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, 2007
| [ ] | 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. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes [ ] No [X]
All of the equity securities of the registrant are owned by South Jersey Industries, Inc., its parent company, a 1934 Act reporting company named in the registrants description of its business, which has itself fulfilled its 1934 Act filing requirements.
During the preceding 36 months (and any subsequent period of days) there has not been any default in (1) any of the indebtedness of the registrant or its subsidiaries, and (2) the payment of rentals under material long-term leases (of which there are none).
The registrant meets all of the conditions set forth in General Instruction I 1(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format.
Documents Incorporated by Reference: None
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 SJG 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 dth | = One decatherm |
| | 1 MMdth | = One million decatherms |
| | | |
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 Pipeline Corporation (Transco) and Columbia Gas Transmission Corporation (Columbia). During 2007, SJG purchased and had delivered approximately 45.7 MMdth of natural gas for distribution to both on-system and off-system customers. Of this total, 28.4 MMdth was transported on the Transco pipeline system and 17.3 MMdth was transported on the Columbia pipeline system. SJG also secures firm transportation and other long term services from three additional pipelines upstream of the Transco and Columbia systems. They include Columbia Gulf Transmission Company (Columbia Gulf), Texas Gas Transmission Corporation (Texas Gas) and Dominion Transmission, Inc. (Dominion). Services provided by these upstream pipelines are utilized to deliver gas into either the Transco or Columbia systems for ultimate delivery to SJG. Services provided by all of the above-mentioned pipelines are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). 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. These services include six year-round and one seasonal firm transportation (FT) service arrangements. When combined, these services enable SJG to purchase from third parties and have delivered to its city gate stations by Transco a total of 280,525 dth of gas per day (dth/d). The terms of the year-round agreements extend for various periods through 2025, while the term of the seasonal agreement extends to 2011.
SJG also has seven long-term gas storage service agreements with Transco that, when combined, are capable of storing approximately 6.4 MMdth. 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 dth/d during periods of high demand. The terms of the storage service agreements extend for various periods from 2008 to 2013.
Effective May 1, 2006 SJG permanently released its Transco WSS Storage Service (with a storage capacity of 4.4 MMdth and a maximum withdrawal quantity of 51,837 dth/d to SJRG resulting in significant savings in gas related costs. This action was taken in concert with SJG’s Conservation Incentive Program.
Dominion:
Entering 2007 SJG had three firm transportation services on Dominion which delivered gas to Transco’s Leidy Line for ultimate delivery to SJG city gate stations. Two of these services are associated with storage services which SJG subscribes to with Dominion and Transco, while the third provided a link between SJG’s service on Texas Gas and the Transco Leidy Line system in Pennsylvania. As SJG opted to let its Texas Gas service expire (as noted below), it also chose to allow its FT service on Dominion (unrelated to storage), with a maximum contract quantity of 24,874 dth/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 maximum withdrawal capacity of 10,000 dth/d during the period between November 16 and March 31 of winter season with 423,000 dth 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 dth/d of firm deliverability and extend through October 31, 2009.
SJG also subscribes to a firm storage service from Columbia, through March 31, 2009, which provides a maximum withdrawal quantity of 52,891 dth/d during the winter season with an associated 3.5 MMdth of storage capacity.
Texas Gas:
SJG allowed its firm upstream transportation service on Texas Gas to expire under its terms, effective October 31, 2007, resulting in significant savings in gas supply related costs.
Gas Supplies
SJG had two long-term gas supply agreements with a single producer and marketer that expired on October 31, 2007. Under these agreements, SJG was able to purchase a delivered quantity of up to 7.0 MMdth of natural gas per year. When advantageous to do so, SJG would purchase spot supplies of natural gas in place of or in addition to those volumes reserved under long-term agreements. In recent years, due to increased liquidity in the market place, SJG has replaced its long-term gas supply contracts with short-term agreements and uses financial contracts through SJRG to hedge against forward price risk. Short-term agreements typically extend between one day and several months in duration. As such, the above mentioned long-term contracts were not renewed.
Supplemental Gas Supplies
During 2007 SJG entered into two seasonal Liquefied Natural Gas (LNG) sales agreements with a single third party supplier. The term of one agreement extended through October 29, 2007, and had an associated contract quantity of 220,500 dth. The second agreement, which extends through March 31, 2008, replaced the first agreement and provides SJG with up to 216,000 dth 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 dth of natural gas and has an installed capacity to vaporize up to 96,750 dth 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 dth of gas and injecting up to 10,350 dth/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 was estimated for the 2007-2008 winter season to be 506,949 dth. SJG projects that it has adequate supplies and interstate pipeline entitlements to meet its design requirements. On February 5, 2007, SJG experienced its highest peak-day demand for calendar year 2007 of 432,594 dth with an average temperature of 14.02 degrees F during that day.
Natural Gas Prices
SJG’s average cost of natural gas purchased and delivered in 2007, 2006 and 2005, including demand charges, was $9.07 per dth, $9.27 per dth and $9.36 per dth, 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 396 employees as of December 31, 2007. Of that total, 274 employees are unionized and are covered under collective bargaining agreements that expire in January 2009. We consider relations with employees to be good.
Financial Information About Foreign and Domestic Operations and Export Sales
SJG has no foreign operations and export sales are not a part of its business.
Item 1A. Risk Factors
SJG operates in an environment that involves risks, many of which are beyond our control. The Company has identified the following risk factors that could cause the Company’s operating results and financial condition to be materially adversely affected. Security Holders should carefully consider these risk factors and should also be aware that this list is not all-inclusive of existing risks. In addition, new risks may emerge at any time, and the Company cannot predict those risks or the extent to which they may affect the Company’s businesses or financial performance.
| | • | SJG’s business activities are concentrated in southern New Jersey. Changes in the economies of southern New Jersey and surrounding regions could negatively impact the growth opportunities available to SJG and the financial condition of customers and prospects of SJG. |
| | • | 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 will 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. |
| | • | 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, 2007, there were approximately 107.3 miles of mains in the transmission systems and 5,721 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, 2007, SJG’s utility plant had a gross book value of $1,124.0 million and a net book value, after accumulated depreciation, of $847.7 million. In 2007, $49.8 million was spent on additions to utility plant and there were retirements of property having an aggregate gross book cost of $5.6 million. Construction and remediation expenditures for 2008 are currently expected to approximate $78.5 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 $378.3 million at December 31, 2007.
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, 2007, these restrictions did not affect the amount that may be distributed from SJG’s retained earnings. Dividends of $18.7 million were declared and paid on SJG’s common stock in 2007 and $19.9 million were declared and paid in 2006.
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, | |
| | | | | | | | | | | | | | | | |
| | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 630,547 | | | $ | 642,671 | | | $ | 587,212 | | | $ | 508,827 | | | $ | 536,442 | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 83,989 | | | $ | 81,209 | | | $ | 77,676 | | | $ | 71,451 | | | $ | 65,420 | |
| | | | | | | | | | | | | | | | | | | | | |
| Income before Preferred Dividend Requirement | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,592 | | | $ | 31,597 | | | $ | 26,743 | |
| | | | | | | | | | | | | | | | | | | | | |
| Preferred Dividend Requirements (1) | | | - | | | | - | | | | (45 | ) | | | (135 | ) | | | (135 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Income Applicable to Common Stock | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,547 | | | $ | 31,462 | | | $ | 26,608 | |
| | | | | | | | | | | | | | | | | | | | | |
| 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) | | | 4.1 | x | | | 3.7 | x | | | 4.0 | x | | | 3.9 | x | | | 3.3 | x |
| | | | | | | | | | | | | | | | | | | | | |
| | As of December 31, |
| | | | | | | | | | | | | | | | | | | | | |
| | | 2007 | | | 2006 | | | 2005 | | | 2004 | | | 2003 | |
| | | | | | | | | | | | | | | | | | | | | |
| Property, Plant and Equipment, Net | | $ | 847,691 | | | $ | 821,833 | | | $ | 788,787 | | | $ | 732,781 | | | $ | 684,823 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 1,227,162 | | | $ | 1,228,076 | | | $ | 1,170,975 | | | $ | 1,007,733 | | | $ | 956,537 | |
| | | | | | | | | | | | | | | | | | | | | |
| Capitalization: | | | | | | | | | | | | | | | | | | | | |
| Common Equity (3) | | $ | 378,348 | | | $ | 360,353 | | | $ | 344,568 | | | $ | 302,827 | | | $ | 266,953 | |
| Preferred Stock (1) | | | - | | | | - | | | | - | | | | 1,690 | | | | 1,690 | |
| Long-Term Debt | | | 294,873 | | | | 294,893 | | | | 272,235 | | | | 282,008 | | | | 263,781 | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 673,221 | | | $ | 655,246 | | | $ | 616,803 | | | $ | 586,525 | | | $ | 532,424 | |
| Total Customers | | | 335,663 | | | | 330,049 | | | | 322,424 | | | | 313,579 | | | | 304,562 | |
| | | | | | | | | | | | | | | | | | | | | |
| (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 cash contributions to capital as follows: 2007 and 2006 - none; 2005 - $30.0 million; 2004 - $15.0 million; 2003 - $20.0 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 burgeoning shore communities on the eastern side. Economic development and housing growth have long been 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 now accounts for approximately half of our annual customer growth. The foundation for growth in Atlantic City and the surrounding region rests primarily with new gaming and non-gaming investments that emphasize destination style attractions. The casino industry is expected to remain a significant source of regional economic development going forward. The ripple effect from Atlantic City continues to produce new housing 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 64% 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 industrial parks.
As of December 31, 2007, we served 335,663 residential, commercial and industrial customers in southern New Jersey, compared with 330,049 customers at December 31, 2006. No material part of our business is dependent upon a single customer or a few customers. Gas sales, transportation and capacity release for 2007 amounted to 141.6 MMDth (million decatherms), of which 53.4 MMDth were firm sales and transportation, 3.1 MMDth were interruptible sales and transportation and 85.1 MMDth were off-system sales and capacity release. The breakdown of firm sales and transportation includes 45.7% residential, 23.0% commercial, 23.0% industrial, and 8.3% cogeneration and electric generation. At year-end 2007, we served 312,969 residential customers, 22,220 commercial customers and 474 industrial customers. This includes 2007 net additions of 5,050 residential customers and 564 commercial and industrial 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 2007, off-system sales amounted to 17.7 MMDth and capacity release amounted to 67.4 MMDth.
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 2007 usage by interruptible customers, excluding off-system customers, amounted to 3.1 MMDth, approximately 2.2% 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 — The vibrancy of the economic development in and adjacent to southern New Jersey, our primary area of operations, and related strong demand for new housing enabled our utility to increase its customer base at an average rate of 2.5% over the past five years. In the face of well publicized issues in the new housing market during 2007, net customer growth totaled 1.7% for the year. A smaller, but still significant driver of customer growth is conversion from other heating fuels, such as electric or oil. Conversions have historically accounted for 20-25% of annual utility customer growth. Customers in our service territory typically base their decisions to convert on comparisons of fuel costs and environmental considerations. While housing growth most significantly benefits utility performance, it also translates into additional opportunities to market retail products and services through our nonutility businesses.
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 and commercial 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. The price charged to our periodic customers is set annually, with a regulatory mechanism in place to make limited adjustments to that price during the course of a year. In the event that gas cost increases would justify customer price increases greater than those permitted under the regulatory mechanism, we can petition the BPU for an incremental rate increase. High prices can make it more difficult for our customers to pay their bills and may result in elevated levels of bad-debt expense.
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 offered a voluntary separation program at the end of 2007. Our workforce totaled 396 employees at the end of 2007, with 69% of that total covered under collective bargaining agreements that run through January 2009.
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 50.3% and 47.4% at the end of 2007 and 2006, 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. We derive the fair value for most of the energy-related contracts from markets where the contracts are actively traded and quoted. For other contracts, we use published market surveys and, in certain cases, unrelated third parties to validate managements estimates of contracts’ current value. Market quotes tend to be more plentiful for contracts maturing in two years or less.
Environmental Remediation Costs - We estimate future costs based on projected investigation and work plans using existing technologies. We estimate the range of future costs from $73.9 million to $233.5 million. In preparing financial statements, we record liabilities for future costs using the lower end of the range because a single reliable estimation point is not feasible due to the amount of uncertainty involved in the nature of projected remediation efforts and the long period over which remediation efforts will continue. We update estimates each year to take into account past efforts, changes in work plans, remediation technologies, government regulations and site specific requirements (See Note 12 to the financial statements).
Pension and Other Postretirement Benefit Costs - The costs of providing pension and other postretirement employee benefits are impacted by actual plan experience as well as assumptions of future experience. Employee demographics, plan contributions, investment performance, and assumptions concerning 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 2006 we changed to more current mortality tables (to the RP 2000 table) which resulted in an increase in benefit costs. However, a 20 basis point increase in the discount rate and higher than expected returns on plan assets during 2006 more than offset this increase and 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 are expected to further reduce such benefit costs in 2008.
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, Dominion Transmission, Inc., and Texas Gas Transmission Corporation, 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.
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):
| | | 2007 | | | 2006 | | | 2005 | |
| Net Income Benefit/(Reduction): | | | | | | | | | |
TAC | | $ | - | | | $ | 5.1 | | | $ | (0.2 | ) |
CIP – Weather Related | | | 1.6 | | | | 2.9 | | | | - | |
| CIP – Usage Related | | | 5.9 | | | | 1.7 | | | | - | |
| Total Net Income Benefit/(Reduction) | | $ | 7.5 | | | $ | 9.7 | | | $ | (0.2 | ) |
| | | | | | | | | | | | | |
Weather Compared to 20-Year TAC Average | | 3.2% warmer | | | 15.0 % warmer | | | 3.0 % colder | |
Weather Compared to Prior Year | | 13.8% colder | | | 17.5 % warmer | | | 2.9 % colder | |
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.
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 25,309, 16,392 and 60,934 during 2007, 2006 and 2005, 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):
| | | 2007 | | | 2006 | | | 2005 | |
| Utility Throughput – dth: | | | | | | | | | | | | | | | | | | |
| Firm Sales - | | | | | | | | | | | | | | | | | | |
| Residential | | | 22,523 | | | | 16 | % | | | 19,830 | | | | 15 | % | | | 19,464 | | | | 12 | % |
| Commercial | | | 6,339 | | | | 4 | % | | | 6,958 | | | | 5 | % | | | 7,607 | | | | 5 | % |
| Industrial | | | 193 | | | | - | | | | 296 | | | | - | | | | 204 | | | | - | |
| Cogeneration and electric generation | | | 1,335 | | | | 1 | % | | | 1,103 | | | | 1 | % | | | 1,743 | | | | 1 | % |
| Firm Transportation - | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 1,870 | | | | 1 | % | | | 956 | | | | 1 | % | | | 5,755 | | | | 4 | % |
| Commercial | | | 5,927 | | | | 4 | % | | | 4,420 | | | | 3 | % | | | 5,267 | | | | 3 | % |
| Industrial | | | 12,107 | | | | 9 | % | | | 11,970 | | | | 9 | % | | | 12,920 | | | | 8 | % |
| Cogeneration and electric generation | | | 3,088 | | | | 2 | % | | | 2,625 | | | | 2 | % | | | 3,604 | | | | 2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Firm Throughput | | | 53,382 | | | | 37 | % | | | 48,158 | | | | 36 | % | | | 56,564 | | | | 35 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Interruptible Sales | | | 68 | | | | - | | | | 93 | | | | - | | | | 119 | | | | - | |
| Interruptible Transportation | | | 3,002 | | | | 2 | % | | | 3,474 | | | | 3 | % | | | 2,836 | | | | 2 | % |
| Off-System | | | 17,686 | | | | 13 | % | | | 18,221 | | | | 13 | % | | | 15,045 | | | | 9 | % |
| Capacity Release | | | 67,430 | | | | 48 | % | | | 66,458 | | | | 48 | % | | | 86,119 | | | | 54 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Throughput | | | 141,568 | | | | 100 | % | | | 136,404 | | | | 100 | % | | | 160,683 | | | | 100 | % |
| Utility Operating Revenues: | | | | | | | | | | | | | | | | | | |
| Firm Sales- | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 342,809 | | | | 54 | % | | $ | 334,201 | | | | 52 | % | | $ | 252,150 | | | | 43 | % |
| Commercial | | | 80,237 | | | | 13 | % | | | 99,578 | | | | 15 | % | | | 88,321 | | | | 15 | % |
| Industrial | | | 8,381 | | | | 1 | % | | | 6,590 | | | | 1 | % | | | 4,428 | | | | 1 | % |
| Cogeneration and electric generation | | | 11,722 | | | | 2 | % | | | 10,746 | | | | 2 | % | | | 17,916 | | | | 3 | % |
| Firm Transportation - | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 8,982 | | | | 1 | % | | | 4,768 | | | | 1 | % | | | 25,296 | | | | 4 | % |
| Commercial | | | 17,299 | | | | 3 | % | | | 12,510 | | | | 2 | % | | | 14,043 | | | | 3 | % |
| Industrial | | | 12,229 | | | | 2 | % | | | 11,351 | | | | 2 | % | | | 11,437 | | | | 2 | % |
| Cogeneration and electric generation | | | 1,847 | | | | - | | | | 1,552 | | | | - | | | | 1,821 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Firm Revenues | | | 483,506 | | | | 76 | % | | | 481,296 | | | | 75 | % | | | 415,412 | | | | 71 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Interruptible Sales | | | 785 | | | | - | | | | 1,109 | | | | - | | | | 1,498 | | | | - | |
| Interruptible Transportation | | | 1,970 | | | | - | | | | 1,868 | | | | - | | | | 1,898 | | | | - | |
| Off-System | | | 131,586 | | | | 22 | % | | | 147,180 | | | | 23 | % | | | 153,637 | | | | 27 | % |
| Capacity Release | | | 11,208 | | | | 2 | % | | | 9,656 | | | | 2 | % | | | 12,808 | | | | 2 | % |
| Other | | | 1,492 | | | | - | | | | 1,562 | | | | - | | | | 1,959 | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Utility Operating Revenues | | $ | 630,547 | | | | 100 | % | | $ | 642,671 | | | | 100 | % | | $ | 587,212 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Less: | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of sales | | | 453,034 | | | | | | | | 472,286 | | | | | | | | 414,952 | | | | | |
| Conservation recoveries * | | | 4,458 | | | | | | | | 6,862 | | | | | | | | 7,933 | | | | | |
| RAC recoveries * | | | 2,056 | | | | | | | | 1,807 | | | | | | | | 2,180 | | | | | |
| Revenue taxes | | | 8,850 | | | | | | | | 7,890 | | | | | | | | 9,089 | | | | | |
| Utility Margin | | $ | 162,149 | | | | | | | $ | 153,826 | | | | | | | $ | 153,058 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Margin: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 102,077 | | | | 63 | % | | $ | 90,442 | | | | 59 | % | | $ | 102,706 | | | | 67 | % |
| Commercial and industrial | | | 40,036 | | | | 25 | % | | | 38,129 | | | | 25 | % | | | 40,862 | | | | 27 | % |
| Cogeneration and electric generation | | | 2,212 | | | | 1 | % | | | 2,189 | | | | 1 | % | | | 2,514 | | | | 2 | % |
| Interruptible | | | 195 | | | | - | | | | 226 | | | | - | | | | 249 | | | | - | |
| Off-system & capacity release | | | 2,994 | | | | 2 | % | | | 4,711 | | | | 3 | % | | | 4,697 | | | | 3 | % |
| Other revenues | | | 1,952 | | | | 1 | % | | | 1,871 | | | | 1 | % | | | 2,319 | | | | 1 | % |
| Margin before weather normalization & decoupling | | | 149,466 | | | | 92 | % | | | 137,568 | | | | 89 | % | | | 153,347 | | | | 100 | % |
| TAC mechanism | | | - | | | | - | | | | 8,511 | | | | 6 | % | | | (289 | ) | | | - | |
| CIP mechanism | | | 12,683 | | | | 8 | % | | | 7,747 | | | | 5 | % | | | - | | | | - | |
| Utility Margin | | $ | 162,149 | | | | 100 | % | | $ | 153,826 | | | | 100 | % | | $ | 153,058 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Number of Customers at Year End: | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 312,969 | | | | 93 | % | | | 307,919 | | | | 93 | % | | | 300,652 | | | | 93 | % |
| Commercial | | | 22,220 | | | | 7 | % | | | 21,652 | | | | 7 | % | | | 21,322 | | | | 7 | % |
| Industrial | | | 474 | | | | - | | | | 478 | | | | - | | | | 450 | | | | - | |
| Total Customers | | | 335,663 | | | | 100 | % | | | 330,049 | | | | 100 | % | | | 322,424 | | | | 100 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Annual Degree Days: | | | 4,488 | | | | | | | | 3,943 | | | | | | | | 4,777 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| * Represents revenues for which there is a corresponding charge in operating expenses. Therefore, such recoveries have no impact on | |
| our financial results. | |
Throughput - - Total gas throughput increased 3.8% compared with 2006, to 142 MMDth in 2007. 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. In 2006, total gas throughput decreased 15.1% compared with 2005, to 136 MMDth. The lower throughput was primarily due to significantly warmer weather experienced during 2006, as previously discussed under the TAC and CIP, which lowered sales and demand for capacity release.
Operating Revenues - 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. Last year’s rate 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.
Revenues increased $55.5 million in 2006, compared with 2005, primarily due to three factors. First, we added 7,625 customers in 2006, which represented a 2.4% increase in total customers. Second, the average number of transportation customers decreased 73.1%, from 60,934 in 2005 to 16,392 in 2006. As previously discussed, the migration of customers from transportation service back to sales service has a direct impact on utility revenues as charges for gas costs are included in sales revenues and not in transportation revenues. Third, we were granted two BGSS rate increases as a result of substantial increases in wholesale natural gas prices across the country. The first increase in September 2005, resulted in a 4.4% increase in the average residential customer’s bill and 5.0% in the average commercial/industrial customer’s bill. The second was effective in December 2005, and resulted in a 24.3% increase in the average residential customer’s bill and 28.4% in the average commercial/industrial customer’s bill. Since gas costs are passed on directly to customers without any profit margin added by us, these BGSS rate increases did not impact our profitability.
Partially offsetting the positive factors noted above were lower customer utilization rates experienced during 2006, before the CIP became effective, compared with 2005. This was primarily due to the impact of higher natural gas prices and conservation efforts on customer usage. Additionally, sales to an electric generation customer were substantially lower than 2005, as the 2006 summer season weather was not nearly as warm as the 2005 summer season.
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 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.
Total margin for 2006 was comparable to the 2005 total margin; however, residential margins were much lower in 2006, than compared with 2005. This decrease was offset by contributions to net income from the TAC and CIP, which together, accounted for 11% of the 2006 total margin. Weather was substantially warmer in 2006 as compared to 2005, a year in which the TAC represented only a negligible portion of total margin. The CIP added $7.7 million to margin in 2006, related to the 2006-2007 winter season. Of this amount $4.9 million was related to weather variations and $2.8 million was related to other customer usage variations. Had the CIP not been implemented, our margins and net income would have been significantly lower.
Operating Expenses - A summary of changes in other operating expenses (in thousands):
| | | 2007 vs. 2006 | | | 2006 vs. 2005 | |
| | | | | | | |
| Operations | | $ | 1,745 | | | $ | (4,992 | ) |
| Maintenance | | | 807 | | | | (276 | ) |
| Depreciation | | | 1,106 | | | | 1,602 | |
| Energy and Other Taxes | | | 690 | | | | (1,742 | ) |
| | | | | | | | | |
Operations – Operations expense increased $1.7 million during 2007, as compared with 2006. The increase is primarily comprised of several factors. First, 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 reasons 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 have decreased as the Company is no longer managing as many plans as it had in 2006. Such costs are recovered on a dollar-for-dollar basis; therefore, SJG experienced an offsetting decrease in revenue during 2007 (see preceding margin table). The BPU-approved NJCEP allows for full recovery of costs, including carrying costs when applicable. As a result, the decrease in expense had no impact on our net income.
Operations expense decreased $5.0 million during 2006, compared with 2005, as a result of several factors. First, there was a $1.1 million decrease in 2006 in our costs under the New Jersey Clean Energy Program (NJCEP). As previously discussed, such costs are recovered on a dollar-for-dollar basis and had no impact on net income. Second, the Provision for Uncollectibles decreased $0.7 million from December 31, 2005 to December 31, 2006 in relation to a decrease in customer account receivables, inclusive of Unbilled Revenues. During 2005, the Provision for Uncollectibles had increased $0.6 million, resulting in a net change of $1.3 million in expense when comparing 2006 with 2005. Third, our regulatory expenses decreased $0.7 million in 2006, primarily as a result of amortization of previously deferred expenses related to our 2004 base rate proceeding with the BPU. Such costs were fully amortized as of December 31, 2005. Fourth, we also experienced lower pension and postretirement benefit costs during 2006. Such reductions were the result of earnings on additional contributions to the plans, the transfer of employees to SJI Services, LLC (SJIS) effective January 1, 2006, and savings resulting from the early retirement plan (ERIP) offered in 2004 and 2005. The total cost of providing the ERIP in 2005, including monetary incentives, was $1.8 million. There was no ERIP offered in 2006. Finally, we also experienced a significant decrease in compensation and healthcare costs as a result of the transfer of approximately 10% of our workforce to SJIS. While much of those costs were charged back to us for services rendered, increased activity and growth in SJI’s non-utility entities resulted in a net savings to us. Additional information regarding compensation can be found in Note 1 to the financial statements under Stock-Based Compensation Plans.
Maintenance – Maintenance expense increased $0.8 million during 2007, compared with 2006, primarily due to a $0.5 million increase in environmental remediations 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 2007. 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 $1.1 million and $1.6 million in 2007 and 2006, respectively, due mainly to our continuing investment in utility plant. SJG’s investment in utility plant during 2007, 2006 and 2005 was $48.1 million, $61.4 million and $70.1 million, respectively.
Energy and Other Taxes - Energy and Other Taxes increased in 2007, compared with 2006, primarily due to higher energy-related taxes based on increased taxable firm throughput and revenues in 2007. Higher taxable firm throughput in 2007 resulted from colder weather and customer growth in 2007. Energy and Other Taxes decreased in 2006, compared with 2005, primarily due to lower energy-related taxes based on lower sales volumes in 2006 coupled with a reduction in payroll taxes as a result of the transfer of employees to SJI Services, LLC.
Other Income and Expense - Other income and expense increased in 2006, compared with 2005, primarily as a result of $0.5 million in earnings on our restricted investments related to the issue of our variable-rate bonds in April 2006 and a $0.3 million improvement in the earnings performance of our available-for-sale securities over prior year. These securities represent assets held in trusts for the payment of postretirement healthcare costs. Both investments noted above continued to yield comparable contributions to our net income in both 2007 and 2006.
Interest Charges - 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.
Interest charges increased by $3.9 million in 2006, compared with 2005, due primarily to higher levels of short-term debt and higher interest rates on short-term debt. Short-term debt levels rose to support our capital expenditures that had not been financed with long-term debt, and costs not yet collected from customers for gas previously consumed. A steep rise in short-term interest rates for that period was driven by a series of interest rate hikes enacted by the Federal Reserve Bank in 2005 and 2006.
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 $89.4 million in 2007, $50.7 million in 2006, and $42.5 million in 2005. 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 provided by operating activities increased in 2006, as compared with 2005, as a result of several factors. First, lower accounts receivable levels, as well as higher over-collections related to budget billings, were experienced due to much warmer weather in the fourth quarter of 2006, as compared with the same period in 2005. Higher customer credit balances related to our budget billing program occurred as enrolled customers are billed a fixed amount each month based on normal weather expectations. Second, additional cash was derived from a sale of inventory gas to our affiliate, SJRG, in 2006 in the amount of $13.0 million (See Note 4 to the financial statements). The proceeds from this sale were credited to our BGSS which, along with higher BGSS rates put into place in mid-December 2005, enabled us to generate cash inflows in 2006 related to gas cost recoveries despite lower consumption levels due to warm weather. Third, inventory purchases required less cash in 2006, as commodity prices were not as high as in 2005. We also purchased less inventory in 2006, as compared with 2005, due to unseasonably warm weather in 2006. These cash sources were partially offset by lower consumption levels in 2006 that resulted in reduced recoveries of our rate mechanisms such as the RAC and SBC. Cash flows related to gas purchases were also negatively impacted in 2006 as we paid for gas purchased at unusually high prices at the end of 2005 due to the impact of hurricanes on gas production.
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 $13.4 million less in 2007, as compared with 2006, primarily due to infrastructure improvements made in previous years that continue to support SJG’s growth. Cash used for capital purchases was approximately $8.7 million less in 2006, compared with 2005, due to cash outflows for three large pipeline installation projects in 2005 that were necessary to support the growth in our territory. This was offset by the investment of $8.6 million of net proceeds from the issue of our variable-rate debt as such amounts have not yet been drawn down for their intended capital purpose. In April 2006, SJG issued $25.0 million of secured, tax-exempt debt through the New Jersey Economic Development Authority. Such funds can only be utilized for qualified construction activity as defined in our debt agreement. Unused funds in the amount of $14.3 million were placed in a restricted account during the second quarter of 2006. Funds from that account were used to finance capital expenditures totaling $6.3 million and $5.7 million in 2007 and 2006, respectively.
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. No long-term debt was issued in 2007.
Bank credit available to us totaled $176.0 million at December 31, 2007, of which $78.3 million was used. Those bank facilities consist of a $100.0 million revolving credit facility and $76.0 million of uncommitted bank lines. In August 2006, we replaced our existing revolving credit with a new $100.0 million revolver that expires in August 2011. The revolving credit facility contains one financial covenant that limits our total debt to total capitalization ratio to no more than 65%, measured on a quarterly basis. We were in compliance with this covenant as of December 31, 2007. 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.
Our net borrowings of short-term debt decreased by $25.2 million from 2006 to 2007 due to the increase in cash flows from operating activities discussed previously. The increase in our net borrowings of short-term debt of $16.5 million from 2005 to 2006, resulted from the underrecovery of costs that had not yet been collected under our various rate mechanisms, capital expenditures only partially financed with long-term debt, and payments for storage gas deferred from 2005 to 2006.
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 currently have in place a $150.0 million MTN program under which $115.0 million remains available for issuance. We repaid long-term debt totaling $2.3 million, $2.3 million and $22.8 million in 2007, 2006 and 2005, respectively.
SJI contributed no capital to us in 2007 and 2006; however, they did contribute $30.0 million to us in 2005. Contributions of capital are credited to Other Paid-in Capital and Premium on Common Stock.
As of December 31, our capital structure was as follows:
| | | 2007 | | | 2006 | |
| | | | | | | |
| Common Equity | | | 50.3 | % | | | 47.4 | % |
| Long-Term Debt | | | 39.3 | % | | | 38.7 | % |
| Short-Term Debt | | | 10.4 | % | | | 13.9 | % |
| | | | | | | | | |
| Total | | | 100.0 | % | | | 100.0 | % |
Our long-term, senior secured debt is rated “A” and “Baa1” by Standard & Poor’s and Moody’s Investor Services, respectively. These ratings have not changed in at least the past five years.
We are restricted as to the amount of cash dividends or other distributions that may be paid on our common stock by an order issued by the BPU in July 2004, that granted us an increase in base rates. Per the order, we are required to maintain total common equity of no less than $289.2 million. Our total common equity balance was $378.3 million at December 31, 2007.
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 2007 amounted to $48.1 million and $10.9 million, respectively. We estimate total cash outflows for construction and remediation projects for 2008, 2009 and 2010, to be approximately $78.5 million, $67.3 million and $59.2 million, respectively.
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, 2007, average $49.8 million annually and total $219.1 million over the contracts’ lives. Approximately 44% 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, 2007 (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 | | | $ | - | | | $ | 10,000 | | | $ | 27,187 | | | $ | 257,686 | |
| Interest on Long-Term Debt | | | 217,636 | | | | 16,993 | | | | 33,987 | | | | 31,019 | | | | 135,637 | |
| Operating Leases | | | 137 | | | | 88 | | | | 49 | | | | - | | | | - | |
| Commodity Supply Purchase Obligations | | | 219,114 | | | | 50,962 | | | | 76,160 | | | | 23,891 | | | | 68,101 | |
| New Jersey Clean Energy Program (Note 2) | | | 10,542 | | | | 10,542 | | | | - | | | | - | | | | - | |
| Other Purchase Obligations | | | 643 | | | | 643 | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Total Contractual | | | | | | | | | | | | | | | | | | | | |
| Cash Obligations | | $ | 742,945 | | | $ | 79,228 | | | $ | 120,196 | | | $ | 82,097 | | | $ | 461,424 | |
Interest on Long-Term Debt includes the impact of the related interest rate swap agreements on 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. As discussed in Note 11 to the financial statements, we made a pension contribution of approximately $4.8 million in the first quarter of 2008; however, changes in future investment performance and discount rates may result in additional contributions. Furthermore, future pension contributions beyond 2008 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, 2007 is as follows (in thousands):
| Assets: | | | Maturity | | | Maturity | | | | |
| | Source of Fair Value | | <1 Year | | | 1 - 3 Years | | | Total | |
| | | | | | | | | | | |
| Prices Actively Quoted | NYMEX | | $ | 991 | | | $ | 93 | | | $ | 1,084 | |
| Other External Sources | Basis | | | 1,245 | | | | - | | | | 1,245 | |
| Total | | | $ | 2,236 | | | $ | 93 | | | $ | 2,329 | |
| | | | | | | | | | | | | | |
| Liabilities: | | | Maturity | | | Maturity | | | | | |
| | Source of Fair Value | | <1 Year | | | 1 - 3 Years | | | Total | |
| | | | | | | | | | | | | | |
| Prices Actively Quoted | NYMEX | | $ | (3,601 | ) | | $ | (61 | ) | | $ | (3,662 | ) |
| Other External Sources | Basis | | | (759 | ) | | | - | | | | (759 | ) |
| Total | | | $ | (4,360 | ) | | $ | (61 | ) | | $ | (4,421 | ) |
NYMEX (New York Mercantile Exchange) is the primary national commodities exchange on which natural gas is traded. Basis represents the price of a NYMEX natural gas futures contract adjusted for the difference in price for delivering the gas at another location. Contracted volumes of our NYMEX and Basis contracts are 8.3 MMDth with a weighted-average settlement price of $8.39 per dth.
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, 2007 | | $ | (16,669 | ) |
| Contracts Settled During 2007, Net | | | 16,531 | |
| Other Changes in Fair Value from Continuing and New Contracts, Net | | | (1,954 | ) |
| Net Derivatives — Energy Related Liability, December 31, 2007 | | $ | (2,092 | ) |
The change in our derivative position from a $16.7 million liability at December 31, 2006 to a $2.1 million liability at December 31, 2007 is primarily due to the change in value of our financial positions held with SJRG. This change in value is primarily due to the settlement of contracts during the twelve months ended December 31, 2007.
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, 2007, was $78.3 million and averaged $66.3 million during 2007. The months where average outstanding variable-rate debt was at its highest and lowest levels were January, at $107.7 million, and May, at $20.0 million. A hypothetical 100 basis point (1%) increase in interest rates on our average variable-rate debt outstanding would result in a $391,000 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: 2007 – 36 b.p. decrease; 2006 - 72 b.p. increase; 2005 - 191 b.p. increase; 2004 - 115 b.p. increase; and 2003 - 31 b.p. decrease. As of December 31, 2007, our average borrowing cost, which changes daily, was 5.30%.
We issue long-term debt either at fixed rates or use interest rate derivatives to reduce exposure to changing interest rates on variable-rate, long-term debt. Consequently, interest expense on existing long-term debt is not significantly impacted by changes in market interest rates.
However, during 2008, due to general market conditions, the demand for auction-rate securities has been 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 is exposed to changes in interest rates that may not be completely mitigated by the related interest rate derivatives.
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, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in 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, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, 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 1 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, and in 2006 the Company changed its method of accounting for stock-based compensation to conform to FASB Statement No. 123(R), Share-Based Payment. As discussed in Note 11 to the financial statements, in 2006 the Company changed its method of accounting for postretirement benefits to conform to FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R). Also as discussed in Note 1 to the financial statements, in 2005 the Company changed its method of accounting for asset retirement obligations to conform to FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.
/s/ DELOITTE & TOUCHE LLP
Philadelphia, Pennsylvania
February 29, 2008
| SOUTH JERSEY GAS COMPANY | |
| STATEMENTS OF INCOME | |
| (In Thousands) | |
| | | Year Ended December 31, | |
| | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | |
| Operating Revenues | | $ | 630,547 | | | $ | 642,671 | | | $ | 587,212 | |
| | | | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | | | |
| Cost of Sales (Excluding depreciation) | | | 453,034 | | | | 472,286 | | | | 414,952 | |
| Operations | | | 51,736 | | | | 49,991 | | | | 54,983 | |
| Maintenance | | | 6,345 | | | | 5,538 | | | | 5,814 | |
| Depreciation | | | 24,614 | | | | 23,508 | | | | 21,906 | |
| Energy and Other Taxes | | | 10,829 | | | | 10,139 | | | | 11,881 | |
| | | | | | | | | | | | | |
| Total Operating Expenses | | | 546,558 | | | | 561,462 | | | | 509,536 | |
| | | | | | | | | | | | | |
| Operating Income | | | 83,989 | | | | 81,209 | | | | 77,676 | |
| | | | | | | | | | | | | |
| Other Income and Expense | | | 1,673 | | | | 1,480 | | | | 212 | |
| | | | | | | | | | | | | |
| Interest Charges | | | (20,985 | ) | | | (22,099 | ) | | | (18,156 | ) |
| | | | | | | | | | | | | |
| Income Before Income Taxes | | | 64,677 | | | | 60,590 | | | | 59,732 | |
| | | | | | | | | | | | | |
| Income Taxes | | | (26,652 | ) | | | (24,811 | ) | | | (25,185 | ) |
| | | | | | | | | | | | | |
| Net Income Applicable to Common Stock | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,547 | |
| | | | | | | | | | | | | |
| 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, | |
| | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | |
| Cash Flows from Operating Activities: | | | | | | | | | |
| Net Income | | $ | 38,025 | | | $ | 35,779 | | | $ | 34,547 | |
| Adjustments to Reconcile Net Income to Net Cash | | | | | | | | | | | | |
| Provided by Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 29,317 | | | | 28,140 | | | | 27,303 | |
| Provision for Losses on Accounts Receivable | | | 2,672 | | | | 1,284 | | | | 2,073 | |
| TAC/CIP Receivable | | | (7,946 | ) | | | (15,740 | ) | | | 291 | |
| Deferred Gas Costs - Net of Recoveries | | | 7,755 | | | | 18,694 | | | | (34,585 | ) |
| Deferred SBC Costs - Net of Recoveries | | | 3,960 | | | | (4,221 | ) | | | 1,871 | |
| Environmental Remediation Costs - Net of Recoveries | | | (10,926 | ) | | | (10,840 | ) | | | (6,655 | ) |
| Deferred and Noncurrent Income Taxes and Credits - Net | | | 12,957 | | | | 4,426 | | | | 25,662 | |
| Additional Pension Contributions | | | - | | | | - | | | | (1,390 | ) |
| Gas Plant Cost of Removal | | | (1,275 | ) | | | (1,369 | ) | | | (985 | ) |
| Changes in: | | | | | | | | | | | | |
| Accounts Receivable | | | (8,528 | ) | | | 9,658 | | | | (22,829 | ) |
| Inventories | | | 24,884 | | | | 11,099 | | | | (23,579 | ) |
| Prepaid and Accrued Taxes - Net | | | (2,099 | ) | | | 4,997 | | | | (5,934 | ) |
| Other Prepayments and Current Assets | | | (14 | ) | | | 594 | | | | (780 | ) |
| Gas Purchases Payable | | | (8,817 | ) | | | (40,270 | ) | | | 59,001 | |
| Accounts Payable and Other Accrued Liabilities | | | 9,787 | | | | 11,605 | | | | (13,246 | ) |
| Other Assets | | | (121 | ) | | | 1,978 | | | | 336 | |
| Other Liabilities | | | (272 | ) | | | (5,120 | ) | | | 1,423 | |
| | | | | | | | | | | | | |
Net Cash Provided by Operating Activities | | | 89,359 | | | | 50,694 | | | | 42,524 | |
| | | | | | | | | | | | | |
| Cash Flows from Investing Activities: | | | | | | | | | | | | |
| Capital Expenditures | | | (48,070 | ) | | | (61,440 | ) | | | (70,120 | ) |
| Merchandise Loans | | | (4,123 | ) | | | (3,342 | ) | | | (4,425 | ) |
| Proceeds from Merchandise Loans | | | 3,877 | | | | 3,707 | | | | 4,831 | |
| Purchase of Restricted Investment with Escrowed Loan Proceeds | | | (363 | ) | | | (14,661 | ) | | | - | |
| Proceeds from Sale of Restricted Investment from Escrowed Loan Proceeds | | | 6,710 | | | | 6,075 | | | | - | |
| | | | | | | | | | | | | |
Net Cash Used in Investing Activities | | | (41,969 | ) | | | (69,661 | ) | | | (69,714 | ) |
| | | | | | | | | | | | | |
| Cash Flows from Financing Activities: | | | | | | | | | | | | |
| Net (Repayments of) Borrowing from Lines of Credit | | | (25,160 | ) | | | 16,500 | | | | 34,000 | |
| Proceeds from Issuance of Long-Term Debt | | | - | | | | 25,000 | | | | 10,000 | |
| Principal Repayments of Long-Term Debt | | | (2,290 | ) | | | (2,345 | ) | | | (22,773 | ) |
| Redemption of Preferred Stock | | | - | | | | - | | | | (1,690 | ) |
| Dividends on Common Stock | | | (18,732 | ) | | | (19,902 | ) | | | (22,502 | ) |
| Premium for Early Retirement of Debt | | | - | | | | - | | | | (184 | ) |
| Payments for Issuance of Long-Term Debt | | | - | | | | (1,051 | ) | | | (420 | ) |
| Additional Investment by Shareholder | | | - | | | | - | | | | 30,000 | |
| Excess Tax Benefit from Restricted Stock Plan | | | 55 | | | | 181 | | | | - | |
| | | | | | | | | | | | | |
Net Cash (Used in) Provided by Financing Activities | | | (46,127 | ) | | | 18,383 | | | | 26,431 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | 1,263 | | | | (584 | ) | | | (759 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 1,967 | | | | 2,551 | | | | 3,310 | |
| | | | | | | | | | | | | |
| Cash and Cash Equivalents at End of Period | | $ | 3,230 | | | $ | 1,967 | | | $ | 2,551 | |
| | | | | | | | | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | | | | | | | | | | |
| Interest (Net of Amounts Applicable to Gas Cost | | | | | | | | | | | | |
| Overcollections and Amounts Capitalized) | | $ | 20,863 | | | $ | 21,832 | | | $ | 18,899 | |
| Income Taxes (Net of Refunds) | | $ | 15,684 | | | $ | 11,309 | | | $ | 8,434 | |
| | | | | | | | | | | | | |
| Supplemental Disclosures of Noncash Investing Activities: | | | | | | | | | | | | |
| Capital property and equipment acquired on | | | | | | | | | | | | |
| account but not paid at year-end | | $ | 4,182 | | | $ | 2,819 | | | $ | 8,990 | |
| | | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. | | | | | | | | | | | | |
| SOUTH JERSEY GAS COMPANY | |
| BALANCE SHEETS | |
| (In Thousands) | |
| | | December 31, | |
| | | 2007 | | | 2006 | |
| Assets | | | | | | |
| | | | | | | |
| Property, Plant and Equipment: | | | | | | |
| Utility Plant, at original cost | | $ | 1,123,992 | | | $ | 1,079,614 | |
| Accumulated Depreciation | | | (276,301 | ) | | | (257,781 | ) |
| | | | | | | | | |
| Property, Plant and Equipment - Net | | | 847,691 | | | | 821,833 | |
| | | | | | | | | |
| Investments: | | | | | | | | |
| Available-for-Sale Securities | | | 6,714 | | | | 6,342 | |
| Restricted Investments | | | 2,239 | | | | 8,586 | |
| | | | | | | | | |
| Total Investments | | | 8,953 | | | | 14,928 | |
| | | | | | | | | |
| Current Assets: | | | | | | | | |
| Cash and Cash Equivalents | | | 3,230 | | | | 1,967 | |
| Accounts Receivable | | | 48,984 | | | | 47,928 | |
| Accounts Receivable - Related Parties | | | 2,267 | | | | 3,939 | |
| Unbilled Revenues | | | 41,576 | | | | 34,502 | |
| Provision for Uncollectibles | | | (3,265 | ) | | | (2,741 | ) |
| Natural Gas in Storage, average cost | | | 56,404 | | | | 81,039 | |
| Materials and Supplies, average cost | | | 1,436 | | | | 1,685 | |
| Prepaid Taxes | | | 10,849 | | | | 7,774 | |
| Derivatives - Energy Related Assets | | | 2,236 | | | | 1,692 | |
| Other Prepayments and Current Assets | | | 2,278 | | | | 2,264 | |
| | | | | | | | | |
| Total Current Assets | | | 165,995 | | | | 180,049 | |
| | | | | | | | | |
| Regulatory and Other Noncurrent Assets: | | | | | | | | |
| Regulatory Assets | | | 188,688 | | | | 196,962 | |
| Unamortized Debt Issuance Costs | | | 6,307 | | | | 6,835 | |
| Prepaid Pension | | | 1,472 | | | | - | |
| Accounts Receivable - Merchandise | | | 6,118 | | | | 5,950 | |
| Derivatives - Energy Related Assets | | | 93 | | | | 19 | |
| Derivatives - Other | | | - | | | | 148 | |
| Other | | | 1,845 | | | | 1,352 | |
| | | | | | | | | |
| Total Regulatory and Other Noncurrent Assets | | | 204,523 | | | | 211,266 | |
| | | | | | | | | |
| Total Assets | | $ | 1,227,162 | | | $ | 1,228,076 | |
| | | | | | | | | |
| 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, | |
| | | 2007 | | | 2006 | |
| | | | | | | |
| Capitalization and Liabilities | | | | | | |
| | | | | | | |
| Common Equity: | | | | | | |
| Common Stock, Par Value $2.50 per share: | | | | | | |
| Authorized - 4,000,000 shares | | | | | | |
| Outstanding - 2,339,139 shares | | $ | 5,848 | | | $ | 5,848 | |
| Other Paid-In Capital and Premium on Common Stock | | | 200,317 | | | | 200,317 | |
| Accumulated Other Comprehensive Loss | | | (5,356 | ) | | | (4,429 | ) |
| Retained Earnings | | | 177,539 | | | | 158,617 | |
| | | | | | | | | |
| Total Common Equity | | | 378,348 | | | | 360,353 | |
| | | | | | | | | |
| Long-Term Debt | | | 294,873 | | | | 294,893 | |
| | | | | | | | | |
| Total Capitalization | | | 673,221 | | | | 655,246 | |
| | | | | | | | | |
| Current Liabilities: | | | | | | | | |
| Notes Payable | | | 78,340 | | | | 103,500 | |
| Current Maturities of Long-Term Debt | | | - | | | | 2,270 | |
| Accounts Payable - Commodity | | | 34,870 | | | | 43,687 | |
| Accounts Payable - Other | | | 13,650 | | | | 8,786 | |
| Accounts Payable - Related Parties | | | 22,417 | | | | 12,134 | |
| Derivatives - Energy Related Liabilities | | | 4,360 | | | | 18,006 | |
| Deferred Income Taxes - Net | | | 11,582 | | | | 4,049 | |
| Customer Deposits and Credit Balances | | | 18,067 | | | | 23,016 | |
| Environmental Remediation Costs | | | 25,447 | | | | 26,048 | |
| Taxes Accrued | | | 2,937 | | | | 1,961 | |
| Pension Benefits | | | 765 | | | | 776 | |
| Interest Accrued | | | 6,245 | | | | 6,112 | |
| Other Current Liabilities | | | 5,777 | | | | 4,904 | |
| | | | | | | | | |
| Total Current Liabilities | | | 224,457 | | | | 255,249 | |
| | | | | | | | | |
| Regulatory and Other Noncurrent Liabilities: | | | | | | | | |
| Regulatory Liabilities | | | 55,779 | | | | 50,797 | |
| Deferred Income Taxes - Net | | | 168,254 | | | | 164,797 | |
| Environmental Remediation Costs | | | 48,433 | | | | 41,746 | |
| Asset Retirement Obligations | | | 24,364 | | | | 23,743 | |
| Pension and Other Postretirement Benefits | | | 24,682 | | | | 29,354 | |
| Investment Tax Credits | | | 2,149 | | | | 2,470 | |
| Derivatives - Energy Related Liabilities | | | 61 | | | | 374 | |
| Derivatives - Other | | | 618 | | | | - | |
| Other | | | 5,144 | | | | 4,300 | |
| | | | | | | | | |
| Total Regulatory and Other Noncurrent Liabilities | | | 329,484 | | | | 317,581 | |
| | | | | | | | | |
| Commitments and Contingencies (Note 12) | | | | | | | | |
| | | | | | | | | |
| Total Capitalization and Liabilities | | $ | 1,227,162 | | | $ | 1,228,076 | |
| | | | | | | | | |
| 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 & Premium on Common Stock | | | Accumulated Other Comprehensive Loss | | | Retained Earnings | | | Total | |
| | | | | | | | | | | | | | | | |
| Balance at January 1, 2005 | | $ | 5,848 | | | $ | 170,317 | | | $ | (4,033 | ) | | $ | 130,695 | | | $ | 302,827 | |
| Net Income | | | | | | | | | | | | | | | 34,547 | | | | 34,547 | |
| Other Comprehensive Income (Loss), Net of Tax: (a) | | | | | | | | | | | | | | | | | | | | |
| Minimum Pension Liability Adjustment | | | | | | | | | | | 423 | | | | | | | | 423 | |
| Unrealized Gain on Available-for-Sale Securities | | | | | | | | | | | 63 | | | | | | | | 63 | |
| Unrealized Loss on Derivatives | | | | | | | | | | | (790 | ) | | | | | | | (790 | ) |
| Other Comprehensive Loss, Net of Tax: (a) | | | | | | | | | | | | | | | | | | | (304 | ) |
| Comprehensive Income | | | | | | | | | | | | | | | | | | | 34,243 | |
| Additional Investment by Shareholder | | | | | | | 30,000 | | | | | | | | | | | | 30,000 | |
| Cash Dividends Declared - Common Stock | | | | | | | | | | | | | | | (22,502 | ) | | | (22,502 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 5,848 | | | | 200,317 | | | | (4,337 | ) | | | 142,740 | | | | 344,568 | |
| 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 Income (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 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Disclosure of Changes in Accumulated Other Comprehensive Loss Balances (a) |
| (In Thousands) |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Postretirement Plan Liability Adjustment | | | Unrealized Gain (Loss) on Available-for-Sale Securities | | | Unrealized (Loss) Gain on Derivatives | | | Accumulated Other Comprehensive Loss | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at January 1, 2005 | | | | | | $ | (3,921 | ) | | $ | 91 | | | $ | (203 | ) | | $ | (4,033 | ) |
| Changes During Year | | | | | | | 423 | | | | 63 | | | | (790 | ) | | | (304 | ) |
| Balance at December 31, 2005 | | | | | | | (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 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| (a) Determined using a combined statutory tax rate of 41.08% in 2007 and 2006 and 40.85% in prior years. | | | | | | | | | | | | | |
| (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 $8.8 million, $7.9 million and $9.1 million in 2007, 2006 and 2005, 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, 2007 and 2006 were comprised of the following (in thousands):
| | | 2007 | | | 2006 | |
| Utility Plant: | | | | | | |
| Production Plant | | $ | 302 | | | $ | 302 | |
| Storage Plant | | | 11,582 | | | | 11,576 | |
| Transmission Plant | | | 149,542 | | | | 147,891 | |
| Distribution Plant | | | 919,205 | | | | 878,168 | |
| General Plant | | | 37,136 | | | | 35,529 | |
| Other Plant | | | 3,665 | | | | 3,394 | |
| Utility Plant in Service | | | 1,121,432 | | | | 1,076,860 | |
| Construction Work in Progress | | | 2,560 | | | | 2,754 | |
| | | | | | | | | |
| Total Utility Plant | | $ | 1,123,992 | | | $ | 1,079,614 | |
Asset Retirement Obligations - On December 31, 2005, the Company adopted FASB Interpretation No. 47, "Accounting for Conditional Retirement Obligations.” Obligations are recorded on the balance sheet under Asset Retirement Obligations (ARO). The amounts included in 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 2007 and 2006 was as follows (in thousands):
| | | 2007 | | | 2006 | |
| AROs as of January 1, | | $ | 23,743 | | | $ | 22,505 | |
| Accretion | | | 498 | | | | 953 | |
| Additions | | | 174 | | | | 290 | |
| Settlements | | | (51 | ) | | | (5 | ) |
| AROs as of December 31, | | $ | 24,364 | | | $ | 23,743 | |
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 2007 and 2006, and 2.4% in 2005. Under our 2004 rate case settlement, our composite depreciation rate was reduced from 2.9% to 2.4% effective July 8, 2004 (See Note 2). 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 2007 and 2006, and $1.2 million in 2005.
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 2007, 2006 and 2005, 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, 2007 and 2006, we had $2.1 million and $16.7 million of costs, respectively, included in our BGSS related to open financial contracts (See Note 3).
From time to time we enter into interest rate derivatives and similar agreements to hedge exposure to increasing interest rates, and the impact of those rates on our cash flows with respect to our variable-rate debt. We have designated and account for these interest rate derivatives as cash flow hedges.
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, 2007, the unamortized balance is approximately $1.3 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, 2007, the unrealized loss on these interest rate derivative agreements was ($0.6) million and is included on the balance sheet under the caption Regulatory and Other Noncurrent Liabilities: Derivatives - Other. The recorded balance as of December 31, 2007 represents the amount we would have expected to pay to the counterparties if the contracts had been terminated on that date. As of December 31, 2006, the unrealized gain on interest rate derivative agreements was $0.1 million and was included on the balance sheet under the caption Regulatory and Other Noncurrent Assets: Derivatives - Other. The recorded balance as of December 31, 2006 represents the amount we would have expected to receive from the counterparties if the contracts had been terminated on that date. As of December 31, 2007 and 2006, we determined that the swaps were highly effective; therefore, we recorded the changes in fair value of the swaps along with the cumulative unamortized costs, net of taxes, in Accumulated Other Comprehensive Loss.
We determined the fair value of derivative instruments by reference to quoted market prices of listed contracts, published quotations or quotations from unrelated third parties.
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 for: (i) awards granted on, or after, January 1, 2006 and (ii) unvested awards previously granted and outstanding as of January 1, 2006. In addition, 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.
As permitted by Statement No. 123(R), SJI chose the modified prospective method of adoption; accordingly, financial results for the prior period presented were not retroactively adjusted to reflect the effects of this Statement. Under the modified prospective application, this Statement applies to new awards and to awards modified, repurchased, or cancelled after the required effective date, which for us, was January 1, 2006. Compensation costs for the portion of awards for which the requisite service has not been rendered, that were outstanding as of the required effective date, are being recognized as the requisite service is rendered based on the grant-date fair value.
We are allocated a portion of SJI's compensation cost during the vesting period. Upon vesting, we make a cash payment to SJI equal to the amounts accrued as compensation cost during the vesting period. For shares granted on, or after, January 1, 2006, the accrued liability and payment is based on the grant date fair value of the restricted stock award earned by the employee at the date of vesting. As a result of this policy, 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. For unvested awards previously granted and outstanding as of January 1, 2006, the payment is based on the sum of (i) amounts previously accrued as liabilities for such awards as of December 31, 2005, and (ii) the grant date fair value of the remaining services as of January 1, 2006 on such awards, as determined on a basis consistent with those awards granted on, or after, January 1, 2006. 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, 2007, and the assumptions used to estimate the fair value of the awards (adjusted for a June 2005 two-for-one stock split):
| Grant | | Shares | | | Fair Value | | | Expected | | | Risk-Free | |
| Date | | Outstanding | | | Per Share | | | Volatility | | | Interest Rate | |
| | | | | | | | | | | | | |
| Jan. 2005 | | | 8,126 | | | $ | 25.155 | | | | 15.5 | % | | | 3.4 | % |
| Jan. 2006 | | | 8,450 | | | $ | 27.950 | | | | 16.9 | % | | | 4.5 | % |
| Jan. 2007 | | | 9,526 | | | $ | 29.210 | | | | 18.5 | % | | | 4.9 | % |
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, 2007, 2006 and 2005, the cost of restricted stock awards was $0.2 million, $0.2 million and $2.8 million, respectively. Of these costs, $0.1 million, $0.1 million and $0.9 million, respectively, were capitalized to Utility Plant. The significant decrease in costs subsequent to 2005 resulted from: the transfer of a majority of the officers to SJI and SJI Services, LLC, an affiliate by common ownership, upon an SJI corporate restructuring effective January 1, 2006 (See Note 4); officer retirements during 2006; and the methodology change resulting from adopting FAS123(R) as discussed below.
As of December 31, 2007, there was $0.2 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.
Prior to the adoption of Statement No. 123 (R), SJI applied Statement No. 123, as amended, which permitted the application of APB No. 25. In accordance with APB No. 25, we recorded compensation expense over the requisite service period for restricted stock based on the probable number of shares expected to be issued and the market value of SJI’s common stock at the end of each reporting period. As a result of this previous accounting treatment, there have been no excess tax benefits recognized prior to the adoption of Statement No. 123(R).
For the year ended December 31, 2006, the decrease in stock-based compensation expense resulting from the adoption of Statement No. 123(R), was $0.3 million, or $0.2 million after tax. This decrease in compensation expense would have had an immaterial impact on our cash flows for the period presented.
The following table summarizes information regarding restricted stock award activity during 2007, excluding accrued dividend equivalents:
| | | Shares | |
| Nonvested Shares Outstanding, January 1, 2007 | | | 26,738 | |
| Granted | | | 9,628 | |
| Vested* | | | (10,352 | ) |
| Cancelled/Forfeited | | | (1,734 | ) |
Transferred From Affiliate | | | 1,822 | |
| Nonvested Shares Outstanding, December 31, 2007 | | | 26,102 | |
| | | | | |
| * Actual shares awarded upon vesting, including dividend equivalents and adjustments for performance measures, totaled 17,143 shares. |
During 2007, SJI awarded 17,143 shares to our officers at a market value of $0.6 million. During 2006, 44,575 shares were awarded to our officers at a market value of $1.3 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 2007 and 2006, were approximately $1.1 million and $2.1 million, respectively, relating to stock awards and 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 - On January 1, 2007 SJG adopted the provisions of FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes.” This Interpretation provides guidance on the recognition and measurement of uncertain tax positions in the financial statements. 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. The total unrecognized tax benefits as of January 1, 2007 were $1.1 million, not including $0.4 million of accrued interest and penalties. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
| Balance at January 1, 2007 | | $ | 1,112 | |
| Increase as a result of tax positions taken in prior years | | | 28 | |
| Decrease due to a lapse in the statute of limitations | | | (233 | ) |
| Balance at December 31, 2007 | | $ | 907 | |
The total unrecognized tax benefits as of December 31, 2007 is $0.9 million, not including $0.5 million of accrued interest and penalty. 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 2007. There have been no material changes to the unrecognized tax benefits during 2007 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 2004 forward and state income tax returns primarily from 2003 forward are open and subject to examination.
In September 2006, the FASB issued its Staff Position (FSP) on “Accounting for Planned Major Maintenance Activities.” This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods. This FSP was effective in 2007 and did not have a material effect on our financial statements.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. This statement is effective for 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. Management does not anticipate that the adoption of this statement will have a material effect on our 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. Management does not anticipate that the adoption of this statement will have a material effect on our financial statements.
CORRECTION IN THE PRESENTATION OF THE STATEMENT OF CASH FLOWS - The following items represent corrections, during 2007, of the presentation of certain amounts from prior years Statements of Cash Flows:
| | · | Cash flows related to merchandise loans to customers for the purpose of attracting conversions to natural gas heating systems should have been classified under the caption Cash Flows from Investing Activities on the Statements of Cash Flows. Accordingly, cash outflows for loans originated of $3.3 million in 2006 and $4.4 million in 2005 and cash inflows from the principal collection on these loans of $3.7 million in 2006 and $4.8 million in 2005 are now included within Cash Flows from Investing Activities. The overall net impact resulted in $0.4 million of Cash Flows from Operating Activities for each of the years ended December 31, 2006 and 2005 now being included within Cash Flows from Investing Activities. |
| | · | Cash flows related to unused loan proceeds that are held in restricted escrow accounts were incorrectly presented on a net basis within Cash Flows from Investing Activities on the Statements of Cash Flows. Accordingly, purchases of restricted investments with unused loan proceeds of $14.7 million in 2006 is now included in Purchase of Restricted Investments with Escrowed Loan Proceeds and proceeds from the sale of these restricted investments of $6.1 million in 2006 are now included in Proceeds from Sale of Restricted Investments from Escrowed Loan Proceeds. This change had no overall impact on total Cash Flows from Investing Activities on the Statements of Cash Flows. |
These changes did not impact previously reported revenue or net income and are considered immaterial to the overall presentation of our 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. 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 though 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:
| · | February 2005 - We filed notice with the BPU to provide for an $11.4 million bill credit to customers. |
| · | March 2005 - The bill credit was approved and implemented. |
| · | June 2005 - We made our annual periodic BGSS filing with the BPU requesting a $17.1 million, or 6.3%, increase in gas cost recoveries in response to increasing wholesale gas costs. |
| · | August 2005 - The BPU approved our requested June 2005 increase, effective September 1, 2005, on an interim basis. |
| · | November 2005 - We filed a BGSS Motion for Emergent Rate Relief in conjunction with the other natural gas utilities in New Jersey. This filing was necessary due to substantial increases in wholesale natural gas prices across the country. We requested a $103.2 million increase. |
| · | December 2005 - The BPU approved on a provisional basis, an $85.7 million increase to our rates, effective December 15, 2005. |
| · | 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 will continue for three summer injection periods through 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 2007 and 2006 were $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. |
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, 2007 and 2006, our balance sheets include a TAC receivable of $6.5 million and $9.0 million, respectively, under the caption Regulatory Assets.
Regulatory actions regarding the TAC were as follows:
| · | November 2005 - We made our annual TAC filing, requesting a $1.0 million increase in annual revenues, to recover the cash related to the net TAC deficiency resulting from warmer-than-normal weather for the 2003-2004 winter, partially offset by colder-than-normal weather for the 2004-2005 winter. |
| · | 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. |
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. |
| · | 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. |
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:
| · | November 2005 - We made our annual SBC filing, requesting a $6.1 million reduction in annual recoveries. |
| · | 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. |
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, 2007 and 2006, we reflected the unamortized remediation costs of $26.0 million and $17.9 million, respectively, on the balance sheet under Regulatory Assets (See Note 3). Since implementing the RAC in 1992, we have recovered $43.1 million through rates.
New Jersey Clean Energy Program (NJCEP) - This mechanism recovers costs associated with our energy efficiency and renewable energy programs. In December 2004, the BPU approved the statewide funding of the NJCEP of $745.0 million for the years 2005 through 2008. Of this amount, we will be responsible for approximately $25.4 million over the 4-year period. 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. In June 2004, the BPU approved the statewide budget of $113.0 million for all the state’s electric and gas utilities and the increased rates were implemented effective July 1, 2004, resulting in a $3.9 million increase to our annual USF recoveries. 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:
| · | April 2005 - We made our annual USF filing, along with the state’s other electric and gas utilities, proposing no rate change to the statewide program. This rate proposal was approved by the BPU in June 2005. |
| · | 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 is designed to decrease our annual USF revenues by $3.4 million. The revised rates are effective from October 5, 2007 through September 30, 2008. |
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.
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, 2007, 25,171 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, 2007 and 2006, costs incurred under this program totaled $0.8 million and $0.4 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): | |
| | | | | | | |
| | | 2007 | | | 2006 | |
Environmental Remediation Costs: Expended - Net | | $ | 25,960 | | | $ | 17,854 | |
| Liability for Future Expenditures | | | 73,880 | | | | 67,794 | |
| Income Taxes - Flowthrough Depreciation | | | 3,707 | | | | 4,685 | |
| Deferred Asset Retirement Obligation Costs | | | 21,572 | | | | 21,009 | |
| Deferred Fuel Costs - Net | | | - | | | | 19,698 | |
| Deferred Pension and Other Postretirement Benefit Costs | | | 32,686 | | | | 39,359 | |
| Temperature Adjustment Clause Receivable | | | 6,516 | | | | 8,996 | |
| Conservation Incentive Program Receivable | | | 18,173 | | | | 7,747 | |
| Societal Benefit Costs Receivable | | | 2,952 | | | | 6,912 | |
| Premium for Early Retirement of Debt | | | 1,370 | | | | 1,532 | |
| Other Regulatory Assets | | | 1,872 | | | | 1,376 | |
| | | $ | 188,688 | | | $ | 196,962 | |
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, “Accounting for Conditional Asset Retirements Obligations” (FIN 47), 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 Fuel 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 $1.9 million at December 31, 2007. 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. We were in a net underrecovered position as of both December 31, 2007 and 2006.
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, 2007 and 2006, 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):
| | | 2007 | | | 2006 | |
| Excess Plant Removal Costs | | $ | 48,705 | | | $ | 48,377 | |
| Liability for NJCEP | | | 2,797 | | | | 796 | |
| Deferred Revenues - Net | | | 2,586 | | | | - | |
| Other | | | 1,691 | | | | 1,624 | |
| | | | | | | | | |
| Total Regulatory Liabilities | | $ | 55,779 | | | $ | 50,797 | |
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 Fuel 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 (dth) 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; therefore, administrative support from us to affiliates decreased from the level provided in 2005. 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):
| | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | |
| Operating Revenues/Affiliates: | | | | | | | | | |
| SJRG | | $ | 19,328 | | | $ | 67,262 | | | $ | 10,680 | |
| Other | | | 386 | | | | 2,302 | | | | 3,028 | |
| Total Operating Revenues/Affiliates | | $ | 19,714 | | | $ | 69,564 | | | $ | 13,708 | |
Related party transactions, excluding pass-through items, included in Operating Expenses were as follows (in thousands):
| | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | | | | |
| Costs of Sales/Affiliates | | | | | | | | | | | | |
| (Excluding depreciation): | | | | | | | | | | | | |
SJRG | | $ | 43,770 | | | $ | 53,196 | | | $ | 13,140 | |
Total Cost of Sales/Affiliates | | $ | 43,770 | | | $ | 53,196 | | | $ | 13,140 | |
| | | | | | | | | | | | | |
| Operations Expense/Affiliates | | | | | | | | | | | | |
| SJI | | $ | 1,014 | | | $ | 7,434 | | | $ | 5,811 | |
| SJIS | | | 4,550 | | | | 5,373 | | | | - | |
| Millennium | | | 2,872 | | | | 2,743 | | | | 2,626 | |
| Other | | | 139 | | | | - | | | | - | |
| Total Operations Expense/Affiliates | | $ | 8,575 | | | $ | 15,550 | | | $ | 8,437 | |
5. PREFERRED STOCK:
On May 2, 2005, we redeemed all of our Redeemable Cumulative Preferred 8% Series of preferred stock at its par value of $1.7 million.
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):
| | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | | | | |
| Tax at Statutory Rate | | $ | 22,637 | | | $ | 21,206 | | | $ | 20,906 | |
| Increase (Decrease) Resulting from: | | | | | | | | | | | | |
| State Income Taxes | | | 4,396 | | | | 4,107 | | | | 4,035 | |
| Amortization of Investment Tax Credits | | | (320 | ) | | | (325 | ) | | | (334 | ) |
| ESOP Dividend | | | (610 | ) | | | (674 | ) | | | - | |
| Amortization of Flowthrough Depreciation | | | 664 | | | | 664 | | | | 664 | |
| Other - Net | | | (115 | ) | | | (167 | ) | | | (86 | ) |
| Net Income Taxes | | $ | 26,652 | | | $ | 24,811 | | | $ | 25,185 | |
| | | | | | | | | | | | | |
| The provision for Income Taxes is comprised of the following (in thousands): | | | | |
| | | | | |
| | | 2007 | | | 2006 | | | 2005 | |
| Current: | | | | | | | | | |
| Federal | | $ | 9,951 | | | $ | 16,556 | | | $ | (1,819 | ) |
| State | | | 3,744 | | | | 3,829 | | | | 1,342 | |
| Total Current | | | 13,695 | �� | | | 20,385 | | | | (477 | ) |
| Deferred: | | | | | | | | | | | | |
| Federal: | | | | | | | | | | | | |
| Excess of Tax Depreciation Over | | | | | | | | | | | | |
| Book Depreciation - Net | | | 7,747 | | | | 7,979 | | | | 4,832 | |
| Deferred Fuel Costs - Net | | | (6,228 | ) | | | (12,646 | ) | | | 17,567 | |
| Environmental Costs - Net | | | 3,586 | | | | 1,808 | | | | 970 | |
| Prepaid Pension | | | 1,378 | | | | 202 | | | | 346 | |
| Deferred Regulatory Costs | | | (1,928 | ) | | | 3,525 | | | | (1,156 | ) |
| Conservation Incentive Program | | | 6,361 | | | | - | | | | - | |
| Other - Net | | | (658 | ) | | | 1,394 | | | | (1,429 | ) |
| State | | | 3,019 | | | | 2,489 | | | | 4,866 | |
| Total Deferred | | | 13,277 | | | | 4,751 | | | | 25,996 | |
| Investment Tax Credits | | | (320 | ) | | | (325 | ) | | | (334 | ) |
| Net Income Taxes | | $ | 26,652 | | | $ | 24,811 | | | $ | 25,185 | |
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):
| | | 2007 | | | 2006 | |
| | | | | | | |
| Current: | | | | | | |
| Deferred Fuel Costs - Net | | $ | 4,121 | | | $ | 4,121 | |
| Uncollectibles | | | (976 | ) | | | (956 | ) |
| Deferred Revenues | | | 8,061 | | | | - | |
| Section 461 Prepayments | | | 866 | | | | 967 | |
| Other | | | (490 | ) | | | (83 | ) |
| Current Deferred Tax Liability - Net | | $ | 11,582 | | | $ | 4,049 | |
| | | | | | | | | |
Noncurrent: | | | | | | | | |
| Book Versus Tax Basis of Property | | $ | 156,634 | | | $ | 147,296 | |
| Deferred Fuel Costs - Net | | | 5,141 | | | | 6,733 | |
| Environmental | | | 11,068 | | | | 6,546 | |
| Deferred Regulatory Costs | | | 1,238 | | | | 3,370 | |
| Deferred State Tax | | | (6,331 | ) | | | (4,238 | ) |
| Investment Tax Credit Basis Gross-Up | | | (1,107 | ) | | | (1,272 | ) |
| Deferred Pension & Other Post Retirement Benefits | | | 15,239 | | | | 15,239 | |
| Pension & Other Post Retirement Benefits | | | (9,021 | ) | | | (11,672 | ) |
| Deferred Revenues | | | (3,726 | ) | | | 2,376 | |
| Other | | | (881 | ) | | | 419 | |
| Noncurrent Deferred Tax Liability - Net | | $ | 168,254 | | | $ | 164,797 | |
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, 2007 and 2006, income taxes due from SJI were approximately $4.3 million and $0.7 million, respectively, and are included in the balance sheets under the caption, Prepaid Taxes.
7. LONG-TERM DEBT: (A)
A schedule of our long-term debt as of December 31, including current maturities, is as follows (in thousands):
| | | | | | 2007 | | | 2006 | |
| | | | | | | |
| First Mortgage Bonds: (B) | | | | | | |
| | 8.19 | % | | Series due 2007 | | $ | - | | | $ | 2,270 | |
| | 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 | | | | 9,893 | |
| | 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 | | | | 297,163 | |
| Less Current Maturities | | | - | | | | (2,270 | ) |
| Long-Term Debt | | | | | $ | 294,873 | | | $ | 294,893 | |
| (A) | Long-term debt maturities and sinking funds requirements for the succeeding five years are as follows (in thousands): 2008, $-0-; 2009, $-0-; 2010, $10,000; 2011, $25,000; 2012, $2,187. 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) | In April 2006, we issued $25.0 million of secured tax-exempt, auction-rate debt through the New Jersey Economic Development Authority (NJEDA) to finance infrastructure costs that qualify for tax-exempt financing. The auction rate, which resets weekly, was set at 4.90% as of December 31, 2007. As of December 31, 2007, $2.2 million, including interest thereon, remains in escrow pending the incurrence of capital costs that qualify for tax-exempt financing. In conjunction with this debt, we entered into interest rate swap agreements under which we pay a fixed interest rate 3.43% and receive floating rate interest payments at 67% of LIBOR, from December 1, 2006 through January 2036. This debt was issued under the Medium-Term Note (MTN) program. As of December 31, 2007, an additional $115.0 million remains available under the MTN program. These notes contain no financial covenants. |
We estimated the fair values of our long-term debt, including current maturities, as of December 31, 2007 and 2006, to be $326.1 and $318.4 million, respectively. Carrying amounts as of December 31, 2007 and 2006 are $294.9 and $297.2 million, respectively. We base the estimates on interest rates available to us at the end of each year for debt with similar terms and maturities. We retire debt when it is cost effective as permitted by the debt agreements.
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, 2007, the escrowed proceeds, including interest earned, totaled $2.2 million.
Other Financial Instruments - The carrying amounts of our other financial instruments approximate their fair values at December 31, 2007 and 2006.
9. UNUSED LINES OF CREDIT:
Bank credit available to us totaled $176.0 million at December 31, 2007, of which $78.3 million was used. Those bank facilities consist of a $100.0 million credit facility and $76.0 million of uncommitted bank lines. The revolving credit facility expires in August 2011 and contains one financial covenant regarding the ratio of total debt to total capitalization, measured on a quarterly basis. We were in compliance with this covenant as of December 31, 2007. Borrowings under these credit facilities are at market rates. Our average borrowing cost, which changes daily, was 5.30%, 5.71% and 4.91% at December 31, 2007, 2006 and 2005, 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 $378.3 million at December 31, 2007.
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, 2007, these loan restrictions did not affect the amount that may be distributed from our retained earnings.
We received no equity infusions from SJI in 2007 or 2006, but we received an equity infusion of $30.0 million from SJI during 2005. Contributions of capital are credited to Other Paid-In Capital and Premium on Common Stock. Future equity contributions will occur on an as needed basis.
11. PENSION AND OTHER POSTRETIREMENT BENEFITS:
In September 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 required 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 beginning with its 2006 year-end balance sheet 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).
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 | |
| | | 2007 | | | 2006 | | | 2005 | | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Service Cost | | $ | 2,442 | | | $ | 2,322 | | | $ | 2,704 | | | $ | 661 | | | $ | 656 | | | $ | 732 | |
| Interest Cost | | | 6,376 | | | | 5,988 | | | | 5,970 | | | | 2,295 | | | | 2,279 | | | | 1,963 | |
| Expected Return on Plan Assets | | | (8,068 | ) | | | (7,518 | ) | | | (7,494 | ) | | | (1,895 | ) | | | (1,617 | ) | | | (1,482 | ) |
| Amortizations: | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior Service Cost (Credits) | | | 239 | | | | 389 | | | | 522 | | | | (254 | ) | | | (264 | ) | | | (361 | ) |
| Actuarial Loss | | | 1,624 | | | | 2,032 | | | | 2,349 | | | | 560 | | | | 789 | | | | 570 | |
| Net Periodic Benefit Cost | | | 2,613 | | | | 3,213 | | | | 4,051 | | | | 1,367 | | | | 1,843 | | | | 1,422 | |
| ERIP Cost | | | - | | | | - | | | | 459 | | | | - | | | | - | | | | 1,187 | |
| Capitalized Benefit Costs | | | (1,131 | ) | | | (1,574 | ) | | | (1,823 | ) | | | (648 | ) | | | (903 | ) | | | (640 | ) |
| Total Net Periodic Benefit Expense | | $ | 1,482 | | | $ | 1,639 | | | $ | 2,687 | | | $ | 719 | | | $ | 940 | | | $ | 1,969 | |
Capitalized benefit costs reflected in the table above relate to our construction program. The ERIP costs relate to an early retirement plan offered during 2005. Additional monetary incentives not reflected in the table above totaled $0.2 million in 2005 and were funded outside of the retirement plans.
The estimated costs that will be amortized from Regulatory Assets into net periodic benefit costs in 2008 are as follows (in thousands):
| | | Pension Benefits | | | Other Postretirement Benefits | |
| Prior Service Costs (Credits) | | $ | 239 | | | $ | (254 | ) |
| Net Actuarial Loss | | $ | 677 | | | $ | 540 | |
The estimated costs that will be amortized from Accumulated Other Comprehensive Loss into net periodic benefit costs in 2008 are as follows (in thousands):
| | | Pension Benefits | | | Other Postretirement Benefits | |
| Net Actuarial Loss | | $ | 690 | | | $ | - | |
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 | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
Change in Benefit Obligations: | | | | | | | | | | | | |
| Benefit Obligation at Beginning of Year | | $ | 109,735 | | | $ | 111,767 | | | $ | 41,272 | | | $ | 39,062 | |
| Transferred to Affiliate | | | - | | | | (5,356 | ) | | | - | | | | (1,639 | ) |
| Service Cost | | | 2,442 | | | | 2,322 | | | | 661 | | | | 656 | |
| Interest Cost | | | 6,376 | | | | 5,988 | | | | 2,295 | | | | 2,279 | |
| Plan Amendments | | | - | | | | - | | | | - | | | | 1,408 | |
| Actuarial (Gain) / Loss | | | (3,188 | ) | | | 711 | | | | (1,910 | ) | | | 2,014 | |
| Retiree Contributions | | | - | | | | - | | | | 147 | | | | 305 | |
| Benefits Paid | | | (6,064 | ) | | | (5,697 | ) | | | (2,966 | ) | | | (2,813 | ) |
| Benefit Obligation at End of Year | | $ | 109,301 | | | $ | 109,735 | | | $ | 39,499 | | | $ | 41,272 | |
| | | | | | | | | | | | | | | | | |
| Change in Plan Assets: | | | | | | | | | | | | | | | | |
| Fair Value of Plan Assets at Beginning of Year | | $ | 94,603 | | | $ | 94,311 | | | $ | 26,274 | | | $ | 23,373 | |
| Transferred to Affiliate | | | - | | | | (5,137 | ) | | | - | | | | (882 | ) |
| Actual Return on Plan Assets | | | 7,172 | | | | 10,360 | | | | 1,273 | | | | 2,822 | |
| Employer Contributions | | | 830 | | | | 766 | | | | 3,556 | | | | 3,469 | |
| Retiree Contributions | | | - | | | | - | | | | 147 | | | | 305 | |
| Benefits Paid | | | (6,064 | ) | | | (5,697 | ) | | | (2,966 | ) | | | (2,813 | ) |
| Fair Value of Plan Assets at End of Year | | $ | 96,541 | | | $ | 94,603 | | | $ | 28,284 | | | $ | 26,274 | |
Funded Status at End of Year: | | | | | | | | | | | | |
| Accrued Net Benefit Cost at End of Year | | $ | (12,760 | ) | | $ | (15,132 | ) | | $ | (11,215 | ) | | $ | (14,998 | ) |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in the Statement | | | | | | | | | | | | | | | | |
| of Financial Position Consist of: | | | | | | | | | | | | | | | | |
| Noncurrent Asset | | $ | 1,472 | | | $ | - | | | $ | - | | | $ | - | |
| Current Liabilities | | | (765 | ) | | | (776 | ) | | | - | | | | - | |
| Noncurrent Liabilities | | | (13,467 | ) | | | (14,356 | ) | | | (11,215 | ) | | | (14,998 | ) |
| Net Amount Recognized at End of Year | | $ | (12,760 | ) | | $ | (15,132 | ) | | $ | (11,215 | ) | | $ | (14,998 | ) |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in Regulatory Assets | | | | | | | | | | | | | | | | |
| Consist of: | | | | | | | | | | | | | | | | |
| Prior Service Costs (Credit) | | $ | 1,620 | | | $ | 1,859 | | | $ | (977 | ) | | $ | (1,231 | ) |
| Net Actuarial Loss | | | 18,913 | | | | 23,376 | | | | 11,240 | | | | 13,087 | |
| | | $ | 20,533 | | | $ | 25,235 | | | $ | 10,263 | | | $ | 11,856 | |
| | | | | | | | | | | | | | | | | |
| Amounts Recognized in Accumulated Other | | | | | | | | | | | | | | | | |
| Comprehensive Loss Consist of: | | | | | | | | | | | | | | | | |
| Net Actuarial Loss | | $ | 7,208 | | | $ | 6,661 | | | $ | - | | | $ | - | |
The accumulated benefit obligation (ABO) of our qualified employee pension plans at December 31, 2007 and 2006, was $85.7 million and $87.0 million, respectively. The projected benefit obligation and ABO for our non-funded SERP, which had accumulated benefits in excess of plan assets, were $14.2 million and $13.6 million, respectively, as of December 31, 2007, and $13.0 million and $12.8 million, respectively, as of December 31, 2006. The SERP is reflected in the tables above and has no assets.
At December 31, 2007 and 2006, we had recorded additional postretirement liabilities under FAS 158 related to the SERP of $7.2 million and $6.7 million, respectively, with corresponding amounts recorded to Accumulated Other Comprehensive Loss.
The net changes included in Accumulated Other Comprehensive Loss due to the increase in the minimum pension obligation related to the SERP were $(0.3) million, $(0.4) million and $0.4 million for the years ended December 31, 2007, 2006 and 2005, respectively.
The weighted-average assumptions used to determine benefit obligations at December 31 were:
| | | Pension Benefits | | | Other Postretirement Benefits | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Discount Rate | | | 6.36 | % | | | 6.04 | % | | | 6.36 | % | | | 6.04 | % |
| 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 | |
| | | 2007 | | | 2006 | | | 2005 | | | 2007 | | | 2006 | | | 2005 | |
| | | | | | | | | | | | | | | | | | | |
| Discount Rate | | | 6.04 | % | | | 5.84 | % | | | 5.75 | % | | | 6.04 | % | | | 5.84 | % | | | 5.75 | % |
| Expected Long-Term Return on Plan Assets | | | 8.75 | % | | | 8.75 | % | | | 8.75 | % | | | 7.25 | % | | | 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, 2007 and 2006, 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.
In 2006, we elected to make a change in our mortality table from the 1983 GAM to the RP 2000 tables. All obligations disclosed herein reflect that change. While this change in mortality tables resulted in an increase to benefit costs in 2007, a 20 basis point increase in the discount rate and higher than expected returns on plan assets in 2006 more than offset this increase.
The assumed health care cost trend rates at December 31 were:
| | | 2007 | | | | 2006 | |
| | | | | | | | |
| Post-65 Medical Care Cost Trend Rate Assumed for Next Year | | 10.0 | % | | | 6.67 | % |
| Pre-65 Medical Care Cost Trend Rate Assumed for Next Year | | | 10.0 | % | | | 9.0 | % |
| Dental Care Cost Trend Rate Assumed for Next Year | | | 6.33 | % | | | 6.67 | % |
| Rate to which Cost Trend Rates are Assumed to Decline | | | | | | | | |
| (the Ultimate Trend Rate) | | | 5.0 | % | | | 5.0 | % |
| Year that the Rate Reaches the Ultimate Trend Rate | | | 2013 | | | | 2013 | |
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 | | $ | 119 | | | $ | (105 | ) |
| Effect on Postretirement Benefit Obligation | | | 1,266 | | | | (1,129 | ) |
Plan Assets - SJG’s weighted-average asset allocations at December 31, 2007 and 2006, by asset category are as follows:
| | | | | | | | | Other | |
| | | Pension Benefits | | | Postretirement Benefits | |
| | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | |
| Asset Category: | | | | | | | | | | | | |
| U.S. Equity Securities | | | 50 | % | | | 51 | % | | | 47 | % | | | 48 | % |
| International Equity Securities | | | 15 | | | | 16 | | | | 15 | | | | 17 | |
| Fixed Income | | | 35 | | | | 33 | | | | 38 | | | | 35 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
Based on the investment objectives and risk tolerances stated in SJI’s current pension and other postretirement benefit plans’ investment policy and guidelines, the long-term asset mix target considered appropriate is within the range of 58% to 68% equity and 32% to 42% fixed-income investments. Historical performance results and future expectations suggest that equities will provide higher total investment returns than fixed-income securities over a long-term investment horizon.
The policy recognizes that risk and volatility are present to some degree with all types of investments. We seek to avoid high levels of risk at the total fund level through diversification by asset class, style of manager, and sector and industry limits. Specifically prohibited investments include, but are not limited to, venture capital, margin trading, commodities and securities of companies with less than $250.0 million capitalization (except in the small-cap portion of the fund where capitalization levels as low as $50.0 million are permissible). 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 | |
| | | | | | | |
| 2008 | | $ | 6,040 | | | $ | 3,413 | |
| 2009 | | | 6,103 | | | | 3,549 | |
| 2010 | | | 6,227 | | | | 3,656 | |
| 2011 | | | 6,478 | | | | 3,509 | |
| 2012 | | | 6,701 | | | | 3,469 | |
| 2013 - 2017 | | | 39,808 | | | | 17,252 | |
Contributions - We made a contribution of approximately $4.8 million to our employee pension plan in the first quarter of 2008; however, changes in future investment performance and discount rates may ultimately result in additional contributions. Payments related to the unfunded SERP plan are expected to approximate $0.8 million in 2008. 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 2007 and 2006, and $0.8 million in 2005.
12. COMMITMENTS AND CONTINGENCIES:
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 2008. 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 $4.6 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 69% of our workforce at December 31, 2007 and operate under agreements that run through January 2009.
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 $15.3 million through December 31, 2007.
Since the early 1980s, we accrued environmental remediation costs of $193.8 million, of which $119.9 million has been spent as of December 31, 2007. The following table details the amounts accrued and expended for environmental remediation at December 31 (in thousands):
| | | 2007 | | | 2006 | |
| | | | | | | |
| Beginning of Year | | $ | 67,794 | | | $ | 56,717 | |
| Accruals | | | 18,666 | | | | 20,553 | |
| Expenditures | | | (12,580 | ) | | | (9,476 | ) |
| | | | | | | | | |
| End of Year | | $ | 73,880 | | | $ | 67,794 | |
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 $73.9 million to $233.5 million. We recorded the lower end of this range, $73.9 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. Four of our sites comprise a significant portion of these estimates, ranging from a low of $42.0 million to a high of $126.1 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 four most significant sites include the following:
Site 1 - A remedial action work plan has been prepared and submitted to the New Jersey Department of Environmental Protection (NJDEP) for approval. Remaining steps to remediate include regulatory approval and remedy implementation for impacted soil, groundwater, and river sediments as well as acceptance of the selected remedy by affected property owners.
Site 2 - Various remedial investigation and action activities, such as completed and approved interim remedial measures and conceptual remedy selection, are ongoing at this site. Remaining steps to remediate include remedy selection, regulatory approval, and implementation for the remaining impacted soil, groundwater, and 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.
At one site not specifically discussed above, the estimate was increased by $6.0 million to reflect the impact of the bids received at Site 4 since the same remediation alternative is currently proposed for this site.
13. QUARTERLY RESULTS OF OPERATIONS - UNAUDITED:
The summarized quarterly results of our operations are as follows (in thousands):
| | | 2007 Quarter Ended | | | 2006 Quarter Ended | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | | | March 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 277,864 | | | $ | 95,996 | | | $ | 84,420 | | | $ | 172,267 | | | $ | 277,081 | | | $ | 105,006 | | | $ | 87,715 | | | $ | 172,869 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of Sales | | | 205,544 | | | | 63,848 | | | | 62,223 | | | | 121,419 | | | | 208,621 | | | | 76,040 | | | | 65,014 | | | | 122,611 | |
| Operation and Maintenance | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Including Fixed Charges | | | 26,667 | | | | 23,890 | | | | 24,071 | | | | 29,052 | | | | 26,146 | | | | 22,914 | | | | 24,194 | | | | 27,882 | |
| Income Taxes (Benefit) | | | 16,870 | | | | 2,839 | | | | (1,278 | ) | | | 8,221 | | | | 15,530 | | | | 1,938 | | | | (1,062 | ) | | | 8,405 | |
| Energy and Other Taxes | | | 4,624 | | | | 1,872 | | | | 1,307 | | | | 3,026 | | | | 4,286 | | | | 1,673 | | | | 1,336 | | | | 2,844 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Expenses | | | 253,705 | | | | 92,449 | | | | 86,323 | | | | 161,718 | | | | 254,583 | | | | 102,565 | | | | 89,482 | | | | 161,742 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income and Expense | | | 100 | | | | 356 | | | | 157 | | | | 1,060 | | | | (20 | ) | | | 158 | | | | 232 | | | | 1,110 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) Applicable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| to Common Stock | | $ | 24,259 | | | $ | 3,903 | | | $ | (1,746 | ) | | $ | 11,609 | | | $ | 22,478 | | | $ | 2,599 | | | $ | (1,535 | ) | | $ | 12,237 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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, 2007. 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 to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
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, 2007.
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 was no change in the Company’s internal control over financial reporting during the fourth fiscal quarter, that 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 2007. 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 $320,000 and $155,200 in fiscal years 2007 and 2006, respectively. In May 2006, we were billed an additional $34,672 related to the 2005 audit. During 2006, Deloitte & Touche LLP also billed us $26,800 for services related to our variable rate bond issuance in April 2006.
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, February 29, 2008. 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 60.
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 May 25, 2007. | Incorporated by reference from Exhibit (3)(b) of Form 10-K filed March 6, 2007. |
(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 |
| (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 (WSS) between South Jersey Gas Company and Transco dated August 1, 1991. | Incorporated by reference from Exhibit (10)(h) of Form 10-K for 1991 (1-6364). |
(10)(a)(iv) | 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)(v) | 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) | Gas transportation service agreement (LG-A) between South Jersey Gas Company and Transco dated December 20, 1991. | Incorporated by reference from Exhibit (10)(i)(j) of Form 10-K for 1993 (1-6364). |
(10)(b)(iii) | 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)(iv) | 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)(b)(v) | Gas transportation service agreement (TF) between South Jersey Gas Company and CNG Transmission Corporation dated October 1, 1993. | Incorporated by reference from Exhibit (10)(k)(h) of Form 10-K for 1993 (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. 39556 between South Jersey Gas Company and Columbia Gas Transmission Corporation dated November 1, 1993. | Incorporated by reference from Exhibit (10)(k)(m) of Form 10-K for 1993 (1-6364). |
(10)(c)(iii) | 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)(iv) | 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)(v) | 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 2007 (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 2007. |
(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. |
(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: February 29, 2008
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 | February 29, 2008 |
| (Edward J. Graham) | (Principal Executive Officer) | |
| | | |
| | | |
/s/ David A. Kindlick | Senior Vice President & Chief Financial Officer | February 29, 2008 |
| (David A. Kindlick) | (Principal Financial and Accounting Officer) | |
| | | |
| | | |
/s/ Richard H. Walker, Jr. | Senior Vice President, General Counsel & Secretary | February 29, 2008 |
| (Richard H. Walker, Jr.) | | |
| | | |
| | | |
/s/ Shirli M. Billings | Director | February 29, 2008 |
| (Shirli M. Billings) | | |
| | | |
| | | |
| /s/ Sheila Hartnett-Devlin | Director | February 29, 2008 |
| (Sheila Hartnett-Devlin) | | |
| | | |
| | | |
| | | |
| /s/ William J. Hughes | Director | February 29, 2008 |
| (William J. Hughes) | | |
| | | |
| | | |
| | | |
| /s/ Frederick R. Raring | Director | February 29, 2008 |
| (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, 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 | |
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| | | | | | | | | | | | | | | | | | | | | |
| Provision for Uncollectible | | | | | | | | | | | | | | | | | | | | |
| Accounts for the Year Ended | | | | | | | | | | | | | | | | | | | | |
| December 31, 2005 | | $ | 2,871 | | | $ | 2,073 | | | $ | 85 | | | $ | 1,568 | | | $ | 3,461 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| (a) Recoveries of accounts previously written off and minor adjustments. | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| (b) Uncollectible accounts written off. | | | | | | | | | |
