UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
| | [X] | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2005
| | [ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | | For the transition period from ____________to ______________. |
Commission File Number: 000-22211
SOUTH JERSEY GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey | 21-0398330 |
| (State of incorporation) | (IRS employer identification no.) |
1 South Jersey Plaza, Folsom, New Jersey 08037
(Address of principal executive offices, including zip code)
(609) 561-9000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act: Yes [ ] No [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer”
in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
All of the equity securities of the registrant are owned by South Jersey Industries, Inc., its parent company, a 1934 Act reporting company named in the registrants description of its business, which has itself fulfilled its 1934 Act filing requirements.
During the preceding 36 months (and any subsequent period of days) there has not been any default in (1) any of the indebtedness of the registrant or its subsidiaries, and (2) the payment of rentals under material long-term leases (of which there are none).
The registrant meets all of the conditions set forth in General Instruction I 1(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.
Documents Incorporated by Reference: None
PART I
Item 1. Business
General
The registrant, South Jersey Gas Company (SJG), a New Jersey corporation, is an operating public utility. All of the common equity securities of SJG are owned by South Jersey Industries, Inc. (SJI), its parent company, which is itself a 1934 Act reporting company.
Information regarding SJG can be found at SJI’s internet address, www.sjindustries.com. We make available free of charge on or through our website SJG’s annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (SEC). The SEC maintains an Internet site that contains these reports at http://www.sec.gov. The content on any web site referred to in this filing is not incorporated by reference into this filing unless expressly noted otherwise.
Financial Information About Industry Segments
Not applicable.
Units of Measurement
| | For Natural Gas: | |
| | 1 Mcf | = One thousand cubic feet |
| | 1 MMcf | = One million cubic feet |
| | 1 Bcf | = One billion cubic feet |
Description of Business
SJG is an operating public utility company engaged in the purchase, transmission and sale of natural gas for residential, commercial and industrial use. SJG also sells natural gas and pipeline transportation capacity (off-system sales) on a wholesale basis to various customers on the interstate pipeline system and transports natural gas purchased directly from producers or suppliers by some of its customers.
SJG’s service territory covers approximately 2,500 square miles in the southern part of New Jersey. It includes 112 municipalities throughout Atlantic, Cape May, Cumberland and Salem Counties and portions of Burlington, Camden and Gloucester Counties, with an estimated permanent population of 1.2 million. SJG benefits from its proximity to Philadelphia and Wilmington on the western side of its service territory and Atlantic City and the burgeoning shore communities on the eastern side. Economic development and housing growth had long been driven by the development of the Philadelphia metropolitan area. In recent years, however, housing growth in the eastern portion of the service territory has increased substantially and now accounts for approximately half of SJG’s annual customer growth. The foundation for growth in Atlantic City and the surrounding region rests primarily with new gaming and non-gaming investments that emphasize destination style attractions. The casino industry is expected to remain a significant source of regional economic development going forward. The ripple effect from Atlantic City continues to produce new housing, commercial and industrial construction. Combining with the gaming industry catalyst is the ongoing conversion of southern New Jersey’s oceanfront communities from seasonal resorts to year round economies. New and expanded hospitals, schools, and large scale retail developments throughout the service territory have contributed to SJG’s growth. Presently, SJG serves approximately 58% of households within its territory with natural gas. SJG also serves southern New Jersey’s diversified industrial base that includes processors of petroleum and agricultural products; chemical, glass and consumer goods manufacturers; and high technology industrial parks.
SJG serves 322,424 residential, commercial and industrial customers (at December 31, 2005) in southern New Jersey. Gas sales, transportation and capacity release for 2005 amounted to 153,911 MMcf (million cubic feet), of which 54,180 MMcf was firm sales and transportation, 2,830 MMcf was interruptible sales and transportation and 96,901 MMcf was off-system sales and capacity release. The breakdown of firm sales and transportation includes 44.6% residential, 22.8% commercial, 3.7% cogeneration and electric generation and 28.9% industrial. At year-end 2005, SJG served 300,652 residential customers, 21,322 commercial customers and 450 industrial customers. This includes 2005 net additions (losses) of 8,467 residential customers, 383 commercial customers and (5) industrial customers.
Under an agreement with Atlantic City Electric Company, an electric utility serving southern New Jersey, SJG supplies natural gas to several electric generation facilities. This gas service is provided under the terms of a firm electric service tariff approved by the New Jersey Board of Public Utilities (BPU) on a demand/commodity basis. In 2005, 1.96 Bcf (billion cubic feet) was delivered under this agreement.
SJG serviced 9 cogeneration facilities in 2005. Combined sales and transportation of natural gas to such customers amounted to approximately 3.15 Bcf in 2005, 0.45 Bcf less than 2004. The decrease in sales and transportation volumes to these cogeneration customers was due to the cessation of operations at a large cogeneration facility during 2005. However, SJG started serving 4 additional, smaller facilities during the year.
SJG makes wholesale gas sales for resale to gas marketers for ultimate delivery to end users. These “off-system” sales are made possible through the issuance of the Federal Energy Regulatory Commission (FERC) Orders No. 547 and 636. Order No. 547 issued a blanket certificate of public convenience and necessity authorizing all parties, which are not interstate pipelines, to make FERC jurisdictional gas sales for resale at negotiated rates, while Order No. 636 allowed SJG to deliver gas at delivery points on the interstate pipeline system other than its own city gate stations and release excess pipeline capacity to third parties. During 2005, off-system sales amounted to 14.4 Bcf. Also in 2005, capacity release and storage throughput amounted to 82.5 Bcf.
Supplies of natural gas available to SJG that are in excess of the quantity required by those customers who use gas as their sole source of fuel (firm customers) make possible the sale and transportation of gas on an interruptible basis to commercial and industrial customers whose equipment is capable of using natural gas or other fuels, such as fuel oil and propane. The term “interruptible” is used in the sense that deliveries of natural gas may be terminated by SJG at any time if this action is necessary to meet the needs of higher priority customers as described in SJG’s tariffs. Usage by interruptible customers, excluding off-system customers, in 2005 amounted to approximately 2.8 Bcf, approximately 1.8% of the total throughput.
No material part of SJG’s business is dependent upon a single customer or a few customers.
In 2005, SJG made no public announcement of, or otherwise made public information about, a new product or industry segment that would require the investment of a material amount of the assets of SJG or which otherwise was material.
Rates and Regulation
As a public utility, SJG is subject to regulation by the New Jersey Board of Public Utilities (BPU). Additionally, the Natural Gas Policy Act, which was enacted in November 1978, contains provisions for Federal regulation of certain aspects of SJG’s business. SJG is affected by Federal regulation with respect to transportation and pricing policies applicable to its pipeline capacity from Transcontinental Gas Pipeline Corporation, SJG’s major supplier, Columbia Gas Transmission Corporation, Columbia Gulf Transmission Company, Dominion Transmission, Inc., and Texas Gas Transmission Corporation, since such services are provided under rates and terms established under the jurisdiction of the FERC.
Retail sales by SJG are made under rate schedules within a tariff filed with and subject to the jurisdiction of the BPU. These rate schedules provide primarily for either block rates or demand/commodity rate structures. The tariff allows for the adjustment of revenues when temperatures are higher or lower than normal, thereby stabilizing SJG’s income. In years which are warmer or colder than normal, SJG increases or decreases its revenue, respectively, to a level equivalent with that of normal temperature. The tariff also contains provisions permitting the recovery of environmental remediation costs associated with former manufactured gas plant sites, energy efficiency and renewable energy program costs, consumer education program costs and low-income program costs. These costs are recovered through SJG’s Societal Benefits Clause. In addition, the tariff contains provisions permitting SJG to pass on to customers increases and decreases in the cost of purchased gas supplies. The cost of gas purchased from the utility by consumers is set annually by the BPU through a Basic Gas Supply Service (BGSS) within SJG’s tariff. When actual gas costs experienced by SJG are less than those charged to customers under BGSS, customer bills in the subsequent BGSS period(s) are reduced by returning the overrecovery with interest. When actual gas costs are more than is recovered through rates, SJG is permitted to charge customers more for gas in future periods for the underrecovery.
In February 1999, the Electric Discount and Energy Competition Act (the Act) was signed into law in New Jersey. This bill created the framework and necessary time schedules for the restructuring of the state’s electric and natural gas utilities. The Act established unbundling, where redesigned utility rate structures allow natural gas and electric consumers to choose their energy supplier. It also established time frames for instituting competitive services for customer account functions and for determining whether basic gas supply services should become competitive.
In January 2000, the BPU approved full unbundling of SJG’s system. This allows all natural gas consumers to select their natural gas supplier. Customers choosing to purchase natural gas from providers other than the utility are charged for the cost of gas by the marketer, not the utility. The resulting decrease in SJG’s revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect SJG’s net income or financial condition. The BPU continues to allow for full recovery of natural gas costs.
In December 2002, the BPU approved the BGSS price structure. BGSS is the gas supply service being provided by the natural gas utility. Upon implementation of BGSS in 2003, customers have the ability to make more informed decisions regarding their choices of an alternate supplier by having a utility price structure that is more consistent with market conditions. Further, BGSS provides SJG with more pricing flexibility, through automatic rate changes, conceptually resulting in the reduction of over/under-recoveries. Although the BGSS price structure replaced the pricing structure in the previous rate clause, all other mechanisms from the previous clause, such as, but not limited to, deferred accounting treatment and the allowance for full recovery of natural gas costs, remain in place under BGSS
In July 2004, the BPU approved SJG’s August 2002 petition and related agreements to transfer its appliance service business from the regulated utility. SJI had previously formed South Jersey Energy Service Plus (SJESP) to accommodate the transfer. SJESP purchased certain assets and assumed certain liabilities of the appliance service business for the net book value of $1.2 million. SJESP paid an additional $1.5 million for certain intangible assets and that amount was credited by SJG to its customers through the Remediation Adjustment Clause.
In January 1997, the BPU granted SJG rate relief, which was predicated in part upon a 9.62% rate of return on rate base that included an 11.25% return on common equity. This rate relief provided cost-of-service recovery, including deferred costs, through base rates. Additionally, SJG’s threshold for sharing pre-tax margins generated by interruptible and off-system sales and transportation had increased. As a result of this case, SJG kept 100% of pre-tax margins up to the threshold level of $7.8 million. The next $750,000 was credited to customers through the BGSS clause. Thereafter, SJG kept 20% of the pre-tax margins as it had historically.
On July 7, 2004, the BPU granted SJG a base rate increase of $20.0 million, which was predicated in part upon a 7.97% rate of return on rate base that included a 10.0% return on common equity. The increase was effective July 8, 2004 and designed to provide an incremental $8.5 million on an annualized basis to net income. SJG was also permitted recovery of regulatory assets contained in its petition and a reduction in its composite depreciation rate from 2.9% to 2.4%.
Included in the base rate increase was a change to the sharing of pre-tax margins on interruptible and off-system sales and transportation. SJG now recovers through its base rates the $7.8 million that it had previously recovered through the sharing of pre-tax margins. As a result, the sharing of pre-tax margins now begins from dollar one, with SJG retaining 20%. Moreover, SJG now shares pre-tax margins from on-system capacity release sales, in addition to the interruptible and off-system sales and transportation. Effective July 1, 2006, the 20% retained by SJG will decrease to 15% of such margins.
As part of the overall settlement effective July 8, 2004, SJG reduced rates in several rate clauses that were no longer needed by SJG to recover costs. SJG was either no longer incurring or had already recovered the specific costs that these clauses were designed to recover. Since revenues raised under these clauses were for cost recovery only and had no profit margin built in, their elimination has no impact on SJG’s net income. However, SJG’s customers’ bills declined by an estimated $38.9 million annually due to the elimination of these clauses, more than offsetting the base rate increase awarded.
Additional information on regulatory affairs is incorporated by reference to Notes 1, 2, 6, 11 and 12 of SJG’s financial statements for the year ended December 31, 2005. See Item 8.
Raw Materials
Transportation Contracts and Storage
SJG has direct connections to two interstate pipeline companies, Transcontinental Gas Pipeline Corporation (Transco) and Columbia Gas Transmission Corporation (Columbia). During 2005, SJG purchased and had delivered approximately 42.9 Bcf of natural gas for distribution to both on-system and off-system customers. Of this total, 25.8 Bcf was transported on the Transco pipeline system and 17.1 Bcf was transported on the Columbia pipeline system. SJG also secures firm transportation and other long term services from three additional pipelines upstream of the Transco and Columbia systems. They include Columbia Gulf Transmission Company (Columbia Gulf), Texas Gas Transmission Corporation (Texas Gas) and Dominion Transmission Inc. (Dominion). Services provided by these upstream pipelines are utilized to deliver gas into either the Transco or Columbia systems for ultimate delivery to SJG. Services provided by all of the above-mentioned pipelines are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).
Transco:
Transco is SJG’s largest supplier of long-term gas transmission services. These services include six year-round and one seasonal firm transportation (FT) service arrangements. When combined, these services enable SJG to purchase from third parties and have delivered to its city gate stations by Transco a total of 271,038 Thousand Cubic Feet of gas per day (Mcf/d). The terms of the year-round agreements extend for various periods from 2007 to 2025 while the term of the seasonal agreement extends to 2011.
SJG also has seven long-term gas storage service agreements with Transco that, when combined, are capable of storing approximately 10.1 Bcf. Through these services, SJG can inject gas into market area storage during periods of low demand and withdraw gas at a rate of up to 86,972 Mcf/d during periods of high demand. The terms of the storage service agreements extend for various periods from 2005 to 2017.
Dominion:
SJG has a storage service with Dominion which provides a maximum withdrawal capacity of 9,662 Mcf per day during the period between November 16 and March 31 of winter season with 408,696 Mcf of storage capacity. Gas is delivered through both the Dominion and Transco pipeline systems.
Columbia:
SJG has two firm transportation agreements with Columbia which, when combined, provide for 43,500 Mcf/d of firm deliverability.
SJG also subscribes to a firm storage service from Columbia, to March 31, 2009, which provides a maximum withdrawal quantity of 51,102 Mcf/d during the winter season with an associated 3,355,557 Mcf of storage capacity.
Gas Supplies
SJG has two long-term gas supply agreements with a single producer and marketer that expire on October 31, 2006. Under these agreements, SJG can purchase up to 6,798,628 Mcf of natural gas per year. When advantageous, SJG can purchase spot supplies of natural gas in place of or in addition to those volumes reserved under long-term agreements. In recent years, SJG has replaced long-term gas supply contracts with short-term agreements. The short-term agreements are typically for several months in duration. The above contract will not be renewed.
Supplemental Gas Supplies
During 2005 SJG entered into two separate Liquefied Natural Gas (LNG) sales agreements with third party suppliers. The term of one agreement extended through November 23, 2005, and had an associated contract quantity of 116,279 Mcf. The second agreement, which extends through October 31, 2006, replaced the first agreement and provides SJG with up to 186,047 Mcf of LNG.
SJG operates peaking facilities which can store and vaporize LNG for injection into its distribution system. SJG’s LNG facility has a storage capacity equivalent to 404,000 Mcf of natural gas and has an installed capacity to vaporize up to 90,000 Mcf of LNG per day for injection into its distribution system.
SJG also operates a high-pressure pipe storage field at its New Jersey LNG facility which is capable of storing 12,000 Mcf of gas and injecting up to 10,000 Mcf/d of gas per day into SJG’s distribution system.
Peak-Day Supply
SJG plans for a winter season peak-day demand on the basis of an average daily temperature of
2 degrees F. Gas demand on such a design day was estimated for the 2005-2006 winter season to be 519,892 Mcf. SJG projects that it has adequate supplies and interstate pipeline entitlements to meet its design requirements. On January 23, 2005, SJG experienced its highest peak-day demand for the year of 405,994 Mcf with an average temperature of 14.25 degrees F.
Natural Gas Prices
SJG’s average cost of natural gas purchased and delivered in 2005, 2004 and 2003, including demand charges, was $9.74 per Mcf, $7.39 per Mcf and $6.74 per Mcf, respectively.
Patents and Franchises
SJG holds nonexclusive franchises granted by municipalities in the seven-county area of southern New Jersey that it serves. No other natural gas public utility presently serves the territory covered by SJG’s franchises. Otherwise, patents, trademarks, licenses, franchises and concessions are not material to the business of SJG.
Seasonal Aspects
SJG experiences seasonal fluctuations in sales when selling natural gas for heating purposes. SJG meets this seasonal fluctuation in demand from its firm customers by buying and storing gas during the summer months, and by drawing from storage and purchasing supplemental supplies during the heating season. As a result of this seasonality, SJG’s revenues and net income are significantly higher during the first and fourth quarters than during the second and third quarters of the year.
Working Capital Practices
Reference is made to “Liquidity and Capital Resources” included in Item 7, Management’s Discussion and Analysis of Results of Operations and Financial Condition.
Customers
No material part of SJG’s business is dependent upon a single customer or a few customers, the loss of which would have a material adverse effect SJG’s business. See Item 1, “Description of Business.”
Backlog
Backlog is not material to an understanding of SJG’s business.
Government Contracts
No material portion of SJG’s business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of any government.
Competition
SJG’s franchises are non-exclusive; however, no other utility provides natural gas service within its territory. SJG does not expect any other utilities to do so in the foreseeable future because of the extensive investment required for utility plant and related costs. SJG competes with oil, propane and electricity suppliers for residential, commercial and industrial users. SJG competes with alternative fuel source providers based upon price, convenience and environmental factors. The market for natural gas commodity sales is subject to competition as a result of deregulation. Through its tariff, SJG has promoted competition while maintaining its margins. Substantially all of SJG’s profits are from the transportation, rather than the sale, of the commodity. SJG has maintained its focus on being a low-cost provider of natural gas. SJG also competes with other marketers/brokers in the selling of wholesale natural gas services.
Research
During the last three fiscal years, SJG did not engage in research activities to any material extent.
Environmental Matters
Information on environmental matters is incorporated by reference to Note 12 to SJG’s financial statements for the year ended December 31, 2005. See Item 8.
Employees
SJG had a total of 505 employees as of December 31, 2005. Of that total, 321 employees are unionized. Employees totaling 270 and 51 are covered under collective bargaining agreements that expire in January 2009 and January 2008, respectively. We consider relations with employees to be good.
Financial Information About Foreign and Domestic Operations and Export Sales
SJG has no foreign operations and export sales are not a part of its business.
Item 1A. Risk Factors
SJG operates in an environment that involves risks, many of which are beyond our control. The Company has identified the following risk factors that could cause the Company’s operating results and financial condition to be materially adversely affected. Security Holders should carefully consider these risk factors and should also be aware that this list is not all-inclusive of existing risks. In addition, new risks may emerge at any time, and the Company cannot predict those risks or the extent to which they may affect the Company’s businesses or financial performance.
| | · | SJG’s business activities are concentrated in southern New Jersey. Changes in the economies of southern New Jersey and surrounding regions could negatively impact the growth opportunities available to SJG and the financial condition of customers and prospects of SJG. |
| | · | SJG may not be able to respond effectively to competition, which may negatively impact SJG’s financial performance or condition. Regulatory initiatives may provide or enhance opportunities for competitors that could reduce utility income obtained from existing or prospective customers. Also, competitors may be able to provide superior or less costly products or services based upon currently available or newly developed technologies. |
| | · | Warm weather or high commodity costs could result in reduced demand for some of our energy products and services. While SJG has a temperature adjustment clause that protects its revenues and gross margin against temperatures that are higher than normal, the clause does not protect against changes in the amount of gas that customers use at specific temperature levels. Also, customers could reduce gas consumption in response to high gas costs. Lower customer energy utilization levels will reduce SJG’s net income. |
| | · | High natural gas prices could cause more of SJG’s receivables to be uncollectible. Higher levels of uncollectibles from either residential or commercial customers would negatively impact SJG’s income and could result in higher working capital requirements. |
| | · | SJG’s net income could decrease if it is required to incur additional costs to comply with new governmental safety, health or environmental legislation. SJG is subject to extensive and changing federal and state laws and regulations that impact many aspects of its business; including the storage, transportation and distribution of natural gas, as well as the remediation of environmental contamination at former manufactured gas plant facilities. |
| | · | Increasing interest rates will negatively impact the net income of SJG. SJG is capital intensive, resulting in the incurrence of significant amounts of debt financing. While all of SJG’s existing long-term debt has been issued at fixed rates, new issues of long-term debt and all variable rate short-term debt is exposed to the impact of rising interest rates. |
| | · | The inability to obtain natural gas would negatively impact the financial performance of SJG. SJG’s business is based upon the ability to deliver natural gas to customers. Disruption in the production of natural gas or transportation of that gas to SJG from its suppliers, could prevent SJG from completing sales to its customers. |
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The principal property of SJG consists of its gas transmission and distribution systems that include mains, service connections and meters. The transmission facilities carry the gas from the connections with Transco and Columbia to SJG’s distribution systems for delivery to customers. As of December 31, 2005, there were approximately 100.8 miles of mains in the transmission systems and 5,577 miles of mains in the distribution systems.
SJG owns office and service buildings, including its corporate headquarters, at seven locations in the territory. There is also a liquefied natural gas storage and vaporization facility at one of those locations.
As of December 31, 2005, SJG’s utility plant had a gross book value of $1,030 million and a net book value, after accumulated depreciation, of $788.8 million. In 2005, $74.9 million was spent on additions to utility plant and there were retirements of property having an aggregate gross book cost of $7.9 million. Construction and remediation expenditures for 2006 are currently expected to approximate $50.6 million.
Virtually all of SJG’s transmission pipeline, distribution mains and service connections are in streets or highways or on the property of others. The transmission and distribution systems are maintained under franchises or permits or rights-of-way, many of which are perpetual. SJG’s properties (other than property specifically excluded) are subject to a lien of mortgage under which its first mortgage bonds are outstanding. We believe these properties are well maintained and in good operating condition.
Item 3. Legal Proceedings
SJG is subject to claims which arise in the ordinary course of business and other legal proceedings. We accrue liabilities related to these claims when we can determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse affect on SJG’s financial position, results of operations or liquidity.
Item 4. Submission Of Matters To A Vote of Security Holders
Not applicable.
PART II
Item 5. Market for the Registrant’s Common Stock and
Related Stockholder Matters
Common equity securities of SJG, owned by its parent company, South Jersey Industries, Inc., are not traded on any stock exchange. SJG no longer has any preferred stock outstanding.
SJG is restricted as to the amount of cash dividends or other distributions that may be paid on its common stock by an order issued by the New Jersey Board of Public Utilities in July 2004, that granted SJG an increase in base rates. Per the order, SJG is required to maintain Total Common Equity of no less than $289 million. SJG’s Total Common Equity balance was $345 million at December 31, 2005.
SJG is also restricted under its First Mortgage Indenture, as supplemented, as to the amount of cash dividends or other distributions that may be paid on its common stock. As of December 31, 2005, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. Dividends of $22.5 million were declared on SJG’s common stock in 2005 and $9.1 million were declared in 2004.
Item 6. Selected Financial Data
The following financial data has been obtained from SJG’s audited financial statements:
(In Thousands)
| | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | | | | | | | | | | | | | | | |
| | | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 587,212 | | $ | 508,827 | | $ | 536,442 | | $ | 424,027 | | $ | 481,449 | |
| | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 77,676 | | $ | 71,451 | | $ | 65,420 | | $ | 60,874 | | $ | 60,462 | |
| | | | | | | | | | | | | | | | | |
| Income before Preferred Dividend | | | | | | | | | | | | | | | | |
| Requirement and Discontinued Operations | | $ | 34,592 | | $ | 31,597 | | $ | 26,743 | | $ | 23,357 | | $ | 21,666 | |
| | | | | | | | | | | | | | | | | |
| Preferred Dividend Requirements | | | (45 | ) | | (135 | ) | | (135 | ) | | (135 | ) | | (139 | ) |
| | | | | | | | | | | | | | | | | |
| Income from Continuing Operations | | | 34,547 | | | 31,462 | | | 26,608 | | | 23,222 | | | 21,527 | |
| | | | | | | | | | | | | | | | | |
| Loss from Discontinued Operations | | | - | | | - | | | - | | | (29 | ) | | (207 | ) |
| | | | | | | | | | | | | | | | | |
| Net Income Applicable to Common Stock | | $ | 34,547 | | $ | 31,462 | | $ | 26,608 | | $ | 23,193 | | $ | 21,320 | |
| | | | | | | | | | | | | | | | | |
| Average Shares of Common Stock Outstanding | | | 2,339,139 | | | 2,339,139 | | | 2,339,139 | | | 2,339,139 | | | 2,339,139 | |
| | | | | | | | | | | | | | | | | |
| Ratio of Earnings to Fixed Charges (1) | | | 4.0x | | | 3.9x | | | 3.3x | | | 2.9x | | | 2.6x | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | As of December 31, | |
| | | | | | | | | | | | | | | | | |
| | | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| | | | | | | | | | | | | | | | | |
| Property, Plant and Equipment, Net | | $ | 788,787 | | $ | 732,781 | | $ | 684,823 | | $ | 651,486 | | $ | 622,115 | |
| | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 1,168,153 | | $ | 1,007,733 | | $ | 956,537 | | $ | 926,318 | | $ | 898,604 | |
| | | | | | | | | | | | | | | | | |
| Capitalization: | | | | | | | | | | | | | | | | |
Common Equity (2) | | $ | 344,568 | | $ | 302,827 | | $ | 266,953 | | $ | 212,621 | | $ | 205,982 | |
Preferred Stock (3) | | | - | | | 1,690 | | | 1,690 | | | 1,690 | | | 1,690 | |
Long-Term Debt | | | 272,235 | | | 282,008 | | | 263,781 | | | 235,098 | | | 266,329 | |
| | | | | | | | | | | | | | | | | |
Total | | $ | 616,803 | | $ | 586,525 | | $ | 532,324 | | $ | 449,409 | | $ | 474,001 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (1) The ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings cover | | |
| fixed charges. Earnings consist of net income, to which has been added fixed charges and taxes based on | | | | |
| income of the company before discontinued operations. Fixed charges consist of interest charges and | | | | |
| preferred securities dividend requirements. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Included are cash contributions to capital as follows: 2005 - $30.0 million; 2004 - $15.0 million; 2003 - $20.0 million; | | | | |
| 2002 - $2.5 million; 2001 - $7.0 million. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (3) On May 2, 2005, we redeemed all of our 8% Redeemable Cumulative Preferred Stock. | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| SOUTH JERSEY GAS COMPANY COMPARATIVE OPERATING STATISTICS | |
Comparative statistical data related to revenues and gas throughput is as follows: | | |
| | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| | | | | | | | | | | | | | | | | |
| Operating Revenues (Thousands): | | | | | | | | | | | | | | | | |
| Firm Sales - | | | | | | | | | | | | | | | | |
Residential | | $ | 252,150 | | $ | 182,826 | | $ | 193,725 | | $ | 174,252 | | $ | 201,531 | |
Commercial | | | 88,321 | | | 57,826 | | | 58,749 | | | 52,300 | | | 76,416 | |
Industrial | | | 4,428 | | | 5,223 | | | 5,635 | | | 4,512 | | | 4,250 | |
Cogeneration & Electric Generation | | | 17,916 | | | 9,496 | | | 6,513 | | | 9,363 | | | 7,405 | |
| Firm Transportation - | | | | | | | | | | | | | | | | |
Residential | | | 25,296 | | | 42,375 | | | 40,067 | | | 23,172 | | | 11,280 | |
Commercial | | | 14,043 | | | 22,142 | | | 22,464 | | | 15,958 | | | 8,423 | |
Industrial | | | 12,999 | | | 15,732 | | | 11,500 | | | 10,065 | | | 9,591 | |
Cogeneration & Electric Generation | | | 259 | | | 323 | | | 49 | | | 241 | | | 271 | |
| | | | | | | | | | | | | | | | | |
Total Firm Revenues | | | 415,412 | | | 335,943 | | | 338,702 | | | 289,863 | | | 319,167 | |
| | | | | | | | | | | | | | | | | |
| Interruptible | | | 1,498 | | | 1,641 | | | 1,682 | | | 1,142 | | | 1,485 | |
| Interruptible Transportation | | | 1,898 | | | 1,462 | | | 1,121 | | | 1,567 | | | 1,268 | |
| Off-System | | | 153,637 | | | 151,161 | | | 176,555 | | | 115,714 | | | 145,530 | |
| Capacity Release & Storage | | | 12,808 | | | 10,157 | | | 6,686 | | | 5,365 | | | 5,596 | |
| Appliance Service | | | - | | | 6,362 | | | 9,596 | | | 8,386 | | | 6,136 | |
| Other | | | 1,959 | | | 2,101 | | | 2,100 | | | 1,990 | | | 2,267 | |
| | | | | | | | | | | | | | | | | |
Total Operating Revenues | | $ | 587,212 | | $ | 508,827 | | $ | 536,442 | | $ | 424,027 | | $ | 481,449 | |
| | | | | | | | | | | | | | | | | |
| Throughput (MMcf): | | | | | | | | | | | | | | | | |
| Firm Sales - | | | | | | | | | | | | | | | | |
Residential | | | 18,644 | | | 14,723 | | | 15,843 | | | 15,519 | | | 17,390 | |
Commercial | | | 7,287 | | | 5,198 | | | 5,351 | | | 5,273 | | | 7,544 | |
Industrial | | | 196 | | | 187 | | | 212 | | | 202 | | | 248 | |
Cogeneration & Electric Generation | | | 1,669 | | | 1,095 | | | 777 | | | 1,986 | | | 1,519 | |
| Firm Transportation - | | | | | | | | | | | | | | | | |
Residential | | | 5,512 | | | 9,059 | | | 8,774 | | | 5,174 | | | 2,887 | |
Commercial | | | 5,045 | | | 7,394 | | | 7,639 | | | 5,846 | | | 3,789 | |
Industrial | | | 15,492 | | | 16,441 | | | 15,774 | | | 15,292 | | | 14,795 | |
Cogeneration & Electric Generation | | | 335 | | | 236 | | | 27 | | | 158 | | | 614 | |
| | | | | | | | | | | | | | | | | |
Total Firm Throughput | | | 54,180 | | | 54,333 | | | 54,397 | | | 49,450 | | | 48,786 | |
| | | | | | | | | | | | | | | | | |
| Interruptible | | | 114 | | | 172 | | | 220 | | | 198 | | | 207 | |
| Interruptible Transportation | | | 2,716 | | | 2,463 | | | 2,247 | | | 3,189 | | | 2,638 | |
| Off-System | | | 14,411 | | | 21,294 | | | 27,041 | | | 29,980 | | | 30,117 | |
| Capacity Release & Storage | | | 82,490 | | | 54,585 | | | 41,119 | | | 38,048 | | | 27,187 | |
| | | | | | | | | | | | | | | | | |
Total Throughput | | | 153,911 | | | 132,847 | | | 125,024 | | | 120,865 | | | 108,935 | |
| | | | | | | | | | | | | | | | | |
| Number of Customers at Year End: | | | | | | | | | | | | | | | | |
Residential | | | 300,652 | | | 292,185 | | | 283,722 | | | 275,979 | | | 268,046 | |
Commercial | | | 21,322 | | | 20,939 | | | 20,405 | | | 19,966 | | | 19,542 | |
Industrial | | | 450 | | | 455 | | | 435 | | | 429 | | | 420 | |
| | | | | | | | | | | | | | | | | |
Total Customers | | | 322,424 | | | 313,579 | | | 304,562 | | | 296,374 | | | 288,008 | |
| | | | | | | | | | | | | | | | | |
| Maximum Daily Sendout (MMcf) | | | 424 | | | 428 | | | 422 | | | 344 | | | 326 | |
| | | | | | | | | | | | | | | | | |
| Annual Degree Days | | | 4,777 | | | 4,641 | | | 4,929 | | | 4,380 | | | 4,495 | |
| | | | | | | | | | | | | | | | | |
Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations
Overview
South Jersey Gas Company (SJG) is a regulated natural gas utility. We distributed natural gas in the seven southernmost counties of New Jersey to 322,424 customers at December 31, 2005, compared with 313,579 customers at December 31, 2004. We also:
| | · | sell natural gas and pipeline transportation capacity (off-system sales) on a wholesale basis to various customers on the interstate pipeline system; |
| | · | transport natural gas purchased directly from producers or suppliers for our own sales and for some of our customers; and |
| | · | serviced appliances via the sale of appliance service programs, as well as on a time and materials basis, through September 1, 2004, at which time the business line was transferred into an affiliate by common ownership, South Jersey Energy Service Plus, LLC. |
Our primary goal is to provide safe, reliable natural gas service at the lowest cost possible. Other goals include: 1) promoting natural gas as the fuel of choice for a variety of energy needs, ranging from home heating, to cooking (both residential and commercial), to recreational uses (such as gas fireplaces and grills); and 2) maintaining annual customer growth above the national average of 1.5% for natural gas utilities through a combination of new customer additions and customer conversions from other fuels.
The following is a summary of the primary factors we expect to have the greatest impact on our performance and our ability to achieve our goals going forward:
Business Model - We are the primary focus of our parent, SJI, and will continue to account for the majority of SJI’s net income by maximizing the growth potential of our service territory.
Customer Growth - The vibrancy of the economic development in and adjacent to southern New Jersey, our primary area of operations, and related strong demand for new housing has enabled us to increase our customer base at an average rate of 2.8% over the past five years. Housing growth significantly benefits utility performance.
Regulatory Environment - We are primarily regulated by the New Jersey Board of Public Utilities (BPU). The BPU sets the rates that we charge our rate-regulated customers for services provided and establishes the terms of service under which we operate. We expect the BPU to continue to set rates and establish terms of service that will enable us to obtain a fair and reasonable return on capital invested. The BPU approved a change in base rates in July 2004, (discussed in greater detail in Note 2 to the financial statements) that increased utility margins (revenues less gas costs and associated energy taxes) by approximately $6.3 million in 2005, compared with 2004.
Weather Conditions - Our earnings are largely protected from fluctuations in temperatures by a BPU-approved Temperature Adjustment Clause. This clause has a stabilizing effect on our earnings as we recognize and record earnings based upon an average of temperatures over a 20-year period, and not actual temperatures experienced during a given year. However, our earnings are not protected from changes in the natural gas usage patterns of our customers. Usage patterns can be affected by a number of factors, such as wind, precipitation, temperature extremes and customer conservation.
Changes in Natural Gas Prices - In recent years, prices for natural gas have become increasingly volatile. Gas costs are passed on directly to customers without any profit margin added. The price charged to customers is set annually, with a regulatory mechanism in place to make limited adjustments to that price during the course of a year. In the event that gas cost increases would justify customer price increases greater than those permitted under the regulatory mechanism, we can petition the BPU for an incremental rate increase. High prices can make it more difficult for our customers to pay their bills and may result in elevated levels of bad-debt expense as well as result in higher levels of conservation, which affects revenues.
Changes in Interest Rates - We have operated in a relatively low interest rate environment over the past several years. Rising interest rates would raise the expense associated with existing variable-rate debt and all issuances of new debt. We have sought to mitigate the impact of a potential rising rate environment by fixing the costs on all long-term debt, either by directly issuing fixed-rate debt or by entering into derivative transactions to hedge against rising interest rates.
Labor and Benefit Costs - Labor and benefit costs have a significant impact on our profitability. Benefit costs, especially those related to health care, have risen in recent years. We sought to manage these costs by revising health care plans offered to existing employees, capping postretirement health care benefits, and changing health care and pension packages offered to new hires. Our workforce totaled 505 employees at the end of 2005, with 64% of that total being unionized. During 2004, we agreed to new contracts with all of our bargaining units that encompass the changes mentioned above. The contracts run through at least January 2008, with the largest bargaining units signed through January 2009. We expect savings from these changes to gradually increase as new hires replace retiring employees. In an effort to accelerate the realization of those benefits, we offered an early retirement incentive program at the end of 2004 through 2005.
Balance Sheet Strength - Over the past three years, we took significant steps to enhance the quality of our balance sheet. Through the receipt of capital contributions from our parent and strong earnings performance, our equity-to-capitalization ratio, inclusive of short-term debt, improved from 43% at the end of 2003, to 48% at the end of 2004, and to 49% at the end of 2005. A strong balance sheet permits us the financial flexibility necessary to address volatile economic and commodity markets while maintaining a low-risk financial profile.
Forward-Looking Statement & Risk Factors
Certain statements contained in this Report may qualify as “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included in this Report should be considered forward-looking statements made in good faith and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. Words such as “anticipate”, “believe”, “expect”, “estimate”, “forecast”, “goal”, “intend”, “objective”, “plan”, “project”, “seek”, “strategy” and similar expressions are intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include, but are not limited to, the following: general economic conditions on an international, national, state and local level; weather conditions in our marketing areas; changes in commodity costs; changes in the availability of natural gas; regulatory, legislative and court decisions; competition; the availability and cost of capital; costs and effects of legal proceedings and environmental liabilities; the failure of customers or suppliers to fulfill their contractual obligations; and changes in business strategies.
A discussion of these and other risks and uncertainties may be found throughout this Report and in filings made by us with the Securities and Exchange Commission. These cautionary statements should not be construed by you to be exhaustive and they are made only as of the date of this Report. While we believe these forward-looking statements to be reasonable, there can be no assurance that they will approximate actual experience or that the expectations derived from them will be realized. Further, we undertake no obligation to update or revise any of our forward-looking statements, whether as a result of new information, future events or otherwise.
Critical Accounting Policies
Estimates and Assumptions:
As described in the notes to our financial statements, management must make estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Actual results could differ from those estimates. Five types of transactions presented in our financial statements require a significant amount of judgment and estimation. These relate to regulatory accounting, energy derivatives, environmental remediation costs, pension and other postretirement employee benefit costs, and revenue recognition.
Regulatory Accounting - We maintain our accounts according to the Uniform System of Accounts as prescribed by the New Jersey Board of Public Utilities (BPU). As a result of the ratemaking process, we are required to follow Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” We are required under Statement No. 71 to recognize the impact of regulatory decisions on our financial statements. We are required under our Basic Gas Supply Service clause (BGSS) to forecast our natural gas costs in setting our rates and provide the ability, subject to BPU approval, to recover or refund the difference between gas cost recoveries and the actual costs of gas through a BGSS charge to customers. We record any over/under-recoveries as a regulatory asset or liability on the balance sheets and reflect it in the BGSS in subsequent years. We also enter into derivatives that are used to hedge natural gas purchases, and we record the offset to the resulting derivative assets or liabilities is also recorded as a regulatory asset or liability on the balance sheets.
In addition to the BGSS, other regulatory assets consist primarily of remediation costs associated with manufactured gas plant sites, which are discussed below under Environmental Remediation Costs, and several other assets as detailed in Note 1 to the financial statements. If there are changes in future regulatory positions that indicate the recovery of such regulatory assets is not probable, we would charge the related cost to earnings. Currently, there are no such anticipated changes at the BPU.
Energy Derivatives - We recognize assets or liabilities for the energy-related contracts that qualify as derivatives when contracts are executed. We record contracts at their fair value in accordance with FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We record changes in the fair value of the effective portion of derivatives qualifying as cash flow hedges, net of tax, in Accumulated Other Comprehensive Loss and recognize such changes in the income statement when the hedged item affects earnings. Changes in the fair value of derivatives not designated as hedges are recorded in earnings in the current period. Certain derivatives that result in the physical delivery of the commodity may meet the criteria to be accounted for as normal purchases and normal sales if so designated, in which case the contract is not marked-to-market, but rather is accounted for when the commodity is delivered. However, due to the application of regulatory accounting principles under FASB Statement No. 71, derivatives related to gas purchases are recorded through our BGSS rather than Accumulated Other Comprehensive Loss. We occasionally enter into financial derivatives to hedge against forward price risk. These derivatives are recorded at fair value with an offset to regulatory assets and liabilities, through our BGSS, subject to BPU approval (See Note 2 to the financial statements). We adjust the fair value of the contracts each reporting period for changes in the market. We derive the fair value for most of the energy-related contracts from markets where the contracts are actively traded and quoted. For other contracts, we use published market surveys and, in certain cases, unrelated third parties to obtain quotes concerning the contracts’ current value. Market quotes tend to be more plentiful for contracts maturing in two years or less. Very few of our contracts extend beyond two years.
Environmental Remediation Costs - Outside consulting firms assist us in estimating future costs for environmental remediation activities. We estimate future costs based on projected investigation and work plans using existing technologies. We estimate the range of future costs from $56.7 million to $206.3 million. In preparing financial statements, we record liabilities for future costs using the lower end of the range because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. We update estimates each year to take into account past efforts, changes in work plans, remediation technologies, government regulations and site specific requirements (See Note 12 to the financial statements).
Pension and Other Postretirement Benefit Costs - The costs of providing pension and other postretirement employee benefits are impacted by actual plan experience as well as assumptions of future experience. Employee demographics, plan contributions, investment performance, and assumptions concerning return on plan assets, discount rates and health care cost trends all have a significant impact on determining our projected benefit obligations. We evaluate these assumptions annually with the assistance of our investment manager and actuary; and we adjust them accordingly. These adjustments could result in significant changes to the net periodic benefit costs of providing such benefits and the related liabilities recognized by us.
Revenue Recognition - Gas revenues are recognized in the period the commodity is delivered. We bill customers monthly at rates approved by the BPU. A majority of our customers have their meters read on a cycle basis throughout the month. As a result, recognized revenues include estimates. For customers that are not billed at the end of each month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month. Our unbilled revenue is estimated each month based on natural gas delivered monthly into the system; unaccounted for natural gas based on historical results; customer specific use factors, when available; actual temperatures during the period; and applicable customer rates.
We deferred and recognized revenues related to our appliance service contracts seasonably over the full 12-month term of the contract. This practice ceased upon the transfer of our appliance repair operations to an affiliate on September 1, 2004.
The BPU allows us to recover gas costs in rates through the Basic Gas Supply Service (BGSS) price structure. We defer over/under-recoveries of gas costs and include them in subsequent adjustments to the BGSS rate. These adjustments result in over/under-recoveries of gas costs being included in rates during future periods. As a result of these deferrals, utility revenue recognition does not directly translate to profitability. While we realize profits on gas sales during the month of providing the utility service, significant shifts in revenue recognition may result from the various recovery clauses approved by the BPU. This revenue recognition process does not shift earnings between periods, as these clauses only provide for cost recovery on a dollar-for-dollar basis (See Note 2 to the financial statements).
New Accounting Pronouncements
See detailed discussions concerning New Accounting Pronouncements and their impact in Note 1 to the financial statements.
Temperature Adjustment Clause
The BPU-approved Temperature Adjustment Clause (TAC) is designed to mitigate the effect of variations in heating season temperatures from historical norms. While we record the revenue and earnings impacts of TAC adjustments as incurred, cash inflows or outflows directly attributable to TAC adjustments generally do not begin until the next clause year. Each TAC year begins October 1 and ends May 31 of the subsequent year. The TAC (decreased) increased our net income by $(0.2) million, $0.2 million and $(1.7) million in 2005, 2004 and 2003, respectively. Weather in 2005 was 2.9% colder than in 2004, and 3.0% colder than the 20-year TAC average. Weather in 2004 was 5.8% warmer than in 2003, and 1.0% warmer than the 20-year TAC average. Weather in 2003 was 12.5% colder than 2002, and 5.1% colder than the 20-year TAC average.
Regulatory Actions
See detailed discussions concerning Regulatory Actions in Note 2 to the financial statements.
Environmental Remediation
See detailed discussion concerning Environmental Remediation in Note 12 to the financial statements.
Competition
Our franchises are non-exclusive. Currently, no other utility provides retail gas distribution services within our territory. We do not expect any other utilities to do so in the foreseeable future because of the extensive investment required for utility plant and related costs. We compete with oil, propane and electricity suppliers for residential, commercial and industrial users. The market for natural gas sales is subject to competition due to deregulation. We enhanced our competitive position while maintaining margins by using an unbundled tariff. This tariff allows full cost-of-service recovery, except for the variable cost of the gas commodity, when transporting gas for our customers. Under this tariff, we profit from transporting, rather than selling, the commodity. Our residential, commercial and industrial customers can choose their supplier while we recover the cost of service through transportation service (see Customer Choice Legislation).
Customer Choice Legislation
All residential natural gas customers in New Jersey can choose their gas supplier under the terms of the “Electric Discount and Energy Competition Act of 1999.” As of December 31, 2005, approximately 9,800 of our residential customers chose a natural gas commodity supplier other than us. The number of such customers fell from over 87,600 at December 31, 2004, as marketers were unable to offer natural gas at prices competitive with those available under regulated utility tariffs during 2005, due to changing market conditions. Customers purchasing natural gas from providers other than us are charged for gas costs by the marketer. While customer choice can significantly affect utility revenues and gas costs, it does not affect our earnings or financial condition (See Results of Operations). The BPU continues to allow for full recovery of prudently incurred natural gas costs through the Basic Gas Supply Service Clause as well as other costs of service, including deferred costs, through tariffs.
Results of Operations
Operating Revenues:
Revenues increased $78.4 million compared with prior year primarily due to five factors. First, we added 8,845 customers during 2005, which represents a 2.8% increase in total customers. Second, 89% of the residential customers and 25% of the commercial customers purchasing their gas from sources other than us migrated back to utility sales service. The total number of transportation customers decreased from 89,537 at December 31, 2004, to 11,238 at December 31, 2005, as third party marketers found it difficult to compete with the utility’s Basic Gas Supply Service (BGSS) rates under current market conditions. The migration of customers from transportation service back to sales service has a direct impact on utility revenues as charges for gas costs are included in sales revenues and not in transportation revenues. However, since gas costs are passed on directly to customers without any profit margin added by us, the change in customer utilization of gas marketers did not impact our earnings.
Third, natural gas sales to an electric generation customer increased by $8.1 million in 2005, compared with 2004, as it experienced a high demand for electricity during an unusually hot summer season in 2005. Fourth, we were granted two BGSS rate increases as a result of substantial increases in wholesale natural gas prices across the country. The first increase in September 2005, resulted in a 4.4% increase in the average residential customer’s bill and 5.0% in the average commercial/industrial customer’s bill. The second was effective in December 2005, and resulted in a 24.3% increase in the average residential customer’s bill and 28.4% in the average commercial/industrial customer’s bill. However, as previously stated, since gas costs are passed on directly to customers without any profit margin added by us, the BGSS rate increases did not impact our profitability. Finally, we experienced an increase in revenues from Off-System Sales (OSS) as a direct result of the higher per unit cost of natural gas. This was coupled with an increase in capacity release activity in 2005. Capacity release allows us to sell any unused capacity, but the revenues from such activities are much lower than those from OSS since no commodity is included in the sale.
Partially offsetting the positive factors noted above were lower customer utilization rates experienced during 2005, compared with 2004, the transfer of the appliance service business from the utility, and the impact of the July 2004 rate case settlement on revenues (refer to the Comparative Operating Statistics table in Part 1, Item 6 of this Report). Our revenues for 2005 were reduced by the impact of the July 2004 settlement of several matters before the BPU. This settlement increased our base rates but, at the same time, eliminated rates in several clauses that were no longer needed to recover costs. We were either no longer incurring or had already recovered the specific costs that these clauses were designed to recover. Since revenues raised under these clauses were for cost recovery only and had no profit margin built in, their elimination had no impact on our earnings.
Revenues decreased $27.6 million in 2004, compared with 2003. The decrease was primarily due to lower OSS revenues. OSS revenues decreased $25.3 million as a direct result of lower sales volumes and lower prices for natural gas in this market in 2004, compared with 2003. Additionally, weather was 5.8% warmer than last year resulting in lower utility sales. Offsetting these factors were the addition of 9,017 customers in 2004, and a $5.7 million increase in recoveries for previously deferred costs under the New Jersey Clean Energy Program (See Operations Expense).
Total gas throughput increased 15.9% compared with 2004 to 153.9 billion cubic feet (Bcf) in 2005. The higher throughput was primarily due to a significant increase in capacity release activity during 2005. While revenues from such activities are not as high as when we sell the commodity, contributions to margins are still comparable. Total gas throughput increased 6.3% compared with 2003, to 132.8 Bcf in 2004. The higher throughput in 2004 was also primarily due to a significant increase in capacity release activity.
Cost of Sales:
Cost of sales increased $74.1 million in 2005, compared with 2004, due to the increase in our total customer base, the impact of the migration of customers from transportation service back to sales service and increased Off-System Sales (OSS) volumes and Electric Generation Sales volumes, as discussed in detail under Operating Revenues. While changes in gas costs associated with OSS directly impact cost of sales, changes in the unit cost of gas sold to utility ratepayers do not always directly affect cost of sales. We defer fluctuations in gas costs to ratepayers not reflected in current rates to future periods under a BPU-approved Basic Gas Supply Service (BGSS) price structure. As a result of the two BGSS rate increases in 2005, discussed under Operating Revenues, we were able to recover and recognize some of the increase in gas costs experienced during the year.
Finally, cost of sales experienced a partially offsetting decrease from the transfer of the appliance service business out of the utility effective September 1, 2004. Cost of sales related to the appliance service business are included in our results through September 1, 2004, and totaled $1.8 million in 2004.
Our cost of sales decreased $35.0 million in 2004, compared with 2003, due principally to a significant decrease in sales volumes, primarily in the OSS market. In addition, firm sales volumes in the residential and commercial markets decreased by 6.0% for the year 2004, compared with 2003, primarily as a result of the impact of warmer weather.
Gas supply sources include contract and open-market purchases. We secure and maintain our own gas supplies to serve our sales customers. We do not anticipate any difficulty renewing or replacing expiring contracts under acceptable terms and conditions.
Margin:
The July 2004 base rate increase, discussed in greater detail in Note 2 to the financial statements, had the impact of increasing utility margins (revenues less gas costs and associated energy taxes) by approximately $6.3 million in 2005, compared with 2004. This was offset by a $1.6 million contribution to margin in 2004, due to the buyout of a large utility customer’s long-term contract.
Operating Expenses:
A summary of changes in other operating expenses (in thousands):
| | | 2005 vs. 2004 | | | 2004 vs. 2003 | |
| | | | | | | | |
| Operations | | $ | (1,255 | ) | $ | 3,971 | |
| Maintenance | | | 42 | | | 94 | |
| Depreciation | | | (1,142 | ) | | (615 | ) |
| Energy and Other Taxes | | | 423 | | | (267 | ) |
Operations expense decreased $1.3 million in 2005, which is the net result of a $3.5 million decrease in appliance service expense partially offset by an increase of $2.3 million in utility operations expense. Appliance service expense decreased $3.5 million due to the transfer of this business from the utility in 2004. The $2.3 million offset in expense was due primarily to an increase in bad-debt expense, early retirement incentive plan (ERIP) cost, officers’ long-term incentive compensation, and higher employee wages and salaries. Additional bad-debt expense in the amount of $1.3 million was recognized due to higher write-offs and to an increase in the reserve for potential uncollectible accounts to correspond with the increase in customer accounts receivable caused by rising gas prices. Also, as previously discussed, we offered an ERIP in late 2005. Overall, costs related to the plan were $0.6 million more in 2005, than in 2004. We also incurred additional expense for the officers’ long-term incentive compensation plan, which provides for annual awards based on SJI’s performance as compared to a select peer group. Due to improved corporate performance, we recorded $0.5 million more expense in 2005, than in 2004. Finally, we experienced an increase in wages and salaries from 2004 to 2005, due to contract terms and cost of living increases. The increases in these expenses were partially offset by lower pension expense caused by earnings on additional pension contributions, and lower postretirement benefit costs (not related to the ERIP) due to the cost caps put in place in November 2004 (See Note 11 to the financial statements).
Operations expense increased in 2004, as compared with 2003, primarily as a result of the BPU-approved increase in our Societal Benefits Clause (SBC) in August 2003 (See Note 2 to the financial statements). With this approval, recoveries and a corresponding charge to expense for previously deferred costs under the New Jersey Clean Energy Program (NJCEP) increased by $5.7 million for the year 2004, when compared with 2003. The BPU-approved SBC clause allows for full recovery of these deferred costs including carrying costs and, as a result, the increase in expense had no impact on our net income. Our administrative and general expenses also increased in 2004, compared with 2003, primarily as a result of deferred cost amortizations approved as part of the July 2004 rate case settlement. The resulting amortizations of approximately $0.5 million in 2004, were included in rate recovery from our customers and had no impact on net income. In addition, we incurred significant expense during the year to improve controls to ensure compliance with new SEC and BPU rules and regulations. Lower bad-debt expense during 2004, offset the previously noted increases for the year. A March 2004 BGSS refund improved our accounts receivable aging significantly in 2004. As a result, we benefited from lower uncollectible account write-offs during 2004. In addition, operating expenses related to the appliance service operations decreased $1.9 million as a result of the September 1, 2004 transfer of this function to an affiliated company (See Note 2 to the financial statements).
Depreciation expense decreased during the last two years due to a reduction in the composite depreciation rate from 2.9% to 2.4% effective July 2004, offset by additional depreciation on our continuing investment in utility plant.
Energy and Other Taxes increased in 2005, compared with 2004, primarily due to higher energy-related taxes based on increased sales volumes and revenues in 2005.
Other Income and Expense:
Other income and expense was higher in 2004, compared with both 2005 and 2003, due to a pre-tax gain of $0.7 million on our postretirement healthcare plan trust. The movement of plan assets to a new investment manager triggered the recognition of gains on investments in 2004.
Interest Charges:
Interest charges increased by $0.3 million in 2005, compared with 2004, due primarily to higher levels of short-term debt and higher interest rates on short-term debt. Short-term debt levels rose to support our capital expenditures, which we have not yet financed with long-term debt. A steep rise in short-term interest rates was driven by a series of interest rate hikes enacted by the Federal Reserve Bank over the past 18 months. The increase in interest charges associated with short-term debt was partially offset by lower levels of long-term debt outstanding during 2005, compared with 2004.
Interest charges decreased in 2004, compared with 2003, due primarily to the refunding of higher priced, fixed-rate, long-term debt with lower-cost debt. These refundings occurred primarily during 2003, with smaller portions occurring in 2004, and were accomplished with long-term, fixed-rate debt issuances under our Medium Term Note Program. We also benefited from lower levels of short-term bank debt outstanding as compared with 2003. These benefits were partially offset by higher average short-term interest rates experienced on bank debt during 2004.
Debt is incurred primarily to expand and upgrade our gas transmission and distribution system and to support seasonal working capital needs related to inventories and customer receivables.
Net Income Applicable to Common Stock:
Net income increased $3.1 million, or 9.8%, to $34.5 million in 2005, as compared with $31.5 million in 2004. Net income in 2004 increased $4.9 million, or 18.2% as compared with $26.6 million in 2003. Reasons for the increases in net income in 2005 and 2004 are discussed in detail above.
Liquidity and Capital Resources
Liquidity needs are driven by factors that include natural gas commodity prices; the impact of weather on customer bills; lags in fully collecting gas costs from customers under the Basic Gas Supply Service charge; the timing of construction and remediation expenditures and related permanent financings; mandated tax payment dates; both discretionary and required repayments of long-term debt; and the amounts and timing of dividend payments.
Liquidity needs are first met with net cash provided by operating activities. Net cash provided by operating activities totaled $42.9 million, $74.6 million and $77.5 million in 2005, 2004 and 2003, respectively. Net cash provided by operating activities varies from year-to-year primarily due to the impact of weather on customer demand and related gas purchases, inventory utilization and gas cost recoveries. Net cash provided by operating activities in 2005 was heavily impacted by these factors as collection of much higher fuel costs incurred during 2005 were deferred for collection until 2006. On December 15, 2005, we were authorized by the BPU to increase the rate we charge customers by 24.3% for residential and 28.4% for commercial/industrial. The increase enables us to recover from our customers the higher cost of gas that has been and will be delivered to them during 2005 and 2006. Changes in Accounts Receivable, Inventories and Accounts Payable on the statement of cash flows for 2005 reflected the impact of higher gas prices experienced during the year. We use short-term borrowings under lines of credit from commercial banks to supplement cash from operations, to support working capital needs and to finance capital expenditures as incurred. From time to time, we refinance short-term debt incurred to finance capital expenditures with long-term debt.
Our operations are also subject to seasonal fluctuations. Significant changes in the balances of Current Assets and Current Liabilities can occur from the end of one reporting period to another, as evidenced by the changes on the balance sheets. During the fourth quarter, gas is typically withdrawn from storage to meet heightened winter demand levels. Due to unseasonably warm weather experienced during the fourth quarter of 2005, withdrawals from inventory were lower than normal. Consequently, we anticipate the cash flow benefit received from reducing inventory will be delayed until the first quarter of 2006. We also end each calendar year in a prepaid tax position due to mandatory prepayment requirements on all state taxes. Such prepayments are credited against amounts otherwise due during the first quarter of the subsequent year; further improving first quarter liquidity.
Bank credit available to us totaled $176.0 million at December 31, 2005, of which $87.0 million was used. Those bank facilities consist of a $100.0 million, 3-year revolving credit facility and $76.0 million of uncommitted bank lines. The revolving credit was established in August 2003 with a syndicate of banks to enhance our liquidity position. We are presently working with our banks to extend the revolving credit through 2011. We anticipate the extended agreement to be in place during the first quarter of 2006. The revolving credit facilities contain certain financial covenants measured on a quarterly basis. We were in compliance with these covenants as of December 31, 2005. Based upon the existing credit facilities and a regular dialog with our banks, we believe that there will continue to be sufficient credit available to meet our business’ future liquidity needs.
We supplement our operating cash flow and credit lines with both debt and equity capital. Over the years, we have used long-term debt, primarily in the form of First Mortgage Bonds and Medium Term Notes (MTN), secured by the same pool of utility assets, to finance our long-term borrowing needs. These needs are primarily capital expenditures for property, plant and equipment. In September 2005, we established a new $150.0 million MTN program and issued a $10.0 million note under the program at a rate of 5.45%, maturing in 2035. The proceeds of the 2005 note issue were used to refinance a $10.0 million, 7.9% note issued under a previous MTN program that was called for redemption in July 2005. During 2005, we repaid long-term debt totaling $22.8 million including the July 2005 redemption.
SJI contributed $30.0 million, $15.0 million and $20.0 million of capital to us during 2005, 2004 and 2003, respectively. Contributions of capital are credited to Other Paid-in Capital and Premium on Common Stock.
Our capital structure was as follows:
| | | As of December 31, | |
| | | | 2005 | | | 2004 | |
| | | | | | | | |
| Common and Preferred Stock Equity | | | 49 | % | | 48 | % |
| Long-Term Debt | | | 38 | % | | 44 | % |
| Short-Term Debt | | | 13 | % | | 8 | % |
| | | | | | | | |
| Total | | | 100 | % | | 100 | % |
Our long-term, senior secured debt is rated “A” and “Baa1” by Standard & Poor’s and Moody’s Investor Services, respectively. These ratings have not changed in the past five years.
We are restricted as to the amount of cash dividends or other distributions that may be paid on our common stock by an order issued by the BPU in July 2004, that granted us an increase in base rates. Per the order, we are required to maintain total common equity of no less than $289.0 million. Our total common equity balance was $344.6 million at December 31, 2005.
Capital Expenditures, Commitments and Contingencies
Capital Expenditures:
We have a continuing need for cash resources and capital, primarily to invest in new and replacement facilities and equipment and for environmental remediation costs. Net cash outflows for construction and remediation projects for 2005 amounted to $70.1 million and $4.1 million, respectively. We estimate net cash outflows for construction and remediation projects for 2006, 2007 and 2008, to be approximately $50.7 million, $43.8 million and $44.2 million, respectively. Included in the 2006 estimate is $8.9 million in capital costs accrued but not paid as of December 31, 2005, primarily related to two large special projects totaling $12.1 million for pipeline installation.
Commitments and Contingencies:
We have certain commitments for both pipeline capacity and gas supply for which we pay fees regardless of usage. Those commitments as of December 31, 2005, average $47.4 million annually and total $239.9 million over the contracts’ lives. Approximately 52% of the financial commitment under these contracts expires during the next five years. We expect to renew each of these contracts under renewal provisions as provided in each contract. We recover all prudently incurred fees through rates via the Basic Gas Supply Service clause.
The following table summarizes our contractual cash obligations and their applicable payment due dates as of December 31, 2005 (in thousands):
| | | | | Up to | | Years | | Years | | More than | |
Contractual Cash Obligations | | Total | | 1 Year | | 2 & 3 | | 3 & 5 | | 5 Years | |
| | | | | | | | | | | | | | | | | |
| Long-Term Debt | | $ | 274,508 | | $ | 2,273 | | $ | 2,270 | | $ | 10,000 | | $ | 259,965 | |
| Interest on Long-Term Debt | | | 226,203 | | | 16,426 | | | 32,380 | | | 32,287 | | | 145,110 | |
| Operating Leases | | | 480 | | | 273 | | | 175 | | | 32 | | | - | |
| Construction Obligations | | | 6,966 | | | 6,868 | | | 98 | | | - | | | - | |
| Commodity Supply | | | | | | | | | | | | | | | | |
| Purchase Obligations | | | 239,892 | | | 44,751 | | | 78,556 | | | 46,013 | | | 70,572 | |
| New Jersey Clean Energy Program | | | | | | | | | | | | | | | | |
| Funding (Note 2) | | | 20,600 | | | 5,600 | | | 15,000 | | | - | | | - | |
| Other Purchase Obligations | | | 5,033 | | | 2,183 | | | 1,800 | | | 1,050 | | | - | |
| | | | | | | | | | | | | | | | | |
| Total Contractual Cash Obligations | | $ | 773,682 | | $ | 78,374 | | $ | 130,279 | | $ | 89,382 | | $ | 475,647 | |
Expected environmental remediation costs and asset retirement obligations are not included in the table above due to the subjective nature of these costs and timing of anticipated payments. As a result, the total obligation cannot be calculated. As discussed in Note 11 to the financial statements, we currently do not expect to make a pension contribution in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. Furthermore, future pension contributions beyond 2006 cannot be determined at this time. Our regulatory obligation to contribute approximately $3.6 million annually to our postretirement benefit plans’ trusts, less costs incurred directly by us, is not included as the duration is indefinite.
Off-Balance Sheet Arrangements:
We have no off-balance sheet financing arrangements.
Pending Litigation:
We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to claims when we can determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse effect on our financial position, results of operations or liquidity.
Contract Modifications:
On October 1, 2004, we executed an agreement with a large utility customer for the buy-out of the customer’s long-term energy contract. This settlement contributed approximately $1.6 million to net income in 2004.
In November 2004, our largest bargaining unit voted to ratify a new, 4-year contract. The contract covers the period from the old contract’s expiration on January 15, 2005 through January 14, 2009. Terms of the contract include wage increases ranging from 3% to 3.5% over the contract’s life, health care plan redesign, the establishment of caps on payments for postretirement medical benefits, and the implementation of separate wage and benefit packages for new hires. With this agreement, all unionized personnel, which represent 64% of our workforce at December 31, 2005, are operating under agreements that run through at least January 2008.
Market Risks
Commodity Market Risks:
We are involved in buying, selling, transporting and storing natural gas and are subject to market risk due to price fluctuations. To hedge against this risk, we enter into a variety of physical and financial transactions including forward contracts, futures and options agreements. To manage these transactions, we have a well-defined risk management policy approved by our Board of Directors that includes volumetric and monetary limits. Management reviews reports detailing activity daily. Generally, the derivative activities described above are entered into for risk management purposes.
We transact commodities on a physical basis and typically do not enter into financial derivative positions directly. SJRG, an affiliate by common ownership, manages our risk by entering into the types of transactions noted above. As part of our gas purchasing strategy, we occasionally use financial contracts to hedge against forward price risk. These contracts are recoverable through our BGSS, subject to BPU approval. It is management’s policy, to the extent practical, within predetermined risk management policy guidelines, to have limited unmatched positions on a deal or portfolio basis while conducting these activities. The majority of our contracts are typically less than 12-months long. The fair value and maturity of all these energy trading and hedging contracts determined under the mark-to-market method as of December 31, 2005 is as follows (in thousands):
| Assets | | | | Maturity | | Maturity | | Beyond | | | |
| | | Source of Fair Value | | <1 Year | | 1 - 3 Years | | 3 Years | | Total | |
| | | | | | | | | | | | |
| Prices Actively Quoted | | | NYMEX | | $ | 6,342 | | $ | 271 | | $ | - | | $ | 6,613 | |
| Other External Sources | | | Basis | | | 154 | | | - | | | - | | | 154 | |
| Total | | | | | $ | 6,496 | | $ | 271 | | $ | - | | $ | 6,767 | |
| | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | Maturity | | | Maturity | | | Beyond | | | | |
| | | | Source of Fair Value | | | <1 Year | | | 1 - 3 Years | | | 3 Years | | | Total | |
| | | | | | | | | | | | | | | | | |
| Prices Actively Quoted | | | NYMEX | | $ | 2,914 | | $ | 84 | | $ | - | | $ | 2,998 | |
| Other External Sources | | | Basis | | | 3,283 | | | - | | | - | | | 3,283 | |
| Total | | | | | $ | 6,197 | | $ | 84 | | $ | - | | $ | 6,281 | |
NYMEX (New York Mercantile Exchange) is the primary national commodities exchange on which natural gas is traded. Basis represents the price of a NYMEX natural gas futures contract adjusted for the difference in price for delivering the gas at another location. Contracted volumes of our NYMEX and Basis contracts are 4.3 million decatherms with a weighted average settlement price of $9.70 per decatherm.
A reconciliation of our estimated net fair value of energy-related derivatives, including energy trading and hedging contracts follows (in thousands):
| Net Derivatives — Energy Related Liability, January 1, 2005 | | $ | (527 | ) |
| Contracts Settled During 2005, Net | | | (7,972 | ) |
| Other Changes in Fair Value from Continuing and New Contracts, Net | | | 8,985 | |
| Net Derivatives — Energy Related Asset, December 31, 2005 | | $ | 486 | |
Interest Rate Risk:
Our exposure to interest rate risk relates primarily to short-term, variable-rate borrowings. Short-term, variable-rate debt outstanding at December 31, 2005 was $87.0 million and averaged $43.9 million during 2005. The months where average outstanding variable-rate debt was at its highest and lowest levels were December, at $96.0 million, and May, at $-0-. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $259,000 increase in our annual interest expense, net of tax. The 100 basis point increase was chosen for illustrative purposes, as it provides a simple basis for calculating the impact of interest rate changes under a variety of interest rate scenarios. Over the past five years, the change in basis points (b.p.) of our average monthly interest rates from the beginning to end of each year was as follows: 2005 - 191 b.p. increase; 2004 - 115 b.p. increase; 2003 - 31 b.p. decrease; 2002 - 74 b.p. decrease; and 2001 - 383 b.p. decrease. For December 2005, our average interest rate on variable-rate debt was 4.82%.
We issue long-term debt either at fixed rates or use interest rate derivatives to fix interest rates on variable-rate, long-term debt. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates. In October 2005, in anticipation of issuing long-term, variable-rate, tax-exempt debt during 2006 under the MTN Program, we executed $25.0 million of forward-starting interest rate swaps that will result in an effective fixed rate of 3.43% for 30 years. The debt will be used to provide long-term financing for capital improvements to our gas transmission and distribution system serving Atlantic and Cape May Counties in southern New Jersey.
Ratio of Earnings to Fixed Charges
Our ratio of earnings to fixed charges for each of the periods indicated is as follows:
| Year Ended December 31, |
| 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| 4.0x | | | 3.9x | | | 3.3x | | | 2.9x | | | 2.6x | |
The ratio of earnings to fixed charges represents, on a pre-tax basis, the number of times earnings covers fixed charges. Earnings consist of net income, to which has been added fixed charges and taxes based on income before discontinued operations. Fixed charges consist of interest charges and preferred securities dividend requirements and an interest factor in rentals.
Item 7A. Quantitative and Qualitative Disclosures about Market Risks
Information required by this item is incorporated by reference to the section entitled "Market Risks" beginning on page 28 of this report.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
South Jersey Gas Company
We have audited the accompanying balance sheets of South Jersey Gas Company (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, changes in common equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedules listed in the Index at Item 15(a)2. These financial statements and financial statement schedules are the responsibility of the Company's 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial position of South Jersey Gas Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, 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 financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 1 to the financial statements, the Company changed its method of accounting for asset retirement obligations to conform with the FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” in 2005.
/s/ DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
March 2, 2006
SOUTH JERSEY GAS COMPANY | |
| | | | | | | | | | | |
STATEMENTS OF INCOME | |
| (In Thousands) | |
| | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | |
Operating Revenues | | $ | 587,212 | | $ | 508,827 | | $ | 536,442 | |
| | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | |
| Cost of Sales | | | 414,952 | | | 340,860 | | | 375,815 | |
| Operations | | | 54,983 | | | 56,238 | | | 54,141 | |
| Maintenance | | | 5,814 | | | 5,772 | | | 5,678 | |
| Depreciation | | | 21,906 | | | 23,048 | | | 23,663 | |
| Energy and Other Taxes | | | 11,881 | | | 11,458 | | | 11,725 | |
| | | | | | | | | | | |
| Total Operating Expenses | | | 509,536 | | | 437,376 | | | 471,022 | |
| | | | | | | | | | | |
Operating Income | | | 77,676 | | | 71,451 | | | 65,420 | |
| | | | | | | | | | | |
Other Income and Expense | | | 212 | | | 886 | | | 111 | |
| | | | | | | | | | | |
Interest Charges | | | (18,156 | ) | | (17,906 | ) | | (19,304 | ) |
| | | | | | | | | | | |
Income Before Income Taxes | | | 59,732 | | | 54,431 | | | 46,227 | |
| | | | | | | | | | | |
Income Taxes | | | (25,185 | ) | | (22,969 | ) | | (19,619 | ) |
| | | | | | | | | | | |
Net Income Applicable to Common Stock | | $ | 34,547 | | $ | 31,462 | | $ | 26,608 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | |
| | | | | | | | | | | |
SOUTH JERSEY GAS COMPANY | |
| | | | | | | | | | | |
STATEMENTS OF CASH FLOWS | |
| (In Thousands) | |
| | | | | | | | | | | |
| | | | Year Ended December 31, | |
| | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | |
Cash Flows from Operating Activities: | | | | | | | | | | |
| Net Income | | $ | 34,547 | | $ | 31,462 | | $ | 26,608 | |
| Adjustments to Reconcile Net Income to Net Cash | | | | | | | | | | |
| Provided by Operating Activities: | | | | | | | | | | |
| Depreciation and Amortization | | | 24,717 | | | 25,831 | | | 26,627 | |
| Provision for Losses on Accounts Receivable | | | 2,073 | | | 816 | | | 3,084 | |
| Revenues and Fuel Costs Deferred - Net | | | (34,742 | ) | | 14,582 | | | 29,874 | |
| Deferred and Non-current Income Taxes and Credits - Net | | | 25,662 | | | 13,982 | | | 1,225 | |
| Environmental Remediation Costs - Net | | | (4,069 | ) | | (2,634 | ) | | 2,323 | |
| Additional Pension Contributions | | | (1,390 | ) | | (8,028 | ) | | (5,200 | ) |
| Gas Plant Cost of Removal | | | (985 | ) | | (1,107 | ) | | (925 | ) |
| Changes in: | | | | | | | | | | |
| Accounts Receivable | | | (22,761 | ) | | 7,871 | | | 6,854 | |
| Inventories | | | (23,579 | ) | | (7,713 | ) | | (18,065 | ) |
| Prepayments and Other Current Assets | | | (780 | ) | | (311 | ) | | 1,118 | |
| Prepaid and Accrued Taxes - Net | | | (5,934 | ) | | (11,536 | ) | | 4,888 | |
| Accounts Payable and Other Accrued Liabilities | | | 45,755 | | | 10,111 | | | (376 | ) |
| Other Assets | | | 2,909 | | | 817 | | | 462 | |
| Other Liabilities | | | 1,507 | | | 417 | | | (993 | ) |
| | | | | | | | | | | |
| Net Cash Provided by Operating Activities | | | 42,930 | | | 74,560 | | | 77,504 | |
| | | | | | | | | | | |
Cash Flows from Investing Activities: | | | | | | | | | | |
| Return of Investment in Affiliate | | | - | | | - | | | 1,082 | |
| Capital Expenditures | | | (70,120 | ) | | (66,308 | ) | | (52,284 | ) |
| Purchase of Available-for-Sale Securities | | | - | | | (338 | ) | | (339 | ) |
| Proceeds from Sale of Appliance Service Operations | | | - | | | 2,668 | | | - | |
| | | | | | | | | | | |
| Net Cash Used in Investing Activities | | | (70,120 | ) | | (63,978 | ) | | (51,541 | ) |
| | | | | | | | | | | |
Cash Flows from Financing Activities: | | | | | | | | | | |
| Net Borrowing (Repayments) of Lines of Credit | | | 34,000 | | | (34,200 | ) | | (66,700 | ) |
| Proceeds from Issuance of Long-Term Debt | | | 10,000 | | | 40,000 | | | 110,000 | |
| Principal Repayments of Long-Term Debt | | | (22,773 | ) | | (21,773 | ) | | (86,740 | ) |
| Redemption of Preferred Stock | | | (1,690 | ) | | - | | | - | |
| Dividends on Common Stock | | | (22,502 | ) | | (9,123 | ) | | - | |
| Premium for Early Retirement of Debt | | | (184 | ) | | - | | | (1,048 | ) |
| Payments for Issuance of Long-Term Debt | | | (420 | ) | | (386 | ) | | (1,845 | ) |
| Additional Investment by Shareholder | | | 30,000 | | | 15,000 | | | 20,000 | |
| | | | | | | | | | | |
| Net Cash Provided by (Used in) Financing Activities | | | 26,431 | | | (10,482 | ) | | (26,333 | ) |
| | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (759 | ) | | 100 | | | (370 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 3,310 | | | 3,210 | | | 3,580 | |
| | | | | | | | | | | |
Cash and Cash Equivalents at End of Period | | $ | 2,551 | | $ | 3,310 | | $ | 3,210 | |
| | | | | | | | | | | |
Supplemental Disclosures of Cash Paid During the Period for: | | | | | | | | | | |
| Interest (Net of Amounts Applicable to Gas Cost | | | | | | | | | | |
| Overcollections and Amounts Capitalized) | | $ | 18,899 | | $ | 17,467 | | $ | 19,805 | |
| Income Taxes (Net of Refunds) | | $ | 8,434 | | $ | 14,594 | | $ | 14,060 | |
| | | | | | | | | | | |
Supplemental Disclosures of Noncash Investing Activities: | | | | | | | | | | |
| Capital property and equipment acquired on | | | | | | | | | | |
| account but not paid at year-end | | $ | 8,990 | | $ | 4,531 | | $ | 2,207 | |
| | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | |
| | | | | | | | | | | |
SOUTH JERSEY GAS COMPANY | |
| | | | | | | | |
BALANCE SHEETS | |
| (In Thousands, except share amounts) | |
| | | December 31, | |
| | | | 2005 | | | 2004 | |
| | | | | | | | |
ASSETS | | | | | | | |
| | | | | | | | |
Property, Plant and Equipment: | | | | | | | |
| Utility Plant, at original cost | | $ | 1,030,029 | | $ | 957,287 | |
| Accumulated Depreciation and Amortization | | | (241,242 | ) | | (224,506 | ) |
| | | | | | | | |
| Property, Plant and Equipment - Net | | | 788,787 | | | 732,781 | |
| | | | | | | | |
Investments: | | | | | | | |
| Available-for-Sale Securities | | | 5,628 | | | 5,296 | |
| | | | | | | | |
Current Assets: | | | | | | | |
| Cash and Cash Equivalents | | | 2,551 | | | 3,310 | |
| Accounts Receivable | | | 42,407 | | | 39,916 | |
| Unbilled Revenues | | | 53,648 | | | 34,861 | |
| Provision for Uncollectibles | | | (3,461 | ) | | (2,871 | ) |
| Natural Gas in Storage, average cost | | | 89,957 | | | 65,691 | |
| Materials and Supplies, average cost | | | 3,866 | | | 4,553 | |
| Deferred Income Taxes - Net | | | - | | | 147 | |
| Prepaid Taxes | | | 12,972 | | | 6,104 | |
| Derivatives - Energy Related Assets | | | 6,496 | | | 1,273 | |
| Other Prepayments and Current Assets | | | 2,858 | | | 2,078 | |
| | | | | | | | |
| Total Current Assets | | | 211,294 | | | 155,062 | |
| | | | | | | | |
Regulatory Assets: | | | | | | | |
| Environmental Remediation Costs: | | | | | | | |
| Expended - Net | | | 9,350 | | | 5,281 | |
| Liability for Future Expenditures | | | 56,717 | | | 51,046 | |
| Gross Receipts and Franchise Taxes | | | 480 | | | 924 | |
| Income Taxes - Flowthrough Depreciation | | | 5,663 | | | 6,641 | |
| Asset Retirement Obligation Costs | | | 19,986 | | | - | |
| Deferred Fuel Costs | | | 21,237 | | | - | |
| Deferred Postretirement Benefit Costs | | | 2,646 | | | 3,024 | |
| Societal Benefit Costs | | | 2,691 | | | 4,562 | |
| Premium for Early Retirement of Debt | | | 1,694 | | | 1,672 | |
| Other Regulatory Assets | | | 1,019 | | | 1,157 | |
| | | | | | | | |
| Total Regulatory Assets | | | 121,483 | | | 74,307 | |
| | | | | | | | |
Other Noncurrent Assets: | | | | | | | |
| Unamortized Debt Issuance Costs | | | 6,251 | | | 6,285 | |
Prepaid Pension | | | 26,202 | | | 24,812 | |
| Accounts Receivable - Merchandise | | | 6,472 | | | 7,101 | |
| Derivatives - Energy Related Assets | | | 271 | | | - | |
Other | | | 1,765 | | | 2,089 | |
| | | | | | | | |
Total Other Noncurrent Assets | | | 40,961 | | | 40,287 | |
| | | | | | | | |
| Total Assets | | $ | 1,168,153 | | $ | 1,007,733 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | |
| | | | | | | | |
| | | | | | | | | |
| | | | | | | | |
SOUTH JERSEY GAS COMPANY | |
| | | | | | | | |
BALANCE SHEETS | |
| (In Thousands, except share amounts) | |
| | | December 31, | |
| | | | 2005 | | | 2004 | |
| | | | | | | | |
CAPITALIZATION AND LIABILITIES | | | | | | | |
| | | | | | | | |
Common Equity: | | | | | | | |
| Common Stock, Par Value $2.50 per share: | | | | | | | |
| Authorized - 4,000,000 shares | | | | | | | |
| Outstanding - 2,339,139 shares | | $ | 5,848 | | $ | 5,848 | |
| Other Paid-In Capital and Premium on Common Stock | | | 200,317 | | | 170,317 | |
| Accumulated Other Comprehensive Loss | | | (4,337 | ) | | (4,033 | ) |
| Retained Earnings | | | 142,740 | | | 130,695 | |
| | | | | | | | |
| Total Common Equity | | | 344,568 | | | 302,827 | |
| | | | | | | | |
Preferred Stock: | | | | | | | |
| Redeemable Cumulative Preferred 8% Series - Par Value $100 per share; | | | | | | | |
| Authorized 41,966 shares; 0 and 16,904 shares outstanding at Dec. 31, 2005 | | | | | | | |
| and 2004, respectively | | | - | | | 1,690 | |
| | | | | | | | |
Long-Term Debt | | | 272,235 | | | 282,008 | |
| | | | | | | | |
| Total Capitalization | | | 616,803 | | | 586,525 | |
| | | | | | | | |
Current Liabilities: | | | | | | | |
| Notes Payable | | | 87,000 | | | 53,000 | |
| Current Maturities of Long-Term Debt | | | 2,273 | | | 5,273 | |
| Accounts Payable - Commodity | | | 87,620 | | | 28,619 | |
| Accounts Payable - Other | | | 21,452 | | | 30,407 | |
| Derivatives - Energy Related Liabilities | | | 6,197 | | | 1,800 | |
| Derivatives - Other | | | - | | | 344 | |
| Deferred Income Taxes - Net | | | 2,295 | | | - | |
| Customer Deposits | | | 9,323 | | | 8,846 | |
| Environmental Remediation Costs | | | 17,873 | | | 13,531 | |
| Taxes Accrued | | | 2,162 | | | 1,228 | |
| Interest Accrued and Other Current Liabilities | | | 12,077 | | | 12,386 | |
| | | | | | | | |
| Total Current Liabilities | | | 248,272 | | | 155,434 | |
| | | | | | | | |
Deferred Credits and Other Noncurrent Liabilities: | | | | | | | |
| Deferred Income Taxes - Net | | | 162,542 | | | 138,274 | |
| Environmental Remediation Costs | | | 38,844 | | | 37,515 | |
| Regulatory Liabilities | | | 54,002 | | | 63,836 | |
| Asset Retirement Obligations | | | 22,505 | | | - | |
| Pension and Other Postretirement Benefits | | | 16,633 | | | 17,701 | |
| Investment Tax Credits | | | 2,795 | | | 3,129 | |
| Derivatives - Energy Related Liabilites | | | 84 | | | - | |
| Derivatives - Other | | | 306 | | | - | |
| Other | | | 5,367 | | | 5,319 | |
| | | | | | | | |
| Total Deferred Credits and Other Noncurrent Liabilities | | | 303,078 | | | 265,774 | |
| | | | | | | | |
| Commitments and Contingencies (Note 12) | | | | | | | |
Total Capitalization and Liabilities | | $ | 1,168,153 | | $ | 1,007,733 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | |
| | | | | | | | |
| | | | | | | | | | | | |
SOUTH JERSEY GAS COMPANY | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF CHANGES IN COMMON EQUITY AND COMPREHENSIVE INCOME | |
| (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Other Paid-in | | | | | | Accumulated | | | | | | | |
| | | Capital & | | | | | | Other | | | | | | | |
| | | Common | | | Premium on | | | Comprehensive | | | Retained | | | | |
| | | Stock | | | Common Stock | | | (Loss) Income | | | Earnings | | | Total | |
| | | | | | | | | | | | | | | | | |
Balance at December 31, 2002 | | $ | 5,848 | | $ | 135,317 | | $ | (10,292 | ) | $ | 81,748 | | $ | 212,621 | |
| Net Income Applicable to Common Stock | | | | | | | | | | | | 26,608 | | | 26,608 | |
| Other Comprehensive Income, Net of Tax:* | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | | | | | | | 7,212 | | | | | | 7,212 | |
| Unrealized Gain on Equity Investments | | | | | | | | | 432 | | | | | | 432 | |
| Unrealized Gain on Derivatives | | | | | | | | | 80 | | | | | | 80 | |
| Other Comprehensive Income, Net of Tax:* | | | | | | | | | | | | | | | 7,724 | |
| | | | | | | | | | | | | | | | | |
Comprehensive Income | | | | | | | | | | | | | | | 34,332 | |
| Additional Investment by Shareholder | | | | | | 20,000 | | | | | | | | | 20,000 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | - | | | - | |
| | | | | | | | | | | | | | | | | |
Balance at December 31, 2003 | | | 5,848 | | | 155,317 | | | (2,568 | ) | | 108,356 | | | 266,953 | |
| Net Income Applicable to Common Stock | | | | | | | | | | | | 31,462 | | | 31,462 | |
| Other Comprehensive Loss, Net of Tax:* | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | | | | | | | (1,074 | ) | | | | | (1,074 | ) |
| Unrealized Loss on Equity Investments | | | | | | | | | (192 | ) | | | | | (192 | ) |
| Unrealized Loss on Derivatives | | | | | | | | | (199 | ) | | | | | (199 | ) |
| Other Comprehensive Loss, Net of Tax:* | | | | | | | | | | | | | | | (1,465 | ) |
| | | | | | | | | | | | | | | | | |
Comprehensive Income | | | | | | | | | | | | | | | 29,997 | |
| Additional Investment by Shareholder | | | | | | 15,000 | | | | | | | | | 15,000 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | (9,123 | ) | | (9,123 | ) |
| | | | | | | | | | | | | | | | | |
Balance at December 31, 2004 | | | 5,848 | | | 170,317 | | | (4,033 | ) | | 130,695 | | | 302,827 | |
| Net Income Applicable to Common Stock | | | | | | | | | | | | 34,547 | | | 34,547 | |
| Other Comprehensive Income (Loss), Net of Tax:* | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | | | | | | | 423 | | | | | | 423 | |
| Unrealized Gain on Equity Investments | | | | | | | | | 63 | | | | | | 63 | |
| Unrealized Loss on Derivatives | | | | | | | | | (790 | ) | | | | | (790 | ) |
| Other Comprehensive Loss, Net of Tax:* | | | | | | | | | | | | | | | (304 | ) |
| | | | | | | | | | | | | | | | | |
Comprehensive Income | | | | | | | | | | | | | | | 34,243 | |
| Additional Investment by Shareholder | | | | | | 30,000 | | | | | | | | | 30,000 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | (22,502 | ) | | (22,502 | ) |
| | | | | | | | | | | | | | | | | |
Balance at December 31, 2005 | | $ | 5,848 | | $ | 200,317 | | $ | (4,337 | ) | $ | 142,740 | | $ | 344,568 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Disclosure of Changes in Accumulated Other Comprehensive (Loss) Income Balances* | | | | | | | | | | | | | |
| (In Thousands) | | | | | | | | | | | | | | | | |
| | | | | | | Minimum Pension Liability Adjustment | | | Unrealized (Loss) Gain on Equity Investments | | | Unrealized Gain (Loss) on Derivatives | | | Accumulated Other Comprehensive (Loss) Income | |
| Balance at December 31, 2002 | | | | | $ | (10,059 | ) | $ | (149 | ) | $ | (84 | ) | $ | (10,292 | ) |
| Changes During Year | | | | | | 7,212 | | | 432 | | | 80 | | | 7,724 | |
| Balance at December 31, 2003 | | | | | | (2,847 | ) | | 283 | | | (4 | ) | | (2,568 | ) |
| Changes During Year | | | | | | (1,074 | ) | | (192 | ) | | (199 | ) | | (1,465 | ) |
| Balance at December 31, 2004 | | | | | | (3,921 | ) | | 91 | | | (203 | ) | | (4,033 | ) |
| Changes During Year | | | | | | 423 | | | 63 | | | (790 | ) | | (304 | ) |
| Balance at December 31, 2005 | | | | | $ | (3,498 | ) | $ | 154 | | $ | (993 | ) | $ | (4,337 | ) |
| | | | | | | | | | | | | | | | | |
| *Determined using a combined statutory tax rate of 40.85%. | | | | | | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | |
SOUTH JERSEY GAS COMPANY
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The Entity - South Jersey Industries, Inc. (SJI) owns all of the outstanding common stock of South Jersey Gas Company (SJG). In our opinion, the financial statements reflect all adjustments needed to fairly present our financial position and operating results at the dates and for the periods presented.
Equity Investments - We classify marketable equity investments purchased as long-term investments as Available-for-Sale Securities on our balance sheets and carry them at their fair value. Any unrealized gains or losses are included in Accumulated Other Comprehensive Loss.
Estimates and Assumptions - We prepare our financial statements to conform with accounting principles generally accepted in the United States of America. Management makes estimates and assumptions that affect the amounts reported in the financial statements and related disclosures. Therefore, actual results could differ from those estimates. Significant estimates include amounts related to regulatory accounting, energy derivatives, environmental remediation costs, pension and other postretirement benefit costs, and revenue recognition.
Regulation - We are subject to the rules and regulations of the New Jersey Board of Public Utilities (BPU). We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts (See Note 2). SJG follows the accounting for regulated enterprises prescribed by the Financial Accounting Standards Board (FASB) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” In general, Statement No. 71 allows deferral of certain costs and creation of certain obligations when it is probable that such items will be recovered from or refunded to customers in future periods.
Operating Revenues - Gas revenues are recognized in the period the commodity is delivered and customers are billed monthly. For retail customers not billed at the end of each month, we record an estimate to recognize unbilled revenues for gas delivered from the date of the last meter reading to the end of the month. We deferred and recognized revenues related to our appliance service contracts seasonally over the full 12-month term of the contract prior to transferring that business to South Jersey Energy Service Plus, an affiliate by common ownership.
The BPU allows us to recover all prudently incurred gas costs through the Basic Gas Supply Service (BGSS) clause. We collect these costs on a forecasted basis upon BPU order. SJG defers over/under-recoveries of gas costs and includes them in the following year's BGSS. We pay interest on the net overcollected BGSS balances at the rate of return on rate base utilized by the BPU to set rates in our last base rate proceeding (See Note 2).
Our tariff also includes a Temperature Adjustment Clause (TAC), a Remediation Adjustment Clause (RAC), a New Jersey Clean Energy Program (NJCEP) and a Universal Service Fund (USF) program. Our TAC provides stability to SJG’s earnings and our customers’ bills by normalizing the impact of extreme winter temperatures. The RAC recovers environmental remediation costs of former gas manufacturing plants and the NJCEP recovers costs associated with our energy efficiency and renewable energy programs. The USF is a statewide customer assistance program that utilizes utilities as a collection agent. TAC adjustments affect revenue, earnings and cash flows since colder-than-normal weather can generate credits to customers, while warmer-than-normal weather can result in additional billings. RAC adjustments do not directly affect earnings because we defer and recover related costs through rates over 7-year amortization periods (See Notes 2 & 12). NJCEP and USF adjustments are also deferred and do not affect earnings, as related costs and customer credits are recovered through rates on an ongoing basis (See Note 2).
Accounts Receivable and Provision for Uncollectible Accounts - Accounts receivable are carried at the amount owed by customers. A provision for uncollectible accounts was established based on our collection experience and an assessment of the collectibility of specific accounts.
Property, Plant & Equipment - For regulatory purposes, utility plant is stated at original cost, which may be different than our cost if the assets were acquired from another regulated entity. The cost of adding, replacing and renewing property is charged to the appropriate plant account. Utility Plant balances as of December 31, 2005 and 2004 were comprised of the following (in thousands):
| | | 2005 | | 2004 | |
| Utility Plant: | | | | | | | |
| Production Plant | | $ | 302 | | $ | 302 | |
| Storage Plant | | | 11,755 | | | 11,049 | |
| Transmission Plant | | | 134,234 | | | 113,691 | |
| Distribution Plant | | | 831,732 | | | 784,267 | |
| General Plant | | | 34,563 | | | 33,775 | |
Intangible Plant | | | 3,394 | | | 1,855 | |
| Utility Plant in Service | | | 1,015,980 | | | 944,939 | |
| Construction Work in Progress | | | 14,049 | | | 12,348 | |
| | | | | | | | |
| Total Utility Plant | | $ | 1,030,029 | | $ | 957,287 | |
Depreciation and Amortization - We depreciate utility plant on a straight-line basis over the estimated remaining lives of the various property classes. These estimates are periodically reviewed and adjusted as required after BPU approval. The composite annual rate for all depreciable utility property was approximately 2.4% in 2005. Under our 2004 rate case settlement, our composite depreciation rate was reduced from 2.9% to 2.4% effective July 8, 2004 (See Note 2). Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage (See Asset Retirement Costs).
Capitalized Interest - SJG capitalizes interest on construction at the rate of return on rate base utilized by the BPU to set rates in the last base rate proceeding (See Note 2). Capitalized interest is included in Utility Plant on the balance sheets. Interest Charges are presented net of capitalized interest. SJG capitalized interest of $1.2 million, $0.7 million and $0.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Impairment of Long-Lived Assets - We review the carrying amount of long-lived assets for possible impairment whenever events or changes in circumstances indicate that such amounts may not be recoverable. For the years ended 2005, 2004 and 2003, no significant impairments were identified.
Derivative Instruments - We account for derivative instruments in accordance with FASB Statement No. 133, as amended “Accounting for Derivative Instruments and Hedging Activities,” as amended. We record all derivatives, whether designated as hedging relationships or not, on the balance sheets at fair value unless the derivative contracts qualify for the normal purchase and sale exemption. In general, if the derivative is designated as a fair value hedge, we recognize the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk in earnings. We currently have no fair value hedges. If the derivative is designated as a cash flow hedge, we record the effective portion of the hedge in Accumulated Other Comprehensive Loss and recognize it in the income statement when the hedged item affects earnings. However, due to the application of regulatory accounting principles under FASB Statement No. 71, derivatives related to gas purchases are recorded through our BGSS rather than Accumulated Other Comprehensive Loss. We recognize ineffective portions of changes in the fair value of cash flow hedges immediately in earnings.
As part of our gas purchasing strategy, we occasionally use financial contracts to hedge against forward price risk. The costs or benefits of these short-term contracts are recoverable through our BGSS, subject to BPU approval. As of December 31, 2005 and 2004, we had $(0.5) million and $0.5 million of (benefits) costs, respectively, included in our BGSS related to open financial contracts (See Regulatory Assets & Regulatory Liabilities).
The vast majority of our contracts relate to physical transactions that qualify for the normal purchase and sale exception. Therefore, we are not required to mark these contracts to market.
From time to time we enter into interest rate derivatives and similar agreements to hedge exposure to increasing interest rates with respect to our variable-rate debt. We have designated and account for these interest rate derivatives as cash flow hedges. We used derivative transactions known as “Treasury Locks” to hedge against the impact of possible interest rate increases on a planned $10.0 million, 30-year debt issuance. The first Treasury Lock was entered into in November 2004, and was terminated in July 2005. A second Treasury Lock was entered into in August 2005, and was terminated in September 2005, in coordination with the debt issuance. The $1.4 million cost of both Treasury Locks has been included in Accumulated Other Comprehensive Loss and is being amortized over the 30-year life of the new debt issue.
On October 21, 2005, we entered into two forward-starting interest rate swaps which effectively fixed the interest rate at 3.43% for 30 years on $25 million of variable-rate, tax-exempt debt which is expected to be issued in 2006. The differential to be paid or received as a result of these swap agreements is accrued as interest rates change and is recognized as an adjustment to interest expense. Interest rate swaps are accounted for as a cash flow hedge.
As of December 31, 2005 and 2004, the market value of these agreements was $0.3 million in each year, which represents the amount we would have to pay the counterparty to terminate these contracts as of those dates. We included these balances on the balance sheets under the caption Derivatives - Other. As of December 31, 2005 and 2004, we calculated the swaps to be highly effective; therefore, we recorded the change in fair value of the swaps along with the cumulative unamortized costs net of taxes, in Accumulated Other Comprehensive Loss.
We determine the fair value of interest rate swap agreements using quotations from unrelated third parties.
Asset Retirement Obligations - On January 1, 2003, we adopted FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of an asset retirement obligation (ARO) be recognized in the period in which it is incurred. It applies to legal obligations associated with the retirement of long-lived assets resulting from the acquisition, construction, development and/or the normal operation of a long-lived asset. We identified certain easements and right-of-way agreements that qualify as legal obligations under this Statement. However, it is our intent to maintain these agreements in perpetuity; therefore, the value of any liability associated with these agreements would not be material.
In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligation as used in Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the company’s control. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or settlement method. Thus, an entity is required to recognize a liability if it can be reasonably estimated.
We have identified several AROs within the expanded scope of FIN 47. Such AROs include asbestos removal, underground tank removal, mercury regulator removal, and a legal obligation for certain safety requirements upon the retirement of our gas distribution and transmission system. At December 31, 2005, the present value of our future ARO was approximately $22.5 million, of which $22.0 million is related to the safety requirements of the gas distribution and transmission system.
Upon adoption of FIN 47 on December 31, 2005, we recorded this obligation of $22.5 million on the balance sheet under Asset Retirement Obligations, which includes $16.9 million of accumulated accretion as of December 31, 2005. The present value of the initial ARO that is included in Utility Plant is $5.6 million. The accumulated depreciation on this asset totaled $3.1 million as of December 31, 2005. We believe that the recording of ARO-related accumulated accretion and depreciation amounts represent timing differences in the recognition of legal retirement costs that we are currently recovering in rates and, as such, we are deferring such differences as Regulatory Assets under FASB Statement No. 71 in the amount of $20.0 million at December 31, 2005.
Additionally, had FIN 47 been applied to earlier periods presented within this report, the ARO as of December 31, 2004 and 2003, would have been $19.2 million and $17.9 million, respectively. In accordance with FIN 47, such amounts are not required to be recorded on the balance sheets.
Asset Retirement Costs - We recover certain asset retirement costs through rates charged to customers. As of December 31, 2005 and 2004, we had accrued amounts in excess of actual removal costs incurred totaling $48.1 million and $47.3 million, respectively, which we recorded as Regulatory Liabilities on the balance sheets, in accordance with Statement No. 143.
New Accounting Pronouncements - In December 2004, the FASB issued Statement No. 123(R), “Share-Based Payment”, which revises FASB Statement No. 123, and supersedes Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees”. Since officers of South Jersey Gas participate in the Stock Option, Stock Appreciation Rights and Restricted Stock Award Plan of SJI, changes in accounting for share-based payments also impact us. Statement No. 123(R) will require us to measure and recognize stock-based compensation expense in our financial statements based on the fair value at the date of grant for share-based awards, which currently include performance shares containing market and service conditions. Statement No. 123(R) is effective for interim and annual financial statements beginning after January 1, 2006. In accordance with Statement No. 123(R), we are required to recognize compensation expense over the requisite service period for: (i) awards granted on, or after, January 1, 2006 and (ii) unvested awards previously granted and outstanding as of January 1, 2006. In addition, we can estimate forfeitures over the requisite service period when recognizing compensation expense. These estimates can be adjusted to the extent to which actual forfeitures differ, or are expected to materially differ, from such estimates.
As permitted by Statement No. 123(R), upon adoption, we may choose between two transition methods: the modified prospective or modified retrospective method. Under the modified prospective application, this Statement applies to new awards and to awards modified, repurchased, or cancelled after the required effective date. Compensation costs for the portion of awards for which the requisite service has not been rendered that are outstanding as of the required effective date shall be recognized as the requisite service is rendered based on the grant-date fair value. The modified retrospective application may be applied either (a) to all prior years for which Statement 123 was effective or (b) only to prior interim periods in the year of initial adoption if the required effective date of this Statement does not coincide with the beginning of the entity's fiscal year. Adjustments would be made to financial statements for prior periods to give effect to the fair-value-based method of accounting for awards granted, modified, or settled in cash in fiscal years beginning after December 15, 1994, on a basis consistent with the pro forma disclosures required for those periods by Statement No. 123.
SJI and SJG adopted Statement No. 123(R), as amended, on January 1, 2006 using the modified prospective method. The impact of the adoption of Statement No. 123(R) is not expected to materially impact our financial statements. In addition, since we are required to settle our obligation to officers by purchasing shares of SJI common stock in exchange for cash, we will continue to reflect our obligations under this compensation plan as liabilities on the balance sheets.
In November 2004, the FASB issued Statement No. 151, “Inventory Costs.” This statement 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. The effective date of this statement is January 1, 2006; however, we do not expect it to materially impact our financial statements.
In December 2004, the FASB issued Statement No. 153, “Exchanges of Nonmonetary Assets,” an amendment to APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” This statement redefines the types of nonmonetary exchanges that require fair value measurement. Statement No. 153 is effective for nonmonetary transactions entered into on and after July 1, 2005. The adoption of this statement had no effect on our financial statements.
Income Taxes - Deferred income taxes are provided for all significant temporary differences between book and taxable basis of assets and liabilities in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (See Notes 5 & 6). A valuation allowance will be established when it is determined that it is more likely than not that a deferred tax asset will not be realized.
Regulatory Assets & Regulatory Liabilities - All significant regulatory assets are separately identified on the balance sheets. Each item that is separately identified is being recovered through utility rate charges. We are currently permitted to recover interest on our Environmental Remediation Costs and Societal Benefit Costs while the other assets are being recovered without a return on investment over the following periods (See Note 2):
| | | Years Remaining | |
| Regulatory Asset | | As of December 31, 2005 | |
| | | | |
| Environmental Remediation Costs: (Notes 2 & 12) | | | | |
| Expended - Net | | | Various | |
| Liability for Future Expenditures | | | Not Applicable | |
| Gross Receipts and Franchise Taxes (Note 6) | | | 1 | |
| Income Taxes - Flowthrough Depreciation (Note 6) | | | 6 | |
| Deferred Fuel Costs - Net (Note 2) | | | Various | |
| Deferred Postretirement Benefit Costs (Note 11) | | | 7 | |
| Premium for Early Retirement of Debt | | | Various | |
| Societal Benefit Costs (Note 2) | | | Various | |
Some of the assets reflected under the caption Other Regulatory Assets are currently being recovered from ratepayers as approved by the BPU (See Note 2). Management believes the remaining deferred costs are probable of recovery from ratepayers through future utility rates.
Over/under collections of gas costs are monitored through our BGSS mechanism. Net undercollected gas costs are classified as a Regulatory Asset and net overcollected gas costs are classified as a Regulatory Liability. Derivative contracts used to hedge our natural gas purchases are recoverable through the BGSS, subject to BPU approval. The offset to the change in fair value of these contracts is recorded as a component of the regulatory asset, Deferred Fuel Costs - Net if we are in a net undercollected position, or as a component of the regulatory liability, Deferred Gas Revenues - Net if we are in a net overcollected position. As of December 31, 2005, benefits related to derivative contracts reduced Deferred Fuel Costs - Net by $0.5 million. As of December 31, 2004, costs related to derivative contracts offset Deferred Gas Revenues - Net by $0.5 million.
Regulatory Liabilities at December 31, 2005 and 2004 consisted of the following items (in thousands):
| | | 2005 | | 2004 | |
| | | | | | |
| Deferred Gas Revenues - Net (Note 2) | | $ | - | | $ | 12,334 | |
| Excess Plant Removal Costs | | | 48,071 | | | 47,345 | |
| Overcollected State Taxes | | | 4,025 | | | 3,871 | |
| Other | | | 1,906 | | | 286 | |
| | | | | | | | |
| Total Regulatory Liabilities | | $ | 54,002 | | $ | 63,836 | |
Deferred Gas Revenues - Net represents our net overcollected gas costs as previously discussed. Excess Plant Removal Costs represent amounts accrued in excess of actual utility plant removal costs incurred to date, which we have an obligation to either expend or return to ratepayers in future periods (See Asset Retirement Costs). All other regulatory liabilities are subject to being returned to ratepayers in future rate proceedings.
Cash and Cash Equivalents - For purposes of reporting cash flows, highly liquid investments with original maturities of three months or less are considered cash equivalents.
Reclassifications - We reclassified some previously reported amounts to conform with current year classifications. We determined that certain acquisitions of property and equipment made on account were reflected as cash capital expenditures in the statements of cash flows, and have reduced cash flows used in investing activities with a corresponding reduction in cash provided by operating activities of approximately $2.3 million and $0.9 million for the years ended December 31, 2004 and 2003, respectively. In 2005 we were required to record an additional minimum liability for our supplemental executive retirement plan (SERP) with offsetting amounts, net of tax, included in Common Equity within Accumulated Other Comprehensive Loss on the balance sheets. We recorded a similar additional minimum liability identified in 2005, related to 2004, in the amount of $6.9 million, with offsetting amounts of $0.3 million, $2.7 million and $3.9 million recorded in Other Noncurrent Assets, Deferred Income Taxes - Net and Common Equity within Accumulated Other Comprehensive Loss, respectively, on the balance sheets. These amounts are considered immaterial to the overall presentation of our financial statements.
2. REGULATORY ACTIONS:
Base Rates - In January 1997, the BPU granted us rate relief, which was predicated in part upon a 9.62% rate of return on rate base that included an 11.25% return on common equity. This rate relief provided for the recovery of cost of service, including deferred costs, through base rates.
On July 7, 2004, the BPU granted us a base rate increase of $20.0 million, which was predicated in part upon a 7.97% rate of return on rate base that included a 10.0% return on common equity. The increase was effective July 8, 2004 and designed to provide an incremental $8.5 million on an annualized basis to net income. We were also permitted recovery of regulatory assets contained in our petition and a reduction in our composite depreciation rate from 2.9% to 2.4%.
As part of the overall settlement effective July 8, 2004, we provided customers with an offsetting $38.9 million revenue reduction. This reduction was provided to customers through the reduction and elimination of rates associated with our various clauses. Under those clauses, costs incurred by us were billed to customers on a dollar-for-dollar basis and the reductions did not negatively impact our net income.
Pending Audits - In 2004, the BPU commenced a competitive services audit and a management audit that included a focused review of our gas supply and purchasing practices. The BPU is mandated by statute to conduct such audits at predetermined intervals. In February 2006, the audit reports were released by the BPU for comments. The recommendations contained in these audits have no apparent material effect on our financial statements.
Appliance Service Business - On July 23, 2004, the BPU approved our petition and related agreements to transfer our appliance service business. In anticipation of this transfer, SJI had formed South Jersey Energy Service Plus, LLC (SJESP), to perform appliance repair services after BPU approval of the transfer. SJESP purchased certain assets and assumed certain liabilities required to perform such repair services from us for the net book value of $1.2 million on September 1, 2004. The agreements also called for SJESP to pay us an additional $1.5 million. This $1.5 million was credited by us to customers through the RAC and had no earnings impact. The transfer has no effect on the provision of safety-related or emergency-related services to the public since the transferred services include only non-safety related, competitive appliance services.
Other Regulatory Matters - Effective January 10, 2000, the BPU approved full unbundling of our system. This allows all natural gas consumers to select their natural gas commodity supplier. As of December 31, 2005, approximately 9,800 of our residential customers were purchasing their gas commodity from someone other than us. Customers choosing to purchase natural gas from providers other than the utility are charged for the cost of gas by the marketer. The resulting decrease in our revenues is offset by a corresponding decrease in gas costs. While customer choice can reduce utility revenues, it does not negatively affect our net income or financial condition. The BPU continues to allow for full recovery of prudently incurred natural gas costs through the BGSS. Unbundling did not change the fact that we still recover cost of service, including certain deferred costs, through base rates.
In March 2003, the BPU approved a statewide Universal Service Fund (USF) program through which funds for the USF and Lifeline Credit and Tenants Assistance Programs would be collected from customers of all New Jersey electric and gas utilities. In June 2004, the BPU approved the statewide budget of $113.0 million for all the state’s electric and gas utilities and the increased rates were implemented effective July 1, 2004, resulting in a $3.9 million increase to our annual USF recoveries. In April 2005, we made our annual USF filing, along with the state’s other electric and gas utilities, proposing no rate change to the statewide program. This rate proposal was approved by the BPU in June 2005.
In February 2004, we filed notice with the BPU to reduce our gas cost revenues by approximately $5.0 million, via a rate reduction, in addition to providing for a $21.8 million bill credit to customers. Both the rate reduction and bill credit were approved and implemented in March 2004.
In June 2004, we made our annual BGSS filing with the BPU requesting a $4.9 million increase in gas cost recoveries. In October 2004, the requested increase was approved on a provisional basis.
In September 2004, we filed for a $2.6 million reduction to our annual Societal Benefits Clause (SBC) recovery level. The SBC recovers costs related to BPU-mandated programs, including environmental remediation costs that are recovered through the RAC; energy efficiency and renewable energy program costs that are recovered through the NJCEP; consumer education program costs; and low income program costs that are recovered through the USF.
In December 2004, the BPU approved the statewide funding of the NJCEP of $745.0 million for the years 2005 through 2008. Of this amount, we will be responsible for approximately $25.4 million over the 4-year period. Amounts not yet expended have been included in our Contractual Cash Obligations table included in Note 12.
In February 2005, we filed notice with the BPU to provide for an $11.4 million bill credit to customers. The bill credit was implemented in March 2005. In June 2005, we made our annual BGSS filing with the BPU requesting a $17.1 million, or 6.3% increase in gas cost recoveries in response to increasing wholesale gas costs. In August 2005, the BPU approved our requested increase, effective September 1, 2005.
In October 2005, we, along with the three other natural gas distribution companies in New Jersey, filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). The purpose of the Tracker is to recover costs to be incurred by us as a result of new federal regulations, which are aimed at enhancing public safety and reliability. The regulations require that utilities use a comprehensive analysis to assess, evaluate, repair and validate the integrity of certain transmission lines in the event of a leak or failure. The New Jersey utilities are requesting approval of the Tracker since the new regulations will result in ongoing incremental costs. We anticipate that a large portion of the incremental cost is dependent upon overall assessment results, and therefore cannot be specifically predicted at this time.
In November 2005, we made our annual SBC filing, requesting a $6.1 million reduction in annual recoveries.
Also, in November 2005, we filed a BGSS Motion for Emergent Rate Relief in conjunction with the other natural gas utilities in New Jersey. This filing was necessary due to substantial increases in wholesale natural gas prices across the country. We requested a $103.2 million increase. In December 2005, the BPU approved an $85.7 million increase to our rates, effective December 15, 2005.
In November 2005, we made our annual TAC filing, requesting a $1.0 million increase in annual revenues. The increase will recover the cash related to the net TAC deficiency resulting from warmer-than-normal weather for the 2003-2004 winter, partially offset by colder-than-normal weather for the 2004-2005 winter.
In December 2005, we made a filing to implement a Conservation and Usage Adjustment (CUA) Clause, on a 5-year pilot basis. The primary purpose of the CUA is to base our profit margin on the number of customers rather than the amount of natural gas distributed to customers. This structure will allow us to aggressively promote conservation programs without negatively impacting our financial stability. The proposed CUA would replace our existing TAC.
Filings and petitions described above are still pending unless otherwise indicated.
3. RELATED PARTY TRANSACTIONS:
We conducted business with our parent, SJI, and several of SJI’s other wholly owned subsidiaries. A description of each of these affiliates is as follows:
| | · | South Jersey Energy Company (SJE) - a third party energy marketer supplying natural gas to customers within our territory. |
| | · | South Jersey Resources Group (SJRG) - a wholesale gas and risk management business that supplies natural gas to retail marketers, utility businesses and electricity generators in the mid-Atlantic and southern regions. |
| | · | Marina Energy LLC (Marina) - an owner and operator of energy production facilities for the commercial and industrial markets. |
| | · | South Jersey Energy Service Plus (SJESP) - an appliance service and installation company. |
We sold natural gas for resale to both SJE and SJRG. These sales comply with Section 284.02 of the Regulations of the Federal Energy Regulatory Commission (FERC). Additionally, we met some of our gas purchasing requirements by purchasing natural gas for resale from SJRG. For SJE and SJESP, we also provided billing services. For SJE’s residential customers, for which we performed billing services, we purchased the related accounts receivable at book value plus a factor for potential uncollectible accounts and assumed all risk associated with the collection of such amounts. Finally, we provided natural gas transportation services to Marina under BPU-approved utility tariffs.
In addition to the above, we provided various administrative and professional services for SJI, SJE, SJRG, SJESP and Marina. These services included administrative support, information system and data management support, and office space rental. Likewise, SJI provided substantial administrative services on our behalf including such items as public and governmental relations, cash management and consulting services.
A summary of these related party transactions were as follows at December 31 (in thousands):
| | | 2005 | | 2004 | | 2003 | |
| | | | | | | | |
Sales and Services Provided to: | | | | | | | | | | |
| SJI | | $ | 1,234 | | $ | 820 | | $ | 867 | |
| SJE | | | 635 | | | 8,427 | | | 26,129 | |
| SJRG | | | 10,680 | | | 6,173 | | | 12,853 | |
| Marina | | | 266 | | | 222 | | | 102 | |
| SJESP | | | 893 | | | 282 | | | - | |
| | | | | | | | | | | |
Sales and Services Received from: | | | | | | | | | | |
| SJRG | | $ | 13,140 | | $ | 22,120 | | $ | 20,694 | |
| SJI | | | 5,811 | | | 4,222 | | | 3,602 | |
| | | | | | | | | | | |
Amounts due to related parties are included in Accounts Payable and amounts due from related parties are included in Accounts Receivable on the
balance sheets. As of December 31, these related party balances are as follows (in thousands):
| | | 2005 | | 2004 | |
| | | | | | |
Amounts due to: | | | | | | | |
| SJI | | $ | 699 | | $ | 741 | |
| SJE | | | 1,270 | | | 622 | |
| SJESP | | | 993 | | | 1,808 | |
| SJRG | | | 2,293 | | | - | |
| | | | | | | | |
Amounts due from: | | | | | | | |
| SJI | | $ | 507 | | $ | 49 | |
| SJE | | | 32 | | | 79 | |
| SJRG | | | - | | | 641 | |
| Marina | | | 25 | | | 24 | |
| SJESP | | | 69 | | | 83 | |
For certain types of transactions, we served as central processing agents for the related parties discussed above. Amounts due to and due from these related parties for pass-through items are not considered material to the financial statements as a whole and are not included in the amounts disclosed above.
Lastly we purchased meter reading services from Millennium Account Services, LLC (Millennium), a partnership between SJI and Conectiv Solutions, LLC. Millennium reads our utility customers’ meters on a monthly basis for a fee. Fees incurred by us related to such services and the amounts due, which are included in Accounts Payable on the balance sheets, are as follows at December 31 (in thousands):
| | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | |
| Meter Reading Service Fees | | $ | 2,626 | | $ | 2,600 | | $ | 2,438 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | 2005 | | | 2004 | | | | |
| | | | | | | | | | | |
| Amounts due to Millennium | | $ | 220 | | $ | 440 | | | | |
4. PREFERRED STOCK:
On May 2, 2005, we redeemed all of our Redeemable Cumulative Preferred 8% Series of preferred stock at its par value of $1.7 million.
5. INCOME TAXES:
SJG is included in the consolidated Federal income tax return filed by SJI. The actual taxes, including credits, are allocated by SJI to its subsidiaries, generally on a separate return basis. Total income taxes applicable to operations differ from the tax that would have resulted by applying the statutory Federal Income Tax rate to pre-tax income for the following reasons (in thousands):
| | | 2005 | | | 2004 | | | 2003 | |
| Tax at Statutory Rate | | $ | 20,906 | | $ | 19,051 | | $ | 16,319 | |
| Increase (Decrease) Resulting from: | | | | | | | | | | |
| State Income Taxes | | | 4,035 | | | 3,738 | | | 3,137 | |
| Amortization of Investment | | | | | | | | | | |
| Tax Credits (Note 6) | | | (334 | ) | | (342 | ) | | (347 | ) |
| Amortization of Flowthrough | | | | | | | | | | |
Depreciation (Note 6) | | | 664 | | | 664 | | | 664 | |
Other - Net | | | (86 | ) | | (142 | ) | | (154 | ) |
Net Income Taxes | | $ | 25,185 | | $ | 22,969 | | $ | 19,619 | |
| | | | | | | | | | | |
| The provision for Income Taxes is comprised of the following (in thousands): | | | |
| | | | 2005 | | | 2004 | | | 2003 | |
| Current: | | | | | | | | | | |
| Federal | | $ | (1,819 | ) | $ | 4,078 | | $ | 12,143 | |
State | | | 1,342 | | | 4,632 | | | 6,251 | |
Total Current | | | (477 | ) | | 8,710 | | | 18,394 | |
| Deferred: | | | | | | | | | | |
| Federal: | | | | | | | | | | |
| Excess of Tax Depreciation Over | | | | | | | | | | |
| Book Depreciation - Net | | | 4,832 | | | 14,323 | | | 10,396 | |
| Deferred Fuel Costs - Net | | | 17,567 | | | (3,229 | ) | | (9,506 | ) |
| Environmental Costs - Net | | | 970 | | | 752 | | | (167 | ) |
| Alternative Minimum Tax | | | - | | | - | | | 1,332 | |
| Prepaid Pension | | | 346 | | | 2,289 | | | 1,361 | |
| Deferred Regulatory Costs | | | (1,156 | ) | | (804 | ) | | 683 | |
| Other - Net | | | (1,429 | ) | | 151 | | | (1,102 | ) |
State | | | 4,866 | | | 1,119 | | | (1,425 | ) |
Total Deferred | | | 25,996 | | | 14,601 | | | 1,572 | |
| Investment Tax Credits | | | (334 | ) | | (342 | ) | | (347 | ) |
Net Income Taxes | | $ | 25,185 | | $ | 22,969 | | $ | 19,619 | |
The net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and income tax purposes resulted in the following net deferred tax liabilities (assets) at December 31(in thousands):
| | | 2005 | | 2004 | |
| Current: | | | | | | | |
| Deferred Fuel Costs - Net | | $ | 4,098 | | $ | - | |
| Uncollectibles | | | (1,194 | ) | | (935 | ) |
Other | | | (609 | ) | | 788 | |
Current Deferred Tax Liability (Asset) - Net | | $ | 2,295 | | $ | (147 | ) |
| Noncurrent: | | | | | | | |
| | | | | | | | |
| Book Versus Tax Basis of Property | | $ | 132,236 | | $ | 124,630 | |
| Deferred Fuel Costs - Net | | | 22,891 | | | 2,774 | |
| Prepaid Pension | | | 11,959 | | | 11,570 | |
| Environmental | | | 4,018 | | | 2,680 | |
| Deferred Regulatory Costs | | | 1,644 | | | 3,241 | |
| Deferred State Tax | | | (4,761 | ) | | (2,502 | ) |
| Minimum Pension Liability | | | (2,602 | ) | | (2,917 | ) |
| Investment Tax Credit Basis Gross-Up | | | (1,440 | ) | | (1,612 | ) |
| Other | | | (1,403 | ) | | 410 | |
Noncurrent Deferred Tax Liability - Net | | $ | 162,542 | | $ | 138,274 | |
As of December 31, 2005 and 2004, income taxes due from SJI were approximately $6.6 million and $0.2 million, respectively.
| 6. | FEDERAL AND OTHER REGULATORY TAX ASSETS AND DEFERRED CREDITS: |
The primary asset created by adopting FASB Statement No. 109, "Accounting for Income Taxes,” was Income Taxes - Flowthrough Depreciation in the amount of $17.6 million as of January 1, 1993. This amount represented excess tax depreciation over book depreciation on utility plant because of temporary differences for which, prior to Statement No. 109, deferred taxes previously were not provided. We previously passed these tax benefits through to ratepayers. We are recovering the amortization of the regulatory asset through rates over 18 years, which began in December 1994 (See Note 1).
Investment Tax Credits were deferred and continue to be amortized at the annual rate of 3%, which approximates the life of related assets (See Note 5).
We deferred $11.8 million resulting from a change in the basis for accruing the Gross Receipts & Franchise Taxes in 1978, and are amortizing it on a straight-line basis to operations over 30 years beginning that same year. We accelerated this amortization slightly as a result of a subsequent rate making proceeding (See Note 1).
7. LONG-TERM DEBT: (A)
A schedule of our long-term debt, including current maturities, is as follows (in thousands):
| | | | | Principal Outstanding | |
| | | | | December 31, |
| | | | | 2005 | | | 2004 | |
| First Mortgage Bonds: (B) | | | | | | |
| 8.19% | | Series due 2007 | $ | 4,543 | | $ | 6,816 | |
| 6.12% | | Series due 2010 | | 10,000 | | | 10,000 | |
| 6.74% | | Series due 2011 | | 10,000 | | | 10,000 | |
| 6.57% | | Series due 2011 | | 15,000 | | | 15,000 | |
| 4.46% | | Series due 2013 | | 10,500 | | | 10,500 | |
| 5.027% | | Series due 2013 | | 14,500 | | | 14,500 | |
| 4.52% | | Series due 2014 | | 11,000 | | | 11,000 | |
| 5.115% | | Series due 2014 | | 10,000 | | | 10,000 | |
| 6.50% | | Series due 2016 | | 9,965 | | | 9,965 | |
| 4.60% | | Series due 2016 | | 17,000 | | | 17,000 | |
| 4.657% | | Series due 2017 | | 15,000 | | | 15,000 | |
| 7.97% | | Series due 2018 | | 10,000 | | | 10,000 | |
| 7.125% | | Series due 2018 | | 20,000 | | | 20,000 | |
| 7.7% | | Series due 2027 | | 35,000 | | | 35,000 | |
| 7.9% | | Series due 2030 (C) | | - | | | 10,000 | |
| 5.55% | | Series due 2033 | | 32,000 | | | 32,000 | |
| 5.387% | | Series due 2015 | | 10,000 | | | 10,000 | |
| 5.437% | | Series due 2016 | | 10,000 | | | 10,000 | |
| 5.587% | | Series due 2019 | | 10,000 | | | 10,000 | |
| 6.213% | | Series due 2034 | | 10,000 | | | 10,000 | |
| 5.45% | | Series due 2035 (D) | | 10,000 | | | - | |
| | | | | | | | | |
| Unsecured Notes: | | | | | | | | |
| Debenture Notes, 8.6% due 2010 (E) | | - | | | 10,500 | |
| | | | | | | | | |
Total Long-Term Debt Outstanding | | 274,508 | | | 287,281 | |
Less Current Maturities | | (2,273 | ) | | (5,273 | ) |
| Long-Term Debt | | | $ | 272,235 | | $ | 282,008 | |
| | (A) | Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2006, $2,273; 2007, $2,270; 2008, $-0-; 2009, $-0-; and 2010, $10,000. Our long-term debt agreements contain no financial covenants. |
| | (B) | Our First Mortgage date October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant. |
| | (C) | On July 15, 2005, we retired our 7.9% Medium Term Notes at par. |
| | (D) | On September 13, 2005, we issued $10.0 million of debt under our $150 million Medium Term Note (MTN) Program established in 2005. As of December 31, 2005, $140 million remains available under this MTN program. |
| | (E) | On February 1, 2005, we retired the remaining $7.5 million of our 8.6% Unsecured Debenture Notes due 2010 with a call premium of $184,500. We have deferred this premium and will seek BPU approval to amortize and recover it from ratepayers. |
8. FINANCIAL INSTRUMENTS:
Long-Term Debt - We estimated the fair values of our long-term debt, including current maturities, as of December 31, 2005 and 2004, to be $287.4 and $305.0 million, respectively. Carrying amounts as of December 31, 2005 and 2004 are $274.5 and $287.3 million, respectively. We base the estimates on interest rates available to us at the end of each year for debt with similar terms and maturities. We retire debt when it is cost effective as permitted by the debt agreements.
Other Financial Instruments - The carrying amounts of our other financial instruments approximate their fair values at December 31, 2005 and 2004.
9. UNUSED LINES OF CREDIT AND COMPENSATING BALANCES:
Bank credit available to us totaled $176.0 million at December 31, 2005, of which $87.0 million was used. Those bank facilities consist of a $100.0 million, 3-year revolving credit facility that expires August 2006, and $76.0 million of uncommitted bank lines. The revolving credit facilities contain certain financial covenants measured on a quarterly basis. We were in compliance with these covenants as of December 31, 2005. Borrowings under these lines of credit are at market rates. The weighted-average borrowing cost, which changes daily, was 4.91% and 3.00% at December 31, 2005 and 2004, respectively. We maintain demand deposits with lending banks on an informal basis and they do not constitute compensating balances.
10. RETAINED EARNINGS:
We are restricted as to the amount of cash dividends or other distributions that may be paid on our common stock by an order issued by the BPU in July 2004 that granted us an increase in base rates. Per the order, we are required to maintain total common equity of no less than $289.0 million. Our total common equity balance was $344.6 million at December 31, 2005.
Restrictions also exist under various loan agreements regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of December 31, 2005 and 2004, these restrictions did not affect the amount that may be distributed from our retained earnings.
We received equity infusions of $30.0 million, $15.0 million and $20.0 million from SJI during 2005, 2004 and 2003, respectively. Contributions of capital are credited to Other Paid-In Capital and Premium on Common Stock. Future equity contributions will occur on an as needed basis.
11. EMPLOYEE BENEFIT PLANS:
Pensions & Other Postretirement Benefit Plans - We participate in the defined benefit pension plans and other postretirement benefit plans of SJI. The pension plans provide annuity payments to the majority of full-time, regular employees upon retirement. Newly hired employees do not qualify for participation in the defined benefit pension plans. New hires are eligible to receive an enhanced version of a defined contribution plan. Certain officers of SJG also participate in the non-funded supplemental executive retirement plan (SERP) of SJI, a non-qualified defined benefit pension plan. The other postretirement benefit plans provide health care and life insurance benefits to some retirees.
The BPU authorized us to recover costs related to postretirement benefits other than pensions under the accrual method of accounting consistent with FASB Statement No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." We deferred amounts accrued prior to that authorization and are amortizing them as allowed by the BPU. The unamortized balance of $2.6 million at December 31, 2005 is recoverable in rates. We are amortizing this amount over 15 years, which started January 1998.
Net periodic benefit cost related to the employee and officer pension and other postretirement benefit plans consisted of the following components as of December 31(in thousands):
| | | | | | | | | | | Other | | | |
| | | Pension Benefits | Postretirement Benefits |
| | | 2005 | | | 2004 | | | 2003 | | | 2005 | | | 2004 | | | 2003 | |
| Service Cost | | $ | 2,704 | | $ | 2,545 | | $ | 2,462 | | $ | 732 | | $ | 1,160 | | $ | 1,421 | |
| Interest Cost | | | 5,970 | | | 5,246 | | | 5,320 | | | 1,963 | | | 2,173 | | | 2,448 | |
| | | | | | | | | | | | | | | | | | | | |
| Expected Return on Plan Assets | | | (7,494 | ) | | (5,793 | ) | | (4,996 | ) | | 1,482 | ) | | (1,302 | ) | | (1,078 | ) |
| Amortization of Transition Obligation | | | - | | | - | | | 87 | | | - | | | 592 | | | 756 | |
| Amortization of Loss and Other | | | 2,871 | | | 2,066 | | | 1,978 | | | 209 | | | 130 | | | 373 | |
Net Periodic Benefit Cost | | | 4,051 | | | 4,064 | | | 4,851 | | | 1,422 | | | 2,753 | | | 3,920 | |
ERIP Cost | | | 459 | | | 711 | | | - | | | 1,187 | | | 134 | | | - | |
Capitalized Benefit Costs | | | (1,823 | ) | | (1,474 | ) | | (1,615 | ) | | (640 | ) | | (991 | ) | | (1,294 | ) |
Total Net Periodic Benefit Expense | | $ | 2,687 | | $ | 3,301 | | $ | 3,236 | | $ | 1,969 | | $ | 1,896 | | $ | 2,626 | |
Capitalized benefit costs reflected in the table above relate to our construction program.
The ERIP costs reflected in the table above relate to an early retirement plan offered during both 2005 and 2004. Additional monetary incentives not reflected in the table above totaled $0.2 million in 2005 and $0.4 million in 2004, which will be funded outside of the retirement plans.
A reconciliation of the plans’ benefit obligations, fair value of plan assets, funded status and amounts recognized in our balance sheets follows (in thousands):
| | | | | | | Other | |
| | Pension Benefits | Postretirement Benefits |
| | | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
Change in Benefit Obligations: | | | | | | | | | | | | | |
| Benefit Obligation at Beginning of Year | | $ | 105,668 | | $ | 93,632 | | $ | 34,966 | | $ | 43,109 | |
| Transferred to Affiliate (Note 2) | | | - | | | (4,024 | ) | | - | | | (2,804 | ) |
| Service Cost | | | 2,704 | | | 2,545 | | | 732 | | | 1,160 | |
| Interest Cost | | | 5,971 | | | 5,246 | | | 1,963 | | | 2,172 | |
| Plan Amendments | | | - | | | 434 | | | - | | | (8,643 | ) |
| Actuarial Loss and Other | | | 2,297 | | | 11,856 | | | 3,538 | | | 1,723 | |
| Retiree Contributions | | | - | | | - | | | 300 | | | - | |
Benefits Paid | | | (4,873 | ) | | (4,025 | ) | | (2,437 | ) | | (1,751 | ) |
Benefit Obligation at End of Year | | $ | 111,767 | | $ | 105,666 | | $ | 39,062 | | $ | 34,966 | |
| | | | | | | | | | | | | | |
Change in Plan Assets: | | | | | | | | | | | | | |
| Fair Value of Plan Assets at Beginning of Year | | $ | 87,887 | | $ | 76,626 | | $ | 20,711 | | $ | 19,096 | |
| Transferred to Affiliate (Note 2) | | | - | | | (3,585 | ) | | - | | | (1,392 | ) |
| Actual Return on Plan Assets | | | 6,219 | | | 7,643 | | | 1,196 | | | 1,533 | |
| Employer Contributions | | | 5,078 | | | 11,227 | | | 3,603 | | | 3,225 | |
| Retiree Contributions | | | - | | | - | | | 300 | | | - | |
Benefits Paid | | | (4,873 | ) | | (4,024 | ) | | (2,437 | ) | | (1,751 | ) |
| Fair Value of Plan Assets at End of Year | | $ | 94,311 | | $ | 87,887 | | $ | 23,373 | | $ | 20,711 | |
| | | | | | | | | | |
Funded Status: | | $ | (17,456 | ) | $ | (17,781 | ) | $ | (15,688 | ) | $ | (14,255 | ) |
| Unrecognized Prior Service Cost | | | 2,401 | | | 2,922 | | | (2,898 | ) | | (3,260 | ) |
| Unrecognized Net Loss and Other | | | 35,815 | | | 35,056 | | | 13,435 | | | 11,368 | |
| Prepaid (Accrued) Net Benefit Cost at End of Year | | $ | 20,760 | | $ | 20,197 | | $ | (5,151 | ) | $ | (6,147 | ) |
| | | | | | | | | | | | | | |
Amounts Recognized in the Statement | | | | | | | | | | | | | |
of Financial Position Consist of: | | | | | | | | | | | | | |
| Prepaid (Accrued) Benefit Liability | | $ | 14,720 | | $ | 13,258 | | $ | (5,151 | ) | $ | (6,147 | ) |
| Intangible Asset | | | 127 | | | 310 | | | - | | | - | |
| Accumulated Other Comprehensive Income | | | 5,913 | | | 6,629 | | | - | | | - | |
| Net Amount Recognized at End of Year | | $ | 20,760 | | $ | 20,197 | | $ | (5,151 | ) | $ | (6,147 | ) |
The accumulated benefit obligation (ABO) of our qualified employee pension plans at December 31, 2005 and 2004 was $87.3 million and $82.2 million, respectively. The projected benefit obligation and ABO for our non-funded SERP, which had accumulated benefits in excess of plan assets, were $11.6 million and $11.5 million, respectively, as of December 31, 2005, and $11.6 million and $11.6 million, respectively, as of December 31, 2004. The SERP is reflected in the table above and has no assets.
At December 31, 2005 and 2004, we had recorded an additional minimum pension obligation of $6.0 million and $6.9 million, respectively, related to the SERP, with a corresponding amount recorded to Accumulated Other Comprehensive Loss.
The net changes included in Accumulated Other Comprehensive Loss due to the increase in the minimum pension obligation related to the SERP were $0.4 million, $(1.1) million and $(1.2) million for the years ended December 31, 2005, 2004 and 2003, respectively.
As of November 2004, we implemented caps on the amount of the premium we pay for all employees eligible for postretirement health care. Since employees are responsible for those costs that exceed the premium caps, we were able to substantially reduce our postretirement benefit costs other than pension from that date forward.
The weighted-average assumptions used to determine benefit obligations at December 31 were:
| | | | | | | Other | |
| | | Pension Benefits | Postretirement Benefits |
| | | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| | | | | | | | | | | | | | |
| Discount Rate | | | 5.84 | % | | 5.75 | % | | 5.84 | % | | 5.75 | % |
| Rate of Compensation Increase | | | 3.60 | % | | 3.60 | % | | - | | | - | |
The weighted-average assumptions used to determine net periodic benefit cost for years ended December 31 were:
| | | | | | | | | Other | |
| | | Pension Benefits | Postretirement Benefits |
| | | | 2005 | | | 2004 | | | 2003 | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 5.75 | % | | 6.25 | % | | 6.75 | % | | 5.75 | % | | 6.25 | % | | 6.75 | % |
| Expected Long-Term Return on Plan Assets | | | 8.75 | % | | 8.75 | % | | 9.00 | % | | 7.25 | % | | 7.25 | % | | 7.50 | % |
| Rate of Compensation Increase | | | 3.60 | % | | 3.60 | % | | 3.60 | % | | - | | | - | | | - | |
The discount rate used to determine the benefit obligations at December 31, 2005, which will be used to determine the net periodic benefit cost for 2006, was based on a portfolio model of high-quality instruments with maturities that match the expected benefit payments under our pension and other postretirement benefit plans. In prior years, SJI used the Moody’s Aa bond index yield at each respective year-end. We believe that the new method better reflects the rate at which the benefit obligations could be effectively settled. The expected long-term return on plan assets was based on return projections prepared by our investment manager using SJI’s current investment mix as described under Plan Assets below.
The assumed health care cost trend rates at December 31 were:
| | | | 2005 | | | 2004 | |
| | | | | | | | |
| Post-65 Medical Care Cost Trend Rate Assumed for Next Year | | | 7.5 | % | | 6.5 | % |
| Pre-65 Medical Care Cost Trend Rate Assumed for Next Year | | | 11.0 | % | | 11.0 | % |
| Dental Care Cost Trend Rate Assumed for Next Year | | | 7.5 | % | | 6.5 | % |
| Rate to which Cost Trend Rates are Assumed to Decline | | | | | | | |
| (the Ultimate Trend Rate) | | | 5.0 | % | | 5.0 | % |
| Year that the Rate Reaches the Ultimate Trend Rate | | | 2013 | | | 2016 | |
Assumed health care cost trend rates have a significant effect on the amounts reported for our postretirement health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):
| | | 1-Percentage- | | 1-Percentage- | |
| | | | Point Increase | | | Point Decrease | |
| | | | | | | | |
| Effect on the Total of Service and Interest Cost | | $ | 111 | | $ | (99 | ) |
| Effect on Postretirement Benefit Obligation | | | 1,855 | | | (1,686 | ) |
Plan Assets - SJG’s weighted-average asset allocations at December 31, 2005 and 2004, by asset category are as follows:
| | | | | | | Other | |
| | Pension Benefits | Postretirement Benefits |
| | | | 2005 | | | 2004 | | | 2005 | | | 2004 | |
| Asset Category | | | | | | | | | | | | | |
| U.S. Equity Securities | | | 50 | % | | 52 | % | | 48 | % | | 48 | % |
| International Equity Securities | | | 15 | | | 16 | | | 16 | | | 16 | |
| Fixed Income | | | 35 | | | 32 | | | 36 | | | 36 | |
| | | | | | | | | | | | | | |
| Total | | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
Based on the investment objectives and risk tolerances stated in SJI’s current pension and other postretirement benefit plans’ investment policy and guidelines, the long-term asset mix target considered appropriate is within the range of 58% to 68% equity and 32% to 42% fixed-income investments. Historical performance results and future expectations suggest that equities will provide higher total investment returns than fixed-income securities over a long-term investment horizon.
The policy recognizes that risk and volatility are present to some degree with all types of investments. We seek to avoid high levels of risk at the total fund level through diversification by asset class, style of manager, and sector and industry limits. Specifically prohibited investments include, but are not limited to, venture capital, margin trading, commodities and securities of companies with less than $250.0 million capitalization (except in the small-cap portion of the fund where capitalization levels as low as $50.0 million are permissible).
Future Benefit Payments - The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid during the following years (in thousands):
| | | | | Other | |
| | | | Pension Benefits | | | Postretirement Benefits | |
| | | | | | | | |
| 2006 | | $ | 5,436 | | $ | 2,147 | |
| 2007 | | | 5,503 | | | 2,361 | |
| 2008 | | | 5,561 | | | 2,474 | |
| 2009 | | | 5,635 | | | 2,549 | |
| 2010 | | | 5,707 | | | 2,688 | |
| 2011-2015 | | | 31,384 | | | 13,318 | |
Contributions - We expect to make no contributions to our pension plan in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. We also have a regulatory obligation to contribute approximately $3.6 million annually to our other postretirement benefit plans’ trusts, less costs incurred directly by us.
Defined Contribution Plan - We also offer an Employees’ Retirement Savings Plan (Savings Plan) to eligible employees. We match 50% of participant’s contributions up to 6% of base compensation. For newly hired employees who are not eligible for participation in SJI’s defined benefit plan, we match 50% of participants’ contributions up to 8% of base compensation. We also make a year-end contribution of $500 for employees with fewer than 10 years of service and $1,000 for employees with 10 years or more of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $0.8 million in each of the years 2005, 2004 and 2003.
12. COMMITMENTS AND CONTINGENCIES:
The following table summarizes our contractual cash obligations and their applicable payment due dates as of December 31, 2005 (in thousands):
| | | | | Up to | | Years | | Years | | More than | |
Contractual Cash Obligations | | | Total | | | 1 Year | | | 2 & 3 | | | 4 & 5 | | | 5 Years | |
| | | | | | | | | | | | | | | | | |
| Long-Term Debt | | $ | 274,508 | | $ | 2,273 | | $ | 2,270 | | $ | 10,000 | | $ | 259,965 | |
| Interest on Long-Term Debt | | | 226,203 | | | 16,426 | | | 32,380 | | | 32,287 | | | 145,110 | |
| Operating Leases | | | 480 | | | 273 | | | 175 | | | 32 | | | - | |
| Construction Obligations | | | 6,966 | | | 6,868 | | | 98 | | | - | | | - | |
| Commodity Supply Purchase Obligations | | | 239,892 | | | 44,751 | | | 78,556 | | | 46,013 | | | 70,572 | |
| New Jersey Clean Energy Program (Note 2) | | | 20,600 | | | 5,600 | | | 15,000 | | | - | | | - | |
| Other Purchase Obligations | | | 5,033 | | | 2,183 | | | 1,800 | | | 1,050 | | | - | |
| | | | | | | | | | | | | | | | | |
| Total Contractual | | | | | | | | | | | | | | | | |
| Cash Obligations | | $ | 773,682 | | $ | 78,374 | | $ | 130,279 | | $ | 89,382 | | $ | 475,647 | |
Expected environmental remediation costs and asset retirement obligations are not included in the table above due to the subjective nature of such costs and timing of anticipated payments. As a result, the total obligation cannot be calculated. As discussed in Note 11, we currently do not expect to make a pension contribution in 2006; however, changes in future investment performance and discount rates may ultimately result in a contribution. Furthermore, future pension contributions beyond 2006 cannot be determined at this time. Our regulatory obligation to contribute approximately $3.6 million annually to our postretirement benefit plans’ trusts, less costs incurred directly by us, is not included as the duration is indefinite.
Gas Supply Contracts - In the normal course of conducting business, we have entered into long-term contracts for natural gas supplies, firm transportation and gas storage service. The earliest that any of these contracts expires is March 2006. The transportation and storage service agreements between us and our interstate pipeline suppliers were made under Federal Energy Regulatory Commission approved tariffs. Our cumulative obligation for demand charges and reservation fees paid to suppliers for these services is approximately $4.4 million per month, recovered on a current basis through the BGSS.
Pending Litigation - We are subject to claims arising in the ordinary course of business and other legal proceedings. We accrue liabilities related to these claims when we can determine the amount or range of amounts of probable settlement costs. Management does not currently anticipate the disposition of any known claims to have a material adverse effect on our financial position, results of operations or liquidity.
Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where we or our predecessors operated manufactured gas plants (MGP). We stopped manufacturing gas in the 1950s.
We successfully entered into settlements with all of our historic comprehensive general liability carriers regarding the environmental remediation expenditures at our sites. Also, we have purchased a Cleanup Cost Cap Insurance Policy limiting the amount of remediation expenditures that we will be required to make at 11 of our sites. This Policy will be in force until 2024 at 10 sites and until 2029 at one site. The future cost estimates discussed hereafter are not reduced by projected insurance recoveries from the Cleanup Cost Cap Insurance Policy. The policy is limited to an aggregate payment amount of $50.0 million, of which we have recovered $7.5 million through December 31, 2005.
Since the early 1980s, we accrued environmental remediation costs of $154.5 million, of which $97.8 million has been spent as of December 31, 2005. With the assistance of consulting firms, we estimate that undiscounted future costs to clean up our sites will range from $56.7 million to $206.3 million. Four of our sites comprise a significant portion of these estimates, ranging from a low of $33.1 million and a high of $125.5 million. We recorded the lower end of this range, $56.7 million, as a liability because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. Recorded amounts include estimated costs based on projected investigation and remediation work plans using existing technologies. Actual costs could differ from the estimates due to the long-term nature of the projects, changing technology, government regulations and site-specific requirements. Significant risks surrounding these estimates include unforeseen market price increases for remedial services, property owner acceptance of remedy selection, regulatory approval of selected remedy and remedial investigative findings.
The following table details the amounts expended and accrued for environmental remediation (in thousands):
| | | | 2005 | | | 2004 | |
| | | | | | | | |
| Beginning of Year | | $ | 51,046 | | $ | 50,983 | |
Accruals | | | 11,710 | | | 5,282 | |
Expenditures | | | (6,039 | ) | | (5,219 | ) |
| | | | | | | | |
| End of Year | | $ | 56,717 | | $ | 51,046 | |
The balances are segregated between current and non-current on the balance sheets under the captions Current Liabilities and Deferred Credits and Other Non-Current Liabilities.
The remediation efforts at our four most significant sites include the following:
Site 1 - The remedial selection process is underway for this site. Once complete, a remedial action work plan will be submitted to the New Jersey Department of Environmental Protection (NJDEP) for approval. Remaining steps to remediate include remedy selection, regulatory approval and remedy implementation for impacted soil, groundwater, and river sediments as well as acceptance of the selected remedy by affected property owners.
Site 2 - Various remedial investigation and action activities, such as completed and approved interim remedial measures and conceptual remedy selection, are ongoing at this site. Remaining steps to remediate include remedy selection, regulatory approval, and implementation for the remaining impacted soil, groundwater, and stream sediments.
Site 3 - Remedial investigative activities are ongoing at this site. Remaining steps to remediate include completing the remedial investigation of impacted soil and groundwater in preparation for selecting the appropriate action and implementation gaining regulatory and property owner approval of the selected remedy.
Site 4 - The NJDEP has approved the selected remedy to address impacted soil and groundwater at this site. Remaining steps to remediate include bidding, implementation, and ongoing operation and maintenance of the selected remedy.
We have two regulatory assets associated with environmental costs (See Note 1). The first asset, Environmental Remediation Cost: Expended - Net, represents what was actually spent to clean up former gas manufacturing plant sites. These costs meet the requirements of FASB Statement No. 71. The BPU allows us to recover expenditures through the RAC (See Note 2). The other asset, Environmental Remediation Cost: Liability for Future Expenditures, relates to estimated future expenditures determined under the guidance of FASB Statement No. 5, "Accounting for Contingencies." We recorded this amount, which relates to former manufactured gas plant sites, as a regulatory asset under Statement No. 71 with the corresponding amount reflected on the balance sheets under the captions Current Liabilities and Deferred Credits and Other Non-Current Liabilities. The BPU's intent, evidenced by current practice, is to allow us to recover the deferred costs over 7-year periods after they are spent.
As of December 31, 2005, we reflected the unamortized remediation costs of $9.4 million on the balance sheet under Regulatory Assets. Since implementing the RAC in 1992, we have recovered $45.5 million through rates (See Note 2).
13. QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:
The summarized quarterly results of our operations are as follows (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| SOUTH JERSEY GAS COMPANY QUARTERLY FINANCIAL DATA (Unaudited) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Summarized quarterly results of SJG's operations (in thousands): | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2005 Quarter Ended | | | 2004 Quarter Ended | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 214,537 | | $ | 86,083 | | $ | 89,702 | | $ | 196,890 | | $ | 202,260 | | $ | 75,970 | | $ | 73,480 | | $ | 157,117 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of Sales | | | 144,345 | | | 55,111 | | | 67,076 | | | 148,420 | | | 137,096 | | | 47,066 | | | 50,184 | | | 106,514 | |
| Operation and Maintenance | | | | | | | | | | | | | | | | | | | | | | | | | |
| Including Fixed Charges | | | 26,580 | | | 23,080 | | | 22,162 | | | 28,923 | | | 25,614 | | | 25,260 | | | 23,314 | | | 28,776 | |
| Income Taxes (Benefit) | | | 16,125 | | | 2,577 | | | (334 | ) | | 6,817 | | | 14,683 | | | 830 | | | (519 | ) | | 7,975 | |
| Energy and Other Taxes | | | 4,893 | | | 1,952 | | | 1,580 | | | 3,456 | | | 4,728 | | | 1,983 | | | 1,653 | | | 3,094 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Expenses | | | 191,943 | | | 82,720 | | | 90,484 | | | 187,616 | | | 182,121 | | | 75,139 | | | 74,632 | | | 146,359 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income and Expense | | | (30 | ) | | (9 | ) | | 11 | | | 126 | | | 567 | | | (8 | ) | | 72 | | | 255 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) Applicable | | | | | | | | | | | | | | | | | | | | | | | | | |
| to Common Stock | | $ | 22,564 | | $ | 3,354 | | $ | (771 | ) | $ | 9,400 | | $ | 20,706 | | $ | 823 | | $ | (1,080 | ) | $ | 11,013 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| NOTE: Because of the seasonal nature of the business, statements for the 3-month periods are not indicative of the results for a full year. | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures - Management has established controls and procedures to ensure that material information relating to SJG is made known to the officers who certify its financial reports and to other members of senior management and the Board of Directors.
Based upon their evaluation as of December 31, 2005, the principal executive officer and the principal financial officer of SJG have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) employed at SJG are effective to ensure that the information required to be disclosed by SJG in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
No change in SJG’s internal control over financial reporting occurred during SJG’s fourth fiscal quarter.
Item 9B. Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Not applicable.
Item 11. Executive Compensation
Not applicable.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Not applicable.
Item 13. Certain Relationships and Related Transactions
Not applicable.
Item 14. Principal Accounting Fees and Services
Fees Paid to Auditors
Deloitte & Touche LLP served as the auditors of SJG and its parent, SJI, during 2005. During 2005, the audit services performed by that firm for SJG consisted of the audits of the financial statements of the Company and the preparation of various reports based on those audits and services related to filings with the Securities Exchange Commission and New York Stock Exchange.
Audit Fees
The aggregate fees billed for the audit of SJG’s financial statements by Deloitte & Touche totaled $149,400 and $132,000 in fiscal years 2005 and 2004, respectively.
Audit-Related Fees
None.
Tax Fees
None.
All Other Fees
None.
PART IV
Item 15. Exhibits and Financial Statement Schedule
(a) Listed below are all financial statements and schedules filed as part of this report:
1 - The financial statements and notes to financial statements together with the report thereon of Deloitte & Touche LLP, dated March 2, 2006. See Item 8.
2 - Supplementary Financial Information
Supplemental Schedules as of December 31, 2005, 2004 and 2003 and for the three years ended December 31, 2005, 2004, and 2003:
Report of the Independent Registered Public Accounting Firm of Deloitte & Touche LLP, Auditors of the Company. See Item 8.
Schedule II - Valuation and Qualifying Accounts. See page 58.
All schedules, other than that listed above, are omitted because the information called for is included in the financial statements filed or because they are not applicable or are not required.
(b) List of Exhibits (Exhibit Number is in Accordance with the Exhibit Table in Item 601 of Regulation S-K).
Exhibit Number | Description | Reference |
(3)(a) | Certificate of Incorporation of South Jersey Gas Company. | Incorporated by reference from Exhibit (3)(a) of Form 10-K filed March 7, 1997. |
(3)(b) | Bylaws of South Jersey Gas Company, as amended and restated through April 29, 2004 (filed herewith). | |
(4)(a) | Form of Stock Certified for Common Stock. | Incorporated by reference from Exhibit (4)(a) of Form 10 filed March 7, 1997. |
(4)(b)(i) | First Mortgage Indenture dated October 1, 1947. | Incorporated by reference from Exhibit (4)(b)(i) of Form 10-K of SJI for 1987 (1-6364). |
(4)(b)(iv) | Twelfth Supplemental Indenture dated as of June 1, 1980. | Incorporated by reference from Exhibit 5(b) of Form S-7 of SJI (2-68038). |
(4)(b)(xv) | Seventeenth Supplemental Indenture dated as of May 1, 1989. | Incorporated by reference from Exhibit (4)(b)(xv) of Form 10-K of SJI for 1989 (1-6364). |
(4)(b)(xvii) | Nineteenth Supplemental Indenture dated as of April 1, 1992. | Incorporated by reference from Exhibit (4)(b)(xvii) of Form 10-K of SJI for 1992 (1-6364). |
Exhibit Number | Description | Reference |
(4)(b)(xx) | Twenty-Second Supplemental Indenture dated as of October 1, 1998. | Incorporated by reference from Exhibit (4)(b)(ix) of Form S-3 (333-62019). |
(4)(b)(xxi) | Twenty-Third Supplemental Indenture dated as of September 1, 2002. | Incorporated by reference from Exhibit (4)(b)(x) of Form S-3 (333-98411) |
(4)(b)(xxii) | Twenty-Fourth Supplemental Indenture dated as of September 1, 2005. | Incorporated by reference from Exhibit (4)(b)(vi) of Form S-3 (333-126822). |
(4)(c) | Indenture dated as of January 31, 1995; 8.60% Debenture Notes due February 1, 2010. | Incorporated by reference from Exhibit (4)(c) of Form 10-K of SJI for 1994 (1-6364). |
(4)(e) | Medium Term Note Indenture of Trust dated October 1, 1998. | Incorporated by reference from Exhibit (4)(e) of Form S-3 (333-62019). |
(4)(f) | Medium Term Note Indenture of Trust, as amended, dated December 16, 2002. | Incorporated by reference from Exhibit 4(e) of Form S-3 (333-98411). |
(10)(a) | Gas storage agreement (GSS) between South Jersey Gas Company and Transco dated October 1, 1993. | Incorporated by reference from Exhibit (10)(d) of Form 10-K of SJI for 1993 (1-6364). |
(10)(b) | Gas storage agreement (S-2) between South Jersey Gas Company and Transco dated December 16, 1953. | Incorporated by reference from Exhibit (5)(h) of Form S-7 of SJI (2-56223). |
(10)(c) | Gas storage agreement (LG-A) between South Jersey Gas Company and Transco dated June 3, 1974. | Incorporated by reference from Exhibit (5)(f) of Form S-7 of SJI (2-56223). |
(10)(d) | Gas storage agreement (WSS) between South Jersey Gas Company and Transco dated August 1, 1991. | Incorporated by reference from Exhibit (10)(h) of Form 10-K of SJI for 1991 (1-6364). |
(10)(e)(i) | Gas storage agreement (LSS) between South Jersey Gas Company and Transco dated October 1, 1993. | Incorporated by reference from Exhibit (10)(i) of Form 10-K of SJI for 1993 (1-6364). |
(10)(e)(ii) | Gas storage agreement (SS-1) between South Jersey Gas Company and Transco dated May 10, 1987 (effective April 1, 1988). | Incorporated by reference from Exhibit (10)(i)(a) of Form 10-K of SJI for 1988 (1-6364). |
(10)(e)(iv) | Gas transportation service agreement between South Jersey Gas Company and Transco dated April 1, 1986. | Incorporated by reference from Exhibit (10)(i)(c) of Form 10-K of SJI for 1989 (1-6364). |
(10)(e)(vi) | Service agreement (FT) between South Jersey Gas Company and Transco dated February 1, 1992. | Incorporated by reference from Exhibit (10)(i)(f) of Form 10-K of SJI for 1991 (1-6364). |
Exhibit Number | Description | Reference |
(10)(e)(viii) | Gas storage agreement (SS-2) between South Jersey Gas Company and Transco dated July 25, 1990. | Incorporated by reference from Exhibit (10)(i)(i) of Form 10-K of SJI for 1991 (1-6364). |
(10)(e)(ix) | Gas transportation service agreement between South Jersey Gas Company and Transco dated December 20, 1991. | Incorporated by reference from Exhibit (10)(i)(j) of Form 10-K of SJI for 1993 (1-6364). |
(10)(e)(x) | Amendment to gas transportation agreement dated December 20, 1991 between South Jersey Gas Company and Transco dated October 5, 1993. | Incorporated by reference from Exhibit (10)(i)(k) of Form 10-K of SJI for 1993 (1-6364). |
(10)(e)(xi) | CNJEP Service agreement between South Jersey Gas Company and Transco dated June 27, 2005 (filed herewith). | |
(10)(g)(i) | Gas transportation service agreement (TF) between South Jersey Gas Company and CNG Transmission Corporation dated October 1, 1993. | Incorporated by reference from Exhibit (10)(k)(h) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(iii) | Gas transportation service agreement (FTS-1) between South Jersey Gas Company and Columbia Gulf Transmission Company dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(k) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(iv) | Assignment agreement capacity and service rights (FTS-2) between South Jersey Gas Company and Columbia Gulf Transmission Company dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(i) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(v) | FTS Service Agreement No. 39556 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(m) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(vi) | FTS Service Agreement No. 38099 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(n) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(vii) | NTS Service Agreement No. 39305 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(o) of Form 10-K of SJI for 1993 (1-6364). |
(10)(g)(viii) | FSS Service Agreement No. 38130 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(p) of Form 10-K of SJI for 1993 (1-6364). |
Exhibit Number | Description | Reference |
(10)(g)(ix) | SST Service Agreement No. 38086 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(q) of Form 10-K of SJI for 1993 (1-6364). |
(10)(h)(i)* | Deferred Payment Plan for Directors of South Jersey Industries, Inc., South Jersey Gas Company, Energy & Minerals, Inc., R&T Group, Inc. and South Jersey Energy Company as amended and restated October 21, 1994. | Incorporated by reference from Exhibit (10)(l) of Form 10-K of SJI for 1994 (1-6364). |
(10)(h)(ii)* | Form of Deferred Compensation Agreement between South Jersey Industries, Inc. and/or a subsidiary and seven of its officers. | Incorporated by reference from Exhibit (10)(j)(a) of Form 10-K of SJI for 1980 (1-6364). |
(10)(h)(iii)* | Schedule of Deferred Compensation Agreements. | Incorporated by reference from Exhibit (10)(l)(b) of Form 10-K of SJI for 1997 (1-6364). |
(10)(h)(iv)* | Supplemental Executive Retirement Program, as amended and restated effective July 1, 1997, and Form of Agreement between certain South Jersey Industries, Inc. or subsidiary Company officers. | Incorporated by reference from Exhibit (10)(l)(i) of Form 10-K of SJI for 1997 (1-6364). |
(10)(h)(v)* | Form of Officer Employment Agreement between certain officers and either South Jersey Industries, Inc. or its subsidiaries. | Incorporated by reference from Exhibit (10)(l)(d) of Form 10-K of SJI for 1994 (1-6364). |
(10)(h)(vi)* (10)(h)(vii)* | Schedule of Officer Employment Agreements. Officer Severance Benefit Program for all officers. | Incorporated by reference from Exhibit (10)(h)(vi) of Form 10-K of SJI for 2003. Incorporated by reference from Exhibit (10)(l)(g) of Form 10-K of SJI for 1985 (1-6364). |
(10)(h)(viii)* | Discretionary Incentive Bonus Program for all officers and management employees. | Incorporated by reference from Exhibit (10)(l)(h) of Form 10-K of SJI for 1985 (1-6364). |
(10)(i)(i) | Three-year Revolving Credit Agreement for SJG | Incorporated by reference from Exhibit 10 of Form 10-Q of SJG as filed on November 14, 2003 (000-22211). |
(10)(i)(ii) | First Amendment to Three-year Revolving Credit Agreement. | Incorporated by reference from Exhibit 10.1 of Form 10-Q of SJG as filed on November 15, 2004 (000-22211). |
Exhibit Number | Description | Reference |
(12) | Calculation of Ratio of Earnings to Fixed Charges (Before Federal Income Taxes) (filed herewith). | |
(18) | Preferability Letter from Independent Auditors’ Re: Pension Measurement Date. | Incorporated by reference from Exhibit 18 of Form 10-K of SJG for 2002 (000-22211). |
(21) | Subsidiaries of the Registrant (filed herewith). | |
(23) | Independent Registered Public Accounting Firm’s Consent (filed herewith). | |
(31.1) | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
(31.2) | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
(32.1) | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
(32.2) | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
* Constitutes a management contract or a compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTH JERSEY GAS COMPANY
BY: /s/ David A. Kindlick
David A. Kindlick, Senior Vice President &
Chief Financial Officer
Date: March 7, 2006
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | | Title | Date |
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| /s/ Edward J. Graham | | Chairman of the Board, President & Chief Executive Officer | March 7, 2006 |
| (Edward J. Graham) | | (Principal Executive Officer) | |
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| /s/ David A. Kindlick | | Senior Vice President & Chief Financial Officer | March 7, 2006 |
| (David A. Kindlick) | | (Principal Financial and Accounting Officer) | |
| | | | |
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| | | | |
| /s/ Richard H. Walker, Jr. | | Senior Vice President, General Counsel & Secretary | March 7, 2006 |
| (Richard H. Walker, Jr.) | | | |
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| /s/ Shirli M. Billings | | Director | March 7, 2006 |
| (Shirli M. Billings) | | | |
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| | | | |
| | | | |
| /s/ Charles Biscieglia | | Director | March 7, 2006 |
| (Charles Biscieglia) | | | |
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| Signature | | Title | Date |
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| /s/ Sheila Hartnett-Devlin | | Director | March 7, 2006 |
| (Sheila Hartnett-Devlin) | | | |
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| /s/ William J. Hughes | | Director | March 7, 2006 |
| (William J. Hughes) | | | |
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| /s/ Frederick R. Raring | | Director | March 7, 2006 |
| (Frederick R. Raring) | | | |
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SOUTH JERSEY GAS COMPANY |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
(In Thousands) | |
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| Col. A | | | Col. B | | | Col. C | | | Col. D | | | Col. E | |
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| | | | | | Additions | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Balance at | | | Charged to | | | Charged to | | | | | | Balance at | |
| | | Beginning | | | Costs and | | | Other Accounts - | | | Deductions - | | | End | |
| Classification | | | of Period | | | Expenses | | | Describe (a) | | | Describe (b) | | | of Period | |
| | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | |
December 31, 2005 | | $ | 2,871 | | $ | 2,073 | | $ | 85 | | $ | 1,568 | | $ | 3,461 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | |
December 31, 2004 | | $ | 3,263 | | $ | 816 | | $ | 1,716 | | $ | 2,924 | | $ | 2,871 | |
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| | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | |
December 31, 2003 | | $ | 3,258 | | $ | 3,084 | | $ | 806 | | $ | 3,885 | | $ | 3,263 | |
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| (a) Recoveries of accounts previously written off and minor adjustments. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (b) Uncollectible accounts written off. | | | | | | | | | | | | | | | | |
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