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, 2008
| [ ] | 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] (Do not check if a smaller reporting company) Smaller reporting company [ ]
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
Forward Looking Statements
Certain statements contained in this Annual Report on form 10-K 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 by the Company and are intended to qualify for the safe harbor from liability established by the Private Securities Litigation Reform Act of 1995. When used in this Report, or any other of the Company’s documents or oral presentations, 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 risks set forth under “Risk Factors” in Part I, Item 1A of this Annual Report on Form 10-K and elsewhere throughout this Report. 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 South Jersey Gas Company, Inc. (SJG or the Company) believes 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, SJG undertakes no obligation to update or revise any of its forward-looking statements whether as a result of new information, future events or otherwise.
Available Information - Information regarding SJG can be found at the South Jersey Industries, Inc. (SJI) 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.
PART I
Item 1. Business
Units of Measurement
| | For Natural Gas: | |
| | 1 dt | = One decatherm |
| | 1 MMdt | = One million decatherms |
| | Dts/d | = Decatherms per day |
| | MDWQ | = Maximum daily withdrawal quantity |
Description of Business
South Jersey Gas Company (SJG) is a regulated natural gas utility. SJG distributes natural gas in the seven southernmost counties of New Jersey.
Additional information on the nature of our business is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Market Risk” and Note 2, “Rates and Regulatory Actions”.
Financial Information About Reportable Segments
Not applicable.
Rates and Regulation
Information on our rates and regulatory affairs is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 2, “Rates and Regulatory Actions”.
Sources and Availability of Raw Materials
Transportation and Storage Agreements
SJG has direct connections to two interstate pipeline companies, Transcontinental Gas Pipe Line Company, LLC (Transco) and Columbia Gas Transmission, LLC (Columbia). During 2008, SJG purchased and had delivered approximately 37.0 million decatherms (MMdts) of natural gas for distribution to both on-system and off-system customers. Of this total, 25.3 MMdts was transported on the Transco pipeline system while 11.7 MMdts was transported on the Columbia pipeline system. SJG also secures firm transportation and other long term services from two additional pipelines upstream of the Transco and Columbia systems. They include Columbia Gulf Transmission Company, LLC (Columbia Gulf) 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). Unless otherwise indicated, our intentions are to renew or extend these service agreements before they expire.
Transco:
Transco is SJG’s largest supplier of long-term gas transmission services which includes both year-round and seasonal firm transportation (FT) service arrangements. When combined, these services enable SJG to purchase gas from third parties and have delivered to its city gate stations by Transco a total of 280,525 dts per day (dts/d). Of this total, 133,917 dts/d is long-haul FT (where gas can be transported from the production areas of the Southwest to the market areas of the Northeast) while 146,608 dts/d is market area FT. The terms of the year-round agreements extend for various periods through 2025, while the term of the seasonal agreement extends to 2011.
Of the 280,525 dts/d of Transco services mentioned above, SJG has released a total of 89,800 dts/d of its long-haul FT and 25,565 dts/d of its market area FT service. These releases were made in association with SJG’s Conservation Incentive Program (CIP).
SJG also has seven long-term gas storage service agreements with Transco that, when combined, are capable of storing approximately 6.4 MMdts. 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 124,840 dts/d during periods of high demand. The terms of the storage service agreements extend for various periods from 2008 to 2013. During 2008 SJG released 17,433 dts/d of Transco SS-1 storage demand and 1,353,159 dts of its SS-1 storage capacity (both represent 100 percent of this service) thereby reducing its Transco maximum daily storage withdrawal quantity daily to 107,407 dts/d, and its storage capacity to approximately 5.0 MMdts. Also released was 17,433 dts/d of winter season firm transportation service associated with SS-1 storage service.
It should also be noted that effective May 1, 2006 SJG permanently released its Transco WSS Storage Service having a storage capacity of 4.4 MMdts and a maximum daily withdrawal quantity (MDWQ) of 51,837 dts to SJRG resulting in significant savings in gas related costs. This action to release both WSS and SS-1 storages was also taken in concert with SJG’s CIP.
Dominion:
Entering 2008, SJG had two firm transportation services with Dominion which delivered gas to Transco’s Leidy Line for ultimate delivery to SJG city gate stations. One said services is associated with a storage service which SJG subscribes to with Transco (Transco SS-1). Since SJG released its Transco SS-1 storage service in 2008, it also assigned 17,432 dts/d of this associated Dominion firm transportation service to SJRG. SJG had previously had a third firm transportation service with Dominion which provided a link between SJG’s service on Texas Gas and Transco’s Leidy Line system in Pennsylvania. However, as SJG opted to allow its Texas Gas service to expire in 2007, it also chose to allow its FT service on Dominion (unrelated to storage), with a maximum contract quantity of 24,874 dts/d, to expire under its terms effective October 31, 2007. This decision resulted in significant cost savings.
SJG also subscribes to a storage service with Dominion which provides a MDWQ of 10,000 dts during the period between November 16 and March 31 of winter season with 423,000 dts of storage capacity. Gas from this storage is delivered through both the Dominion and Transco pipeline systems.
Columbia:
SJG has two firm transportation agreements with Columbia which, when combined, provide for 45,022 dts/d of firm deliverability and extend through October 31, 2009. In 2008, SJG released 14,714 dts/d of this amount to SJRG in conjunction with its CIP thereby reducing the availability of firm transportation on the Columbia system to 30,308 dts/d.
SJG also subscribes to a firm storage service (FSS) with Columbia under three separate agreements, the longest of which extends through March 31, 2014. When combined, these three FSS storage agreements provide SJG with a winter season MDWQ of 52,891 dts with an associated 3,473,022 dts of storage capacity. During 2008, SJG released to SJRG 17,500 dts of its FSS MDWQ along with 1,249,485 dts of its Columbia FSS storage capacity. In addition, SJG also released to SJRG 17,500 dts of its Columbia SST MDWQ transportation service which is associated with FSS service. Both of these releases were made by SJG in connection with its CIP.
Columbia Gulf
SJG has one firm transportation agreement with Columbia Gulf which provides up to 45,985 dts/d of firm deliverability in the winter season and 43,137dts/d during the summer season. This service facilitates the movement of gas from the production area in southern Louisiana to an interconnect with the Columbia pipeline system at Leach, KY.
During 2008, SJG released 7,969 dts/d of its service on Columbia Gulf to a group of industrial end users on its system, with the remainder being released to SJRG.
Gas Supplies
SJG no longer has long-term gas supply agreements with third party producer-suppliers. In recent years, due to increased liquidity in the market place, SJG has replaced its long-term gas supply agreements with short-term agreements and uses financial contracts secured through SJRG to hedge against forward price risk. Short-term agreements typically extend between one day and several months in duration. As such, its long-term contracts were allowed to expire under their terms.
Supplemental Gas Supplies
During 2008, SJG entered into two seasonal Liquefied Natural Gas (LNG) sales agreements with two separate third party suppliers. The term of the first agreement which was used during the 2008 summer season to refill SJG’s storage tank, extended through November 30, 2008, and had an associated contract quantity of 400,000 dts. The second agreement was acquired to replenish LNG in storage during the 2008-2009 winter season. This agreement extends through March 31, 2009 and provides SJG with up to 200,000 dts 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 434,300 dts of natural gas and has an installed capacity to vaporize up to 96,750 dts 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 12,420 dts of gas and injecting up to 10,350 dts/d 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 Fahrenheit (F). Gas demand on such a design day for the 2008-2009 winter season is estimated to be 451,418 dts. SJG projects that it has adequate supplies and interstate pipeline entitlements to meet its design requirements. SJG experienced its highest peak-day demand for calendar year 2008 of 374,902 dts on December 22nd while experiencing an average temperature of 21.85 degrees F that day.
Natural Gas Prices
SJG’s average cost of natural gas purchased and delivered in 2008, 2007 and 2006, including demand charges, was $9.90 per dt, $9.07 per dt and $9.27 per dt, 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 Financial Condition and Results of Operations”, of this report.
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 on 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
Information on competition is incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, of this report.
Research
During the last three fiscal years, SJG did not engage in research activities to any material extent.
Environmental Matters
Information on environmental matters can be found in Note 12 of the financial statements included under Item 8 of this report.
Employees
SJG had a total of 383 employees as of December 31, 2008. Of that total, 256 employees are unionized. There are 39 unionized employees represented by the International Brotherhood of Electrical Workers (“IBEW”) and they recently ratified a 4-year contract. The remaining unionized employees are represented by the International Association of Machinists and Aerospace Workers (“IAM”). The IAM is asserting that the labor agreement, which the Company believes expired on January 14, 2009, is evergreen for one year from that expiration date. The Company has filed a charge with the National Labor Relations Board for a determination on the matter. We await the Board’s decision, and 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. |
| | • | Changes in the regulatory environment or unfavorable rate regulation may have an unfavorable impact on SJG’s financial performance or condition. SJG’s business is regulated by the New Jersey Board of Public Utilities which has authority over many of the activities of the business including, but not limited to, the rates it charges to its customers, the amount and type of securities it can issue, the nature of investments it can make, the nature and quality of services it provides, safety standards and other matters. The extent to which the actions of regulatory commissions restrict or delay SJG’s ability to earn a reasonable rate of return on invested capital and/or fully recover operating costs may adversely affect its results of operations, financial condition and cash flows. |
| | • | 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, high commodity costs, or customer conservation initiatives could result in reduced demand for natural gas. While SJG currently has a conservation incentive program clause that protects its revenues and gross margin against usage that is lower than a set level, the clause is currently approved as a three-year pilot program. Should this clause expire without replacement, lower customer energy utilization levels would likely reduce SJG’s net income. |
| | • | High natural gas prices could cause more of SJG’s receivables to be uncollectible. Higher levels of uncollectibles from utility 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 would negatively impact the net income of SJG. SJG is capital intensive, resulting in the incurrence of significant amounts of debt financing. SJG has issued all long-term debt either at fixed rates or has utilized interest rate swaps to mitigate changes in floating rates. However, new issues of long-term debt and all variable rate short-term debt are exposed to the impact of rising interest rates. |
| | | The inability to obtain capital, particularly short-term capital from commercial banks, could negatively impact the daily operations and financial performance of SJG. SJG uses short-term borrowings under committed and uncommitted credit facilities provided by commercial banks to supplement cash provided by operations, to support working capital needs, and to finance capital expenditures, as incurred. If the customary sources of short-term capital were no longer available due to market conditions, SJG may not be able to meet its working capital and capital expenditure requirements and borrowing costs could increase. |
| | • | A downgrade in SJG’s credit rating could negatively affect its ability to access adequate and cost effective capital. SJG’s ability to obtain adequate and cost effective capital depends largely on its credit ratings, which are greatly influenced by financial condition and results of operations. If the rating agencies downgrade SJG’s credit ratings, particularly below investment grade, SJG’s borrowing costs would increase. In addition, SJG would likely be required to pay higher interest rates in future financings and potential funding sources would likely decrease. |
| | • | 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. |
| | • | Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs. SJG’s gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, accidents and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of operations, which in turn could lead to substantial losses. In accordance with customary industry practice, SJG maintains insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could adversely affect SJG’s financial position and results of operations. |
| | • | Adverse results in legal proceedings could be detrimental to the financial condition of SJG. The outcomes of legal proceedings can be unpredictable and can result in adverse judgments. |
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, 2008, there were approximately 107.3 miles of mains in the transmission systems and 5,765 miles of mains in the distribution systems.
SJG owns 154 acres of land in Folsom, New Jersey, which is the site of its corporate headquarters. Approximately 140 acres of this property is deed restricted. SJG also has office and service buildings, at six other locations in the territory. There is a liquefied natural gas storage and vaporization facility at one of these locations.
As of December 31, 2008, SJG’s utility plant had a gross book value of $1,172.0 million and a net book value, after accumulated depreciation, of $876.6 million. In 2008, $52.6 million was spent on additions to utility plant and there were retirements of property having an aggregate gross book cost of $5.7 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 Equity
Related Stockholder Matters, and Issuer Purchases of Equity Securities
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 $289.2 million. SJG’s Total Common Equity balance was $401.7 million at December 31, 2008.
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, 2008, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. Dividends of $14.9 million were declared and paid on SJG’s common stock in 2008 and $18.7 million were declared and paid in 2007.
Item 6. Selected Financial Data
The following financial data has been obtained from SJG’s audited financial statements:
(In Thousands of $’s)
| | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 568,046 | | | $ | 630,547 | | | $ | 642,671 | | | $ | 587,212 | | | $ | 508,827 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 84,417 | | | $ | 83,989 | | | $ | 81,209 | | | $ | 77,676 | | | $ | 71,451 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income before Preferred Dividend Requirement | | $ | 39,431 | | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,592 | | | $ | 31,597 | |
| | | | | | | | | | | | | | | | | | | | | |
| Preferred Dividend Requirements (1) | | | - | | | | - | | | | - | | | | (45 | ) | | | (135 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Applicable to Common Stock | | $ | 39,431 | | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,547 | | | $ | 31,462 | |
| | | | | | | | | | | | | | | | | | | | | |
| 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 (2) | | | 4.4 | x | | | 4.1 | x | | | 3.7 | x | | | 4.0 | x | | | 3.9 | x |
| | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | | | | | | | | | | | | | | | | | | | | |
| | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2004 | |
| | | | | | | | | | | | | | | | | | | | | |
| Property, Plant and Equipment, Net | | $ | 876,582 | | | $ | 847,691 | | | $ | 821,833 | | | $ | 788,787 | | | $ | 732,781 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 1,354,015 | | | $ | 1,227,162 | | | $ | 1,228,076 | | | $ | 1,170,975 | | | $ | 1,007,733 | |
| | | | | | | | | | | | | | | | | | | | | |
| Capitalization: | | | | | | | | | | | | | | | | | | | | |
| Common Equity (3) | | $ | 401,739 | | | $ | 378,348 | | | $ | 360,353 | | | $ | 344,568 | | | $ | 302,827 | |
| Preferred Stock (1) | | | - | | | | - | | | | - | | | | - | | | | 1,690 | |
| Long-Term Debt | | | 269,873 | | | | 294,873 | | | | 294,893 | | | | 272,235 | | | | 282,008 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Capitalization | | $ | 671,612 | | | $ | 673,221 | | | $ | 655,246 | | | $ | 616,803 | | | $ | 586,525 | |
| Total Customers | | | 340,136 | | | | 335,663 | | | | 330,049 | | | | 322,424 | | | | 313,579 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) On May 2, 2005, we redeemed all of our 8% Redeemable Cumulative Preferred Stock. |
| (2) 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. Fixed charges consist of interest charges and preferred securities dividend requirements. |
| (3) Included are SJI cash contributions to capital as follows: 2008, 2007 and 2006 - none; 2005 - $30.0 million; 2004 - $15.0 million. |
Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations
OVERVIEW:
Organization - We are an operating public utility company engaged in the purchase, transmission and sale of natural gas for residential, commercial and industrial use. We also sell natural gas and pipeline transportation capacity (off-system sales) on a wholesale basis to various customers on the interstate pipeline system and transport natural gas purchased directly from producers or suppliers to their customers.
Our 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. We benefit from our proximity to Philadelphia, PA and Wilmington, DE on the western side of our service territory and Atlantic City, NJ and the popular shore communities on the eastern side. Economic development and housing growth have been long driven by the development of the Philadelphia metropolitan area. In recent years, housing growth in the eastern portion of our service territory has increased substantially and accounted for approximately half of our annual customer growth. Economic growth in Atlantic City and the surrounding region has been primarily driven by new gaming and non-gaming investments that emphasize destination style attractions. While many of these new projects were suspended or postponed due to the current economic environment, the casino industry is expected to remain a significant source of regional economic development going forward. The ripple effect from Atlantic City has produced new housing and 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 our growth. Presently, we serve approximately 65% of households within our territory with natural gas. We also serve southern New Jersey’s diversified industrial base that includes processors of petroleum and agricultural products; chemical, glass and consumer goods manufacturers; and high technology parks.
As of December 31, 2008, we served 340,136 residential, commercial and industrial customers in southern New Jersey, compared with 335,663 customers at December 31, 2007. No material part of our business is dependent upon a single customer or a few customers. Gas sales, transportation and capacity release for 2008 amounted to 144.3 MMdts (million decatherms), of which 51.2 MMdts were firm sales and transportation, 2.8 MMdts were interruptible sales and transportation and 90.3 MMdts were off-system sales and capacity release. The breakdown of firm sales and transportation includes 45.9% residential, 23.0% commercial, 25.1% industrial, and 6.0% cogeneration and electric generation. At year-end 2008, we served 317,026 residential customers, 22,636 commercial customers and 474 industrial customers. This includes 2008 net additions of 4,057 residential customers and 416 commercial customers.
We make wholesale gas sales to gas marketers for resale and 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 us to deliver gas at delivery points on the interstate pipeline system other than our own city gate stations and release excess pipeline capacity to third parties. During 2008, off-system sales amounted to 9.6 MMdts and capacity release amounted to 80.7 MMdts.
Supplies of natural gas available to us 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 us at any time if this action is necessary to meet the needs of higher priority customers as described in our tariffs. In 2008 usage by interruptible customers, excluding off-system customers, amounted to 2.8 MMdts, approximately 1.9% of the total throughput.
Our primary goals are to: 1) provide safe, reliable natural gas service at the lowest cost possible; 2) promote natural gas as the fuel of choice for residential, commercial and industrial customers; and 3) aid our customers in becoming more energy efficient.
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 — Southern New Jersey, our primary area of operations, has not been immune to the issues impacting the new housing market nationally. However, net customers for SJG still grew 1.3% as we increased our focus on customer conversions. Consumers converting from other heating fuels, such as electric, propane or oil have historically accounted for 20-25% of annual SJG customer growth. In 2008, we increased our efforts to attract conversions in light of the very favorable relationship between natural gas and alternative fuel prices, obtaining 2,700 conversion customers compared with an average of 1,700 per year over the previous five years. Customers in our service territory typically base their decisions to convert on comparisons of fuel costs and environmental considerations.
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 Conservation Incentive Program (CIP) effective October 1, 2006, discussed in greater detail under Results of Operations, that protects our net income from reductions in gas used by our residential, commercial, and small industrial customers.
Weather Conditions and Customer Usage Patterns - Usage patterns can be affected by a number of factors, such as wind, precipitation, temperature extremes and customer conservation. Our earnings are largely protected from fluctuations in temperatures by the CIP, which superseded the Temperature Adjustment Clause (TAC), effective October 1, 2006. The CIP has a stabilizing effect on earnings as we adjust revenues when actual usage per customer experienced during an annual period varies from an established baseline usage per customer.
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. For the vast majority of our customers, the price for natural gas 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.
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 all issuances of new debt. We have sought to mitigate the impact of a potential rising rate environment 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. 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 had offered a voluntary separation program at the end of 2007. Our workforce totaled 383 employees at the end of 2008, with 67% of that total covered under collective bargaining agreements.
Balance Sheet Strength - Our goal is to maintain a strong balance sheet with an average annual equity-to-capitalization ratio of 46% to 50%. Our equity-to-capitalization ratio, inclusive of short-term debt, was 49.5% and 50.3% at the end of 2008 and 2007, respectively. A strong balance sheet permits us the financial flexibility necessary to address volatile economic and commodity markets while maintaining a low-risk platform.
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, derivatives, environmental remediation costs, pension and other postretirement 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 (BGSS) clause to forecast our natural gas costs and customer consumption in setting our rates. Subject to BPU approval, we are able to recover or return 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 charge to customers in subsequent years. We also enter into derivatives that are used to hedge natural gas purchases. The offset of the resulting derivative assets or liabilities is also recorded as a regulatory asset or liability on the balance sheets.
The Conservation Incentive Program (CIP) is a BPU approved three-year pilot program that began October 1, 2006, and is designed to eliminate the link between our profits and the quantity of natural gas we sell, and foster conservation efforts. With the CIP, our profits are tied to the number of customers we serve and how efficiently we serve them, thus allowing us to focus on encouraging conservation and energy efficiency among our customers without negatively impacting our net income. The CIP tracking mechanism adjusts earnings based on weather and also adjusts our earnings where actual usage per customer experienced during an annual period varies from an established baseline usage per customer. Utility earnings are recognized during current periods based upon the application of the CIP. The cash impact of variations in customer usage will result in cash being collected from, or returned to, customers during the subsequent CIP year, which runs from October 1 to September 30.
In addition to the BGSS and the CIP, other regulatory assets consist primarily of remediation costs associated with manufactured gas plant sites (discussed below under Environmental Remediation Costs), deferred pension and other postretirement benefit cost, and several other assets as detailed in Note 3 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.
Derivatives - We recognize assets or liabilities for 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. In 2007, we changed our policy to no longer designate energy-related derivative instruments as cash flow hedges. 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. Due to the application of regulatory accounting principles under FASB Statement No. 71, derivatives related to gas purchases that are marked-to-market are recorded through our BGSS. We periodically 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 Notes 2 and 3 to the financial statements). We adjust the fair value of the contracts each reporting period for changes in the market.
As discussed in Note 13 of the financial statements, energy-related derivative instruments are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy established by FAS 157. Certain non-exchange-based contracts are valued using indicative non-binding price quotations available through brokers or from over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. Management reviews and corroborates the price quotations with at least one additional source to ensure the prices are observable market information, which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. Derivative instruments that are used to limit our exposure to changes in interest rates on variable-rate, long-term debt are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment, as a result, these instruments are categorized in Level 2. For non-exchange-based derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. In instances where observable data is unavailable, management considers the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Counterparty credit risk, and the credit risk of SJG, is incorporated and considered in the valuation of all derivative instruments as appropriate. The effect of counterparty credit risk and the credit risk of SJG on the derivative valuations is not significant.
Environmental Remediation Costs - We estimate future costs based on projected investigation and work plans using existing technologies. 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 mortality, 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 and 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. In 2007, a 20 basis point increase in the discount rate and higher than expected returns on plan assets during 2006 resulted in a net decrease to benefit costs in 2007. Further, an additional 32 basis point increase in the discount rate, higher than expected returns on plan assets during 2007, and a pension contribution in the first quarter of 2008 further reduced such benefit costs in 2008. While the discount rate and expected return on plan assets are both decreasing slightly in the determination of the 2009 benefit costs, the primary cost driver in 2009 will be the erosion of plan assets during 2008. As evidenced by the tables in Note 11, “Pension and Other Postretirement Benefits,” the declines in the equity markets during 2008 have resulted in significant losses in the assets of the plans. Such losses are currently expected to increase the 2009 cost of providing such benefits two-to-three fold.
Revenue Recognition - Gas revenues are recognized in the period the commodity is delivered to customers. 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.
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 Notes 2 and 3 to the financial statements).
In October 2006, the BPU approved the Conservation Incentive Program (CIP) as a three-year pilot program. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, we make filings with the BPU to review and approve amounts recorded under the CIP. BPU approved cash inflows or outflows generally will not begin until the next CIP year and have no impact on earnings at that time.
New Accounting Pronouncements - See detailed discussions concerning New Accounting Pronouncements and their impact in Note 1 to the financial statements.
Rates and Regulation - As a public utility, we are 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 our business. We are affected by Federal regulation with respect to transportation and pricing policies applicable to pipeline capacity from Transcontinental Gas Pipeline Corporation (our major supplier), Columbia Gas Transmission Corporation, Columbia Gulf Transmission Company and Dominion Transmission, Inc., since such services are provided under rates and terms established under the jurisdiction of the FERC. Our retail sales 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. Our primary rate mechanisms include base rates, the Basic Gas Supply Service Clause, Temperature Adjustment Clause and Conservation Incentive Program.
Basic Gas Supply Service Clause (BGSS) - In December 2002, the BPU approved the BGSS price structure which gave customers 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. The cost of gas purchased from the utility by our periodic consumers is set annually by the BPU through a BGSS clause within our tariff. When actual gas costs experienced are less than those charged to customers under the 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, we are permitted to charge customers more for gas in future periods to recover the shortfall.
Temperature Adjustment Clause (TAC) - Through September 30, 2006, our tariff included a TAC to mitigate the effect of variations in heating season temperatures from historical norms. The TAC has since been replaced with the Conservation Incentive Program (discussed below). Each TAC year ran from November 1 through May 31 of the following year. Once the TAC year ended, the net earnings impact was filed with the BPU for future recovery. As a result, the cash inflows or outflows generally would not begin until the next TAC year. Because of the timing delay between the earnings impact and the recovery, the net result could be either a regulatory asset or liability.
Conservation Incentive Program (CIP) - The CIP is a BPU approved three-year pilot program that began October 1, 2006, and is designed to eliminate the link between our profits and the quantity of natural gas we sell, and foster conservation efforts. With the CIP, our profits are tied to the number of customers we serve and how efficiently we serve them, thus allowing us to focus on encouraging conservation and energy efficiency among our customers without negatively impacting our net income. The CIP tracking mechanism adjusts earnings based on weather, as did the TAC, and also adjusts our earnings when actual usage per customer experienced during an annual period varies from an established baseline usage per customer. Under the terms of the settlement, the CIP may be extended for a one year period in the absence of a Board order taking any affirmative action to the contrary with regard to the pilot program.
Similar to the TAC, utility earnings are recognized during current periods based upon the application of the CIP. The cash impact of variations in customer usage will result in cash being collected from, or returned to, customers during the subsequent CIP year, which runs from October 1 to September 30.
The effects of the TAC and the CIP on our net income for the last three years and the associated weather comparisons were as follows ($’s in millions):
| | | 2008 | | | 2007 | | | 2006 | |
| Net Income Benefit: | | | | | | | | | |
| TAC | | $ | - | | | $ | - | | | $ | 5.1 | |
| CIP – Weather Related | | | 1.6 | | | | 1.6 | | | | 2.9 | |
| CIP – Usage Related | | | 9.2 | | | | 5.9 | | | | 1.7 | |
| Total Net Income Benefit | | $ | 10.8 | | | $ | 7.5 | | | $ | 9.7 | |
| | | | | | | | | | | | | |
| Weather Compared to 20-Year TAC Average | | 4.7% warmer | | | 3.2% warmer | | | 15.0 % warmer | |
| Weather Compared to Prior Year | | 1.6% warmer | | | 13.8% colder | | | 17.5 % warmer | |
As part of the CIP, we are required to implement additional conservation programs including customized customer communication and outreach efforts, targeted upgrade furnace efficiency packages, financing offers, and an outreach program to speak to local and state institutional constituents. We are also required to reduce gas supply and storage assets and their associated fees. Note that changes in fees associated with supply and storage assets have no effect on our net income as these costs are passed through directly to customers on a dollar-for-dollar basis.
Earnings accrued and payments received under the CIP are limited to a level that will not cause our return on equity to exceed 10% (excluding earnings from off-system gas sales and certain other tariff clauses) and the annualized savings attained from reducing gas supply and storage assets.
Other Rate Mechanisms - - Our 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 from customers through our Societal Benefits Clause.
See additional detailed discussions on Rates and Regulatory Actions in Note 2 to the financial statements.
Environmental Remediation - See detailed discussion concerning Environment 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, with alternative fuel source providers (wind, solar and fuel cells) based upon price, convenience and environmental factors, and with other marketers/brokers in the selling of wholesale natural gas services. The market for natural gas commodity 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, 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 below).
Customer Choice Legislation - All residential natural gas customers in New Jersey can choose their natural gas commodity supplier under the terms of the “Electric Discount and Energy Competition Act of 1999.” 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. Customers purchasing natural gas from a provider other than the local utility (marketer) are charged for the gas costs by the marketer and charged for the transportation costs by the utility. The number of customers purchasing their natural gas from marketers averaged 28,637, 25,309, and 16,392 during 2008, 2007 and 2006, respectively.
RESULTS OF OPERATIONS:
The following table summarizes the composition of selected gas utility data for the three years ended December 31 (in thousands, except for customer and degree day data):
| | | 2008 | | | 2007 | | | 2006 | |
| Utility Throughput – dth: | | | | | | | | | | | | | | | | | | |
| Firm Sales - | | | | | | | | | | | | | | | | | | |
| Residential | | | 21,530 | | | | 15 | % | | | 22,523 | | | | 16 | % | | | 19,830 | | | | 15 | % |
| Commercial | | | 6,127 | | | | 4 | % | | | 6,339 | | | | 4 | % | | | 6,958 | | | | 5 | % |
| Industrial | | | 188 | | | | - | | | | 193 | | | | - | | | | 296 | | | | - | |
| Cogeneration and electric generation | | | 561 | | | | - | | | | 1,335 | | | | 1 | % | | | 1,103 | | | | 1 | % |
| Firm Transportation - | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 1,988 | | | | 1 | % | | | 1,870 | | | | 1 | % | | | 956 | | | | 1 | % |
| Commercial | | | 5,687 | | | | 4 | % | | | 5,927 | | | | 4 | % | | | 4,420 | | | | 3 | % |
| Industrial | | | 12,661 | | | | 9 | % | | | 12,107 | | | | 9 | % | | | 11,970 | | | | 9 | % |
| Cogeneration and electric generation | | | 2,536 | | | | 2 | % | | | 3,088 | | | | 2 | % | | | 2,625 | | | | 2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Firm Throughput | | | 51,278 | | | | 35 | % | | | 53,382 | | | | 37 | % | | | 48,158 | | | | 36 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Interruptible Sales | | | 35 | | | | - | | | | 68 | | | | - | | | | 93 | | | | - | |
| Interruptible Transportation | | | 2,716 | | | | 2 | % | | | 3,002 | | | | 2 | % | | | 3,474 | | | | 3 | % |
| Off-System | | | 9,632 | | | | 7 | % | | | 17,686 | | | | 13 | % | | | 18,221 | | | | 13 | % |
| Capacity Release | | | 80,665 | | | | 56 | % | | | 67,430 | | | | 48 | % | | | 66,458 | | | | 48 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Throughput | | | 144,326 | | | | 100 | % | | | 141,568 | | | | 100 | % | | | 136,404 | | | | 100 | % |
| Utility Operating Revenues: | | | | | | | | | | | | | | | | | | |
| Firm Sales- | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 320,401 | | | | 57 | % | | $ | 342,809 | | | | 54 | % | | $ | 334,201 | | | | 52 | % |
| Commercial | | | 81,914 | | | | 15 | % | | | 80,237 | | | | 13 | % | | | 99,578 | | | | 15 | % |
| Industrial | | | 5,434 | | | | 1 | % | | | 8,381 | | | | 1 | % | | | 6,590 | | | | 1 | % |
| Cogeneration and electric generation | | | 7,940 | | | | 1 | % | | | 11,722 | | | | 2 | % | | | 10,746 | | | | 2 | % |
| Firm Transportation - | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 10,408 | | | | 2 | % | | | 8,982 | | | | 1 | % | | | 4,768 | | | | 1 | % |
| Commercial | | | 18,286 | | | | 3 | % | | | 17,299 | | | | 3 | % | | | 12,510 | | | | 2 | % |
| Industrial | | | 12,504 | | | | 2 | % | | | 12,229 | | | | 2 | % | | | 11,351 | | | | 2 | % |
| Cogeneration and electric generation | | | 1,682 | | | | - | | | | 1,847 | | | | - | | | | 1,552 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Firm Revenues | | | 458,569 | | | | 81 | % | | | 483,506 | | | | 76 | % | | | 481,296 | | | | 75 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Interruptible Sales | | | 403 | | | | - | | | | 785 | | | | - | | | | 1,109 | | | | - | |
| Interruptible Transportation | | | 1,786 | | | | - | | | | 1,970 | | | | - | | | | 1,868 | | | | - | |
| Off-System | | | 90,430 | | | | 16 | % | | | 131,586 | | | | 22 | % | | | 147,180 | | | | 23 | % |
| Capacity Release | | | 15,549 | | | | 3 | % | | | 11,208 | | | | 2 | % | | | 9,656 | | | | 2 | % |
| Other | | | 1,309 | | | | - | | | | 1,492 | | | | - | | | | 1,562 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Utility Operating Revenues | | | 568,046 | | | | 100 | % | | | 630,547 | | | | 100 | % | | | 642,671 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of sales | | | 383,403 | | | | | | | | 453,034 | | | | | | | | 472,286 | | | | | |
| Conservation recoveries * | | | 7,741 | | | | | | | | 4,458 | | | | | | | | 6,862 | | | | | |
| RAC recoveries * | | | 3,079 | | | | | | | | 2,056 | | | | | | | | 1,807 | | | | | |
| Revenue taxes | | | 8,656 | | | | | | | | 8,850 | | | | | | | | 7,890 | | | | | |
| Utility Margin | | $ | 165,167 | | | | | | | $ | 162,149 | | | | | | | $ | 153,826 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Margin: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 99,862 | | | | 61 | % | | $ | 102,077 | | | | 63 | % | | $ | 90,442 | | | | 59 | % |
| Commercial and industrial | | | 38,995 | | | | 24 | % | | | 40,036 | | | | 25 | % | | | 38,129 | | | | 25 | % |
| Cogeneration and electric generation | | | 1,997 | | | | 1 | % | | | 2,212 | | | | 1 | % | | | 2,189 | | | | 1 | % |
| Interruptible | | | 143 | | | | - | | | | 195 | | | | - | | | | 226 | | | | - | |
| Off-system & capacity release | | | 3,349 | | | | 2 | % | | | 2,994 | | | | 2 | % | | | 4,711 | | | | 3 | % |
| Other revenues | | | 2,440 | | | | 1 | % | | | 1,952 | | | | 1 | % | | | 1,871 | | | | 1 | % |
| Margin before weather normalization & decoupling | | | 146,786 | | | | 89 | % | | | 149,466 | | | | 92 | % | | | 137,568 | | | | 89 | % |
| TAC mechanism | | | - | | | | - | | | | - | | | | - | | | | 8,511 | | | | 6 | |
| CIP mechanism | | | 18,381 | | | | 11 | % | | | 12,683 | | | | 8 | % | | | 7,747 | | | | 5 | |
| Utility Margin | | $ | 165,167 | | | | 100 | % | | $ | 162,149 | | | | 100 | % | | $ | 153,826 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Customers at Year End: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 317,026 | | | | 93 | % | | | 312,969 | | | | 93 | % | | | 307,919 | | | | 93 | % |
| Commercial | | | 22,636 | | | | 7 | % | | | 22,220 | | | | 7 | % | | | 21,652 | | | | 7 | % |
| Industrial | | | 474 | | | | - | | | | 474 | | | | - | | | | 478 | | | | - | |
| Total Customers | | | 340,136 | | | | 100 | % | | | 335,663 | | | | 100 | % | | | 330,049 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Annual Degree Days: | | | 4,417 | | | | | | | | 4,488 | | | | | | | | 3,943 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| * Represents expenses for which there is a corresponding credit in operating revenues. Therefore, such recoveries have no impact on our financial results. | |
Throughput - - Total gas throughput increased 2.8 MMdts, or 1.9%, from 2007 to 2008. This increase is driven by greater capacity release activity during 2008. Firm throughput declined as a result of warmer weather, as reflected by the degree day data in the table above, and customer conservation. Off-System sales (OSS) volume decreased substantially as SJG’s portfolio of assets available for such activities has been reduced under the CIP, as discussed under “Rates and Regulation”. In 2007, total gas throughput increased 3.8% compared with 2006, to 141.6 MMdth. While firm throughput accounted for the entire increase, the residential market reflected the greatest improvement by adding 3.6 MMdth over 2006 as a result of 23.3% colder weather and 5,050 additional residential customers in 2007.
Operating Revenues – Revenues decreased $62.5 million, or 9.9%, during 2008 compared with 2007. Off-System sales (OSS) revenue decreased $41.2 million in relation to the decrease in sales volume noted above under “Throughput”. As previously discussed, SJG’s portfolio of assets available for OSS has been reduced under the CIP. Total firm revenues decreased during 2008 compared to the same period in the prior year primarily due to warmer weather and lower residential revenues resulting from a lower Basic Gas Supply Service (BGSS) rate in effect during most of 2008. For nearly the entire year, the 2008 BGSS rate was 12.7% lower than the rate in effect during the same time last year. SJG reduced its BGSS rate in October 2007 primarily due to a combination of actual and forecasted decreases in wholesale gas costs. However, as the Company does not profit from the sale of the commodity the BGSS rate decrease did not have an impact on Company profitability. Finally, the Company experienced lower sales to the region’s electric utility, as their demand to consume natural gas to generate electric during the summer months decreased substantially. Since the majority of the Company’s profits from electric generation sales are contractually fixed, the decrease in volume and revenue had little impact on profitability. Partially offsetting these decreases, SJG added 4,473 customers during the 12-month period ended December 31 2008, which represents a 1.3% increase in total customers.
Revenues decreased $12.1 million during 2007, compared with 2006, primarily due to lower Off-System sales revenue. Despite comparable sales volume, Off-System sales revenue decreased substantially. Sales revenue during the early part of 2006 was atypically high as it reflected unusually high commodity prices, which were driven by hurricane related production disruptions in fall 2005. In addition, OSS recognized a $4.4 million gain on a financial derivative position in 2006 which did not re-occur in 2007 due to changing market conditions. It should be noted that this $4.4 million gain only contributed $0.4 million to SJG’s bottom line after regulated sharing of 85% with ratepayers through the BGSS and taxes.
While SJG added 5,614 customers during the 12-month period ended December 31, 2007, which represents a 1.7% increase in total customers, and weather was 23.3% colder than last year, firm sales revenue only experienced a modest increase of $2.2 million as a result of a decrease in the BGSS gas cost recovery rate and customer migration from firm sales to firm transportation service. The BGSS rate in 2007 was 10.8% lower than the prior year rate. The rate in 2006 was higher to address under recovery of gas costs stemming from substantial increases in wholesale gas prices across the country in 2005. In addition, the average number of transportation customers increased to 25,309 in 2007 as compared to 16,392 in 2006. Transportation customers generate less revenue for the Company because they purchase the gas commodity from a third party marketer. However, as the Company does not profit from the sale of the commodity, neither BGSS rate changes nor customer migration between sales and transportation have an impact on Company profitability.
Margin - Our margin is defined as natural gas revenues less natural gas costs; volumetric and revenue based energy taxes; and regulatory rider expenses. We believe that margin provides a more meaningful basis for evaluating utility operations than revenues since natural gas costs, energy taxes and regulatory rider expenses are passed through to customers, and therefore, have no effect on our profitability. Natural gas costs are charged to operating expenses on the basis of therm sales at the prices approved by the New Jersey Board of Public Utilities through our BGSS tariff.
Total margin in 2008 increased $3.0 million, or 1.9%, from 2007 primarily due to customer additions, as noted above, increased margins from OSS and capacity release, and increased profits earned through the Company’s Storage Incentive Mechanism (SIM). The SIM allows the Company to retain 20% of storage-related gains and losses as measured against an established benchmark. The balance of these gains and losses are passed through to customers as part of the BGSS.
The CIP protected $18.4 million of pre-tax margin in 2008 that would have been lost due to lower customer usage, compared to $12.7 million in 2007. Of these amounts, $2.7 million and $2.6 million were related to weather variations and $15.7 million and $10.1 million were related to other customer usage variations in 2008 and 2007, respectively.
Total margin in 2007 increased $8.3 million from 2006 primarily due to customer additions and the positive impact from a full year of the usage related component of the CIP. As previously discussed, the CIP mechanism replaced the TAC effective October 1, 2006 and takes into account variations in customer usage factors due to weather as well as all other variations. The usage related component of the CIP added $10.1 million to margin in 2007 as compared to $2.8 million for 2006, as the CIP was only in effect during the fourth quarter of 2006. Customer additions and temperatures that were much closer to normal in 2007 versus 2006 increased margins in the both the Residential and Commercial classes. However, due to the colder weather in 2007, the weather related component of the CIP generated less of a contribution to margin, since SJG had already benefited from the higher sales volume as reflected in the margin table above. Partially offsetting the positive impacts noted above were lower margins from OSS and capacity release. Margin declined in these markets due to less favorable market conditions, primarily in the first quarter of 2007, and a decrease in the percentage of earnings from these sales retained by the Company in accordance with a July 2004 base rate case stipulation. Through July 1, 2006, the Company retained 20% of margins generated by OSS and related activities. Since then the Company is only permitted to retain 15% of such margins.
Operating Expenses - A summary of changes in other operating expenses (in thousands):
| | | 2008 vs. 2007 | | | 2007 vs. 2006 | |
| | | | | | | |
| Operations | | $ | 4,375 | | | $ | 1,745 | |
| Maintenance | | | 1,554 | | | | 807 | |
| Depreciation | | | 975 | | | | 1,106 | |
| Energy and Other Taxes | | | (202 | ) | | | 690 | |
Operations – Operations expense increased $4.4 million during 2008, as compared with 2007. The increases are primarily comprised of the following factors.
First, our spending under the New Jersey Clean Energy Program (NJCEP) increased $3.3 million during 2008 compared to last year. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting increase in revenues during the period. The BPU-approved NJCEP allows for full recovery of costs, including carrying costs when applicable. As a result, the increase in expense had no impact on our net income. Second, corporate support, governance and compliance costs, primarily attributable to our parent, SJI, rose $0.9 million during 2008. Finally the Company also experienced moderate increases in insurance and employee compensation costs; however, these were offset by lower pension and other cost reductions during the year 2008.
Operations expense increased $1.7 million during 2007, as compared with 2006. The increase is primarily comprised of several factors. Expense associated with the Provision for Uncollectibles increased $1.2 million due to higher levels of customer account receivables in 2007 than in 2006. In 2007 the Provision for Uncollectibles had increased $0.5 million in comparison with a decrease of $0.7 million in 2006 as a result of annual fluctuations in customer account receivable balances. Corporate support, governance and compliance costs, primarily attributable to our parent, SJI, also rose $1.1 million as a result of various studies and initiatives undertaken by the Company. Additional factors for the increase include $0.3 million for billing and collection costs including a federal postage rate increase; $0.2 million in employee severance costs that were not incurred during 2006; $0.3 million in Conservation Incentive Program (CIP) expenses that did not begin to be incurred until the approval of the CIP in October 2006; $0.3 million increase in sales expense primarily related to a customer conversion program aimed at converting residential consumers to natural gas heating systems; and higher employee compensation costs.
Partially offsetting the increase above was a $2.4 million decrease in 2007 in our costs under the New Jersey Clean Energy Programs (NJCEP), which had decreased as the Company was transitioning the management of the plans to State agencies. During this time of transition, a temporary slowdown in spending was experienced. As previously noted, such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting decrease in revenue during 2007.
Maintenance – Maintenance expense increased $1.6 million during 2008, compared with 2007, primarily due to a $1.2 million increase in Remediation Adjustment Clause (RAC) expense amortization. As discussed in Notes 2 and 3 to the Financial Statements, these costs are recovered from ratepayers; therefore, SJG experienced an offsetting increase in revenue during 2008. The remaining increase was the result of installing safety devices on certain residential meters aimed at preventing unauthorized usage and maintenance of company equipment.
Maintenance expense increased $0.8 million during 2007, compared with 2006, primarily due to a $0.5 million increase in environmental remediations expense amortization. An additional $0.3 million increase resulted from incremental maintenance requirements of our LNG and distribution plant, including BPU mandated meter protection surveys to ensure public safety.
Depreciation - Depreciation expense increased $1.0 million and $1.1 million in 2008 and 2007, respectively, due mainly to our continuing investment in utility plant. SJG’s investment in utility plant during 2008, 2007 and 2006 was $52.6 million, $48.1 million and $61.4 million, respectively.
Energy and Other Taxes – Energy and Other Taxes decreased $0.2 million during 2008, compared with 2007, primarily due to lower energy-related taxes. Lower taxable firm throughput in 2008 resulted from warmer weather and conservation, as previously discussed. These factors were partially offset by customer growth in 2008.
Energy and Other Taxes increased in 2007, compared with 2006, primarily due to higher energy-related taxes based on increased taxable firm throughput in 2007. Higher taxable firm throughput in 2007 resulted from colder weather and customer growth in 2007.
Other Income and Expense - Other income and expense decreased in 2008, compared with both 2007 and 2006, primarily as a result of the poor earnings performance of our available-for-sale securities over prior years. Due to the significant declines in the equity markets in 2008, income generated by our available-for-sale securities decreased $0.7 million and $0.6 million when compared to 2007 and 2006, respectively. In addition, the Company recognized an impairment loss of $0.7 million during 2008. No impairment losses were recognized in 2007 or 2006. These securities represent assets held in trusts for the payment of postretirement healthcare costs.
Interest Charges – Interest charges decreased by $2.0 million for 2008, compared with 2007. The decrease was the result of lower average short-term interest rates and debt levels, partially offset by higher interest rates incurred on auction-rate securities during the first half of 2008.
Interest charges decreased by $1.1 million in 2007, compared with 2006, due primarily to lower average levels of short-term debt. Short-term debt levels declined primarily due to lower gas cost and inventory levels, which offset the impact of higher average short-term interest rates for the full year.
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.
Cash Flows from Operating Activities - Cash generated from operating activities constitutes our primary source of liquidity and varies from year-to-year due to the impact of weather on customer demand and related gas purchases, customer usage factors related to conservation efforts and the price of the natural gas commodity, inventory utilization and recoveries provided through our various rate mechanisms. Net cash provided by operating activities was $30.3 million in 2008, $89.4 million in 2007 and $50.7 million in 2006.
Cash provided by operating activities decreased in 2008, as compared with 2007, primarily as a result of higher unit gas costs and the impact of those costs on natural gas inventory balances. Further, in anticipation of a large transmission pipeline project in 2009, SJG purchased and inventoried $9.3 million of pipe at the end of 2008. SJG also incurred significantly higher, planned environmental remediation costs in 2008 compared to the prior year. Finally, SJG made a $4.8 million pension contribution during 2008. No such contribution was made in the prior year.
Cash provided by operating activities increased in 2007, as compared with 2006, primarily as a result of the accounts payable pattern in 2007 not having a high carry-over balance from the prior year end. Net cash provided by operating activities in 2006 was negatively impacted by higher unit gas costs following hurricane Katrina and the impact of those costs on inventory and accounts payable balances at the end of 2005. In addition, SJG had deferred the payment of $16.0 million for gas delivered to storage during 2005 until the first quarter of 2006, further increasing the year-end 2005 accounts payable balance. We did not enter into similar supply arrangements during the 2006 or 2007 injection seasons. Therefore, 2007 results do not reflect any payments related to 2006 storage injections or accounts payable at year-end related to 2007 storage injections.
Cash Flows from Investing Activities - We have a continuing need for cash resources for capital purchases, primarily to invest in new and replacement facilities and equipment. Cash used for capital purchases was $52.6 million and $48.1 million in 2008 and 2007, respectively, primarily due to infrastructure improvements that continue to support SJG’s growth.
Cash Flows from Financing Activities - 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. 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. In June 2008, SJG repurchased $25.0 million of its auction-rate securities at par by drawing under its lines of credit. That action resulted in a $25.0 million reduction in long-term debt on SJG’s balance sheet. SJG converted these auction-rate securities to variable-rate demand bonds and remarketed them to the public during the third quarter of 2008. No other long-term debt was issued during 2008.
Bank credit available to SJG totaled $203.0 million at December 31, 2008, of which $114.6 million was used. Those bank facilities consist of a $100.0 million revolving credit facility, a $40.0 million line of credit, a $10.0 million line of credit and $53.0 million of uncommitted bank lines. The revolving credit facility expires in August 2011 and both lines of credit expire in 2009. All facilities contain one financial covenant regarding the ratio of total debt to total capitalization, measured on a quarterly basis. SJG was in compliance with these covenants as of December 31, 2008. Based upon the existing credit facilities and a regular dialogue 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. We repaid long-term debt totaling $25.0 million, $2.3 million and $2.3 million in 2008, 2007 and 2006, respectively. The $25.0 million repayment in 2008 reflects the conversion of auction-rate bonds to variable-rate demand bonds which are carried as current.
SJI contributed no capital to us in 2008, 2007 or 2006.
As of December 31, our capital structure was as follows:
| | | 2008 | | | 2007 | |
| | | | | | | |
| Common Equity | | | 49.5 | % | | | 50.3 | % |
| Long-Term Debt | | | 36.4 | % | | | 39.3 | % |
| Short-Term Debt | | | 14.1 | % | | | 10.4 | % |
| | | | | | | | | |
| Total | | | 100.0 | % | | | 100.0 | % |
Our long-term, senior secured debt was rated “A” and “Baa1” by Standard & Poor’s and Moody’s Investor Services, respectively. These ratings had not changed in at least the past five years until February 2009 when Moody’s Investor Services raised SJG’s senior secured rating to “A3” from “Baal”.
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 $289.2 million. Our total common equity balance was $401.7 million at December 31, 2008.
COMMITMENTS AND CONTINGENCIES:
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 2008 amounted to $52.6 million and $26.2 million, respectively. We estimate total cash outflows for construction and remediation projects for 2009, 2010 and 2011, to be approximately $143.0 million, $104.4 million and $68.7 million, respectively. As discussed in Notes 3 and 12 to the financial statements, certain environmental costs are subject to recovery from insurance carriers and ratepayers.
STANDBY LETTER OF CREDIT - SJG provided a $25.3 million letter of credit, under a separate credit facility from those it borrows under to provide liquidity support for the remarketing of variable-rate demand bonds issued through the NJEDA. The bonds were used to finance the expansion of SJG’s natural gas distribution system as discussed in Note 7 to the financial statements. This letter of credit expires in August 2009.
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, 2008, average $45.1 million annually and total $157.0 million over the contracts’ lives. Approximately 46% of the financial commitments under these contracts expire 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, 2008 (in thousands):
| | | | | | Up to | | | Years | | | Years | | | More than | |
| Contractual Cash Obligations | | Total | | | 1 Year | | | 2 & 3 | | | 4 & 5 | | | 5 Years | |
| | | | | | | | | | | | | | | | |
| Principal Payments on Long-Term Debt | | $ | 294,873 | | | $ | 25,000 | | | $ | 35,000 | | | $ | 29,375 | | | $ | 205,498 | |
| Interest on Long-Term Debt | | | 200,643 | | | | 16,993 | | | | 33,375 | | | | 29,107 | | | | 121,168 | |
| Operating Leases | | | 141 | | | | 70 | | | | 71 | | | | - | | | | - | |
| Construction Obligations | | | 872 | | | | 872 | | | | - | | | | - | | | | - | |
| Commodity Supply Purchase Obligations | | | 156,986 | | | | 43,869 | | | | 39,758 | | | | 18,642 | | | | 54,717 | |
| New Jersey Clean Energy Program (Note 2) | | | 41,760 | | | | 8,643 | | | | 20,139 | | | | 12,978 | | | | - | |
| Other Purchase Obligations | | | 269 | | | | 269 | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Contractual Cash Obligations | | $ | 695,544 | | | $ | 95,716 | | | $ | 128,343 | | | $ | 90,102 | | | $ | 381,383 | |
As discussed in Note 7 to the financial statements, SJG’s variable-rate debt of $25.0 million has been included in the current portion of long-term debt above. However, interest on long-term debt in the table above includes the related interest obligations through maturity, as well as the impact of the related interest rate swap agreements on this variable-rate debt.
Expected environmental remediation costs and asset retirement obligations are not included in the table above as the total obligation cannot be calculated due to the subjective nature of these costs and timing of anticipated payments. While SJG has no obligation to make a contribution to its employee pension plans in 2009, we currently expect to make a contribution in order to improve the funded status of the plans and mitigate the expected increase in expense in 2009. Furthermore, future pension contributions beyond 2009 cannot be determined at this time. Our regulatory obligation to contribute $3.6 million annually to our postretirement benefit plans’ trusts, as discussed in Note 11 to the financial statements, is also not included as its 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.
Item 7a. Quantitative and Qualitative Disclosures about Market Risks
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. South Jersey Resources Group, LLC, 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 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. As a result of holding open positions to a minimal level, the economic impact of changes in value of a particular transaction is substantially offset by an opposite change in the related hedge transaction. 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 using mark-to-market accounting as of December 31, 2008 is as follows (in thousands):
| Assets: | | | Maturity | | | Maturity | | | | |
| | Source of Fair Value | | <1 Year | | | 1 - 3 Years | | | Total | |
| | | | | | | | | | | |
| Prices Actively Quoted | NYMEX | | $ | 345 | | | $ | 15 | | | $ | 360 | |
| Other External Sources | Basis | | | 35 | | | | - | | | | 35 | |
| Total | | | $ | 380 | | | $ | 15 | | | $ | 395 | |
| | | | | | | | | | | | | | |
| Liabilities: | | | Maturity | | | Maturity | | | | | |
| | Source of Fair Value | | <1 Year | | | 1 - 3 Years | | | Total | |
| | | | | | | | | | | | | | |
| Prices Actively Quoted | NYMEX | | $ | 26,178 | | | $ | 2,667 | | | $ | 28,845 | |
| Other External Sources | Basis | | | 520 | | | | - | | | | 520 | |
| Total | | | $ | 26,698 | | | $ | 2,667 | | | $ | 29,365 | |
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 contracts are 13.6 MMdts with a weighted-average settlement price of $7.80 per dt. Contracted volumes of our Basis contracts are 5.3 MMdts with a weighted-average settlement price of $1.42 per dt.
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, 2008 | | $ | (2,092 | ) |
| Contracts Settled During 2008, Net | | | 2,224 | |
| Other Changes in Fair Value from Continuing and New Contracts, Net | | | (29,102 | ) |
| Net Derivatives — Energy Related Liability, December 31, 2008 | | $ | (28,970 | ) |
The change in our derivative position from a $2.1 million liability at December 31, 2007 to a $29.0 million liability at December 31, 2008 is primarily due to the change in value of our financial positions held with SJRG. As of December 31, 2007 the average future price was approximately $7.68 per dt vs. $6.15 per dt as of December 31, 2008. The decrease in prices has resulted in a decline in the market value of these financial contracts. Further, SJG entered into additional contracts during 2008 which also experienced a similar decline in value during the year. However, the ultimate risk management objective of locking in the price of a portion of our future gas purchases, regardless of future fluctuations in the market price, has been met.
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, 2008, was $114.6 million and averaged $69.5 million during 2008. The months where average outstanding variable-rate debt was at its highest and lowest levels were December, at $116.6 million, and April, at $11.6 million. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $410,000 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: 2008 - 317 b.p. decrease; 2007 – 36 b.p. decrease; 2006 - 72 b.p. increase; 2005 - 191 b.p. increase; and 2004 - 115 b.p. increase. As of December 31, 2008, our average borrowing cost, which changes daily, was 1.06%.
We issue long-term debt either at fixed rates or use interest rate derivatives to limit our exposure to changes in interest rates on variable-rate, long-term debt. As of December 31, 2008, the interest costs on all of our long-term debt was either at a fixed-rate or hedged via an interest rate derivative. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates. However, due to general market conditions during 2008, the demand for auction-rate securities was disrupted resulting in increased interest rate volatility for tax-exempt auction-rate debt. As a result, the $25.0 million of tax-exempt auction-rate debt issued by the Company (and repurchased in June 2008) was exposed to changes in interest rates that were not completely mitigated by the related interest rate derivatives. The auction-rate debt was converted to another form of variable- rate debt and resold in the public market in August 2008. The original interest rate derivatives remain in place and are expected to substantially offset changes in interest rates on the security.
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
Folsom, New Jersey
We have audited the accompanying balance sheets of South Jersey Gas Company (the "Company") as of December 31, 2008 and 2007, 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, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a)2. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 6 to the financial statements, in 2007 the Company changed its method of accounting for income taxes to conform to FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.
/s/ DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
March 2, 2009
| SOUTH JERSEY GAS COMPANY | |
| STATEMENTS OF INCOME | |
| (In Thousands) | |
| | | Year Ended December 31, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | |
| Operating Revenues | | $ | 568,046 | | | $ | 630,547 | | | $ | 642,671 | |
| | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | |
| Cost of Sales (Excluding depreciation) | | | 383,403 | | | | 453,034 | | | | 472,286 | |
| Operations | | | 56,111 | | | | 51,736 | | | | 49,991 | |
| Maintenance | | | 7,899 | | | | 6,345 | | | | 5,538 | |
| Depreciation | | | 25,589 | | | | 24,614 | | | | 23,508 | |
| Energy and Other Taxes | | | 10,627 | | | | 10,829 | | | | 10,139 | |
| | | | | | | | | | | | | |
| Total Operating Expenses | | | 483,629 | | | | 546,558 | | | | 561,462 | |
| | | | | | | | | | | | | |
| Operating Income | | | 84,417 | | | | 83,989 | | | | 81,209 | |
| | | | | | | | | | | | | |
| Other Income and Expense | | | 459 | | | | 1,673 | | | | 1,480 | |
| | | | | | | | | | | | | |
| Interest Charges | | | (18,937 | ) | | | (20,985 | ) | | | (22,099 | ) |
| | | | | | | | | | | | | |
| Income Before Income Taxes | | | 65,939 | | | | 64,677 | | | | 60,590 | |
| | | | | | | | | | | | | |
| Income Taxes | | | (26,508 | ) | | | (26,652 | ) | | | (24,811 | ) |
| | | | | | | | | | | | | |
| Net Income | | $ | 39,431 | | | $ | 38,025 | | | $ | 35,779 | |
| | | | | | | | | | | | | |
| 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, | |
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | |
| Cash Flows from Operating Activities: | | | | | | | | | |
| Net Income | | $ | 39,431 | | | $ | 38,025 | | | $ | 35,779 | |
| Provided by Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 31,506 | | | | 29,317 | | | | 28,140 | |
| Provision for Losses on Accounts Receivable | | | 2,281 | | | | 2,672 | | | | 1,284 | |
| TAC/CIP Receivable | | | 2,641 | | | | (7,946 | ) | | | (15,740 | ) |
| Deferred Gas Costs - Net of Recoveries | | | 5,885 | | | | 7,755 | | | | 18,694 | |
| Deferred SBC Costs - Net of Recoveries | | | 1,199 | | | | 3,960 | | | | (4,221 | ) |
| Environmental Remediation Costs - Net of Recoveries | | | (26,177 | ) | | | (10,926 | ) | | | (10,840 | ) |
| Deferred and Noncurrent Income Taxes and Credits - Net | | | 21,378 | | | | 12,957 | | | | 4,426 | |
| Gas Plant Cost of Removal | | | (1,463 | ) | | | (1,275 | ) | | | (1,369 | ) |
| Changes in: | | | | | | | | | | | | |
| Accounts Receivable | | | (4,531 | ) | | | (8,528 | ) | | | 9,658 | |
| Inventories | | | (18,659 | ) | | | 24,884 | | | | 11,099 | |
| Prepaid and Accrued Taxes - Net | | | (1,657 | ) | | | (2,099 | ) | | | 4,997 | |
| Other Prepayments and Current Assets | | | (138 | ) | | | (14 | ) | | | 594 | |
| Gas Purchases Payable | | | 1,717 | | | | (8,817 | ) | | | (40,270 | ) |
| Accounts Payable and Other Accrued Liabilities | | | (13,857 | ) | | | 9,787 | | | | 11,605 | |
| Other Assets | | | (375 | ) | | | (121 | ) | | | 1,978 | |
| Other Liabilities | | | (8,920 | ) | | | (272 | ) | | | (5,120 | ) |
| | | | | | | | | | | | | |
| Net Cash Provided by Operating Activities | | | 30,261 | | | | 89,359 | | | | 50,694 | |
| | | | | | | | | | | | | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | |
| Capital Expenditures | | | (52,580 | ) | | | (48,070 | ) | | | (61,440 | ) |
| Investment in Long-Term Receivables | | | (5,558 | ) | | | (4,123 | ) | | | (3,342 | ) |
| Proceeds from Long-Term Receivables | | | 3,399 | | | | 3,877 | | | | 3,707 | |
| Purchase of Restricted Investment with Escrowed Loan Proceeds | | | (39 | ) | | | (363 | ) | | | (14,661 | ) |
| Proceeds from Sale of Restricted Investment from Escrowed Loan Proceeds | | | 2,146 | | | | 6,710 | | | | 6,075 | |
| | | | | | | | | | | | | |
| Net Cash Used in Investing Activities | | | (52,632 | ) | | | (41,969 | ) | | | (69,661 | ) |
| | | | | | | | | | | | | |
| Cash Flows from Financing Activities: | | | | | | | | | | | | |
| Net Borrowing from (Repayments of) Lines of Credit | | | 36,210 | | | | (25,160 | ) | | | 16,500 | |
| Proceeds from Issuance of Long-Term Debt | | | 25,000 | | | | - | | | | 25,000 | |
| Principal Repayments of Long-Term Debt | | | (25,000 | ) | | �� | (2,290 | ) | | | (2,345 | ) |
| Dividends on Common Stock | | | (14,867 | ) | | | (18,732 | ) | | | (19,902 | ) |
| Payments for Issuance of Long-Term Debt | | | (320 | ) | | | - | | | | (1,051 | ) |
| Excess Tax Benefit from Restricted Stock Plan | | | 346 | | | | 55 | | | | 181 | |
| | | | | | | | | | | | | |
| Net Cash Provided by (Used in) Financing Activities | | | 21,369 | | | | (46,127 | ) | | | 18,383 | |
| | | | | | | | | | | | | |
| Net (Decrease) Increase in Cash and Cash Equivalents | | | (1,002 | ) | | | 1,263 | | | | (584 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 3,230 | | | | 1,967 | | | | 2,551 | |
| | | | | | | | | | | | | |
| Cash and Cash Equivalents at End of Period | | $ | 2,228 | | | $ | 3,230 | | | $ | 1,967 | |
| | | | | | | | | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Interest (Net of Amounts Applicable to Gas Cost | | | | | | | | | | | | |
| Overcollections and Amounts Capitalized) | | $ | 19,550 | | | $ | 20,863 | | | $ | 21,832 | |
| Income Taxes (Net of Refunds) | | $ | 7,315 | | | $ | 15,684 | | | $ | 11,309 | |
| | | | | | | | | | | | | |
| Supplemental Disclosures of Noncash Investing Activities: | | | | | | | | | | | | |
| Capital property and equipment acquired on | | | | | | | | | | | | |
| account but not paid at year-end | | $ | 7,590 | | | $ | 4,182 | | | $ | 2,819 | |
| | | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | | | |
| SOUTH JERSEY GAS COMPANY | |
| BALANCE SHEETS | |
| (In Thousands) | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| Assets | | | | | | |
| | | | | | | |
| Property, Plant and Equipment: | | | | | | |
| Utility Plant, at original cost | | $ | 1,172,014 | | | $ | 1,123,992 | |
| Accumulated Depreciation | | | (295,432 | ) | | | (276,301 | ) |
| | | | | | | | | |
| Property, Plant and Equipment – Net | | | 876,582 | | | | 847,691 | |
| | | | | | | | | |
| Investments: | | | | | | | | |
| Available-for-Sale Securities | | | 4,841 | | | | 6,714 | |
| Restricted Investments | | | 132 | | | | 2,239 | |
| | | | | | | | | |
| Total Investments | | | 4,973 | | | | 8,953 | |
| | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and Cash Equivalents | | | 2,228 | | | | 3,230 | |
| Accounts Receivable | | | 47,787 | | | | 48,984 | |
| Accounts Receivable - Related Parties | | | 624 | | | | 2,267 | |
| Unbilled Revenues | | | 48,225 | | | | 41,576 | |
| Provision for Uncollectibles | | | (3,628 | ) | | | (3,265 | ) |
| Natural Gas in Storage, average cost | | | 65,252 | | | | 56,404 | |
| Materials and Supplies, average cost | | | 11,247 | | | | 1,436 | |
| Prepaid Taxes | | | 11,860 | | | | 10,849 | |
| Derivatives - Energy Related Assets | | | 380 | | | | 2,236 | |
| Other Prepayments and Current Assets | | | 2,416 | | | | 2,278 | |
| | | | | | | | | |
| Total Current Assets | | | 186,391 | | | | 165,995 | |
| | | | | | | | | |
| Regulatory and Other Noncurrent Assets: | | | | | | | | |
| Regulatory Assets | | | 270,434 | | | | 188,688 | |
| Unamortized Debt Issuance Costs | | | 6,147 | | | | 6,307 | |
| Prepaid Pension | | | - | | | | 1,472 | |
| Long-Term Receivables | | | 7,081 | | | | 6,118 | |
| Derivatives - Energy Related Assets | | | 15 | | | | 93 | |
| Other | | | 2,392 | | | | 1,845 | |
| | | | | | | | | |
| Total Regulatory and Other Noncurrent Assets | | | 286,069 | | | | 204,523 | |
| | | | | | | | | |
| Total Assets | | $ | 1,354,015 | | | $ | 1,227,162 | |
| | | | | | | | | |
The accompanying notes are an integral part of the financial statements. | | | | | |
| SOUTH JERSEY GAS COMPANY | |
| BALANCE SHEETS | |
| (In Thousands, except for share data) | |
| | | | |
| | | December 31, | |
| | | 2008 | | | 2007 | |
| | | | | | | |
| 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 | | | 200,663 | | | | 200,317 | |
| Accumulated Other Comprehensive Loss | | | (6,875 | ) | | | (5,356 | ) |
| Retained Earnings | | | 202,103 | | | | 177,539 | |
| | | | | | | | | |
| Total Common Equity | | | 401,739 | | | | 378,348 | |
| | | | | | | | | |
| Long-Term Debt | | | 269,873 | | | | 294,873 | |
| | | | | | | | | |
| Total Capitalization | | | 671,612 | | | | 673,221 | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Notes Payable | | | 114,550 | | | | 78,340 | |
| Current Portion of Long-Term Debt | | | 25,000 | | | | - | |
| Accounts Payable – Commodity | | | 36,587 | | | | 34,870 | |
| Accounts Payable – Other | | | 12,051 | | | | 13,650 | |
| Accounts Payable - Related Parties | | | 16,744 | | | | 22,417 | |
| Derivatives - Energy Related Liabilities | | | 26,698 | | | | 4,360 | |
| Deferred Income Taxes – Net | | | 12,475 | | | | 11,582 | |
| Customer Deposits and Credit Balances | | | 14,219 | | | | 18,067 | |
| Environmental Remediation Costs | | | 13,117 | | | | 25,447 | |
| Taxes Accrued | | | 2,291 | | | | 2,937 | |
| Pension Benefits | | | 991 | | | | 765 | |
| Interest Accrued | | | 6,244 | | | | 6,245 | |
| Other Current Liabilities | | | 6,449 | | | | 5,777 | |
| | | | | | | | | |
| Total Current Liabilities | | | 287,416 | | | | 224,457 | |
| | | | | | | | | |
| Regulatory and Other Noncurrent Liabilities: | | | | | | | | |
| Regulatory Liabilities | | | 50,447 | | | | 55,779 | |
| Deferred Income Taxes – Net | | | 187,050 | | | | 168,254 | |
| Environmental Remediation Costs | | | 50,976 | | | | 48,433 | |
| Asset Retirement Obligations | | | 22,299 | | | | 24,364 | |
| Pension and Other Postretirement Benefits | | | 67,566 | | | | 24,682 | |
| Investment Tax Credits | | | 1,832 | | | | 2,149 | |
| Derivatives - Energy Related Liabilities | | | 2,667 | | | | 61 | |
| Derivatives – Other | | | 7,578 | | | | 618 | |
| Other | | | 4,572 | | | | 5,144 | |
| | | | | | | | | |
| Total Regulatory and Other Noncurrent Liabilities | | | 394,987 | | | | 329,484 | |
| | | | | | | | | |
| Commitments and Contingencies (Note 12) | | | | | | | | |
| | | | | | | | | |
| Total Capitalization and Liabilities | | $ | 1,354,015 | | | $ | 1,227,162 | |
| | | | | | | | | |
| 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) | |
| | | | | | | | | | | | | | | | |
| | | Common Stock | | | Other Paid-In Capital and Premium on Common Stock | | | Accumulated Other Comprehensive Loss | | | Retained Earnings | | | Total | |
| | | | | | | | | | | | | | | | |
| Balance at January 1, 2006 | | $ | 5,848 | | | $ | 200,317 | | | $ | (4,337 | ) | | $ | 142,740 | | | $ | 344,568 | |
| Net Income | | | | | | | | | | | | | | | 35,779 | | | | 35,779 | |
| Other Comprehensive Income (Loss), Net of Tax: (a) | | | | | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | | | | | | | | | (442 | ) | | | | | | | (442 | ) |
| Unrealized Gain on Available-for-Sale Securities | | | | | | | | | | | 54 | | | | | | | | 54 | |
| Unrealized Gain on Derivatives | | | | | | | | | | | 296 | | | | | | | | 296 | |
| Other Comprehensive Loss, Net of Tax: (a) | | | | | | | | | | | | | | | | | | | (92 | ) |
| Comprehensive Income | | | | | | | | | | | | | | | | | | | 35,687 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | | | | (19,902 | ) | | | (19,902 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 5,848 | | | | 200,317 | | | | (4,429 | ) | | | 158,617 | | | | 360,353 | |
| Cumulative Effect Adjustment (b) | | | - | | | | - | | | | - | | | | (371 | ) | | | (371 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at January 1, 2007, as adjusted | | | 5,848 | | | | 200,317 | | | | (4,429 | ) | | | 158,246 | | | | 359,982 | |
| Net Income | | | | | | | | | | | | | | | 38,025 | | | | 38,025 | |
| Other Comprehensive Loss, Net of Tax: (a) | | | | | | | | | | | | | | | | | | | | |
| Postretirement Liability Adjustment | | | | | | | | | | | (307 | ) | | | | | | | (307 | ) |
| Unrealized Loss on Available-for-Sale Securities | | | | | | | | | | | (195 | ) | | | | | | | (195 | ) |
| Unrealized Loss on Derivatives | | | | | | | | | | | (425 | ) | | | | | | | (425 | ) |
| Other Comprehensive Loss, Net of Tax: (a) | | | | | | | | | | | | | | | | | | | (927 | ) |
| Comprehensive Income | | | | | | | | | | | | | | | | | | | 37,098 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | | | | (18,732 | ) | | | (18,732 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | | 5,848 | | | | 200,317 | | | | (5,356 | ) | | | 177,539 | | | | 378,348 | |
| Net Income | | | | | | | | | | | | | | | 39,431 | | | | 39,431 | |
| Other Comprehensive Income (Loss), Net of Tax (a) | | | | | | | | | | | | | | | | | | | | |
| Postretirement Liability Adjustment | | | | | | | | | | | (1,181 | ) | | | | | | | (1,181 | ) |
| Unrealized Loss on Available-for-Sale Securities | | | | | | | | | | | (731 | ) | | | | | | | (731 | ) |
| Unrealized Gain on Derivatives | | | | | | | | | | | 393 | | | | | | | | 393 | |
| Other Comprehensive Loss, Net of Tax (a) | | | | | | | | | | | | | | | | | | | (1,519 | ) |
| Comprehensive Income | | | | | | | | | | | | | | | | | | | 37,912 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | | | | (14,867 | ) | | | (14,867 | ) |
| Excess Tax Benefit from Restricted Stock Plan | | | | | | | 346 | | | | | | | | | | | | 346 | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2008 | | $ | 5,848 | | | $ | 200,663 | | | $ | (6,875 | ) | | $ | 202,103 | | | $ | 401,739 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Disclosure of Changes in Accumulated Other Comprehensive Loss Balances (a) |
| (In Thousands) |
| | | | | | | Postretirement Liability Adjustment | | | Unrealized (Loss) Gain on Available-for-Sale Securities | | | Unrealized Gain (Loss) on Derivatives | | | Accumulated Other Comprehensive Loss | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at January 1, 2006 | | | | | | $ | (3,498 | ) | | $ | 154 | | | $ | (993 | ) | | $ | (4,337 | ) |
| Changes During Year | | | | | | | (442 | ) | | | 54 | | | | 296 | | | | (92 | ) |
| Balance at December 31, 2006 | | | | | | | (3,940 | ) | | | 208 | | | | (697 | ) | | | (4,429 | ) |
| Changes During Year | | | | | | | (307 | ) | | | (195 | ) | | | (425 | ) | | | (927 | ) |
| Balance at December 31, 2007 | | | | | | | (4,247 | ) | | | 13 | | | | (1,122 | ) | | | (5,356 | ) |
| Changes During Year | | | | | | | (1,181 | ) | | | (731 | ) | | | 393 | | | | (1,519 | ) |
| Balance at December 31, 2008 | | | | | | $ | (5,428 | ) | | $ | (718 | ) | | $ | (729 | ) | | $ | (6,875 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| (a) Determined using a combined statutory tax rate of 41.08%. | | | | | |
| (b) Due to the implementation of FIN 48. See Note 1. | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | | | | |
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 normal and recurring adjustments needed to fairly present our financial position and operating results at the dates and for the periods presented.
Equity Investments - Marketable equity securities that are purchased as long-term investments are classified as Available-for-Sale Securities and carried at their fair value on our balance sheets. 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 (GAAP). 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). See Note 2 for a detailed discussion of our rate structure and regulatory actions. We maintain our accounts according to the BPU’s prescribed Uniform System of Accounts. We follow 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 for the deferral of certain costs (regulatory assets) and creation of certain obligations (regulatory liabilities) when it is probable that such items will be recovered from or refunded to customers in future periods. See Note 3 for a detailed discussion of regulatory assets and liabilities.
Operating Revenues - Gas revenues are recognized in the period the commodity is delivered to customers. For retail customers that are not billed at the end of the 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 collect certain revenue-based energy taxes from our customers. Such taxes include New Jersey State Sales Tax, Transitional Energy Facility Assessment (TEFA) and Public Utilities Assessment (PUA). State sales tax is recorded as a liability when billed to customers and is not included in revenue or operating expenses. TEFA and PUA are included in both revenues and cost of sales and totaled $8.7 million, $8.8 million and $7.9 million in 2008, 2007 and 2006, respectively.
Accounts Receivable and Provision for Uncollectible Accounts - Accounts receivable are carried at the amount owed by customers. A provision for uncollectible accounts is established based on our collection experience and an assessment of the collectibility of specific accounts.
Natural Gas in Storage – Natural Gas in Storage is reflected at average cost on the balance sheets, and represents natural gas that will be utilized in the ordinary course of business.
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, 2008 and 2007 were comprised of the following (in thousands):
| | | 2008 | | | 2007 | |
| Utility Plant: | | | | | | |
| Production Plant | | $ | 302 | | | $ | 302 | |
| Storage Plant | | | 11,543 | | | | 11,582 | |
| Transmission Plant | | | 151,546 | | | | 149,542 | |
| Distribution Plant | | | 959,807 | | | | 919,205 | |
| General Plant | | | 41,122 | | | | 37,136 | |
| Other Plant | | | 3,665 | | | | 3,665 | |
| Utility Plant in Service | | | 1,167,985 | | | | 1,121,432 | |
| Construction Work in Progress | | | 4,029 | | | | 2,560 | |
| | | | | | | | | |
| Total Utility Plant | | $ | 1,172,014 | | | $ | 1,123,992 | |
Asset Retirement Obligations - The amounts included under Asset Retirement Obligations (ARO) are primarily related to the legal obligations we have to cut and cap our gas distribution pipelines when taking those pipelines out of service in future years. These liabilities are generally recognized upon the acquisition or construction of the asset. The related asset retirement cost is capitalized concurrently by increasing the carrying amount of the related asset by the same amount as the liability. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
ARO activity during 2008 and 2007 was as follows (in thousands):
| | | 2008 | | | 2007 | |
| AROs as of January 1, | | $ | 24,364 | | | $ | 23,743 | |
| Accretion | | | 427 | | | | 498 | |
| Additions | | | 136 | | | | 174 | |
| Settlements | | | (37 | ) | | | (51 | ) |
| Revisions in Estimated Cash Flows * | | | (2,591 | ) | | | - | |
| AROs as of December 31, | | $ | 22,299 | | | $ | 24,364 | |
| | | | | | | | | |
| * A corresponding reduction was made to Regulatory Assets, thus having no impact on Earnings. |
Depreciation - 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 2.3% in 2008, 2007 and 2006. The actual composite rate may differ from the approved rate as the asset mix changes over time. Except for retirements outside of the normal course of business, accumulated depreciation is charged with the cost of depreciable utility property retired, less salvage.
Capitalized Interest - We capitalize interest on construction at the rate of return on rate base utilized by the BPU to set rates in our 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 on the statements of income. We capitalized interest of $0.4 million in 2008, 2007 and 2006.
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 2008, 2007 and 2006, no significant impairments were identified.
Derivative Instruments - We are involved in buying, selling, transporting and storing natural gas and are subject to market risk due to commodity price fluctuations. Our affiliate, South Jersey Resources Group (SJRG), manages this risk for us by entering into a variety of physical and financial transactions including forward contracts, swap agreements, options contracts and futures contracts on our behalf. Management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in identifying, assessing and controlling various risks. Management reviews any open positions in accordance with strict policies to limit exposure to market risk.
We account for derivative instruments in accordance with FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. We record all derivatives, whether designated in 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. We recognize ineffective portions of cash flow hedges immediately in earnings. In 2007, we changed our policy to no longer designate energy-related derivative instruments as cash flow hedges. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction.
Initially and on an ongoing basis, we assess whether our derivatives are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we decide to discontinue the hedging relationship; determine that the anticipated transaction is no longer likely to occur; or determine that a derivative is no longer highly effective as a hedge. In the event that hedge accounting is discontinued, we will continue to carry the derivative on our balance sheet at its current fair value and recognize subsequent changes in fair value in current period earnings. Unrealized gains and losses on the discontinued hedges that were previously included in Accumulated Other Comprehensive Loss are reclassified into earnings when the forecasted transaction occurs, or when it is probable that it will not occur.
Due to the application of regulatory accounting principles under FASB Statement No. 71, the costs or benefits of derivative contracts related to gas purchases are recovered through our Basic Gas Supply Service (BGSS) Clause, subject to BPU approval (See Note 2). As of December 31, 2008 and 2007, we had $29.0 million and $2.1 million of costs, respectively, included in our BGSS related to open financial contracts (See Note 3).
The Company has entered into interest rate derivatives and similar agreements to hedge exposure to increasing interest rates, and the impact of those rates on cash flows of variable-rate debt. These interest rate derivatives are included in Derivatives-Other on the balance sheets.
We previously used derivative transactions known as “Treasury Locks” to hedge against the impact on our cash flows of possible interest rate increases on debt issued in September 2005. The initial $1.4 million cost of the Treasury Locks has been included in Accumulated Other Comprehensive Loss and is being amortized over the 30 year life of the associated debt issue. As of December 31, 2008, the unamortized balance is approximately $1.2 million.
We currently have two long-term interest rate swaps under which we pay a fixed interest rate at 3.43% through January 2036 on $25.0 million of variable-rate, tax-exempt debt which was issued in April 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.
As of December 31, 2008 and 2007, the fair value of these interest rate derivative agreements was $7.6 million and $0.6 million, respectively, and is included on the balance sheet under the caption Regulatory and Other Noncurrent Liabilities: Derivatives - Other. The fair value represents the amount we would have expected to pay to the counterparties if the contracts had been terminated on those dates. The fair value upon termination can be recovered in rates, and therefore, the unrealized loss has been included in Other Regulatory Assets in the balance sheets in accordance with FASB Statement No. 71 “Accounting for the Effects of Certain Types of Regulation.”
Stock-Based Compensation Plans - On January 1, 2006, SJI adopted FASB Statement No. 123(R), “Share-Based Payment,” which revised FASB Statement No. 123, and superseded Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” As the vesting requirements under the plan are contingent upon market and service conditions, Statement No. 123(R) requires SJI to measure and recognize stock-based compensation expense in its financial statements based on the fair value at the date of grant for share-based awards. Since Officers and other key employees of SJG participate in the Stock Option, Stock Appreciation Rights and Restricted Stock Award Plan (“Plan”) of SJI, changes in accounting for share-based payments also impact us. In accordance with Statement No. 123(R), SJI is recognizing compensation expense on a straight-line basis over the requisite service period of each award. In addition, SJI identifies specific forfeitures of share-based awards and compensation expense is adjusted accordingly over the requisite service period. Compensation expense is not adjusted based on the actual achievement of performance goals. The fair value of Officers’ restricted stock awards on the date of grant is estimated using a Monte Carlo simulation model.
We are allocated a portion of SJI's compensation cost during the vesting period. We accrue a liability and record compensation cost on a straight-line basis over the requisite three-year service period based on the grant date fair value. Upon vesting, we make a cash payment to SJI equal to the amounts accrued as compensation cost during the vesting period. Since the inception of the Plan, our expense recognition policy has been consistent with the expense recognition policy at SJI.
The following table summarizes the SJI nonvested restricted stock awards pertaining to SJG outstanding at December 31, 2008, and the assumptions used to estimate the fair value of the awards:
| Grant | | Shares | | | Fair Value | | | Expected | | | Risk-Free | |
| Date | | Outstanding | | | Per Share | | | Volatility | | | Interest Rate | |
| | | | | | | | | | | | | |
| Jan. 2007 | | | 9,045 | | | $ | 29.210 | | | | 18.5 | % | | | 4.9 | % |
| Jan. 2008 | | | 9,238 | | | $ | 34.030 | | | | 21.7 | % | | | 2.9 | % |
Expected volatility is based on the actual daily volatility of SJI’s share price over the preceding 3-year period as of the valuation date. The risk-free interest rate is based on the zero-coupon U.S. Treasury Bond, with a term equal to the 3-year term of the restricted shares. As notional dividend equivalents are credited to the holders, which are reinvested during the 3-year service period, no reduction to the fair value of the award is required.
For the years ended December 31, 2008, 2007 and 2006, the cost of restricted stock awards was $0.3 million, $0.2 million and $0.2 million, respectively. Of these costs, $0.1 million was capitalized to Utility Plant in each of those years.
As of December 31, 2008, there was $0.3 million of total unrecognized compensation cost related to nonvested share-based compensation awards granted under the restricted stock plans. That cost is expected to be recognized over a weighted average period of 1.7 years.
The following table summarizes information regarding restricted stock award activity during 2008, excluding accrued dividend equivalents:
| | | | | Weighted Average | |
| | | | | Grant Date | |
| | Shares | | | Fair Value | |
| Nonvested Shares Outstanding, January 1, 2008 | | | 17,976 | | | $ | 28.618 | |
| Granted | | | 10,000 | | | | 34.030 | |
| Vested* | | | (8,234 | ) | | | 27.950 | |
| Forfeited | | | (1,459 | ) | | | 31.541 | |
| Nonvested Shares Outstanding, December 31, 2008 | | | 18,283 | | | $ | 31.645 | |
| | | | | | | | | |
| * Actual shares expected to be awarded to officers during the first quarter of 2009, including dividend equivalents and adjustments for performance measures, totaled 13,640 shares. | |
During 2008, SJI awarded 12,299 shares that had vested at December 31, 2007, to our officers at a market value of $0.4 million. During 2007, 17,143 shares were awarded to our officers at a market value of $0.6 million. As discussed earlier, we have a policy of making cash payments to SJI to satisfy our allocated obligations under this plan. Cash payments to SJI during 2008 and 2007, were approximately $0.6 million and $1.1 million, respectively relating to stock awards. These cash payments include obligations for services previously rendered by officers that are currently employed by affiliates as a result of a January 1, 2006 corporate restructuring by SJI. Additionally, a change in control could result in the nonvested shares becoming nonforfeitable or immediately payable in cash.
Income Taxes - Deferred income taxes are provided for all significant temporary differences between the book and taxable basis of assets and liabilities in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (See Note 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.
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.
New Accounting Pronouncements — In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 (FAS 157), “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in accounting principles generally accepted in the United States of America, and expands disclosures about fair value measurements. In October 2008, the FASB issued FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” to provide clarification of the application of FAS 157 in a market that is not active and to provide an example to illustrate key considerations in determining the fair value of a financial asset in such a non-active market. This statement was effective in fiscal years beginning after November 15, 2007. However, for nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, FAS 157 is effective in fiscal years beginning after November 15, 2008. The adoption of the initial phase of this statement did not have a material effect on the Company’s financial statements. Management does not anticipate that the adoption of the remainder of this statement will have a material effect on the Company’s financial statements.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” The statement permits entities to choose to measure certain financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This statement is effective for the first fiscal year beginning after November 15, 2007. The Company has not elected this fair value option and, as a result, the adoption of this statement did not have a material effect on the Company’s financial statements.
In April 2007, the FASB posted FASB Staff Position (FSP) FIN 39-1, “Amendment of FASB Interpretation No. 39,” which addresses questions received by the FASB staff regarding Interpretation 39 relating to the offsetting of amounts recognized for forward, interest rate swap, currency swap, option, and other conditional or exchange contracts. The guidance in this FSP is effective for fiscal years beginning after November 15, 2007. The adoption of this position did not have a material effect on the Company’s financial statements.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161(FAS 161), “Disclosures about Derivative Instruments and Hedging Activities - an amendment of SFAS No. 133.” This statement requires disclosures of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. FAS 161 is effective for fiscal years beginning after November 15, 2008. Management is currently evaluating the impact that the adoption of this statement will have on the Company’s financial statements.
In September 2008, the FASB issued FASB Staff Position (FSP) No. 133-1 and FIN 45-4, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161.” The FSP is intended to improve disclosures about credit derivatives by requiring more information about the potential adverse effects of changes in credit risk on the financial position, financial performance, and cash flows of the sellers of credit derivatives. The provisions of the FSP that amend Statement 133 and Interpretation 45 are effective for reporting periods (annual or interim) ending after November 15, 2008. The adoption of this position did not have a material effect on the Company’s financial statements.
In December 2008, the FASB issued FASB Staff Position (FSP) No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which amends Statement 132(R) to require more detailed disclosures about employers’ plan assets, including employers’ investment strategies, major categories of plan assets, concentrations of risk within plan assets, and valuation techniques used to measure the fair value of plan assets. The provisions of this FSP are effective for reporting periods ending after December 15, 2009. Management is currently evaluating the impact that the adoption of this position will have on the Company’s financial statements.
In December 2008, the Emerging Issue Task Force issued EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value With a Third-Party Credit Enhancement.” The Task Force reached a consensus that an issuer of a liability with a third-party credit enhancement that is inseparable from the liability must treat the liability and the credit enhancement as two units of accounting. Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement; therefore, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability. Entities will need to disclose the existence of any third-party credit enhancements related to their liabilities that are within the scope of this Issue (i.e., that are measured at fair value). The consensus is effective in the first reporting period beginning on or after December 15, 2008. Management is currently evaluating the impact that the adoption of this consensus will have on the Company’s financial statements.
In December, 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, “Disclosures Related to Asset Transfers, VIEs, and QSPEs,” which requires public companies to provide disclosures similar to those proposed in the pending amendments to Statement 140 and Interpretation 46(R). The FSP requires additional disclosures about transfers of financial assets and an enterprise’s involvement with VIEs, including QSPEs. These disclosures should help improve transparency in the current market environment. The FSP is effective for the first reporting period (interim or annual) that ends after December 15, 2008. The adoption of this position did not have a material effect on the Company’s financial statements.
2. RATES AND REGULATORY ACTIONS:
Base Rates - In July 2004 the BPU approved our current rate structure based on a 7.97% rate of return on rate base that included a 10.0% return on common equity. We were also permitted to recover regulatory assets contained in our petition and to reduce our composite depreciation rate from 2.9% to 2.4%. Included in the base rate increase was also a change to the sharing of pre-tax margins on interruptible, off system sales and transportation. The sharing of pre-tax margins begins from dollar one, with our retaining 20% through June 30, 2006. Effective July 1, 2006, the 20% retained by us decreased to 15% of such margins.
Rate Mechanisms - Our tariff, a schedule detailing the terms, conditions and rate information applicable to our various types of natural gas service, as approved by the BPU, has several primary rate mechanisms as discussed in detail below:
Basic Gas Supply Service (BGSS) Clause - The BGSS price structure was approved by the BPU in January 2003, and allows us to recover all prudently incurred gas costs. BGSS charges to customers can be either monthly or periodic (annual). Monthly BGSS charges are applicable to large use customers and are referred to as monthly because the rate changes on a monthly basis pursuant to a BPU-approved formula based on commodity market prices. Periodic BGSS charges are applicable to lower usage customers, which include all of our residential customers, and are evaluated at least annually by the BPU. However, to some extent, more frequent rate changes to the periodic BGSS are allowed. We collect gas costs from customers on a forecasted basis and defer periodic over/under recoveries to the following BGSS year, which runs from October 1 through September 30. If we are in a net cumulative undercollected position, gas costs deferrals are reflected on the balance sheet as a regulatory asset. If we are in a net cumulative overcollected position, amounts due back to customers are reflected on the balance sheet as a regulatory liability. We pay interest on net overcollected BGSS balances at the rate of return on rate base of 7.97% utilized by the BPU to set rates in our last base rate proceeding.
Regulatory actions regarding the BGSS were as follows:
| | · | March 2006 - The BPU approved a global settlement, effective April 1, 2006, which among other items, fully resolved our 2004-2005 BGSS filing and certain issues in our 2005-2006 BGSS filing. The net impact of our global settlement was a $4.4 million reduction to annual revenues; however, this reduction had no impact on net income, as there was a corresponding reduction in expense. In addition, a pilot storage incentive program was approved. This program began during the second quarter of 2006 and continued through the 2008 summer injection period. Any party to this settlement may request that the BPU terminate this program after October 31, 2008. It is designed to provide us with the opportunity to achieve BGSS price reductions and additional price stability. It will also provide us with an opportunity to share in storage-related gains and losses, with 20% being retained by us, and 80% being credited to customers. Total storage-related gains for 2008, 2007 and 2006 were $5.7 million, $2.3 million and $1.6 million, respectively, under this storage incentive program. |
| | · | June 2006 - We made our annual periodic BGSS filing with the BPU requesting a $19.7 million, or 4.4%, decrease in gas cost recoveries in response to decreasing wholesale gas costs, an $11.5 million benefit derived from the release of a storage facility and the liquidation of some low-cost base gas during the second quarter. |
| | · | September 2006 - The BPU approved on a provisional basis, a $38.7 million, or 8.6%, annual decrease in gas cost recoveries due to the continuing decrease in wholesale gas costs subsequent to our June 2006 filing, an agreement to utilize gas from a released storage facility for the upcoming winter, and a credit to gas costs for previously overcollected state taxes. |
| | · | June 2007 – We made our annual periodic BGSS filing with the BPU requesting a $16.9 million, or 5.0%, decrease in gas cost recoveries in response to decreasing wholesale gas costs and a $5.4 million benefit derived from the Company electing not to extend the terms of two firm transportation contracts beyond their primary terms. |
| | · | October 2007 – The BPU approved on a provisional basis, a $36.7 million, or 11%, annual decrease in gas cost recoveries due to the continuing decrease in wholesale gas costs subsequent to our June 2007 filing. |
| | · | May 2008 - We made our annual periodic BGSS filing with the BPU requesting a $73.7 million, or 23%, increase in gas cost recoveries in response to increasing wholesale gas costs. |
| | · | November 2008 – The BPU approved, on a provisional basis, a $38.0 million, or 12% increase in gas cost recoveries reflecting a lower increase in gas costs than originally projected in our May 2008 filing. |
| | · | December 2008 - As part of a global settlement, the BPU approved on a provisional basis, a decrease in gas cost recoveries of $9.0 million, or 3%, due to the continued decline in projections in the wholesale gas market. |
Temperature Adjustment Clause (TAC) - The TAC provided stability to our earnings by normalizing the impact of colder-than-normal and warmer-than-normal weather through September 30, 2006, when it was replaced by the Conservation Incentive Program. Each TAC year began October 1 and ended May 31 of the subsequent year. We recorded the earnings impact of TAC adjustments as incurred on a monthly basis during the TAC year. Subsequent to each TAC year, we made a filing with the BPU requesting the return or recovery of amounts recorded under the TAC. BPU-approved cash inflows or outflows generally did not begin until the next TAC year. TAC adjustments affected revenue, earnings and cash flows since colder-than-normal weather generated credits to customers, while warmer-than-normal weather resulted in additional charges to customers. As of December 31, 2008 and 2007, our balance sheets include a TAC receivable of $0 and $6.5 million, respectively, under the caption Regulatory Assets.
Regulatory actions regarding the TAC were as follows:
| | · | March 2006 - The BPU approved a global settlement, effective April 1, 2006, fully resolving our 2003-2004 TAC filing. |
| | · | October 2006 - The TAC was replaced by the Conservation Incentive Program (CIP). |
| | · | October 2006 - We made our annual TAC filing, requesting recovery of an $8.3 million net deficiency associated with weather being 12.5% warmer-than-normal for the TAC year ended May 31, 2006. |
| | · | October 2007 – The BPU approved on a provisional basis, our 2005-2006 TAC filing, which superseded our 2004-2005 TAC filing. The effect of this action resulted in an $8.0 million increase in annual revenues. |
| | · | December 2008 –The regulatory asset related to the TAC was completely recovered and as part of a global settlement, the BPU approved the suspension of the TAC rate which resulted in a decrease of $9.3 million in annual revenues. |
Conservation Incentive Program (CIP) - In December 2005, we made a filing to implement a Conservation and Usage Adjustment (CUA) Clause. The primary purpose of the CUA was to promote conservation efforts, without negatively impacting financial stability, and to base our profit margin on the number of customers rather than the amount of natural gas distributed to customers. In October 2006, the BPU approved the CUA as a three-year pilot program and renamed it the Conservation Incentive Program. Each CIP year begins October 1 and ends September 30 of the subsequent year. On a monthly basis during the CIP year, we record adjustments to earnings based on weather and customer usage factors, as incurred. Subsequent to each year, we will make filings with the BPU to review and approve amounts recorded under the CIP. BPU approved cash inflows or outflows generally will not begin until the next CIP year.
| | · | June 2007 – We made our first annual CIP filing, requesting recovery of $14.3 million in deficiency, of which $9.6 million was non-weather related. |
| | · | October 2007 – The BPU approved on a provisional basis, recovery of $15.5 million in deficiency, of which $9.1 million was non-weather related. |
| | · | May 2008 - We made our annual CIP filing, requesting recovery of $19.1 million, of which $14.1 million was non-weather related. |
| | · | December 2008 - As part of a global settlement, the BPU approved, on a provisional basis, the recovery of CIP revenue of $20.4 million, of which $16.4 million was non-weather related. |
Societal Benefits Clause (SBC) - The SBC allows us to recover costs related to several BPU-mandated programs. Within the SBC are a Remediation Adjustment Clause (RAC), a New Jersey Clean Energy Program (NJCEP), a Universal Service Fund (USF) program and a Consumer Education Program (CEP).
Regulatory actions regarding the SBC, with the exception of USF which requires separate regulatory filings, were as follows:
| | · | March 2006 - As part of the global settlement discussed under BGSS above, our September 2004 SBC filing was fully resolved effective April 1, 2006. |
| | · | October 2006 - We made our annual SBC filing, superseding our 2005 SBC filing, requesting a $0.4 million reduction in annual SBC recoveries. |
| | · | December 2007 – We made our annual SBC filing, superseding our 2005 and 2006 SBC filings, requesting a $7.4 million increase in annual SBC recoveries. |
| | · | December 2008 – As part of the global settlement, the BPU approved an increase in the RAC portion of the SBC, resulting in an increase in revenue of $8.5 million. In addition, the BPU approved a reduction in the interest rate utilized to calculate deferred tax on the RAC. |
Remediation Adjustment Clause (RAC) - The RAC recovers environmental remediation costs of 12 former gas manufacturing plants (See Note 12). The BPU allows us to recover such costs over 7-year amortization periods. The net between the amounts actually spent and amounts recovered from customers is recorded as a regulatory asset, Environmental Remediation Cost Expended - Net. Note that RAC activity affects revenue and cash flows but does not directly affect earnings because of the cost recovery over 7-year amortization periods. As of December 31, 2008 and 2007, we reflected the unamortized remediation costs of $48.1 million and $26.0 million, respectively, on the balance sheet under Regulatory Assets (See Note 3). Since implementing the RAC in 1992, we have recovered $40.7 million through rates.
New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with our energy efficiency and renewable energy programs. In August 2008, the BPU approved the statewide funding of the NJCEP of $1.2 billion for the years 2009 through 2012. Of this amount, we will be responsible for approximately $41.8 million over the 4-year period. NJCEP adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered through rates on an on-going basis.
Universal Service Fund (USF) - - The USF is a statewide program through which funds for the USF and Lifeline Credit and Tenants Assistance Programs are collected from customers of all New Jersey electric and gas utilities. USF adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered through rates on an ongoing basis.
Separate regulatory actions regarding the USF were as follows:
| | · | July 2006 - We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to increase annual statewide gas revenues to $115.3 million, an increase of $68.5 million. This rate proposal was approved by the BPU in October 2006, on an interim basis, and was designed to increase our annual USF revenues by $7.7 million. The revised rates were effective from November 1, 2006 through September 30, 2007. |
| | · | July 2007 – We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to decrease annual statewide gas revenues to $78.1 million. This rate proposal was approved by the BPU in October 2007, on an interim basis, and were designed to decrease our annual USF revenues by $3.4 million. The revised rates were effective from October 5, 2007 through September 30, 2008. |
| | · | June 2008 – We made our annual USF filing, along with the state’s other electric and gas utilities, proposing to increase annual statewide gas revenues to $97.3 million. This proposal was designed to increase our annual USF revenues by $ 2.6 million. |
| | · | October 2008 – The BPU approved the statewide budget of $96.7 million for all of the State’s gas utilities. Our portion of this total is approximately $8.8 million and increased rates were implemented effective October 27, 2008 resulting in a $2.5 million increase to our annual USF recoveries. |
Consumer Education Program (CEP) - The CEP recovers costs associated with providing education to the public concerning customer choice. CEP adjustments affect revenue and cash flows but do not directly affect earnings as related costs are deferred and recovered on an ongoing basis. Note that our CEP recovery rate was reduced to zero in April 2006, and as a result of a previous BPU Order, it has been removed from our tariff as of December 2008.
Other Regulatory Matters -
Unbundling - 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, 2008, 24,968 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.
Pipeline Integrity - In October 2005, we filed a petition with the BPU to implement a Pipeline Integrity Management Tracker (Tracker). The purpose of the Tracker is to recover incremental 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. As of December 31, 2008 and 2007, costs incurred under this program totaled $1.1 million and $0.8 million, respectively, and are included in Other Regulatory Assets (See Note 3). We continue to engage in settlement negotiations in which we are proposing to modify the original request and provide for deferred accounting treatment of Pipeline Integrity related operating expenses, with the ultimate recovery of these costs to be sought in our next base rate case.
Filings and petitions described above are still pending unless otherwise indicated.
3. REGULATORY ASSETS AND LIABILITIES:
The discussion under Note 2, Rates and Regulatory Actions, is integral to the following explanations of specific regulatory assets and liabilities.
| Regulatory Assets at December 31 consisted of the following items (in thousands): | |
| | | | | | | |
| | | 2008 | | | 2007 | |
Environmental Remediation Costs: Expended – Net | | $ | 48,143 | | | $ | 25,960 | |
| Liability for Future Expenditures | | | 64,093 | | | | 73,880 | |
| Income Taxes - Flowthrough Depreciation | | | 2,729 | | | | 3,707 | |
| Deferred Asset Retirement Obligation Costs | | | 21,901 | | | | 21,572 | |
| Deferred Gas Costs – Net | | | 18,406 | | | | - | |
| Deferred Pension and Other Postretirement Benefit Costs | | | 80,162 | | | | 32,686 | |
| Temperature Adjustment Clause Receivable | | | - | | | | 6,516 | |
| Conservation Incentive Program Receivable | | | 22,048 | | | | 18,173 | |
| Societal Benefit Costs Receivable | | | 1,753 | | | | 2,952 | |
| Premium for Early Retirement of Debt | | | 1,208 | | | | 1,370 | |
| Other Regulatory Assets | | | 9,991 | | | | 1,872 | |
| | | $ | 270,434 | | | $ | 188,688 | |
Except where noted below, all regulatory assets are or will be recovered through utility rate charges, as detailed in the following discussion. 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.
Environmental Remediation Costs - We have two regulatory assets associated with environmental costs related to the cleanup of 12 sites where we or our predecessors previously operated gas manufacturing plants. The first asset, Environmental Remediation Cost: Expended - Net, represents what was actually spent to clean up the sites, less recoveries through the RAC and insurance carriers. These costs meet the deferral requirements of FASB Statement No. 71, as the BPU allows us to recover such expenditures through the RAC. The other asset, Environmental Remediation Cost: Liability for Future Expenditures, relates to estimated future expenditures required to complete the remediation of these sites as determined under the guidance of FASB Statement No. 5, "Accounting for Contingencies." We recorded this estimated amount as a regulatory asset under Statement No. 71, with the corresponding current and noncurrent liabilities on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities. The BPU allows us to recover the deferred costs over 7-year periods after they are spent.
Income Taxes - Flowthrough Depreciation - This regulatory asset was created upon the adoption of FASB Statement No. 109, "Accounting for Income Taxes,” in 1993. The amount represents unamortized 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 and are recovering the amortization of the regulatory asset through rates until 2011.
Deferred Asset Retirement Obligation Costs - This regulatory asset was created with the adoption of FASB Interpretation No. 47(FIN 47), “Accounting for Conditional Asset Retirements Obligations”, in 2005. FIN 47 resulted in the recording of asset retirement obligations (ARO’s) and additional utility plant, primarily related to a legal obligation we have for certain safety requirements upon the retirement of our gas distribution and transmission system. We recover asset retirement costs through rates charged to customers. All related accumulated accretion and depreciation amounts for these ARO’s represent timing differences in the recognition of 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.
Deferred Gas Costs - Net - 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 also included in the BGSS, subject to BPU approval. See detailed discussion under Derivative Instruments in Note 1.
Deferred Pension and Other Postretirement Benefit Costs - The BPU authorized us to recover costs related to postretirement benefits 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 over 15 years through 2012. The unamortized balance was $1.5 million at December 31, 2008. Upon the adoption of FASB Statement No. 158 in 2006, our regulatory asset was increased by $37.1 million representing the recognition of the underfunded positions of our pension and other postretirement benefit plans. Subsequent adjustments to this balance occur annually to reflect changes in the funded positions of these benefit plans caused by changes in actual plan experience as well as assumptions of future experience (See Note 11).
Temperature Adjustment Clause Receivable - As discussed in Note 2, the net income impact of the TAC was recorded as an adjustment to earnings as incurred. The recovery (or credit) generally did not begin until the next TAC year. As a result, there was a timing difference that resulted in a regulatory asset or liability. As a result of a Global Settlement in December 2008, the BPU approved rolling in the remaining overrecovered TAC position into the weather portion of the CIP, and the suspension of the TAC rate.
Conservation Incentive Program Receivable - Similar to the TAC, the impact of the CIP is recorded as an adjustment to earnings as incurred. The first year of cash recovery under the CIP began October 2007.
Societal Benefit Costs Receivable - At both December 31, 2008 and 2007, this regulatory asset primarily represents cumulative costs less recoveries under the USF program.
Premium for Early Retirement of Debt - This regulatory asset represents unamortized debt issuance costs related to long-term debt refinancings and a call premium associated with the retirement of debt, all occurring in 2005 and 2004. Unamortized debt issuance costs are being amortized over the term of the new debt issue pursuant to regulatory approval by the BPU. The call premium is expected to be approved for recovery through future rate proceedings.
Other Regulatory Assets - Some of the assets included in Other Regulatory Assets are currently being recovered from ratepayers as approved by the BPU. Management believes the remaining deferred costs are probable of recovery from ratepayers through future utility rates.
Regulatory Liabilities at December 31 consisted of the following items (in thousands):
| | | 2008 | | | 2007 | |
| Excess Plant Removal Costs | | $ | 48,820 | | | $ | 48,705 | |
| Liability for NJCEP | | | - | | | | 2,797 | |
| Deferred Revenues – Net | | | - | | | | 2,586 | |
| Other | | | 1,627 | | | | 1,691 | |
| | | | | | | | | |
| Total Regulatory Liabilities | | $ | 50,447 | | | $ | 55,779 | |
Excess Plant Removal Costs – Represents 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.
Liability for NJCEP – This represents revenues received in excess of actual expenditures, which we have an obligation to either expend or return to ratepayers in future periods.
Deferred Revenue – Net – See previous discussion under “Deferred Gas Costs – Net”.
Other Regulatory Liabilities – All other regulatory liabilities are subject to being returned to ratepayers in future rate proceedings.
4. RELATED PARTY TRANSACTIONS:
We conducted business with our parent, SJI, and several other related parties. A description of each of these affiliates and related transactions is as follows:
SJI Services, LLC (SJIS) - a wholly owned subsidiary of SJI established on January 1, 2006, that provides services, such as information technology, human resources, government relations, corporate communications, materials purchasing, fleet management and insurance to SJI and all of its subsidiaries.
South Jersey Energy Solutions, LLC (SJES) - a wholly owned subsidiary of SJI that serves as a holding company for all of SJI’s nonutility operating businesses:
| | · | South Jersey Energy Company (SJE) - a wholly owned subsidiary of SJI and a third party energy marketer that acquires and markets natural gas and electricity to retail end users and provides total energy management services to commercial and industrial customers. We previously sold natural gas for resale to SJE and also provide them with billing services. For SJE’s residential customers, for which we perform billing services, we purchase the related accounts receivable at book value less a factor for potential uncollectible accounts, and assume all risk associated with collection. |
| | · | South Jersey Resources Group, LLC (SJRG) - a wholly owned subsidiary of SJI and a wholesale gas and risk management business that supplies natural gas storage, commodity and transportation to retail marketers, utility businesses and electricity generators in the mid-Atlantic and southern regions. We sell natural gas for resale and capacity release to SJRG and also meet some of our gas purchasing requirements by purchasing natural gas from SJRG. Additionally, SJRG manages our market risk associated with fluctuations in the cost of natural gas by entering into financial derivative contracts on our behalf. The gain or loss associated with these derivative contracts is included in our BGSS and in the SJRG receivable and payable amounts shown below. In addition to our normal gas purchases and sales with SJRG, during 2006, we sold 1,710,903 decatherms of gas to SJRG for $13.1 million. The proceeds from the sale were credited to the BGSS clause and did not impact earnings. |
| | · | Marina Energy LLC (Marina) - a wholly owned subsidiary of SJI and developer, owner and operator of energy related projects. We provide natural gas transportation services to Marina under BPU-approved tariffs. |
| | · | South Jersey Energy Service Plus, LLC (SJESP) - a wholly owned subsidiary of SJI and an appliance service and installation of heating and cooling systems company. We lease vehicles and provide billing services to SJESP. |
Millennium Account Services, LLC (Millennium) - a partnership between SJI and Conectiv Solutions, LLC, which reads our utility customers’ meters on a monthly basis for a fee.
Sales of gas to SJRG and SJE comply with Section 284.02 of the Regulations of the Federal Energy Regulatory Commission (FERC).
In addition to the above, we provide various administrative and professional services to SJI and each of the affiliates discussed above. Likewise, SJI provides substantial administrative services on our behalf. Beginning in January 2006, SJIS began to provide a majority of the aforementioned administrative services to SJI and its subsidiaries. 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.
A summary of these related party transactions, excluding pass-through items, included in Operating Revenues were as follows (in thousands):
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | |
| Operating Revenues/Affiliates: | | | | | | | | | |
| SJRG | | $ | 7,604 | | | $ | 19,328 | | | $ | 67,262 | |
| Other | | | 402 | | | | 386 | | | | 2,302 | |
| Total Operating Revenues/Affiliates | | $ | 8,006 | | | $ | 19,714 | | | $ | 69,564 | |
Related party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands):
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Costs of Sales/Affiliates | | | | | | | | | | | | |
| (Excluding depreciation): | | | | | | | | | | | | |
| SJRG | | $ | 28,565 | | | $ | 24,601 | | | $ | 23,083 | |
| | | | | | | | | | | | | |
| Derivative Gains (Losses) (See Note 1): | | | | | | | | | | | | |
| SJRG | | $ | (6,215 | ) | | $ | 19,169 | | | $ | 30,113 | |
| | | | | | | | | | | | | |
| Operations Expense/Affiliates | | | | | | | | | | | | |
| SJI | | $ | 6,957 | | | $ | 6,650 | | | $ | 7,434 | |
| SJIS | | | 4,154 | | | | 4,550 | | | | 5,373 | |
| Millennium | | | 2,982 | | | | 2,872 | | | | 2,743 | |
| Other | | | (226 | ) | | | 139 | | | | - | |
| Total Operations Expense/Affiliates | | $ | 13,867 | | | $ | 14,211 | | | $ | 15,550 | |
6. INCOME TAXES AND CREDITS:
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):
| | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Tax at Statutory Rate | | $ | 23,078 | | | $ | 22,637 | | | $ | 21,206 | |
| Increase (Decrease) Resulting from: | | | | | | | | | | | | |
| State Income Taxes | | | 4,491 | | | | 4,396 | | | | 4,107 | |
| Amortization of Investment Tax Credits | | | (318 | ) | | | (320 | ) | | | (325 | ) |
| ESOP Dividend | | | (736 | ) | | | (610 | ) | | | (674 | ) |
| Amortization of Flowthrough Depreciation | | | 664 | | | | 664 | | | | 664 | |
| Other - Net | | | (671 | ) | | | (115 | ) | | | (167 | ) |
| Net Income Taxes | | $ | 26,508 | | | $ | 26,652 | | | $ | 24,811 | |
| | | | | | | | | | | | | |
| The provision for Income Taxes is comprised of the following (in thousands): | | | | |
| | | | | |
| | | 2008 | | | 2007 | | | 2006 | |
| Current: | | | | | | | | | |
| Federal | | $ | 1,042 | | | $ | 9,951 | | | $ | 16,556 | |
| State | | | 4,088 | | | | 3,744 | | | | 3,829 | |
| Total Current | | | 5,130 | | | | 13,695 | | | | 20,385 | |
| Deferred: | | | | | | | | | | | | |
| Federal | | | 18,877 | | | | 10,258 | | | | 2,262 | |
| State | | | 2,819 | | | | 3,019 | | | | 2,489 | |
| Total Deferred | | | 21,696 | | | | 13,277 | | | | 4,751 | |
| Investment Tax Credits | | | (318 | ) | | | (320 | ) | | | (325 | ) |
| Net Income Taxes | | $ | 26,508 | | | $ | 26,652 | | | $ | 24,811 | |
Investment Tax Credits were deferred and continue to be amortized at the annual rate of 3%, which approximates the life of related assets.
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 at December 31 (in thousands):
| | | 2008 | | | 2007 | |
| | | | | | | |
| Current: | | | | | | |
| Deferred Fuel Costs - Net | | $ | 4,121 | | | $ | 4,121 | |
| Uncollectibles | | | (1,208 | ) | | | (976 | ) |
| Deferred Revenues | | | 9,055 | | | | 8,061 | |
| Section 461 Prepayments | | | 514 | | | | 866 | |
| Other | | | (7 | ) | | | (490 | ) |
| Current Deferred Tax Liability - Net | | $ | 12,475 | | | $ | 11,582 | |
| | | | | | | | | |
| Noncurrent: | | | | | | | | |
| Book Versus Tax Basis of Property | | $ | 174,208 | | | $ | 156,634 | |
| Deferred Fuel Costs - Net | | | 5,470 | | | | 5,141 | |
| Environmental | | | 20,608 | | | | 11,068 | |
| Deferred Regulatory Costs | | | 1,246 | | | | 1,238 | |
| Deferred State Tax | | | (7,366 | ) | | | (6,331 | ) |
| Investment Tax Credit Basis Gross-Up | | | (944 | ) | | | (1,107 | ) |
| Deferred Pension & Other Post Retirement Benefits | | | 32,311 | | | | 15,239 | |
| Pension & Other Post Retirement Benefits | | | (27,063 | ) | | | (9,021 | ) |
| Deferred Revenues | | | (11,226 | ) | | | (3,726 | ) |
| Other | | | (194 | ) | | | (881 | ) |
| Noncurrent Deferred Tax Liability - Net | | $ | 187,050 | | | $ | 168,254 | |
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. As of December 31, 2008 and 2007, income taxes due from SJI were approximately $5.8 million and $4.3 million, respectively, and are included in the balance sheets under the caption, Prepaid Taxes.
On January 1, 2007 SJG adopted the provisions of FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes.” As a result of the implementation of FIN 48, SJG recognized a $0.4 million reduction to beginning retained earnings as a cumulative effect adjustment and a noncurrent deferred tax asset of $1.1 million. A reconciliation of unrecognized tax benefits is as follows (in thousands):
| | | 2008 | | | 2007 | |
| | | | | | | |
| Balance at January 1, | | $ | 907 | | | $ | 1,112 | |
| Increase as a result of tax positions taken in prior years | | | 253 | | | | 28 | |
| Decrease due to a lapse in the statute of limitations | | | (250 | ) | | | (233 | ) |
| Balance at December 31, | | $ | 910 | | | $ | 907 | |
The total unrecognized tax benefit as of December 31, 2008 is $0.9 million, not including $0.6 million of accrued interest and penalty. The total unrecognized tax benefits as of December 31, 2007 were $0.9 million, not including $0.5 million of accrued interest and penalties. The amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is not significant. Our policy is to record interest and penalties related to unrecognized tax benefits as interest expense and other expense respectively. These amounts were not significant in 2008. There have been no material changes to the unrecognized tax benefits during 2008 and we do not anticipate any significant changes in the total unrecognized tax benefits within the next 12 months.
The unrecognized tax benefits are primarily related to an uncertainty of state income tax issues and the timing of certain deductions taken on our income tax returns. Federal income tax returns from 2005 forward and state income tax returns primarily from 2004 forward are open and subject to examination.
7. LONG-TERM DEBT: (A)
A schedule of our long-term debt as of December 31, including current maturities, is as follows (in thousands):
| | | | | 2008 | | | 2007 | |
| | | | | | | |
| First Mortgage Bonds: (B) | | | | | | |
| | 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 | |
| | 5.387 | % | Series due 2015 | | | 10,000 | | | | 10,000 | |
| | 6.50 | % | Series due 2016 | | | 9,873 | | | | 9,873 | |
| | 4.60 | % | Series due 2016 | | | 17,000 | | | | 17,000 | |
| | 5.437 | % | Series due 2016 | | | 10,000 | | | | 10,000 | |
| | 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 | |
| | 5.587 | % | Series due 2019 | | | 10,000 | | | | 10,000 | |
| | 7.7 | % | Series due 2027 | | | 35,000 | | | | 35,000 | |
| | 5.55 | % | Series due 2033 | | | 32,000 | | | | 32,000 | |
| | 6.213 | % | Series due 2034 | | | 10,000 | | | | 10,000 | |
| | 5.45 | % | Series due 2035 | | | 10,000 | | | | 10,000 | |
| Series A 2006 Tax-Exempt First Mortgage Bonds | | | | | | | | |
| Variable Rate, due 2036 (C) | | | 25,000 | | | | 25,000 | |
| | | | | | | | | | | | |
| Total Long-Term Debt Outstanding | | | 294,873 | | | | 294,873 | |
| Current Portion of Long-Term Debt (C) | | | (25,000 | ) | | | - | |
| Long-Term Debt | | | | $ | 269,873 | | | $ | 294,873 | |
| (A) | Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2009, $0; 2010, $10,000; 2011, $25,000; 2012, $2,187; 2013, $25,000 (See Note (c) below). Our long-term debt agreements contain no financial covenants. |
| (B) | Our First Mortgage dated October 1, 1947, as supplemented, securing the First Mortgage Bonds constitutes a direct first mortgage lien on substantially all utility plant. |
| (C) | On April 20, 2006, SJG issued $25.0 million of tax-exempt, auction-rate debt through the New Jersey Economic Development Authority (NJEDA) under its $150.0 million MTN Program. These bonds were repurchased by the Company in June 2008 and remarketed to the public in August 2008 as variable-rate demand bonds with liquidity support provided by a letter of credit from a commercial bank. The letter of credit expires in August 2009, and as such, these bonds have been included in the current portion of long-term debt. Material terms of the original bonds, such as the 2036 maturity date, floating rate interest that resets weekly, and a first mortgage collateral position, remain unchanged. |
We estimated the fair values of our long-term debt, including current maturities, as of December 31, 2007 and 2006, to be $326.1 million and $318.4 million, respectively. Carrying amounts as of both December 31, 2008 and 2007 are $294.9 million. 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.
8. FINANCIAL INSTRUMENTS:
Restricted Investments - In accordance with the terms of our tax-exempt first mortgage bonds, unused proceeds are required to be escrowed pending approved construction expenditures. As of December 31, 2008 and 2007, the escrowed proceeds, including interest earned, totaled $0.1 million and $2.2 million, respectively.
Long-Term Receivables – SJG provides financing to customers for the purpose of attracting conversions to natural gas heating systems from competing fuel sources. The terms of these loans call for customers to make monthly payments over a period of up to five years with no interest. The carrying amounts of such loans were $10.1 million and $8.4 million as of December 31, 2008 and 2007, respectively. The current portion of these receivables is reflected in Accounts Receivable and the non-current portion is reflected in Long-Term Receivables on the balance sheet. The carrying amounts noted above are net of unamortized discounts resulting from imputed interest in the amounts of $1.2 million and $0.7 million as of December 31, 2008 and 2007, respectively. The annual amortization to interest is not material to SJG’s financial statements.
Other Financial Instruments - The carrying amounts of our other financial instruments approximate their fair values at December 31, 2008 and 2007.
9. UNUSED LINES OF CREDIT:
Bank credit available to SJG totaled $203.0 million at December 31, 2008, of which $114.6 million was used. Those bank facilities consist of a $100.0 million credit facility, a $40.0 million line of credit, a $10.0 million line of credit and $53.0 million of uncommitted bank lines. The $100.0 million and $40.0 million revolving credit facilities expire in August 2011 and December 2009, respectively, and both contain one financial covenant regarding the ratio of total debt to total capitalization, measured on a quarterly basis. SJG was in compliance with these covenants as of December 31, 2008. Borrowings under these credit facilities are at market rates. The weighted average borrowing cost, which changes daily, was 1.06%, 5.30% and 5.71% at December 31, 2008, 2007, and 2006, respectively.
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 $289.2 million. Our total common equity balance was $401.7 million at December 31, 2008.
Various loan agreements also contain potential restrictions regarding the amount of cash dividends or other distributions that we may pay on our common stock. As of December 31, 2008, these loan restrictions did not affect the amount that may be distributed from our retained earnings.
We received no equity infusions from SJI in 2008, 2007 or 2006. Future equity contributions will occur on an as needed basis.
11. PENSION AND OTHER POSTRETIREMENT BENEFITS:
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. Participation in the SJI qualified defined benefit pension plans was closed to new employees beginning in 2003; however, employees who are not eligible for these pension plans are eligible to receive an enhanced version of SJI’s 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.
Net periodic benefit cost related to the employee and officer pension and other postretirement benefit plans consisted of the following components (in thousands):
| | | | | | Pension Benefits | | | | | | Other Postretirement Benefits | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Service Cost | | $ | 2,408 | | | $ | 2,442 | | | $ | 2,322 | | | $ | 605 | | | $ | 661 | | | $ | 656 | |
| Interest Cost | | | 6,843 | | | | 6,376 | | | | 5,988 | | | | 2,497 | | | | 2,295 | | | | 2,279 | |
| Expected Return on Plan Assets | | | (8,394 | ) | | | (8,068 | ) | | | (7,518 | ) | | | (1,995 | ) | | | (1,895 | ) | | | (1,617 | ) |
| Amortizations: | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior Service Cost (Credits) | | | 239 | | | | 239 | | | | 389 | | | | (254 | ) | | | (254 | ) | | | (264 | ) |
| Actuarial Loss | | | 1,365 | | | | 1,624 | | | | 2,032 | | | | 677 | | | | 560 | | | | 789 | |
| Net Periodic Benefit Cost | | | 2,461 | | | | 2,613 | | | | 3,213 | | | | 1,530 | | | | 1,367 | | | | 1,843 | |
| Capitalized Benefit Costs | | | (1,073 | ) | | | (1,131 | ) | | | (1,574 | ) | | | (765 | ) | | | (648 | ) | | | (903 | ) |
| Affiliate SERP Allocations | | | (315 | ) | | | (232 | ) | | | (247 | ) | | | - | | | | - | | | | - | |
| Total Net Periodic Benefit Expense | | $ | 1,073 | | | $ | 1,250 | | | $ | 1,392 | | | $ | 765 | | | $ | 719 | | | $ | 940 | |
Capitalized benefit costs reflected in the table above relate to our construction program.
In 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158). This statement requires companies with publicly traded equity securities that sponsors a postretirement benefit plan to fully recognize, as an asset or liability, the overfunded or underfunded status of its benefit plans and recognize changes in the funded status in the year in which the changes occur. Changes in funded status are generally reported in Other Comprehensive Loss; however, since we recover all prudently incurred pension and postretirement benefit costs from our ratepayers, a significant portion of the charges resulting from the recording of additional liabilities under this statement are reported as regulatory assets (See Note 3).
The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2009 are as follows (in thousands):
| | | Pension Benefits | | | Other Postretirement Benefits | |
| Prior Service Costs (Credits) | | $ | 232 | | | $ | (254 | ) |
| Net Actuarial Loss | | $ | 3,754 | | | $ | 1,616 | |
The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2009 are as follows (in thousands):
| | | Pension Benefits | | | Other Postretirement Benefits | |
| Net Actuarial Loss | | $ | 824 | | | $ | - | |
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 | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | | | | | | | | | | | |
Change in Benefit Obligations: | | | | | | | | | | | | |
| Benefit Obligation at Beginning of Year | | $ | 109,301 | | | $ | 109,735 | | | $ | 39,499 | | | $ | 41,272 | |
| Service Cost | | | 2,408 | | | | 2,442 | | | | 605 | | | | 661 | |
| Interest Cost | | | 6,843 | | | | 6,376 | | | | 2,497 | | | | 2,295 | |
| Actuarial Loss / (Gain) | | | 5,071 | | | | (3,188 | ) | | | 2,947 | | | | (1,910 | ) |
| Retiree Contributions | | | - | | | | - | | | | 164 | | | | 147 | |
| Benefits Paid | | | (6,302 | ) | | | (6,064 | ) | | | (3,224 | ) | | | (2,966 | ) |
| Benefit Obligation at End of Year | | $ | 117,321 | | | $ | 109,301 | | | $ | 42,488 | | | $ | 39,499 | |
| | | | | | | | | | | | | | | | | |
| Change in Plan Assets: | | | | | | | | | | | | | | | | |
| Fair Value of Plan Assets at Beginning of Year | | $ | 96,541 | | | $ | 94,603 | | | $ | 28,284 | | | $ | 26,274 | |
| Actual Return on Plan Assets | | | (25,384 | ) | | | 7,172 | | | | (8,094 | ) | | | 1,273 | |
| Employer Contributions | | | 5,733 | | | | 830 | | | | 3,535 | | | | 3,556 | |
| Retiree Contributions | | | - | | | | - | | | | 164 | | | | 147 | |
| Benefits Paid | | | (6,302 | ) | | | (6,064 | ) | | | (3,224 | ) | | | (2,966 | ) |
| Fair Value of Plan Assets at End of Year | | $ | 70,588 | | | $ | 96,541 | | | $ | 20,665 | | | $ | 28,284 | |
Funded Status at End of Year: | | | | | | | | | | | | |
| Accrued Net Benefit Cost at End of Year | | $ | (46,733 | ) | | $ | (12,760 | ) | | $ | (21,823 | ) | | $ | (11,215 | ) |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in the Statement | | | | | | | | | | | | | | | | |
| of Financial Position Consist of: | | | | | | | | | | | | | | | | |
| Noncurrent Asset | | $ | - | | | $ | 1,472 | | | $ | - | | | $ | - | |
| Current Liabilities | | | (991 | ) | | | (765 | ) | | | - | | | | - | |
| Noncurrent Liabilities | | | (45,742 | ) | | | (13,467 | ) | | | (21,823 | ) | | | (11,215 | ) |
| Net Amount Recognized at End of Year | | $ | (46,733 | ) | | $ | (12,760 | ) | | $ | (21,823 | ) | | $ | (11,215 | ) |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in Regulatory Assets | | | | | | | | | | | | | | | | |
| Consist of: | | | | | | | | | | | | | | | | |
| Prior Service Costs (Credit) | | $ | 1,381 | | | $ | 1,620 | | | $ | (723 | ) | | $ | (977 | ) |
| Net Actuarial Loss | | | 54,393 | | | | 18,913 | | | | 23,599 | | | | 11,240 | |
| | | $ | 55,774 | | | $ | 20,533 | | | $ | 22,876 | | | $ | 10,263 | |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in Accumulated Other | | | | | | | | | | | | | | | | |
| Comprehensive Loss Consist of: | | | | | | | | | | | | | | | | |
| Net Actuarial Loss | | $ | 9,212 | | | $ | 7,208 | | | $ | - | | | $ | - | |
Details of the activity within the Regulatory Asset and Accumulated Other Comprehensive Loss associated with Pension and Other Postretirement Benefits are as follows (in thousands):
| | | | | | Accumulated Other | |
| | | Regulatory Assets | | | Comprehensive Loss (pre-tax) | |
| | | | | | Other | | | | | | Other | |
| | | Pension | | | Postretirement | | | Pension | | | Postretirement | |
| | | Benefits | | | Benefits | | | Benefits | | | Benefits | |
| Balance at December 31, 2006 | | $ | 25,235 | | | $ | 11,856 | | | $ | 6,661 | | | $ | - | |
| | | | | | | | | | | | | | | | | |
| Amounts Arising during the Period: | | | | | | | | | | | | | | | | |
| Net Actuarial (Gain) Loss | | | (3,495 | ) | | | (1,287 | ) | | | 1,203 | | | | - | |
| Amounts Amortized to Net Periodic Costs: | | | | | | | | | | | | | |
| Net Actuarial Loss | | | (968 | ) | | | (560 | ) | | | (656 | ) | | | - | |
| Prior Service (Cost) Credit | | | (239 | ) | | | 254 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | $ | 20,533 | | | $ | 10,263 | | | $ | 7,208 | | | $ | - | |
| | | | | | | | | | | | | | | | | |
| Amounts Arising during the Period: | | | | | | | | | | | | | | | | |
| Net Actuarial Loss | | | 36,171 | | | | 13,036 | | | | 2,678 | | | | - | |
| Amounts Amortized to Net Periodic Costs: | | | | | | | | | | | | | |
| Net Actuarial Loss | | | (691 | ) | | | (677 | ) | | | (674 | ) | | | - | |
| Prior Service (Cost) Credit | | | (239 | ) | | | 254 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2008 | | $ | 55,774 | | | $ | 22,876 | | | $ | 9,212 | | | $ | - | |
The projected benefit obligation (PBO) and accumulated benefit obligation (ABO) of our qualified employee pension plans were $100.2 million and $90.8 million, respectively, as of December 31, 2008, and $95.1 million and $85.7 million, respectively, as of December 31, 2007. The ABO of these plans exceeded the value of the plan assets as of December 31, 2008. The value of these assets can be seen in the tables above. The PBO and ABO for our non-funded SERP, which had accumulated benefits in excess of plan assets, were $17.1 million and $16.7 million, respectively, as of December 31, 2008, and $14.2 million and $13.6 million, respectively, as of December 31, 2007. The SERP is reflected in the tables above and has no assets.
The weighted-average assumptions used to determine benefit obligations at December 31 were:
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | | | | | | | | | | | |
| Discount Rate | | | 6.24 | % | | | 6.36 | % | | | 6.24 | % | | | 6.36 | % |
| 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:
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2008 | | | 2007 | | | 2006 | | | 2008 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 6.36 | % | | | 6.04 | % | | | 5.84 | % | | | 6.36 | % | | | 6.04 | % | | | 5.84 | % |
| Expected Long-Term Return on Plan Assets | | | 8.50 | % | | | 8.75 | % | | | 8.75 | % | | | 7.00 | % | | | 7.25 | % | | | 7.25 | % |
| Rate of Compensation Increase | | | 3.60 | % | | | 3.60 | % | | | 3.60 | % | | | - | | | | - | | | | - | |
The discount rates used to determine the benefit obligations at December 31, 2008 and 2007, which are used to determine the net periodic benefit cost for the subsequent year, were 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.
The expected long-term return on plan assets was based on SJI’s current investment mix as described under Plan Assets below.
All obligations disclosed herein reflect the use of the RP 2000 mortality tables.
The assumed health care cost trend rates at December 31 were:
| | | 2008 | | | | 2007 | |
| | | | | | | | |
| Medical Care and Drug Cost Trend Rate Assumed for Next Year | | 9.0 | % | | | 10.0 | % |
| Dental Care Cost Trend Rate Assumed for Next Year | | | 6.33 | % | | | 6.33 | % |
| 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 | | | 2012 | | | | 2012 | |
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 | | $ | 66 | | | $ | (60 | ) |
| Effect on Postretirement Benefit Obligation | | | 1,105 | | | | (986 | ) |
Plan Assets - SJG’s weighted-average asset allocations at December 31, 2008 and 2007, by asset category are as follows:
| | | | | | | | | Other | |
| | | Pension Benefits | | | Postretirement Benefits | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | | | | | | | | | | | | |
| Asset Category: | | | | | | | | | | | | |
| U.S. Equity Securities | | | 47 | % | | | 50 | % | | | 39 | % | | | 47 | % |
| International Equity Securities | | | 12 | | | | 15 | | | | 12 | | | | 15 | |
| Fixed Income | | | 41 | | | | 35 | | | | 49 | | | | 38 | |
| | | | | | | �� | | | | | | | | | | |
| 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. However, due to dramatic decline in the equity markets in the latter part of 2008, this allocation policy was suspended to prevent further transfer of fixed income assets into equities. Upon indication that the equity markets are in recovery, this policy will be revisited. 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). These restrictions are only applicable to individual investment managers with separately managed portfolios and do not apply to mutual funds or commingled trusts.
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 | |
| | | | | | | |
| 2009 | | $ | 6,475 | | | $ | 3,694 | |
| 2010 | | $ | 6,592 | | | $ | 3,791 | |
| 2011 | | $ | 6,767 | | | $ | 3,671 | |
| 2012 | | $ | 6,983 | | | $ | 3,651 | |
| 2013 | | $ | 7,325 | | | $ | 3,617 | |
| 2014 -2018 | | $ | 42,460 | | | $ | 18,037 | |
Contributions - We made a contribution of approximately $4.8 million to our employee pension plan in 2008. While SJG has no obligation to make a contribution in 2009, we currently expect to make a contribution in order to improve the funded status of the plans and mitigate the expected increase in expense in 2009. Payments related to the unfunded SERP plan are expected to approximate $1.0 million in 2009. 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 participants’ contributions up to 6% of base compensation. For 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. Employees not eligible for the pension plans also receive a year-end contribution of $500 if fewer than 10 years of service, or $1,000 if 10 or more years of service. The amount expensed and contributed for the matching provision of the Savings Plan approximated $0.7 million in each of the years 2008 and 2007, and 2006.
12. COMMITMENTS AND CONTINGENCIES:
Standby Letter Of Credit - SJG provided a $25.3 million letter of credit, under a separate credit facility from those it borrows under to provide liquidity support for the remarketing of variable-rate demand bonds issued through the NJEDA. The bonds were used to finance the expansion of SJG’s natural gas distribution system as discussed in Note 7. This letter of credit expires in August 2009.
Gas Supply Related 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 2009. However, discussions are taking place to extend the referenced agreement. The transportation and storage service agreements between us and our interstate pipeline suppliers were made under FERC approved tariffs. Our cumulative obligation for demand charges and reservation fees paid to suppliers for these services is approximately $4.0 million per month and is 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 reasonably estimate the amount or range of amounts of probable settlement costs or other charges. 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.
Collective Bargaining Agreements - Unionized personnel represent 67% of our workforce at December 31, 2008. The Company has collective bargaining agreements with two unions who represent these employees: the International Brotherhood of Electrical Workers (“IBEW”) and the International Association of Machinists and Aerospace Workers (“IAM”). The Company and the IBEW have recently agreed to a new 4-year contract. The IAM is asserting that the labor agreement, which the Company believes expired on January 14, 2009, is evergreen for one year from that expiration date. The Company has filed a charge with the National Labor Relations Board for a determination on the matter and we await the Board’s decision.
Environmental Remediation Costs - We incurred and recorded costs for environmental cleanup of 12 sites where we or our predecessors operated gas manufacturing plants. 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 $23.7 million through December 31, 2008.
Since the early 1980s, we accrued environmental remediation costs of $211.2 million, of which $148.1 million has been spent as of December 31, 2008. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):
| | | 2008 | | | 2007 | |
| | | | | | | |
| Beginning of Year | | $ | 73,880 | | | $ | 67,794 | |
| Accruals | | | 14,622 | | | | 18,666 | |
| Expenditures | | | (24,409 | ) | | | (12,580 | ) |
| | | | | | | | | |
| End of Year | | $ | 64,093 | | | $ | 73,880 | |
The balances are segregated between current and noncurrent on the balance sheets under the captions Current Liabilities and Regulatory and Other Noncurrent Liabilities.
Management estimates that undiscounted future costs to clean up our sites will range from $64.1 million to $235.1 million. We recorded the lower end of this range, $64.1 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. Six of our sites comprise the majority of these estimates, ranging from a low of $49.0 million to a high of $172.4 million. 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 remediation efforts at our six most significant sites include the following:
Site 1 - A remedial action work plan has been approved by the New Jersey Department of Environmental Protection (NJDEP). Remaining steps to remediate include regulatory permitting and 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 ongoing implementation of the approved remedy for stream sediments as well as acceptance of the selected remedy by affected property owners.
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 and gaining regulatory and property owner approval of the selected remedy.
Site 4 - Remedial action activities are planned at this site. Remaining steps to remediate include continuing implementation of the NJDEP approved Remedial Action Work Plan of impacted soil and groundwater.
Site 5 – Various remedial investigation and action activities are ongoing at this site. An interim remedial measure has been implemented and a remedial action work plan has been prepared and submitted to the NJDEP for an off site interim remedial measure. Remaining steps to implement the off site interim remedial measure include regulatory approval, remedial investigation of bay sediments, as well as acceptance of the selected remedy by affected property owners. Remaining steps to remediate soil and groundwater include completing the remedial investigation of impacted soil and groundwater in preparation for selecting the appropriate action and implementation and gaining regulatory and property owner approval of the selected remedy.
Site 6 – 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 and gaining regulatory and property owner approval of the selected remedy.
13. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES:
Effective January 1, 2008, SJG adopted the provisions of FAS 157 that relate to financial assets and financial liabilities as discussed in Note 1. FAS 157 establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques. The levels of the hierarchy are described below:
| | · | Level 1: Observable inputs such as quoted prices in active markets for identical assets or liabilities. |
| | · | Level 2: Inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly; these include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. |
| | · | Level 3: Unobservable inputs that reflect the reporting entity’s own assumptions. |
Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of financial assets and financial liabilities and their placement within the fair value hierarchy.
For financial assets and financial liabilities measured at fair value on a recurring basis, information about the fair value measurements for each major category as of December 31, 2008 is as follows (in thousands):
| | | Total | | | Level 1 | | | Level 2 | | | Level 3 | |
Assets - | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Available-for-Sale Securities (A) | | $ | 4,841 | | | $ | 4,841 | | | $ | - | | | $ | - | |
| Derivatives – Energy Related Assets (B) | | | 395 | | | | 360 | | | | 35 | | | | - | |
| | | $ | 5,236 | | | $ | 5,201 | | | $ | 35 | | | $ | - | |
| | | | | | | | | | | | | | | | | |
Liabilities - | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Derivatives – Energy Related Liabilities (B) | | $ | 29,365 | | | $ | 28,845 | | | $ | 520 | | | $ | - | |
| Derivatives – Other (C) | | | 7,578 | | | | - | | | | 7,578 | | | | - | |
| | | $ | 36,943 | | | $ | 28,845 | | | $ | 8,098 | | | $ | - | |
| | | | | | | | | | | | | | | | | |
(A) Available-for-Sale Securities are valued using the quoted principal market close prices that are provided by the trustees of these securities.
(B) Derivatives – Energy Related Assets and Liabilities are traded in both exchange-based and non-exchange-based markets. Exchange-based contracts are valued using unadjusted quoted market sources in active markets and are categorized in Level 1 in the fair value hierarchy. Certain non-exchange-based contracts are valued using indicative price quotations available through brokers or over-the-counter, on-line exchanges and, are categorized in Level 2. These price quotations reflect the average of the bid-ask mid-point prices and are obtained from sources that management believes provide the most liquid market. Management reviews and corroborates the price quotations to ensure the prices are observable which includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration.
(C) Derivatives – Other are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
| 14. | AVAILABLE–FOR–SALE SECURITIES: |
The Company's portfolio of investments consists of five highly diversified funds which are not used for working capital purposes. These funds are in an unrealized loss position as of December 31, 2008. Due to the nature of the underlying securities, these funds as a whole are susceptible to changes in the economy and have been adversely affected by the economic slowdown, particularly during the fourth quarter of 2008 when the Company's investments became impaired. The Company has evaluated the near-term prospects of the overall funds in relation to the severity and duration of the impairment. Based on that evaluation, the Company recorded an insignificant impairment loss during the fourth quarter of 2008. Due to the Company's ability and intent to hold the remaining funds for a reasonable period of time sufficient for a forecasted recovery of fair value, the Company does not consider these remaining investments to be other-than-temporarily impaired at December 31, 2008.
The following table shows the gross unrealized losses and fair value of the Company's Available-for-Sale Securities with unrealized losses that are not deemed to be other-than-temporarily impaired (in thousands), aggregated by length of time that the individual funds have been in a continuous unrealized loss position at December 31, 2008.
| | Less than 12 Months | Greater Than 12 Months | Total |
| | | | | | | |
| | Fair Value | Unrealized Losses | Fair Value | Unrealized Losses | Fair Value | Unrealized Losses |
| Marketable Equity Securities | $3,609 | $1,218 | $0 | $0 | $3,609 | $1,218 |
| 15. | QUARTERLY RESULTS OF OPERATIONS - UNAUDITED: |
The summarized quarterly results of our operations are as follows (in thousands):
| | | 2008 Quarter Ended | | | 2007 Quarter Ended | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 237,904 | | | $ | 93,571 | | | $ | 64,563 | | | $ | 172,008 | | | $ | 277,864 | | | $ | 95,996 | | | $ | 84,420 | | | $ | 172,267 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of Sales | | | 162,917 | | | | 60,263 | | | | 41,201 | | | | 119,022 | | | | 205,544 | | | | 63,848 | | | | 62,223 | | | | 121,419 | |
| Operation and Maintenance | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Including Fixed Charges | | | 28,257 | | | | 26,134 | | | | 25,408 | | | | 28,737 | | | | 26,667 | | | | 23,890 | | | | 24,071 | | | | 29,052 | |
| Income Taxes (Benefit) | | | 17,530 | | | | 2,482 | | | | (1,306 | ) | | | 7,802 | | | | 16,870 | | | | 2,839 | | | | (1,278 | ) | | | 8,221 | |
| Energy and Other Taxes | | | 4,357 | | | | 1,711 | | | | 1,356 | | | | 3,203 | | | | 4,624 | | | | 1,872 | | | | 1,307 | | | | 3,026 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Expenses | | | 213,061 | | | | 90,590 | | | | 66,659 | | | | 158,764 | | | | 253,705 | | | | 92,449 | | | | 86,323 | | | | 161,718 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income and Expense | | | 170 | | | | 457 | | | | 242 | | | | (410 | ) | | | 100 | | | | 356 | | | | 157 | | | | 1,060 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) Applicable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| to Common Stock | | $ | 25,013 | | | $ | 3,438 | | | $ | (1,854 | ) | | $ | 12,834 | | | $ | 24,259 | | | $ | 3,903 | | | $ | (1,746 | ) | | $ | 11,609 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| NOTE: Because of the seasonal nature of our 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
The Company’s management, with the participation of its chief executive officer and chief financial officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2008. Based on that evaluation, the Company’s chief executive officer and chief financial officer concluded that the disclosure controls and procedures employed at the Company are effective.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined under Exchange Act Rules 13a-15(f). The Company’s internal control system is designed to provide reasonable assurance to its management and board of directors regarding the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under that framework, management concluded that our internal control over financial reporting was effective as of December 31, 2008.
This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. The Company's internal control over financial reporting was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
Changes in Internal Control over Financial Reporting
There has not been any change in the Company's internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, during the fiscal quarter ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.
Item 11. Executive Compensation
Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.
Item 13. Certain Relationships and Related Transactions
Omitted in accordance with General Instruction I 1(a) and (b) of Form 10-K.
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 2008. In accordance with its charter, the Audit Committee pre-approved all services provided by Deloitte & Touche LLP. Audit services performed consisted of the audits of the financial statements and the preparation of various reports based on those audits and services related to filings with the United States Securities and Exchange Commission and New York Stock Exchange.
Audit Fees
The aggregate fees billed for the audit of SJG’s financial statements by Deloitte & Touche LLP totaled $356,000 and $320,000 in fiscal years 2008 and 2007, 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, March 2, 2009. See Item 8.
2 - Supplementary Financial Information
Report of the Independent Registered Public Accounting Firm on financial statement schedule. See Item 8.
Schedule II - Valuation and Qualifying Accounts. See page 61.
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 18, 2008 (filed herewith). | |
(4)(a) | Form of Stock Certificate 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)(ii) | 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). |
(4)(b)(iii) | Twenty-First Supplemental Indenture dated as of March 1, 1997. | Incorporated by reference from Exhibit (4)(b)(xviv) of Form 10-K of SJI for 1997 (1-6364). |
(4)(b)(iv) | 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)(v) | 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)(vi) | 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)(b)(vii) | Amendment to Twenty-Fourth Supplemental Indenture dated as of March 31, 2006. | Incorporated by reference from Exhibit 4 of Form 8-K as filed April 26, 2006. |
| (4)(b)(viii) | Loan Agreement by and between New Jersey Economic Development Authority as SJG dated April 1, 2006. | Incorporated by reference from Exhibit 10 of Form 8-K of SJG as filed April 26, 2006. |
(4)(c)(i) | Medium Term Note Indenture of Trust dated October 1, 1998. | Incorporated by reference from Exhibit (4)(e) of Form S-3 (333-62019). |
(4)(c)(ii) | First Supplement to Indenture of Trust dated as of June 29, 2000. | Incorporated by reference from Exhibit 4.1 of Form 8-K of SJG dated July, 12, 2001. |
(4)(c)(iii) | Second Supplement to Indenture of Trust dated as of July 5, 2000. | Incorporated by reference from Exhibit 4.2 of Form 8-K of SJG dated July, 12, 2001. |
(4)(c)(iv) | Third Supplement to Indenture of Trust dated as of July 9, 2001. | Incorporated by reference from Exhibit 4.3 of Form 8-K of SJG dated July, 12, 2001. |
Exhibit Number | Description | Reference |
(10)(a)(i) | 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)(a)(ii) | 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-& (2-56233). |
(10)(a)(iii) | 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 for 1993 (1-6364). |
(10)(a)(iv) | 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 for 1988 (1-6364). |
(10)(b)(i) | 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 for 1991 (1-6364). |
(10)(b)(ii) | 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 for 1993 (1-6364). |
(10)(b)(iii) | CNJEP Service agreement between South Jersey Gas Company and Transco dated June 27, 2005. | Incorporated by reference from Exhibit (10)(i)(l) of Form 10-K for 2005 (1-6364). |
(10)(c)(i) | 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 for 1993 (1-6364). |
(10)(c)(ii) | 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 for 1993 (1-6364). |
(10)(c)(iii) | 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 for 1993 (1-6364). |
(10)(c)(iv) | 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 for 1993 (1-6364). |
(10)(d)(i) | 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 for 1993 (1-6364). |
Exhibit Number | Description | Reference |
(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)* | 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)(iii)* | 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)(iv)* | Form of Officer Employment Agreement between certain officers and either South Jersey Industries, Inc. or its subsidiaries. | Incorporated by reference from Exhibit (10)(e)(iii) of Form 10-K of SJI for 2008 (1-6364). |
(10)(h)(v)* | Schedule of Officer Employment Agreements. | Incorporated by reference from Exhibit (10)(e)(iv) of Form 10-K of SJI for 2008. |
(10)(h)(vi)* | Officer Severance Benefit Program for all officers. | Incorporated by reference from Exhibit (10)(l)(g) of Form 10-K of SJI for 1985 (1-6364). |
(10)(i)(i) | Five-year Revolving Credit Agreement for SJG. | Incorporated by reference from Exhibit 10 of Form 8-K as filed on August 8, 2006. |
(10)(i)(ii) | Loan Agreement between Toronto Dominion (New York) LLC and SJG dated December 15, 2008 ( filed herewith). | |
(12) | Calculation of Ratio of Earnings to Fixed Charges (Before Federal Income Taxes) (filed herewith). | |
(14) | Code of Ethics | Incorporated by reference from Exhibit (14) of Form 10-K of SJI as filed for 2007. |
(21) | Subsidiaries of the Registrant (filed herewith). | |
(23) | Independent Registered Public Accounting Firm’s Consent (filed herewith). | |
Exhibit Number | Description | Reference |
(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 4, 2009
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 |
| | | |
| | | |
/s/ Edward J. Graham | Chairman of the Board, President & Chief Executive Officer | March 4, 2009 |
| (Edward J. Graham) | (Principal Executive Officer) | |
| | | |
| | | |
/s/ David A. Kindlick | Senior Vice President & Chief Financial Officer | March 4, 2009 |
| (David A. Kindlick) | (Principal Financial and Accounting Officer) | |
| | | |
| | | |
/s/ Richard H. Walker, Jr. | Senior Vice President, General Counsel & Secretary | March 4, 2009 |
| (Richard H. Walker, Jr.) | | |
| | | |
| | | |
/s/ Shirli M. Billings | Director | March 4, 2009 |
| (Shirli M. Billings) | | |
| | | |
| | | |
/s/ Thomas A. Bracken | Director | March 4, 2009 |
| (Thomas A. Bracken) | | |
| | | |
| | | |
/s/ Sheila Hartnett-Devlin | Director | March 4, 2009 |
| (Sheila Hartnett-Devlin) | | |
| | | |
| | | |
| | | |
| /s/ William J. Hughes | Director | March 4, 2009 |
| (William J. Hughes) | | |
| | | |
| | | |
| | | |
| /s/ Frederick R. Raring | Director | March 4, 2009 |
| (Frederick R. Raring) | | |
| SOUTH JERSEY GAS COMPANY | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| (In Thousands) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Col. A | | Col. B | | | Col. C | | | Col. D | | | Col. E | |
| | | | | | | | | | | | | | | | |
| | | | | | 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, 2008 | | $ | 3,265 | | | $ | 2,281 | | | $ | 279 | | | $ | 2,197 | | | $ | 3,628 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | | | | | |
| December 31, 2007 | | $ | 2,741 | | | $ | 2,672 | | | $ | 725 | | | $ | 2,873 | | | $ | 3,265 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | | | | | |
| December 31, 2006 | | $ | 3,461 | | | $ | 1,284 | | | $ | (428 | ) | | $ | 1,576 | | | $ | 2,741 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| (a) Recoveries of accounts previously written off and minor adjustments. | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| (b) Uncollectible accounts written off. | | | | | | | | | |
