts, and having a fair value of
$646.6 million. Fair value is defined as the present value
of the debt securities future cash flows discounted at
interest rates that reflect market conditions as of
September 30, 2004. While these are fixed-rate instruments
and, therefore, do not expose the Company to the risk of
earnings loss due to changes in market interest rates, they are
subject to changes in fair value as market interest rates
change. A total of $183.5 million, or approximately
32.0 percent, of the regulated utilitys outstanding
MTNs, excluding current maturities, have put or call options, or
a combination of both, allowing either Washington Gas or the
holder of the debt to mitigate this market risk through the
early redemption of those debt instruments.
Using sensitivity analyses to measure this market
risk exposure, the regulated utility estimates that the fair
value of its long-term debt would increase by approximately
$18.1 million if interest rates were to decline by ten
percent. The Company also estimates that the fair value of its
long-term debt would decrease by approximately
$17.0 million if interest rates were to increase by ten
percent. In general, such an increase or decrease in fair value
would impact earnings and cash flows only if the Company were to
reacquire all or a portion of these instruments in the open
market prior to their maturity.
Derivative Instruments.
Washington Gas utilizes derivative
financial instruments from time to time in order to minimize its
exposure to interest-rate risk. In June 2003, Washington
Gas entered into two forward-starting swaps with an aggregate
notional principal amount of $62.0 million to mitigate a
substantial portion of interest-rate risk associated with
anticipated future debt transactions. These swaps were
designated as cash flow hedges and were carried at fair value.
In November 2003, Washington Gas terminated
$37.0 million of the total $62.0 million aggregate
notional principal amount of the forward-starting swaps
concurrent with the November issuance of $37.0 million of
MTNs as discussed previously in
Liquidity and Capital
Resources
included herein. Washington Gas received
$2.6 million associated with the settlement of this hedge
agreement. In December 2003, Washington Gas terminated the
remaining $25.0 million aggregate notional principal of the
forward-starting swaps, and received $1.2 million
associated with the settlement of this hedge agreement.
In September 2004, Washington Gas entered
into two forward-starting swaps with an aggregate notional
principal amount of $60.5 million. These swaps are intended
to mitigate a substantial portion of interest-rate risk
associated with anticipated future debt transactions, and are
scheduled to terminate in fiscal year 2005 concurrent with
the execution of debt transactions planned for that year. These
swaps were designated as cash flow hedges in accordance with
SFAS No. 133, as amended, and are carried at fair value. At
September 30, 2004, these swaps had a fair value loss
totaling $475,000.
Refer to Note 6 of the Notes to Consolidated
Financial Statements for a further discussion of the accounting
for these transactions.
52
Washington Gas Light Company
WASHINGTON GAS LIGHT COMPANY
This section of Managements Discussion
focuses on the financial position and results of operations of
Washington Gas for the reported periods. In many cases,
explanations for the changes in financial position and results
of operations for both WGL Holdings and Washington Gas are
substantially the same.
RESULTS OF OPERATIONS
Summary Results
Washington Gas net income applicable to its
common stock was $95.3 million, $109.6 million and
$47.4 million for the fiscal years ended September 30,
2004, 2003 and 2002, respectively.
The following table provides the key factors
contributing to the changes in utility net revenues between
years.
Utility Net Revenues
Net revenues for Washington Gas were
$549.0 million for fiscal year 2004 compared to
$564.0 million for fiscal year 2003. Net revenues were
affected primarily by weather, which was 11.6 percent
warmer in fiscal year 2004 than in fiscal year 2003.
Favorably contributing to net revenues for fiscal year 2004 was
the addition of 30,140 active customer meters, or
3.1 percent, which increased net revenues by
$12.7 million in the current fiscal year. Net revenues for
fiscal year 2004 also benefited by $5.7 million from
the impact of rate changes that were implemented in Maryland on
November 6, 2003, the District of Columbia on
November 24, 2003, and the effect of approximately one and
one-half months of the rate decision that became effective in
Virginia in November 2002.
Included as part of the November 24, 2003
rate increase in the District of Columbia was a reduction in
rates for the effect of post-employment benefit costs that had
been previously deferred on the balance sheet as a regulatory
liability. During fiscal year 2004, Washington Gas refunded
over-collections of these costs to its District of Columbia
customers, thereby resulting in a lowering of base rates by the
PSC of DC for the effect of these over-collections. The effect
of this reduction in annual revenues results in an accounting
adjustment that reduces both the regulatory liability on the
balance sheet and operation and maintenance expenses on the
statement of income. Accordingly, the regulatory deferral
mechanism (or tracker) results in no affect on net
income as the lower rates reflected in revenues are offset by
lower operation and maintenance expenses. For fiscal year 2004,
Washington Gas net income reflects a $4.7 million
reduction in both its net revenues and operation and maintenance
expenses related to this tracker in accordance with the Final
Order by the PSC of DC. For purposes of the table presented
above, the $4.7 million has been included in Impact
of rate cases and deducted from Other for
fiscal year 2004.
53
Utility net revenues of $564.0 million for
fiscal year 2003 represented an increase of $125.6 million,
or 28.6 percent, over fiscal year 2002. This increase
was attributable primarily to 37.7 percent colder weather
in fiscal year 2003 than in fiscal year 2002, along with
customer growth. Higher retail rates in Maryland and Virginia,
as well as new rates and a new rate design in the District of
Columbia, contributed an additional $21.3 million to the
increase in net revenues for fiscal year 2003.
Revenue taxes comprised principally of gross
receipts taxes, increased by $9.6 million and
$12.9 million in fiscal years 2004 and 2003,
respectively. Changes in revenue taxes primarily are impacted by
changes in the volume of gas sold and delivered. Although
volumes decreased in fiscal year 2004, tax rates charged in
Maryland and the District of Columbia increased significantly in
fiscal year 2004. The increase in these taxes for fiscal
year 2003 compared to fiscal year 2002 was driven
primarily by increased volumes. The regulated utility is allowed
recovery of these amounts from its customers and therefore these
fees do not affect total net revenues.
Gas Service to Firm
Customers.
The level of gas
delivered to firm customers is highly sensitive to weather
variability as a large portion of the natural gas delivered by
Washington Gas is used for space heating. The regulated
utilitys rates are based on normal weather, and none of
the tariffs for the jurisdictions in which it operates has a
weather normalization provision. Nonetheless, declining block
rates in the regulated utilitys Maryland and Virginia
jurisdictions, and the existence of a fixed demand charge in all
jurisdictions to collect a portion of revenues, reduce the
effect that variations from normal weather have on net revenues.
During the fiscal year ended September 30,
2004, firm therm deliveries decreased 5.4 percent from
fiscal year 2003 to 1.311 billion therms. This decrease
primarily reflects 11.6 percent warmer weather during
fiscal year 2004 when compared to fiscal year 2003, partially
offset by a 3.1 percent increase in active customer meters
being served. Weather for fiscal year 2004 was 6.1 percent
colder than normal, as compared to 19.8 percent colder than
normal for the prior fiscal year. In fiscal year 2003, firm
therm deliveries increased 31.9 percent over fiscal year
2002 due to 37.7 percent colder weather in fiscal year 2003
than in fiscal year 2002, coupled with an increase in active
customer meters.
Many customers choose to buy the natural gas
commodity from third-party marketers, rather than purchase the
natural gas commodity and delivery service from Washington Gas
on a bundled basis. Gas delivered to firm
54
customers but purchased from third-party
marketers represented 34.7 percent of total firm therms
delivered during fiscal year 2004, compared to 35.9 percent
and 33.0 percent delivered during fiscal years 2003 and
2002, respectively. On a per unit basis, Washington Gas earns
the same net revenues from delivering gas for others as it earns
from bundled gas sales in which customers purchase both the
natural gas commodity and the associated delivery service from
Washington Gas. Therefore, the regulated utility does not
experience any loss in net revenues when customers choose to
purchase the natural gas commodity from a third-party marketer.
Gas Service to Interruptible Customers.
Washington Gas must curtail or
interrupt service to this class of customer when the demand by
firm customers exceeds specified levels. Therm deliveries to
interruptible customers
increased 2.3 percent
in fiscal year 2004 over fiscal year 2003. This is
attributable to an increase of 10.7 million therms in
interruptible deliveries for others, reflecting a reduction in
the curtailment of interruptible service due to warmer weather
in fiscal year 2004 compared to fiscal year 2003. This
increase was partially offset by a reduction in interruptible
gas sold and delivered of 4.5 million therms. Deliveries to
interruptible customers during fiscal year 2003 decreased by
18.1 million therms, or 6.3 percent, from fiscal
year 2002 primarily due to customers use of
alternative fuels or conversion to firm deliveries as a result
of higher natural gas prices.
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. Under these arrangements, except as
noted below as it relates to Virginia operations, Washington Gas
shares a majority of the margins earned on interruptible gas
sales and deliveries to 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 class in rate design. In the Virginia
jurisdiction, Washington Gas shares only margins on
interruptible gas sales to firm customers; interruptible
delivery service rates are based on the cost of service, and
Washington Gas retains all revenues from interruptible delivery
service.
Gas Service for Electric Generation.
Washington Gas sells and/or
delivers natural gas for use at two electric generation
facilities in Maryland that are each owned by companies
independent of WGL Holdings. During fiscal year 2004, deliveries
to these customers decreased 39.0 percent to
41.1 million therms, reflecting the use by these customers
of alternative fuels primarily due to higher natural gas prices.
During fiscal year 2003, these deliveries decreased
60.3 percent to 67.2 million therms compared to fiscal
year 2002. Washington Gas shares a significant majority of the
margins earned from gas deliveries to these customers with firm
customers. Therefore, changes in the volume of interruptible gas
deliveries to these customers do not materially affect either
net revenues or net income
.
Cost
of Gas
The regulated utilitys cost of natural gas
includes both fixed and variable components. The regulated
utility pays fixed costs or demand charges to
pipeline companies for system capacity needed to transport and
store natural gas. The regulated utility pays variable costs, or
the cost of the natural gas commodity itself, to natural gas
producers. Variations in the utilitys cost of gas expense
result from changes in gas sales volumes, the price of the gas
purchased and the level of gas costs collected through the
operation of firm gas cost recovery mechanisms. Under these
regulated recovery mechanisms, the regulated utility records
cost of gas expense equal to the cost of gas recovered from
customers and included in revenues. The difference between the
firm gas costs paid and the gas costs recovered from customers
is deferred on the balance sheet as an amount to be collected
from or refunded to customers in future periods. Therefore,
increases or decreases in the cost of gas associated with sales
made to firm customers have no direct effect on net revenues and
net income. Revenues can vary widely on an annual basis because
of changes in the cost of gas, but such variations will not have
any impact on net revenues or net income. Changes in the cost of
gas can cause significant variations in the utilitys cash
provided by or used in operating activities. The regulated
utility 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.
The commodity costs of gas invoiced to the
utility (excluding the cost and related volumes applicable to
sales made outside of the utilitys service territory,
referred to as off-system sales) were 61.17¢, 55.75¢
and 34.27¢ per therm for fiscal years 2004, 2003 and 2002,
respectively. The higher gas costs in fiscal year 2004 and 2003
reflect higher commodity gas prices associated with greater
demand due to colder-than-normal weather during these years and
the increased price volatility in the wholesale market, as
discussed above.
55
Utility
Operating Expenses
Operation and Maintenance Expenses.
Operation and maintenance expenses
increased $10.8 million, or 5.0 percent, from fiscal
year 2003 to fiscal year 2004, and increased
$10.8 million, or 5.2 percent, from fiscal
year 2002 to fiscal year 2003.
The following table summarizes the major factors
that contributed to the changes in operation and maintenance
expenses.
Expenses related to labor and incentive plans
decreased by $900,000 in fiscal year 2004 primarily due to eight
percent fewer employees. The $2.4 million increase in
employee severance costs during the current fiscal year reflects
operational efficiencies at the utility. Labor-related expenses
increased $8.8 million in fiscal year 2003 primarily due to
base pay increases and increased incentive pay accruals related
to performance-based incentive awards, partially offset by fewer
employees.
The $3.0 million increase in employee
benefits expenses for fiscal year 2004 was largely due to an
increase in the cost of group insurance. The increase in these
costs for fiscal year 2003 primarily was due to weaker financial
performance related to the Companys pension plan, and
decreasing interest rates which caused an increase in the
discounted liabilities associated with plan benefits.
During fiscal year 2004, the Company recorded
lower costs associated with post-retirement benefits other than
pensions of $2.7 million associated with the Medicare
subsidy. This subsidy resulted from a law enacted in December
2003 that entitles the Company to a federal subsidy for
sponsoring a retiree health care benefit plan with a
prescription drug benefit that is at least actuarially
equivalent to the benefit to be provided under Medicare.
The $1.6 million decrease in the provision
for uncollectible accounts for fiscal year 2004 was primarily
driven by improved collection efforts by the regulated utility,
as well as warmer weather compared to fiscal year 2003. The
$2.0 million increase in fiscal year 2003 was driven by
higher natural gas costs and significantly colder weather in
fiscal year 2003 than the prior fiscal year.
Other non-labor operating expenses for fiscal
year 2004 increased $10.6 million over fiscal year 2003.
This increase included an accrual of $2.4 million for
operational expenses recorded in the current fiscal year for
which the Company ultimately may be partially or fully
reimbursed; the potential reimbursement was not accrued as a
receivable as of September 30, 2004. Additionally, this
increase reflects $2.0 million associated with information
technology improvements, $700,000 for implementing the
provisions of the Sarbanes-Oxley Act and increases for other
miscellaneous items. The $9.1 million decrease in fiscal
year 2003 from fiscal year 2002 was primarily attributable to a
decrease in professional services and billing-related costs that
resulted from the implementation of various operational
enhancements during fiscal year 2003. These cost reductions were
slightly offset by higher costs of public liability insurance.
Depreciation and Amortization.
Depreciation and amortization
expense for fiscal year 2004 rose to $90.8 million, an
increase of $7.9 million, or 9.6 percent, over fiscal
year 2003. This increase reflects increased plant investment to
meet continuing customer growth, as well as the effect of a
December 18, 2003 Final Order issued by
56
the SCC of VA. In connection with the Final
Order, the Company recorded $3.5 million (pre-tax) of
additional depreciation expense in the current fiscal year to
implement higher depreciation rates applicable to the period
from January 1, 2002 through November 11, 2002.
Additionally, the Company recorded $1.0 million of
additional depreciation expense in fiscal year 2004 related to
the performance of earnings tests required by the Final Order of
the SCC of VA dated December 18, 2003. This earnings test,
as more fully described in Note 14 of the Notes to
Consolidated Financial Statements, effectively limits the return
on equity of the regulated utilitys Virginia operations at
the allowed return on equity until a regulatory asset
established for regulatory accounting purposes is eliminated.
Depreciation and amortization expense increased
$10.6 million in fiscal year 2003 over 2002 primarily due
to increased plant investment, and higher depreciation rates in
effect for the Virginia jurisdiction. The utilitys
composite depreciation and amortization rate was
3.48 percent, 3.20 percent and 2.93 percent for
fiscal years 2004, 2003 and 2002, respectively.
General Taxes.
General taxes decreased by
$1.5 million from fiscal year 2003 and increased by
$3.6 million over fiscal year 2002. Right-of-way fees
assessed and collected, principally in the District of Columbia,
primarily are impacted by changes in volumes of gas sold and
delivered that decreased in fiscal year 2004 and increased in
fiscal year 2003.
Income Taxes.
The Statements of Income Taxes
detail the composition of the change in income tax expense for
Washington Gas. Income taxes for the regulated utility decreased
$10.2 million in fiscal year 2004 when compared to 2003
primarily due to lower pre-tax income. The $40.2 million
increase in fiscal year 2003 over 2002 primarily reflects higher
pre-tax income, partially offset by an adjustment of
$2.7 million that reduced income tax expense in fiscal year
2003.
Other Income (Expenses) Net
Other income (expenses) net reflects net
income of $2.1 million for the fiscal year ended
September 30, 2004, as compared to a net expense of
$662,000 for the year ended September 30, 2003. The
$2.8 million increase in income was primarily attributable
to a current year allocation from WGL Holdings to Washington Gas
of non-operating tax benefits. This allocation was made in
accordance with the tax sharing agreement under which Washington
Gas and all other subsidiaries of WGL Holdings participate. WGL
Holdings consolidated financial statements do not reflect
the effect of this allocation that was eliminated in
consolidation. Additionally, fiscal year 2003 included a
$2.5 million after-tax gain from the sale of the
Companys headquarters property that resulted in a decrease
in income for the current fiscal year. This was mostly offset by
increased interest income earned on higher short-term investment
balances during fiscal year 2004, as well as by increased other
miscellaneous income.
Other income (expenses) net reflected a
net expense of $662,000 for fiscal year 2003 compared to income
of $561,000 for fiscal year 2002. This reduction in income was
due primarily to $8.7 million of after-tax benefits
realized in fiscal 2002 from the proceeds of a weather insurance
policy, which was substantially offset by the following factors:
(i)
a $2.5 million after-tax gain realized in
fiscal year 2003 related to the sale of the headquarters
property,
(ii)
a $3.9 million reduction in
fiscal year 2003 of after-tax expenses related to uncollectible
accounts and
(iii)
a $1.7 million after-tax
charge included in fiscal year 2002 related to a transaction
with a bankrupt energy trader.
Interest Expense
The explanations for changes in Washington
Gas interest expense are substantially the same as the
explanations included in the Managements Discussion of WGL
Holdings. Those explanations are incorporated herein by
reference into this discussion.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity and capital resources for Washington
Gas are substantially the same as the liquidity and capital
resources discussion included in the Managements
Discussion of WGL Holdings (except for certain items and
transactions that pertain to WGL Holdings and its unregulated
subsidiaries) which, therefore, are incorporated herein by
reference into this discussion.
57
REGULATORY MATTERS
During fiscal year 2004, the effect of regulatory
decisions issued in fiscal years 2003 and 2004 has contributed
favorably to the Companys overall operating results. A
relatively higher contribution during the later half of the
Companys fiscal year 2004 reflects changes in rate design
that are contributing proportionately more from higher fixed
system charges that include certain of the fixed costs the
Company incurs to serve customers. The earnings effect of
regulatory decisions also reflects certain accounting
adjustments necessitated by the decisions.
The regulated utility bases its requests for
modifying existing rates on increased net investment in plant
and equipment, higher operating expenses and the need to earn a
just and reasonable return on invested capital. From 1994
through September 30, 2002, the regulated utility had not
modified base rates in its major jurisdictions. Commencing in
fiscal year 2002, Washington Gas has increased the frequency for
seeking rate relief to ensure its rates reflect the underlying
cost of providing utility service. The following table
summarizes major rate applications and results.
Refer to Item 1 under the caption
Rates and Regulatory Matters
in this
Form 10-K and Note 14 of the Notes to Consolidated
Financial Statements for a further discussion of the
Companys regulatory activities and related contingencies.
58
WGL Holdings, Inc.
ITEM 7A. QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following issues related to the
Companys Market Risk are included under Item 7 and
are incorporated herein by reference into this discussion.
Table of Contents
Net Income (Loss) by Operating Segment
Years Ended September 30,
(In thousands)
2004
2003
2002
$
88,951
$
109,036
$
51,721
8,280
3,745
4,967
(5,396
)
(1,184
)
3,984
(3,510
)
(9,431
)
2,884
2,561
(3,990
)
4,802
745
(8,610
)
7,686
3,306
(12,600
)
$
96,637
$
112,342
$
39,121
Table of Contents
Table of Contents
Composition of Non-Utility Revenue Changes
Increase/(Decrease)
Compared to Prior Year
(In millions)
2004
2003
$
63.6
$
130.4
$
(5.4
)
$
(26.4
)
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Credit Ratings for Outstanding Debt Instruments
WGL Holdings
Washington Gas
Unsecured
Unsecured
Medium-Term Notes
Commercial
Medium-Term
Commercial
Rating Service
(Indicative)*
Paper
Notes
Paper
A+
F1
AA-
F1+
**
Not-Prime
A2
P-1
AA-
A-1
AA-
A-1
* Indicates the ratings that may be
applicable if WGL Holdings were to issue unsecured medium-term
notes.
** Unpublished.
Table of Contents
Table of Contents
Estimated Contractual Obligations and Commercial Commitments (Assumes Normal Weather)
Years Ended September 30,
(In millions)
Total
2005
2006
2007
2008
2009
Thereafter
$
850.0
$
136.8
$
116.9
$
105.0
$
85.1
$
60.6
$
345.6
634.1
60.5
50.0
85.0
45.1
75.0
318.5
16.7
0.1
0.3
0.1
0.1
0.1
16.0
311.2
39.3
34.5
30.6
26.0
22.7
158.1
254.5
215.3
39.2
288.9
245.9
36.7
6.3
131.6
108.7
22.9
49.6
4.1
4.2
4.2
4.2
3.8
29.1
24.7
5.6
5.5
5.4
5.4
1.4
1.4
$
2,561.3
$
816.3
$
310.2
$
236.6
$
165.9
$
163.6
$
868.7
(a)
Expected minimum payments under natural gas
transportation and storage contracts based on current estimates
of growth of the Washington Gas system, together with current
expectations of the timing and extent of unbundling initiatives
in the Washington Gas service territory. These contracts have
expiration dates through fiscal year 2024.
(b)
Represents scheduled repayment of
principal.
(c)
Represents the scheduled interest payments
associated with MTNs and other long-term debt.
(d)
Includes short-term gas purchase commitments
to purchase fixed volumes of natural gas under Washington
Gas regulatory-approved hedging program, as well as
long-term gas purchase commitments that contain fixed volume
purchase requirements. Commitment amounts are estimated based on
forecasted market prices for minimum purchases under these
purchase commitments.
(e)
Represents commitments based on a combination
of market prices at September 30, 2004 and fixed price
contract commitments for natural gas delivered to various city gate
stations, including the cost of transportation to that point,
which is bundled in the purchase price.
(f)
Expected expenditures based on forecasted
usage of its existing customer base. These commitments are
pursuant to electric purchase contracts with wholesale energy
marketers for full requirements service with no minimum
commitments (see Market Risk for a further
discussion of these contracts). Purchases will fluctuate based on
customers actual usage.
(g)
Includes certain Information Technology
service contracts. Also includes committed payments related to
certain environmental response costs.
Table of Contents
Table of Contents
Storage gas inventory increased
$53.0 million from September 30, 2003 due to higher
natural gas costs and increased storage capacity to accommodate
the requirements for the 2004-2005 winter heating season.
Accounts payable increased $40.7 million
from September 30, 2003 largely to fund higher natural gas
and electricity purchases. Higher natural gas purchases are due
mostly to higher prices associated with storage injections.
Table of Contents
Long-Term Debt Activity
2004
2003
2002
(In millions)
Interest Rate
Amount
Interest Rate
Amount
Interest Rate
Amount
4.88
%
$
37.0
$
5.17 6.05%
$
107.0
6.95
%
(36.0
)
6.50 7.04%
(40.0
)
6.90 7.56%
(42.6
)
6.75
%
0.8
5.99 7.88%
23.3
5.99 7.88%
(21.3
)
7.22 7.88%
(9.7
)
(0.2
)
(0.2
)
(0.2
)
$
1.6
$
(61.5
)
$
77.8
(a)
Includes the non-cash extinguishment of
project debt financing of $19.7 million and
$9.7 million for fiscal years 2003 and 2002,
respectively.
Capital Expenditures
Actual
Projected
(In millions)
2002
2003
2004
2005
2006
2007
2008
2009
Total
$
99.5
$
70.2
$
67.5
$
68.8
$
63.6
$
66.0
$
66.3
$
63.8
$
328.5
41.5
27.1
24.9
35.2
33.9
34.8
35.6
38.3
177.8
21.4
31.8
21.0
30.5
39.7
36.2
30.6
27.4
164.4
$
162.4
$
129.1
$
113.4
$
134.5
$
137.2
$
137.0
$
132.5
$
129.5
$
670.7
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Composition of Utility Net Revenue Changes
Increase/(Decrease)
(In millions)
From Prior Year
2004
2003
$
(31.5
)
$
90.3
12.7
5.3
5.7
21.3
2.7
2.0
(4.7
)
6.7
$
(15.1
)
$
125.6
(a)
For fiscal year 2004, Impact of rate
cases includes a $4.7 million benefit of an
accounting tracker granted by the PSC of DC related to pension
and other post-employment benefit expenses, and
Other excludes this benefit.
Table of Contents
Gas Deliveries, Weather and Meter Statistics
Years Ended September 30,
2004
2003
2002
Gas Sales and Deliveries
(thousands of therms)
856,135
888,437
703,160
454,549
496,889
346,910
1,310,684
1,385,326
1,050,070
7,626
12,163
10,646
268,483
257,799
277,367
276,109
269,962
288,013
41,052
67,245
169,210
1,627,845
1,722,533
1,507,293
4,024
4,550
3,304
3,792
3,799
3,814
6.1
%
19.8
%
(13.4
)%
990,062
959,922
939,291
29,438
26,167
31,205
Table of Contents
Table of Contents
Composition of Operation and Maintenance Expense Changes
Increase/(Decrease)
Compared to Prior Year
(In millions)
2004
2003
$
(0.9
)
$
8.8
2.4
0.4
3.0
8.7
(2.7
)
(1.6
)
2.0
10.6
(9.1
)
$
10.8
$
10.8
Table of Contents
Table of Contents
Summary of Major Rate Increase Applications and Results
Test Year
Application
Effective
12 Months
Increase in Annual
Allowed
Jurisdiction
Filed
Date
Ended
Revenues (Millions)
Rate of Return
Requested
Granted
Overall
Equity
02/07/03
11/24/03
09/30/02
$
18.8
9.7%
$
5.4
(a)
2.8%
8.42
%
10.60
%
06/19/01
04/09/03
12/31/00
16.3
6.8%
(5.4
)
(2.2)
%
8.83
%
10.60
%
District of Columbia
01/14/94
08/01/94
09/30/93
17.3
9.0%
6.4
3.4%
(b)
(b)
03/31/03
11/06/03
12/31/02
27.2
6.8%
2.9
0.7%
8.61
%
10.75
%
Maryland
03/28/02
09/30/02
12/31/01
31.4
9.3%
9.3
2.8%
(b)
(b)
06/01/94
12/01/94
03/31/94
17.6
5.7%
7.4
2.4%
9.79
%
(c)
11.50%
(c)
01/27/04
10/04/04
06/30/03
19.6
4.7%
(e)
(e)
8.44
%
10.50
%
06/14/02
11/12/02
(d)
12/31/01
23.8
6.6%
9.9
2.7%
8.44
%
10.50
%
04/29/94
09/27/94
12/31/93
15.7
6.4%
6.8
2.7%
9.72
%
11.50
%
(a)
The revenue increase includes a reduction for
the effect of a $6.5 million lower level of pension and
other post-retirement benefit costs that had been previously
deferred on the balance sheet of Washington Gas as a regulatory
liability. This deferral mechanism ensures that the variation in
these annual costs, when compared to the levels collected from
customers, does not affect net income. Therefore, this reduction
of annual revenues for pension and other post-retirement benefit
costs will be reflected as a change to the regulatory liability
on the balance sheet since the liability had already been
recorded. Additionally, the $5.4 million annual revenue
increase includes an $800,000 per year increase in certain
expenses that are also subject to the regulatory deferral
mechanism treatment. Accordingly, the total annual effect of the
Order on the Companys pre-tax income will result in an
annual increase of $11.1 million.
(b)
Application was settled without stipulating
the return on common equity.
(c)
Rates were implemented as a result of a
settlement agreement. The return on equity indicated in the
Final Order of 11.50 percent was not utilized to establish
rates.
(d)
New depreciation rates effective
January 1, 2002. New base rates went into effect subject to
refund on November 12, 2002. Final Order released on
December 18, 2003.
(e)
Rate increases went into effect, subject to
refund, on February 26, 2004 under an expedited rate
application. On September 27, 2004, a Final Order was
issued approving a proposed Stipulation filed by Washington Gas
and other participants to resolve all issues related to this
expedited rate case. Under the approved Stipulation, Washington
Gas adjusted its billing rates commencing October 4, 2004
to reflect the level of annual revenues as determined in the
previous Final Order issued on December 18, 2003 and noted
in (d) above.
Table of Contents
Price Risk Related to Regulated Utility Operations
Price Risk Related to Retail Energy-Marketing
Operations
Weather Risk
Interest-Rate Risk
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
59
WGL Holdings, Inc.
Years Ended September 30,
(In thousands, except per share data)
2004
2003
2002
$
1,267,948
$
1,301,057
$
925,131
668,968
696,561
459,149
50,079
40,465
27,549
548,901
564,031
438,433
182,573
176,482
164,236
44,178
39,773
40,825
91,510
83,549
72,921
36,544
37,841
34,328
58,463
68,633
28,702
413,268
406,278
341,012
135,633
157,753
97,421
789,859
726,231
595,866
30,123
35,521
61,887
1,673
1,439
1,918
821,655
763,191
659,671
(5,402
)
(9,431
)
816,172
761,540
654,573
2,175
168
1,725
818,347
761,708
656,298
3,308
1,483
(11,460
)
138,941
159,236
85,961
3,161
807
357
142,102
160,043
86,318
41,822
43,866
43,138
2,323
2,515
2,739
44,145
46,381
45,877
1,320
1,320
1,320
$
96,637
$
112,342
$
39,121
48,640
48,587
48,563
48,847
48,756
48,651
$
1.99
$
2.31
$
0.81
$
1.98
$
2.30
$
0.80
$
1.2950
$
1.2775
$
1.2675
The accompanying notes are an integral part of these statements.
60
WGL Holdings, Inc.
September 30,
(In thousands)
2004
2003
$
2,667,924
$
2,563,923
(752,373
)
(689,000
)
1,915,551
1,874,923
6,587
4,470
158,590
171,772
4,099
11,368
16,832
15,580
(16,042
)
(17,543
)
163,479
181,177
15,232
12,989
217,630
164,597
13,178
11,980
12,260
26,919
4,494
6,753
432,860
408,885
16,098
10,490
45,847
52,333
71,869
66,753
22,683
22,668
156,497
152,244
$
2,504,908
$
2,436,052
$
853,424
$
818,218
28,173
28,173
590,164
636,650
1,471,761
1,483,041
60,639
12,180
95,634
166,662
178,970
142,708
16,813
15,701
2,781
3,027
16,142
15,886
14,450
11,046
7,815
7,553
16,627
8,699
3,040
2,612
412,911
386,074
14,944
15,841
268,540
236,888
37,047
37,356
251,695
230,672
22,079
22,444
25,931
23,736
620,236
566,937
$
2,504,908
$
2,436,052
The accompanying notes are an integral part of these statements.
61
WGL Holdings, Inc.
Years Ended September 30,
(In thousands)
2004
2003
2002
$
96,637
$
112,342
$
39,121
91,510
83,549
72,921
4,735
5,724
5,001
28,178
41,625
(7,391
)
(897
)
(898
)
(901
)
(5,213
)
(5,159
)
(14,980
)
(6,414
)
(5,671
)
1,500
5,402
9,431
1,769
197
434
10,429
3,352
(24,606
)
7,531
(3,022
)
56,063
(53,033
)
(65,510
)
36,675
14,659
(13,497
)
6,041
40,737
(2,289
)
21,650
1,112
1,353
(1,010
)
3,404
(4,436
)
6,825
7,928
(1,258
)
(3,172
)
(246
)
(281
)
50
(5,608
)
(5,218
)
(3,241
)
3,847
2,881
1,007
242,565
143,784
205,320
50
37,800
93
130,411
(36,189
)
(41,903
)
(42,862
)
(879
)
(418
)
(1,055
)
(71,028
)
75,797
(43,188
)
(62,746
)
(61,948
)
(61,433
)
390
2,087
827
(132,602
)
(26,292
)
(17,300
)
(113,439
)
(129,083
)
(162,383
)
6,414
21,300
(3,900
)
(821
)
(7,768
)
(31,312
)
(107,846
)
(115,551
)
(197,595
)
2,117
1,941
(9,575
)
4,470
2,529
12,104
$
6,587
$
4,470
$
2,529
$
22,073
$
45,275
$
36,102
$
43,355
$
45,283
$
44,951
$
$
19,707
$
9,750
The accompanying notes are an integral part of these statements.
62
WGL Holdings, Inc.
September 30,
(In thousands, except shares)
2004
2003
$
471,547
$
471,497
3,789
2,582
379,562
345,927
(5
)
(32
)
(1,469
)
(716
)
(1,040
)
853,424
58.0%
818,218
55.2%
15,000
15,000
7,173
7,173
6,000
6,000
28,173
1.9%
28,173
1.9%
20,500
20,500
45,100
45,100
75,000
75,000
24,000
24,000
30,000
30,000
77,000
77,000
67,000
30,000
20,000
20,000
36,000
40,000
40,000
50,000
50,000
125,000
125,000
52,000
52,000
8,500
8,500
634,100
633,100
16,783
16,172
(80
)
(442
)
60,639
12,180
590,164
40.1%
636,650
42.9%
$
1,471,761
100.0%
$
1,483,041
100.0%
The accompanying notes are an integral part of these statements.
63
WGL Holdings, Inc.
Accumulated
Other
Common Stock Issued
Comprehensive
(In thousands,
Paid-In
Retained
Deferred
Loss, Net of
Treasury
except shares)
Shares
Amount
Capital
Earnings
Compensation
Taxes
Stock
Total
48,650,635
$
471,497
$
1,781
$
318,111
$
(275
)
$
$
(2,861
)
$
788,253
39,121
39,121
(136
)
155
566
585
(61,556
)
(61,556
)
48,650,635
471,497
1,645
295,676
(120
)
(2,295
)
766,403
112,342
112,342
(716
)
(716
)
111,626
937
88
1,255
2,280
(62,091
)
(62,091
)
48,650,635
471,497
2,582
345,927
(32
)
(716
)
(1,040
)
818,218
96,637
96,637
(753
)
(753
)
95,884
1,872
50
1,207
27
1,040
2,324
(63,002
)
(63,002
)
48,652,507
$
471,547
$
3,789
$
379,562
$
(5
)
$
(1,469
)
$
$
853,424
The accompanying notes are an integral part of these statements.
64
WGL Holdings, Inc.
Years Ended September 30,
(In thousands)
2004
2003
2002
$
29,389
$
30,841
$
30,978
28,291
26,997
26,078
355
1,010
(21,243
)
2,627
976
2,450
(976
)
(1,244
)
(722
)
(9
)
10,700
(1,649
)
211
(181
)
9
(528
)
432
(6,298
)
29,971
38,690
(1,375
)
(897
)
(898
)
(901
)
58,463
68,633
28,702
2,148
(1,731
)
4,647
27
1,899
(2,922
)
2,175
168
1,725
2,084
(1,869
)
4,544
(1,820
)
1,036
(3,094
)
264
(833
)
1,450
$
60,902
$
67,968
$
31,877
The accompanying notes are an integral part of these statements.
65
Washington Gas Light Company
|
|||||||||||||||||
Years Ended September 30, | |||||||||||||||||
|
|||||||||||||||||
(In thousands) | 2004 | 2003 | 2002 | ||||||||||||||
|
|||||||||||||||||
UTILITY OPERATIONS
|
|||||||||||||||||
Operating Revenues
|
$ | 1,293,675 | $ | 1,313,039 | $ | 938,804 | |||||||||||
Less: Cost of gas
|
694,639 | 708,543 | 472,823 | ||||||||||||||
Revenue taxes
|
50,079 | 40,465 | 27,549 | ||||||||||||||
|
|||||||||||||||||
Utility Net Revenues
|
548,957 | 564,031 | 438,432 | ||||||||||||||
|
|||||||||||||||||
Other Operating Expenses
|
|||||||||||||||||
Operation
|
184,860 | 178,239 | 166,305 | ||||||||||||||
Maintenance
|
43,663 | 39,459 | 40,595 | ||||||||||||||
Depreciation and amortization
|
90,809 | 82,866 | 72,254 | ||||||||||||||
General taxes
|
36,121 | 37,652 | 34,013 | ||||||||||||||
Income taxes
|
58,212 | 68,416 | 28,263 | ||||||||||||||
|
|||||||||||||||||
Utility Other Operating Expenses
|
413,665 | 406,632 | 341,430 | ||||||||||||||
|
|||||||||||||||||
Utility Operating Income
|
135,292 | 157,399 | 97,002 | ||||||||||||||
|
|||||||||||||||||
NON-UTILITY OPERATIONS
|
|||||||||||||||||
Operating Revenues
|
|||||||||||||||||
Other non-utility
|
1,523 | 1,512 | 1,819 | ||||||||||||||
|
|||||||||||||||||
Non-Utility Operating Revenues
|
1,523 | 1,512 | 1,819 | ||||||||||||||
|
|||||||||||||||||
Other Operating Expenses
|
|||||||||||||||||
Operating expenses (income)
|
(912 | ) | 9 | 7,645 | |||||||||||||
Income tax expense (benefit)
|
128 | 591 | (2,262 | ) | |||||||||||||
|
|||||||||||||||||
Non-Utility Operating Expenses
(Income)
|
(784 | ) | 600 | 5,383 | |||||||||||||
|
|||||||||||||||||
Non-Utility Operating Income (Loss)
|
2,307 | 912 | (3,564 | ) | |||||||||||||
|
|||||||||||||||||
TOTAL OPERATING INCOME
|
137,599 | 158,311 | 93,438 | ||||||||||||||
Other Income (Expenses) Net
|
2,132 | (662 | ) | 561 | |||||||||||||
|
|||||||||||||||||
INCOME BEFORE INTEREST EXPENSE
|
139,731 | 157,649 | 93,999 | ||||||||||||||
INTEREST EXPENSE
|
|||||||||||||||||
Interest on long-term debt
|
41,822 | 43,866 | 43,138 | ||||||||||||||
Other
|
1,319 | 2,885 | 2,174 | ||||||||||||||
|
|||||||||||||||||
Total Interest Expense
|
43,141 | 46,751 | 45,312 | ||||||||||||||
|
|||||||||||||||||
NET INCOME (BEFORE PREFERRED STOCK
DIVIDENDS)
|
96,590 | 110,898 | 48,687 | ||||||||||||||
DIVIDENDS ON PREFERRED STOCK
|
1,320 | 1,320 | 1,320 | ||||||||||||||
|
|||||||||||||||||
NET INCOME (APPLICABLE TO COMMON
STOCK)
|
$ | 95,270 | $ | 109,578 | $ | 47,367 | |||||||||||
|
The accompanying notes are an integral part of these statements.
66
Washington Gas Light Company
|
||||||||||||||
September 30, | ||||||||||||||
|
||||||||||||||
(In thousands) | 2004 | 2003 | ||||||||||||
|
||||||||||||||
ASSETS
|
||||||||||||||
Property, Plant and Equipment
|
||||||||||||||
At original cost
|
$ | 2,642,815 | $ | 2,539,397 | ||||||||||
Accumulated depreciation and amortization
|
(733,894 | ) | (671,990 | ) | ||||||||||
|
||||||||||||||
Net property, plant and equipment
|
1,908,921 | 1,867,407 | ||||||||||||
|
||||||||||||||
Current Assets
|
||||||||||||||
Cash and cash equivalents
|
3,398 | 4,119 | ||||||||||||
Receivables
|
||||||||||||||
Accounts receivable
|
66,602 | 69,455 | ||||||||||||
Gas costs due from customers
|
4,099 | 11,368 | ||||||||||||
Accrued utility revenues
|
16,832 | 15,580 | ||||||||||||
Allowance for doubtful accounts
|
(13,202 | ) | (15,826 | ) | ||||||||||
|
||||||||||||||
Net receivables
|
74,331 | 80,577 | ||||||||||||
|
||||||||||||||
Materials and supplies principally at
average cost
|
15,068 | 12,825 | ||||||||||||
Storage gas at cost (first-in, first-out)
|
165,196 | 124,416 | ||||||||||||
Deferred income taxes
|
11,654 | 10,957 | ||||||||||||
Other prepayments principally taxes
|
9,749 | 19,089 | ||||||||||||
Receivables from associated companies
|
887 | | ||||||||||||
|
||||||||||||||
Total current assets
|
280,283 | 251,983 | ||||||||||||
|
||||||||||||||
Deferred Charges and Other Assets
|
||||||||||||||
Regulatory assets
|
||||||||||||||
Gas costs
|
16,098 | 10,490 | ||||||||||||
Other
|
45,847 | 52,333 | ||||||||||||
Prepaid qualified pension benefits
|
71,511 | 66,420 | ||||||||||||
Other
|
21,757 | 19,784 | ||||||||||||
|
||||||||||||||
Total deferred charges and other assets
|
155,213 | 149,027 | ||||||||||||
|
||||||||||||||
Total Assets
|
$ | 2,344,417 | $ | 2,268,417 | ||||||||||
|
||||||||||||||
CAPITALIZATION AND LIABILITIES
|
||||||||||||||
Capitalization
|
||||||||||||||
Common shareholders equity
|
$ | 811,632 | $ | 778,502 | ||||||||||
Preferred stock
|
28,173 | 28,173 | ||||||||||||
Long-term debt
|
590,156 | 636,614 | ||||||||||||
|
||||||||||||||
Total capitalization
|
1,429,961 | 1,443,289 | ||||||||||||
|
||||||||||||||
Current Liabilities
|
||||||||||||||
Current maturities of long-term debt
|
60,611 | 12,100 | ||||||||||||
Notes payable
|
18,699 | 65,226 | ||||||||||||
Accounts payable
|
123,463 | 111,001 | ||||||||||||
Wages payable
|
16,714 | 15,623 | ||||||||||||
Accrued interest
|
2,781 | 3,027 | ||||||||||||
Dividends declared
|
16,142 | 15,886 | ||||||||||||
Customer deposits and advance payments
|
14,450 | 11,046 | ||||||||||||
Gas costs due to customers
|
7,815 | 7,553 | ||||||||||||
Accrued taxes
|
13,422 | 6,426 | ||||||||||||
Payables to associated companies
|
19,092 | 10,026 | ||||||||||||
Other
|
622 | 1,496 | ||||||||||||
|
||||||||||||||
Total current liabilities
|
293,811 | 259,410 | ||||||||||||
|
||||||||||||||
Deferred Credits
|
||||||||||||||
Unamortized investment tax credits
|
14,926 | 15,818 | ||||||||||||
Deferred income taxes
|
270,908 | 237,483 | ||||||||||||
Accrued pensions and benefits
|
36,954 | 37,264 | ||||||||||||
Regulatory liabilities
|
||||||||||||||
Accrued asset removal costs
|
251,695 | 230,672 | ||||||||||||
Other
|
22,069 | 22,431 | ||||||||||||
Other
|
24,093 | 22,050 | ||||||||||||
|
||||||||||||||
Total deferred credits
|
620,645 | 565,718 | ||||||||||||
|
||||||||||||||
Commitments and Contingencies
(Note 14)
|
||||||||||||||
|
||||||||||||||
Total Capitalization and Liabilities
|
$ | 2,344,417 | $ | 2,268,417 | ||||||||||
|
The accompanying notes are an integral part of these statements.
67
Washington Gas Light Company
The accompanying notes are an integral part of
these statements.
68
Washington Gas Light Company
The accompanying notes are an integral part of
these statements.
69
Washington Gas Light Company
The accompanying notes are an integral part of
these statements.
70
Washington Gas Light Company
71
WGL Holdings, Inc.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
1. ACCOUNTING POLICIES
GENERAL
WGL Holdings, Inc. (WGL Holdings or the Company)
is a holding company that was established on November 1,
2000 under the
Public Utility Holding Company Act of
1935
. WGL Holdings owns all of the shares of common stock of
Washington Gas Light Company (Washington Gas or the regulated
utility), a regulated natural gas utility, and all of the shares
of common stock of Crab Run Gas Company, Hampshire Gas Company
(Hampshire) and Washington Gas Resources Corporation (Washington
Gas Resources). Washington Gas Resources owns all of the shares
of common stock of various unregulated, energy-related
businesses. Until October 15, 2002, the Company held a
50-percent equity investment in Primary Investors, LLC (Primary
Investors) (refer to Note 2
Disposition of Limited
Liability Company Investment
).
NATURE OF OPERATIONS
The Companys core business is the delivery
and sale of natural gas through its regulated utility,
Washington Gas. The Company also offers retail 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 unregulated subsidiaries of Washington
Gas Resources.
Washington Gas is a regulated public utility that
delivers and sells natural gas to approximately one million
customers primarily in Washington, D.C., and the surrounding
metropolitan areas in Maryland and Virginia. Deliveries to firm
residential and commercial customers accounted for 80.5 percent
of the total therms delivered by Washington Gas in fiscal year
2004, deliveries to interruptible customers accounted for
17.0 percent, and deliveries to customers who use natural gas to
generate electricity
accounted for 2.5 percent. Washington Gas does not depend
on any one customer or group of customers to derive income.
Hampshire operates an underground gas storage facility that
provides services exclusively to Washington Gas. Hampshire is
regulated under a cost of service tariff by the Federal Energy
Regulatory Commission (FERC).
Washington Gas Resources owns the Companys
unregulated subsidiaries. These unregulated operations include
retail energy-marketing provided by Washington Gas Energy
Services (WGEServices), as well as commercial heating,
ventilating and air conditioning (HVAC) products and
services provided by American Combustion Industries, Inc.
(ACI) and Washington Gas Energy Systems, Inc. (WGESystems).
CONSOLIDATION OF FINANCIAL STATEMENTS
The consolidated financial statements include the
accounts of the Company and its subsidiaries during the periods
reported. Intercompany transactions have been eliminated.
Certain amounts in financial statements of prior years have been
reclassified to conform to the presentation of the current
fiscal year.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL
STATEMENTS
In accordance with Generally Accepted Accounting
Principles in the United States of America (GAAP), management
makes certain estimates and assumptions regarding:
(i)
reported amounts of assets and liabilities;
(ii)
disclosure of contingent assets and liabilities
at the date of the financial statements and
(iii)
reported amounts of revenues, revenues subject
to refund, and expenses during the reporting period. Actual
results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment (principally
utility plant) are stated at original cost, including labor,
materials, taxes and overhead. The cost of utility and other
plant of the regulated utility includes an allowance for funds
used during construction (AFUDC) that is calculated under a
formula prescribed by the FERC. The regulated utility
capitalizes AFUDC as a component of construction overhead. The
2004, 2003 and 2002 before-tax rates for AFUDC
72
were 1.98 percent, 1.76 percent, and
4.4 percent, respectively. The regulated utility
capitalized AFUDC of $94,700 during the fiscal year ended
September 30, 2004, excluding offsets of $20,000
representing adjustments to AFUDC for items such as small
projects that were discontinued and expensed. Capitalized AFUDC
for fiscal years 2003 and 2002 was $193,600 and $329,000,
respectively, excluding offsets of $206,000 and $362,000.
Washington Gas accrues estimated non-legal asset
removal costs through depreciation expense, with a corresponding
credit to Regulatory liabilities Accrued asset
removal costs. Additionally, when Washington Gas retires
depreciable utility plant and equipment, it charges the
associated original costs to Accumulated depreciation and
amortization and any related non-legal removal costs
incurred are charged to Regulatory liabilities
Accrued asset removal costs. In the rate setting process,
the liability for non-legal asset removal costs is treated as a
reduction to the net rate base upon which the regulated utility
has the opportunity to earn its allowed rate of return.
The Companys regulated utility charges
maintenance and repairs to operating expenses, except those
charges applicable to transportation and power-operated
equipment, which it allocates to operating expenses,
construction and other accounts based on the use of the
equipment. The Companys regulated utility capitalizes
betterments and renewal costs, and calculates depreciation
applicable to its utility gas plant in service primarily using a
straight-line method over the estimated remaining life of the
plant. The composite depreciation and amortization rate of the
regulated utility was 3.48 percent, 3.20 percent and
2.93 percent for fiscal years 2004, 2003 and 2002,
respectively. Such rates include the component related to
non-legal asset removal costs. The Companys regulated
utility periodically reviews the adequacy of its depreciation
rates by considering estimated remaining lives and other
factors. Refer to Note 14
Commitments and
Contingencies
for a discussion of depreciation-related
contingencies.
At both September 30, 2004 and 2003,
99.7 percent of the Companys consolidated original
cost of property, plant and equipment was related to the
regulated utility segment as shown below.
REGULATED OPERATIONS
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
, as amended and supplemented.
This standard includes accounting principles for companies whose
rates are determined by independent third-party regulators. When
setting rates, regulators often make decisions, the economics of
which require companies to record costs as expense (or defer
costs or revenues) in different periods than may be appropriate
for unregulated enterprises. When this situation occurs, the
regulated utility defers the associated costs as assets
(regulatory assets) on the balance sheet, and records them as
expenses on the income statement as it collects revenues through
customers rates. Further, regulators can also impose
liabilities upon a company for amounts previously collected from
customers, and for recovery of costs that are expected to be
incurred in the future (regulatory liabilities).
73
At September 30, 2004 and 2003, the
regulated utility had recorded the following regulatory assets
and liabilities on the Balance Sheets. These assets and
liabilities will be recognized as revenues and expenses in
future periods as they are reflected in customers rates.
Regulatory assets are reported on the Balance
Sheets under the captions Regulatory assets Gas
costs, Regulatory assets Other and
Gas costs due from customers. Regulatory liabilities
are reported on the Balance Sheets under the captions
Regulatory liabilities Accrued asset removal
costs, Regulatory liabilities Other and
Gas costs due to customers. With the exception of
Gas costs due from customers and Regulatory
assets Gas costs, there are no material regulatory
assets that reflect an outlay of cash by Washington Gas for
which Washington Gas does not earn its overall rate of return.
Washington Gas is allowed to recover and is required to pay,
using short-term interest rates, the carrying costs related to
gas costs due from and to its customers in the District of
Columbia and Virginia jurisdictions.
As required by SFAS No. 71, Washington Gas
monitors its regulatory and competitive environment to determine
whether the recovery of its regulatory assets continues to be
probable. If Washington Gas were to determine that recovery of
these assets is no longer probable, it would write off the
assets against earnings. The Company believes that SFAS
No. 71 continues to apply to its regulated operations, and
the recovery of its regulatory assets is probable.
CASH AND CASH EQUIVALENTS
WGL Holdings considers all investments with
original maturities of three months or less to be cash
equivalents. The Company did not have any restrictions on its
cash balances that would impact the payment of dividends by WGL
Holdings or its subsidiaries as of September 30, 2004.
REVENUE AND COST RECOGNITION
Utility Operations
Revenues.
For
regulated deliveries of natural gas, Washington Gas reads meters
and bills customers on a cycle basis. It accrues revenues for
gas delivered, but not yet billed, at the end of the accounting
period. Such revenues are recognized as unbilled revenues that
are adjusted in subsequent periods when actual meter readings
are taken.
74
Cost of Gas.
The regulated utilitys
jurisdictional tariffs contain mechanisms that provide for the
recovery of the cost of gas paid to suppliers on behalf of firm
customers. Under these mechanisms, the regulated utility
periodically adjusts its firm customers rates to reflect
increases and decreases in the cost of gas paid to suppliers.
Annually, the regulated utility reconciles the difference
between the total gas costs collected from firm customers and
the total gas costs 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.
The balance sheet captions Gas costs due from
customers, Gas costs due to customers and
Regulatory assets gas costs reflect amounts
related to these reconciliations.
Transportation Gas Imbalance.
Interruptible shippers and
third-party marketer shippers transport gas on the pipeline
facilities of the regulated utility as part of the unbundled
services offered by the regulated utility. The delivered volumes
of gas from third-party shippers often do not equal the volumes
delivered out of the pipeline system to the customers, resulting
in a transportation gas imbalance. These imbalances are usually
short-term in duration, and the regulated utility monitors the
activity and regularly notifies the shippers when their accounts
have an imbalance. In accordance with regulatory treatment,
Washington Gas does not record assets or liabilities associated
with gas volumes related to these transportation imbalances but,
rather, reflects the economic impact in its actual cost
adjustment balance calculations eliminating any profit or loss
that would occur as a result of the imbalance.
The regulated utility also engages an asset
manager to operate its pipeline and storage capacity, and to
assist in the acquisition of natural gas supply. From time to
time, the asset manager will utilize the upstream pipeline
capacity reserved by the regulated utility and the capacity from
the regulated utilitys own pipeline system for its own
purposes. The regulated utility also designates portions of its
pipeline, peaking and storage capacity to third-party marketers,
under a program approved by relevant regulatory bodies, in
connection with its unbundling and customer choice programs.
Non-Utility Operations
Retail Energy-Marketing.
WGEServices, the Companys
retail energy-marketing subsidiary, sells natural gas and
electricity on an unregulated basis to residential, commercial
and industrial customers both inside and outside the Washington
Gas service territory.
WGEServices enters into indexed or fixed-rate
contracts with residential, commercial and industrial customers,
for sales of natural gas. Customer contracts, which have terms
of up to 36 months, allow WGEServices to bill customers
based upon metered gas usage at customer premises or quantities
delivered to the local utility, either of which may vary by
month. WGEServices recognizes revenue based on contractual
billing amounts plus an accrual for gas delivered and unbilled.
WGEServices electric commodity contracts
are full requirements contracts in which the wholesale energy
suppliers from whom WGEServices purchases electricity are
responsible for each customers full metered electricity
usage. WGEServices recognizes revenue based on electricity
delivered and billed to customers, and accrues revenue for
electric volumes delivered, but not yet billed, at the end of
the accounting period. WGEServices recognizes electricity costs
based on the same volumetric estimates that it uses to record
revenue. These estimates later are actualized to the
customers final metered usage (refer to Note 14
Commitments and Contingencies
for a further discussion of
an electric supplier contract).
Heating, Ventilating and Air Conditioning.
Two unregulated subsidiaries, ACI
and WGESystems, design and renovate mechanical HVAC systems for
commercial and governmental customers under construction
contracts. The Company recognizes income for all contracts using
the percentage-of-completion method.
RATE REFUNDS DUE TO CUSTOMERS
If Washington Gas were to file a request with a
state regulatory commission to modify customers rates, the
regulated utility could, depending on the jurisdiction, charge
customers the new rates until the regulatory commission renders
a final decision. During this interim period, the regulated
utility would potentially record a provision for a rate refund
based on the difference between the amount it collected in rates
subject to refund and the amount it expected
75
to recover pending the final regulatory decision.
Similarly, Washington Gas periodically records provisions for
rate refunds related to other transactions of the regulated
utility. Actual results for these regulatory contingencies are
difficult to predict and could differ significantly from the
estimates reflected in the financial statements. When necessary,
in managements judgment, Washington Gas establishes an
estimated refund to customers. Refer to Note 14
Commitments and Contingencies
for a further discussion of
the Companys regulatory matters and related contingencies.
REACQUISITION OF LONG-TERM DEBT
Washington Gas defers gains or losses resulting
from the reacquisition of long-term debt for financial reporting
purposes, and amortizes them over future periods as adjustments
to interest expense in accordance with established regulatory
practice. For income tax purposes, Washington Gas recognizes
these gains and losses when they are incurred.
WEATHER INSURANCE POLICY
Effective October 1, 2000, Washington Gas
purchased a five-year weather insurance policy to minimize the
impact of warmer-than-normal weather on the Companys
financial results. On an annual basis that begins on October 1
and ends on September 30 of each year during the five-year
term of the policy, the regulated utility receives $32,000 for
every heating degree day (HDD) below the normal level of
HDDs stated in the policy. Washington Gas cannot be paid for
more than 515 HDDs per fiscal year, subject to certain
limitations. Furthermore, the regulated utility cannot be paid
for more than 1,295 HDDs over the entire five-year policy
life.
Washington Gas pays an annual premium of
$4.25 million for the weather insurance policy and spreads
the premium cost during the year on the basis of the estimated
normal HDDs that are expected in each month of the year. Using
this method of accounting for the insurance premium causes
approximately 90 percent of the annual premium to be recorded
during the first and second quarters of the fiscal year.
At any point in time during the fiscal year,
benefits derived from the policy are recorded in WGL
Holdings Consolidated Statements of Income for the
cumulative number of HDDs that are warmer than normal,
multiplied by $32,000, with an assumption of normal weather for
the remainder of the fiscal year. As a result, income from the
policy recorded in one interim accounting period can be reduced
or even eliminated in a subsequent interim accounting period.
The benefits derived from the policy in any one fiscal year
cannot be eliminated in a subsequent fiscal year other than to
reduce the remaining number of HDDs that can be utilized over
the five-year term of the policy.
In fiscal years 2004 and 2003, weather was colder
than normal and Washington Gas realized no benefits from this
insurance. In fiscal year 2002, the regulated utility recorded
$14.8 million of pre-tax income from the policy as the
weather from October 1, 2001 through September 30,
2002 was 462 HDDs warmer than the normal HDDs, as defined
by the terms of the policy. This income from the policy was
accrued in fiscal year 2002, and cash was subsequently received
in October 2002 from the underwriter of the insurance policy.
The weather insurance policy is accounted for
under the guidelines issued by the Emerging Issues Task Force
(EITF) of the Financial Accounting Standards Board
(FASB) in Issue No. 99-2. Washington Gas records both
the benefits and the expense of the insurance in Other
income (expenses) net in the Statements of Income.
The premium expense and any benefits that are derived from the
weather insurance policy are not considered in establishing the
retail rates of the regulated utility.
CONCENTRATION OF CREDIT RISK
The revenues of the regulated utility segment
accounted for approximately 61.9 percent of WGL
Holdings total consolidated revenues. There is a
relatively low concentration of credit risk in the regulated
utility with respect to its customer base due to the large
number of customers, none of which are singularly large as a
percentage of the regulated utilitys total customer base.
Certain suppliers that sell gas to Washington Gas have either
relatively low credit ratings or are not rated by major credit
rating agencies. A suppliers failure to deliver contracted
volumes of gas
76
may cause the regulated utility to replace those
volumes at prevailing market prices, which may be higher than
the original transaction prices, and pass these costs through to
its sales customers under the purchase gas cost adjustment
mechanisms.
The concentration of credit risk for
WGEServices retail energy-marketing business as it relates
to the size of its customer base is very similar to the credit
risk associated with the regulated utility. The retail
energy-marketing business purchases natural gas and electricity
from certain suppliers that have low credit ratings or are not
rated by major credit rating agencies. This presents a risk to
the extent a supplier does not deliver gas or electricity under
the terms of its contract and the retail energy-marketing
company has to repurchase energy at a higher cost. In July 2003,
the principal supplier of electricity to WGEServices filed for
bankruptcy protection under Chapter 11 of the Bankruptcy
Code but has, to date, continued to honor its supply obligations
to WGEServices. Refer to Note 14
Commitments and
Contingencies
for a further discussion of the credit risk
associated with WGEServices electric supplier contract.
DERIVATIVE ACTIVITIES
The Company applies the accounting guidelines of
SFAS No. 133,
Accounting for Derivative Instruments and
Hedging Activities
, as amended by SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain
Hedging Activities
and SFAS No. 149,
Amendment of
Statement 133 on Derivative Instruments and Hedging
Activities
(collectively referred to as SFAS No. 133).
SFAS No. 133 requires derivative instruments, including
derivative instruments embedded in certain contracts, to be
recorded at fair value as either an asset or a liability.
Changes in the derivatives fair value are recorded in
earnings, unless the derivative meets specific hedge accounting
criteria. If the derivative is designated as a fair value hedge,
the changes in the fair value of the derivative and the hedged
item are recognized in earnings. If the derivative is designated
as a cash flow hedge, changes in the fair value of the
derivative generally are recorded in other comprehensive income
(loss) and recognized in income when the hedged item
affects earnings. Additionally in accordance with SFAS
No. 133, the Company formally documents, designates and
assesses the effectiveness of derivatives that are accounted for
as hedging instruments. For those derivatives that are
associated with activities of the regulated utility whose costs
are likely to be recovered from or refunded to customers in
future periods, the corresponding fair value is recorded as a
regulatory asset or a regulatory liability, subject to SFAS
No. 71, rather than through earnings or other comprehensive
income (loss).
The Company enters into forward contracts and
other related transactions for the purchase of natural gas. A
majority of these contracts qualify as normal purchases and
sales, and are exempt from the accounting requirements of SFAS
No. 133. Contracts that qualify as derivative instruments
under SFAS No. 133 are recorded on the balance sheet at
fair value.
From time to time, Washington Gas utilizes
derivative instruments that are designed to minimize
interest-rate risk associated with planned issuances of
Medium-Term Notes (MTNs). The interest costs associated with
issuing MTNs reflect spreads over comparable maturity U.S.
Treasury yields. Such spreads take into account credit quality,
maturity and other factors.
Refer to Note 6
Derivative
Instruments
for a further discussion of these transactions.
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 income 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. Refer to the table under
Regulated
Operations
above that depicts the regulated
utilitys regulatory assets and liabilities associated with
income taxes due from and to customers at September 30,
2004 and
77
2003. 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.
The Company amortizes investment tax credits as
reductions to income tax expense over the estimated service
lives of the related properties.
STOCK-BASED COMPENSATION
As permitted by SFAS No. 123,
Accounting
for Stock-Based Compensation
, as amended by SFAS
No. 148,
Accounting for Stock-Based
Compensation-Transition and Disclosure
, the Company applies
Accounting Principles Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees
, and related
interpretations in accounting for its stock-based compensation
plans. In accordance with APB No. 25, the Company does not
record compensation expense related to its stock option grants.
The Company records compensation expense for performance shares
awarded to certain key employees. If compensation expense for
stock options had been determined and recorded based on fair
value at their grant dates consistent with the method prescribed
by SFAS No. 123, as amended, the Companys net income
and earnings per share would have been reduced to the amounts
shown in the following table.
RECENT ACCOUNTING STANDARDS
Effective March 31, 2004, the Company
adopted SFAS No. 132 (revised 2003),
Employers
Disclosure about Pensions and Other Postretirement Benefits
,
which amends SFAS No. 87,
Employers Accounting for
Pensions
, SFAS No. 88,
Employers Accounting
for Settlements and Curtailments of Defined Benefit Pension
Plans and for Termination Benefits
, and SFAS No. 106,
Employers Accounting for Postretirement Benefits Other
Than Pensions
, and replaces SFAS No. 132,
Employers Disclosures about Pensions and Other
Postretirement Benefits
(collectively referred to as
SFAS No. 132 (revised)). SFAS No. 132
(revised) expands employers disclosures about pension and
other post-retirement benefit plans to present more information
regarding the economic resources and obligations of such plans
in terms of the plans assets, obligations, cash flows and
net periodic benefit costs (refer to Note 11
Pension and Post-Retirement Benefit Plans
). Additionally,
SFAS No. 132 (revised) requires interim-period
disclosures regarding plan benefit costs and plan contributions.
The adoption of SFAS No. 132 (revised) did not change the
Companys measurement or recognition of pension and other
post-retirement benefit costs as required by SFAS No. 87,
SFAS No. 88 and SFAS No. 106, nor did the adoption of
this new standard have any effect on the Companys
consolidated financial statements.
Effective December 2003, the Company adopted FASB
Staff Position (FSP) No. 106-1,
Accounting and
Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003
. FSP
78
No. 106-1 permitted the sponsor of a
post-retirement health care plan that provides a prescription
drug benefit to make a one-time election to defer accounting for
the effects of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act), and required certain
disclosures pending further consideration of the underlying
accounting issue. The Act, signed into law on December 8,
2003, introduces a prescription drug benefit under Medicare, as
well as a federal subsidy to sponsors of retiree health care
benefit plans that provide a benefit that is at least
actuarially equivalent to Medicare (Medicare Part D). The
Company elected to follow the deferral provisions of FSP
No. 106-1 for both the first and second quarters ended
December 31, 2003 and March 31, 2004, respectively. In
accordance with this FSP, the effects of this Act on any
measures of the Accumulated Post-Retirement Benefit Obligation
(APBO) or net periodic post-retirement benefit cost
associated with the Companys benefit plans were not
reflected in the Companys unaudited consolidated financial
statements or accompanying notes for those interim reporting
periods. The deferral provisions of FSP No. 106-1 were
permitted until such time as new specific authoritative guidance
on the accounting for the Medicare subsidy was issued.
In May 2004, the FASB issued FSP No. 106-2,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003
, which superseded the accounting guidance in FSP
No. 106-1. FSP No. 106-2 provides specific guidance on
accounting for the effects of the Act for employers sponsoring
post-retirement health care plans that provide certain
prescription drug benefits. Additionally, this guidance allows
companies who elected to follow the deferral provisions of FSP
No. 106-1, and whose prescription drug benefit plans are
actuarially equivalent to the benefit to be provided under
Medicare Part D, to either reflect the effects of the federal
subsidy to be provided by the Act in their financial statements
on a prospective basis or on a retroactive basis.
The Company and its external actuary determined
that the prescription drug benefit provided by the
Companys post-retirement benefit plans as of the date of
the Acts enactment was at least actuarially equivalent to
those that will be provided by Medicare Part D and, accordingly,
the Company will be entitled to the federal subsidy when it
begins in calendar year 2006. In June 2004, the Company adopted
the provisions of FSP No. 106-2, and applied these
provisions on a retroactive basis effective January 1,
2004, the beginning of the Companys second quarter of
fiscal year 2004. Accordingly, the Company calculated the
incremental effect of the Medicare subsidy on its APBO as of
December 31, 2003, the end of the interim period that
included the date of the Acts enactment (all other
actuarial assumptions determined as of September 30, 2003
for fiscal year 2004 were not changed). Based on this
calculation, the Company recognized the effects of the Medicare
subsidy on its net periodic post-retirement benefit costs which,
net of capitalization and deferrals required by the effects of
regulation on the regulated utility, reduced this expense and
improved earnings by $2.7 million for the fiscal year ended
September 30, 2004 (refer to Note 11
Pensions
and Other Post-Retirement Benefit Plans
). Additionally, the
Company restated net income for the three months ended
March 31, 2004, increasing it by $1.2 million to
recognize the effect of the subsidy related to this period
(refer to
Supplementary Financial Information
(Unaudited)
) included in this Annual Report on
Form 10-K for further information regarding the interim
period restatement).
In December 2003, the FASB issued FASB
Interpretation No. 46 (revised December 2003),
Consolidation of Variable Interest Entities, an
interpretation of ARB No. 51
(FIN 46R). The
primary objective of FIN 46R is to provide guidance on the
identification and consolidation of variable interest entities
(VIEs), which are entities by which control is achieved through
means other than voting rights. FIN 46R replaced FASB
Interpretation No. 46,
Consolidation of Variable
Interest Entities
, which was issued in January 2003.
FIN 46R generally became effective March 31, 2004 for
all VIEs. Management has reviewed this new standard and
concluded that it does not have any effect on the Companys
consolidated financial statements at this time.
79
In November 2004, the FASB issued SFAS
No. 151,
Inventory Costs
. SFAS No. 151 requires
that abnormal amounts of idle facility expense, freight,
handling costs and spoilage be charged to income as a current
period expense rather than capitalized as inventory costs. SFAS
No. 151 is effective for the Company on October 1,
2005. Management is currently reviewing the effect of this new
standard, but does not believe it will materially affect the
Companys consolidated financial statements.
2. DISPOSITION OF LIMITED LIABILITY
COMPANY INVESTMENT
On September 20, 2002, WGL Holdings and
Thayer Capital Partners (Thayer) entered into an agreement to
restructure Primary Investors LLC (Primary Investors), a limited
liability company in which the Company held a 50 percent
equity method investment, such that WGL Holdings had no
liability or financial commitment to Thayer, Primary Investors
or any subsidiary of Primary Investors. On October 15,
2002, WGL Holdings and Primary Investors executed a final
closing, and WGL Holdings transferred all of its interest in
Primary Investors to Thayer. Since September 30, 2002, the
Company had no net investment in this equity venture nor was
there any effect on consolidated net income from this venture
during fiscal years 2003 and 2004. Net income for fiscal year
ended 2002 included a net loss from these operations of
$3.5 million as well as an impairment provision of
$9.4 million to reflect the permanent decline in value.
3. SALE OF CARRIED INTEREST AND OTHER
ASSETS
During the second quarter of fiscal year 2004,
the Companys non-utility operations realized pre-tax
earnings of $6.4 million from the sale, by a third party,
of two buildings at Maritime Plaza, a commercial development
project in which the Company held a carried interest. This
carried interest had no cost basis, and was accounted for under
the equity method. WGL Holdings utilized a capital loss
carryforward to offset the federal income taxes associated with
this transaction and, after considering other local income tax
expense, WGL Holdings realized after-tax earnings of
$5.8 million for the fiscal year ended September 30,
2004.
In the quarter ended March 31, 2003, the
regulated utility realized a pre-tax gain of $4.1 million
(or $2.5 million after income taxes) from the sale of its
land and the former headquarters building located in Washington,
D.C. This gain was reported in Other income
(expenses) net for the fiscal year ended
September 30, 2003 after considering managements
estimate of the regulatory liability that would be due to
customers as a result of this gain (refer to Note 14
Commitments and Contingencies
for a further discussion of
these regulatory matters and related contingencies).
In the quarter ended December 31, 2002, the
Companys non-utility operations realized a pre-tax gain of
$1.5 million (or $926,000 after income taxes) from the sale
of a real estate partnership interest.
4. SHORT-TERM DEBT
WGL Holdings and Washington Gas satisfy their
short-term financing requirements through the sale of commercial
paper or through bank borrowings. Due to the seasonal nature of
the regulated utility and retail energy-marketing operations,
short-term financing requirements can vary significantly during
the year. The Company maintains revolving credit agreements to
support its outstanding commercial paper and to permit
short-term borrowing flexibility. The Companys policy is
to maintain bank credit facilities in an amount equal to its
expected maximum commercial paper position.
Effective April 28, 2004, Washington Gas and
WGL Holdings each entered into new credit agreements with a
group of banks in the amount of $175 million for each
entity. The credit facility for Washington Gas expires on
April 28, 2009, and permits the regulated utility to
request until April 28, 2005, and the banks to approve, an
additional line of credit of $100 million above the
original credit limit, for a maximum potential total of
$275 million. The WGL Holdings credit facility
expires on April 27, 2007, and permits the Company to
request until April 28, 2005, and the banks to approve, an
additional line of credit of $50 million above the original
credit limit, for a maximum
80
potential total of $225 million. As of
September 30, 2004, there was no amount outstanding under
either the Washington Gas or WGL Holdings credit facility.
Both WGL Holdings and Washington Gas may reduce
the amount of the commitments at their option. Depending on the
type of borrowing option chosen under these credit agreements,
loans may bear interest at variable rates based on the
Eurodollar rate, the higher of the prime lending rate or the Fed
Funds effective rate, or at a competitive rate determined
through auction.
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 on their revolving
credit agreements. Also under the revolving credit agreements, the
ratio of consolidated indebtedness to consolidated total
capitalization can not exceed 0.65 to 1.0 (65.0 percent), and,
for WGL Holdings, the ratio of earnings before interest and taxes to
interest expense can not fall below 2.25 to 1.0 (2.25 times). Under
the terms of the revolving credit agreements, 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, 2004, the Company was in compliance
with all of the covenants under its revolving credit agreements.
At September 30, 2004 and 2003, WGL Holdings
and its subsidiaries had $95.6 million and
$166.7 million, respectively, in commercial paper
outstanding at a weighted average cost of 1.99 percent and
1.17 percent, respectively. Included in these consolidated
balances were $18.7 million and $65.2 million in
commercial paper that Washington Gas had outstanding at
September 30, 2004 and 2003, respectively.
5. LONG-TERM DEBT
FIRST MORTGAGE
BONDS
The Mortgage of Washington Gas dated
January 1, 1933 (Mortgage), as supplemented and amended,
securing any First Mortgage Bonds (FMBs) it issues, constitutes
a direct lien on substantially all property and franchises owned
by the regulated utility, other than a small amount of property
that is expressly excluded. The regulated utility had no debt
outstanding under the Mortgage at September 30, 2004 and
2003. Any FMBs that may be issued in the future will represent
indebtedness of Washington Gas.
SHELF
REGISTRATION
At September 30, 2004, Washington Gas was
authorized to issue up to $213.0 million of long-term debt
under a shelf registration that was declared effective by the
Securities and Exchange Commission (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.
UNSECURED
MEDIUM-TERM NOTES
Washington Gas issues unsecured Medium-Term Notes
(MTNs) with individual terms regarding interest rates,
maturities and call or put options. These notes can have
maturity dates of one or more years from the date of issuance.
At September 30, 2004 and 2003, the weighted average
interest rate on all outstanding MTNs was 6.46 percent and
6.58 percent, respectively.
The indenture for these unsecured MTNs provides
that Washington Gas will not issue any FMBs under its Mortgage
without securing all MTNs with all other debt secured by the
Mortgage.
Certain of Washington Gas outstanding MTNs
have call options, put options, or both. Certain other MTNs have
attached a make-whole call feature that pays the holder a
premium based on a spread over the yield to maturity of a U.S.
Treasury security having a comparable maturity, when that
particular note is called by Washington Gas before its stated
maturity date. With the exception of this make-whole call
feature, Washington Gas is not required to pay call premiums for
calling debt prior to the stated maturity date.
On November 17, 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 4.88 percent MTNs due in fiscal year 2014 that were
issued in November 2003. The $1.2 million loss incurred in
connection with the debt retirement was deferred and is being
amortized over the life of the newly issued debt in accordance
with regulatory accounting requirements. Refer to
Note 6
Derivative Instruments
for a discussion
of a derivative transaction that was settled concurrent with the
debt issuance discussed in this footnote.
81
LONG-TERM DEBT
MATURITIES
Maturities of long-term debt for each of the next
five fiscal years and thereafter as of September 30, 2004
are summarized in the following table.
6. DERIVATIVE INSTRUMENTS
Washington Gas enters into forward contracts and
other related transactions for the purchase of natural gas that
qualify as derivative instruments under SFAS No. 133. The
net fair value loss of these forward contracts and other related
transactions, at September 30, 2004 and 2003, totaled
$8.2 million and $3.3 million, respectively. These
amounts were recorded as a payable, with a corresponding amount
recorded as a regulatory asset in accordance with regulatory
accounting requirements.
Washington Gas enters into derivative instruments
that are designed to minimize interest-rate risk associated with
planned issuances of MTNs. In June 2003, Washington Gas entered
into two forward-starting swaps with an aggregate notional
principal amount of $62.0 million to mitigate a substantial
portion of interest-rate risk associated with anticipated future
debt transactions. These swaps were designated as cash flow
hedges in accordance with SFAS No. 133, and were carried at
fair value. Concurrent with the issuance of $37.0 million
of MTNs in November 2003 (see Note 5
Long-Term
Debt
), Washington Gas terminated $37.0 million of the
total $62.0 million aggregate notional principal amount of
the forward-starting swaps. Washington Gas received
$2.6 million associated with the settlement of this hedge
agreement, which was recorded as a regulatory liability. As a
result of a Virginia rate order issued
on September 27, 2004, $737,000 of this amount received was
reclassified from a regulatory liability to a current liability
as it will be refunded to customers during the January 2005
billing cycle (refer to Note 14
Commitments and
Contingencies
for a further discussion of this regulatory
matter). The remaining balance is being amortized over the life
of the newly issued MTNs in accordance with regulatory
accounting requirements. In December 2003, Washington Gas
terminated the remaining $25.0 million aggregate notional
principal of the forward-starting swaps, and received
$1.2 million associated with the settlement of this hedge
agreement which was recorded as a regulatory liability. Of this
amount, $495,000 was reclassified to a current liability which will
be refunded to customers in connection with a Virginia rate order.
On September 16, 2004, Washington Gas
entered into two forward-starting swaps with an aggregate
notional principal amount of $60.5 million. These swaps are
intended to mitigate a substantial portion of interest-rate risk
associated with anticipated future debt transactions, and are
scheduled to terminate in fiscal year 2005 concurrent with the
execution of debt transactions planned for that year. These
swaps were designated as cash flow hedges and carried at fair
value. At September 30, 2004, these instruments had a fair
value loss totaling $475,000 that was recorded as a payable with
a corresponding amount recorded as a regulatory asset.
The Companys non-regulated retail
energy-marketing subsidiary, WGEServices, enters into contracts
for the sale and purchase of natural gas that qualify as
derivative instruments under SFAS No. 133. WGEServices also
enters into other derivative instruments (primarily in the form
of call options, put options and swap contracts) related to the
sale and purchase of natural gas. WGEServices derivative
instruments are recorded at fair value on the Companys
82
Consolidated Balance Sheets. Changes in the fair
value of these various derivative instruments are reflected in
the earnings of the retail energy-marketing segment. These
derivative instruments were valued at $719,000 and $188,000 at
September 30, 2004 and 2003, respectively. WGEServices
recorded net gains of $892,000 and $221,000 for fiscal years
2004 and 2003, respectively. WGEServices recorded a net loss of
$323,000 during fiscal year 2002 related to similar derivative
instruments.
WGEServices also holds HDD option contracts that
are used to manage its risk for natural gas customers who
participate in a program that allows them to pay a fixed amount
for their gas requirements regardless of the amount of gas
consumed. These hedges cover a portion of WGEServices
estimated net revenue exposure to variations in HDDs. These
contracts pay WGEServices a fixed dollar amount for every HDD
over a specified level during the calculation period. Similar to
Washington Gas weather insurance policy (see
Note 1
Accounting Policies
), these contracts
are accounted for under the guidelines issued by EITF Issue
No. 99-2. WGEServices recorded, net of premium costs, a net
loss related to these hedges of $114,000 for fiscal year 2004,
and a net gain of $372,000 for fiscal year 2003. No such gains
or losses were recorded in fiscal year 2002.
7. COMMON STOCK
COMMON STOCK
OUTSTANDING
Shares of common stock outstanding, net of
treasury shares, were 48,652,507, 48,611,563 and 48,564,667 at
September 30, 2004, 2003 and 2002, respectively.
COMMON STOCK
RESERVES
At September 30, 2004, there were 2,951,956
authorized, but unissued, shares of common stock reserved under
the following plans.
Refer to Note 12
Stock-Based
Compensation
for a discussion regarding the Companys
stock-based compensation plans.
83
8. PREFERRED STOCK
Washington Gas has three series of cumulative preferred
stock outstanding, and each series is callable by Washington
Gas. All three series have a dividend preference that prevents
Washington Gas from declaring and paying common dividends unless
preferred dividends have been paid. In addition, all outstanding
shares of preferred stock have a preference as to the amounts
that would be distributed in the event of a liquidation or
dissolution of Washington Gas. The following table presents this
information, as well as call prices for each preferred stock
series outstanding.
9. EARNINGS PER SHARE
Basic earnings per share (EPS) is computed
by dividing net income by the weighted average number of common
shares outstanding during the reported period. Diluted EPS
assumes the issuance of common shares pursuant to stock-based
compensation plans at the beginning of the applicable period
(see Note 12
Stock-Based Compensation
). The
following table reflects the computation of the Companys
basic and diluted EPS for WGL Holdings for fiscal years ended
September 2004, 2003 and 2002, respectively.
84
10. INCOME TAXES
The Company files a consolidated federal income
tax return. The Companys federal income tax returns for
all years through September 30, 2000 have been reviewed and
closed, or closed without review by the Internal Revenue
Service. The Company and each of its subsidiaries also
participate in a tax sharing agreement that establishes the
method for allocating tax benefits from losses to various
subsidiaries that are utilized on a consolidated federal income
tax return. During fiscal year 2004, Washington Gas realized
$5.3 million of tax savings resulting from this tax sharing
agreement. This benefit was reflected primarily in Other income
(expenses) net on Washington Gas Statement of
Income. The effect of this allocation of benefits to Washington
Gas has no effect on WGL Holdings consolidated financial
statements. During fiscal years 2003 and 2002, Washington Gas
realized $355,000 and $1.1 million, respectively, of tax
savings as a result of this tax sharing agreement. State income
tax returns are filed on a separate company basis in states
where the Company has operations and/or a requirement to file.
The Statements of Income Taxes provide the
following:
(i)
the components of income tax expense;
(ii)
a reconciliation between the statutory federal
income tax rate and the effective income tax rate and
(iii)
the components of accumulated deferred income
tax assets and liabilities at September 30, 2004 and 2003.
During fiscal years ended September 30, 2004
and 2003, the Company recognized tax benefits of
$2.0 million and $2.4 million, respectively, from the
release of a valuation allowance associated primarily with
previously unrecognized capital losses. A valuation allowance of
$2.0 million and $4.0 million remained for unused tax
benefits of capital losses as of September 30, 2004 and
2003, respectively.
11. PENSION AND OTHER POST-RETIREMENT
BENEFIT PLANS
Washington Gas maintains a qualified, trusteed,
non-contributory defined benefit pension plan (qualified pension
plan) covering all active and vested former employees of
Washington Gas. To the extent allowable by law, Washington Gas
funds pension costs accrued for the qualified pension plan.
Executive officers of Washington Gas also
participate in a non-funded supplemental executive retirement
plan (SERP), a non-qualified defined benefit pension plan. A
rabbi trust has been established for the potential future
funding of the SERP liability.
Washington Gas provides certain healthcare and
life insurance benefits for retired employees. Substantially all
employees of the regulated utility may become eligible for such
benefits if they attain retirement status while working for
Washington Gas. The Company accounts for these benefits under
the provisions of SFAS No. 106,
Employers
Accounting for Postretirement Benefits Other Than Pensions
.
The Company elected to amortize the accumulated post-retirement
benefit obligation of $190.6 million existing at the
October 1, 1993 adoption date of this standard, known as
the transition obligation, over a twenty-year period. Effective
January 1, 2004, changes were made to post-retirement
medical benefits that reduced the Companys post-retirement
benefit obligations by $37.9 million as of
September 30, 2003.
Certain subsidiaries of the Company offer
defined-contribution savings plans to eligible employees,
covering all employee groups. These plans allow participants to
defer on a pre-tax or after-tax basis, a portion of their
salaries for investment in various alternatives. The Company
makes matching contributions to the amounts contributed by
employees in accordance with the specific plan provisions. The
Companys contributions to the plans were $3.0 million
during both fiscal years 2004 and 2003, and $2.9 million
during fiscal year 2002.
The Company uses a measurement date of
September 30 for its pension, and retiree healthcare and
life insurance benefit plans.
85
The following tables provide certain information
about the Companys post-retirement benefits:
The Companys Accumulated Benefit Obligation
(ABO) for its qualified pension plan was
$574.5 million at September 30, 2004 and
$527.8 million at September 30, 2003. The projected
benefit obligation and ABO for the Companys non-funded
SERP, which had accumulated benefits in excess of plan assets,
were $24.4 million and $20.5 million, respectively, as
of September 30, 2004, and $21.8 million and
$19.8 million, respectively, as of September 30, 2003.
The SERP is reflected in the table above and has no assets.
As of September 30, 2003, the Company had
recorded a minimum pension obligation of $5.3 million
related to the SERP, with corresponding amounts recorded to
Regulatory assets Other of $4.2 million
and Accumulated other comprehensive loss of
$1.1 million (before income taxes). This accounting
treatment reflected the Companys
86
belief that a significant portion of this
obligation ultimately would be recovered through future rates in
certain jurisdictions. During fiscal year 2004, the Company
discontinued regulatory accounting treatment related to the
SERP. At September 30, 2004, the Company had recorded a
minimum pension obligation of $4.6 million related to the
SERP, with corresponding amounts recorded to an intangible asset
of $2.2 million included in Deferred charges and
other assets Other and $2.4 million recorded to
Accumulated other comprehensive loss.
The pre-tax amounts included in other
comprehensive loss due to the increase in the minimum pension
obligation related to the SERP were $1.3 million ($753,000
after income taxes) and $1.1 million ($716,000 after income
taxes) for the fiscal years ended September 30, 2004 and
2003.
Assets under the Companys post-retirement
benefit plans are valued using a method designed to spread
realized and unrealized gains and losses over a period of five
years. Each year, 20 percent of the prior five years
asset gains and losses are recognized. The market-related value
of assets is set equal to the market value of assets less the
following percentages of prior years realized and
unrealized gains and losses on equities: 80 percent of
prior year, 60 percent of the second prior year,
40 percent of the third prior year and 20 percent of
the fourth prior year.
The Company employs a total return investment
approach whereby a mix of equities and fixed income investments
can be used to maximize the long-term return of plan assets for
a prudent level of risk. The intent of this strategy is to
minimize plan expenses by outperforming plan liabilities over
the long run. Risk tolerance is established through careful
consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio can
contain a diversified blend of equity and fixed income
investments. Investment risk is measured and monitored on an
ongoing basis through annual liability measurements, periodic
asset/liability studies, and quarterly investment portfolio
reviews.
The asset allocations for the qualified pension
plan and healthcare and life insurance benefit trusts as of
September 30, 2004 and 2003 and the weighted average target
asset allocations as of September 30, 2004, by asset
category, are as follows:
Expected benefit payments, including benefits
attributable to estimated future employee service, which are
expected to be paid over the next ten years are as follows:
87
During fiscal year 2005, the Company does not
expect to make any contributions related to its qualified
pension plan. The Company expects to make payments totaling
$1.3 million in fiscal year 2005 to participants in its non-funded SERP.
The Company expects to contribute
$34.0 million to its health and life insurance benefit plan
during fiscal year 2005.
As discussed in Note 1
Accounting
Policies
, the Company implemented FSP No. 106-2 in June
2004, to account for the impact of the Medicare subsidy on the
Companys post-retirement benefits costs.
The implementation of FSP No. 106-2 resulted
in a $33.8 million reduction in the APBO, and was accounted
for as an actuarial gain as required by the FSP. The table below
reflects the effects of the Medicare subsidy on the components
of net periodic benefits cost related to the Companys
healthcare and life insurance benefit plans for the year ended
September 30, 2004.
88
Expected receipts attributable to the Medicare
subsidy to be received over the next ten years are as follows:
The weighted average assumptions used to
determine net periodic benefit obligations and net periodic
benefit costs were as follows:
The Company determines the expected long-term
rate of return by averaging the expected earnings for the target
asset portfolio. In developing the Companys expected rate
of return assumption, the Company evaluates an analysis of
historical actual performance and long-term return projections,
which gives consideration to the Companys asset mix and
anticipated length of obligation of the plan.
The Company has assumed the initial healthcare
cost trend rates related to the APBO at September 30, 2004
for Medicare and non-Medicare eligible retirees to be
12.0 percent and 10.0 percent, respectively. 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.
The assumed healthcare trend rate has a
significant effect on the amounts reported for the healthcare
plans. A one percentage-point change in the assumed healthcare
trend rate would have the following effects:
A significant portion of the estimated
post-retirement medical and life insurance benefits apply to the
Companys regulated activities.
89
The Public Service Commission of the District of
Columbia (PSC of DC) granted the recovery of post-retirement
medical and life insurance benefit costs determined in
accordance with GAAP through a five-year phase-in plan that
ended September 30, 1998. The regulated utility deferred
the difference generated during the phase-in period as a
regulatory asset. Effective October 1, 1998, the PSC of DC
granted the regulated utility full recovery of costs determined
under GAAP, plus a fifteen-year amortization of the regulatory
asset established during the phase-in period.
On September 28, 1995, the State Corporation
Commission of Virginia (SCC of VA) issued a generic order that
allowed the regulated utility to recover most costs determined
under GAAP in rates over twenty years. The SCC of VA, however,
set a forty-year recovery period of the transition obligation.
As prescribed by GAAP, the regulated utility amortizes these
costs over a twenty-year period.
The Public Service Commission of Maryland (PSC of
MD) has not rendered a decision that specifically addresses
recovery of post-retirement medical and life insurance benefit
costs determined in accordance with GAAP. However, the PSC of MD
has approved a level of rates sufficient to recover the costs
determined under GAAP.
Post-retirement medical and life insurance
benefit costs deferred as a regulatory asset at
September 30, 2004 and 2003 were $6.4 million and
$6.6 million, respectively. The regulated utility expects
that these costs will be recovered over a twenty-year period
that began October 1, 1993.
Each regulatory commission having jurisdiction
over the regulated utility requires it to fund amounts reflected
in rates for post-retirement medical and life insurance benefits
to irrevocable trusts. The expected long-term rate of return on
the assets in the trusts was 7.25 percent for fiscal year
2004, and 8.25 percent for fiscal years 2003 and 2002. The
regulated utility assumes a 39.7 percent income tax rate to
compute taxes on the taxable portion of the income in the trusts.
12. STOCK-BASED COMPENSATION
The Company and its subsidiaries periodically
provide compensation in the form of common stock to certain
employees and Company directors. As permitted by SFAS
No. 123, as amended by SFAS No. 148, the Company
applies APB No. 25, and related interpretations in
accounting for its stock-based compensation plans. The
stock-based compensation arrangements are discussed more fully
below.
STOCK-BASED
COMPENSATION FOR KEY EMPLOYEES
The Company has granted restricted stock to
participants in the Long-Term Incentive Compensation Plan
(LTICP) and to certain other employees. These shares have
restrictions on vesting, sale and transferability. Restrictions
lapse with the passage of time. The Company holds the
certificates for restricted stock until the shares fully vest.
In the interim, the participants receive full dividend and
voting rights. The LTICP expired on June 27, 1999, and was
replaced with the 1999 Incentive Compensation Plan
(1999 Plan).
Approved by the shareholders in February 1999 and
amended in March 2003, the 1999 Plan allows the Company to grant
up to 2,000,000 shares of unrestricted common stock to officers
and key employees. Under the 1999 Plan, the Company may impose
performance goals, which if unattained, may result in
participants forfeiting all or part of the award. Performance
shares granted under the 1999 Plan currently vest over
36 months from the date of grant. At the end of the
associated vesting period, the issuance of any performance
shares depends upon the Companys achievement of
performance goals for total shareholder return relative to a
selected peer group.
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In accordance with APB No. 25, the Company
recognizes estimated compensation expense for restricted stock
and performance shares ratably over the shares vesting
periods. The following table discloses the number of shares
granted and outstanding under the LTICP and 1999 Plan, as well
as the associated weighted average fair value at grant dates and
compensation expense recognized during each reporting period.
STOCK OPTIONS
OUTSTANDING AND OTHER INFORMATION
Since stock options are granted at the fair
market value of the Companys stock on the grant dates, no
compensation expense is recognized. The Companys stock
options generally have a vesting period of three years, and
expire ten years from the date of grant.
The following table summarizes information
regarding option activity under the 1999 Plan for fiscal years
2004, 2003 and 2002.
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The following table summarizes stock options
outstanding and exercisable at September 30, 2004.
The fair value of each option grant was estimated
on the date of grant using the Black-Scholes option-pricing
model, with the following assumptions:
STOCK GRANTS TO DIRECTORS
Non-employee directors receive a portion of their
annual retainer fee in the form of common stock through the
Directors Stock Compensation Plan. Up to 120,000 shares of
common stock may be awarded under the plan. Shares granted to
directors totaled 8,000, 7,500 and 5,600 for fiscal years 2004,
2003 and 2002, respectively. For those periods, the fair value
of the stock on the grant dates was $28.02, $24.89 and $29.18,
respectively. Shares awarded to the participants:
(i)
vest immediately and cannot be forfeited;
(ii)
may be sold or transferred; and
(iii)
have voting and dividend rights.
13. 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:
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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. Washington Gas is working with the owner of the
affected adjoining property to adopt a remediation plan for that
portion of the site.
At a second former MGP site and on an adjacent
parcel of land, Washington Gas made application under a state
voluntary closure program. Washington Gas developed a
monitoring-only remediation plan for the site for
which it received state approval during fiscal year 2004.
Accordingly, the Company reduced its liability in fiscal year
2004 for estimated environmental response costs related to this
matter.
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.
At September 30, 2004 and 2003, Washington
Gas had a liability of $5.6 million and $6.8 million,
respectively, on an undiscounted basis related to future
environmental response costs, which included the estimated costs
for the ten MGP sites. These estimates principally include the
minimum liabilities associated with a range of environmental
response costs expected to be incurred at the sites identified.
At September 30, 2004 and 2003, Washington Gas estimated
the maximum liability associated with all of its sites to be
approximately $12.8 million and $14.9 million,
respectively. The estimates were determined by Washington
Gas environmental experts, based on experience in
remediating MGP sites and advice from legal counsel and
environmental consultants. Variations within the range of
estimated liability result primarily from differences in the
number of years that will be required to perform environmental
response processes at each site and the extent of remediation
that may be required.
Regulatory orders issued by the PSC of MD allow
Washington Gas to recover the costs associated with the sites
applicable to Maryland over periods ranging from five to thirty
years. Rate orders issued by the PSC of DC allow Washington Gas
a three-year recovery of prudently incurred environmental
response costs, and allow Washington Gas to defer additional
costs incurred between rate cases. Regulatory orders from the
SCC of VA have generally allowed the recovery of prudent
environmental remediation costs to the extent they were included
in a test year.
At September 30, 2004 and 2003, Washington
Gas reported a regulatory asset of $2.6 million and
$4.3 million, respectively, for the portion of
environmental response costs it believes are recoverable in
future rates. Washington Gas does not expect that the ultimate
impact of these matters will have a material adverse effect on
its financial statements.
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14. COMMITMENTS AND
CONTINGENCIES
OPERATING LEASES
Minimum future rental payments under operating
leases over the next five years and thereafter are as follows:
Rent expense totaled $3.8 million,
$1.8 million and $809,000 in fiscal years ended
September 30, 2004, 2003 and 2002, respectively.
REGULATED UTILITY
OPERATIONS
Natural Gas Contracts Minimum Commitments
At September 30, 2004, Washington Gas had
service agreements with four pipeline companies that provided
direct service for firm transportation and/or storage services.
These agreements, which have expiration dates ranging from
fiscal years 2005 to 2024, require Washington Gas to pay fixed
charges each month. As of September 30, 2004, based on
current estimates of growth of the Washington Gas system,
together with current expectations of the timing and extent of
unbundling initiatives in the Washington Gas service territory,
the minimum aggregate amount of required payments under the
pipeline service agreements total approximately
$848.1 million for contracts in effect through fiscal year
2024. The SCC of VA has approved mandatory assignment of firm
transportation to third-party marketers. The issue recently was
rejected in the District of Columbia and Maryland; however, the
issue can be brought up in a subsequent proceeding.
The following table summarizes the contract
minimum payments that Washington Gas will make under its
pipeline transportation contracts during the next five fiscal
years and thereafter.
When a customer selects a third-party marketer to
provide supply, Washington Gas generally assigns pipeline and
storage capacity to third-party marketers to deliver gas to
Washington Gas city gate. If a customer does not select a
third-party marketer, Washington Gas has a commodity acquisition
plan to acquire the natural gas supply to serve the customer.
94
In connection with this plan, Washington Gas
utilizes an asset manager to acquire the necessary supply to
serve these customers. Washington Gas commitment to the
asset manager is to purchase gas supply at market prices that
are tied to various public indices for natural gas. The contract
commitment is related to customer demand, and there are no
minimum bill commitments. Additionally, Washington Gas enters
into long-term purchase commitments to purchase fixed volumes of
natural gas at variable prices, and there are no minimum bill
commitments. Accordingly, there are no amounts included in the
table above related to asset manager and long-term natural gas
purchase commitments.
Currently, Washington Gas recovers its cost of
gas through the purchased gas cost recovery mechanisms included
in its retail rate schedules in each of its jurisdictions.
However, the timing and extent of Washington Gas
initiatives or regulatory requirements to separate the purchase
and sale of natural gas from the delivery of gas could cause its
gas supply commitments to be in excess of its continued sales
obligations.
Washington Gas has rate provisions in each of its
jurisdictions that would allow it to continue to recover
potential excess commitments in rates. The regulated utility
also actively manages its supply portfolio to ensure its sales
and supply obligations remain balanced. This reduces the
likelihood that the contracted supply commitments would exceed
supply obligations. However, to the extent Washington Gas were
to determine that changes in regulation would cause it to
discontinue recovery of these costs in rates, the regulated
utility would be required to charge these costs to expense
without any corresponding revenue recovery. If this occurred,
depending upon the timing of the occurrence, the related impact
on the Companys financial position and results of
operations would likely be significant.
Rate
Case Contingencies
Certain legal and administrative proceedings,
incidental to the Companys business, including rate case
contingencies, involve WGL Holdings and/or its subsidiaries. In
the opinion of management, the Company has recorded an adequate
provision for probable losses or refunds to customers for rate
case contingencies related to these proceedings in accordance
with SFAS No. 5,
Accounting for Contingencies
.
District
of Columbia Jurisdiction
In a March 28, 2003 Final Order, the PSC of
DC upheld a previous ruling that approved a methodology for
sharing with customers 50 percent of asset management
revenues previously received by Washington Gas. As part of this
ruling, the PSC of DC also approved a methodology for sharing
with customers 50 percent of annual ground lease and development
fees that Washington Gas received from Maritime Plaza, a
commercial development project constructed on land owned by
Washington Gas. The rates approved by the PSC of DC reflect
annual sharing of this income with customers totaling $15,000.
On May 23, 2003, the District of Columbia Office of the
Peoples Counsel (DC OPC) filed an appeal with the District
of Columbia Court of Appeals (DC Court of Appeals) seeking to
overturn these two portions of the March 28, 2003 ruling by
the PSC of DC. On March 18, 2004, the DC Court of Appeals
affirmed the PSC of DCs March 28, 2003 ruling with
respect to the treatment of Washington Gas asset
management revenues. Furthermore, the DC Court of Appeals
ordered 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 on this matter of the allocation. On
October 12, 2004, Washington Gas filed testimony before the
PSC of DC that supports the allocation methodology that was
approved in the PSC of DCs 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. Management cannot predict the outcome of this matter.
Virginia
Jurisdiction
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 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. Under the regulations of the SCC of VA,
Washington
95
Gas placed the proposed general revenue increase
into effect on November 12, 2002, subject to refund,
pending the SCC of VAs 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
managements judgment of the rate case outcome.
On December 18, 2003, the SCC of VA issued a
Final Order in this proceeding which 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 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 the quarter ended December 31, 2003 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 VAs 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. This annual earnings test
shall 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. During fiscal year ended
September 30, 2004, Washington Gas recorded additional
depreciation expense of $1.0 million in connection with earnings
tests performed. The amount recorded could change if the SCC of
VA differs with managements calculations or methodology.
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 VAs final decision in the proceeding.
96
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.
Under the Stipulation, Washington Gas will not
change its annual base revenues, and will maintain the allowed
rate of return on common equity of 10.50 percent and the
overall rate of return of 8.44 percent as approved by the
December 18, 2003 Final Order as previously discussed.
Refunds to customers, with interest, are being made during the
December 2004 billing cycle for the amount of the proposed
annual revenue increase that has been collected since
February 26, 2004. Based on the terms of the Stipulation,
the Company implemented billing rates commencing October 4,
2004 that reflect the level of annual revenues determined in the
December 18, 2003 Final Order, and implemented the agreed
upon changes in rate design that are contained in the
Stipulation.
The Stipulation provides for a one-time credit to
all Virginia customers of $3.2 million for certain
liabilities that were previously recorded by Washington Gas.
This one-time credit will be made to customers during the
January 2005 billing cycle. Providing this credit to customers
does not have an effect on earnings of Washington Gas. Under the
Stipulation, Washington Gas is required to file with the SCC of
VA, on or before December 27, 2004, an earnings test
calculation for the twelve-month period ended December 31,
2003. Future annual earnings test calculations will be estimated
by the Company quarterly, and when appropriate, accounting
adjustments will be recorded.
The Companys financial results for the nine
months ended June 30, 2004 reflected a provision for rate
refunds to customers based on the difference between the amount
the Company had collected in rates subject to refund through
June 30, 2004, and the amount that the Company had expected
to be realized from the final outcome of the rate case filed in
January 2004, based on managements judgment at that time.
The amount of the proposed revenue increase that had been
included in net income for the nine months ended June 30,
2004, after considering the provision for rate refunds, was
$2.2 million (pre-tax). After taking into consideration the Stipulation discussed
above, Washington Gas increased its provision for rate refunds
in the quarter ended September 30, 2004 to the full amount
of revenues that had been collected subject to refund through
the fiscal year ended September 30, 2004. The increased
provision eliminated the $2.2 million of pre-tax income that was previously included in net income for the nine months
ended June 30, 2004. After the additional provision for
rate refunds was recorded in the quarter ended
September 30, 2004, there was no effect on fiscal year
2004, nor will there be any effect on fiscal year 2005 earnings for the rates initially put into effect in February 2004.
NON-UTILITY
OPERATIONS
Natural Gas
WGEServices has contracts to purchase natural gas
with terms of up to 30 months. WGEServices designs its
purchase contracts to match the duration of its sales
commitments and effectively to lock in a margin on estimated gas
sales over the terms of existing sales contracts. Gas purchase
commitments disclosed below are based on existing fixed-price
purchase commitments using city gate equivalent deliveries, the
majority of which are for fixed volumes.
Electricity
WGEServices owns no electric generation assets,
and receives its electric supply to serve its retail customers
under full requirements supply contracts. WGEServices
principal supplier of electricity is Mirant Americas Energy
Marketing L.P. (MAEM), a wholly owned subsidiary of Mirant
Americas, Inc., which is a wholly owned subsidiary of
Mirant Corporation (Mirant). WGEServices purchases full
requirements services from MAEM, including electric energy,
capacity and certain ancillary services, and then resells it to
retail electric customers in the District of Columbia and
Maryland. As a result, WGEServices has no open position on its
electric supply contracts at September 30, 2004. Electric
commitments are based on customer usage, and the range of the
commitment could extend from zero to the full amount used by
customers. The Company has no fixed commitment to purchase
electricity. Therefore, no commitment for electricity is shown
in the table below.
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The following table summarizes the contractual
obligations and minimum commitments of WGEServices at
September 30, 2004.
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 was included in these bankruptcy filings. Future
performance by MAEM may be subject to further developments in
the bankruptcy proceedings. The performance risk associated with
the pre-bankruptcy petition MAEM contracts is mitigated through
a Security and Escrow agreement entered into between WGEServices
and MAEM prior to the bankruptcy filing. Under the Security and
Escrow agreement, WGEServices has access to collateral that is
intended to cover the difference between the current market
price of electricity and the price at which WGEServices has
contracted to buy electricity. In the opinion of counsel to the
Company, WGEServices has the contractual right to draw on the
escrow funds in the account (which totaled $3.0 million and
$30.0 million as of September 30, 2004 and 2003,
respectively) if the pre-bankruptcy petition contracts between
WGEServices and MAEM are terminated. The amount of
WGEServices exposure in the event of termination of these
contracts between WGEServices and MAEM is estimated to be less
than the amount of collateral included in the escrow account.
This estimate of WGEServices exposure to contract
termination is based upon acquiring supply, priced at forward
electricity prices through the expiration of the existing sales
contracts or until WGEServices exercises certain damage
limitation provisions of its customers sales contracts.
The actual exposure for WGEServices may differ from the estimate
due to changes in timing of any contract termination, deviations
from normal weather, changes in future market conditions, or
other factors.
Since the bankruptcy filing, MAEM has continued
to honor its supply obligations to WGEServices. All obligations
to WGEServices under the pre-bankruptcy petition MAEM contracts
expire by the end of October 2005, with the majority of these
obligations expiring by December 2004. In October 2003,
WGEServices and MAEM signed a post-bankruptcy petition contract
that enables WGEServices to renew expiring contracts with its
current electric customers and to make purchases for new
customers. These post-bankruptcy petition contracts include
provisions that allow WGEServices to net payables to MAEM
against any damages that might result from default on the part
of MAEM, and allow WGEServices to request collateral under
certain situations.
Transfers
and Servicing of Financial Assets and Extinguishment of
Liabilities
The Companys unregulated consumer financing
business previously had extended credit to certain residential
and small commercial customers to purchase gas appliances and
other energy-related products. The Companys unregulated
consumer financing business transferred with recourse certain of
these accounts receivable to commercial banks.
In September 2001, the Company scaled back its
consumer financing operation. The Company stopped financing new
loans, but expects to continue servicing existing loans until
they are fully amortized by the end of fiscal year 2005 or the
beginning of fiscal year 2006. In May 2002, the Company
contracted with a third-party vendor to service the remaining
loans. During fiscal years 2004, 2003 and 2002, there were no
sales of receivables to commercial banks.
98
At September 30, 2004, the Company had loans
totaling $2.5 million, all of which were recorded in the
Companys financial statements. The Company had a $304,000
reserve for uncollectible accounts. Loan repurchases from
commercial banks totaled $3.2 million for both fiscal years
2004 and 2003.
Construction
Project Financing
In October 2000, Washington Gas contracted with
the U.S. General Services Administration (GSA) to construct
certain facilities at the GSA central plant in Washington, D.C.
Payments to Washington Gas for this construction were to be made
by the GSA over a 15-year period. In November 2000, Washington
Gas and General Electric Capital Assurance Company
(GEFA) entered into a long-term financing arrangement,
whereby GEFA funded this construction project. As part of this
financing arrangement, Washington Gas assigned to GEFA the
15-year stream of payments due from the GSA. The amount of this
long-term financing arrangement, including change orders,
origination fees and capitalized finance charges was
$69.4 million. As the long-term financing from GEFA was
funded, Washington Gas established a note receivable
representing the GSAs obligation to remit principal and
interest. Upon completion and acceptance of phases of the
construction project, Washington Gas accounts for the transfer
of the financed asset as an extinguishment of long-term debt and
removes both the note receivable and long-term financing from
its financial statements. As of September 30, 2004,
construction of these facilities was substantially complete.
Work on the construction project that has not been completed or
accepted by the GSA was valued at $15.6 million, which
represents an obligation on Washington Gas Balance Sheet
at September 30, 2004. At any time before the contract with
the GSA is fully accepted, should there be a contract default,
such as, among other things, non-payment by the GSA, GEFA may
call on Washington Gas to fund the entire unpaid principal in
exchange for which Washington Gas would receive the right to the
stream of repayments from the GSA. Once final acceptance by the
GSA is made, GEFA will have no recourse against the Company
related to this long-term debt. As of September 30, 2004,
the GSA had made all required payments under this long-term
financing arrangement, and the remaining unpaid principal
balance was $63.8 million.
In addition to the GSA project described above,
the Company finances other smaller construction projects and
accounts for them using a similar methodology. During fiscal
year 2004, the Company issued an additional $800,000 of debt to
finance such projects. In fiscal year 2003, the Company
eliminated $21.3 million of notes receivable and long-term
debt related to completed projects. The following table details
the activity related to long-term borrowings associated with
construction projects.
Financial
Guarantees
WGL Holdings has guaranteed payments for certain
purchases of natural gas and electricity made by WGEServices. At
September 30, 2004, these guarantees totaled
$218.9 million. Termination of these guarantees is
coincident with the satisfaction of all obligations of
WGEServices covered by the guarantees. WGL Holdings also had
guarantees totaling $6.0 million at September 30, 2004
that were made on behalf of certain of its non-utility
subsidiaries associated with their banking transactions. Of the
total guarantees of $224.9 million, $42.0 million,
$4.0 million and $600,000 are due to expire on
December 31, 2004, June 30, 2006 and February 29,
2008, respectively. The remaining guarantees of
$178.3 million do not have specific maturity dates. For all
of its financial guarantees, WGL Holdings may cancel any or all
future obligations imposed by the guarantees upon written notice
to the counterparty, but WGL Holdings would continue to be
responsible for the obligations that had been created under the
guarantees prior to the effective date of the cancellation.
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15. FAIR VALUE OF FINANCIAL
INSTRUMENTS
The following table presents the carrying amounts
and estimated fair values of the Companys financial
instruments at September 30, 2004 and 2003. The fair value
of a financial instrument represents the amount at which the
instrument could be exchanged in a current transaction between
willing parties. The carrying amount of current assets and
current liabilities approximates fair value because of the
short-term maturity of these instruments, and therefore are not
shown in the table below.
The carrying amount of preferred stock
approximates fair value. The fair value of long-term debt
was estimated based on the quoted market prices of U.S. Treasury issues
having a similar term to maturity, adjusted for Washington
Gas credit quality and the present value of future cash
flows.
16. OPERATING SEGMENT REPORTING
In accordance with SFAS No. 131,
Disclosures about Segments of an Enterprise and Related
Information,
the Company identifies and reports on operating
segments under the management approach. Operating
segments comprise revenue-generating components of an enterprise
for which the Company produces separate financial information
internally that management regularly uses to make operating
decisions and assess performance. The Company reports three
operating segments: 1) regulated utility; 2) retail
energy-marketing and 3) commercial HVAC.
With approximately 93 percent of WGL
Holdings consolidated total assets, the regulated utility
segment is the Companys core business. Represented by
Washington Gas and Hampshire, the regulated utility segment
provides regulated gas distribution services (including the sale
and delivery of natural gas, meter reading, responding to
customer inquiries and bill preparation) to customers primarily
in Washington, D.C. and the surrounding metropolitan areas in
Maryland and Virginia. In addition to the regulated operations
of Washington Gas, the regulated utility segment includes the
operations of Hampshire, an underground natural gas storage
facility that is regulated under a cost of service tariff by the
FERC, and provides services exclusively to Washington Gas.
Through WGEServices, the retail energy-marketing
segment sells natural gas and electricity directly to retail
customers, both inside and outside of Washington Gas
traditional service territory, in competition with unregulated
gas and electricity marketers. Through two wholly owned
subsidiaries, ACI and WGESystems, the commercial HVAC segment designs,
renovates and services mechanical heating, ventilating and air
conditioning systems for commercial and governmental customers.
For fiscal year 2002, the HVAC segment also included the results
of the Companys 50 percent former equity investment
in Primary Investors, an entity that provided HVAC services to
residential customers. The Company terminated its interest in
Primary Investors in October 2002 (refer to Note 2
Disposition of Limited Liability Company
Investment
).
Certain activities of the Company are not
significant enough on a stand-alone basis to warrant treatment
as an operating segment and the activities do not fit into one
of the segments contained in the Companys financial
statements. For purposes of segment reporting, these activities
are aggregated in the category Other Activities of
the Companys non-utility operations as presented below in
the Operating Segment Financial Information. These activities
are included in the Consolidated Statements of Income in the
appropriate lines, revenues and expenses in Non-Utility
Operations.
100
The same accounting policies as those described
in Note 1
Accounting Policies
also apply to
the reported segments. While net income or loss is the primary
criterion for measuring a segments performance, the
Company also evaluates its operating segments based on other
relevant factors, such as penetration into their respective
markets and return on invested capital. The following tables
present operating segment information for fiscal years ended
September 30, 2004, 2003 and 2002.
101
17. TRANSACTIONS BETWEEN WASHINGTON GAS
AND AFFILIATES
Washington Gas and other subsidiaries of WGL
Holdings engage in transactions with each other during the
ordinary course of business. All of these intercompany
transactions and balances have been eliminated from the
consolidated financial statements of WGL Holdings.
Washington Gas provides administrative and
general support to affiliates, such as cash collections and
other services, and has filed tax returns that include
affiliated taxable transactions. The actual costs of these
services are billed to the appropriate affiliates and to the
extent such billings are not yet paid, they are reflected in
Receivables from associated companies on the
Washington Gas Balance Sheets. Cash collected by Washington Gas
on behalf of its affiliates but not yet transferred is recorded
in Payables to associated companies on the
Washington Gas Balance Sheets. Washington Gas does not recognize
revenues or expenses associated with providing these services.
At September 30, 2004 and 2003, the
Washington Gas Balance Sheets reflected a net payable to
associated companies of $18.2 million and
$10.0 million, respectively. All affiliated transactions,
including these balances, were eliminated from the WGL Holdings
Consolidated Balance Sheets in accordance with GAAP.
Additionally, Washington Gas provides gas
balancing services related to storage, injections, withdrawals
and deliveries to all unregulated energy marketers participating
in the sale of natural gas on an unregulated basis through the
customer choice programs that operate in its service territory.
Washington Gas records revenues for these balancing services
pursuant to tariffs approved by the appropriate regulatory
bodies. In conjunction with such services, Washington Gas
charged WGEServices, an affiliated energy marketer,
$25.7 million and $12.0 million for the fiscal years
ended September 30, 2004 and 2003, respectively. These
related party amounts have been eliminated in the consolidated
financial statements of WGL Holdings.
102
WGL Holdings, Inc.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Board of Directors and Shareholders of WGL
Holdings, Inc. and Washington Gas Light Company
We have audited the accompanying consolidated
balance sheets and consolidated statements of capitalization of
WGL Holdings, Inc. and subsidiaries and the separate balance
sheets and statements of capitalization of Washington Gas Light
Company (the Companies) as of September 30, 2004 and 2003,
and the related statements of income, common shareholders
equity, cash flows and income taxes for each of the three years
in the period ended September 30, 2004. Our audits also
included the financial statement schedules listed in the Index
at Item 15 under Schedule II. These financial statements and
financial statement schedules are the responsibility of the
Companies management. Our responsibility is to express an
opinion on the financial statements and financial statement
schedules based on our audits.
We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present
fairly, in all material respects, the consolidated financial
position of WGL Holdings, Inc. and subsidiaries and the
financial position of Washington Gas Light Company as of
September 30, 2004 and 2003, and the respective results of
their operations and their cash flows for each of the three
years in the period ended September 30, 2004 in conformity
with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial
statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present
fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE LLP
McLean, Virginia
103
WGL Holdings, Inc.
SUPPLEMENTARY FINANCIAL INFORMATION
(Unaudited)
QUARTERLY FINANCIAL DATA
The Company believes that all adjustments
necessary for a fair presentation have been included in the
quarterly information provided below. Due to the seasonal nature
of its business, WGL Holdings reports substantial variations in
operations on a quarterly basis.
104
WGL Holdings, Inc.
Glossary of Key Terms
ACI:
American
Combustion Industries, Inc. is a subsidiary of WGL Holdings,
Inc. that provides HVAC-related products and services to
commercial customers.
Active Customer
Meters:
Natural gas meters that are physically
connected to a building structure within the Washington Gas
distribution system and service is active.
Customers are billed for flowing gas and/or fixed charges.
Bcf:
A
measurement standard of natural gas volumes of one billion cubic
feet, or approximately ten million therms.
Book Value Per
Share:
Common shareholders
equity divided by the number of common shares outstanding.
Bundled
Service:
Service in which
customers purchase both the natural gas commodity and the
distribution or delivery of the commodity from the local
regulated utility. When customers purchase bundled service from
Washington Gas, no mark-up is applied to the cost of the natural
gas commodity that is passed through to customers. The regulated
utility has an opportunity to earn a fair rate of return on the
net investment used to deliver natural gas.
City Gate:
A
point or measuring station at which a gas distribution company
such as Washington Gas receives natural gas from a pipeline or
transmission system.
Connected Customer
Meters:
Natural gas meters that are physically
connected to a building structure within the Washington Gas
distribution system, however, service may or may
not be active.
Degree Day
(Heating):
A measure of the
variation in weather based on the extent to which the daily
average temperature falls below 65 degrees Fahrenheit.
Delivery
Service:
The regulated
distribution or delivery of natural gas to retail customers.
Washington Gas provides delivery service to retail customers in
Washington, D.C. and parts of Maryland and Virginia.
Dividend Yield on Book
Value:
Dividends declared per
share divided by book value per share.
Firm
Customers:
Customers whose gas
supply will not be disrupted to meet the needs of other
customers. Typically, this class of customer comprises
residential customers and the vast majority of commercial
customers.
HVAC:
Heating, ventilating and air conditioning products and services.
Interruptible
Customers:
Large commercial
customers whose service can be temporarily interrupted in order
for the regulated utility to meet the needs of firm customers.
These customers pay a lower delivery rate than firm customers
and they must be able to readily substitute an alternate fuel
for natural gas. The effect on net income of any changes in
delivered volumes or prices to the interruptible class is
minimized by margin sharing arrangements in the regulated
utilitys tariffs.
Market-to-Book
Ratio:
Market price of a share of
common stock divided by its book value per share.
Merchant
Function:
The purchase of the
natural gas commodity by the regulated utility on behalf of
retail customers.
New Customer Meters
Added:
Natural gas meters that are
newly connected to a building structure within the Washington Gas
distribution system. Service may or may
not have been activated.
Payout Ratio:
Dividends declared per share divided by basic earnings per share.
PSC of DC:
The Public Service Commission of the District of Columbia is a
three-member board that regulates the utilitys
distribution operations in the District of Columbia.
PSC of MD:
The Public Service Commission of Maryland is a five-member board
that regulates the utilitys distribution operations in
Maryland.
Regulated Utility
Operations:
See Utility Operations.
Retail
Energy-Marketing:
Unregulated
sales of the natural gas and electricity to end users by a
company subsidiary, Washington Gas Energy Services, Inc.
Return on Average Common
Equity:
Net income divided by
average common shareholders equity.
105
SCC of VA:
The State Corporation Commission of Virginia is a three-member
board that regulates the utilitys distribution operations
in Virginia.
Service Area:
The region in which the regulated utility operates. The service
area includes Washington, D.C. and the surrounding
metropolitan areas in Maryland and Virginia.
Tariffs:
Documents issued by the regulatory commission in each
jurisdiction that set the prices the regulated utility may
charge and the practices it must follow when providing utility
service to its utility customers.
Third-Party
Marketer:
Unregulated companies
that sell natural gas and electricity directly to retail
customers. Washington Gas Energy Services, Inc., a subsidiary
company of Washington Gas Resources Corp., is a third-party
marketer.
Therm:
A
natural gas unit of measurement that includes a standard measure
for heating value. The regulated utility reports its natural gas
sales and deliveries in therms. Ten million therms equal
approximately one
billion cubic feet (bcf).
Unbundling:
The separation of the delivery of natural gas or electricity
from the sale of these commodities and related services that, in
the past, were provided only by a regulated utility.
Utility Net
Revenues:
Utility revenues, less
the associated cost of gas and applicable revenue taxes.
Utility
Operations:
The regulated business
that delivers and sells natural gas to retail customers in
Washington, D.C., Maryland and Virginia. Utility operations
are regulated primarily by state regulatory commissions.
Value-At-Risk:
A risk measurement that estimates the largest expected loss over
a specified period of time under normal market conditions within
a specified probabilistic confidence interval.
Washington
Gas:
Washington Gas Light Company
is a subsidiary of WGL Holdings, Inc. that delivers and sells
natural gas primarily to retail customers in accordance with
tariffs set by the District of Columbia, Maryland and Virginia
regulatory commissions.
Washington Gas Resources
Corporation:
Washington Gas
Resources Corp. is a subsidiary of WGL Holdings, Inc. that owns
the majority of the non-utility subsidiaries.
WGEServices:
Washington Gas Energy Services, Inc. is a subsidiary of
Washington Gas Resources Corp. that markets natural gas and
electricity to retail customers on an unregulated basis.
WGESystems:
Washington Gas Energy Systems, Inc., is a subsidiary of
Washington Gas Resources Corp. that offers HVAC-related products
and services to commercial customers.
WGL Holdings:
WGL Holdings, Inc. is a holding company that became the parent
company of Washington Gas Light Company and its subsidiaries
effective November 1, 2000.
Weather
Insurance:
An insurance policy
that provides the regulated utilitys earnings with some
protection from the effects of warmer-than-normal winter weather.
106
WGL Holdings, Inc.
Years Ended September 30,
(In thousands)
2004
2003
2002
$
96,590
$
110,898
$
48,687
90,809
82,866
72,254
4,339
5,030
3,917
30,364
37,165
(3,714
)
(892
)
(893
)
(895
)
(5,198
)
(5,118
)
(14,980
)
(4,138
)
1,769
197
(261
)
(1,910
)
349
6,323
7,531
(3,022
)
56,063
(40,780
)
(55,209
)
40,467
9,340
(10,773
)
8,325
26,003
31,940
(6,735
)
1,091
1,341
(646
)
3,404
(4,436
)
6,825
6,996
(794
)
(1,144
)
(246
)
(281
)
46
(5,608
)
(5,218
)
(3,241
)
(627
)
6,595
4,790
222,975
186,499
216,081
37,800
130,338
(36,109
)
(41,669
)
(42,600
)
(879
)
(418
)
(1,055
)
20,186
(46,527
)
39,521
(73,019
)
(64,065
)
(63,260
)
(62,738
)
(270
)
1,296
282
(110,050
)
(64,530
)
(28,606
)
(112,825
)
(128,468
)
(161,230
)
16,000
(821
)
(8,019
)
(31,145
)
(113,646
)
(120,487
)
(192,375
)
(721
)
1,482
(4,900
)
4,119
2,637
7,537
$
3,398
$
4,119
$
2,637
$
16,665
$
41,706
$
34,867
$
42,352
$
44,608
$
44,326
$
$
19,707
$
9,750
Table of Contents
September 30,
(In thousands, except shares)
2004
2003
$
46,479
$
46,479
452,400
450,813
314,227
281,958
(5
)
(32
)
(1,469
)
(716
)
811,632
56.7
%
778,502
53.9
%
15,000
15,000
7,173
7,173
6,000
6,000
28,173
2.0
%
28,173
2.0
%
20,500
20,500
45,100
45,100
75,000
75,000
24,000
24,000
30,000
30,000
77,000
77,000
67,000
30,000
20,000
20,000
36,000
40,000
40,000
50,000
50,000
125,000
125,000
52,000
52,000
8,500
8,500
634,100
633,100
16,747
16,056
(80
)
(442
)
60,611
12,100
590,156
41.3
%
636,614
44.1
%
$
1,429,961
100.0
%
$
1,443,289
100.0
%
Table of Contents
Accumulated
Common Stock
Other
Issued
Comprehensive
Paid-In
Retained
Deferred
Loss, Net of
(In thousands, except shares)
Shares
Amount
Capital
Earnings
Compensation
Taxes
Total
46,479,536
$
46,479
$
429,050
$
248,632
$
(275
)
$
$
723,886
48,687
48,687
15
15
267
155
422
20,186
20,186
(61,556
)
(61,556
)
(1,320
)
(1,320
)
46,479,536
46,479
449,518
234,443
(120
)
730,320
110,898
110,898
(716
)
(716
)
110,182
1,295
88
1,383
(62,063
)
(62,063
)
(1,320
)
(1,320
)
46,479,536
46,479
450,813
281,958
(32
)
(716
)
778,502
96,590
96,590
(753
)
(753
)
95,837
1,587
27
1,614
(63,001
)
(63,001
)
(1,320
)
(1,320
)
49,479,536
$
46,479
$
452,400
$
314,227
$
(5
)
$
(1,469
)
$
811,632
(a)
Stock-based compensation is based on the stock
awards of WGL Holdings, Inc. that are allocated to Washington
Gas Light Company for its pro-rata share.
Table of Contents
Years Ended September 30,
(In thousands)
2004
2003
2002
$
29,134
$
30,682
$
30,499
28,293
26,955
26,141
355
1,010
(21,243
)
2,623
954
2,419
(976
)
(1,244
)
(722
)
(9
)
10,700
(1,649
)
211
(181
)
9
(527
)
433
(6,296
)
29,970
38,627
(1,341
)
(892
)
(893
)
(895
)
58,212
68,416
28,263
(391
)
(1,130
)
125
519
1,721
(2,387
)
128
591
(2,262
)
(4,671
)
2,343
1,843
(125
)
(3,183
)
14
(4,796
)
(840
)
1,857
$
53,544
$
68,167
$
27,858
Table of Contents
Table of Contents
Property, Plant and Equipment at Original Cost
At September 30,
2004
2003
(In millions)
Dollars
%
Dollars
%
$
2,376.5
89.1
$
2,297.6
89.6
247.5
9.3
229.3
8.9
36.1
1.3
29.4
1.2
2,660.1
99.7
2,556.3
99.7
7.8
0.3
7.6
0.3
$
2,667.9
100.0
$
2,563.9
100.0
Table of Contents
Regulatory Assets and Liabilities
Regulatory
Regulatory
(In millions)
Assets
Liabilities
At September 30,
2004
2003
2004
2003
$
$
$
251.7
$
230.7
18.1
16.6
7.9
9.3
5.9
8.8
7.7
7.1
6.4
6.6
4.1
11.4
7.8
7.6
4.2
5.4
8.1
4.5
1.9
2.6
4.3
5.0
16.1
10.5
2.6
4.3
3.2
2.1
$
66.0
$
74.2
$
281.6
$
260.7
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Pro Forma Effect of Stock Options
Years Ended September 30,
(In thousands, except per share data)
2004
2003
2002
$
96,637
$
112,342
$
39,121
reported
net income, net of tax
(a)
1,225
1,078
528
determined
under the fair value-based method, net of tax
(1,656
)
(1,425
)
(902
)
$
96,206
$
111,995
$
38,747
$
1.99
$
2.31
$
0.81
$
1.98
$
2.31
$
0.80
$
1.98
$
2.30
$
0.80
$
1.97
$
2.30
$
0.80
(a)
Reflects compensation expense related to
performance shares.
Table of Contents
Table of Contents
Table of Contents
Table of Contents
Long-Term Debt Maturities
(a)
(In millions)
MTNs
Other
Total
$
60.5
$
0.1
$
60.6
50.0
0.3
50.3
85.0
0.1
85.1
45.1
0.1
45.2
75.0
0.1
75.1
318.5
16.0
334.5
634.1
16.7
650.8
60.5
0.1
60.6
$
573.6
$
16.6
$
590.2
(a)
Excludes unamortized discounts of $80,000 as
of September 30, 2004.
Table of Contents
Common Stock Reserves
Reserved for:
Number of Shares
1,863,687
376,890
637,196
74,183
2,951,956
(a)
Included are shares that potentially could be
issued and that would reduce the Incentive Compensation Plan
shares authorized. These shares include 940,300 shares dedicated
to incentive stock options issued but not exercised, and 249,566
shares dedicated to performance shares granted but not
vested.
Table of Contents
Preferred Stock
Liquidation Preference
Preferred
Per Share
Series
Shares
Call Price
Outstanding
Outstanding
Involuntary
Voluntary
Per Share
$4.80
150,000
$100
$101
$101
$4.25
70,600
$100
$105
$105
$5.00
60,000
$100
$102
$102
Basic EPS and Diluted EPS
Net
Per Share
(In thousands, except per share data)
Income
Shares
Amount
$
96,637
48,640
$
1.99
207
$
96,637
48,847
$
1.98
$
112,342
48,587
$
2.31
169
$
112,342
48,756
$
2.30
$
39,121
48,563
$
0.81
88
$
39,121
48,651
$
0.80
Table of Contents
Table of Contents
Post-Retirement Benefits
Health and Life
(In millions)
Pension Benefits
Benefits
Years Ended September 30,
2004
2003
2004
2003
$
615.9
$
567.1
$
361.2
$
322.9
10.3
9.2
8.6
8.0
36.1
35.9
19.8
20.5
(37.9
)
27.6
35.6
36.5
62.7
(34.1
)
(31.9
)
(17.6
)
(15.0
)
$
655.8
$
615.9
$
408.5
$
361.2
$
661.5
$
611.2
$
163.5
$
147.3
56.8
83.1
2.2
2.8
1.2
1.2
27.0
28.4
(2.3
)
(2.1
)
(34.1
)
(31.9
)
(17.6
)
(15.0
)
$
683.1
$
661.5
$
175.1
$
163.5
$
27.3
$
45.6
$
(233.4
)
$
(197.7
)
13.2
(11.3
)
166.3
124.3
15.5
17.8
0.2
51.7
57.4
$
56.0
$
52.3
$
(15.4
)
$
(16.0
)
Table of Contents
Post-Retirement Investment Allocations
Pension Benefits
Health and Life Benefits
Target
Actual
Target
Actual
Allocation
Allocation
Allocation
Allocation
At September 30,
2004
2004
2003
2004
2004
2003
50
%
50
%
51
%
50
%
4
%
50
%
50
%
49
%
50
%
96
%
100
%
100
%
100
%
100
%
100
%
100
%
100
%
(a)
None of the Companys common stock is
included in its plans.
Expected Benefit Payments
Pension
Health and Life
(In millions)
Benefits
Benefits
$
34.3
$
17.3
35.0
18.8
36.2
20.4
37.4
22.0
38.6
23.5
218.4
141.2
Table of Contents
Components of Net Periodic Benefit Costs (Income)
(In millions)
Pension Benefits
Health and Life Benefits
Years Ended September 30,
2004
2003
2002
2004
2003
2002
$
10.4
$
9.2
$
8.1
$
8.6
$
8.0
$
6.1
36.1
35.9
35.5
19.8
20.6
18.3
(52.3
)
(54.0
)
(55.8
)
(12.1
)
(11.4
)
(10.2
)
2.3
2.3
2.3
0.9
0.5
(6.5
)
4.1
1.1
0.2
0.2
(0.9
)
5.7
9.5
9.5
(2.4
)
(5.9
)
(17.3
)
26.1
27.8
23.7
0.7
1.5
4.4
(4.7
)
(5.8
)
(4.2
)
(2.7
)
0.8
3.4
0.2
0.6
1.4
$
(4.4
)
$
(3.6
)
$
(9.5
)
$
21.6
$
22.6
$
20.9
Effect of Medicare Subsidy on Components of Net Periodic Benefit Costs
Health and Life
(In millions)
Benefits
Year Ended September 30,
2004
$
(0.6
)
(1.5
)
(2.0
)
(4.1
)
0.7
0.7
$
(2.7
)
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Medicare Subsidy Receipts
Health and Life
(In millions)
Benefits
$
0.9
1.4
1.6
1.7
10.6
Net Periodic Benefit Obligations Assumptions
Pension Benefits
Health and Life Benefits
Years Ended September 30,
2004
2003
2004
2003
5.75
%
6.00
%
5.75
%
6.00
%
4.00
%
4.00
%
4.00
%
4.00
%
Net Periodic Benefit Cost Assumptions
Pension Benefits
Health and Life Benefits
Years Ended September 30,
2004
2003
2002
2004
2003
2002
6.00
%
6.50
%
7.25
%
6.00
%
6.50
%
7.25
%
8.25
%
8.50
%
8.50
%
7.25
%
8.25
%
8.25
%
4.00
%
4.00
%
4.00
%
4.00
%
4.00
%
4.00
%
Healthcare Trends
One Percentage-Point
One Percentage-Point
(In millions)
Increase
Decrease
$
5.4
$
(4.2
)
$
63.3
$
(50.6
)
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Schedule of LTICP and 1999 Plan Shares Outstanding
Long-Term Incentive
Compensation Plan
1999 Plan
Years Ended September 30,
2004
2003
2002
2004
2003
2002
2,400
8,300
16,470
181,533
117,088
107,071
107,236
91,232
64,105
(1,200
)
(5,900
)
(8,170
)
(28,706
)
(26,787
)
(40,332
)
(10,497
)
(13,756
)
1,200
2,400
8,300
249,566
181,533
117,088
$
$
$
$
27.58
$
23.91
$
26.89
$
22,125
$
83,119
$
150,000
$
1,862,320
$
1,574,594
$
662,836
Stock Option Activity
Years Ended September 30,
2004
2003
2002
Weighted
Weighted
Weighted
Number
Average
Number
Average
Number
Average
of
Exercise
of
Exercise
of
Exercise
Options
Price
Options
Price
Options
Price
615,384
$
25.24
411,836
$
26.00
271,604
$
25.41
343,850
27.58
238,424
23.90
156,698
27.02
(18,934
)
23.71
(28,826
)
25.14
(6,050
)
24.06
(16,466
)
25.96
940,300
$
26.13
615,384
$
25.24
411,836
$
26.00
376,253
$
26.21
224,509
$
25.56
152,743
$
24.74
Table of Contents
Stock Options as of September 30, 2004
Options Outstanding
Options Exercisable
Weighted
Weighted
Average
Weighted
Average
Remaining
Average
Options
Exercise
Contractual
Options
Exercise
Range of Exercise Prices
Outstanding
Price
Life
(a)
Exercisable
Price
300,011
$
23.67
7.2
69,558
$
22.92
640,289
$
27.28
7.5
306,695
$
26.96
940,300
$
26.13
7.4
376,253
$
26.21
(a)
Weighted average remaining contractual life in
years.
Fair Market Value Assumptions (Black-Scholes Model)
2004
2003
2002
4.6
%
5.3
%
5.3
%
19.04
%
21.55
%
24.0
%
0.94
%
1.58
%
6.3
%
3 years
3 years
3 years
$2.26
$2.13
$4.41
the complexity of the site;
changes in environmental laws and regulations at
the federal, state and local levels;
the number of regulatory agencies or other
parties involved;
new technology that renders previous technology
obsolete or experience with existing technology that proves
ineffective;
the ultimate selection of technology;
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the level of remediation required; and
variations between the estimated and actual
period of time that must be dedicated to respond to an
environmentally-contaminated site.
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Minimum Payments Under Operating Leases
(In millions)
$
4.1
4.2
4.2
4.2
3.8
29.1
$
49.6
Washington Gas Contract Minimums
(In millions)
Pipeline contracts
$
135.1
116.8
104.9
85.1
60.6
345.6
$
848.1
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WGEServices Contract Minimums
Gas purchase
Pipeline
(In millions)
Commitments
(a)
Contracts
Total
$
134.4
$
1.7
$
136.1
16.0
0.1
16.1
2.3
0.1
2.4
$
152.7
$
1.9
$
154.6
(a)
Represents fixed price commitments with city
gate equivalent deliveries.
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Debt Activity Related to Construction Projects
(In millions)
2004
2003
$
15.6
$
36.9
0.8
(21.3
)
$
16.4
$
15.6
(a)
Includes the non-cash extinguishment of
project debt financing of $19.7 million for fiscal year
2003.
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Fair Value of Financial Instruments
At September 30,
2004
2003
Carrying
Fair
Carrying
Fair
(In millions)
Amount
Value
Amount
Value
$
28.2
$
28.2
$
28.2
$
28.2
$
590.2
$
646.6
$
637.1
$
722.9
(a)
Excludes current maturities and unamortized discounts.
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Operating Segment Financial Information
Non-Utility Operations
Regulated
Retail Energy-
Other
Eliminations/
(In thousands)
Utility
Marketing
HVAC
Activities
(a)
Total
Other
Consolidated
$
1,293,675
$
789,859
$
30,123
$
1,673
$
821,655
$
(25,727
)
$
2,089,603
91,510
218
135
43
396
91,906
1,008,013
775,882
36,114
3,836
815,832
(25,727
)
1,798,118
58,463
4,924
(2,077
)
(672
)
2,175
60,638
1,157,986
781,024
34,172
3,207
818,403
(25,727
)
1,950,662
135,689
8,835
(4,049
)
(1,534
)
3,252
138,941
43,141
714
12
978
1,704
(700
)
44,145
Other Non-Operating Income
(Expense)
(c)
(2,277
)
159
(1,335
)
7,314
6,138
(700
)
3,161
Dividends on Washington Gas
Preferred Stock
1,320
1,320
$
88,951
$
8,280
$
(5,396
)
$
4,802
$
7,686
$
$
96,637
$
2,333,114
$
152,816
$
24,281
$
86,680
$
263,777
$
(91,983
)
$
2,504,908
$
113,225
$
56
$
158
$
$
214
$
$
113,439
Total Revenues
$
1,313,041
$
726,231
$
35,521
$
1,439
$
763,191
$
(11,984
)
$
2,064,248
83,549
(64
)
134
625
695
84,244
1,003,106
719,459
37,539
3,847
760,845
(11,984
)
1,751,967
68,633
2,521
(960
)
(1,393
)
168
68,801
1,155,288
721,916
36,713
3,079
761,708
(11,984
)
1,905,012
157,753
4,315
(1,192
)
(1,640
)
1,483
159,236
45,563
581
16
669
1,266
(448
)
46,381
Other Non-Operating Income (Expense)
(c)
(1,834
)
11
24
3,054
3,089
(448
)
807
Dividends on Washington Gas Preferred Stock
1,320
1,320
$
109,036
$
3,745
$
(1,184
)
$
745
$
3,306
$
$
112,342
$
2,257,787
$
141,421
$
23,053
$
114,027
$
278,501
$
(100,236
)
$
2,436,052
$
129,003
$
8
$
72
$
$
80
$
$
129,083
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Operating Segment Financial Information
Non-Utility Operations
Regulated
Retail Energy-
Other
Eliminations/
(In thousands)
Utility
Marketing
HVAC
Activities
(a)
Total
Other
Consolidated
$
938,804
$
595,866
$
61,887
$
1,918
$
659,671
$
(13,673
)
$
1,584,802
72,921
430
675
483
1,588
74,509
739,761
587,633
53,591
11,761
652,985
(13,673
)
1,379,073
28,596
1,931
1,527
(1,733
)
1,725
105
30,426
841,278
589,994
55,793
10,511
656,298
(13,568
)
1,484,008
(5,402
)
(5,402
)
(5,402
)
(9,431
)
(9,431
)
(9,431
)
97,526
5,872
(8,739
)
(8,593
)
(11,460
)
(105
)
85,961
45,312
912
335
795
2,042
(1,477
)
45,877
Other Non-Operating Income (Expense)
(c)
827
7
117
778
902
(1,372
)
357
Dividends on Washington Gas Preferred Stock
1,320
1,320
$
51,721
$
4,967
$
(8,957
)
$
(8,610
)
$
(12,600
)
$
$
39,121
$
2,177,713
$
128,127
$
25,591
$
73,672
$
227,390
$
(65,957
)
$
2,339,146
$
161,645
$
433
$
4,313
$
(108
)
$
4,638
$
$
166,283
(a)
2004 includes an after-tax gain of
$5.8 million from the sale of an interest in two buildings
by a third party in a commercial development project in which
the Company held a carried interest.
(b)
Includes cost of gas and revenue
taxes.
(c)
Amounts reported are net of applicable income
taxes.
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Quarter Ended
(In thousands, except per share data)
December 31
(a)
March 31
(b)
June 30
(c)
September 30
(d)
$
585,289
$
862,252
$
356,852
$
285,210
52,384
84,755
7,553
(5,751
)
39,543
79,232
(4,128
)
(18,010
)
0.81
1.63
(0.08
)
(0.37
)
0.81
1.62
(0.08
)
(0.37
)
$
560,022
$
851,073
$
373,155
$
279,998
63,137
92,955
9,283
(6,139
)
51,622
80,963
(2,640
)
(17,603
)
1.06
1.67
(0.05
)
(0.36
)
1.06
1.66
(0.05
)
(0.36
)
(a)
Quarter ended December 31, 2003 included
additional 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, in
connection with a December 18, 2003 Virginia rate order.
(b)
Quarter ended March 31, 2004 included
after tax-earnings of $5.8 million, or $0.12 per share,
from the sale, by an unrelated third party, of two buildings at
Maritime Plaza, a commercial development project in which the
Company held a carried interest under the equity method of
accounting, and quarter ended March 31, 2003 included an
after-tax gain of $2.5 million, or $0.05 per share, from
the sale of the Companys Washington D.C. headquarters
property. The results for the quarter ended March 31, 2004
reflect the following restatement due to the implementation of
FSP No. 106-2 in the third quarter of fiscal year
2004:
Effect of
(In thousands, except per share data)
Reported
Subsidy
Restated
$
78,055
$
1,177
$
79,232
1.60
0.03
1.63
1.60
0.02
1.62
(c)
Quarter ended June 30, 2003 included a
reduction in income taxes of $2.1 million, or $0.04 per
share, due to the realization of tax benefits of capital loss
carryforwards.
(d)
Quarter ended September 30, 2004 included
a $1.3 million after-tax, or $0.03 per share, decrease in
revenues related to the provision for rate refunds in Virginia,
as well as a $1.5 million charge, or $0.03 per share, for
the impairment of goodwill related to the Companys
investment in its HVAC business.
(e)
The sum of quarterly per share amounts may not
equal annual per share amounts as the quarterly calculations are
based on varying numbers of common shares.
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ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Senior management, including the Chairman and Chief Executive Officer and the Vice President and Chief Financial Officer, evaluated the effectiveness of WGL Holdings and Washington Gas disclosure controls and procedures as of September 30, 2004. Based on this evaluation process, the Chairman and Chief Executive Officer and the Vice President and Chief Financial Officer have concluded that WGL Holdings and Washington Gas disclosure controls and procedures were effective as of September 30, 2004. There have been no changes in the Registrants internal control over financial reporting during the quarter ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect, the Registrants internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
107
WGL Holdings, Inc.
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANTS
Information concerning the Companys Board
of Directors and the audit committee financial expert contained
in WGL Holdings definitive
Proxy Statement
and
Washington Gas definitive
Information Statement
for
the February 23, 2005 Annual Meeting of Shareholders is
hereby incorporated by reference. Information related to
Executive Officers is reflected in Part 1 hereof.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning Executive Compensation contained in WGL Holdings definitive Proxy Statement and Washington Gas definitive Information Statement for the February 23, 2005 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of September 30, 2004 is reflected in Part I hereof.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information captioned Security Ownership of Management and Certain Beneficial Owners and the information captioned Equity Compensation Plan Information in WGL Holdings definitive Proxy Statement and Washington Gas definitive Information Statement for the February 23, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information captioned Business Relationship with Associate of Directors in WGL Holdings definitive Proxy Statement and Washington Gas definitive Information Statement for the February 23, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned Audit Firm Fee Summary in WGL Holdings definitive Proxy Statement and Washington Gas definitive Information Statement for the February 23, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.
108
WGL Holdings, Inc.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Financial Statement Schedules
All of the financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8. |
Schedule II should be read in conjunction with the financial statements in this report. Schedules not included herein have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. |
Schedule/ | ||||
Exhibit | Description | |||
|
|
|||
II | Valuation and Qualifying Accounts and Reserves for the years ended September 30, 2004, 2003 and 2002WGL Holdings, Inc. | |||
Valuation and Qualifying Accounts and Reserves for the years ended September 30, 2004, 2003 and 2002Washington Gas Light Company. | ||||
(a)(3) |
Exhibits
Exhibits Filed Herewith: |
|||
3 | Articles of Incorporation and Bylaws: | |||
Bylaws of Washington Gas Light Company as amended on October 1, 2004. | ||||
10 | Material Contracts: | |||
10.1 | Service Agreement, renegotiated and effective November 1, 2004, with Columbia Gulf Transmission Company related to Firm Transportation Service. | |||
10.2 | Service Agreement, effective November 1, 2004, with Dominion Cove Point LNG, LP related to Firm Transportation Service. | |||
10.3 | Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Firm Transportation Service from the Mid Atlantic project. | |||
10.4 | Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Storage Service from the Mid Atlantic project. | |||
10.5 | Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Firm Storage Service from the Mid Atlantic project. | |||
10.6 | Service Agreement, effective October 1, 2004, with Transcontinental Pipe Line Corporation related to additional Firm Transportation Service from Leidy East. | |||
10.7 | Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Firm Storage Service. (Agreements 78843,78844,78845 and 78846) | |||
10.8 | Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Storage Service. (Agreements 78837, 78838, 78839 and 78840) | |||
10.9 | Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Firm Transportation Service. (Agreements 78833, 78834, 78835 and 78836) | |||
10.10 | Service Agreement, effective November 27, 2003, with Columbia Gas Transmission Corporation related to additional Firm Transportation Service. | |||
10.11 | Service Agreement, effective January 1, 1996, with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service. |
109
Schedule/ | ||||
Exhibit | Description | |||
|
|
|||
(a)(3) | Exhibits (continued) | |||
10.12 | Service Agreement, effective April 1, 1995, with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service. | |||
10.13 | Service Agreement, effective August 1, 1991, with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service. | |||
10.14 | Service Agreements, effective January 12, 2004 with East Tennessee Natural Gas Company and Saltville Storage Company related to Firm Transportation and Firm Storage Service. | |||
10.15 | WGL Holdings, Inc. 1999 Incentive Compensation Plan, as amended and restated as of March 5, 2003.* | |||
12 | Statement re Computation of Ratios: | |||
12.1 | Computation of Ratio of Earnings to Fixed ChargesWGL Holdings, Inc. | |||
12.2 | Computation of Ratio of Earnings to Fixed Charges and Preferred Stock DividendsWGL Holdings, Inc. | |||
12.3 | Computation of Ratio of Earnings to Fixed ChargesWashington Gas Light Company. | |||
12.4 | Computation of Ratio of Earnings to Fixed Charges and Preferred Stock DividendsWashington Gas Light Company. | |||
21 | Subsidiaries of WGL Holdings, Inc. | |||
23 | Consent of Deloitte & Touche LLP. | |||
31.1 | Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of WGL Holdings, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
31.2 | Certification of Frederic M. Kline, the Vice President and Chief Financial Officer of WGL Holdings, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
31.3 | Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of Washington Gas Light Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
31.4 | Certification of Frederic M. Kline, the Vice President and Chief Financial Officer of Washington Gas Light Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |||
32 | Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer, and Frederic M. Kline, the Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |||
Exhibits Incorporated by Reference: | ||||
2 | Plan of Merger between WGL Holdings, Inc. and Washington Gas Light Company, filed on Form S-4 dated February 2, 2000. | |||
3 | Articles of Incorporations & Bylaws: | |||
Washington Gas Light Company Charter, filed on Form S-3 dated July 21, 1995. | ||||
WGL Holdings, Inc. Charter and Bylaws, filed on Form S-4 dated February 2, 2000. | ||||
4 | Instruments Defining the Rights of Security Holders including Indentures: | |||
Indenture, dated September 1, 1991 between Washington Gas Light Company and The Bank of New York, as Trustee, regarding issuance of unsecured notes, filed as an exhibit to Form 8-K on September 19, 1991. |
110
Schedule/ | ||||
Exhibit | Description | |||
|
|
|||
(a)(3) | Exhibits (continued) | |||
Supplemental Indenture, dated September 1, 1993 between Washington Gas Light Company and The Bank of New York, as Trustee, regarding the addition of a new section to the Indenture dated September 1, 1991, filed as an exhibit to Form 8-K on September 10, 1993. | ||||
10 | Material Contracts: | |||
Service Agreement effective November 1, 2002 with the Transcontinental Gas Pipe Line Corporation for the MarketLink Firm Transportation Capacity, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 2003. | ||||
Service Agreement effective October 1, 1993 with Transcontinental Gas Pipe Line Corporation related to the upstream capacity on the Dominion Transmission, Inc. system, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Service Agreement effective October 1, 1993 with Transcontinental Gas Pipe Line Corporation related to General Storage Service, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Service Agreement effective October 1, 1993 with Dominion Transmission, Inc. related to Firm Transportation Service, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Service Agreement effective October 1, 1993 with Dominion Transmission, Inc. related to Firm Transportation Storage Service, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Service Agreement effective October 1, 1993 with Dominion Transmission, Inc. related to General Storage Service, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Service Agreement effective August 1, 1991 with Transcontinental Gas Pipe Line Corporation related to Washington Storage Service, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1993. | ||||
Retirement Plan for Outside Directors, as amended on December 18, 1996 and filed as an exhibit to Form 10-K for the fiscal year ended September 30, 1997.* | ||||
WGL Holdings, Inc. and Washington Gas Light Company Deferred Compensation Plan for Outside Directors, adopted December 18, 1985, and amended as of November 1, 2000, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
WGL Holdings, Inc. Directors Stock Compensation Plan, adopted on October 25, 1995, and amended as of November 1, 2000, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
Employment Agreement between Washington Gas Light Company and Mr. Thomas F. Bonner, as defined in Item 402 (a)(3) of Regulation S-K, dated April 29, 2002, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 2003.* | ||||
Employment Agreement between Washington Gas Light Company and Ms. Beverly J. Burke, as defined in Item 402 (a)(3) of Regulation S-K, dated December 14, 2001, filed as an exhibit to Form 10-K for the fiscal year ended September 30, 2003.* | ||||
Employment Agreement between Washington Gas Light Company and Mr. James H. DeGraffenreidt, Jr., as defined in Item 402 (a)(3) of Regulation S-K, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* |
111
Schedule/ | ||||
Exhibit | Description | |||
|
|
|||
(a)(3) | Exhibits (concluded) | |||
Employment Agreement between Washington Gas Light Company and Mr. Frederic M. Kline, as defined in Item 402 (a)(3) of Regulation S-K, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
Employment Agreement between Washington Gas Light Company and Mr. Terry D. McCallister, as defined in Item 402 (a)(3) of Regulation S-K, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
Washington Gas Light Company Supplemental Executive Retirement Plan amended November 1, 2000, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
WGL Holdings, Inc. Long-Term Incentive Compensation Plan, adopted June 28, 1989, amended as of November 1, 2000, filed as an exhibit to Form 10-K in the fiscal year ended September 30, 2001.* | ||||
Form of Nonqualified Stock Option Award Agreement, filed as an exhibit to Form 8-K dated October 5, 2004.* | ||||
Form of Performance Share Award Agreement, filed as an exhibit to Form 8-K dated October 5, 2004.* | ||||
Distribution Agreement among Washington Gas Light Company and Citigroup Capital Markets Inc., Bank One Capital Markets, Inc., Merrill Lynch, Pierce Fenner & Smith Incorporated, The Williams Capital Group, L.P. and Wachovia Services, Inc. for the issuance and sale of up to $250.0 million of Medium-Term Notes, Series G, under an Indenture dated as of September 1, 1991. This was filed as an exhibit to Form 8-K dated May 22, 2003. | ||||
* This asterisk designates an agreement that is a compensatory plan or arrangement. |
112
113
114
WGL Holdings, Inc.
SIGNATURES
Pursuant to the requirements of Section 13
or 15(d) of the Securities Exchange Act of 1934, the Registrants
have duly caused this report to be signed on their behalf by the
undersigned, thereunto duly authorized.
Date: December 9, 2004
Pursuant to the requirements of the Securities
Exchange Act of 1934, this report has been signed below by the
following persons on behalf of the registrants and in the
capacities and on the dates indicated.
115
WGL HOLDINGS, INC. and WASHINGTON GAS LIGHT COMPANY 2004
WGL HOLDINGS, INC.
and
WASHINGTON GAS LIGHT COMPANY
(Co-registrants)
/s/ Frederic M. Kline
Frederic M. Kline
Vice President and
Chief Financial Officer
Signature
Title
Date
/s/ James H. DeGraffenreidt, Jr.
(James H.
DeGraffenreidt, Jr.)
Chairman of the Board and Chief Executive Officer
December 9, 2004
/s/ Terry D. McCallister
(Terry D.
McCallister)
President and Chief Operating Officer
December 9, 2004
/s/ Frederic M. Kline
(Frederic M. Kline)
Vice President and Chief Financial Officer
(Principal Financial Officer)
December 9, 2004
/s/ Mark P. OFlynn
(Mark P.
OFlynn)
Controller
(Principal Accounting Officer)
December 9, 2004
/s/ Michael D. Barnes
(Michael D. Barnes)
Director
December 9, 2004
/s/ Daniel J. Callahan, III
(Daniel J.
Callahan, III)
Director
December 9, 2004
/s/ George P. Clancy, Jr.
(George P. Clancy,
Jr.)
Director
December 9, 2004
/s/ James W. Dyke, Jr., Esq.
(James W. Dyke,
Jr., Esq.)
Director
December 9, 2004
/s/ Melvyn J. Estrin
(Melvyn J. Estrin)
Director
December 9, 2004
/s/ James F. Lafond
(James F. Lafond)
Director
December 9, 2004
/s/ Debra L. Lee
(Debra L. Lee)
Director
December 9, 2004
/s/ Karen Hastie Williams, Esq.
(Karen Hastie
Williams, Esq.)
Director
December 9, 2004
Table of Contents
Exhibit
Description
Bylaws of the Washington Gas Light Company as amended on October 1, 2004
Material Contracts:
Service Agreement, renegotiated and effective November 1, 2004, with Columbia Gulf Transmission Company related to Firm Transportation Service.
Service Agreement, effective November 1, 2004, with Dominion Cove Point LNG, LP related to Firm Transportation Service.
Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Firm Transportation Service from the Mid Atlantic project.
Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Storage Service from the Mid Atlantic project.
Service Agreement, effective November 1, 2004, with Dominion Transmission Inc. related to Firm Storage Service from the Mid Atlantic project.
Service Agreement, effective October 1, 2004, with Transcontinental Pipe Line Corporation related to additional Firm Transportation Service from Leidy East.
Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Firm Storage Service. (Agreements
78843, 78844, 78845 and 78846)
Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Storage Service. (Agreements 78837, 78838,
78839 and 78840)
Service Agreements, renegotiated and effective June 1, 2004, with Columbia Gas Transmission Corporation related to Firm Transportation Service. (Agreements
78833, 78834, 78835 and 78836)
Service Agreement, effective November 27, 2003, with Columbia Gas Transmission Corporation related to additional Firm Transportation Service.
Service Agreement, effective January 1, 1996, with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service.
Service Agreement, effective April 1, 1995, with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service.
Service Agreement, effective August 1, 1991 with Transcontinental Gas Pipe Line Corporation related to Firm Transportation Service.
Service Agreements effective
January 12, 2004 with East Tennessee Natural Gas Company and
Saltville Storage Company related to Firm Transportation and Firm
Storage Service.
WGL Holdings, Inc. 1999 Incentive
Compensation Plan, as amended and restated as of March 5, 2003.
Statement re Computation of Ratios:
Computation of Ratio of Earnings to
Fixed ChargesWGL Holdings, Inc.
Computation of Ratio of Earnings to Fixed Charges and Preferred Stock
DividendsWGL Holdings, Inc.
Computation of Ratio of Earnings to
Fixed ChargesWashington Gas Light Company.
Computation of Ratio of Earnings to Fixed Charges and Preferred Stock
DividendsWashington Gas Light Company.
Subsidiaries of WGL Holdings, Inc.
Consent of Deloitte & Touche LLP
Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of WGL Holdings, Inc., pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
Certification of Frederic M. Kline, the Chief Financial Officer of WGL Holdings, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of Washington Gas Light Company, pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
Certification of Frederic M. Kline, the Chief Financial Officer of Washington Gas Light Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer, and Frederic M. Kline, The Chief Financial Officer,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 3
Effective 9/29/2004
WASHINGTON GAS LIGHT COMPANY
ARTICLE I
Stockholders.
SECTION 1.
Annual Meeting.
The annual meeting of stockholders of
Washington Gas Light Company (the Company) shall be held on the last Wednesday
in the month of February in each year, at 10:00 a.m., at the George Washington
University, Washington, D.C., for the purpose of electing directors and for the
transaction of such other business as properly may come before such meeting.
If the day fixed for the annual meeting shall be a legal holiday in the
District of Columbia, such meeting shall be held on the next succeeding
business day.
SECTION 2.
Special Meetings.
Special meetings of stockholders may
be held upon call by the Chairman of the Board, the President, the Secretary, a
majority of the Board of Directors, or a majority of the Executive Committee,
and shall be called by the Chairman of the Board, the President or Secretary
upon the request in writing of the holders of record of not less than one-tenth
of all the outstanding shares of stock entitled by its terms to vote at such
meeting, at such time and at such place within the District of Columbia as may
be fixed in the call and stated in the notice setting forth such call. Such
request by the stockholders and such notice shall state the purpose of the
proposed meeting.
SECTION 3.
Notice of Meetings.
Notice of the time, place and
purpose of every meeting of the stockholders, shall, except as otherwise
required by law, be delivered personally or mailed at least ten (10) but not
more than one hundred (100) days prior to the date of such meeting to each
stockholder of record entitled to vote at the meeting at his address as it
appears on the records
of the
Effective 9/29/2004
Company. Any meeting may be held without notice if all of the stockholders entitled to vote thereat are present in person or by proxy at the meeting, or if notice is waived by those not so present in person or by proxy.
SECTION 4. Quorum. At every meeting of the stockholders, the holders of record of a majority of the shares entitled to vote at the meeting, represented in person or by proxy, shall constitute a quorum. The vote of the majority of such quorum shall be necessary for the transaction of any business, unless otherwise provided by law or the articles of incorporation. If the meeting cannot be organized because a quorum has not attended, those present in person or by proxy may adjourn the meeting from time to time until a quorum is present when any business may be transacted that might have been transacted at the meeting as originally called.
SECTION 5. Voting. Unless otherwise provided by law or the articles of incorporation, every stockholder of record entitled to vote at any meeting of stockholders shall be entitled to one vote for every share of stock standing in his name on the records of the Company on the record date fixed as provided in these Bylaws. In the election of directors, all votes shall be cast by ballot and the persons having the greatest number of votes shall be the directors. On matters other than election of directors, votes may be cast in such manner as the Chairman of the meeting may designate.
SECTION 6. Inspectors. The Board of Directors shall annually appoint two or more persons to act as inspectors or judges at any election of directors or vote conducted by ballot at any meeting of stockholders. Such inspectors or judges of election shall take charge of the polls and after the balloting shall make a certificate of the result of the vote taken. In case of a failure to appoint inspectors, or in case an inspector shall fail to attend, or refuse or be unable to serve, the Chairman
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of the meeting may appoint, or the stockholders may elect, an inspector or inspectors to act at such meeting. Such inspector or inspectors shall make a certificate of the result of the vote taken.
SECTION 7. Conduct of Stockholders Meeting. The following persons, in the order named, shall be entitled to call each stockholders meeting to order: (1) the Chairman of the Board, (2) the President of the Company, (3) a Vice President, or (4) any person elected by the stockholders. The stockholders shall have the right to elect a Chairman of the meeting.
The Secretary of the Company, or in his absence any person appointed by the Chairman, shall act as Secretary of the meeting for organization purposes. The stockholders shall have the right to elect a secretary of the meeting.
SECTION 8. Record Date. In lieu of closing the stock transfer books, the Board of Directors, in order to make a determination of stockholders entitled to notice of or to vote at any meeting, or to receive payment of any dividends or for any other proper purpose, may fix in advance a date, but not more than fifty days in advance, as a record date for such determination, and in such case only stockholders of record on the date so fixed shall be entitled to notice of, and to vote at, such meeting, or to receive payment of such dividend, or to exercise such other rights, as the case may be, notwithstanding any transfer of stock on the books of the Company after such date. If the Board of Directors does not fix a record date as aforesaid, such date shall be as provided by law.
SECTION 9. Notice of Business . At any meeting of the stockholders, only such business shall be conducted as shall have been brought before the meeting (1) by or at the direction of the Board of Directors or (2) by any stockholder of the Company who is a stockholder of record at the
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time of giving of the notice as provided for in this Section 9, who shall be entitled to vote at such meeting and who complies with the following procedures:
Requirement of Timely Notice . For business to be properly brought before a meeting of stockholders by a stockholder, the business shall be a proper subject of stockholder action and the stockholder shall have given timely notice thereof in writing to the Secretary. To be timely, a stockholders notice shall be delivered to or mailed and received by the Secretary at the principal executive office of the Company not less than sixty (60) days prior to the scheduled date of the meeting (regardless of any postponements, deferrals or adjournments of the meeting to a later date); provided , however , if no notice is given and no public announcement is made to the stockholders regarding the date of the meeting at least 75 days prior to the meeting, the stockholders notice shall be valid if delivered to or mailed and received by the Secretary at the principal executive office of the Company not less than fifteen (15) days following the day on which the notice or public announcement of the date of the meeting was given or made.
Contents of Notice . Such stockholders notice to the Secretary shall set forth as to each item of business the stockholder proposes to bring before the meeting (1) a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and, in the event that such business includes a proposal to amend either the Charter or these Bylaws, the language of the proposed amendment, (2) the name and address, as they appear on the Companys books, of the
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stockholder proposing such business, (3) the class and number of shares of capital stock of the Company that are beneficially owned by such stockholder, and (4) any material interest (financial or other) of such stockholder in such business.
Compliance with Bylaws . Notwithstanding anything in these Bylaws to the contrary, no business shall be conducted at a stockholders meeting except in accordance with the procedures set forth in this Section 9. The chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that the business was not properly brought before the meeting and in accordance with the provisions of these Bylaws, and if he should so determine, he shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted at the meeting. Notwithstanding the foregoing provisions of this Section 9, a stockholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in this Section 9.
Effective Date of Stockholder Business . Notwithstanding anything in these Bylaws to the contrary, no business brought before a meeting of the stockholders by a stockholder shall become effective until the final termination of any proceeding which may have been commenced in any court of competent jurisdiction for an adjudication of any legal issues incident to determining the validity of such business and the procedure pursuant to which it was brought before the stockholders, unless and until such court shall have determined that such proceedings are not being pursued expeditiously and in good faith.
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ARTICLE II
Board of Directors.
SECTION 1. Number, Powers, Term of Office, Quorum. The Board of Directors of the Company shall consist of nine persons. The Board of Directors may exercise all the powers of the Company and do all acts and things which are proper to be done by the Company which are not by law or by these Bylaws directed or required to be exercised or done by the stockholders. The members of the Board of Directors shall be elected at the annual meeting of stockholders and shall hold office until the next succeeding annual meeting, or until their successors shall be elected and shall qualify. A majority of the number of directors fixed by the Bylaws shall constitute a quorum for the transaction of business. The action of a majority of the directors present at any lawful meeting at which there is a quorum shall, except as otherwise provided by law or by these Bylaws, be the action of the Board.
SECTION 2. Election . Except as provided in Section 3 hereof, directors shall be elected by the stockholders of the Company pursuant to the procedures enumerated below:
Eligible Persons . Only persons who are nominated in accordance with the following procedures shall be eligible for election by the stockholders as directors of the Company.
Nominations . Nominations of persons for election as directors of the Company may be made at a meeting of stockholders (1) by or at the direction of the Board of Directors, (2) by any nominating committee or person appointed by the Board of Directors or (3) by any stockholder of the Company entitled to vote for the election of directors at the meeting who complies with the notice procedures set forth in this Section 2.
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Nomination by Directors or Nominating Committee . Nominations made by or at the direction of the Board of Directors or the nominating committee or person appointed by the Board of Directors may be made at any time prior to the stockholders meeting. The Board of Directors must send notice of nominations to the stockholders together with the notice of the meeting of the stockholders; provided , however , if the nominations are made after the notice of the meeting has been mailed, the Board of Directors must send notice of its nominations to the stockholders as soon as practicable.
Nomination by Stockholders . Nominations, other than those made by or at the direction of the Board of Directors or the nominating committee or person appointed by the Board of Directors, shall be made pursuant to timely notice in writing to the Secretary. To be timely, a stockholders notice shall be delivered to or mailed and received by the Secretary at the principal executive office of the Company not less than sixty (60) days prior to the scheduled date of the meeting (regardless of any postponements, deferrals or adjournments of the meeting to a later date); provided , however , if no notice is given and no public announcement is made to the stockholders regarding the date of the meeting at least 75 days prior to the meeting, the stockholders notice shall be valid if delivered to or mailed and received by the Secretary at the principal executive office of the Company not less than fifteen (15) days following the day on which the notice or public announcement of the date of the meeting was given or made.
Contents of Notice . Nominations, other than those made by or at the direction of the Board of Directors or the nominating committee or person appointed by the Board of Directors, shall set forth:
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(1) as to each person whom the stockholder proposes to nominate for election or reelection as a director, (a) the name, age, business address and residential address of the person, (b) the principal occupation or employment of the person (c) the class and number of shares of capital stock of the Company that are beneficially owned by the person, (d) written consent by the person, agreeing to serve as director if elected, (e) a description of all arrangements or understandings between the person and the stockholder regarding the nomination, (f) a description of all arrangements or understandings between the person and any other person or persons (naming such persons) regarding the nomination, (g) all information relating to the person that is required to be disclosed in solicitations for proxies for election of directors pursuant to Rule 14a under the Securities Exchange Act of 1934, as amended, and (h) such other information as the Company may reasonably request to determine the eligibility of such proposed nominee to serve as director of the Company; and
(2) as to the stockholder giving the notice, (a) the name, business address and residential address of the stockholder giving the notice, (b) the class and number of shares of capital stock of the Company that are beneficially owned by such stockholder, (c) a description of all arrangements or understandings between the stockholder and the nominee regarding the nomination, and (d) a description of all arrangements or understandings between the stockholder and any other person or persons (naming such persons) regarding the nomination.
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Compliance with Bylaws . No person shall be eligible for election by the stockholders as a director of the Company unless nominated in accordance with the procedures set forth in this section of the Bylaws. The Chairman of the Board of Directors shall, if the facts warrant, determine and declare prior to the meeting of stockholders that the nomination was not made in accordance with the foregoing procedure, and if he should so determine, he shall so inform the nominee and the stockholder who nominated the nominee as soon as practicable and the defective nomination shall be disregarded.
Effective Date of Election of Director . Notwithstanding anything in these Bylaws to the contrary, no election of a director nominated by a stockholder shall become effective until the final termination of any proceeding which may have been commenced in any court of competent jurisdiction for an adjudication of any legal issues incident to determining the procedure pursuant to which the nomination of such director was brought before the stockholders, unless and until such court shall have determined that such proceedings are not being pursued expeditiously and in good faith.
SECTION 3. Vacancies. Whenever any vacancy shall occur in the Board of Directors by any cause other than by reason of an increase in the number of directors, a majority of the remaining directors, by an affirmative vote at any lawful meeting may elect a director to fill the vacancy and to hold office until the next annual election, or until his successor is duly elected and qualified.
SECTION 4. Meetings. Regular meetings of the Board shall be held at the office of the Company in the District of Columbia at times fixed by resolution of the Board of Directors. Notice of such meetings need not be given.
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Special meetings of the Board may be called by the Chairman of the Board, the President of the Company, or by any two directors. At least two days notice of all special meetings of the Board shall be given to each director personally by telegraphic or written notice. Any meeting may be held without notice if all of the directors are present, or if those not present waive notice of the meeting by telegram or in writing. Special meetings of the Board of Directors may be held within or without the District of Columbia.
SECTION 5. Committees. The Board of Directors shall, by resolution or resolutions passed by a majority of the whole Board, designate an Executive Committee, to consist of the Chief Executive Officer of the Company who may be the Chairman of the Board, or the President and three additional members, and three alternates to serve at the call of the Chief Executive Officer in case of the unavoidable absence of one of the regular members, to be elected from the Board of Directors. The Executive Committee shall, when the Board is not in session, have and may exercise all of the authority of the Board of Directors in the management of the business and affairs of the Company.
The Board of Directors may appoint other committees, standing or special, from time to time, from among their own number, or otherwise, and confer powers on such committees, and revoke such powers and terminate the existence of such committees at its pleasure.
A majority of the members of any such committee shall constitute a quorum for the purpose of fixing the time and place of its meetings, unless the Board shall otherwise provide. All action taken by any such committee shall be reported to the Board at its meeting next succeeding such action.
SECTION 6. Compensation of Directors. The Board of Directors shall fix the fee to be paid
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to each director for attendance at any meeting of the Board or of any committee thereof, and may, in its discretion, authorize payment to directors of traveling expenses incurred in attending any such meeting.
SECTION 7. Removal. Any directors may be removed from office at any time, with or without cause, and another be elected in his place, by the vote of the holders of record of a majority of the outstanding shares of stock of the Company (of the class or classes by which such director was elected) entitled to vote thereon, at a special meeting of stockholders called for such purpose.
ARTICLE III
Officers.
SECTION 1. Officers. The officers of the Company shall be elected by the Board of Directors and shall consist of a Chairman of the Board, a President, a Secretary, a Treasurer, and one or more Vice Presidents, and such other officers as the Board from time to time shall elect, with such duties as the Board shall deem necessary to conduct the business of the Company. Any officer may hold two or more offices (including those of the Chairman of the Board and President) except that the offices of President and Secretary may not be held by the same person. The Chairman of the Board shall be a director; other officers, including any Vice Chairman and the President, may be, but are not required to be, Directors.
SECTION 2. Term of Office. Removal. In the absence of a special contract, all officers shall hold their respective offices for one year or until their successors shall have been duly elected and qualified, but they or any of them may be removed from their respective offices on a vote by a majority of the Board.
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SECTION 3. Powers and Duties . The officers of the Company shall have such powers and duties as generally pertain to their offices, respectively, as well as such powers and duties as from time to time shall be conferred by the Board of Directors and/or by the Executive Committee. In the absence of the Chairman of the Board, if any, the President shall preside at the meetings of the Board of Directors. In the absence of both the Chairman of the Board and the President, and provided a quorum is present, the senior member of the Board present, in terms of service on the Board, shall serve as Chairman pro tem of the meeting.
SECTION 4. Salaries. The salaries of all executive officers of the Company shall be determined and fixed by the Board of Directors, or pursuant to such authority as the Board may from time to time prescribe.
ARTICLE III-A
Indemnification of Directors and Officers.
SECTION 1. With respect to a Company officer, director, or employee, the Company shall indemnify, and with respect to any other individual the Company may indemnify, any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding (an Action), whether civil, criminal, administrative, arbitrative or investigative (including an action by or in the right of the Company) by reason of the fact the person is or was a director, officer, employee, or agent of the Company, or is or was serving at the request of the Company as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by that person in connection with such Action;
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except in relation to matters as to which the person shall be finally adjudged in such Action to have knowingly violated the criminal law or be liable for willful misconduct in the performance of the persons duty to the Company. The termination of any Action by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not of itself create a presumption that the person was guilty of willful misconduct.
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Any indemnification (unless ordered by a court) shall be made by the Company only as authorized in the specific case upon a determination that indemnification of the director, officer, employee or agent is proper in the circumstance because the person has met the applicable standard of conduct set forth above. In the case of any director, such determination shall be made: (1) by the Board of Directors by a majority vote of a quorum consisting of directors who were not parties to such Action; or (2) if such a quorum is not obtainable, by majority vote of a committee duly designated by the Board of Directors (in which designation directors who are parties may participate) consisting solely of two or more directors not at the time parties to the proceeding; or (3) by special legal counsel selected by the Board of Directors or its committee in the manner prescribed by clause (1) or (2) of this paragraph, or if such a quorum is not obtainable and such a committee cannot be designated, by majority vote of the Board of Directors, in which selection directors who are parties may participate; or (4) by vote of the shareholders, in which vote shares owned by or voted under the control of directors, officers and employees who are at the time parties to the Action may not be voted. In the case of any officer, employee, or agent other than a director, such determination may be made (i) by the Board of Directors or a committee thereof; (ii) by the Chairman of the Board of the Company or, if the Chairman is a party to such Action, the President of the Company, or (iii) such other officer of the Company, not a party to such Action, as such person specified in clause (i) or (ii) of this paragraph may designate. Authorization of indemnification and evaluation as to reasonableness of expenses shall be made in the same manner as the determination that indemnification is permissible, except that if the determination is made by special legal counsel, authorization of indemnification and evaluation as to reasonableness of expenses shall be made by
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those entitled hereunder to select such legal counsel.
Expenses incurred in defending an Action for which indemnification may be available hereunder shall be paid by the Company in advance of the final disposition of such Action as authorized in the manner provided in the preceding paragraph, subject to execution by the person being indemnified of a written undertaking to repay such amount if and to the extent that it shall ultimately be determined by a court that such indemnification by the Company is not permitted under applicable law.
It is the intention of the Company that the indemnification set forth in this Section of Article III-A, shall be applied to no less extent than the maximum indemnification permitted by law. In the event that any right to indemnification or other right hereunder may be deemed to be unenforceable or invalid, in whole or in part, such unenforceability or invalidity shall not affect any other right hereunder, or any right to the extent that is not deemed to be unenforceable. The indemnification provided herein shall be in addition to, and not exclusive of, any other rights to which those indemnified may be entitled under any Bylaw, agreement, vote of stockholders, or otherwise, and shall continue as to a person who has ceased to be a director, officer, employee, or agent and inure to the benefit of such persons heirs, executors, and administrators.
SECTION 2. In any proceeding brought by a stockholder in the right of the Company or brought by or on behalf of the stockholders of the Company, no monetary damages shall be assessed against an officer or director. The liability of an officer or director shall not be limited as provided in this section if the officer or director engaged in willful misconduct or a knowing violation of the criminal law or of any federal or state securities law.
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ARTICLE IV
Checks, Notes, Etc.
SECTION 1. All checks and drafts on the Companys bank accounts and all bills of exchange and promissory notes, and all acceptances, obligations and other instruments for the payment of money, shall be signed by such officer or officers, agent or agents, as shall be thereunto authorized from time to time by the Board of Directors.
SECTION 2. Shares of stock and other interests in other corporations or associations shall be voted by such officer or officers as the Board of Directors may designate.
SECTION 3. Except as the Board of Directors shall otherwise provide, all contracts expressly approved by the Board shall be signed on behalf of the Company by the Chairman of the Board, the President, or a Vice President.
ARTICLE V
Capital Stock.
SECTION 1. Certificate for shares. The interest of each stockholder of the Company shall be evidenced by a certificate or certificates for shares of stock in such form as required by law and as the Board of Directors may from time to time prescribe. The certificates of stock shall be signed by the President or a Vice President and the Secretary or an Assistant Secretary and sealed with the seal of the Company. Such seal may be a facsimile.
Where any such certificate is countersigned by a transfer agent other than the Company, or an employee of the Company, or is countersigned by a transfer clerk and is registered by a registrar, the signatures of the President or Vice President and the Secretary or Assistant Secretary may be facsimiles.
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In case any officer who has signed, or whose facsimile signature has been placed upon such certificate, shall have ceased to be such officer before such certificate is issued, it may nevertheless be issued by the Company with the same effect as if such officer had not ceased to hold such office at the date of its issue.
SECTION 2. Transfer of Shares. The shares of stock of the Company shall be transferable on the books of the Company by the holders thereof in person or by duly authorized attorney, upon surrender and cancellation of certificates for a like number of shares, with duly executed assignment and power of transfer endorsed thereon or attached thereto, and with such proof of the authenticity of the signatures as the Company or its agents may reasonably require.
SECTION 3. Lost, Stolen or Destroyed Certificates. No certificate of stock claimed to have been lost, destroyed or stolen shall be replaced by the Company with a new certificate of stock until the holder thereof has produced evidence of such loss, destruction or theft, and has furnished indemnification to the Company and its agents to such extent and in such manner as the proper officers or the Board of Directors may from time to time prescribe.
ARTICLE VI
Corporate Records.
SECTION 1. Where Kept . The books, records and papers belonging to the business of the Company, and the corporate seal, shall be kept at the office of the Company in the District of Columbia.
SECTION 2. Inspection. Any stockholder or stockholders, who shall have been such for at
-17-
Effective 9/29/2004
least six months, or who shall be the holder or holders of record of at least five percent of all the outstanding shares of stock of the Company, desiring to inspect the books or records of the Company, shall present to the Board of Directors or the Executive Committee an application for such inspection, specifying the particular books or records to be inspected and the purpose for which such inspection is desired. If, upon such application, the Board of Directors or Executive Committee deems such inspection is sought for a legitimate purpose connected with the interest of the applicant as a stockholder of the Company, such application shall be granted and a time and place for the inspection shall be specified. The stock and transfer books of the Company shall at all times, during business hours, be open to the inspection of stockholders. The Board of Directors shall have the power from time to time to establish general regulations conferring upon stockholders such further rights with respect to inspection of books and records of the Company as the Board shall deem proper.
ARTICLE VII
Fiscal Year.
The fiscal year of the Company shall begin on the 1st day of October in each year and shall end on the 30th day of September following.
ARTICLE VIII
Corporate Seal.
The seal of the Company shall be circular in form and there shall be inscribed thereon Washington Gas Light Company a Corporation of the District of Columbia and Virginia Originally Chartered by Congress in 1848.
-18-
Effective 9/29/2004
ARTICLE IX
Amendments.
The Board of Directors shall have power to make and alter (unless the stockholders shall in any particular instance have otherwise prescribed) any Bylaws of the Company. Such action may be taken at any meeting of the Board by the affirmative vote of a majority of the total number of directors, provided that notice of the proposed change shall have been given to all directors prior to the meeting, or that all of the directors shall be present at the meeting. Any Bylaws made or altered by the Board of Directors may be altered or repealed at any time by the stockholders.
-19-
Exhibit 10.1
|
||||||
|
SERVICE AGREEMENT NO. | 79356 | ||||
|
CONTROL NO. | 2004-07-16-0007 |
FTS1 SERVICE AGREEMENT
THIS
AGREEMENT, made and entered into this
1
st
day
of
November
,
2004
, by
and between:
|
Columbia Gulf Transmission Company
|
(Transporter)
|
AND
|
Washington Gas Light Company
|
(Shipper)
|
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive the service in accordance with the provisions of the effective FTS1 Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission herein contained. The maximum obligations of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which the Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of November 1, 2004, and shall continue in full force and effect until October 31, 2007. Shipper and Transporter agree to avail themselves of the Commissions pre-granted abandonment authority upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions Regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage percentage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities; b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported).
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to at the following until changed by either party by written notice:
Washington Gas Light Company
|
Attn: Gas Acquisition
|
Room 320-B
|
6801 Industrial Road
|
Springfield, VA 22151
|
ATTN: Tim Sherwood
|
|
||||||
|
SERVICE AGREEMENT NO. | 79356 | ||||
|
CONTROL NO. | 2004-07-16-0007 |
FTS1 SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FTS1 37992.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Unbundling Reduction Option pursuant to Section 34 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions or Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the Maximum Daily Quantity, as applicable, set forth in Transporters currently effective Rate Schedule FTS1 Appendix A, Revision N/A with Shipper, which for such points set forth are incorporated by reference.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A, Revision No. 3 shall commence as of November 1, 2004. This Appendix A, Revision N/A shall cancel and supersede the previous Appendix A, Revision N/A to the Service Agreement dated November 1, 2004. With the exception of this Appendix A, Revision N/A all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
Primary Receipt Points
Transportation Demand
71,843
Dth/Day
Measuring
Foot -
Measuring
Maximum Daily
Point No.
note
Point Name
Quantity (Dth/Day)
CGT-RAYNE
71,843
Primary Delivery Points
Measuring | Foot- | Measuring | Maximum Daily | |||||
Point No.
|
note
|
Point Name
|
Quantity (Dth/Day)
|
|||||
801
|
TCO-LEACH | 71,843 |
|
||||||
|
SERVICE AGREEMENT NO. | 79356 | ||||
|
CONTROL NO. | 2004-07-16-0006 |
FTS1 SERVICE AGREEMENT
THIS GREEMENT, made and entered into this 1 st day of November , 2004 , by and between:
Columbia Gulf Transmission Company
|
(Transporter)
|
AND
|
Washington Gas Light Company
|
(Shipper)
|
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive the service in accordance with the provisions of the effective FTS1 Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission herein contained. The maximum obligations of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which the Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of November 1, 2004, and shall continue in full force and effect until October 31, 2006. Shipper and Transporter agree to avail themselves of the Commissions pre-granted abandonment authority upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions Regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage percentage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities; b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported).
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to at the following until changed by either party by written notice:
Washington Gas Light Company
|
Attn: Gas Acquisition
|
Room 320-B
|
6801 Industrial Road
|
Springfield, VA 22151
ATTN: Tim Sherwood |
|
||||||
|
SERVICE AGREEMENT NO. | 79356 | ||||
|
CONTROL NO. | 2004-07-16-0006 |
FTS1 SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FTS1 37992.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Unbundling Reduction Option pursuant to Section 34 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions or Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the Maximum Daily Quantity, as applicable, set forth in Transporters currently effective Rate Schedule FTS1 Appendix A, Revision N/A with Shipper, which for such points set forth are incorporated by reference.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A, Revision No. 2 shall commence as of November 1, 2004. This Appendix A, Revision N/A shall cancel and supersede the previous Appendix A, Revision N/A to the Service Agreement dated November 1, 2004. With the exception of this Appendix A, Revision N/A all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
Transportation Demand 71,843 Dth/Day
Primary Receipt Points
Measuring | Foot- | Measuring | Maximum Daily | |||||
Point No.
|
note
|
Point Name
|
Quantity (Dth/Day)
|
|||||
2700010
|
CGT-RAYNE | 71,843 |
Primary Delivery Points
Measuring | Foot- | Measuring | Maximum Daily | |||||
Point No.
|
note
|
Point Name
|
Quantity (Dth/Day)
|
|||||
801
|
TCO-LEACH | 71,843 |
SERVICE AGREEMENT NO.
79356
CONTROL NO.
2004-07-16-001
FTS1 SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 1 st day of November , 2004 , by and between:
|
Columbia Gulf Transmission Company | |
|
(Transporter) | |
|
AND | |
|
Washington Gas Light Company | |
|
(Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive the service in accordance with the provisions of the effective FTS1 Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second ReviseD Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission herein contained. The maximum obligations of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which the Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of November 1, 2004, and shall continue in full force and effect until October 31, 2005. Shipper and Transporter agree to avail themselves of the Commissions pre-granted abandonment authority upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions Regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage percentage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities; b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported).
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to at the following until changed by either party by written notice:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
SERVICE AGREEMENT NO. 79356
CONTROL NO. 2004-07-16-0002
FTS1 SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FTS1 37992.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER
|
|
Name:
|
TERRY D. McCALLISTER
|
|
Title:
|
PRESIDENT & COO
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle
|
|
Name:
|
T. N. Brasselle
|
|
Title:
|
MGR Customer Services
|
|
Date:
|
NOV 01 2004
|
|
Revision No. 1 | |
|
Control No. 2004-07-16-0002 |
Appendix A to Service Agreement No.
79356
FTS1
Columbia Gulf Transmission Company
Washington Gas Light Company
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Unbundling Reduction Option pursuant to Section 34 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions or Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the Maximum Daily Quantity, as applicable, set forth in Transporters currently effective Rate Schedule FTS1 Appendix A, Revision N/A with Shipper, which for such points set forth are incorporated by reference.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A, Revision No. 1 shall commence as of November 1, 2004. This Appendix A, Revision N/A shall cancel and supersede the previous Appendix A, Revision N/A to the Service Agreement dated November 1, 2004. With the exception of this Appendix A, Revision N/A all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER
|
|
Title:
|
PRESIDENT & COO
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle
|
|
Name:
|
T. N. Brasselle
|
|
Title:
|
MGR Customer Services
|
|
Date:
|
NOV 01 2004
|
|
Revision No. 1 | |
|
Control No. 2004-07-16-0002 |
Appendix A to Processing Service Agreement No. 79356
Transportation
Demand
65,729
Dth/Day
Primary Receipt Points
FTS1
Columbia Gulf Transmission Company
Washington Gas Light Company
Measuring
Foot-
Measuring
Maximum Daily
Point No.
note
Point Name
Quantity (Dth/Day)
CGT-RAYNE
35,729
KOCH-BARRON
30,000
|
Revision No. 1 | |
|
Control No. 2004-07-16-0002 |
Appendix A to
Processing Service Agreement No.
79356
Under Rate Schedule
FTS1
Between (Transporter)
Columbia Gulf Transmission Company
and
(Shipper)
Washington Gas Light Company
Primary Delivery Points
Measuring
|
Foot- | Measuring | Maximum Daily | |||
Point No.
|
note
|
Point Name
|
Quantity (Dth/Day)
|
|||
801
|
TCO-LEACH | 65,729 |
|
SERVICE AGREEMENT NO. 79356 | |
|
CONTROL NO. 2004-07-14-0008 |
FTS1 SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 1 st day of November , 2004 , by and between:
|
Columbia Gulf Transmission Company | |
|
(Transporter) | |
|
AND | |
|
Washington Gas Light Company | |
|
(Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive the service in accordance with the provisions of the effective FTS1 Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission herein contained. The maximum obligations of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which the Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of November 1, 2004, and shall continue in full force and effect until October 31, 2008. Shipper and Transporter agree to avail themselves of the Commissions pre-granted abandonment authority upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions Regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage percentage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities; b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported).
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to at the following until changed by either party by written notice:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
|
SERVICE AGREEMENT NO. 79356 | |
|
CONTROL NO. 2004-07-14-0008 |
FTS1 SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: FTS1 37992.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
|
Revision No. | |
|
Control No. 2004-07-14-0008 |
Appendix A to Service Agreement No.
79356
Under Rate Schedule
FTS1
Between (Transporter)
Columbia Gulf Transmission Company
and (Shipper)
Washington Gas Light Company
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Unbundling Reduction Option pursuant to Section 34 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions or Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the Maximum Daily Quantity, as applicable, set forth in Transporters currently effective Rate Schedule FTS1 Appendix A, Revision N/A with Shipper, which for such points set forth are incorporated by reference.
CANCELLATION OF PREVIOUS APPENDIX A
Service changes pursuant to this Appendix A, Revision No. 0 shall commence as of November 1, 2004. This Appendix A, Revision No.0 shall cancel and supersede the previous Appendix A, Revision N/A to the Service Agreement dated N/A. With the exception of this Appendix A, Revision no. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ TERRY D. McCALLISTER | |
|
|
|
Name:
|
TERRY D. McCALLISTER | |
|
|
|
Title:
|
PRESIDENT & COO | |
|
|
|
Date:
|
||
|
|
|
|
||
|
Columbia Gulf Transmission Company | |
|
||
By:
|
/s/ T. N. Brasselle | |
|
|
|
Name:
|
T. N. Brasselle | |
|
|
|
Title:
|
MGR Customer Services | |
|
|
|
Date:
|
NOV 01 2004 | |
|
|
|
Revision No. | |
|
Control No. 2004-07-14-0008 |
Appendix A to
Processing Service Agreement No.
79356
Under Rate Schedule
FTS1
Between (Transporter)
Columbia Gulf Transmission Company
and (Shipper)
Washington Gas Light Company
Primary Receipt Points
Foot-
Measuring
Maximum Daily
note
Point Name
Quantity (Dth/Day)
CGT-RAYNE
71,843
|
Revision No. | |
|
Control No. 2004-07-14-0008 |
Appendix A to
Processing Service Agreement No.
79356
Under Rate Schedule
FTS1
Between (Transporter)
Columbia Gulf Transmission Company
and (Shipper)
Washington Gas Light Company
Primary Delivery Points
Measuring Point No. |
Foot-
note |
Measuring
Point Name |
Maximum Daily
Quantity (Dth/Day) | |||
801
|
TCO-LEACH | 71,843 |
Exhibit 10.2
SERVICE AGREEMENT
UNDER RATE SCHEDULE FTS
THIS AGREEMENT, made and entered into as of this 1st day of January, 2004, by and between DOMINION COVE POINT LNG, LP (Operator) and WASHINGTON GAS LIGHT COMPANY (Buyer).
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Operator shall perform and Buyer shall receive service in accordance with the provisions of the effective Rate schedule FTS, the applicable General Terms and Conditions of Operators FERC Gas Tariff, Original Volume No. 1, on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission and the terms and conditions of the Service Agreement including Appendix A. The maximum obligation of Operator to provide FTS service to or for Buyer is specified in Appendix A, as the same may be amended from time to time by agreement between Buyer and Operator. Service hereunder shall be provided subject to the provisions of Subpart G of Part 284 of the Commissions regulations.
Section 2. Term. Service under this Agreement shall commence as of ten days after the date that Operator notifies Buyer that Operator is prepared to transport gas under this Agreement, but no earlier than June 1, 2004, and shall continue in full force and effect for a primary term of twenty years. This Agreement shall continue from year to year thereafter until either party gives at least twelve months written notice to the other prior to the start of a contract year. Pre-granted abandonment shall apply upon termination of this Agreement, provided, however, that Buyer shall have any rights of first refusal applicable under the tariff.
Section 3. Rates. Buyer shall pay Operator the rates and charges described on Exhibit B.
Section 4. Notices. Notices to Operator under this Agreement shall be addressed to it at 120 Tredegar St., Richmond, VA 23219 Attention: Jeffrey L. Keister and notices to Buyer shall be addressed to it at 6801 Industrial Rd. Springfield, VA 22151 Attention: Tim Sherwood Dept. Head Energy Acquisition until changed by either party by written notice.
DOMINION COVE POINT LNG, LP
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WASHINGTON GAS LIGHT COMPANY | |||||
By: Its Partner,
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Dominion Cove Point LNG Company, LLC
Operator |
Buyer | |||||
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By: | /s/ [ILLEGIBLE] | By: | /s/ Terry McCallister | |||
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Its:
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Managing Director, Transmission | Its: | Terry McCallister | |||
Marketing & Customer Service
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President and | |||||
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Chief Operating Officer |
Appendix A
To
FTS Service Agreement
Between DOMINION COVE POINT LNG, LP (Operator)
And WASHINGTON GAS LIGHT COMPANY (Buyer)
Dated as of January 1, 2004
Maximum Firm Transportation Quantity (MFTQ): 350,000 (Dth/day)
FTS Service is not being performed as the Elected FTS Service option pursuant
to Rate Schedule FPS-l, FPS-2 or FPS-3.
Primary Receipt Points
Measuring
Maximum Daily
Station Name
Quantity (Dth/day)
Interconnect between Dominion Transmission, Inc. And Operator at Loudoun, VA
100,000
Interconnect between Transcontinental Gas Pipeline Company and Operator at Pleasant Valley
150,000
Interconnect between Columbia Gas Transmission Corporation at Loudoun, VA
100,000
Primary Delivery Points
Measuring
Maximum Daily
Station Name
Quantity (Dth/day)
Interconnect between Operator and Buyer at Centerville
95,000
Interconnect between Operator and Buyer at White Plains
9,000
Interconnect between Operator and Buyer at Gardnier Road
234,000
Interconnect between Operator and Buyer at Prince Fredrick
6,000
Interconnect between Operator and Buyer at Patuxent
6,000
The Master List of Interconnects (MLI) as defined in the General Terms and Conditions of Operators Tariff is incorporated herein by reference for the purposes of listing valid secondary receipt points and delivery points.
[SIGNATURES ON FOLLOWING PAGE]
WASHINGTON GAS LIGHT | DOMINION COVE POINT LNG, LP | |||||
COMPANY
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By: Its Partner, Dominion Cove Point LNG | |||||
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Company, LLC | |||||
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By: | /s/ Terry McCallister | By: | /s/ [ILLEGIBLE] | |||
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Title:
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Terry McCallister | Title: | ||||
Date:
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President and | Date: | ||||
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Chief Operating Officer |
Appendix B
To
FTS Service Agreement
Between Dominion Cove Point LNG, LP (Operator) and
Washington Gas Light Company (Buyer)
Dated as of January 1, 2004
Rates and Charges:
Unless otherwise mutually agreed in a written amendment to this Agreement, Buyer shall pay Operator for transportation services rendered pursuant to this Agreement, the maximum rates and charges, including the incremental fuel retention and electric power surcharge, provided under Rate Schedule FTS for the Cove Point East Project set forth in the Summary of Incremental Rates in Operators effective FERC Gas Tariff, as well as all other rates, charges, surcharges, and penalties applicable under Rate Schedule FTS, including the maximum usage charge and the applicable Fuel Retention Percentage. Upon the beginning of the term of this Agreement, the incremental reservation rate shall be consistent with the FERCs order granting Operator its certificate in Docket Nos. CP03-74-000.
Dominion Cove Point LNG, LP
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FERC Gas Tariff
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First Revised Sheet No. 12 | |
Pro Forma Original Volume No. 1
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SUMMARY OF INCREMENTAL
RATES
($ PER DTH)
Base | Reservation | |||||||||||
Reservation | Electric | Fuel | ||||||||||
Rate
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Surcharge 1/
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Retention 2/
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Cove Point East (X-l)
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1.9704 | 0.3016 | 0.30 | % |
1/ Updated annually in electric tracker.
2/ Updated annually in fuel tracker.
Issued by: Anne E. Bomar, Managing Director-Rates & Regulatory
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Issued on:
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Effective on: |
Exhibit 10.3
AGREEMENT ID | FTNN CONTRACT NO. | |||
532 | 100112 | |||
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SERVICE AGREEMENT
APPLICABLE TO TRANSPORTATION OF NATURAL GAS
UNDER RATE SCHEDULES FTNN
AGREEMENT made as of this 26 day of November, 2003, by and between DOMINION TRANSMISSION, INC., a Delaware corporation, hereinafter called Pipeline, and WASHINGTON GAS LIGHT COMPANY, a District of Columbia and Virginia corporation, hereinafter called Customer.
WHEREAS, by Order issued by the Federal Energy Regulatory Commission (FERC) on September 11, 2003 in Docket Nos. CP03-41-000 and CP03-43-000, Pipeline was issued a certificate of public convenience and necessity pursuant to Section 7 of the Natural Gas Act and Part 157 of the Commissions Regulations authorizing Pipeline to construct, own, and operate facilities providing a total of 223,000 Dekatherms (Dt) per day of firm transportation service and a total of 5.6 Bcf of firm storage capacity (the Mid-Atlantic Project);
WHEREAS, Pipeline has accepted the certificate issued by the FERC in Docket Nos. CP03-41-000 and CP03-43-000;
WHEREAS, Customer has requested that Pipeline transport natural gas for it as part of the Mid-Atlantic Project; and
WHEREAS, Pipeline is willing to provide transportation service for Customer as part of the Mid-Atlantic Project commencing on November 1, 2004, or as soon as any additional necessary rights and regulatory approvals are received and accepted by Pipeline and as the necessary facilities are constructed and ready for service.
WITNESSETH: That, in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
ARTICLE I
Quantities
A. During the term of this Agreement, Pipeline will transport for Customer, on a firm basis, and Customer may furnish, or cause to be furnished, to Pipeline natural gas for such transportation, and Customer will accept, or cause to be accepted, delivery from Pipeline of the quantities Customer has tendered for transportation.
B. The maximum quantities of gas which Pipeline shall deliver and which Customer may tender shall be as set forth on Exhibit A, attached hereto.
FTNN CONTRACT NO. | ||
100112 |
ARTICLE II
Rate
A. Unless otherwise mutually agreed in a written amendment to this Agreement, Customer shall pay Pipeline for transportation services rendered pursuant to this Agreement, the maximum rates and charges provided under Rate Schedule FTNN for the Mid-Atlantic Project set forth in the Summary of Incremental Rates in Pipelines effective FERC Gas Tariff, including applicable surcharges and the Fuel Retention Percentage. Upon the beginning of the term of this Agreement, that rate shall be consistent with the FERCs order granting Pipeline its certificate in Docket Nos. CP03-41-000 and CP03-43-000 (as modified upon rehearing, if applicable).
B. Pipeline shall have the right to propose, file and make effective with the FERC or any other body having jurisdiction, revisions to any applicable rate schedule, or to propose, file, and make effective superseding rate schedules for the purpose of changing the rate, charges, and other provisions thereof effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule FTNN Applicability and Character of Service, (ii) term, (iii) quantities, and (iv) points of receipt and points of delivery shall not be subject to unilateral change under this Article. Said rate schedule or superseding rate schedule and any revisions thereof which shall be filed and made effective shall apply to and become a part of this Service Agreement. The filing of such changes and revisions to any applicable rate schedule shall be without prejudice to the right of Customer to contest or oppose such filing and its effectiveness.
ARTICLE III
Term of Agreement
Subject to all the terms and conditions herein, this Agreement shall be effective ten days after Pipeline notifies Customer that it is prepared to transport gas for Customer under the Agreement, which date shall be no earlier than ten days prior to November 1, 2004. Service pursuant to this Agreement shall continue in effect from that date for a primary term of ten years, and from year to year thereafter; provided, however, that either Pipeline or Customer may terminate the Agreement at the end of the primary term by giving written notice to the other party at least twelve months prior to the start of the next contract year.
FTNN CONTRACT NO. | ||
100112 |
ARTICLE IV
Points of Receipt and Delivery
The Primary Points of Receipt and Delivery and the maximum quantities for each point for all gas that may be received for Customers account for transportation by Pipeline shall be as set forth on Exhibit A. Customer shall also be entitled to utilize Secondary Receipt and Delivery Points in accordance with applicable provisions of Rate Schedule FTNN.
ARTICLE V
Regulatory Approval
Performance under this Agreement by Pipeline and Customer shall be contingent upon Pipeline and Customer receiving all necessary regulatory or other governmental approvals upon terms satisfactory to each. Should Pipeline and Customer be denied such approvals to provide or continue the service contemplated herein or to construct and operate any necessary facilities therefor upon the terms and conditions requested in the application therefor, then Pipelines and Customers obligations here under shall terminate.
ARTICLE VI
Incorporation By Reference of Tariff Provisions
A. To the extent not inconsistent with the terms and conditions of this Agreement, the following provisions of Pipelines effective FERC Gas Tariff, and any revisions thereof that may be made effective hereafter, are hereby made applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule FTNN, or any effective superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as they may be revised or superseded from time to time.
ARTICLE VII
Miscellaneous
A. No change, modification or alteration of this Agreement shall be or become effective until executed in writing by the parties hereto; provided, however, that the parties do not intend that this Article VII.A. requires a further written agreement either prior to the making of any request or filing permitted under Article II hereof or prior to the effectiveness of such request or filing after Commission approval, provided further, however, that nothing in this Agreement shall be deemed to prejudice any position the parties may take as to whether the
FTNN CONTRACT NO. | ||
100112 |
request, filing or revision permitted under Article II must be made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any notice
which either party may desire to give the other, shall be in writing and sent
to the following addresses:
Dominion Transmission, Inc.
120 Tredegar Street
Richmond, VA 23219
Attention: Jeffrey Keister
Phone: (804) 819-2820
Fax: (804) 819-2062
Washington Gas Light Company
6801 Industrial Road
Springfield, Virginia 22151
Attention: Tim Sherwood
Phone: (703) 750-5816
Fax: (703) 750-7945
or any such other address as either party shall designate by formal written notice.
C. No presumption shall operate in favor of or against either party hereto as a result of any responsibility either party may have had for drafting this Agreement.
D. The subject headings of the provisions of this Agreement are inserted for the purpose of convenient reference and are not intended to become a part of or to be considered in any interpretation of such provisions.
ARTICLE VIII
Prior Contract
To the extent not inconsistent with the terms and conditions of this Agreement, the provisions of the Precedent Agreement for Firm Transportation Service between Customer and Pipeline dated December 31, 2001, and as amended, shall survive; otherwise, the provisions of this Agreement shall govern.
FTNN CONTRACT NO. | ||
100112 |
IN WITNESS WHEREOF, the parties hereto intending to be legally bound, have caused this Agreement to be signed by their duly authorized officials as of the day and year first written above.
Dominion Transmission, Inc. | ||
(Pipeline) | ||
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By:
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/s/ [ILLEGIBLE] | |
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Its: MANAGING, DIRECTOR | ||
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(Title) | ||
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Washington Gas Light Company | ||
(Customer) | ||
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By:
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/s/ Terry D. McCallister | |
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Its: President & COO | ||
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(Title) |
FTNN CONTRACT NO. | ||
100112 |
EXHIBIT A
To The FTNN Agreement
Dated
November
26
, 2003
Between Dominion Transmission, Inc.
And Washington Gas Light Company
A. Quantities
1. The maximum quantities of gas which Pipeline shall deliver and which Customer may tender shall be as follows:
a. A Maximum Daily Transportation Quantity (MDTQ) of 40,000 Dt.
b. A Maximum Annual Transportation Quantity (MATQ) of 14,600,000 Dt.
B. Points of Receipt and Delivery
1. The Points of Receipt and the maximum quantities for that point shall be as follows:
a. Up to 40,000 Dt per Day at a point of interconnection between the facilities of Pipeline and Texas Eastern Transmission, L.P. in Westmoreland County, Pennsylvania known as the Oakford Interconnection, at a pressure of not less than 575 pounds per square inch gauge. In addition to these quantities, Customer may increase the quantities furnished to Pipeline at the Point(s) of Receipt provided that such quantities, when reduced by the applicable fuel retention percentage specified in Pipelines then-effective FERC Gas Tariff, do not exceed the MDTQ.
Customer shall have the right to use this Primary Point of Receipt and any available Secondary Points of Receipt to tender gas for injection into storage under its Storage Service Agreement subject to the following terms and conditions:
(i) | Nominations of Receipts for Injection into Storage, whether made by Customer or by Customers agent, assignee, or Replacement Customer, shall reduce Customers entitlement to receipts under the FTNN Transportation Service Agreement by an equivalent quantity. | |||
(ii) | Nominations of Receipts for Transportation under the FTNN Transportation Service Agreement at the Primary Point of Receipt, whether made by Customer or by Customers agent, |
FTNN CONTRACT NO. | ||
100112 |
assignee, or Replacement Customer, shall reduce Customers entitlement to receive gas for injection into storage at such point, by an equivalent quantity. | ||||
(iii) | All nominations under the FTNN Transportation Service Agreement for injection into storage shall be subject to Pipelines confirmation of a corresponding nomination for injection of such gas into Pipelines storage pool(s) under the Storage Service Agreement. | |||
(iv) | The foregoing terms and conditions shall not be affected by any capacity release or assignment of service entitlements under the FTNN Transportation Service Agreement or the Storage Service Agreement. |
b. Up to 40,000 Dt per Day during the Winter Period, from November 1 through March 31 of each year, at the points of withdrawal from Pipelines storage pool(s), provided that, these points of receipt shall be Primary, as defined in Pipelines tariff, only to the extent a corresponding nomination for withdrawal from pipelines storage pool(s) is provided under a firm storage service agreement between Pipeline and Customer.
c. Customers aggregate receipts on any Day at the points specified in paragraphs 1.a. and 1.b. above shall not exceed the MDTQ.
2. The Points of Delivery and the maximum quantities for each point shall be as follows:
a. Up to 40,000 Dt per Day at an existing interconnection between the facilities of Pipeline and Customer at the Town of Leesburg, Loundon County, Virginia, known as the Leesburg Connection, at a maximum pressure of 375 pounds per square inch.
b. Up to the quantities permitted by Paragraph B.1.a.(iii) of this Exhibit A into Pipelines storage pools.
c. Pipelines aggregate delivery obligation at the points described in paragraphs 2.a. and 2.b. above shall not exceed the MDTQ.
Exhibit 10.4
GSS AGREEMENT
CONTRACT #300161
With Dominion Transmission, Inc.
Effective April 1, 2004 thru April 1, 2014
SERVICE AGREEMENT
AGREEMENT made as of this
26
day of November, 2003, by and between
DOMINION TRANSMISSION, INC., a Delaware corporation, hereinafter called
Pipeline, and WASHINGTON GAS LIGHT COMPANY, a District of Columbia and
Virginia corporation, hereinafter called Customer.
WHEREAS, by Order issued by the Federal Energy Regulatory Commission
(FERC) on September 11, 2003 in Docket Nos. CP03-41-000 and CP03-43-000,
Pipeline was issued a certificate of public convenience and necessity
pursuant to Section 7 of the Natural Gas Act and Part 157 of the Commissions
Regulations authorizing Pipeline to construct, own, and operate facilities
providing a total of 223,000 Dekatherms (Dt) per day of firm transportation
service and a total of 5.6 Bcf of firm storage capacity (the Mid-Atlantic
Project);
WHEREAS, Pipeline has accepted the certificate issued by the FERC
in Docket Nos. CP03-41-000 and CP03-43-000;
WHEREAS, Customer has requested that Pipeline store natural gas for it
as part of the Mid-Atlantic Project; and
WHEREAS, Pipeline is willing to provide storage service for Customer as
part of the Mid-Atlantic Project commencing on April 1, 2004, or as soon as
any additional necessary rights and regulatory approvals are received and
accepted by Pipeline and as the necessary facilities are constructed and
ready for service.
WITNESSETH: That, in consideration of the mutual covenants herein
contained, the parties hereto agree that Pipeline will store natural gas for
Customer during the term, at the rates and on the terms and conditions
hereinafter provided and, with respect to gas delivered by each of the parties
to the other, under and subject to Pipelines Rate Schedule GSS and all of the
General Terms and Conditions contained in Pipelines FERC Gas Tariff and any
revisions thereof that may be made effective hereafter:
ARTICLE I
During the term of this Agreement, Customer agrees to deliver to Pipeline
and Pipeline agrees to receive for storage in Pipelines underground storage
properties, and Pipeline agrees to inject or cause to be injected into storage
for Customers account, store, withdraw from storage, and deliver to Customer
and
Customer agrees to receive, quantities of natural gas as set forth on
Exhibit A, attached hereto.
ARTICLE II
A. For storage service rendered by Pipeline to Customer hereunder,
Customer shall pay Pipeline the maximum rates and charges provided under
Rate Schedule GSS contained in Pipelines effective FERC Gas Tariff or any
effective superseding rate schedule.
B. Pipeline shall have the right to propose, file and make effective with
the FERC or any other body having jurisdiction, revisions to any applicable
rate schedule, or to propose, file, and make effective superseding rate
schedules for the purpose of changing the rate, charges, and other provisions thereof
effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule GSS
Applicability and Character of Service, (ii) term, (iii) quantities, and (iv) points of
receipt and points of delivery shall not be subject to unilateral change under this
Article. Said rate schedule or superseding rate schedule and any revisions thereof which
shall be filed and made effective shall apply to and become a part of this Service
Agreement. The filing of such changes and revisions to any applicable rate schedule
shall be without prejudice to the right of Customer to contest or oppose such
filing and its effectiveness.
C. The Storage Demand Charge and the Storage Capacity Charge provided
in the aforesaid rate schedule shall commence on the first of the month
during which Pipeline is prepared to accept injections under this Storage Service Agreement, which date shall be no earlier than April 1, 2004.
ARTICLE III
Subject to all the terms and conditions herein, this Agreement shall be
effective ten days after Pipeline notifies Customer that it is prepared to
accept injections under this Storage Service Agreement, which date shall be no
earlier than April 1
,
2004, for purposes of Pipelines receipt of injections
into storage and the payment of rates pursuant to Rate Schedule GSS and
November 1, 2004, for purposes of Pipelines deliveries of gas from storage.
Service under this Service Agreement shall continue in effect for a primary
term of ten years and from year to year thereafter, until either party
terminates this Agreement at or after the end of the primary term by giving
written notice to the other at least twenty-four months prior to the start of
an annual term.
ARTICLE IV
The Points of Receipt for Customers tender of storage injection
quantities, and the Point(s) of Delivery for withdrawals from storage shall be
specified on Exhibit A, attached hereto.
ARTICLE V
Performance under this Agreement by Pipeline and Customer shall be
contingent upon Pipeline and Customer receiving all necessary regulatory or
other governmental approvals upon terms satisfactory to each. Should Pipeline
and Customer be denied such approvals to provide the service contemplated
herein to construct and operate any necessary facilities therefor upon the
terms and conditions requested in the application therefor, then Pipelines and
Customers obligations hereunder shall terminate.
ARTICLE VI
To the extent not inconsistent with the terms and conditions of this
Agreement, the following provisions of Sellers effective FERC Gas Tariff, and
any revisions thereof that may be made effective hereafter are hereby made
applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule GSS or any effective superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as they may be revised or superseded from time to time.
ARTICLE VII
A. No change, modification or alteration of this Agreement shall be or
become effective until executed in writing by the parties hereto; provided,
however, that the parties do not intend that this Article VII.A. requires a
further written agreement either prior to the making of any request or filing
permitted under Article II hereof or prior to the effectiveness of such request
or filing after Commission approval, provided further, however, that nothing in
this Agreement shall be deemed to prejudice any position the parties may take
as to whether the request, filing or revision permitted under Article II must
be made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any
notice which either party may desire to give the other, shall be in writing and
sent to the following addresses:
or any such other address as either party shall designate by formal written
notice.
C. No presumption shall operate in favor of or against either party hereto
as a result of any responsibility either party may have had for drafting
this Agreement.
D. The subject headings of the provisions of this Agreement are inserted
for the purpose of convenient reference and are not intended to become a
part of or to be considered in any interpretation of such provisions.
ARTICLE VIII
To the extent not inconsistent with the terms and conditions of this
Agreement, the provisions of the Precedent Agreement for Firm Transportation
Service between Customer and Pipeline dated December 31, 2001, and as amended,
shall survive; otherwise, the provisions of this Agreement shall govern.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
signed by their duly authorized officials as of the day and year first above
written.
EXHIBIT A
To The GSS Agreement
A. Quantities
The quantities of natural gas storage service which Customer may utilize under
this Agreement, as well as Customers applicable Billing Determinants, are as
follows:
1. Storage Capacity of 2,800,000 Dekatherms (Dt), and
2. Storage Demand of 40,000 Dt per day.
B. Points of Receipt and Delivery
1. The Point(s) of Receipt for Customers tender of storage injection
quantities, and the maximum quantities and character of service for each
point, shall be:
The points of injection into Pipelines storage pools, provided that,
these Point(s) of Receipt shall be Primary, as defined in Pipelines FERC Gas
Tariff, only to the extent that Pipeline provides corresponding transportation
to the points of injection into Pipelines storage pools under the FTNN
Transportation Service Agreement between Pipeline and Customer.
2. The Point(s) of Delivery for withdrawals from storage, and the maximum
quantities and character of service for each point, shall be:
The points of withdrawal from Pipelines storage pools, provided that,
these Point(s) of Delivery shall be Primary, as defined in Pipelines FERC Gas
Tariff, only to the extent that Pipeline provides corresponding transportation
from the points of withdrawal from Pipelines storage pools under the FTNN
Transportation Service Agreement between Pipeline and Customer.
AGREEMENT ID
GSS CONTRACT NO.
531
300161
APPLICABLE TO THE STORAGE OF NATURAL GAS
UNDER RATE SCHEDULE GSS
Quantities
GSS CONTRACT NO.
300161
Rate
Term of Agreement
GSS CONTRACT NO.
300161
Points of Receipt and Delivery
Regulatory Approval
Incorporation By Reference of Tariff Provisions
Miscellaneous
GSS CONTRACT NO.
300161
Pipeline :
Dominion Transmission, Inc.
120 Tredegar Street
Richmond, VA 23219
Attention: Jeffrey Keister
Phone: (804) 819-2820
Fax: (804) 819-2062
Customer:
Washington Gas Light Company
6801 Industrial Road
Springfield, Virginia 22151
Attention: Tim Sherwood
Phone: (703) 750-5816
Fax: (703) 750-7945
Prior Contracts
GSS CONTRACT NO.
300161
Dominion Transmission, Inc.
(Pipeline)
By:
/s/ [ILLEGIBLE]
Its:
MANAGING, DIRECTOR
(Title)
Washington Gas Light Company
(Customer)
By:
/s/ Terry McCallister
Its:
President & COO
(Title)
GSS CONTRACT NO.
300161
Dated November
26
, 2003
Between Dominion Transmission, Inc.
And Washington Gas Light Company
Exhibit 10.5
FT AGREEMENT CONTRACT #200386
With Dominion Transmission, Inc .
Effective November 1, 2004 thru November 1, 2014
AGREEMENT ID | ||
533 | ||
|
FT CONTRACT NO.
200386
SERVICE AGREEMENT
APPLICABLE TO TRANSPORTATION OF NATURAL GAS
UNDER RATE SCHEDULES FT
AGREEMENT made as of this 26 day of November, 2003, by and between DOMINION TRANSMISSION, INC., a Delaware corporation, hereinafter called Pipeline, and WASHINGTON GAS LIGHT COMPANY, INC., a District of Columbia and Virginia corporation, hereinafter called Customer.
WHEREAS, by Order issued by the Federal Energy Regulatory Commission (FERC) on September 11, 2003 in Docket Nos. CP03-41-000 and CP03-43-000, Pipeline was issued a certificate of public convenience and necessity pursuant to Section 7 of the Natural Gas Act and Part 157 of the Commissions Regulations authorizing Pipeline to construct, own, and operate facilities providing a total of 223,000 Dekatherms (Dt) per day of firm transportation service and a total of 5.6 Bcf of firm storage capacity (the Mid-Atlantic Project);
WHEREAS, Pipeline has accepted the certificate issued by the FERC in Docket Nos. CP03-41-000 and CP03-43-000;
WHEREAS, Customer has requested that Pipeline transport natural gas for it as part of the Mid-Atlantic Project; and
WHEREAS, Pipeline is willing to provide transportation service for Customer as part of the Mid-Atlantic Project commencing on November 1, 2004, or as soon as any additional necessary rights and regulatory approvals are received and accepted by Pipeline and as the necessary facilities are constructed and ready for service.
WITNESSETH: That, in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
ARTICLE I
Quantities
A. During the term of this Agreement, Pipeline will transport for Customer, on a firm basis, and Customer may furnish, or cause to be furnished, to Pipeline natural gas for such transportation, and Customer will accept, or cause to be accepted, delivery from Pipeline of the quantities Customer has tendered for transportation.
B. The maximum quantities of gas which Pipeline shall deliver and which Customer may tender shall be as set forth on Exhibit A, attached hereto.
FT CONTRACT NO.
200386
ARTICLE II
Rate
A. Unless otherwise mutually agreed in a written amendment to this Agreement, Customer shall pay Pipeline for transportation services rendered pursuant to this Agreement, the maximum rates and charges provided under Rate Schedule FT for the Mid-Atlantic Project set forth in the Summary of Incremental Rates in Pipelines effective FERC Gas Tariff, including applicable surcharges and the Fuel Retention Percentage. Upon the beginning of the term of this Agreement, that rate shall be consistent with the FERCs order granting Pipeline its certificate in Docket Nos. CP03-41-000 and CP03-43-000 (as modified upon rehearing, if applicable).
B. Pipeline shall have the right to propose, file and make effective with the FERC or any other body having jurisdiction, revisions to any applicable rate schedule, or to propose, file, and make effective superseding rate schedules for the purpose of changing the rate, charges, and other provisions thereof effective as to Customer; provided, however, that (i) Section 2 of Rate Schedule FT Applicability and Character of Service, (ii) term, (iii) quantities, and (iv) points of receipt and points of delivery shall not be subject to unilateral change under this Article. Said rate schedule or superseding rate schedule and any revisions thereof which shall be filed and made effective shall apply to and become a part of this Service Agreement. The filing of such changes and revisions to any applicable rate schedule shall be without prejudice to the right of Customer to contest or oppose such filing and its effectiveness.
ARTICLE III
Term of Agreement
Subject to all the terms and conditions herein, this Agreement shall be effective ten days after Pipeline notifies Customer that it is prepared to transport gas for Customer under the Agreement, which date shall be no earlier than ten days prior to November 1, 2004. Service pursuant to this Agreement shall continue in effect from that date for a primary term of ten years, and from year to year thereafter; provided, however, that either Pipeline or Customer may terminate the Agreement at the end of the primary term by giving written notice to the other party at least twelve months prior to the start of the next contract year.
FT CONTRACT NO.
200386
ARTICLE IV
Points of Receipt and Delivery
The Primary Points of Receipt and Delivery and the maximum quantities for each point for all gas that may be received for Customers account for transportation by Pipeline shall be as set forth on Exhibit A. Customer shall also be entitled to utilize Secondary Receipt and Delivery Points in accordance with applicable provisions of Rate Schedule FT.
ARTICLE V
Regulatory Approval
Performance under this Agreement by Pipeline and Customer shall be contingent upon Pipeline and Customer receiving all necessary regulatory or other governmental approvals upon terms satisfactory to each. Should Pipeline and Customer be denied such approvals to provide or continue the service contemplated herein or to construct and operate any necessary facilities therefor upon the terms and conditions requested in the application therefor, then Pipelines and Customers obligations hereunder shall terminate.
ARTICLE VI
Incorporation By Reference of Tariff Provisions
A. To the extent not inconsistent with the terms and conditions of this Agreement, the following provisions of Pipelines effective FERC Gas Tariff, and any revisions thereof that may be made effective hereafter, are hereby made applicable to and a part hereof by reference:
1. All of the provisions of Rate Schedule FT, or any effective superseding rate schedule or otherwise applicable rate schedule; and
2. All of the provisions of the General Terms and Conditions, as they may be revised or superseded from time to time.
ARTICLE VII
Miscellaneous
A. No change, modification or alteration of this Agreement shall be or become effective until executed in writing by the parties hereto; provided, however, that the parties do not intend that this Article VII.A. requires a further written agreement either prior to the making of any request or filing permitted under Article II hereof or prior to the effectiveness of such request or filing after Commission approval, provided further, however, that nothing in this Agreement shall be deemed to prejudice any position the parties may take as to whether the
FT CONTRACT NO.
200386
request, filing or revision permitted under Article II must be made under Section 7 or Section 4 of the Natural Gas Act.
B. Any notice, request or demand provided for in this Agreement, or any
notice which either party may desire to give the other, shall be in
writing and sent
to the following addresses:
Dominion Transmission, Inc.
120 Tredegar Street
Richmond, VA 23219
Attention: Jeffrey Keister
Phone: (804) 819-2820
Fax: (804) 819-2062
Washington Gas Light Company
6801 Industrial Road
Springfield, Virginia 22151
Attention: Tim Sherwood
Phone:
(703) 750-5816
Fax: (703) 750-7945
or any such other address as either party shall designate by formal written notice.
C. No presumption shall operate in favor of or against either party hereto as a result of any responsibility either party may have had for drafting this Agreement.
D. The subject headings of the provisions of this Agreement are inserted for the purpose of convenient reference and are not intended to become a part of or to be considered in any interpretation of such provisions.
ARTICLE VIII
Prior Contract
To the extent not inconsistent with the terms and conditions of this Agreement, the provisions of the Precedent Agreement for Firm Transportation Service between Customer and Pipeline dated December 31, 2001, and as amended, shall survive; otherwise, the provisions of this Agreement shall govern.
FT CONTRACT NO.
200386
IN WITNESS WHEREOF, the parties hereto intending to be legally bound, have caused this Agreement to be signed by their duly authorized officials as of the day and year first written above.
Dominion Transmission, Inc. | ||||||||||
(Pipeline) | ||||||||||
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By: | /s/ [ILLEGIBLE] | |||||||||
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Its: | MANAGING, DIRECTOR | ||||||||
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(Title) | |||||||||
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Washington Gas Light Company | ||||||||||
(Customer) | ||||||||||
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By: | /s/ Terry McCallister | |||||||||
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Its: | President & COO | ||||||||
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(Title) |
FT CONTRACT NO. | ||
200386 | ||
EXHIBIT A
To The FT Agreement
Dated November
26
, 2003
Between Dominion Transmission, Inc.
And Washington Gas Light Company
A. Quantities
1. The maximum quantities of gas which Pipeline shall deliver and which Customer may tender shall be as follows:
a. A Maximum Daily Transportation Quantity (MDTQ) of 25,000 Dt.
b. A Maximum Annual Transportation Quantity (MATQ) of 9,125,000 Dt.
B. Points of Receipt and Delivery
1. The Point of Receipt and the maximum quantities for that point shall be as follows:
Up to 25,000 Dt per Day at a point of interconnection between the facilities of Pipeline and Texas Eastern Transmission, L.P. in Westmoreland County, Pennsylvania known as the Oakford Interconnection, at a pressure of not less than 575 pounds per square inch gauge. In addition to these quantities, Customer may increase the quantities furnished to Pipeline at the Point(s) of Receipt provided that such quantities, when reduced by the applicable fuel retention percentage specified in Pipelines then-effective FERC Gas Tariff, do not exceed the MDTQ.
2. The Point of Delivery and the maximum quantities for that point shall be as follows:
Up to 25,000 Dt per Day at an existing interconnection between the facilities of Pipeline and Dominion Cove Point LNG, Limited Partnership in Loudoun County, Virginia, known as the Loudoun Interconnection. Each of the parties shall use due care and diligence to ensure that pressures are maintained within the normal operating tolerances at the Point of Delivery as reasonably may be required to render service hereunder.
Exhibit 10.6
Contract # 9020256
Leidy East
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
WASHINGTON GAS LIGHT COMPANY
Dated
October 1, 2004
SERVICE AGREEMENT
THIS AGREEMENT entered into this 29 th day of SEPTEMBER , 2004, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as Seller, first party, and WASHINGTON GAS LIGHT COMPANY, hereinafter referred to as Buyer, second party,
WITNESSETH
WHEREAS, by orders issued October 25, 2001 and October 23, 2002 in Docket Nos. CP01-389-000 and CP01-389-003, the Federal Energy Regulatory Commission (FERC) has authorized Sellers Leidy East Expansion Project (referred to as Leidy East Project); and
WHEREAS, Seller and Reliant Energy Services, Inc. (Reliant) are parties to that certain Rate Schedule FT Service Agreement, dated May 30, 2001 and amended on September 27, 2002 (and effective November 1, 2002), for firm transportation service of 25,000 dekatherms per day under the Leidy East Project (Leidy East Agreement); and
WHEREAS, pursuant to Section 42.14 of the General Terms and Conditions of Sellers FERC Gas Tariff, Reliant has permanently released all of its firm transportation capacity under the Leidy East Agreement to Buyer, and Buyer has agreed to accept such permanent release, effective as of October 1, 2004; and
WHEREAS, Seller is willing to provide the requested firm transportation service for Buyer under the Leidy East Project pursuant to the terms and conditions of this agreement and Sellers Rate Schedule FT commencing as provided in Article IV of this agreement.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
GAS TRANSPORTATION SERVICE
1. Subject to the terms and provisions of this agreement and of Sellers Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to a Transportation Contract Quantity (TCQ) of 25,000 dekatherms per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 and, if applicable, Section 42 of the General Terms and Conditions of Sellers FERC Gas Tariff.
ARTICLE II
POINT(S) OF RECEIPT
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Sellers pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) of Sellers pipeline system at such point(s) of receipt. In the event the maximum operating pressure(s) of Sellers pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
1
SERVICE AGREEMENT
(CONTINUED)
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
POINT(S) OF DELIVERY
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
TERM OF AGREEMENT
This agreement shall be effective as of October 1, 2004 and shall remain in force and effect until 9:00 a.m. Central Clock Time November 1, 2022 and thereafter until terminated by Seller or Buyer upon at least two years written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Sellers reasonable judgment fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 32 of the General Terms and Conditions of Sellers Volume No. 1 Tariff. As set forth in Section 8 of Article II of Sellers August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted abandonment under Section 284.221 (d) of the Commissions Regulations shall not apply to any long term conversions from firm sales service to transportation service under Sellers Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service.
ARTICLE V
RATE SCHEDULE AND PRICE
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Sellers Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Sellers FERC Gas Tariff as filed with the FERC, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof. In the event Buyer and Seller mutually agree to a negotiated rate pursuant to the provisions in Section 53 of the General Terms and Conditions and specified term for service hereunder, provisions governing such negotiated rate (including surcharges) and term shall be set forth on Exhibit C to the service agreement.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Sellers Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Sellers Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyers request for service under Sellers Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
2
SERVICE AGREEMENT
(CONTINUED)
ARTICLE VI
MISCELLANEOUS
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto: None
2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
(a) |
If to Seller:
Transcontinental Gas Pipe Line Corporation P.O. Box 1396 Houston, Texas, 77251-1396 Attn: Director Marketing Services Transco (South) |
|||
(b) |
If to Buyer:
Washington Gas Light 6801 Industrial Road Springfield, Virginia 22151 Attn: DEPT. HEAD - ENERGY ACQUISITION |
Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.
3
SERVICE AGREEMENT
(CONTINUED)
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION | ||||
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(Seller) | |||
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||||
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By: |
/s/ Frank J. Ferazzi
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||
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Frank J. Ferazzi | |||
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Vice President, Commercial Operations | |||
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WASHINGTON GAS LIGHT COMPANY | ||||
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(Buyer) | |||
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||||
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By: |
/s/ Terry McCallister
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||
`
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Title: | PRESIDENT/ C.O.O. |
4
SERVICE AGREEMENT
(CONTINUED)
Exhibit A
ATTACHED AND MADE PART OF THAT SERVICE AGREEMENT BY AND BETWEEN TRANSCONTINENTAL GAS PIPE LINE CORPORATION, AS SELLER, AND WASHINGTON GAS LIGHT COMPANY, AS BUYER, DATED SEPTEMBER 29 , 2004.
|
Sellers | |
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Cumulative | |
|
Daily Receipt | |
Point(s) of Receipt
|
Obligation (Dt/d) 1 | |
The
point of interconnection between Seller and
CNG Transmission Corporation at Leidy, Clinton County, Pennsylvania. |
25,000* | |
|
||
The
point of interconnection between Seller and
National Fuel Gas Distribution Corporation at Leidy, Clinton County, Pennsylvania |
*Note: The sum of the receipts from the points specified above, not inclusive of fuel and line loss make-up, may not exceed the TCQ of 25,000 dt/d except as permitted in Sellers FERC Gas Tariff, as effective at the time of receipt.
1 | These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. Therefore, Buyer shall also deliver or cause to be delivered at the receipt points such additional quantities of gas in kind to be retained by Seller for compressor fuel and line loss make-up. |
SERVICE AGREEMENT
(CONTINUED)
Exhibit B
ATTACHED AND MADE PART OF THAT SERVICE AGREEMENT BY AND BETWEEN TRANSCONTINENTAL GAS PIPE LINE CORPORATION, AS SELLER, AND WASHINGTON GAS LIGHT COMPANY, AS BUYER, DATED SEPT. 29 , 2004.
|
Maximum Daily | |||
Point(s) of Delivery and Pressures
1
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Delivery Quantity (Dt/d) 2 | |||
The point of interconnection between Sellers, Leidy
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25,000 | |||
Line and its Main line in Mercer County, New Jersey
|
||||
(referred to as Princeton Junction or Station 210)
|
1 | Pressure(s) shall not be less than fifty (50) pounds per square inch gauge or at such other pressures as may be agreed upon by Buyer and Seller. | |
2 | Deliveries to or for the account of Buyer at the delivery point(s) shall be subject to the limits of the Delivery Point Entitlement (DPEs), if applicable, of the entities receiving the gas at the delivery points, as such DPEs are set forth in Transcos FERC Gas Tariff, as amended from time to time. |
SERVICE AGREEMENT
(CONTINUED)
Exhibit C
ATTACHED AND MADE PART OF THAT SERVICE AGREEMENT BY AND BETWEEN TRANSCONTINENTAL GAS PIPE LINE CORPORATION, AS SELLER, AND WASHINGTON GAS LIGHT COMPANY, AS BUYER, DATED SEPTEMBER 29 , 2004
Specification of Negotiated Rate and Term
Primary Term: 18 Years and 1 month
The Negotiated Reservation Rate shall be effective during the primary term of this Service Agreement
Negotiated Monthly Reservation Rate: ($/Dth) $6.39
Negotiated Daily Reservation Rate: ($/Dth) $0.21008
In addition to the negotiated reservation rate, Buyer shall be responsible for fuel retention, electric power charges, and all surcharges, except for the Great Plains Surcharge, applicable to Sellers Rate Schedule FT Service as approved by the FERC. Fuel retention, electric power charges and applicable surcharges are subject to change from time to time as approved by the FERC.
Seller agrees not to file or cause to be filed with the FERC under Section 4 of the Natural Gas Act (NGA) to seek to modify the negotiated reservation rate, and Buyer agrees not to file or cause to be filed with the FERC any action, claim, complaint, or other pleading under Section 4 or 5 of the NGA, or to support or participate in any such proceeding initiated by any other party, relating to the negotiated reservation rate.
Exhibit 10.7
SERVICE
AGREEMENT NO.
78843
CONTROL NO. 2003-06-19-0003
FSS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shippers Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004 , and shall continue in full force and effect until October 31, 2005 and from Year-to-Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
SERVICE
AGREEMENT NO.
78843
CONTROL NO. 2003-06-19-0003
FSS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
SERVICE
AGREEMENT NO.
78843
CONTROL NO. 2003-06-19-0003
FSS SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
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Washington Gas Light Company | |
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||
By:
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/s/ Terry McCallister | |
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Name:
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Terry McCallister | |
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Title:
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President & COO | |
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Date:
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4/8/04 | |
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Columbia Gas Transmission Corporation | |
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By:
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/s/ Jeanne A. Adkins | |
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Name:
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Jeanne A. Adkins | |
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Title:
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Manager - Customer Services | |
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Date:
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May 7, 2004 | |
|
|
Revision No.
Control No. 2003-06-19-0003
Appendix A to Service Agreement No. 78843 | ||
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Under
Rate Schedule
|
FSS | |
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||
Between
(Transporter)
|
Columbia Gas Transmission Corporation | |
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||
and
(Shipper)
|
Washington Gas Light Company |
Storage Contract Quantity 4,685,668 Dth
Maximum Daily Storage Quantity 79,440 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
[ ]Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ]Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. shall be effective from June 1, 2004 through October 31, 2005.
[X]Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supersede the Previous Appendix A, Revision No. N/A effective as of N/A, to the Service Agreement referenced above.
With the exception of this Appendix A, Revision No. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
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Washington Gas Light Company | |
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||
By:
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/s/ Terry McCallister | |
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Name:
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Terry McCallister | |
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Title:
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President & COO | |
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Date:
|
4/8/04 | |
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||
|
Columbia Gas Transmission Corporation | |
|
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By:
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/s/ Jeanne A. Adkins | |
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Name:
|
Jeanne A. Adkins | |
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|
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Title:
|
Manager-Customer Services | |
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Date:
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May 7, 2004 | |
|
|
Revision No.
Control No. 2003-06-19-0003
Appendix B
to Service Agreement No.
|
||
|
||
Under
Rate Schedule
|
FSS | |
|
||
Between
(Transporter)
|
Columbia Gas Transmission Corporation | |
|
||
and
(Shipper)
|
Washington Gas Light Company |
Superceded
Agreements:
|
||||
|
FSS | 53005 | ||
|
FSS | 71573 | ||
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FSS | 73994 | ||
|
FSS | 75643 |
|
SERVICE AGREEMENT NO. 78844 | |
|
CONTROL NO. 2003-06-19-0004 |
FSS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shippers Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2007 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78844 | |
|
CONTROL NO. 2003-06-19-0004 |
FSS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78844 | ||||||
|
CONTROL NO. 2003-06-19-0004 |
FSS SERVICE AGREEMENT
Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
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|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
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|
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Date:
|
4/8/04 | |
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|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
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/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager Customer Services | |
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|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |||||||
|
Control No. 2003-06-19-0004 | |||||||
Appendix A to Service Agreement No.
|
78844 | |||||||
Under Rate Schedule
|
FSS | |||||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||||
and (Shipper)
|
Washington Gas Light Company |
Storage Contract Quantity 6,247,557 Dth
Maximum Daily Storage Quantity 105,920 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. shall be effective from June 1, 2004 through March 31, 2007.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supersede the Previous Appendix A, Revision No. N/A effective as of N/A, to the Service Agreement referenced above.
With the exception of this Appendix A, Revision No. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |||||||
|
Control No. 2003-06-19-0004 | |||||||
Appendix B to Service Agreement No.
|
78844 | |||||||
Under Rate Schedule
|
FSS | |||||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||||
and (Shipper)
|
Washington Gas Light Company |
Superceded Agreements:
|
||||||
|
FSS | 53005 | ||||
|
FSS | 71573 | ||||
|
FSS | 73994 | ||||
|
FSS | 75643 |
|
SERVICE AGREEMENT NO. 78845 | |||||
|
CONTROL NO. 2003-06-19-0005 |
FSS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shippers Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2008 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78845 | |||||
|
CONTROL NO. 2003-06-19-0005 |
FSS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78845 | |||||
|
CONTROL NO. 2003-06-19-0005 |
FSS SERVICE AGREEMENT
Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |
|
Control No. 2003-06-19-0005 |
Appendix A to Service Agreement No. 78845 | ||
Under Rate Schedule
|
FSS | |
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
and (Shipper)
|
Washington Gas Light Company |
Storage Contract Quantity 6,247,557 Dth
Maximum Daily Storage Quantity 105,920 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. shall be effective from June 1, 2004 through March 31, 2008.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supersede the Previous Appendix A, Revision No. N/A effective as of N/A, to the Service Agreement referenced above.
With the exception of this Appendix A, Revision No. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date :
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne
A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
|
Revision No. | |
|
Control No. 2003-06-19-0005 |
Appendix B
to Service Agreement No.
|
78845 | |
Under
Rate Schedule
|
FSS | |
Between
(Transporter)
|
Columbia Gas Transmission Corporation | |
and
(Shipper)
|
Washington Gas Light Company |
Superceded
Agreements:
|
||||
|
FSS | 53005 | ||
|
FSS | 71573 | ||
|
FSS | 73994 | ||
|
FSS | 75643 |
|
SERVICE AGREEMENT NO. 78846 | |
|
CONTROL NO. 2003-06-19-0006 |
FSS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FSS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. Transporter shall store quantities of gas for Shipper up to but not exceeding Shippers Storage Contract Quantity as specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2009 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish the Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
Revision No. | |
|
Control No. 2003-06-19-0006 |
Appendix B to Service Agreement No
.
|
78846 | |
Under Rate Schedule
|
FSS | |
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
and (Shipper)
|
Washington Gas Light Company |
Superceded
Agreements:
|
||||
|
FSS | 53005 | ||
|
FSS | 71573 | ||
|
FSS | 73994 | ||
|
FSS | 75643 |
|
SERVICE AGREEMENT NO. 78846 | |
|
CONTROL NO. 2003-06-19-0006 |
FSS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78846 | |
|
CONTROL NO. 2003-06-19-0006 |
FSS SERVICE AGREEMENT
Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date :
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
|
Revision No. | |
|
Control No. 2003-06-19-0006 |
Appendix A to Service Agreement No. 78846 | ||
Under Rate Schedule
|
FSS | |
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
and (Shipper)
|
Washington Gas Light Company |
Storage Contract Quantity 3,436,156 Dth
Maximum Daily Storage Quantity 58,256 Dth per day
CANCELLATION OF PREVIOUS APPENDIX A
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. shall be effective from June 1, 2004 through March 31, 2009.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supersede the Previous Appendix A, Revision No. N/A effective as of N/A, to the Service Agreement referenced above.
With the exception of this Appendix A, Revision No. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date :
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
EXHIBIT 10.8
|
SERVICE AGREEMENT NO. 78837 | |
|
CONTROL NO. 2003-06-18-0035 |
SST SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
|
Columbia Gas Transmission Corporation | |
|
(Transporter) | |
|
AND | |
|
Washington Gas Light Company | |
|
(Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper. .
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until October 31, 2005 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78837 | |
|
CONTROL NO. 2003-06-18-0035 |
SST SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager-Commercial Services and notices to Shipper shall be addressed to it at:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78837 | |
|
CONTROL NO. 2003-06-18-0035 |
SST SERVICE AGREEMENT
Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |
|
Control No. 2003-06-18-0035 |
Appendix A to Service Agreement No. 78837 | ||||
|
||||
|
Under Rate Schedule | SST | ||
|
||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
||||
|
and (Shipper) | Washington Gas Light Company |
October through March Transportation Demand 79,440 Dth/Day
April through September Transportation Demand 39,720 Dth/Day
Primary Receipt Points
Maximum
Daily
Scheduling
Scheduling
Quantity
Point No.
Point Name
(Dth/Day)
STORAGE WITHDRAWALS
STOW
79,440
|
Revision No. | |
|
Control No. 2003-06-18-0035 |
Appendix A to Service Agreement No. 78837 | ||
Under Rate Schedule
|
SST | |
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 79,440 |
|
Revision No. | |
|
Control No. 2003-06-18-0035 |
|
Appendix A to Service Agreement No. | 78837 | ||||
|
Under Rate Schedule | SST | ||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
and (Shipper) | Washington Gas Light Company |
1/
|
Application of MDDOs, DDQs, and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A | |
|
||
|
The following notes apply to all scheduling points on this contract: | |
|
||
GFN1
|
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR ANY SHIPPER SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH ABOVE. |
Superceded Agreements:
Revision No.
Control No.
2003-06-18-0035
78837
SST
Columbia Gas Transmission Corporation
Washington Gas Light Company
38089
71572
73993
75644
|
Revision No. | |
|
Control No. 2003-06-18-0035 |
Appendix A to Service Agreement No. 78837 | ||||
|
Under Rate Schedule | SST | ||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
and (Shipper) | Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through October 31, 2005
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
SERVICE AGREEMENT NO. 78838 | |
|
CONTROL NO. 2003-06-18-0046 |
SST SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
|
Columbia Gas Transmission Corporation | |
|
(Transporter) | |
|
AND | |
|
Washington Gas Light Company | |
|
(Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2007 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78838 | |
|
CONTROL NO. 2003-06-18-0046 |
SST SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78838 | |
|
CONTROL NO. 2003-06-18-0046 |
SST SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |
|
Control No. 2003-06-18-0046 |
Appendix A to Service Agreement No. 78838 | ||||
|
Under Rate Schedule | SST | ||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
and (Shipper) | Washington Gas Light Company |
October through March Transportation Demand 105,920 Dth/Day
April through September Transportation Demand 52,960 Dth/Day
Primary Receipt Points
Maximum
Daily
Scheduling
Scheduling
Quantity
Point No.
Point Name
(Dth/Day)
STORAGE
STOW
105,920
WITHDRAWALS
|
Revision No. | |
|
Control No. 2003-06-18-0046 |
Appendix A to Service Agreement No. 78838 | ||||
|
Under Rate Schedule | SST | ||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
and (Shipper) | Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||||||
78-30
|
WASHINGTON | 78-30 | 105,920 | |||||||||||||||||||||||||||
|
GAS-30 |
|
Revision No. | |
|
Control No. 2003-06-18-0046 |
|
Appendix A to Service Agreement No. | 78838 | ||||
|
Under Rate Schedule | SST | ||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
and (Shipper) | Washington Gas Light Company |
1/
|
Application of MDDOs, DDQs, and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A | |
|
||
|
The following notes apply to all scheduling points on this contract: | |
|
||
GFN1
|
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR ANY SHIPPER SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH ABOVE. |
Superceded Agreements:
Revision No.
Control No. 2003-06-18-0046
78838
SST
Columbia Gas Transmission Corporation
Washington Gas Light Company
38089
71572
73993
75644
|
Revision No. | |
|
Control No. 2003-06-18-0046 |
Appendix A to Service Agreement No. 78838 | ||||
|
Under Rate Schedule | SST | ||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
and (Shipper) | Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through March 31, 2007.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
SERVICE AGREEMENT NO. 78839 | |
|
CONTROL NO. 2003-06-18-0050 |
SST SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term. Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2008 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates. Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78839 | |
|
CONTROL NO. 2003-06-18-0050 |
SST SERVICE AGREEMENT
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78839 | |
|
CONTROL NO. 2003-06-18-0050 |
SST SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |
|
Control No. 2003-06-18-0050 |
Appendix A to Service Agreement No. 78839 | ||||
|
Under Rate Schedule | SST | ||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||
|
and (Shipper) | Washington Gas Light Company |
October through March Transportation Demand 105,920 Dth/Day
April through September Transportation Demand 52,960 Dth/Day
Primary Receipt Points
Maximum
Daily
Scheduling
Scheduling
Quantity
Point No.
Point Name
(Dth/Day)
STORAGE
WITHDRAWALS
STOW
105,920
|
Revision No. | |
|
Control No. 2003-06-18-0050 |
Appendix B to Service Agreement No.
|
78839 | |||
Under
Rate Schedule
|
SST | |||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
LOUDOUN
|
LOUDOUN LNG | LOUDOUN | 92,363 | |||||||||||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 105,920 | |||||||||||||||||||||||
|
|
Revision No. | |
|
Control No. 2003-06-18-0050 |
|
Appendix A to Service Agreement No. | 78839 | ||||
|
Under Rate Schedule | SST | ||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
and (Shipper) | Washington Gas Light Company |
1/
|
Application of MDDOs, DDQs, and ADQs shall be as follows: SST Services Agreement No. 50239 Appendix A | |
|
||
|
The following notes apply to all scheduling points on this contract: | |
|
||
GFN1
|
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR ANY SHIPPER SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH ABOVE. |
Superceded Agreements:
Revision No.
Control No. 2003-06-18-0050
78839
SST
Columbia Gas Transmission Corporation
Washington Gas Light Company
38089
71572
73993
75644
|
Revision No. | |||
|
Control No. 2003-06-18-0050 | |||
Appendix A to Service Agreement No. 78839 | ||||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through March 31, 2008.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
Washington Gas Light Company | ||||||||||
|
||||||||||
By: | /s/ Terry McCallister | |||||||||
|
||||||||||
Name:
|
Terry McCallister | |||||||||
|
||||||||||
Title:
|
President & COO | |||||||||
|
||||||||||
Date: | 4/8/04 | |||||||||
|
||||||||||
|
||||||||||
Columbia Gas Transmission Corporation | ||||||||||
|
||||||||||
By: | /s/ Jeanne A. Adkins | |||||||||
|
||||||||||
Name: | Jeanne A. Adkins | |||||||||
|
||||||||||
Title: | Manager Customer Services | |||||||||
|
||||||||||
Date: | May 7, 2004 | |||||||||
|
|
SERVICE AGREEMENT NO. 78840 | |
|
CONTROL NO. 2003-06-18-0052 |
SST SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective SST Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until March 31, 2009 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78840 | |
|
CONTROL NO. 2003-06-18-0052 |
SST SERVICE AGREEMENT
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78840 CONTROL NO. 2003-06-18-0052 |
SST SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
Washington Gas Light Company | ||||||||||
|
||||||||||
By: | /s/ Terry McCallister | |||||||||
|
||||||||||
Name:
|
Terry McCallister | |||||||||
|
||||||||||
Title:
|
President & COO | |||||||||
|
||||||||||
Date: | 4/8/04 | |||||||||
|
||||||||||
|
||||||||||
Columbia Gas Transmission Corporation | ||||||||||
|
||||||||||
By: | /s/ Jeanne A. Adkins | |||||||||
|
||||||||||
Name: | Jeanne A. Adkins | |||||||||
|
||||||||||
Title: | Manager Customer Services | |||||||||
|
||||||||||
Date: | May 7, 2004 | |||||||||
|
|
Revision No. | |||
|
Control No. 2003-06-18-0052 | |||
Appendix A to Service Agreement No. 78840 | ||||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
October through March Transportation Demand 58,256 Dth/Day
April through September Transportation Demand 29,128 Dth/Day
Primary Receipt Points
Maximum
Daily
Scheduling
Scheduling
Quantity
Point No.
Point Name
(Dth/Day)
STORAGE
WITHDRAWALS
STOW
58,256
|
Revision No. | |||
Appendix A to Service Agreement No. 78840 | Control No. 2003-06-18-0052 | |||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||||||||
78-28
|
WASHINGTON GAS-28 | 78-28 | 44,900 | |||||||||||||||||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 58,256 |
|
Revision No. | |||
Control No. 2003-06-18-0052 | ||||
Appendix A to Service Agreement No.
|
78840 | |||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
1/ | Application of MDDOs, DDQs, and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A |
The following notes apply to all scheduling points on this contract: |
GFN1
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE
AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM
DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN
TRANSPORTER AND SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO
QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs IN A
SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR ANY SHIPPER
SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH ABOVE.
|
Revision No. | |||
Control No. 2003-06-18-0052 | ||||
Appendix B
to Service Agreement No.
|
78840 | |||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Superceded Agreements:
SST 38089
SST 71572
SST 73993
SST 75644
|
Revision No. | |||
|
Control No. 2003-06-18-0052 | |||
Appendix A to Service Agreement No. 78840 | ||||
Under Rate Schedule
|
SST | |||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
and (Shipper)
|
Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through March 31, 2009.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
Washington Gas Light Company | ||||||||||
|
||||||||||
By: | /s/ Terry McCallister | |||||||||
|
||||||||||
Name:
|
Terry McCallister | |||||||||
|
||||||||||
Title:
|
President & COO | |||||||||
|
||||||||||
Date: | 4/8/04 | |||||||||
|
||||||||||
|
||||||||||
Columbia Gas Transmission Corporation | ||||||||||
|
||||||||||
By: | /s/ Jeanne A. Adkins | |||||||||
|
||||||||||
Name: | Jeanne A. Adkins | |||||||||
|
||||||||||
Title: | Manager - Customer Services | |||||||||
|
||||||||||
Date: | May 7, 2004 | |||||||||
|
|
Revision No. 3 | |||
|
Control No. 2003-07-31-0003 | |||
Appendix A to Service Agreement No. 50239 | ||||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
October through March Transportation Demand 7,114 Dth/Day
April through September Transportation Demand 3,557 Dth/Day
Primary Receipt Points
Maximum
Scheduling
Scheduling
Daily Quantity
Point No.
Point Name
(Dth/Day)
STORAGE WITHDRAWALS
STOW
7,114
|
Revision No. 3 | |||
|
Control No. 2003-07-31-0003 | |||
Appendix A to Service Agreement No. 50239 | ||||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
802675 | WGL Dranesville | 132,542 | 300 | FN02 | ||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
802677 | ROCKVILLE | 488,585 | 300 | FN02 | ||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
803276 | WGL Cedar Creek | 12,509 | 500 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
804581 | MANASSAS | 0 | 0 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
805007 | STRASBURG | 1,700 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
805181 | New Market | 750 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
805268 | Howell Metal Co. | 372 | 50 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
805439 | NINEVEH | 16,712 | 500 | |||||||||||||||||
78-28
|
WASHINGTON
GAS-28 |
805458 | BRINK | 45,000 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
807000 |
MAIN LINE
CUSTOMERS |
710 | ||||||||||||||||||
LOUDOUN
|
LOUDOUN LNG | 817762 | Loudoun TCO to LNG | 101,363 | 300 | FN02 | ||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
819683 | WOODSTOCK | 4,400 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
828715 | WGL Mt Jackson | 400 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
831526 |
ROCKVILLE HEATER
FUEL #1 |
0 |
|
Revision No. 3 | |||
Control No. 2003-07-31-0003 | ||||
|
||||
Appendix A to Service Agreement No.
|
50239 | |||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
831527 |
ROCKVILLE HEATER
FUEL #2 |
0 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
832737 | Mt. View Rendering Co. | 1,350 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
832797 | MT.VIEW HTR FUEL READING SLIP | 0 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
834217 | ASPHALT | 0 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
834308 | MIDDLEBURG | 960 | ||||||||||||||||||
78-28
|
WASHINGTON
GAS-28 |
835175 | WGL POOLESVILLE | 2,400 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
835804 | WGL Linton Hall | 7,200 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
835865 | LAKE MANASSAS | 1,440 | ||||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
836717 | WGL-CHANTILLY | 21,645 | 300 | |||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
853181 | HAMPSHIRE | 30,000 | FN01 | 300 | ||||||||||||||||
78-30
|
WASHINGTON
GAS-30 |
890191 |
SHENANDOAH
VALLEY |
48 |
|
Revision No. 3 | |||
|
Control No. 2003-07-31-0003 | |||
Appendix A to Service Agreement No.
|
50239 | |||
|
||||
Under Rate Schedule
|
SST | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
1/ | Application of MDDOs, DDQs, and ADQs shall be as follows: |
FN01
THE HAMPSHIRE INJECTION MDDO IS ZERO (0) DTH/D FROM NOVEMBER 1 THROUGH MARCH
31. IN NO EVENT SHALL THE HOURLY WITHDRAWAL QUANTITY EXCEED 105% OF 1/24TH OF
THE RATE SCHEDULE X39 WHICH CONTRACT DEMAND LEVEL IS BASED ON A CONVERSION
FACTOR OF 1.035 DTH PER MCF.
Revision No. 3
Control No. 2003-07-31-0003
50239
SST
Columbia Gas Transmission Corporation
Washington Gas Light Company
FN02
THE MAXIMUM DAILY DELIVERY OBLIGATIONS FOR LOUDOUN, DRANESVILLE AND ROCKVILLE SHALL APPLY ON AN HOURLY BASIS
AS FOLLOWS: THE MAXIMUM HOURLY FLOW RATE TRANSPORTER IS OBLIGATED TO
PROVIDE TO WASHINGTON GAS (WG), AT LOUDOUN, DRANESVILLE AND ROCKVILLE
WILL BE 5,490, 5,633, AND 20,765 DTH/HOUR RESPECTIVELY, PROVIDED WG
MAINTAINS A TOTAL FIRM ENTITLEMENT OF 751,087 DTH/DAY AND THE CURRENT
MAXIMUM DAILY DELIVERY OBLIGATIONS OF 131,758 DTH/DAY AT LOUDOUN,
132,542 DTH/DAY AT DRANESVILLE, AND 488,585 DTH/DAY AT ROCKVILLE AND
50,000 DTHS OF HAMPSHIRE (X-39) VOLUMES ARE NOMINATED, CONFIRMED AND
SCHEDULED (NCS) ON ANY GAS DAY.
THE MAXIMUM HOURLY FLOW RATE OBLIGATION OF 20,765 DTH/HOUR AT ROCKVILLE
IS CONTINGENT UPON 50,000 DTHS BEING NOMINATED, CONFIRMED, AND
SCHEDULED FROM HAMPSHIRE (X-39) ON ANY GAS DAY. THE MAXIMUM HOURLY FLOW
RATE OBLIGATION OF 20,765 DTH/HOUR WILL BE PROPORTIONATELY REDUCED WHEN
VOLUMES LESS THAN 50,000 DTHS ARE NOMINATED, CONFIRMED AND SCHEDULED
FROM HAMPSHIRE (X-39). FOR EXAMPLE, THE MAXIMUM HOURLY FLOW RATE
OBLIGATION AT ROCKVILLE WOULD BE 20,358 DTH/HOUR AND 20,561 DTH/HOUR
WHEN THE NOMINATED, CONFIRMED AND SCHEDULED QUANTITIES FROM HAMPSHIRE
(X-39) ARE ZERO (0) AND 25,000 DTHS ON ANY GAS DAY.
IF THERE IS A REDUCTION IN THE TOTAL FIRM ENTITLEMENT OR THE CURRENT
MAXIMUM DAILY DELIVERY OBLIGATIONS OF WG AT LOUDOUN, DRANESVILLE AND/OR
ROCKVILLE, THE MAXIMUM HOURLY FLOW RATE AT THESE POINTS WILL BE
DETERMINED AS FOLLOWS: LOUDOUN 1/24TH OF REVISED MDDO; DRANESVILLE 102%
OF 1/24TH OF THE REVISED MDDO; AND ROCKVILLE 1/24TH OF THE REVISED MDDO
PLUS THE HOURLY FLOW RATE ASSOCIATED WITH THE HAMPSHIRE (X-39) VOLUMES
REFERENCED ABOVE. THE HOURLY FLOW RATE INCREASE ASSOCIATED WITH ANY
INCREASES TO THE MDDOS AT LOUDOUN, DRANESVILLE AND/OR ROCKVILLE WILL
BE NEGOTIATED BUT THE INCREASE WILL NOT BE BELOW 1/24TH OF THE MDDO OR
TFE ADDITION.
ANY DIFFERENCE BETWEEN WGS ACTUAL HOURLY USAGE AT ROCKVILLE AND WGS
CONTRACTUAL HOURLY FLOW COMMITMENT AT ROCKVILLE WILL INCREASE WGS
HOURLY FLOW RIGHTS AT EITHER DRANESVILLE OR LOUDOUN, SUBJECT TO
FACILITY LIMITATIONS AND PRIMARY FIRM OBLIGATIONS AT THOSE POINTS.
THESE HOURLY FLOWRATE OBLIGATIONS WILL BE PROPORTIONATELY REDUCED BY 100% OF 1/24TH OF:
QUANTITIES NOMINATED, CONFIRMED, AND SCHEDULED UNDER WGS FTS SERVICE AGREEMENTS BELOW THE MAXIMUM
CONTRACT QUANTITY ON ANY GAS DAY.
FTS OR SST QUANTITIES THAT ARE NOMINATED, CONFIRMED, AND SCHEDULED TO A SECONDARY DELIVERY POINT, AND
ANY SST QUANTITIES REDUCED AS A RESULT OF SEASONAL ADJUSTMENTS.
|
Revision No. 3 | |||
|
Control No. 2003-07-31-0003 | |||
Appendix A to Service Agreement No.
|
50239 | |||
Under Rate Schedule
|
SST | |||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
and (Shipper)
|
Washington Gas Light Company |
IF THIRD PARTY SHIPPERS WITH PRIMARY DELIVERY POINTS AT THE ROCKVILLE
AND DRANESVILLE GATE STATIONS NOMINATE, CONFIRM, AND SCHEDULE CAPACITY
TO MLI 78-30 FOR DELIVERY TO THOSE PRIMARY DELIVERY POINTS,
ONE-TWENTY-FOURTH (1/24) OR THE ACTUAL CONTRACTUAL HOURLY FLOW RIGHT,
IF GREATER THAN 1/24, OF SUCH THIRD PARTY CAPACITY NOMINATED,
CONFIRMED, AND SCHEDULED FOR DELIVERY TO THOSE POINTS WILL BE AVAILABLE
TO WASHINGTON GAS AS THE CITY GATE OPERATOR IN ADDITION TO WASHINGTON
GAS OWN CONTRACTUAL HOURLY FLOW ENTITLEMENTS.
The following notes apply to all scheduling points on this contract:
GFN1
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND
SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION,
UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN TRANSPORTER AND
SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO
QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs
IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR
ANY SHIPPER SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH
ABOVE.
|
Revision No. 3 | |||||
|
||||||
|
Control No. 2003-07-31-0003 | |||||
Appendix A to Service Agreement No. 50239 | ||||||
|
||||||
|
Under Rate Schedule | SST | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
The Master list of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for purposes of listing valid secondary receipt and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 3 shall be effective June 1, 2004 through October 31, 2013.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 3 shall cancel and supersede the Previous Appendix A, Revision No. 2 effective as of November 1, 1999, to the Service Agreement referenced above.
[ ] Yes [X] No (Check applicable blank) All Gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 3 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date:
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
|
Revision No. 3 | |||||
|
||||||
|
Control No. 2003-07-31-0004 | |||||
Appendix A to Service Agreement No. 50240 | ||||||
|
||||||
|
Under Rate Schedule | SST | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
October through March Transportation Demand 40,000 Dth/Day
April through September Transportation Demand 20,000 Dth/Day
Primary Receipt Points
Maximum
Daily
Scheduling
Scheduling
Quantity
Point No.
Point Name
(Dth/Day)
STORAGE
STOW
40,000
WITHDRAWALS
|
Revision No. 3 | |||||
|
||||||
|
Control No. 2003-07-31-0004 | |||||
Appendix A to Service Agreement No. 50240 | ||||||
|
||||||
|
Under Rate Schedule | SST | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||
LOUDOUN
|
LOUDOUN LNG | LOUDOUN | 7,637 | |||||||||||||||
78-28
|
WASHINGTON GAS-28 | 78-28 | 2,122 | |||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 40,000 |
|
Revision No. 3 | |||||
|
||||||
|
Control No. 2003-07-31-0004 | |||||
Appendix A to Service Agreement No. 50240 | ||||||
|
||||||
|
Under Rate Schedule | SST | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
1/
|
Application of MDDOs, DDQs, and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A | |
|
||
|
The following notes apply to all scheduling points on this contract: | |
|
||
GFN1
|
THIS SERVICE AGREEMENT AND ITS EFFECTIVENESS ARE SUBJECT TO PRECEDENT AGREEMENT NO. 47741 BETWEEN BUYER AND SELLER DATED MAY 30, 1995. | |
|
||
|
UNLESS STATION SPECIFIC MDDOs ARE SPECIFIED IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, TRANSPORTERS AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY OTHER SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER, AT THE STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDDO QUANTITIES SET FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOs IN A SEPARATE FIRM SERVICE AGREEMENT BETWEEN TRANSPORTER AND SHIPPER OR ANY SHIPPER SHALL BE ADDITIVE TO THE INDIVIDUAL STATION MDDOs SET FORTH ABOVE. |
|
Revision No. 3 | |||||
|
||||||
|
Control No. 2003-07-31-0004 | |||||
Appendix A to Service Agreement No. 50240 | ||||||
|
||||||
|
Under Rate Schedule | SST | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through October 31, 2012.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date:
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
Exhibit 10.9
|
SERVICE AGREEMENT NO. 78833 | |
|
CONTROL NO. 2003-06-17-0013 |
FTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
|
Columbia Gas Transmission Corporation | |
|
(Transporter) | |
|
AND | |
|
Washington Gas Light Company | |
|
(Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term. Service under this Agreement shall commence as of June 1, 2004 , and shall continue in full force and effect until October 31, 2005 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates. Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78833 | |
|
CONTROL NO. 2003-06-17-0013 |
FTS SERVICE AGREEMENT
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to it at:
|
Washington Gas Light Company | |
|
Attn: Gas Acquisition | |
|
Room 320-B | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
ATTN: Tim Sherwood |
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78833 | |
|
CONTROL NO. 2003-06-17-0013 |
FTS SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister
|
|
Name:
|
Terry McCallister
|
|
Title:
|
President & COO
|
|
Date:
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins
|
|
Name:
|
Jeanne A. Adkins
|
|
Title:
|
Manager - Customer Services
|
|
Date:
|
May 7, 2004
|
|
Revision No. | |||||
|
||||||
|
Control No. 2003-06-17-0013 | |||||
Appendix A to Service Agreement No. 78833 | ||||||
|
||||||
|
Under Rate Schedule | FTS | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
Transportation Demand 64,043 Dth/Day
Primary Receipt Points
Minimum | ||||||||||||||||||||
Maximum | Receipt | |||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring |
Daily
Quantity |
Pressure
Obligation |
Hourly
Flowrate |
||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/Day)
|
(psig)
|
(Dtn/hour)
|
||||||||||||||
A01
|
KENOVA AGG POINT-19 | A01 | 12 | |||||||||||||||||
CNR02
|
BOLDMAN-18 | CNR02 | 4,100 | |||||||||||||||||
CNR14
|
HUFF CREEK-16 | CNR14 | 1,400 | |||||||||||||||||
1001
|
DIRECT APPALACHIAN | 1001 | 500 | |||||||||||||||||
801
|
TCO-LEACH | 801 | 58,031 |
|
Revision No. | |||||
|
||||||
|
Control No. 2003-06-17-0013 | |||||
Appendix A to Service Agreement No. 78833 | ||||||
|
||||||
|
Under Rate Schedule | FTS | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day)
1/
|
(Dth/Day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
78-30
|
WASHINGTON | 78-30 | 64,043 | |||||||||||||||||||||||
|
GAS-30 |
|
Revision No. | |||||
|
Control No. | 2003-06-17-0013 | ||||
Appendix A to Service Agreement No.
|
78833 | |||||
Under Rate Schedule
|
FTS | |||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||
and (Shipper)
|
Washington Gas Light Company |
1/ Application of MDDOs, DDQs and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A
|
Revision No. | |||||
|
Control No. | 2003-06-17-0013 | ||||
Appendix B to Service Agreement No.
|
78833 | |||||
Under Rate Schedule
|
FTS | |||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||
and (Shipper)
|
Washington Gas Light Company |
Superceded Agreements:
|
|||||
|
FTS | 38116 | |||
|
FTS | 71574 | |||
|
FTS | 73997 | |||
|
FTS | 73998 |
|
Revision No. | |||||
|
Control No. | 2003-06-17-0013 | ||||
Appendix A to Service Agreement No.
|
78833 | |||||
Under Rate Schedule
|
FTS | |||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||
and (Shipper)
|
Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through through October 31, 2005.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20___, to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
SERVICE AGREEMENT NO. 78834 | |||||
|
CONTROL NO. | 2003-06-17-0014 |
FTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until October 31, 2006 and from Year -to- Year thereafter unless/ terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. 78834 | |
|
CONTROL NO. 2003-06-17-0014 |
FTS SERVICE AGREEMENT
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager-Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. 78834 | |
|
CONTROL NO. 2003-06-17-0014 |
FTS SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
Transportation Demand 70,000 Dth/Day
Primary Receipt Points
Minimum | ||||||||||||||||||||||||
Maximum | Receipt | |||||||||||||||||||||||
Daily | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Quantity | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/Day)
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
801
|
TCO-LEACH | 801 | 70,000 |
|
Revision No. | |||||||
|
Control No. | 2003-06-17-0014 | ||||||
Appendix A to Service Agreement No.
|
78834 | |||||||
Under Rate Schedule
|
FTS | |||||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | ||||||||||||||||||||||||||||||
Daily | Design | Delivery | |||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | |||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | |||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day) 1/
|
(Dth/Day)
1/
|
Quantity
1/
|
(psig)
|
(Dth/hour)
|
|||||||||||||||||||||||
78-30
|
WASHINGTON | 78-30 | 70,000 | ||||||||||||||||||||||||||||
|
GAS-30 |
|
Revision No. | |||||||
Appendix A to Service Agreement No.
|
78834 | Control No. | 2003-06-17-0014 | |||||
Under Rate Schedule
|
FTS | |||||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||||
and (Shipper)
|
Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through October 31, 2006
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. __ effective as of , 20 __, to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |||||||
|
Control No. | 2003-06-17-0014 | ||||||
Appendix A to Service Agreement No.
|
78834 | |||||||
Under Rate Schedule
|
FTS | |||||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||||||
and (Shipper)
|
Washington Gas Light Company |
1/ Application of MDDOs, DDQs and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A
|
SERVICE AGREEMENT NO. | 78835 | ||||
|
CONTROL NO. | 2003-06-17-0015 |
FTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004 , by and between:
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1 . Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until October 31, 2007 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. | 78835 | ||||
|
CONTROL NO. | 2003-06-17-0015 |
FTS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager - Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition
Room 320-B
6801 Industrial Road
Springfield, VA 22151
ATTN: Tim Sherwood
until changed by either party by written notice.
|
SERVICE AGREEMENT NO. | 78835 | ||||
|
CONTROL NO. | 2003-06-17-0015 |
FTS SERVICE AGREEMENT
Section 5. Superseded Agreements . This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 |
|
Revision No. | |
|
Control No. 2003-06-17-0015 |
Appendix A to Service Agreement No. 78835 | ||||||
|
||||||
|
Under Rate Schedule | FTS | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
Transportation Demand 70,000 Dth/Day
Primary Receipt Points
Minimum | ||||||||||||||||||||||||
Maximum | Receipt | |||||||||||||||||||||||
Daily | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Quantity | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/Day)
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
801
|
TCO-LEACH | 801 | 70,000 |
|
Revision No. | |
|
Control No. 2003-06-17-0015 |
Appendix A to Service Agreement No. 78835 | ||||||
|
||||||
|
Under Rate Schedule | FTS | ||||
|
||||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
||||||
|
and (Shipper) | Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day) 1/
|
(Dth/day) 1/
|
Quantity 1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||||||||
LOUDOUN
|
LOUDOUN LNG | LOUDOUN | 70,000 | |||||||||||||||||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 70,000 |
|
Revision No. | |
|
Control No. 2003-06-17-0015 |
Appendix A to Service Agreement No.
|
78835 | |
|
||
Under Rate Schedule
|
FTS | |
|
||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
|
||
and (Shipper)
|
Washington Gas Light Company |
1/ Application of MDDOs, DDQs and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A
|
Revision No. | |
|
Control No. 2003-06-17-0015 |
Appendix B to Service Agreement No.
|
78835 | |
Under Rate Schedule
|
FTS | |
Between (Transporter)
|
Columbia Gas Transmission Corporation | |
and (Shipper)
|
Washington Gas Light Company | |
Superceded
Agreements:
|
|
FTS 38116 | |
|
FTS 71574 | |
|
FTS 73997 | |
|
FTS 73998 |
|
Revision No. | |
|
Control No. 2003-06-17-0015 |
Appendix A to Service Agreement No. 78835 | ||||||
|
Under Rate Schedule | FTS | ||||
|
Between (Transporter) | Columbia Gas Transmission Corporation | ||||
|
and (Shipper) | Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through October 31, 2007.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
SERVICE AGREEMENT NO. | 78836 | ||||
|
CONTROL NO. | 2003-06-17-0016 |
FTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 8th day of April , 2004, by and between:
Columbia Gas Transmission Corporation
(Transporter)
AND
Washington Gas Light Company
(Shipper)
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered. Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term. Service under this Agreement shall commence as of June 1, 2004, and shall continue in full force and effect until October 31, 2008 and from Year -to- Year thereafter unless terminated by either party upon 6 Months written notice to the other prior to the end of the initial term granted or any anniversary date thereafter. Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates which had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
|
SERVICE AGREEMENT NO. | 78836 | ||||
|
CONTROL NO. | 2003-06-17-0016 |
FTS SERVICE AGREEMENT
Section 4. Notices. Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas Light Company
Attn: Gas Acquisition Room 320-B 6801 Industrial Road Springfield, VA 22151 ATTN: Tim Sherwood |
until changed by either party by written notice.
SERVICE AGREEMENT NO.
78836
CONTROL NO. 2003-06-17-0016
FTS SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: See Appendix B.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04 | |
|
|
|
|
||
|
Columbia Gas Transmission Corporation | |
|
||
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
|
Revision No. | |||
|
Control No. 2003-06-17-0016 | |||
|
||||
Appendix A to Service Agreement No.
78836
|
||||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Transportation Demand 70,000 Dth/Day
Primary Receipt Points
Minimum | ||||||||||||||||||||||||
Maximum | Receipt | |||||||||||||||||||||||
Daily | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Quantity | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/Day)
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
801
|
TCO-LEACH | 801 | 70,000 |
|
Revision No. | |||
|
Control No. 2003-06-17-0016 | |||
|
||||
Appendix A to Service Agreement No. 78836 | ||||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
Primary Delivery Points
Maximum | Minimum | |||||||||||||||||||||||||||||||
Daily | Design | Delivery | ||||||||||||||||||||||||||||||
Delivery | Daily | Aggregate | Pressure | Hourly | ||||||||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Obligation | Quantity | Daily | Obligation | Flowrate | ||||||||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/day) 1/
|
(Dth/Day) 1/
|
Quantity 1/
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||||||||
LOUDOUN
|
LOUDOUN LNG | LOUDOUN | 22,363 | |||||||||||||||||||||||||||||
78-28
|
WASHINGTON GAS-28 | 78-28 | 44,900 | |||||||||||||||||||||||||||||
78-30
|
WASHINGTON GAS-30 | 78-30 | 70,000 |
|
Revision No. | |||
|
Control No. 2003-06-17-0016 | |||
|
||||
Appendix A to Service Agreement No. | 78836 | |||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas Light Company |
1/ Application of MDDOs, DDQs and ADQs shall be as follows: SST Service Agreement No. 50239 Appendix A |
Revision No.
Control No. 2003-06-17-0016
Appendix B to Service Agreement No.
78836
FTS
Columbia Gas Transmission Corporation
Washington Gas Light Company
FTS
38116
FTS
71574
FTS
73997
FTS
73998
|
Revision No. | |||
|
Control No. 2003-06-17-0016 | |||
|
||||
Appendix A to Service Agreement No.
|
78836 | |||
Under Rate Schedule
|
FTS | |||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
and (Shipper)
|
Washington Gas Light Company |
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective June 1, 2004 through October 31, 2008.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supercede the previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[X] Yes [ ] No (Check applicable blank) All gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule SST Appendix A, Revision No. 3 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0, all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas Light Company | |
|
||
By:
|
/s/ Terry McCallister | |
|
|
|
Name:
|
Terry McCallister | |
|
|
|
Title:
|
President & COO | |
|
|
|
Date:
|
4/8/04
|
|
|
||
|
Columbia Gas Transmission Corporation | |
By:
|
/s/ Jeanne A. Adkins | |
|
|
|
Name:
|
Jeanne A. Adkins | |
|
|
|
Title:
|
Manager - Customer Services | |
|
|
|
Date:
|
May 7, 2004 | |
|
|
Exhibit 10.10
AGREEMENT ID |
SERVICE AGREEMENT
NO. 77323
|
|
536 |
CONTROL NO. 2003-11-25-0016
|
|
|
FTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 3 day of December , 2003 , by and between:
Columbia Gas Transmission Corporation
(Transporter) AND Washington Gas (Shipper) |
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Section 1. Service to be Rendered . Transporter shall perform and Shipper shall receive service in accordance with the provisions of the effective FTS Rate Schedule and applicable General Terms and Conditions of Transporters FERC Gas Tariff, Second Revised Volume No. 1 (Tariff), on file with the Federal Energy Regulatory Commission (Commission), as the same may be amended or superseded in accordance with the rules and regulations of the Commission. The maximum obligation of Transporter to deliver gas hereunder to or for Shipper, the designation of the points of delivery at which Transporter shall deliver or cause gas to be delivered to or for Shipper, and the points of receipt at which Shipper shall deliver or cause gas to be delivered, are specified in Appendix A, as the same may be amended from time to time by agreement between Shipper and Transporter, or in accordance with the rules and regulations of the Commission. Service hereunder shall be provided subject to the provisions of Part 284. 223 of Subpart G of the Commissions regulations. Shipper warrants that service hereunder is being provided on behalf of Shipper.
Section 2. Term . Service under this Agreement shall commence as of November 27, 2003, and shall continue in full force and effect until October 31, 2023 . Pre-granted abandonment shall apply upon termination of this Agreement, subject to any right of first refusal Shipper may have under the Commissions regulations and Transporters Tariff.
Section 3. Rates . Shipper shall pay Transporter the charges and furnish Retainage as described in the above-referenced Rate Schedule, unless otherwise agreed to by the parties in writing and specified as an amendment to this Service Agreement. Transporter may agree to discount its rate to Shipper below Transporters maximum rate, but not less than Transporters minimum rate. Such discounted rate may apply to: a) specified quantities (contract demand or commodity quantities); b) specified quantities above or below a certain level or all quantities if quantities exceed a certain level; c) quantities during specified time periods; d) quantities at specified points, locations, or other defined geographical areas; and e) that a specified discounted rate will apply in a specified relationship to the quantities actually transported (i.e., that the reservation charge will be adjusted in a specified relationship to quantities actually transported). In addition, the discount agreement may include a provision that if one rate component which was at or below the applicable maximum rate at the time the discount agreement was executed subsequently exceeds the applicable maximum rate due to a change in Transporters maximum rate so that such rate component must be adjusted downward to equal the new applicable maximum rate, then other rate components may be adjusted upward to achieve the agreed overall rate, so long as none of the resulting rate components exceed the maximum rate applicable to that rate component. Such changes to rate components shall be applied prospectively, commencing with the date a Commission order accepts revised tariff sheets. However, nothing contained herein shall be construed to alter a refund obligation under applicable law for any period during which rates had been charged under a discount agreement exceeded rates which ultimately are found to be just and reasonable.
SERVICE AGREEMENT NO. 77323
CONTROL NO. 2003-11-25-0016
FTS SERVICE AGREEMENT
Section 4. Notices . Notices to Transporter under this Agreement shall be addressed to it at Post Office Box 1273, Charleston, West Virginia 25325-1273, Attention: Manager Commercial Services and notices to Shipper shall be addressed to it at:
Washington Gas
Attn: Gas Acquisition Room 320-B 6801 Industrial Road Springfield, VA 22151 ATTN: Tim Sherwood |
until changed by either party by written notice.
SERVICE AGREEMENT NO. 77323
CONTROL NO. 2003-11-25-0016
FTS SERVICE AGREEMENT
Section 5. Superseded Agreements. This Service Agreement supersedes and cancels, as of the effective date hereof, the following Service Agreements: N/A.
|
Washington Gas | |||
|
||||
By:
|
/s/ Terry McCallister | |||
|
|
|||
Name:
|
Terry McCallister | |||
|
|
|||
Title:
|
President and Chief Operating Officer | |||
|
|
|||
Date:
|
||||
|
|
|||
|
||||
|
Columbia Gas Transmission Corporation | |||
|
||||
By:
|
/s/ T. N. Brasselle | |||
|
|
|||
Name:
|
T. N. Brasselle | |||
|
|
|||
Title:
|
MGR Customer Services | |||
|
|
|||
Date:
|
MAR 23 2004 | |||
|
|
|
Revision No. 0 | |||
|
Control No. 2003-11-25-0016 | |||
Appendix A to Service Agreement No. 77323 | ||||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas |
Transportation Demand 30,395 Dth/Day
Primary Receipt Points
|
||||||||||||||||||||||||
Minimum | ||||||||||||||||||||||||
Maximum | Receipt | |||||||||||||||||||||||
Daily | Pressure | Hourly | ||||||||||||||||||||||
Scheduling | Scheduling | Measuring | Measuring | Quantity | Obligation | Flowrate | ||||||||||||||||||
Point No.
|
Point Name
|
Point No.
|
Point Name
|
(Dth/Day)
|
(psig)
|
(Dth/hour)
|
||||||||||||||||||
F1
|
PAULDING-3 | F1 | 9,146 | |||||||||||||||||||||
F4
|
MONCLOVA-1 | F4 | 21,249 |
Revision No. 0
Control No. 2003-11-25-0016
Appendix A to Service Agreement No. 77323
FTS
Columbia Gas Transmission Corporation
Washington Gas
Primary Delivery Points
Maximum
Minimum
Daily
Design
Delivery
Delivery
Daily
Aggregate
Pressure
Hourly
Scheduling
Scheduling
Measuring
Measuring
Obligation
Quantity
Daily
Obligation
Flowrate
Point No.
Point Name
Point No.
Point Name
(Dth/day)
1/
(Dth/Day)
1/
Quantity
1/
(psig)
(Dth/hour)
LOUDOUN LNG
817762
Loudoun TCO to LNG
30,395
|
Revision No. 0 | |||
|
Control No. 2003-11-25-0016 | |||
Appendix A to Service Agreement No.
|
77323 | |||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas |
1/ Application of MDDOs, DDQs and ADQs shall be as follows:
|
Revision No. 0 | |||
|
Control No. 2003-11-25-0016 | |||
Appendix A to Service Agreement No. 77323 | ||||
|
||||
Under Rate Schedule
|
FTS | |||
|
||||
Between (Transporter)
|
Columbia Gas Transmission Corporation | |||
|
||||
and (Shipper)
|
Washington Gas |
The Master list of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Transporters Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points and delivery points.
[ ] Yes [X] No (Check applicable blank) Transporter and Shipper have mutually agreed to a Regulatory Restructuring Reduction Option pursuant to Section 42 of the General Terms and Conditions of Transporters FERC Gas Tariff.
[ ] Yes [X] No (Check applicable blank) Shipper has a contractual right of first refusal equivalent to the right of first refusal set forth from time to time in Section 4 of the General Terms and Conditions of Transporters FERC Gas Tariff.
Service pursuant to this Appendix A, Revision No. 0 shall be effective November 27, 2003 through October 31, 2023.
[X] Yes [ ] No (Check applicable blank) This Appendix A, Revision No. 0 shall cancel and supersede the Previous Appendix A, Revision No. effective as of , 20 , to the Service Agreement referenced above.
[ ] Yes [X] No (Check applicable blank) All Gas shall be delivered at existing points of interconnection within the MDDOs, and/or ADQs, and/or DDQs, as applicable, set forth in Transporters currently effective Rate Schedule FTS Appendix A, Revision No. 0 with Shipper, which for such points set forth are incorporated herein by reference.
With the exception of this Appendix A, Revision No. 0 all other terms and conditions of said Service Agreement shall remain in full force and effect.
|
Washington Gas | |||
|
||||
By:
|
/s/ Terry McCallister | |||
|
|
|||
Name:
|
Terry McCallister | |||
|
|
|||
Title:
|
President and Chief Operating Officer | |||
|
|
|||
Date:
|
||||
|
|
|||
|
||||
|
Columbia Gas Transmission Corporation | |||
|
||||
By:
|
/s/ T. N. Brasselle | |||
|
|
|||
Name:
|
T. N. Brasselle | |||
|
|
|||
Title:
|
MGR Customer Services | |||
|
|
|||
Date:
|
MAR 23 2004 | |||
|
|
Exhibit 10.11
Contract # 1.225 4
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
WASHINGTON GAS LIGHT COMPANY
Dated
January 1, 1996
AGREEMENT ID | ||
193.0 | ||
|
SERVICE AGREEMENT
THIS AGREEMENT entered into this 1st day of January, 1996 by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as Seller, first party, and WASHINGTON GAS LIGHT COMPANY, hereinafter referred to as Buyer, second party,
W I T N E S S E T H
WHEREAS, Seller and Buyer are parties to a firm transportation agreement dated February 1, 1992 (TGPL system contract number .3705); and
WHEREAS, Seller and Frederick Gas Company, Inc. are parties to a firm transportation agreement dated February 1, 1992 (TGPL system contract number .3927); and
WHEREAS, as a result of the merger of Buyer and its subsidiary Frederick Gas Company, Inc. effective January 1, 1996, Frederick Gas Company, Inc. will no longer exist as a separate entity; and
WHEREAS, Buyer wishes to consolidate such firm transportation agreements into one agreement, effective as of the date of the merger, for purposes of administrative ease; and
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
1. Subject to the terms and provisions of this agreement and of Sellers Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity (TCQ) of 59,500 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Sellers FERC Gas Tariff.
ARTICLE II
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Sellers pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) of Sellers pipeline system at such point(s) of receipt. In the event the maximum operating pressure(s) of Sellers pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
2
SERVICE AGREEMENT (CONTINUED)
ARTICLE III
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
This agreement shall be effective as of January 1, 1996 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time March 31, 2009 and thereafter until terminated by Seller or Buyer upon at least three (3) years written notice ; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Sellers reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 32 of the General Terms and Conditions of Sellers Volume No. 1 Tariff. As set forth in Section 8 of Article II of Sellers August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et. al., (a) pregranted abandonment under Section 284.221(d) of the Commissions Regulations shall not apply to any long term conversions from firm sales service to transportation service under Sellers Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service .
ARTICLE V
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Sellers Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Sellers FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Sellers Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Sellers Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyers request for service under Sellers Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
3
SERVICE AGREEMENT (CONTINUED)
ARTICLE VI
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto:
One Service Agreement between Buyer and Seller,
dated February 1, 1992 (TGPL system contract number .3705);
and
One Service Agreement between Frederick Gas Company, Inc. and Seller dated February 1, 1992 (TGPL system contract number .3927). |
2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
(a) |
If to Seller:
Transcontinental Gas Pipe Line Corporation P.O. Box 1396 Houston, Texas, 77251-1396 Attention: Vice President - Customer Service |
|||
(b) |
If to Buyer:
Washington Gas Light Company 6801 Industrial Road Springfield, VA 22151 Attention; Stephen J. Shaiko Executive Director - Gas Supply |
Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.
4
SERVICE AGREEMENT (CONTINUED)
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller)
| ||
By: |
/s/ Frank J. Ferazzi
Frank J. Ferazzi Vice President-Customer Service |
|
WASHINGTON GAS LIGHT COMPANY
(Buyer)
|
||
By:
Title: |
/s/ James H. DeGraffenreidt, Jr.
James H. DeGraffenreidt, Jr. President and Chief Operating Officer |
EXHIBIT A
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
1.
10,115
2.
10,115
3.
10,115
4.
10,115
5.
10,115
6.
10,115
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
7.
10,115
8.
10,115
9.
10,115
10.
10,115
11.
10,115
12.
10,115
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
13.
10,115
14.
10,115
15.
10,115
16.
10,115
17.
24,990
18.
24,990
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
19.
24,990
20.
24,990
21.
24,990
22.
36,295
23.
36,295
24.
36,295
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
25.
36,295
26.
36,295
27.
36,295
28.
36,295
29.
36,295
30.
23,205
31.
23,205
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
32.
23,205
33.
23,205
34.
23,205
35.
23,205
36.
23,205
37.
23,205
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
38.
23,205
39.
59,500
40.
59,500
41.
59,500
42.
59,500
43.
59,500
44.
59,500
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
45.
59,500
46.
59,500
47.
59,500
48.
59,500
49.
59,500
50.
59,500
51.
59,500
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
52.
59,500
53.
59,500
54.
59,500
55.
59,500
56.
59,500
57.
59,500
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
58.
59,500
59.
59,500
60.
59,500
61.
59,500
62.
59,500
63.
59,500
64.
59,500
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/day)*
65.
59,500
66.
59,500
67.
59,500
68.
59,500
69.
59,500
70.
59,500
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/day)*
|
|||||
71. |
Existing Point of Interconnection
between Seller and Meter named Clarke
County-Koch at M.P. 757.29 in Clarke
County, Mississippi. (Clarke County-
Koch-TP#5566)
|
59,500 | ||||
72. |
Existing Point of Interconnection between
Sellers mainline and Mobile Bay Lateral
at M. P. 784.66 in Choctaw County, Alabama.
(Station 85 - Mainline Pool TP#6971)
|
59,500 | ||||
73. |
Existing Point of Interconnection between
Seller and Magnolia Pipeline in Chilton
County, Alabama. (Magnolia Pipeline
Interconnect-TP#1808)
|
59,500 | ||||
74. |
Existing Point of Interconnection between
Seller and Southern Natural Gas Company,
(Seller Meter No. 4087) at Jonesboro,
Clayton County, Georgia. (Jonesboro-SNG-
TP#6141)
|
59,500 | ||||
75. |
Existing Point of Interconnection between
Seller and Columbia Gas Transmission (Seller
Meter No. 7157 at Dranesville, Fairfax
County, Virginia. (Dranesville-Colgas-
TP#6068) **
|
4,500 |
Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyers Cumulative Mainline Capacity Entitlement for such point(s) of receipt.
* | These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. | |
** | Receipt of gas by displacement only . |
EXHIBIT B
Maximum Daily | ||||||||
Point(s) of Delivery and Pressures**
|
Firm Quantity (Mcf/d)***
|
|||||||
1. |
Station 54 *
|
|||||||
2. |
Herndon Meter Station,
located at milepost 1598.81 on Sellers main transmission line,
adjacent to State Highway 1212 on the east side and State Highway
606 on the north side Fairfax County, Virginia.
|
|
|
55,000
|
|
|||
3 | Bull Run Meter Station, located at milepost 1583.35 on Sellers main transmission line, adjacent to Transcos Compressor Station 185 located in Prince William County, Virginia. |
55,000 *
|
1.035 =
|
56,925
|
DTH/D
|
|||
4. | Frederick Meter Station, located at milepost 1614.46 on Sellers main transmission line near Maryland State Highway No. 115, approximately 3-1/2 miles northeasterly from the City of Rockville, Montgomery County, Maryland. |
4,500 *
|
1.035 =
|
4,658
|
DTH/C
|
|||
|
|
|||||||
|
61,583 | |||||||
5. |
Sellers Eminence
Storage Field Covington County, Mississippi.
|
59,500 |
*Delivery to Sellers Washington Storage Field for injection into storage is subject to the terms, conditions and limitations of Sellers WSS Rate Schedule.
**Subject to the conditions contained in this Agreement, Seller shall make deliveries of gas for the account of Buyer at the Point(s) of Delivery specified above at such pressures as may be available from time to time in Sellers line serving such Point(s) of Delivery not to exceed maximum allowable operating pressure, but not less that the minimum pressure specified in either Sellers FERC tariff or any other superseding agreements for service for deliveries at the Point(s) of Delivery.
***For reservation charge billing purposes 55,000 Mcf/d will be billed at the Zone 5 rate and 4,500 Mfc/d at the Zone 6 rate. For commodity
volumes, all volumes delivered at the Herndon and Bull Run meter stations will be billed at the Zone 5 commodity rate and all volumes delivered at the Frederick meter station will be billed at the Zone 6 commodity rate.
Exhibit 10.12
Contract # 1.0433
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
WASHINGTON GAS LIGHT COMPANY
April 1, 1995
AGREEMENT ID | ||
198.0 | ||
|
SERVICE AGREEMENT
THIS AGREEMENT entered into this 1st day of April, 1995, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as Seller, first party, and WASHINGTON GAS LIGHT COMPANY, hereinafter referred to as Buyer, second party,
WITNESSETH
WHEREAS, pursuant to the requirements of Order Nos. 636, 636-A and 636-B, issued by the Federal Energy Regulatory Commission, Columbia Gas Transmission Corporation (Columbia) has assigned to Buyer upstream capacity previously provided under the Transportation Agreement dated October 1, 1987 (System Contract 0.2255); and
WHEREAS, upon the effective date of this agreement, the contractual arrangement between Columbia and Seller is terminated and abandonment of service under the Transportation Agreement dated October 1, 1987 (System Contract 0.2255) is automatically authorized; and
WHEREAS, Buyer has been assigned a portion of Columbias capacity previously provided under the Transportation Agreement dated October 1, 1987 (System Contract 0.2255), and agrees to such assignment and assumes Columbias obligations pursuant to the Service Agreement and Sellers FT Rate Schedule of Vol. 1 of its FERC Gas Tariff; and
WHEREAS, Seller will provide service hereunder to Buyer pursuant to Sellers blanket certificate authorization and Rate Schedule FT for the assigned capacity designated hereinbelow.
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
1. Subject to the terms and provisions of this agreement and of Sellers Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity (TCQ) of 6,250 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Sellers FERC Gas Tariff.
SERVICE AGREEMENT
ARTICLE II
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Sellers pipeline system at the varying pressures that may exist in such system from time to time; provided, however, the pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) of Sellers pipeline system at such point(s) of receipt. In the event the maximum operating pressure(s) of Sellers pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
See Exhibit A, attached hereto, for points of receipt.
ARTICLE III
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See Exhibit B, attached hereto, for points of delivery and pressures.
ARTICLE IV
This agreement shall be effective as of April 1, 1995 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time February 2, 1998 and thereafter until terminated by Seller or Buyer upon at least six (6) months prior written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Sellers reasonable judgement fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Sellers Rate Schedule FT. As set forth in Section 8 of Article II of Sellers August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et.al., (a) pregranted abandonment under Section 284.221(d) of the Commissions Regulations shall not apply to any long term conversions from firm sales service to transportation service under Sellers Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from
SERVICE AGREEMENT
conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service.
ARTICLE V
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Sellers Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Sellers FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Sellers Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Sellers Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyers request for service under Sellers Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
ARTICLE VI
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s):
Transportation Agreement dated October 1, 1987 (System Contract 0.2255) between Transcontinental Gas Pipe Line Corporation and Columbia Gas Transmission; specifically for that portion of capacity provided in Article I above. |
2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect
SERVICE AGREEMENT
to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
(a) |
If to Seller:
Transcontinental Gas Pipe Line Corporation P.O. Box 1396 Houston, Texas 77251 Attention: Customer Services |
|
(b) |
If to Buyer:
Washington Gas Light Company 6801 Industrial Road Springfield, Virginia 22151 Attn: Mr. Frank J. Hollewa |
Such addresses may be changed from time to time by mailing appropriate notice thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE
CORPORATION
(Seller) | ||
By: |
/s/ James P. Avioli
James P. Avioli Vice President, Gas Control |
|
WASHINGTON GAS LIGHT COMPANY | ||
By: |
/s/ Frank J. Hollewa
Frank J. Hollewa Senior Vice President, Gas Supply |
EXHIBIT A
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
1.
1,562
2.
1,562
3.
1,562
4.
1,562
5.
1,562
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
6.
2,750
7.
2,750
8.
2,750
9.
2,750
10.
2,750
11.
2,750
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
12.
2,750
13.
2,750
14.
3,500
15.
3,500
16.
3,500
17.
3,500
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
18.
3,500
19.
3,500
20.
3,500
21.
3,500
22.
3,500
23.
6,250
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
24.
6,250
25.
6,250
26.
6,250
27.
6,250
28.
6,250
29.
6,250
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
30.
6,250
31.
6,250
32.
6,250
33.
6,250
34.
6,250
35.
6,250
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
36.
6,250
37.
6,250
38.
6,250
39.
6,250
40.
6,250
41.
6,250
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
42.
6,250
43.
6,250
44.
6,250
45.
6,250
46.
6,250
47.
6,250
48.
6,250
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/Day)
49.
6,250
50.
6,250
51.
6,250
52.
6,250
53.
6,250
54.
6,250
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/Day)
|
|||||
55. |
Existing Point of Interconnection
between Seller and Meter named
Clarke County-Koch at M.P. 757.29
in Clarke County, Mississippi.
(Clarke County-Koch-TP#5566)
|
6,250 | ||||
56. |
Existing Point of Interconnection
between Sellers mainline and
Mobile Bay Lateral at M.P. 784.66
in Choctaw County, Alabama
(Station 85 - Mainline Pool TP#6971)
|
6,250 | ||||
57. |
Existing Point of Interconnection
between Seller and Magnolia
Pipeline in Chilton County,
Alabama. (Magnolia Pipeline
Interconnect-TP#1808)
|
6,250 | ||||
58. |
Existing Point of Interconnection
between Seller and Southern Natural
Gas Company, (Seller Meter No.
4087) at Jonesboro, Clayton County,
Georgia. (Jonesboro-SNG-TP#6141)
|
6,250 |
Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyers Cumulative Mainline Capacity Entitlement for such point(s) of receipt.
* | These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. | |
** | Receipt of gas by displacement only. |
EXHIBIT B
Points of Delivery
Pressure(s)
A point of interconnection
between the facilities of
Columbia Gas Transmission and
Transco at Dranesville Meter
Station located at mile post
1599.40 on Transcos main
transmission line, located
two (2) miles eastward from
Dranesville, Virginia on
Virginia Highway #7
Not less than fifty (50) pounds
per square inch gauge or at
such other pressures as may be
agreed upon in the day-to-day
operations of Buyer and
Seller.
Exhibit 10.13
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
between
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
and
WASHINGTON GAS LIGHT COMPANY
DATED
AUGUST 1, 1991
AGREEMENT ID | ||
267. | ||
|
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
THIS AGREEMENT entered into this 1st day of August, 1991, by and between TRANSCONTINENTAL GAS PIPE LINE CORPORATION, a Delaware corporation, hereinafter referred to as Seller, first party, and WASHINGTON GAS LIGHT COMPANY, hereinafter referred to as Buyer, second party,
W I T N E S S E T H
WHEREAS, Seller has offered to interested parties pursuant to a letter dated December 11, 1987 certain firm transportation capacity under Sellers Rate Schedule FT; and
WHEREAS, Buyer has nominated for firm transportation service pursuant to the December 11, 1987 letter; and
WHEREAS, Seller agrees to receive, transport and redeliver or cause the redelivery of such quantities of natural gas as requested under the terms and conditions hereinafter set forth;
NOW, THEREFORE, Seller and Buyer agree as follows:
ARTICLE I
1. Subject to the terms and provisions of this agreement and of Sellers Rate Schedule FT, Buyer agrees to deliver or cause to be delivered to Seller gas for transportation and Seller agrees to receive, transport and redeliver natural gas to Buyer or for the account of Buyer, on a firm basis, up to the dekatherm equivalent of a Transportation Contract Quantity (TCQ) of 1,750 Mcf per day.
2. Transportation service rendered hereunder shall not be subject to curtailment or interruption except as provided in Section 11 of the General Terms and Conditions of Sellers FERC Gas Tariff.
ARTICLE II
Buyer shall deliver or cause to be delivered gas at the point(s) of receipt hereunder at a pressure sufficient to allow the gas to enter Sellers pipeline system at the varying pressures that may exist in such system from time to time; provided, however, that such pressure of the gas delivered or caused to be delivered by Buyer shall not exceed the maximum operating pressure(s) specified below. In the event the maximum operating pressure(s) of Sellers pipeline system, at the point(s) of receipt hereunder, is from time to time increased or decreased, then the maximum allowable pressure(s) of the gas
1
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
delivered or caused to be delivered by Buyer to Seller at the point(s) of receipt shall be correspondingly increased or decreased upon written notification of Seller to Buyer. The point(s) of receipt for natural gas received for transportation pursuant to this agreement shall be:
See EXHIBIT A for Points of Receipt
ARTICLE III
Seller shall redeliver to Buyer or for the account of Buyer the gas transported hereunder at the following point(s) of delivery and at a pressure(s) of:
See EXHIBIT B for Points of Delivery
ARTICLE IV
This agreement shall be effective as of August 1, 1991 and shall remain in force and effect until 8:00 a.m. Eastern Standard Time March 2, 1998 and thereafter until terminated by Seller or Buyer upon at least three (3) years written notice; provided, however, this agreement shall terminate immediately and, subject to the receipt of necessary authorizations, if any, Seller may discontinue service hereunder if (a) Buyer, in Sellers reasonable judgment fails to demonstrate credit worthiness, and (b) Buyer fails to provide adequate security in accordance with Section 8.3 of Sellers Rate Schedule FT. As set forth in Section 8 of Article II of Sellers August 7, 1989 revised Stipulation and Agreement in Docket Nos. RP88-68 et. al., (a) pregranted abandonment under Section 284.221(d) of the Commissions Regulations shall not apply to any long term conversions from firm sales service to transportation service under Sellers Rate Schedule FT and (b) Seller shall not exercise its right to terminate this service agreement as it applies to transportation service resulting from conversions from firm sales service so long as Buyer is willing to pay rates no less favorable than Seller is otherwise able to collect from third parties for such service.
ARTICLE V
1. Buyer shall pay Seller for natural gas delivered to Buyer hereunder in accordance with Sellers Rate Schedule FT and the applicable provisions of the General Terms and Conditions of Sellers FERC Gas Tariff as filed with the Federal Energy Regulatory Commission, and as the same may be legally amended or superseded from
2
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
time to time. Such Rate Schedule and General Terms and Conditions are by this reference made a part hereof.
2. Seller and Buyer agree that the quantity of gas that Buyer delivers or causes to be delivered to Seller shall include the quantity of gas retained by Seller for applicable compressor fuel, line loss make-up (and injection fuel under Sellers Rate Schedule GSS, if applicable) in providing the transportation service hereunder, which quantity may be changed from time to time and which will be specified in the currently effective Sheet No. 44 of Volume No. 1 of this Tariff which relates to service under this agreement and which is incorporated herein.
3. In addition to the applicable charges for firm transportation service pursuant to Section 3 of Sellers Rate Schedule FT, Buyer shall reimburse Seller for any and all filing fees incurred as a result of Buyers request for service under Sellers Rate Schedule FT, to the extent such fees are imposed upon Seller by the Federal Energy Regulatory Commission or any successor governmental authority having jurisdiction.
ARTICLE VI
1. This Agreement supersedes and cancels as of the effective date hereof the following contract(s) between the parties hereto:
Agreement between Buyer and Seller dated April 10, 1990.
2. No waiver by either party of any one or more defaults by the other in the performance of any provisions of this agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or different character.
3. The interpretation and performance of this agreement shall be in accordance with the laws of the State of Texas, without recourse to the law governing conflict of laws, and to all present and future valid laws with respect to the subject matter, including present and future orders, rules and regulations of duly constituted authorities.
4. This agreement shall be binding upon, and inure to the benefit of the parties hereto and their respective successors and assigns.
5. Notices to either party shall be in writing and shall be considered as duly delivered when mailed to the other party at the following address:
3
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
SERVICE AGREEMENT
(a) |
If to Seller:
Transcontinental Gas Pipe Line Corporation P.O. Box 1396 Houston, Texas 77251 |
(b) |
If to Buyer:
Washington Gas Light Company 6801 Industrial Road Springfield, Virginia 22151 Attention: Mr. Frank Hollewa |
Such addresses may be changed from to time by mailing appropriate notice thereof to the other party by certified or registered mail.
IN WITNESS WHEREOF, the parties hereto have caused this agreement to be signed by their respective officers or representatives thereunto duly authorized.
TRANSCONTINENTAL GAS PIPE LINE CORPORATION | |
(Seller) |
By | ||||
|
||||
Thomas E. Skains
Senior Vice President Transportation and Customer Services |
||||
WASHINGTON GAS LIGHT COMPANY
(Buyer) |
||||
By | /s/ [ILLEGIBLE] | |||
|
||||
Title: Vice Chairman of the Board | ||||
|
4
System Contract #.2275
TRANSCONTINENTAL GAS PIPE LINE CORPORATION |
EXHIBIT A
(FT)
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/d)*
|
|||||
1.
|
Suction Side of Sellers Compressor Station 30 at the Existing Point of Interconnection between Sellers Central Texas Lateral and Sellers Mainline at Wharton County, Texas. (Station 30 TP# 7133) | 298 | ||||
2.
|
Existing Point of Interconnection between Seller and Valero Transmission Company (Seller Meter No. 3396) at Wharton County, Texas. (Wharton Valero TP# 6690) | 298 | ||||
3.
|
Existing Point of Interconnection between Seller and Meter named Spanish Camp (Seller Meter No. 3365) Wharton County, Texas. (Spanish Camp-Delhi TP# 6895) | 298 | ||||
4.
|
Existing Point of Interconnection between Seller and Meter named Denton Cooley #l (Seller Meter No. 3331), in Fort Bend County, Texas. (Denton Cooley #l-TP# 1106) | 298 | ||||
5.
|
Existing Point of Interconnection between Seller and Meter named Randon East (Fulshear) (Seller Meter No. 1427), in Fort Bend County, Texas. (Randon East (Fulshear) TP# 299) | 298 | ||||
6.
|
Existing Point of Interconnection between Seller and Houston Pipeline Company (Seller Meter No. 3364) at Fulshear, Fort Bend County, Texas. (Fulshear-HPL TP# 6097) | 298 |
A-1
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection
between Seller and Meter named White Oak
Bayou-Exxon Gas System, Inc. (Seller Meter
No. 3545), in Harris County, Texas. (White
Oak Bayou-EGSI TP# 1036)
298
Existing Point of Interconnection
between Seller and Houston Pipeline
Company (Seller Meter No. 4359) at
Bammel, Harris County, Texas.
(Bammel-HPL TP# 6014)
298
Existing Point of Interconnection
between Seller and Delhi Pipeline
Company (Seller Meter No. 3346) at
Hardin County, Texas. (Hardin-Delhi
TP# 6696)
298
Existing Point of Interconnection
between Seller and Meter named Vidor
Field Junction (Seller Meter No. 3554),
in Jasper County, Texas. (Vidor Field
Junction TP# 2337)
298
Existing Point of Interconnection
between Seller and Meter named Starks
McConathy (Seller Meter No. 3535), in
Calcasieu Parish, Louisiana. (Starks
McConathy TP# 7346)
298
Existing Point of Interconnection
between Seller and Meter named DeQuincy
Intercon (Seller Meter No. 2698), in
Calcasieu Parish, Louisiana. (DeQuincy
Intercon TP# 7035)
298
A-2
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyers
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection
between Seller and Meter named DeQuincy
Great Scott (Seller Meter No. 3357), in
Calcasieu Parish, Louisiana. (DeQuincy
Great Scott TP# 6809)
298
Existing Point of Interconnection
between Seller and Meter named Perkins-Phillips (Seller Meter No. 3532), in
Calcasieu Parish, Louisiana. (Perkins-Phillips TP# 7508)
298
Existing Point of Interconnection
between Seller and Meter named Perkins
(Intercon) (Seller Meter No. 3395), in
Calcasieu Parish, Louisiana. (Perkins
(Intercon) TP# 7036)
298
Existing Point of Interconnection
between Seller and Meter named Perkins
East (Seller Meter No. 2369), in
Beauregard Parish, Louisiana. (Perkins
East TP# 139)
298
Discharge Side of Sellers Compressor
Station 45 at the Existing Point of
Interconnection between Sellers
Southwest Louisiana Lateral and
Sellers Mainline Beauregard Parish,
Louisiana. (Station 45 TP# 7101)
735
Existing Point of Interconnection
between Seller and Texas Eastern
Transmission Corporation (Seller Meter
No. 4198) at Ragley, Beauregard Parish,
Louisiana. (Ragley-TET TP# 6217)
735
A-3
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection
between Seller and Trunkline Gas
Company (Seller Meter No. 4215) at
Ragley, Beauregard Parish, Louisiana.
(Ragley-Trunkline TP# 6218)
735
Existing Point of Interconnection
between Seller and Tennessee Gas
Transmission Company (Seller Meter
No. 3371) at Kinder, Allen Parish,
Louisiana. (Kinder TGT TP# 6149)**
735
Existing Point of Interconnection
between Seller and Texas Gas Transmission
Corporation (Seller Meter Nos. 3227,4314,
4457) at Eunice, Evangeline Parish,
Louisiana. (Eunice Mamou Tx. Gas TP# 6923)
735
Suction Side of Sellers Compressor
Station 50 at the Existing Point of
Interconnection between Sellers Central
Louisiana Lateral and Sellers Mainline
Evangeline Parish, Louisiana. (Station 50
TP# 6948)
1,068
Existing Point of Interconnection
between Seller and Columbia Gulf
Transmission Corporation (Seller Meter
No. 3142) at Eunice, Evangeline Parish,
Louisiana. (Eunice Evangeline Col. Gulf
TP# 6414)
1,068
Discharge Side of Sellers Compressor
Station 54 at Sellers Washington Storage
Field, St. Landry Parish, Louisiana.
(Station 54 TP# 6768)****
1,068
A-4
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection
between Seller and Acadian Pipeline
(Seller Meter No. 3506) in Pointe Coupee
Parish, Louisiana. (Morganza-Acadian
Pipeline TP# 7060)
1,068
Existing Point of Interconnection
(Seller Meter No. 3272) at M.P. 566.92,
Morganza Field, Pointe Coupee Parish,
Louisiana. (Morganza Field TP# 576)
1,068
Existing Point of Interconnection
between Seller and Meter named West
Feliciana Parish-Creole (Seller Meter
No. 4464, in West Feliciana Parish,
Louisiana. (West Feliciana Parish-
Creole TP# 7165)
1,068
Existing Point of Interconnection
between Seller and Mid-Louisiana Gas
Company (Seller Meter Nos. 4137, 4184,
3229) at Ethel, East Feliciana Parish,
Louisiana. (Ethel-Mid LA TP# 6083)
1,068
Existing Point of Interconnection
between Seller and Meter named Liverpool
Northwest (Seller Meter No. 3390), in
St. Helena Parish, Louisiana. (Liverpool
Northwest TP# 6757)
1,068
Suction Side of Sellers Compressor
Station 62 on Sellers Southeast
Louisiana Lateral in Terrebonne Parish
Louisiana. (Station 62 TP# 7141)
683
Existing Point of interconnection between
Seller and Meter named Texas Gas - TLIPCO -
Thibodeaux (Seller Meter No. 3533), in
Lafourche Parish, Louisiana. (TXGT-TLIPCO-
Thibodeaux TP# 7206)
683
A-5
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection
between Seller and Meter named Romeville-
Monterey (Seller Meter No. 4410), in
St. James Parish, Louisiana. (Romeville-Monterey Pipeline TP# 580)
683
Existing Point of Interconnection
between Seller and Meter named St. James
CCIPC (Seller Meter No. 4462), in
St. James Parish, Louisiana. (St. James
CCIPC TP# 7164)**
683
Existing Point of Interconnection
between Seller and Meter named St. James
Faustina (St. Amelia) (Seller Meter No. 3328),
in St. James Parish, Louisiana. (St. James
Faustina (St. Amelia) TP# 6268)**
683
Existing Point of Interconnection between
Seller and Meter named St. James Acadian
(Seller Meter No. 4366), in St. James Parish, Louisiana. (St. James Acadian
TP# 6677)**
683
Existing Point of Interconnection between
Seller and Meter named Livingston-Flare
(Seller Meter No. 3540), in Livingston
Parish, Louisiana. (Livingston-Flare
TP# 8739)
683
Existing Point of Interconnection between
Seller and Florida Gas Transmission
Company (Seller Meter No. 3217) at
St . Helena, St. Helena Parish, Louisiana.
(St. Helena FGT TP# 6267)
683
A-6
TRANSCONTINENTAL GAS PIPE LINE CORPORATION |
EXHIBIT A
(Continued)
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/d)*
|
|||||
38.
|
Existing Point of Interconnection between Seller and Meter named Beaver Dam Creek (Seller Meter No. 3536), in St. Helena Parish, Louisiana. (Beaver Dam Creek TP# 8218) | 683 | ||||
39.
|
Suction Side of Sellers Compressor Station 65 at the Existing Point of Interconnection between Sellers Southeast Louisiana Lateral and Sellers Mainline St. Helena Parish, Louisiana. (Station 65 TP# 6685) | 1,750 | ||||
40.
|
Existing Point of Interconnection between Seller and Meter named Amite County/Koch (Seller Meter No. 3332), in Amite County, Mississippi (Amite County/Koch TP# 6701) | 1,750 | ||||
41.
|
Existing Point of Interconnection between Seller and Meter named McComb (Seller Meter No. 3461), in Pike County, Mississippi. (McComb TP# 6446) | 1,750 | ||||
42.
|
Existing Point of Interconnection between Seller and United Gas Pipe Line Company at Holmesville (Seller Meter No. 3150), Pike County, Mississippi. (Holmesville- United TP# 6128) | 1,750 | ||||
43.
|
Discharge Side of Sellers Compressor Station 70 at M.P. 661.77 in Walthall County, Mississippi. (M.P. 661.77 - Station 70 Discharge TP# 7142) | 1,750 | ||||
44.
|
Existing Point of Interconnection between Seller and United Gas Pipe Line Company at Walthall (Seller Meter No. 3095), Walthall County, Mississippi. (Walthall- UGPL TP# 6310)*** | 1,750 |
A-7
TRANSCONTINENTAL GAS PIPE LINE CORPORATION |
EXHIBIT A
(Continued)
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/d)*
|
|||||
45.
|
Existing Point of Interconnection between Seller and Meter named Darbun-Pruett 34-10 (Seller Meter No. 3446) at M.P. 668.46 on Sellers Main Transmission Line, Darbun Field, Walthall County, Mississippi. (Darbun Pruett TP# 6750) | 1,750 | ||||
46.
|
Existing Point of Interconnection between Seller and Meter named Ivy Newsome (Seller Meter No. 3413) in Marion County, Mississippi. (Ivy Newsome TP# 6179) | 1,750 | ||||
47.
|
Existing Point of Interconnection between Seller and West Oakvale Field at M.P. 680.47-Marion County, Mississippi. (M.P. 680.47-West Oakvale Field TP# 7144) | 1,750 | ||||
48.
|
Existing Point of Interconnection between Seller and East Morgantown Field at M.P. 680.47 in Marion County, Mississippi. (M.P. 680.47-E. Morgantown Field TP# 7145) | 1,750 | ||||
49.
|
Existing Point of Interconnection between Seller and Greens Creek Field, at M.P. 681.84 Marion County, Mississippi. (M.P. 681.84 Greens Creek Field TP# 7146) | 1,750 | ||||
50.
|
Existing Point of Interconnection between Seller and Meter named M.P. 685.00-Oakville Unit 6-6 in Jefferson Davis County, Mississippi. (M.P. 685.00-Oakville Unit 6-6 TP# 1376) | 1,750 | ||||
51.
|
Existing Point of Interconnection between Seller and Meter named M.P. 687.23-Oakvale Field in Marion County, Mississippi. (M.P. 687.23-Oakvale Field TP# 7147) | 1,750 |
A-8
TRANSCONTINENTAL GAS PIPE LINE CORPORATION |
EXHIBIT A
(Continued)
Buyers | ||||||
Cumulative | ||||||
Mainline Capacity | ||||||
Entitlement | ||||||
Point(s) of Receipt
|
(Mcf/d)*
|
|||||
52.
|
Existing Point of Interconnection between Seller and Bassfield at named M.P. 696.40 in Marion County, Mississippi. (M.P. 696.40 Bassfield TP# 9439) | 1,750 | ||||
53.
|
Existing Point of Interconnection between Seller and Meter named Lithium/Holiday Creek-Frm (Seller Meter No. 3418, in Jefferson Davis County, Mississippi. (Lithium/Holiday Creek-Frm TP# 7041) | 1,750 | ||||
54.
|
Existing Point of Interconnection between Seller and S. W. Sumrall Field and Holiday Creek at M.P. 692.05-Holiday Creek in Jefferson Davis, Mississippi, (M.P. 692.05- Holiday Creek TP# 7159) | 1,750 | ||||
55.
|
Existing Point of Interconnection between Seller and ANR Pipe Line Company at Holiday Creek (Seller Meter No. 3241), Jefferson Davis County, Mississippi. (Holiday Creek-ANR TP# 398) | 1,750 | ||||
56.
|
Existing Point of Interconnection between Seller and Mississippi Fuel Company at Jeff Davis (Seller Meter No. 3252), Jefferson Davis County, Mississippi. (Jefferson Davis County-Miss Fuels TP# 6579)*** | 1,750 | ||||
57.
|
Existing Point of Interconnection between Seller and Meter named Jefferson Davis-Frm (Seller Meter No. 4420), in Jefferson Davis County, Mississippi. (Jefferson Davis-Frm TP# 7033) | 1,750 |
A-9
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection between
Seller and Carson Dome Field M.P. 696.41,
in Jefferson Davis County, Mississippi.
(M.P. 696.41 Carson Dome Field TP# 7148)
1,750
Existing Point of Interconnection between
Seller and Meter Station named Bassfield-ANR Company at M.P. 703.17 on Sellers Main
Transmission Line (Seller Meter No. 3238),
Covington County, Mississippi. (Bassfield-ANR TP# 7029)
1,750
Existing Point of Interconnection between
Seller and Meter named Patti Bihm #l
(Seller Meter No. 3468), in Covington
County, Mississippi. (Patti Bihm #l
TP# 7629)
1,750
Discharge Side of Sellers Compressor
at Sellers Eminence Storage Field
(Seller Meter No. 4166 and 3160)
Covington County, Mississippi.
(Eminence Storage TP# 5561)
1,750
Existing Point of Interconnection between
Seller and Dont Dome Field at M.P. 713.39
in Covington County, Mississippi. (M.P. 713.39 Dont Dome TP# 1396)
1,750
Existing Point of Interconnection between
Seller and Endevco in Covington County,
Mississippi. (Hattiesburg-Interconnect
Storage TP# 1686)
1,750
Existing Point at M.P. 719.58 on Sellers
Main Transmission Line (Seller Meter No.
3544), Centerville Dome Field, Jones
County, Mississippi. (Centerville Dome
Field TP# 1532)
1,750
A-10
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point at M.P. 727.78 on
Sellers Main Transmission Line,
Jones County, Mississippi. (Jones
County-Gitano TP# 7166)
1,750
Existing Point of Interconnection between
Seller and a Meter named Koch Reedy Creek
(Seller Meter No. 3333), Jones County,
Mississippi. (Reedy Creek-Koch TP# 670)
1,750
Existing Point of Interconnection between
Seller and Meter named Sharon Field
(Seller Meter No. 3000), in Jones County,
Mississippi. (Sharon Field TP# 419)
1,750
Existing Point of Interconnection between
Seller and Tennessee Gas Transmission
Company at Heidelberg (Seller Meter No. 3109),
Jasper County, Mississippi. (Heidelberg-Tennessee TP# 6120)***
1,750
Existing Point of Interconnection between
Seller and Mississippi Fuel Company at
Clarke (Seller Meter No. 3254),
Clarke County, Mississippi. (Clarke County-
Miss Fuels TP# 6047)***
1,750
Existing Point of Interconnection between
Seller and Meter named Clarke County-Koch
at M.P. 757.29 in Clarke County, Mississippi.
(Clarke County-Koch TP# 5566)
1,750
Existing Point of Interconnection between
Sellers Mainline and Mobile Bay Lateral at
Butler, Choctaw County, Alabama (Butler
TP# 6034)
1,750
A-11
EXHIBIT A
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(Continued)
Buyer's
Cumulative
Mainline Capacity
Entitlement
Point(s) of Receipt
(Mcf/d)*
Existing Point of Interconnection between
Seller and Southern Natural Gas Company,
(Seller Meter No. 4087) at Jonesboro,
Clayton County, Georgia. (Jonesboro-SNG
TP# 6141)
1,750
Buyer shall not tender, without the prior consent of Seller, at any point(s) of receipt on any day a quantity in excess of the applicable Buyers Cumulative Mainline Capacity Entitlement for such point(s) of receipt.
* | These quantities do not include the additional quantities of gas retained by Seller for applicable compressor fuel and line loss make-up provided for in Article V, 2 of this Service Agreement, which are subject to change as provided for in Article V, 2 hereof. | |
** | Receipt of gas by displacement only. | |
*** | Receipt of gas limited to physical capacity of Sellers lateral line facilities. | |
**** | Buyers Cumulative Mainline Capacity Entitlement at Compressor Station 54 shall not supersede or otherwise affect any rights, obligations or limitations which are stated in Sellers WSS Rate Schedule. |
A-12
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
Exhibit B
Point(s) of Delivery
|
Pressure
|
|||
1.
|
Station 54* | Not applicable. | ||
2.
|
Herndon Meter Station, located at mile post 1598.81 on Sellers main transmission line, adjacent to State Highway 1212 on the east side and State Highway 606 on the north side, Fairfax County, Virginia. | Not less than fifty (50) pounds per square inch gauge or such other pressures as may be agreed upon in the day-to-day operations of Buyer and Seller. | ||
3.
|
Bull Run Meter Station, located at mile post 1583.35 on Sellers main transmission line, adjacent to Sellers Compressor Station 185 located in Prince William County, Virginia. | Not less than fifty (50) pounds per square inch gauge or such other pressures as may be agreed upon in the day-to-day operations of Buyer and Seller. | ||
4.
|
Sellers Eminence Storage Field, Covington County, Mississippi. | Prevailing pressure in Sellers pipeline system not to exceed maximum allowable operating pressure. |
* | Delivery to Sellers Washington Storage Field for injection into storage is subject to the terms, conditions and limitations of Sellers WSS Rate Schedule. |
B-1
Exhibit 10.14
FIRM TRANSPORTATION AGREEMENT
(For Use Under Rate Schedules FT-A and FT-GS)
THIS AGREEMENT is made, entered into and effective as of this 12th day of January, 2004, by and between East Tennessee Natural Gas Company, a Tennessee corporation hereinafter referred to as Transporter, and Washington Gas Light Company, a District of Columbia and Virginia corporation, hereinafter referred to as Shipper. Transporter and Shipper shall be referred to herein individually as Party and collectively as Parties.
ARTICLE I DEFINITIONS
The definitions found in Section 1 of Transporters General Terms and Conditions are incorporated herein by reference.
ARTICLE II SCOPE OF AGREEMENT
Transporter agrees to accept and receive daily, on a firm basis, at the Receipt Point(s) listed on Exhibit A attached hereto, from Shipper such quantity of gas as Shipper makes available up to the applicable Maximum Daily Transportation Quantity stated on Exhibit A attached hereto and deliver for Shipper to the Delivery Point(s) listed on Exhibit A attached hereto an Equivalent Quantity of gas. The Rate Schedule applicable to this Agreement shall be stated on Exhibit A.
ARTICLE III RECEIPT AND DELIVERY PRESSURES
Shipper shall deliver, or cause to be delivered, to Transporter the gas to be transported hereunder at pressures sufficient to deliver such gas into Transporters system at the Receipt Point(s). Transporter shall deliver the gas to be transported hereunder to or for the account of Shipper at the pressures existing in Transporters system at the Delivery Point(s) unless otherwise specified on Exhibit A.
ARTICLE IV QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENTS
For all gas received, transported, and delivered hereunder, the Parties agree to the quality specifications and standards for measurement as provided for in Transporters General Terms and Conditions. Transporter shall be responsible for the operation of measurement facilities at the Delivery Point(s) and Receipt Point(s). In the event that measurement facilities are not operated by Transporter, the responsibility for operations shall be deemed to be Shippers.
ARTICLE V FACILITIES
The facilities necessary to receive, transport, and deliver gas as described herein are in place and no new facilities are anticipated to be required.
ARTICLE VI RATES FOR SERVICE
6.1 | Rates and Charges Commencing on the date of implementation of this Agreement under Section 10.1, the compensation to be paid by Shipper to Transporter shall be in |
accordance with Transporters effective Rate Schedule FT-A or FT-GS, as specified on Exhibit A. Where applicable, Shipper shall also pay the Gas Research Institute surcharge and Annual Charge Adjustment surcharge as such rates may change from time to time. Except as provided to the contrary in any written or electronic agreement(s) between Transporter and Shipper in effect during the term of this Agreement, Shipper shall pay Transporter the applicable maximum rate(s) and all other applicable charges and surcharges specified in the Notice of Rates in Transporters FERC Gas Tariff and in this Rate Schedule. Transporter and Shipper may agree that a specific discounted rate will apply only to certain volumes under the Agreement. Transporter and Shipper may agree that a specified discounted rate will apply only to specified volumes (MDRO, MDDO, MDTQ, commodity volumes or Authorized Overrun volumes) under the Agreement; that a specified discounted rate will apply only if specified volumes are achieved (with the maximum rates applicable to volumes above the specified volumes or to all volumes if the specified volumes are never achieved); that a specified discounted rate will apply only during specified periods of the year or over a specifically defined period of time; and/or that a specified discounted rate will apply only to specified points, zones, markets or other defined geographical areas. Transporter and Shipper may agree to a discounted rate pursuant to the provisions of this Section 6.1 provided that the discounted rate is between the applicable maximum and minimum rates for this service.
6.2 | Changes in Rates and Charges Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make changes effective in (a) the rates and charges stated in this Article, (b) the rates and charges applicable to service pursuant to the Rate Schedule under which this service is rendered and (c) any provisions of Transporters General Terms and Conditions as they may be revised or replaced from time to time. Without prejudice to Shippers right to contest such changes, Shipper agrees to pay the effective rates and charges for service rendered pursuant to this Agreement. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for adjustment of Transporters existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates. |
ARTICLE VII RESPONSIBILITY DURING TRANSPORTATION
As between the Parties hereto, it is agreed that from the time gas is delivered by Shipper to Transporter at the Receipt Point(s) and prior to delivery of such gas to or for the account of Shipper at the Delivery Point(s), Transporter shall be responsible for such gas and shall have the unqualified right to commingle such gas with other gas in its system and shall have the unqualified right to handle and treat such gas as its own. Prior to receipt of gas at Shippers Receipt Point(s) and after delivery of gas at Shippers Delivery Point(s), Shipper shall have sole responsibility for such gas.
ARTICLE VIII BILLINGS AND PAYMENTS
Billings and payments under this Agreement shall be in accordance with Section 16 of Transporters General Terms and Conditions as they may be revised or replaced from time to time.
2
ARTICLE IX RATE SCHEDULES AND
GENERAL TERMS AND CONDITIONS
This Agreement is subject to the effective provisions of Transporters FT-A or FT-GS
Rate Schedule, as specified in Exhibit A, or any succeeding rate schedule and
Transporters General Terms and Conditions on file with the Commission, or other duly
constituted authorities having jurisdiction, as the same may be changed or superseded
from time to time in accordance with the rules and regulations of the Commission, which
Rate Schedule and General Terms and Conditions are incorporated by reference and made a
part hereof for all purposes.
ARTICLE X TERM OF CONTRACT
ARTICLE XI REGULATION
10.1
This Agreement shall be effective as of the date of execution set
forth above, and shall remain in force and effect until 364 days after the date of
execution (Primary Term); provided, however, that if the Primary Term is one
year or more, then the contract shall remain in force and effect and the contract
term will automatically roll-over for additional five year increments (Secondary
Term) unless Shipper, one year prior to the expiration of the Primary Term or a
Secondary Term, provides written notice to Transporter of either (1) its intent to
terminate the contract upon expiration of the then current term or (2) its desire
to exercise its right-of-first-refusal in accord with Section 7.3 of Transporters
General Terms and Conditions. Provided further, if the Commission or other
governmental body having jurisdiction over the service rendered pursuant to this
Agreement authorizes abandonment of such service, this Agreement shall terminate
on the abandonment date permitted by the Commission or such other governmental
body.
10.2
In addition to any other remedy Transporter may have, Transporter
shall have the right to terminate this Agreement in the event Shipper fails to pay
all of the amount of any bill for service rendered by Transporter hereunder when
that amount is due, provided Transporter shall give Shipper and the Commission
thirty days notice prior to any termination of service. Service may continue
hereunder if within the thirty day notice period satisfactory assurance of payment
is made in accord with Section 16 of Transporters General Terms and Conditions.
11.1
This Agreement shall be subject to all applicable governmental statutes, orders, rules, and
regulations and is contingent upon the receipt and continuation of all necessary regulatory
approvals or authorizations upon terms acceptable to Transporter and Shipper. This
Agreement shall be void and of no force and effect if any necessary regulatory approval
or authorization is not so obtained or continued. All Parties hereto shall cooperate to
obtain or continue all necessary approvals or authorizations, but no Party shall be liable
to any other Party for failure to obtain or continue such approvals or authorizations.
11.2
Promptly following the execution of this Agreement, the Parties will file, or cause to be
filed, and diligently prosecute, any necessary applications or notices with all
necessary regulatory bodies for approval of the service provided for herein.
3
ARTICLE XII ASSIGNMENTS
ARTICLE XIII WARRANTIES
In addition to the warranties set forth in Section 22 of Transporters General Terms
and Conditions, Shipper warrants the following:
11.3
In the event the Parties are unable to obtain all necessary and
satisfactory regulatory approvals for service prior to the expiration of two (2) years from the effective date
hereof, then, prior to receipt of such regulatory approvals, either Party may terminate this
Agreement by giving the other Party at least thirty (30) days prior written notice, and the
respective obligations hereunder, except for the reimbursement of filing fees herein, shall
be of no force and effect from and after the effective date of such termination. [This
Section 11.3 is not applicable.]
11.4
The transportation service described herein shall be provided subject to the provisions of
the Commissions Regulations shown on Exhibit A hereto.
12.1
Either Party may assign or pledge this Agreement and all rights and obligations
hereunder under the provisions of any mortgage, deed of trust, indenture or other
instrument that it has executed or may execute hereafter as security for indebtedness;
otherwise, Shipper shall not assign this Agreement or any of its rights and obligations
hereunder, except as set forth in Section 17 of Transporters General Terms and
Conditions.
12.2
Any person or entity that shall succeed by purchase, transfer, merger, or consolidation to
the properties, substantially or as an entirety, of either Party hereto shall be
entitled to the rights and shall be subject to the obligations of its predecessor in interest
under this Agreement.
13.1
Shipper warrants that all upstream and downstream transportation arrangements are in
place, or will be in place, as of the requested effective date of service, and that it has
advised the upstream and downstream transporters of the receipt and delivery points
under this Agreement and any quantity limitations for each point as specified on Exhibit
A attached hereto. Shipper agrees to indemnify and hold Transporter harmless for refusal
to transport gas hereunder in the event any upstream or downstream transporter fails to
receive or deliver gas as contemplated by this Agreement.
13.2
Shipper agrees to indemnify and hold Transporter harmless from all suit actions, debts,
accounts, damages, costs, losses, and expenses (including reasonable attorneys fees)
arising from or out of breach of any warranty, by the Shipper herein.
13.3
Shipper warrants that it will have title or the right to acquire title to the gas delivered to Transporter under this Agreement.
13.4
Transporter shall not be obligated to provide or continue service hereunder in the event of any breach of warranty; provided, Transporter shall give Shipper and the Commission
4
thirty days notice prior to any termination of service. Service will continue if,
within the thirty day notice period, Shipper cures the breach of warranty.
ARTICLE XIV MISCELLANEOUS
14.1
Except for changes specifically authorized pursuant to this Agreement, no modification
of or supplement to the terms and conditions hereof shall be or become effective until
Shipper has submitted a request for change via LINK® and Shipper has been notified via
LINK® of Transporters agreement to such change.
14.2
No waiver by any Party of any one or more defaults by the other in the performance of
any provision of this Agreement shall operate or be construed as a waiver of any future
default or defaults, whether of a like or of a different character.
14.3
Except when notice is required via LINK®, pursuant to Transporters FT-A or FT-GS
Rate Schedule, as applicable, or pursuant to Transporters General Terms and Conditions,
any notice, request, demand, statement or bill provided for in this Agreement or any
notice that either Party may desire to give to the other shall be in writing and mailed by
registered mail to the post office address of the Party intended to receive the same, as the
case may be, to the Partys address shown on Exhibit A hereto or to such other address as
either Party shall designate by formal written notice to the other. Routine
communications, including monthly statements and payments, may be mailed by either
registered or ordinary mail. Notice shall be deemed given when sent.
14.4
THE INTERPRETATION AND PERFORMANCE OF THIS AGREEMENT SHALL
BE IN ACCORDANCE WITH AND CONTROLLED BY THE LAWS OF THE STATE
OF TENNESSEE, WITHOUT REGARD TO CHOICE OF LAW DOCTRINE THAT
REFERS TO THE LAWS OF ANOTHER JURISDICTION.
14.5
The Exhibit(s) attached hereto is/are incorporated herein by reference and made a part of
this Agreement for all purposes.
14.6
If any provision of this Agreement is declared null and void, or voidable, by a court of
competent jurisdiction, then that provision will be considered severable at Transporters
option; and if the severability option is exercised, the remaining provisions of the
Agreement shall remain in full force and effect.
14.7
This Agreement supersedes and cancels the Gas Sales and Transportation
Agreement(s) between Shipper and Transporter dated
N/A
and
N/A
, respectively. [This Section 14.7
is not applicable.]
5
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the date first hereinabove written.
EAST TENNESSEE NATURAL GAS COMPANY | ||
BY: /s/ D. Patrick Whitty
D. Patrick Whitty |
||
TITLE: Vice President | ||
WASHINGTON GAS LIGHT COMPANY | ||
BY: /s/ Terry D. McCallister
|
||
TITLE: President & COO |
6
Date: 01/12/04
EXHIBIT A TO THE FIRM
TRANSPORTATION AGREEMENT
DATED January 12th , 2004
Shipper: Washington Gas Light Company
Rate Schedule: FT-A
Maximum Daily Transportation Quantity: 25,000 Dth/d
Proposed Commencement Date: The date of execution set forth in the Firm Transportation Agreement
Termination Date: 364 days after the date of execution
Transportation Service will be provided under Part 284, Subpart G of the Commissions Regulations.
Primary
|
Interconnect | Location | ||||||||||
Receipt
Point(s):
|
Party | County, State | ||||||||||
Name
|
Meter No. | MDRO | ||||||||||
Saltville
Storage Co., LLC
|
59760 | 25,000 | Smyth Co, VA | |||||||||
|
Primary
|
Interconnect | Location | ||||||||||
Delivery
Point(s):
|
Party | County, State | ||||||||||
Name
|
Meter No. | MDRO | ||||||||||
Transco
|
59204 | 25,000 | Rockingham Co, | |||||||||
|
NC | |||||||||||
|
Name of entity(s) to deliver gas to Transporter:
1
Name of entity(s) to receive gas from Transporter:
* | Transporter shall not be obligated to deliver more cubic feet of gas to any Shipper than the quantity calculated using 1.03 dth per million cubic feet. |
2
EXHIBIT A TO THE FIRM
TRANSPORTATION AGREEMENT
DATED January 12th, 2004
Notices not made via LINK® shall be made to:
|
Shipper | |
|
Washington Gas Light Company | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
Attn: Tim S. Sherwood | |
|
||
|
Invoices | |
|
Washington Gas Light Company | |
|
6801 Industrial Road | |
|
Springfield, VA 22151 | |
|
Attn: Accounting Department |
New Facilities Required:
As described in the Commissions November 20, 2002 order in Docket Nos. CP01-415-000, et al. (101 FERC ¶ 61,188 (2002))
New Facilities Charge:
Not applicable
(This Exhibit A supersedes and cancels Exhibit A dated N/A to the Firm Transportation Agreement dated N/A .) [Not Applicable]
EAST TENNESSEE
NATURAL GAS COMPANY
|
(SHIPPER) | |
BY: /s/
D. Patrick Whitty
|
BY: /s/ Terry D. McCallister | |
|
|
|
D. Patrick
Whitty
|
||
TITLE:
Vice President
|
TITLE: President & COO |
1
FIRM STORAGE SERVICE AGREEMENT
THIS AGREEMENT, made and entered into as of this 12th Day of January , 2004, by and between SALTVILLE GAS STORAGE COMPANY L.L.C., a Virginia limited liability company, hereinafter referred to as SELLER, and WASHINGTON GAS LIGHT COMPANY , a Virginia corporation, hereinafter referred to as PURCHASER.
WITNESSETH
WHEREAS, SELLER has undertaken to provide a firm storage service under the Utility Facilities Act of Virginia, in accordance with its Gas Tariff filed with the State Corporation Commission of Virginia (SCC), and under its limited jurisdiction certificate of public convenience and necessity issued pursuant to part 284 of the Regulations of the Federal Energy Regulatory Commission (FERC); and
WHEREAS, PURCHASER has requested storage service on a firm basis pursuant to Rate Schedule FSS in compliance with Section 3 of the General Terms and Conditions of SELLERS SCC Gas Tariff or any successor regulatory Tariff; and
WHEREAS, SELLER has been directed by FERC to file an application for a certificate of convenience and necessity pursuant to Part 157, Subpart A of the Commissions regulations and to file proposed initial rates and tariff terms and conditions pursuant to Part 284, Subpart G of the Commissions regulations, the acceptance of such tariff may supercede SELLERS SCC Gas Tariff; and
WHEREAS, SELLER agrees to furnish firm storage service to PURCHASER on the terms and conditions set forth in this Firm Storage Service Agreement (Agreement).
NOW, THEREFORE, the parties hereby agree as follows:
ARTICLE I
1.1 | Subject to the terms and provisions of this Agreement and the SCC Gas Tariff or any successor regulatory tariff with the SCC or with FERC applicable hereto, PURCHASER shall have the right to deliver to SELLER for storage by SELLER an aggregate quantity of Gas up to the Maximum Storage Quantity, or MSQ specified on Exhibit A. SELLERS obligation to accept Gas at the Primary Receipt Point(s) specified on Exhibit A hereto for injections into storage on any Day is limited to the Maximum Daily Injection Quantity (MDIQ) specified on Exhibit A hereto. | |||
1.2 | Subject to the terms and provisions of this Agreement and the SCC Gas Tariff or any successor regulatory tariff with the SCC or with FERC applicable hereto, PURCHASER shall have the right to cause SELLER to withdraw and redeliver a thermally equivalent quantity of Gas to PURCHASER at the Primary Delivery Point(s) described on Exhibit A hereto. SELLERS obligation to withdraw Gas from storage on any Day is limited to the Maximum Daily Withdrawal Quantity (MDWQ) specified on Exhibit A hereto. |
1
ARTICLE II
CONDITIONS OF SERVICE
2.1 | PURCHASER shall pay SELLER on a monthly basis and in accordance with SELLERS SCC Gas Tariff or any successor regulatory tariff, with the SCC or with FERC |
(a) | a Storage Injection Charge of $0.05 per each dth injected, | |||
(b) | a Storage Withdrawal Charge of $0.05 per each dth withdrawn, and | |||
(c) | a Storage Capacity Charge which shall be the monthly fee of |
(i) | $3.50/dth divided by (12) twelve months multiplied by the Maximum Storage Quantity for the period October 1 April 30, which fee shall be payable in seven (7) equal monthly installments during the period October 1 through April 30, and | |||
(ii) | $1.50 divided by (12) twelve months multiplied by the Maximum Storage Quantity for the period October 1 April 30, which fee shall be payable in five (5) equal monthly installments during the period May 1 through September 30. |
2.2 | PURCHASER shall ensure that the Gas delivered to SELLER at the Primary Receipt Points for injection meets the minimum quality specifications of SELLERS SCC Gas Tariff or any successor regulatory tariff with the SCC or with FERC. SELLER shall ensure that Gas delivered to PURCHASER at the Primary Delivery Points meets the minimum quality specifications of East Tennessee Natural Gas Companys FERC Gas Tariff. | |||
2.3 | The measurement of quantities for billing purposes, in MMBtu, delivered to or received from SELLER shall be performed by East Tennessee Natural Gas Company. | |||
2.4 | Withdrawals from storage shall be adjusted for fuel on the Patriot Expansion on the East Tennessee Pipeline, as deliveries on the East Tennessee pipeline into the interconnect with the Transco Pipeline shall equal the maximum of 25,000 dth/d. |
ARTICLE III
NOTICES
3.1 | Notices hereunder shall be given to the respective party at the applicable address, telephone number or facsimile machine number stated below, or such other addresses, telephone numbers or facsimile numbers as the parties shall respectively designate in writing from time to time. |
For
SELLER:
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SALTVILLE GAS STORAGE COMPANY L.L.C. | |
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1096 Ole Berry Drive | |
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Abingdon,VA 24210 | |
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(276)676-2380 (phone) | |
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(276) 676-5254 (fax) | |
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ATTN: Marketing |
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For PURCHASER
:
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WASHINGTON GAS LIGHT
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6801 Industrial Road
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Springfield, VA 22151
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(703) 750-4468 (phone)
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(703) 750-7692 (fax)
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ATTN: Nimmie Hickman
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ARTICLE IV
TERM
4.1 | Subject to the provisions hereof, this Agreement shall become effective as of January 12th, 2004 and shall be in full force and effect for a primary term through March 31, 2007 (the Termination Date) and, thereafter, shall continue and remain in full force and effect for successive terms of one (1) year each hereafter. PURCHASER retains the right of first refusal on each subsequent one year term unless and until cancelled by either party. SELLER must provide written notice to the PURCHASER 195 days prior to the end of the primary term or any yearly extension thereof. PURCHASER must provide written notice to the SELLER 120 days prior to the end of the primary term or any yearly extension thereof. | |||
4.2 | PURCHASER has the option to extend the primary term for an additional four (4) years of service provided this option is exercised by PURCHASERS provision of written notice to SELLER no later than October 1, 2006. |
ARTICLE V
MISCELLANEOUS
5.1 | SELLER shall have the right to propose, file and make effective with the Virginia State Corporation Commission or other regulatory authority, changes and/or revisions to its FSS Rate Schedule, FSS Rate Statement and/or the General Terms and Conditions of its SCC Gas Tariff for the purpose of changing the provisions thereof effective as to the PURCHASER. The filing of such changes and/or revisions shall be without prejudice to the right of the PURCHASER to contest or oppose the effectiveness of such filing. | |||
5.2 | This Agreement constitutes the entire Agreement between the parties and no waiver by SELLER or PURCHASER of any default of either party under this Agreement shall operate as a waiver of any subsequent default whether of a like or different character. | |||
5.3 | The laws of the Commonwealth of Virginia shall govern the validity, construction, interpretation, and effect of this Agreement, without regard to conflicts of laws principles. | |||
5.4 | No modification of or supplement to the terms and provisions hereof shall be or become effective except by execution of a supplementary written agreement between the parties. | |||
5.5 | Exhibit A attached to this Agreement constitutes a part of this Agreement and is incorporated herein. |
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5.6 | All provisions of the General Terms and Conditions of SELLERS SCC Gas Tariff or successor regulatory tariff with the SCC or with FERC are incorporated herein by reference. | |||
5.7 | Any company which succeeds by purchase, merger, or consolidation of title to the properties, substantially as an entirety, of SELLER or PURCHASER, will be entitled to the rights and will be subject to the obligations of its predecessor in title under this Agreement. Otherwise, neither PURCHASER nor SELLER may assign any of its rights or obligations under this Agreement without the prior written consent of the other Party hereto, which consent shall not be unreasonably withheld. | |||
5.8 | In the event that SELLER loses its Hinshaw pipeline status and there are significant and material changes to the rates or terms and conditions of service provided hereunder, as determined by Purchaser in its sole discretion, PURCHASER may terminate this agreement upon 120 days written notice. | |||
5.9 | PURCHASER has the right to terminate this Agreement with 90 days written notice if the third party which PURCHASER has negotiated a Swap Agreement for physical delivery terminates the Swap Agreement and Purchaser provides written documentation to SELLER of such termination. |
ARTICLE VI
CONFLICTING PROVISIONS
6.1 | In the event of any conflicts in the provisions of this Agreement including the provisions of Exhibit A attached to this Agreement and the General Terms and Conditions of the SELLERS SCC Gas Tariff or any other successor tariff with the SCC or with FERC, then the provisions of this Agreement will govern, provided that those provisions are in accordance with applicable law and that the provisions of this Agreement, at the time of its execution, are consistent with the terms of SELLERS SCC Gas Tariff. |
IN WITNESS WHEREOF, this Agreement has been executed as of the date first written above by the parties duly authorized officers.
Attest:
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WASHINGTON GAS LIGHT COMPANY | |
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By: /s/ Terry D. McCallister | |
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Its: President & COO | |
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Attest:
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SALTVILLE GAS STORAGE COMPANY, LLC | |
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By: /s/ Joseph A. Curia | |
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Its: Vice President, Virginia Gas Pipeline Company, Operating Manager | |
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EXHIBIT A
To that certain Firm Gas Storage Agreement dated January 12th , 2004 by and between SALTVILLE GAS STORAGE COMPANY L.L.C. and WASHINGTON GAS LIGHT COMPANY.
Primary Point(s) of Receipt and Delivery:
Saltville receipt/delivery point, Smyth County, Virginia. For injections, ETNG Meter Number 759766; for withdrawals, ETNG Meter Number 759777.
October 1 2003 April 30 2004:
Maximum Daily Injection Quantity, in dth:
10,000 dth per Day
Maximum Daily Withdrawal Quantity, in dth:
25,000 dth per Day plus applicable East Tennessee fuel charges
Maximum Storage Quantity, in dth:
125,000 dth
May 1, 2004 September 30, 2007: [applicable to consecutive months of May 1 thru September 30]
Maximum Daily Injection Quantity, in dth:
5,000 dth per Day
Maximum Daily Withdrawal Quantity, in dth:
0 dth per Day
Maximum Storage Quantity, in dth:
125,000 dfh
October 1, 2004 March 31, 2007: [applicable to consecutive months of October 1 thru March 31]
Maximum Daily Injection Quantity, in dth:
10,000 dth per Day
Maximum Daily Withdrawal Quantity, in dth:
25,000 dth per Day plus applicable East Tennessee fuel charges
Maximum Storage Quantity, in dth:
250,000 dth
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Exhibit 10.15
WGL HOLDINGS, INC.
1999 INCENTIVE COMPENSATION PLAN,
As Amended and Restated
March 5, 2003
SECTION 1
PURPOSE
Purpose. The purpose of this 1999 Incentive Compensation Plan, as Amended and Restated (the Plan) of WGL Holdings, Inc., a Virginia corporation (the Company), is to advance the interests of the Company and its shareholders by providing for incentive compensation triggered by factors related to operational excellence, customer service, utility reliability and others as a means to attract, retain and reward officers and other key employees of, and consultants and other service providers to, the Company and Subsidiaries and to enable such persons to acquire or increase their interests in the Company and its success, thereby promoting a closer identity of interests between such persons and the Companys shareholders. The Plan is intended to qualify certain compensation awarded under the Plan as performance-based compensation under Code section 162(m) to the extent deemed appropriate by the Committee.
SECTION 2
GENERAL DEFINITIONS
Definitions. The definitions of awards under the Plan, including Options, SARs, Restricted Stock, Deferred Stock, Stock granted as a bonus or in lieu of other awards, Dividend Equivalents, Other Stock-Based Awards and Cash Awards, are set forth in Section 6 of the Plan. Such awards, together with any other right or interest granted to a Participant under the Plan, are termed Awards. For purposes of the Plan, the following additional terms shall be defined as set forth below:
(a) Award Agreement means any written agreement, contract, notice or other instrument or document evidencing or relating to an Award.
(b) Beneficiary means the person, persons, trust or trusts which have been designated by a Participant in his most recent written beneficiary designation filed with the Committee to exercise the rights and receive the benefits specified under an Award upon such Participants death or, if there is no designated Beneficiary or surviving designated Beneficiary, then the person, persons, trust or trusts entitled by will or the laws of descent and distribution to exercise such rights and receive such benefits.
(c) Board means the Board of Directors of the Company.
(d) Change of Control means:
(i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a Person), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 30% or more of either (A) the then-outstanding shares of common stock of the Company or (B) the combined voting power of the then-outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that for purposes of this paragraph (i), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, or any corporation controlled by or otherwise affiliated with the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by or otherwise affiliated with the Company; or (D) any transaction described in clauses (A), (B), and (C) of paragraph (iv) of this definition; or
(ii) Individuals who, as of the close of business on November 1, 2000, constituted the Board of Directors of the Company (the Incumbent Company Board) cease for any reason to constitute at least a majority of the Board of Directors of the Company; provided, however, that any individual becoming a director subsequent to November 1, 2000 whose election, or nomination for election by the Companys shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Company Board shall be considered as though such individual were a member of the Incumbent Company Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Company Board; or
(iii) The acquisition by any Person of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 30% or more of either (A) the then-outstanding shares of common stock of Washington Gas Light Company (the Utility) or (B) the combined voting power of the then-outstanding voting securities of the Utility entitled to vote generally in the election of directors; provided, however, that for purposes of this paragraph (iii), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Utility, (B) any acquisition by the Utility or any corporation controlled by or otherwise affiliated with the Utility, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Utility or any corporation controlled by or otherwise affiliated with the Utility; or (C) any transaction described in clauses (A) and (B) of paragraph (v) of this definition; or
(iv) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a Business Combination), in each case unless, following such Business Combination, (A) all or
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substantially all of the individuals and entities who were the beneficial owners, respectively, of the outstanding Company common stock and outstanding Company voting securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the outstanding Company common stock and outstanding Company voting securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or of such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 30% or more of, respectively, the then-outstanding shares of common stock of the corporation resulting from such Business Combination, or the combined voting power of the then-outstanding voting securities of such corporation, except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Company Board at the time of the execution of the initial agreement, or of such Incumbent Company Board, providing for such Business Combination; or
(v) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Utility (a Utility Business Combination), in each case unless, following such Utility Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, directly or indirectly, respectively, of the outstanding Utility common stock and the outstanding Utility voting securities immediately prior to such Utility Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then-outstanding shares of common stock and the combined voting power of the then-outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Utility Business Combination in substantially the same proportions as their ownership, immediately prior to such Utility Business Combination, of the outstanding Utility common stock and outstanding Utility voting securities, as the case may be, and (B) no Person (excluding any corporation resulting from such Utility Business Combination or any employee benefit plan (or related trust) of the Utility or such corporation resulting from such Utility Business Combination) beneficially owns, directly or indirectly, 30% or more of, respectively, the then-outstanding shares of common stock of the corporation resulting from such Utility Business Combination, or the combined voting power of the then-outstanding voting securities of such corporation, except to the extent that such ownership existed prior to the Utility Business Combination; or
(vi) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
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For purposes of this definition, the term affiliated includes any entity controlled by, controlling or under common control with the entity referred to.
(e) Code means the Internal Revenue Code of 1986, as amended from time to time. References to any provision of the Code shall be deemed to include the regulations thereunder and successor provisions and regulations thereto.
(f) Committee means the committee appointed by the Board to administer the Plan or, if no committee is appointed, the Board.
(g) Exchange Act means the Securities Exchange Act of 1934, as amended from time to time. References to any provision of the Exchange Act shall be deemed to include the rules thereunder and successor provisions and rules thereto.
(h) Fair Market Value means, on any given day, the closing price of one share of Stock as reported on the New York Stock Exchange composite tape on such day or, if the Stock was not traded on such day, then on the next preceding day that the Stock was traded, all as reported by such source as the Committee may select.
(i) ISO means any Option intended to be and designated as an incentive stock option within the meaning of Code section 422.
(j) Participant means a person who, at a time when eligible under Section 5, has been granted an Award.
(k) Plan Year means the Companys fiscal year.
(l) Rule 16b-3 means Rule 16b-3, as from time to time in effect and applicable to the Plan and Participants, promulgated by the Securities and Exchange Commission under Section 16 of the Exchange Act.
(m) Stock means the common stock, no par value, of the Company and such other securities as may be substituted for Stock or for such other securities pursuant to Section 4(c).
(n) Subsidiary or Subsidiaries means any corporation or corporations which, together with the Company, would form a group of corporations described in Code section 424(f). The term shall include the Utility. The term shall also refer to any entity designated as such by the Board for purposes of the Plan.
(o) Utility means Washington Gas Light Company.
SECTION 3
ADMINISTRATION
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(a) Authority of the Committee. The Plan shall be administered by the Committee. The Committee shall have full and final authority to take the following actions, in each case subject to and consistent with the provisions of the Plan:
(i) to select persons to whom Awards may be granted;
(ii) to determine the type or types of Awards to be granted to each such person;
(iii) to determine the number of Awards to be granted, the number of shares of Stock to which an Award will relate, the terms and conditions of any Award (including, without limitation, any exercise price, any grant price or purchase price, any restriction or condition, any schedule for lapse of restrictions or conditions relating to transferability, forfeiture, exercisability or settlement and any waivers or accelerations thereof and any performance conditions (including, without limitation, any performance conditions relating to Awards not intended to be governed by Section 7(e) and any waivers and modifications thereof), based in each case on such considerations as the Committee shall determine) and all other matters to be determined in connection with an Award;
(iv) to determine whether, to what extent and under what circumstances an Award may be settled, or the exercise price of an Award may be paid, in cash, Stock, other Awards or other property, or an Award may be canceled, forfeited or surrendered;
(v) to determine whether, to what extent and under what circumstances cash, Stock, other Awards or other property payable with respect to an Award will be deferred either automatically, or at the election of the Committee or of the Participant;
(vi) to prescribe the form of each Award Agreement, which need not be identical for each Participant;
(vii) to adopt, amend, suspend, waive and rescind such rules and regulations and appoint such agents as the Committee may deem necessary or advisable to administer the Plan;
(viii) to correct any defect or omission or reconcile any inconsistency in the Plan and to construe and interpret the Plan and any Award, rules and regulations or Award Agreement; and
(ix) to make all other decisions and determinations as may be required under the terms of the Plan or as the Committee may deem necessary or advisable for the proper administration of the Plan.
Other provisions of the Plan notwithstanding, the Board may perform any function of the Committee under the Plan, including, without limitation, for the purpose of ensuring that transactions under the Plan by Participants who are then subject to Section 16 of the Exchange Act in respect of the Company are exempt under Rule 16b-3. In any case
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in which the Board is performing a function of the Committee under the Plan, each reference to the Committee herein shall be deemed to refer to the Board.
(b) Manner of Exercise of Committee Authority. Any determination or action of the Committee with respect to the Plan or any Award shall be taken in the sole and absolute discretion of the Committee and shall be final, conclusive and binding on all persons, including, without limitation, the Company, any Subsidiary, any Participant, any person claiming any rights or interests under the Plan or any Award from or through any Participant and the Companys shareholders, except to the extent that the Committee may subsequently modify, or make a further determination or take further action not consistent with its prior determination or action. If not specified in the Plan, the time at which the Committee must or may make any determination or take any action shall be determined by the Committee, and any such determination or action may thereafter be modified by the Committee (subject to Sections 8(e) and 8(f)). The express grant of any specific power to the Committee, the making of any determination or the taking of any action by the Committee or the failure to make any determination or take any action shall not be construed as limiting any power or authority of the Committee. Except as provided in Section 7(e), the Committee may delegate to officers or managers of the Company or any Subsidiary authority, subject to such terms and conditions as the Committee shall determine, to perform such functions as the Committee may determine, to the extent permitted under applicable law.
(c) Limitation of Liability. Each member of the Committee shall be entitled to, in good faith, rely or act upon any report or other information furnished to him by any officer or other employee of the Company or any Subsidiary, the Companys independent certified public accountants or any executive compensation consultant, legal counsel or other professional retained by the Company to assist in the administration of the Plan. No member of the Committee, nor any officer or employee of the Company acting on behalf of the Committee, shall be personally liable for any determination, action or interpretation taken or made in good faith with respect to the Plan, and all members of the Committee and any officer or employee of the Company acting on its behalf shall, to the extent permitted by law, be fully indemnified and protected by the Company with respect to any such determination, action or interpretation.
SECTION 4
STOCK SUBJECT TO THE PLAN AND MAXIMUM AWARDS
(a) Shares of Stock Reserved. Subject to adjustment as provided in Section 4(c), the total number of shares of Stock reserved and available for delivery pursuant to Awards shall not exceed 2,000,000. Shares subject to any Award which is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of fully tradeable shares of Stock to the Participant (or Beneficiary), including, without limitation, shares of Restricted Stock that are forfeited and shares of Stock withheld or surrendered in payment of any exercise price of an Award or taxes related to an Award,
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shall again be available for delivery pursuant to Awards. Notwithstanding the foregoing, the number of shares that may be delivered upon the exercise of ISOs shall not exceed 2,000,000, and the number of shares that may be delivered in the form of Restricted Stock shall not exceed 300,000, in each case subject to adjustment as provided in Section 4(c). Any shares of Stock delivered pursuant to an Award may consist, in whole or in part, of authorized and unissued shares, treasury shares or shares acquired by the Company.
(b) Annual Per-Participant Limitations. During any Plan Year, no Participant may be granted Awards relating to more than 400,000 shares of Stock, subject to adjustment as provided in Section 4(c). In addition, with respect to Cash Awards, no Participant may be paid during any Plan Year cash or other property relating to such Awards that exceeds the Fair Market Value of the number of shares of Stock set forth in the preceding sentence, determined either at the date of grant or the date of settlement, whichever is greater. This provision sets forth two separate limitations, so that Awards that may be settled solely by delivery of Stock will not operate to reduce the amount of Cash Awards, and vice versa. Awards that may be settled either in Stock or in cash must not exceed either limitation during the applicable Plan Year.
(c) Adjustments. In the event that the Committee shall determine that any recapitalization, forward or reverse split, reorganization, merger, consolidation, spin-off, combination, repurchase or exchange of Stock or other securities, Stock dividend or other special, large and nonrecurring dividend or distribution (whether in the form of cash, securities or other property), liquidation, dissolution or other similar corporate transaction or event affects the Stock such that an adjustment is appropriate in order to prevent dilution or enlargement of the rights of Participants, then the Committee shall, in such manner as it may deem equitable, adjust any or all of (i) the number and kind of shares of Stock reserved and available for delivery pursuant to Awards under Section 4(a), including, without limitation, the share limitations for Restricted Stock and ISOs, (ii) the number and kind of shares of Stock specified in the annual per-Participant limitations under Section 4(b), (iii) the number and kind of shares of Stock relating to outstanding Restricted Stock or other Awards in connection with which shares have been issued, (iv) the number and kind of shares of Stock that may be issued in respect of any other outstanding Awards and (v) the exercise price, grant price or purchase price relating to any Awards (or, if deemed appropriate, the Committee may make provision for a cash payment with respect to any outstanding Awards). In addition, the Committee is authorized to make adjustments in the terms and conditions of, and the criteria included in, Awards (including, without limitation, cancellation of unexercised or outstanding Awards, or substitution of Awards using stock of a successor or other entity) in recognition of unusual or nonrecurring events (including, without limitation, events described in the preceding sentence and events constituting a Change of Control) affecting the Company or any Subsidiary or the financial statements of the Company or any Subsidiary, or in response to changes in applicable laws, regulations or accounting principles. Notwithstanding anything herein to the contrary, without the prior approval of the shareholders of the Company, neither the Board nor the Committee may take any action that would constitute a repricing of an outstanding
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Option.
SECTION 5
ELIGIBILITY
Executive officers and other key employees of the Company or of any Subsidiary, including any member of the Board who is also such an employee, and persons who provide consulting or other services to the Company or any Subsidiary deemed by the Committee to be of substantial value, are eligible to be granted Awards. In addition, persons who have been offered employment by the Company or any Subsidiary, and persons employed by an entity that the Committee reasonably expects to become a Subsidiary, are eligible to be granted Awards.
SECTION 6
SPECIFIC TERMS OF AWARDS
(a) General. Awards may be granted on the terms and conditions set forth in this Section 6. In addition, the Committee may impose, in connection with any Award, such additional terms and conditions, not inconsistent with the provisions of the Plan, as the Committee shall determine, including, without limitation, terms requiring forfeiture of Awards in the event of termination of employment or service of the Participant. Except as provided in Section 6(f), 6(h) or 7(a), or to the extent required to comply with requirements of applicable law, only services may be required as consideration for the grant (but not the exercise) of any Award.
(b) Options. The Committee is authorized to grant options to purchase Stock on the following terms and conditions (Options):
(i) Exercise Price. The exercise price per share of Stock purchasable under an Option shall be determined by the Committee; provided, however, that except as provided in Section 7(a), the exercise price shall be not less than the Fair Market Value on the date of grant.
(ii) Time and Method of Exercise. Each Option shall be exercisable during and over such period ending not later than ten years from the date it was granted, as may be determined by the Committee and stated in the Award Agreement. The Committee shall determine the time or times at which an Option may be exercised in whole or in part, the methods by which the exercise price may be paid or deemed to be paid, the form of such payment, including, without limitation, cash, Stock, other Awards or other property (including, without limitation, awards granted under other Company plans and through cashless exercise arrangements, to the extent permitted by applicable law) and the methods by which Stock will be delivered or deemed to be delivered to Participants.
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(iii) ISOs. The terms and conditions of any ISOs shall comply in all respects with the requirements of Code section 422. Notwithstanding anything to the contrary herein, no term of the Plan or of any Award Agreement relating to ISOs shall be interpreted, amended or altered, nor shall any discretion or authority granted hereunder be exercised, so as to cause the ISOs to fail to qualify as such under Code section 422, unless such result is mutually agreed to by the Company and the Participant.
(iv) Termination of Employment or Service. Unless otherwise determined by the Committee, upon termination of a Participants employment or service, as applicable, with the Company and all Subsidiaries, such Participant may exercise any Options during the three-month period following such termination of employment or service, but only to the extent that such Option was exercisable as of such termination of employment or service. Notwithstanding the foregoing, if the Committee determines that such termination is for cause, all Options held by the Participant shall terminate as of the termination of employment or service.
(c) Stock Appreciation Rights. The Committee is authorized to grant Stock appreciation rights on the following terms and conditions (SARs):
(i) Right to Payment. An SAR shall confer on the Participant to whom it is granted a right to receive, upon exercise thereof, the excess of (A) the Fair Market Value on the date of exercise (or, if the Committee shall so determine in the case of any such right other than one related to an ISO, the Fair Market Value at any time during a specified period before or after the date of exercise), over (B) the grant price of the SAR as determined by the Committee as of the date of grant of the SAR, which, except as provided in Section 7(a), shall be not less than the Fair Market Value on the date of grant.
(ii) Other Terms. The Committee shall determine the time or times at which an SAR may be exercised in whole or in part, the method of exercise, method of settlement, form of consideration payable in settlement, method by which Stock will be delivered or deemed to be delivered to Participants, whether or not an SAR shall be in tandem with any other Award, and any other terms and conditions of any SAR.
(d) Restricted Stock. The Committee is authorized to grant restricted shares of Stock on the following terms and conditions (Restricted Stock):
(i) Grant and Restrictions. Restricted Stock shall be subject to such restrictions on transferability and other restrictions, if any, as the Committee may impose, which restrictions may lapse separately or in combination at such times, under such circumstances, in such installments or otherwise, as the Committee may determine. Except to the extent restricted under the terms of the Plan and any Award Agreement relating to the Restricted Stock, a Participant granted Restricted Stock shall have all of the rights of a shareholder, including, without limitation, the right to vote the Restricted Stock and the right to receive dividends thereon.
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(ii) Forfeiture. Except as otherwise determined by the Committee, upon a Participants termination of employment or service (as determined under criteria established by the Committee) during the applicable restriction period, Restricted Stock that is at that time subject to restrictions shall be forfeited and reacquired by the Company; provided, however, that the Committee may provide, by rule or regulation or in any Award Agreement, or may determine in any individual case, that restrictions or forfeiture conditions relating to Restricted Stock shall be waived in whole or in part in the event of termination resulting from specified causes.
(iii) Certificates for Stock. Restricted Stock may be evidenced in such manner as the Committee shall determine. If certificates representing Restricted Stock are registered in the name of the Participant, such certificates may bear an appropriate legend referring to the terms, conditions and restrictions applicable to the Restricted Stock, the Company may retain physical possession of the certificates and the Participant may be required to deliver a stock power to the Company, endorsed in blank, relating to the Restricted Stock.
(iv) Dividends. Dividends paid on Restricted Stock shall be either paid at the dividend payment date in cash or in shares of unrestricted Stock having a Fair Market Value equal to the aggregate amount of such dividends, or the payment of such dividends shall be deferred and/or the amount or value thereof automatically reinvested in additional shares of Restricted Stock, other Awards or other property, as the Committee shall determine or permit the Participant to elect. Stock distributed in connection with a Stock split or Stock dividend, and other property distributed as a dividend, shall be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Stock with respect to which such Stock or other property has been distributed, unless otherwise determined by the Committee.
(e) Deferred Stock. The Committee is authorized to grant deferred shares of Stock subject to the following terms and conditions (Deferred Stock):
(i) Award and Restrictions. Delivery of Deferred Stock shall occur upon expiration of the deferral period specified in the Award by the Committee or, if permitted by the Committee, as elected by the Participant. In addition, Deferred Stock shall be subject to such restrictions as the Committee may impose, if any, which restrictions may lapse at the expiration of the deferral period or at other specified times, separately or in combination at such times, under such circumstances, in installments or otherwise, as the Committee may determine.
(ii) Forfeiture. Except as otherwise determined by the Committee, upon termination of employment or service (as determined under criteria established by the Committee) during the applicable deferral period or portion thereof to which restrictions or forfeiture conditions apply, all Deferred Stock that is at that time subject to such restrictions or forfeiture conditions shall be forfeited; provided, however, that the Committee may provide, by rule or regulation or in any Award Agreement, or may
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determine in any individual case, that restrictions or forfeiture conditions relating to Deferred Stock shall be waived in whole or in part in the event of termination resulting from specified causes.
(f) Bonus Stock and Awards in Lieu of Cash Obligations. The Committee is authorized to grant Stock as a bonus, or to grant Stock or other Awards in lieu of Company obligations to pay cash or other property, under other plans or compensatory arrangements.
(g) Dividend Equivalents. The Committee is authorized to grant dividend equivalents entitling the Participant to receive cash, Stock, other Awards or other property equal in value to dividends paid with respect to a specified number of shares of Stock (Dividend Equivalents). Dividend Equivalents may be awarded on a free-standing basis or in connection with another Award. The Committee may provide that Dividend Equivalents shall be paid or distributed when accrued or shall be deemed to have been reinvested in additional Stock, Awards or other property, and shall be subject to such restrictions on transferability and risks of forfeiture, as the Committee may determine.
(h) Other Stock-Based or Cash Awards. The Committee is authorized, subject to limitations under applicable law, to grant such other Awards that may be denominated or payable in, valued in whole or in part by reference to or otherwise based on or related to Stock and factors that may influence the value of Stock, as deemed by the Committee to be consistent with the purposes of the Plan, including, without limitation, performance shares, convertible or exchangeable debt securities, other rights convertible or exchangeable into Stock, purchase rights for Stock, Awards with a value or payment contingent upon performance of Stock (or any other factors designated by the Committee) and Awards valued by reference to the book value of Stock or the value of securities of or the performance of specified Subsidiaries (Other Stock-Based Awards). The Committee shall determine the terms and conditions of such Awards. Stock issued pursuant to an Other Stock-Based Award in the nature of a purchase right granted under this Section 6(h) shall be purchased for such consideration, paid for at such times, by such methods and in such forms, including, without limitation, cash, Stock, other Awards or other property, as the Committee shall determine. Awards that may be settled in whole or in part in cash or other property (not including Stock) may also be granted pursuant to this Section 6(h) (Cash Awards). The Committee shall determine the terms and conditions of such Cash Awards.
SECTION 7
CERTAIN PROVISIONS APPLICABLE TO AWARDS
(a) Stand-Alone, Additional, Tandem and Substitute Awards. Awards may be granted either alone or in addition to, in tandem with or in substitution for any other Award or any award granted under any other plan of the Company, any business entity
- 11 -
to be acquired by the Company or any Subsidiary, or any other right of a Participant to receive payment from the Company or any Subsidiary. Awards granted in addition to or in tandem with other Awards or awards may be granted either as of the same time or as of a different time from the grant of such other Awards or awards.
(b) Term of Awards. The term of each Award shall be for such period as may be determined by the Committee; provided, however, that in no event shall the term of any ISO or any SAR granted in tandem therewith exceed the period permitted under Code section 422.
(c) Form of Payment Under Awards. Subject to the terms of the Plan and any applicable Award Agreement, payments to be made by the Company or any Subsidiary upon the grant, exercise or settlement of an Award may be made in such forms as the Committee shall determine, including, without limitation, cash, Stock, other Awards or other property, and may be made in a single payment or transfer, in installments or on a deferred basis. Such payments may include, without limitation, provisions for the payment or crediting of reasonable interest on installment or deferred payments or the grant or crediting of Dividend Equivalents in respect of installment or deferred payments denominated in Stock.
(d) Legal Compliance.
(i) Compliance with Code Section 162(m) . It is the intent of the Company that Options, SARs and other Awards designated as such constitute performance-based compensation within the meaning of Code section 162(m). Subject to automatic acceleration and payout resulting from a Change of Control under Section 7(f), if any provision of the Plan or of any Award Agreement relating to such an Award does not comply or is inconsistent with the requirements of Code section 162(m), such provision shall be construed or deemed amended to the extent necessary to conform to such requirements, and no provision shall be deemed to confer upon the Committee or any other person discretion to increase the amount of compensation otherwise payable in connection with any such Award upon attainment of the performance goals.
(ii) Section 16 Compliance. With respect to a Participant who is then subject to Section 16 of the Exchange Act in respect of the Company, the Committee shall implement transactions under the Plan and administer the Plan in a manner that will ensure that each transaction by such a Participant is exempt from liability under Rule 16b-3, except that such a Participant may be permitted to engage in a nonexempt transaction under the Plan if written notice has been given to the Participant regarding the nonexempt nature of such transaction. The Committee may authorize the Company to repurchase any Award or shares of Stock resulting from any Award in order to prevent a Participant who is subject to Section 16 of the Exchange Act from incurring liability under Section 16(b). Unless otherwise specified by the Participant, equity securities, including, without limitation, derivative securities, acquired under the Plan which are disposed of by a Participant shall be deemed to
- 12 -
be disposed of in the order acquired by the Participant.
(e) Performance-Based Awards. The Committee may designate any Award, the exercisability, vesting, payment or settlement of which is subject to the attainment of one or more preestablished performance goals, as a performance-based Award intended to qualify as performance-based compensation within the meaning of Code section 162(m). The performance goals for an Award subject to this Section 7(e) shall consist of one or more business criteria, identified below, and a targeted level or levels of performance with respect to such criteria, as specified by the Committee. Performance goals shall be objective and shall otherwise meet the requirements of Code section 162(m)(4)(C). The following business criteria for the Company, on a consolidated basis, and/or for specified Subsidiaries or business units of the Company, shall be used by the Committee in establishing performance goals for such Awards: (i) earnings; (ii) net income; (iii) net income applicable to Stock; (iv) revenue (v) cash flow; (vi) return on assets; (vii) return on net assets; (viii) return on invested capital; (ix) return on equity; (x) profitability; (xi) economic value added; (xii) operating margins or profit margins; (xiii) income before income taxes; (xiv) income before interest and income taxes; (xv) income before interest, income taxes, depreciation and amortization; (xvi) total return on Common Stock; (xvii) book value; (xviii) expense management; (xix) capital structure and working capital; (xx) strategic business criteria, consisting of one or more objectives based on meeting specified revenue, gross profit, market penetration, geographic business expansion, cost targets or goals relating to acquisitions or divestitures; (xxi) costs; (xxii) employee morale or productivity; (xxiii) customer satisfaction or loyalty; (xxiv) customer service; (xxv) compliance programs; (xxvi) gas delivered; (xxvii) system reliability; (xxviii) adequacy and security of gas supply; and (xxix) safety. The levels of performance required with respect to such business criteria may be expressed in absolute or relative terms, including, without limitation, per share amounts and comparisons to the performance of a published or special index deemed applicable by the Committee, such as the Standard & Poors 500 Stock Index or the performance of one or more comparator companies. In establishing the levels of performance to be attained, the Committee may disregard or offset the effect of such factors as extraordinary and/or nonrecurring events as determined by the Companys independent certified public accountants in accordance with generally accepted accounting principles and changes in or modifications to accounting standards as may be required by the Financial Accounting Standards Board. Achievement of performance goals with respect to such Awards shall be measured over a period of not less than one year nor more than five years, as the Committee may specify. Performance goals may differ for Awards to different Participants. The Committee shall specify the weighting to be given to each business criterion for purposes of determining the final amount payable with respect to any such Award. The Committee may reduce the amount of a payout otherwise to be made in connection with an Award subject to this Section 7(e), but may not exercise its discretion to increase such amount, and the Committee may consider other performance criteria in exercising such negative discretion. All determinations by the Committee as to the attainment of performance goals shall be in writing. The Committee may not delegate any responsibility with respect to an Award that is intended to qualify as performance-based compensation within the meaning of
- 13 -
Code section 162(m).
(f) Acceleration and Payout upon a Change of Control. Notwithstanding anything contained herein to the contrary, all conditions and/or restrictions relating to the continued performance of services and/or the achievement of performance goals with respect to the exercisability, vesting, payment or settlement of an Award shall immediately lapse upon a Change of Control, and all Awards shall be immediately paid or settled; provided, however, that such lapse shall not occur if the Committee determines that such lapse shall not occur.
- 14 -
SECTION 8
GENERAL PROVISIONS
(a) Compliance with Laws and Obligations. The Company shall not be obligated to issue or deliver Stock in connection with any Award or to take any other action under the Plan in a transaction subject to the requirements of any applicable securities law, any requirement under any listing agreement between the Company and any national securities exchange or automated quotation system or any other law, regulation or contractual obligation until the Company is satisfied that such laws, regulations and other obligations have been complied with in full. Certificates representing shares of Stock issued under the Plan may be subject to such stop-transfer orders and other restrictions as may be applicable under such laws, regulations and other obligations, including, without limitation, any requirement that a legend or legends be placed thereon.
(b) Limitations on Transferability. Awards and other rights or benefits under the Plan shall not be transferable by a Participant except by will or the laws of descent and distribution or to a Beneficiary in the event of the Participants death, shall not be pledged, mortgaged, hypothecated or otherwise encumbered, or otherwise be subject to the claims of creditors and, in the case of ISOs and SARs in tandem therewith, shall be exercisable during the lifetime of a Participant only by such Participant or his guardian or legal representative; provided, however, that Awards and other rights (other than ISOs and SARs in tandem therewith) may be transferred to one or more transferees during the lifetime of the Participant to the extent and on such terms and conditions as may then be permitted by the Committee.
(c) No Right to Continued Employment or Service. Neither the Plan nor any action taken hereunder shall be construed as giving any employee or any person the right to be retained in the employ or service, as applicable, of the Company or any Subsidiary, nor shall it interfere in any way with the right of the Company or any Subsidiary to terminate any employees employment or any persons service at any time.
(d) Taxes. The Company and any Subsidiary is authorized to withhold from any Award granted or exercised, vested, paid or settled any delivery of cash, Stock, other Awards or other property, or from any payroll or other payment to a Participant, amounts of withholding and other taxes due or potentially payable in connection with any transaction involving an Award, and to take such other action as the Committee may deem advisable to enable the Company and the Participant to satisfy obligations for the payment of withholding taxes and other tax obligations relating to any Award. This authority shall include, without limitation, authority to withhold or receive Stock, other Awards or other property, and to make cash payments in respect thereof, in satisfaction of a Participants tax obligations.
(e) Changes to the Plan and Awards. The Board may amend, alter, suspend,
- 15 -
discontinue or terminate the Plan or the Committees authority to grant Awards under the Plan without the consent of the Companys shareholders or Participants, except that any such Board action shall be subject to the approval of the Companys shareholders at or before the next annual meeting of shareholders for which the record date is after such Board action if such Board action increases the number of shares of Stock subject to the Plan or if such shareholder approval is required by any federal or state law or regulation or the rules of any stock exchange or automated quotation system on which the Stock may then be listed or quoted, and the Board may otherwise, in its discretion, determine to submit other such changes to the Plan to shareholders for approval; provided, however, that, without the consent of an affected Participant, no such action may materially impair the rights or benefits of such Participant under any Award theretofore granted to him (as such rights and benefits are set forth in the Plan and the Award Agreement). The Committee may waive any terms or conditions under, or amend, alter, suspend, discontinue or terminate any Award theretofore granted and any Award Agreement relating thereto; provided, however, that, without the consent of an affected Participant, no such action may materially impair the rights or benefits of such Participant under such Award (as such rights or benefits are set forth in the Plan and the Award Agreement).
(f) Repricing Restriction. Notwithstanding anything herein to the contrary, without the prior approval of the shareholders of the Company, neither the Board nor the Committee may take any action that would constitute a repricing of an outstanding Option.
(g) No Rights to Awards; No Shareholder Rights. No Participant, employee or eligible person shall have any claim to be granted any Award, and there is no obligation for uniformity of treatment of Participants, employees or eligible persons. No Award shall confer on any Participant any of the rights or benefits of a shareholder of the Company unless and until Stock is duly issued or transferred and delivered to the Participant in accordance with the terms of the Award or, in the case of an Option, the Option is duly exercised.
(h) Unfunded Status of Awards; Creation of Trusts. The Plan is intended to constitute an unfunded plan for incentive and deferred compensation. With respect to any payments not yet made to a Participant pursuant to an Award, nothing contained in the Plan or any Award Agreement shall give any such Participant any rights or benefits that are greater than those of a general creditor of the Company; provided, however, that the Committee may authorize the creation of trusts or make other arrangements to meet the Companys obligations under the Plan to deliver cash, Stock, other Awards or other property pursuant to any Award, which trusts or other arrangements shall be consistent with the unfunded status of the Plan unless the Committee otherwise determines with the consent of an affected Participant.
(i) Nonexclusivity of the Plan. Neither the adoption of the Plan by the Board nor its submission to the Companys shareholders for approval shall be construed as creating any limitations on the power of the Board to adopt such other compensatory
- 16 -
arrangements as it may deem desirable, including, without limitation, the granting of stock options otherwise than under the Plan, and such arrangements may be either applicable generally or only in specific cases.
(j) No Fractional Shares. No fractional shares of Stock shall be issued or delivered pursuant to the Plan or any Award. The Committee shall determine whether cash, other Awards or other property shall be issued or paid in lieu of such fractional shares, or whether such fractional shares or any rights thereto shall be forfeited or otherwise eliminated.
(k) Gender; Singular and Plural. All masculine pronouns shall be deemed to include their feminine counterparts. As the context may require, the singular may be read as the plural and vice versa.
(l) Governing Law. The validity, construction and effect of the Plan or any Award Agreement and any rules and regulations relating to the Plan or any Award Agreement shall be determined in accordance with the laws of the Commonwealth of Virginia, without giving effect to principles of conflicts of laws, and applicable federal law.
(m) Effective Date; Plan Termination. The Plan shall become effective as of the date of its approval by the Companys shareholders, and shall continue in effect until terminated by the Board.
- 17 -
Exhibit 12.1
WGL HOLDINGS, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
($ in thousands)
Twelve Months Ended September 30,
2004
2003
2002
2001
2000
$
43,109
$
44,989
$
44,917
$
49,838
$
43,535
426
855
391
260
346
1,256
594
12
12
12
$
44,791
$
46,438
$
45,320
$
50,110
$
43,893
$
97,957
$
113,662
$
40,441
$
83,765
$
84,574
58,463
68,633
28,702
59,009
47,821
2,439
(665
)
3,175
(1,993
)
(153
)
44,791
46,438
45,320
50,110
43,893
$
203,650
$
228,068
$
117,638
$
190,891
$
176,135
4.5
4.9
2.6
3.8
4.0
Exhibit 12.2
WGL HOLDINGS, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
($ in thousands)
Twelve Months Ended September 30,
2004
2003
2002
2001
2000
$
1,320
$
1,320
$
1,320
$
1,320
$
1,323
0.3834
0.3742
0.4407
0.4050
0.3605
(1-Tax Rate)
0.6166
0.6258
0.5593
0.5950
0.6395
$
2,141
$
2,109
$
2,360
$
2,218
$
2,069
$
43,109
$
44,989
$
44,917
$
49,838
$
43,535
426
855
391
260
346
1,256
594
12
12
12
44,791
46,438
45,320
50,110
43,893
2,141
2,109
2,360
2,218
2,069
$
46,932
$
48,547
$
47,680
$
52,328
$
45,962
$
97,957
$
113,662
$
40,441
$
83,765
$
84,574
58,463
68,633
28,702
59,009
47,821
2,439
(665
)
3,175
(1,993
)
(153
)
44,791
46,438
45,320
50,110
43,893
$
203,650
$
228,068
$
117,638
$
190,891
$
176,135
4.3
4.7
2.5
3.6
3.8
Exhibit 12.3
WASHINGTON GAS LIGHT COMPANY
Computation of Ratio of Earnings to Fixed Charges
($ in thousands)
Twelve Months Ended September 30,
2004
2003
2002
2001
2000
(a)
$
42,106
$
42,309
$
44,326
$
49,197
$
43,535
426
855
391
260
346
968
594
12
12
12
$
43,500
$
43,758
$
44,729
$
49,469
$
43,893
$
96,590
$
110,898
$
48,687
$
85,770
$
84,574
58,212
68,416
28,263
58,701
47,821
(4,668
)
(249
)
(512
)
(3,530
)
(153
)
43,500
43,758
44,729
49,469
43,893
$
193,634
$
222,823
$
121,167
$
190,410
$
176,135
4.5
5.1
2.7
3.8
4.0
(a) | Amounts for fiscal year 2000 reflects the consolidated balances of Washington Gas Light Company and its former subsidiaries. |
Exhibit 12.4
WASHINGTON GAS LIGHT COMPANY
Computation of Ratio of Earnings to Fixed Charges
($ in thousands)
Twelve Months Ended September 30,
2004
2003
2002
2001
2000
(a)
$
1,320
$
1,320
$
1,320
$
1,320
$
1,323
0.3566
0.3807
0.3639
0.3915
0.3605
(1-Tax Rate)
0.6434
0.6193
0.6361
0.6085
0.6395
$
2,052
$
2,131
$
2,075
$
2,169
$
2,069
$
42,106
$
42,309
$
44,326
$
49,197
$
43,535
426
855
391
260
346
968
594
12
12
12
43,500
43,758
44,729
49,469
43,893
2,052
2,131
2,075
2,169
2,069
$
45,552
$
45,889
$
46,804
$
51,638
$
45,962
$
96,590
$
110,898
$
48,687
$
85,770
$
84,574
58,212
68,416
28,263
58,701
47,821
(4,668
)
(249
)
(512
)
(3,530
)
(153
)
43,500
43,758
44,729
49,469
43,893
$
193,634
$
222,823
$
121,167
$
190,410
$
176,135
4.3
4.9
2.6
3.7
3.8
(a) Amounts for fiscal year 2000 reflects the consolidated balances of Washington Gas Light Company and its former subsidiaries. |
Exhibit 21
WGL HOLDINGS, INC.
Percent of
Voting
Securities
Subsidiary Relationship Denoted by Indentation
Owned
State of Incorporation
Virginia
100%
Virginia and the District of Columbia
100%
West Virginia
100%
Virginia
100%
Delaware
100%
Maryland
100%
Delaware
100%
Delaware
100%
Delaware
100%
Delaware
Exhibit 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in
Registration Statement Nos. 333-61199 and 333-104574 on
Form S-3, and in Registration Statement
Nos. 333-104571, 333-104572, 333-104573 and 333-01469 on
Form S-8 of our report dated December 8, 2004,
appearing in this Annual Report on Form 10-K of WGL
Holdings, Inc. and Washington Gas Light Company for the year
ended September 30, 2004.
DELOITTE & TOUCHE LLP
McLean, Virginia
Exhibit 31.1
CERTIFICATION OF WGL HOLDINGS, INC.
I, James H. DeGraffenreidt, Jr., certify that:
Date: December 9, 2004
/s/ James H. DeGraffenreidt, Jr.
1.
I have reviewed this annual report on
Form 10-K of WGL Holdings, Inc. and Washington Gas Light
Company;
2.
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4.
The registrants other certifying officer
and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures,
or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b)
Evaluated the effectiveness of the
registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
c)
Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants fourth fiscal quarter that
has materially affected, or is reasonably likely to materially
affect, the registrants internal control over financial
reporting; and
5.
The registrants other certifying officer
and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the
registrants auditors and the audit committee of the
registrants board of directors:
a)
All significant deficiencies and material
weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process,
summarize and report financial information; and
b)
Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
Exhibit 31.2
CERTIFICATION OF WGL HOLDINGS, INC.
I, Frederic M. Kline, certify that:
Date: December 9, 2004
/s/ Frederic M. Kline
1.
I have reviewed this annual report on
Form 10-K of WGL Holdings, Inc. and Washington Gas Light
Company;
2.
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4.
The registrants other certifying officer
and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures,
or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b)
Evaluated the effectiveness of the
registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
c)
Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants fourth fiscal quarter that
has materially affected, or is reasonably likely to materially
affect, the registrants internal control over financial
reporting; and
5.
The registrants other certifying officer
and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the
registrants auditors and the audit committee of the
registrants board of directors:
a)
All significant deficiencies and material
weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process,
summarize and report financial information; and
b)
Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
Exhibit 31.3
CERTIFICATION OF WASHINGTON GAS LIGHT
COMPANY
I, James H. DeGraffenreidt, Jr., certify that:
Date: December 9, 2004
/s/ James H. DeGraffenreidt, Jr.
1.
I have reviewed this annual report on
Form 10-K of WGL Holdings, Inc. and Washington Gas Light
Company;
2.
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4.
The registrants other certifying officer
and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures,
or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b)
Evaluated the effectiveness of the
registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
c)
Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants fourth fiscal quarter that
has materially affected, or is reasonably likely to materially
affect, the registrants internal control over financial
reporting; and
5.
The registrants other certifying officer
and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the
registrants auditors and the audit committee of the
registrants board of directors:
a)
All significant deficiencies and material
weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process,
summarize and report financial information; and
b)
Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
Exhibit 31.4
CERTIFICATION OF WASHINGTON GAS LIGHT
COMPANY
I, Frederic M. Kline, certify that:
Date: December 9, 2004
/s/ Frederic M. Kline
1.
I have reviewed this annual report on
Form 10-K of WGL Holdings, Inc. and Washington Gas Light
Company;
2.
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statements made, in light
of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements,
and other financial information included in this report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this report;
4.
The registrants other certifying officer
and I are responsible for establishing and maintaining
disclosure controls and procedures (as defined in Exchange Act
Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures,
or caused such disclosure controls and procedures to be designed
under our supervision, to ensure that material information
relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is
being prepared;
b)
Evaluated the effectiveness of the
registrants disclosure controls and procedures and
presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
c)
Disclosed in this report any change in the
registrants internal control over financial reporting that
occurred during the registrants fourth fiscal quarter that
has materially affected, or is reasonably likely to materially
affect, the registrants internal control over financial
reporting; and
5.
The registrants other certifying officer
and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the
registrants auditors and the audit committee of the
registrants board of directors:
a)
All significant deficiencies and material
weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process,
summarize and report financial information; and
b)
Any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial reporting.
Exhibit 32
CERTIFICATION OF THE CHAIRMAN AND CHIEF
EXECUTIVE OFFICER
In connection with the combined Annual Report of
WGL Holdings, Inc. and Washington Gas Light Company (the
Companies) on Form 10-K for the annual period
ended September 30, 2004 as filed with the Securities and
Exchange Commission on the date hereof (the Report),
James H. DeGraffenreidt, Jr., Chairman and Chief Executive
Officer of the Companies, and Frederic M. Kline, Vice President
and Chief Financial Officer of the Companies, each hereby
certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant
to § 906 of the Sarbanes-Oxley Act of 2002, to the best of
their knowledge, that:
This certification is being made for the
exclusive purpose of compliance by the Chairman and Chief
Executive Officer and the Vice President and Chief Financial
Officer of the Companies with the requirements of
Section 906 of the Sarbanes-Oxley Act of 2002, and may not
be disclosed, distributed, or used by any person for any reason
other than as specifically required by law.
/s/ James H. DeGraffenreidt, Jr.
/s/ Frederic M. Kline
(1)
The Report fully complies with the requirements
of Section 13(a) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly
presents, in all material respects, the financial condition and
results of operations of the Companies.
December 9, 2004