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As filed with the Securities and Exchange Commission on August 6, 2008.

Registration No. 333-            

 

 

 

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM S-3

REGISTRATION STATEMENT

UNDER THE SECURITIES ACT OF 1933

 

 

UNITIL CORPORATION

(Exact Name of Registrant as Specified in its Charter)

 

New Hampshire		02-0381573
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

6 Liberty Lane West,

Hampton, New Hampshire 03842-1720

(603) 772-0775

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Mark H. Collin

Senior Vice President, Chief Financial Officer and Treasurer

UNITIL CORPORATION

6 Liberty Lane West

Hampton, New Hampshire 03842-1720

(603) 772-0775

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

Sheri E. Bloomberg, Esq. DEWEY & LEBOEUF LLP 1301 Avenue of the Americas New York, New York 10019 (212) 259-8000		Shelley A. Barber, Esq. VINSON & ELKINS L.L.P. 666 Fifth Avenue New York, New York 10103 (212) 237-0000

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after Unitil Corporation obtains certain regulatory approvals relating to its purchase of all of the outstanding capital stock of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., as discussed in the prospectus, and the effectiveness of this registration statement.

If the only securities being registered on this Form are being offered pursuant to dividend or interest reinvestment plans, please check the following box.  ¨

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box.  x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

(continued on next page)

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If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a registration statement pursuant to General Instruction I.D. or a post-effective amendment thereto that shall become effective upon filing with the Commission pursuant to Rule 462(e) under the Securities Act, check the following box.  ¨

If this Form is a post-effective amendment to a registration statement filed pursuant to General Instruction I.D. filed to register additional securities or additional classes of securities pursuant to Rule 413(b) under the Securities Act, check the following box.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  ¨						Accelerated filer                    x
Non-accelerated filer    ¨						Smaller reporting company   ¨

(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE

 

TITLE OF SECURITIES TO BE REGISTERED		AMOUNT TO BE REGISTERED(1)		PROPOSED MAXIMUM OFFERING PRICE PER UNIT(2)		PROPOSED MAXIMUM AGGREGATE OFFERING PRICE(2)		AMOUNT OF REGISTRATION FEE(2)
COMMON STOCK, NO PAR VALUE		4,000,000 SHARES		$ 26.81		$ 107,240,000.00		$ 4,214.53

(1)

Includes 522,000 shares of common stock issuable upon exercise of the underwriters’ over-allotment option.

 

(2)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) under the Securities Act of 1933, based on the average of the high and low prices of the common stock as reported by the American Stock Exchange on August 4, 2008, which date is within five (5) business days of the filing hereof.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this prospectus is not complete and may be changed. We cannot sell these securities until the Securities and Exchange Commission declares our registration statement effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to completion, dated August 6, 2008

PROSPECTUS

             Shares

Common Stock

 

 

Unitil Corporation is offering              shares of its common stock.

Our common stock is currently listed on the American Stock Exchange under the symbol “UTL.” Our common stock has been authorized for listing on the New York Stock Exchange effective August 21, 2008 under the symbol “UTL.” The last reported sale price of our common stock on August  6, 2008 was $26.65 per share.

Investing in our common stock involves risks that are described in the section entitled Risk Factors beginning on page 12 of this prospectus.

 

 

PRICE $              PER SHARE

 

 

		Per Share			Total
Public offering price		$			$
Underwriting discount		$			$
Proceeds, before expenses, to Unitil Corporation		$			$

The underwriters may also purchase up to an additional              shares from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus to cover over-allotments, if any.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The shares of common stock will be ready for delivery on or about                     , 2008.

 

 

 

RBC CAPITAL MARKETS
JANNEY MONTGOMERY SCOTT LLC		OPPENHEIMER & CO.
BREAN MURRAY, CARRET & CO, LLC		EDWARD JONES

                    , 2008.

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Map of Service Territory⁽¹⁾

 

(1)

This map is presented on a pro forma basis to illustrate the effects of Unitil Corporation’s proposed acquisitions of all of the outstanding capital stock of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., as discussed in the prospectus. For the purposes of this map, “Overlapping Service Territory” illustrates service territories currently served by Unitil Corporation and Northern Utilities, Inc.

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You should rely only on the information contained or incorporated by reference in this prospectus. We have not authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. We are offering to sell the shares and seeking offers to buy the shares only in jurisdictions where offers and sales are permitted. You should not assume that the information we have included in this prospectus is accurate as of any date other than the respective dates shown or that the information we have incorporated by reference to another document is accurate as of any date other than the date of such document. Our business, financial condition, results of operations and prospects may have changed since the date of this prospectus.

In this prospectus, the “Company,” “Unitil,” “we,” “us,” and “our” refer to Unitil Corporation and its subsidiaries, unless the context otherwise requires.

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RISK FACTORS

Before making an investment in shares of our common stock, you should carefully consider the risks described below, as well as the information included or incorporated by reference in this prospectus. We have identified a number of these factors in our Annual Report on Form 10-K for the year ended December 31, 2007 and in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, all of which are specifically incorporated by reference into this prospectus. See the section entitled Where You Can Find More Information. In addition, you should carefully consider the risks and uncertainties referred to below or listed under the section entitled Cautionary Statement about Forward-Looking Statements.

Risks Relating to Our Business

Risks related to the regulation of our business could impact the rates we are able to charge, our costs and our profitability. We are subject to comprehensive regulation by federal and state regulatory authorities, which significantly influences our operating environment and our ability to recover costs from our customers. In particular, we are regulated by the FERC and state regulatory authorities with jurisdiction over public utilities, including the NHPUC and the Massachusetts Department of Public Utilities (MDPU). Upon completion of the Proposed Acquisitions, the portion of Northern Utilities’ operations in Maine will be regulated by the MPUC. These authorities regulate many aspects of our operations, including, but not limited to, construction and maintenance of facilities, operations, safety, issuance of securities, accounting matters, transactions between affiliates, the rates that we can charge customers and the rate of return that we are allowed to realize. Our ability to obtain rate adjustments to maintain our current rate of return depends upon regulatory action under applicable statutes, rules and regulations, and we cannot assure you that we will be able to obtain rate adjustments or continue receiving our current authorized rates of return. These regulatory authorities are also empowered to impose financial penalties and other sanctions on us if we are found to have violated statutes and regulations governing our utility operations.

We are unable to predict the impact on our operating results from the regulatory activities of any of these agencies. Although we have attempted to actively manage the rate making process and have had recent success in obtaining rate adjustments, we can offer no assurances as to future success in the rate making process. Despite our requests, these regulatory commissions have authority under applicable statutes, rules and regulations to leave our rates unchanged, grant increases or order decreases in such rates. They have similar authority with respect to the recovery of our electricity and natural gas supply costs incurred by UES, FG&E and Northern Utilities. In the event that we are unable to recover these costs or recovery of these costs were to be significantly delayed, our operating results could be materially adversely affected. Changes in regulations or the imposition of additional regulations could also have an adverse effect on our operating results.

As a result of electric industry restructuring, we have a significant amount of certain stranded electric generation and generation related supply costs, which are subject to recovery in future periods. The stranded costs resulting from the implementation of electric industry restructuring mandated by the states of New Hampshire and Massachusetts are recovered by us on a pass-through basis through periodically reconciled rates. Any unrecovered balance of purchased power or stranded costs is deferred for future recovery as a regulatory asset. Such regulatory assets are subject to periodic regulatory review and approval for recovery in future periods.

Our power supply portfolio related stranded costs due to the electric industry restructuring in New Hampshire and Massachusetts for which regulatory approval has been obtained for recovery were approximately $42.0 million for FG&E and $30.7 million for UES as of December 31, 2007. Substantially all of FG&E’s stranded costs relate to owned generation assets and power purchase agreements divested by

 

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FG&E under a long-term contract buy-out agreement. UES’ stranded costs are attributable to the long-term power purchase agreements divested by Unitil Power Corp. (Unitil Power) under long-term contract buyout agreements. Because FG&E and Unitil Power remain ultimately responsible for purchase power payments underlying these long-term buyout agreements, FG&E and Unitil Power could incur additional stranded costs were they required to resell such divested entitlements prior to the end of their term for amounts less than the amounts agreed to under the existing long-term buyout agreements. We expect that any such additional stranded costs would be recovered from our customers, although such recovery would require approval from the MDPU or NHPUC, the receipt of which cannot be assured.

Our electric and natural gas sales and revenues are highly correlated with the economy, and national, regional and local economic conditions may negatively impact our customers and correspondingly our operating results and financial condition. Our business is influenced by the economic activity of our service territories. The level of economic growth in our electric and natural gas distribution service territories directly affects our potential for future growth in our business. As a result, adverse changes in the economy may have negative effects on our revenues, operating results and financial condition. Similarly, Northern Utilities’ and Granite State’s businesses are influenced by the economic activity in their service territories, and adverse changes in the economy may negatively affect their revenues, operating results and financial condition.

Declines in the valuation of capital markets could require us to make substantial cash contributions to cover our pension obligations, which could negatively impact our financial condition. On August 17, 2006, the Pension Protection Act of 2006 (PPA) was signed into law. Included in the PPA are new minimum funding rules which will go into effect for plan years beginning in 2008. The funding target will be 100% of a plan’s liability with any shortfall amortized over seven years, with lower (92% – 100%) funding targets available to well-funded plans during the transition period.

We made cash contributions of $2.8 million, $2.5 million and $2.5 million to our pension plan in 2007, 2006 and 2005, respectively, which exceeded minimum funding requirements. If the valuation of capital markets were to significantly decline from current levels, we may be required to make cash contributions to our pension plans substantially in excess of the levels currently anticipated, which could adversely affect our financial condition.

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158), which requires companies to record on their balance sheets the funded status of their retirement benefit obligations (RBO). We have recognized a liability for the projected RBO of our plans and a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas retail rates. In the event that we are unable to recover these costs or recovery of these costs were to be significantly delayed, our operating results could be materially adversely affected. See Note 8 to our financial statements and supplementary data contained in Part II, Item 8 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Increases in interest rates could have a negative impact on our financial condition. Our utility subsidiaries have ongoing capital expenditure and cash funding requirements which they frequently fund by issuing short and long-term debt. Changes in interest rates do not affect interest expense associated with presently outstanding fixed rate long-term debt securities. However, changes in interest rates may affect the interest rate and corresponding interest expense on any new long-term debt securities that are issued. In addition, short-term debt borrowings are typically at variable rates of interest. As a result, changes in short- term interest rates will increase or decrease our interest expense associated with short-term borrowings. Increases in interest rates generally will increase our borrowing costs and could adversely affect our financial condition or results of operations.

 

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Weather conditions may cause our sales to vary from year to year. Our utility operating sales vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual natural gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, particularly during the winter heating season. The Proposed Acquisitions will likely cause this seasonality to become more pronounced. Our electric sales are generally less sensitive to weather than our gas sales, but may also be affected by weather conditions in both the winter and summer seasons.

We are a holding company and have no operating income of our own. Our ability to pay dividends on our common stock is dependent on dividends received from our subsidiaries and on factors directly affecting us, the parent corporation. We cannot assure you that our current annual dividend will be paid in the future. We are a public utility holding company and we do not have any operating income of our own. Consequently, our ability to pay dividends on our common stock is dependent on dividends and other payments received from our subsidiaries, principally UES and FG&E and, upon completion of the Proposed Acquisitions, Northern Utilities and Granite State. The ability of our subsidiaries to pay dividends or make distributions to us will depend on, among other things:

 

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the actual and projected earnings and cash flow, capital requirements and general financial condition of our subsidiaries;

 

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the prior rights of holders of existing and future preferred stock, mortgage bonds, long-term notes and other debt issued by our subsidiaries;

 

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the restrictions on the payment of dividends contained in the existing loan agreements of UES and FG&E and that may be contained in future debt agreements of our subsidiaries, if any; and

 

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limitations that may be imposed by New Hampshire, Massachusetts and, following the Proposed Acquisitions, Maine state regulatory agencies.

In addition, we may incur indebtedness in the future. Before we can pay dividends on our common stock, we have to satisfy our debt obligations and comply with any statutory or contractual limitations.

Our current annual dividend is $1.38 per share of common stock, payable quarterly. However, our Board of Directors reviews our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.

Transporting and storing natural gas and supplemental gas supplies, as well as electricity, involves numerous risks that may result in accidents and other operating risks and costs. Inherent in our electric and gas distribution activities are a variety of hazards and operating risks, such as leaks, explosions, electrocutions and mechanical problems that 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 our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines, storage facilities and electric distribution equipment near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.

 

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Our business is subject to environmental regulation in all jurisdictions in which we operate and our costs of compliance are significant. Any changes in existing environmental regulation and the incurrence of environmental liabilities could negatively affect our results of operations and financial condition. Our utility operations are generally subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, waste management, natural resources and the health and safety of our employees. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties; imposition of remedial requirements; and even issuance of injunctions to ensure future compliance. Liability under certain environmental laws is strict, joint and several in nature. Although we believe we are in general compliance with all applicable environmental and safety laws and regulations, there can be no assurance that significant costs and liabilities will not be incurred in the future. Moreover, it is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations, could result in increased environmental compliance costs.

Catastrophic events could have a material adverse effect on our financial condition or results of operations. The electric and natural gas utility industries are from time to time affected by catastrophic events, such as unusually severe weather and significant and widespread failures of plant and equipment. Other catastrophic occurrences, such as terrorist attacks on utility facilities, may occur in the future. Such events could have a material adverse effect on us, since they could inhibit our ability to continue providing electric and/or gas distribution services to our customers for an extended period, which is the principal source of our operating income.

Risks Relating to the Proposed Acquisitions

If we are not successful in effectively integrating Northern Utilities and Granite State, we may not be able to operate cost-efficiently after the Proposed Acquisitions. Achieving the benefits of the Proposed Acquisitions will depend in part on the successful integration of Northern Utilities’ and Granite State’s operations, services, and personnel with our operations, services, and personnel in a timely and efficient manner. Integration involves the integration of systems, applications, policies, procedures, business processes, and other operations and requires coordination of administrative staff (e.g., human resources, customer service, regulatory services, information technology, accounting and finance, accounts receivable, and accounts payable) and development and engineering teams. Integration may be difficult, unpredictable, and subject to delay because of possible cultural conflicts and differing opinions. Additionally, integration could divert management’s attention away from our operations, which could harm our business, financial condition and operating results. If we cannot successfully integrate the operations, services, and personnel of Northern Utilities and Granite State, we will not realize the expected benefits of the Proposed Acquisitions, including reduced operating expenses and cash flow savings, and may not be able to operate cost-efficiently.

We expect to incur significant costs integrating Northern Utilities and Granite State into us, and if such integration is not successful, we may not realize the expected benefits of the Proposed Acquisitions. We expect to incur significant costs integrating Northern Utilities’ and Granite State’s operations, services, and personnel with our operations, services, and personnel. These costs may include costs for:

 

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additional staff’s salaries and benefits;

 

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converting information systems;

 

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combining gas operations; and

 

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purchasing additional equipment.

 

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We do not know whether we will be successful in these integration efforts or in consummating the Proposed Acquisitions and cannot assure our shareholders that we will realize the expected benefits of the Proposed Acquisitions.

Our ability to obtain a reasonable regulatory plan for Northern Utilities and Granite State following the Proposed Acquisitions depends upon regulatory action under applicable statutes, rules, and regulations. We believe there is an opportunity to stabilize and improve the operating earnings of Northern Utilities and Granite State by executing a consistent and well-structured regulatory plan that will provide Northern Utilities and Granite State with an opportunity to earn a reasonable rate of return. If we are unable to obtain approval of a reasonable regulatory plan, or are delayed in obtaining approval of a reasonable regulatory plan, we may not be able to improve the operating earnings of Northern Utilities and Granite State.

The trading price of our common stock after consummation of the Proposed Acquisitions may be affected by factors different from those currently affecting the trading price of our common stock. The Proposed Acquisitions will increase our assets by approximately 51%, increase our customer base by approximately 52,000 to 167,000 customers, and further diversify our operations with respect to geography (into Maine) and utility mix (between our gas and electric divisions). Therefore, after consummating the Proposed Acquisitions, our results of operations, as well as the trading price of our common stock, may be affected by factors different from those currently affecting the results of operations and the trading price of our common stock.

Failure to complete the Proposed Acquisitions could negatively impact our stock price and our future business and financial results because of, among other things, the disruption that would occur as a result of uncertainties relating to a failure to complete the Proposed Acquisitions. Specified conditions must be satisfied or waived before the Proposed Acquisitions can be completed. These conditions are summarized in the sections entitled Prospectus Summary — Proposed Acquisition of Northern Utilities and Granite State and Proposed Acquisitions – Description of the Proposed Acquisitions and are described in detail in the Stock Purchase Agreement relating to the Proposed Acquisitions, a copy of which was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on February 20, 2008 and is incorporated herein by reference. We cannot assure shareholders that each of these conditions will be satisfied or waived. If the conditions are not satisfied or waived, the Proposed Acquisitions may not occur or may be delayed, which may cause us to lose some or all of the intended or perceived benefits of the Proposed Acquisitions, which could cause the price of our common stock to decline and harm our business.

If the Proposed Acquisitions are not completed for any reason, the price of our common stock may decline to the extent that the current market price of that stock reflects a market assumption that the Proposed Acquisitions will be completed and that the related benefits and synergies will be realized, or as a result of the market’s perceptions that the Proposed Acquisitions were not consummated due to an adverse change in our business. In addition, the price of our common stock may decline as a result, to the extent that investors believe that we cannot compete in the marketplace as effectively without the Proposed Acquisitions or otherwise remain uncertain about our future prospects in the absence of the Proposed Acquisitions. The realization of any of these risks may materially adversely affect our business, financial results, financial condition and stock price.

Increases in interest rates could have a negative effect on our cost to finance a portion of the Proposed Acquisitions with new debt. We plan to finance approximately 50% of the acquisition price with (i) the issuance of new long-term debt securities at the subsidiary level and (ii) short-term lines of credit. Changes in interest rates may affect the interest rate and corresponding interest expense associated with the cost of this new debt. Increases in interest rates generally will increase our financing costs associated with the Proposed Acquisitions and could adversely affect our financial condition and results of operations after consummation of the Proposed Acquisitions.

 

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The Proposed Acquisitions will result in significant costs to us, whether or not they are completed, which will result in a reduction in our income and cash flows. We will be required to pay our costs relating to the Proposed Acquisitions even if the Proposed Acquisitions are not completed and such costs will be significant. Most of these costs will be incurred whether or not the Proposed Acquisitions are completed. Incurring these costs will cause a reduction in our income and cash flows.

We could be exposed to unknown liabilities of Northern Utilities and Granite State, which could cause us to incur substantial financial obligations and harm our business. If Northern Utilities and Granite State have liabilities of which we are not aware, we would assume those liabilities and may have limited recourse against NiSource and Bay State. If such unknown liabilities exist and we are not fully indemnified for any loss that we incur as a result thereof, we could incur substantial financial obligations, which could adversely affect our financial condition and harm our business.

Risks Relating to this Offering

Our stock price may decline when our results decline or when events occur that are adverse to us or our industry. You can expect the market price of our common stock to decline when our quarterly results decline or at any time when events actually or potentially adverse to us or the electricity and gas industry occur. Our common stock price may decline to a price below the price you paid to purchase your shares of common stock in this offering.

Substantial sales of our common stock could cause our stock price to decline. If our existing shareholders sell a large number of shares of our common stock or the public market perceives that existing shareholders might sell shares of our common stock, the market price of our common stock could significantly decline. All of the shares offered by this prospectus will be freely tradable without restriction or further registration under the federal securities laws unless purchased by an “affiliate,” as that term is defined in Rule 144 under the Securities Act. The outstanding shares subject to lock-up agreements between each of our directors and our senior executive officers and the underwriters may be sold 90 days after the date of this prospectus, except as noted in the section entitled Underwriting.

The proposed sale and issuance of common stock will dilute the holdings of our current shareholders who continue to hold their shares of common stock. As of             , 2008, we had shares of common stock outstanding. If the proposed sale and issuance of common stock is consummated, we will have approximately             shares of common stock outstanding. As a result, our shareholders’ proportionate holding in us would be diluted by approximately     %.

If the Proposed Acquisitions do not occur, we may not be able to efficiently use the proceeds from this offering. We expect to commence this offering as soon as practicable after (i) we obtain certain regulatory approvals relating to the Proposed Acquisitions and (ii) the satisfaction of certain other closing conditions relating to the Proposed Acquisitions. However, this offering is not conditioned on the closing of the Proposed Acquisitions and we expect this offering to close prior to the closing of the Proposed Acquisitions. If the Proposed Acquisitions do not close, the proceeds from this offering may exceed our capital needs and we may not be able to efficiently use these proceeds, which could adversely affect the trading price of our common stock.

 

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This prospectus and the documents we incorporate by reference into this prospectus contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act, Section 21E of the Securities and Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this prospectus, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for our future operations, are forward-looking statements.

These statements include declarations regarding our or our management’s beliefs and current expectations. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include those described in the section entitled Risk Factors and the following:

 

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our ability to consummate the Proposed Acquisitions, including potential difficulties in satisfying the conditions set forth in the Stock Purchase Agreement relating to the Proposed Acquisitions;

 

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our ability to integrate the business, operations, and personnel of Northern Utilities and Granite State following the consummation of the Proposed Acquisitions;

 

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our, Northern Utilities’, and Granite State’s ability to retain existing customers and gain new customers prior to and following the Proposed Acquisitions;

 

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variations in weather;

 

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changes in the regulatory environment;

 

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customers’ preferences on energy sources;

 

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interest rate fluctuation and credit market concerns;

 

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general economic conditions;

 

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fluctuations in supply, demand, transmission capacity and prices for energy commodities; and

 

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increased competition.

Many of these risks are beyond our control. Any forward-looking statements speak only as of the date of this prospectus, and we undertake no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors, nor can we assess the impact of any such factor on our business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements.

 

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USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be approximately $             million (approximately $             million if the underwriters’ over-allotment option is exercised in full), after deducting the underwriting discounts and our estimated offering expenses, based on an assumed offering price of $             per share (the closing price of our common stock on the American Stock Exchange on                     , 2008).

We intend to use the proceeds from this offering to partially finance the Proposed Acquisitions, to pay fees and expenses related to the Proposed Acquisitions and for other general corporate purposes.

We expect to commence this offering as soon as practicable after (i) we obtain certain regulatory approvals relating to the Proposed Acquisitions and (ii) the satisfaction of certain other closing conditions relating to the Proposed Acquisitions.

This offering is not conditioned on the closing of the Proposed Acquisitions. If the Proposed Acquisitions do not close for any reason, then we will use the proceeds from this offering for general corporate purposes to the extent that the proceeds can be deployed efficiently and expect to return any proceeds that cannot be deployed efficiently to our shareholders in a timely and efficient manner.

 

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CAPITALIZATION

The table below shows our capitalization as of March 31, 2008:

 

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on an actual consolidated basis;

 

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on a pro forma basis to give effect to the issuance of up to $90 million of debt at the subsidiary level, which is subject to regulatory approval and is not contingent on this offering (see the section entitled Prospectus Summary — Proposed Acquisitions of Northern Utilities and Granite State);

 

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on a pro forma basis to give effect to an increase in short-term debt incurred to replace working capital; and

 

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on an as-adjusted basis to give effect to the receipt of the estimated net proceeds of $             million from the issuance of             shares of common stock in this offering, which is not contingent on the note issuance by Northern Utilities, at an assumed public offering price of $             per share and the application of the estimated net proceeds from this offering (see the section entitled Use of Proceeds).

You should read this table in conjunction with our consolidated financial statements and the related notes incorporated by reference in this prospectus.

 

		As of March 31, 2008
		Actual			Pro-forma Adjustments		Adjustments for this Offering		Pro forma As Adjusted
(in millions)		(unaudited)
Common stock equity		$	100.0
Preferred stock, non-redeemable, non-cumulative			0.2
Preferred stock, redeemable, cumulative			1.9
Long-Term debt, less current portion			159.6
Short-Term debt(1)			17.1
Total capitalization, including short-term debt		$	278.8

 

(1)

Includes $0.4 million for the Current Portion of Long-Term Debt.

 

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PRICE RANGE OF COMMON STOCK AND DIVIDENDS

Our common stock is currently listed on the American Stock Exchange under the symbol “UTL.” Our common stock has been authorized for listing on the New York Stock Exchange effective August 21, 2008 under the symbol “UTL.”

As of                     , 2008, there were             shareholders of record.

The following table sets forth the range of high and low intra-day market prices per share of our common stock and the dividends paid per share for the periods indicated. The closing price of our common stock was $             on                     , 2008. Past performance is not necessarily indicative of future price performance. You should obtain current market quotations for shares of our common stock.

 

		Price Range						Dividends Per Share
		High			Low
2005:
First Quarter		$	27.80		$	25.50		$	0.345
Second Quarter			28.05			25.31			0.345
Third Quarter			28.70			27.00			0.345
Fourth Quarter			28.10			24.37			0.345
2006:
First Quarter		$	26.11		$	24.59		$	0.345
Second Quarter			26.05			23.70			0.345
Third Quarter			24.97			23.80			0.345
Fourth Quarter			26.09			23.82			0.345
2007:
First Quarter		$	27.30		$	25.10		$	0.345
Second Quarter			28.40			26.65			0.345
Third Quarter			31.73			27.07			0.345
Fourth Quarter			29.97			25.75			0.345
2008:
First Quarter		$	29.00		$	25.75		$	0.345
Second Quarter			28.60			26.41			0.345
Third Quarter (through                     , 2008)									n/a

On June 19, 2008, our Board of Directors declared a dividend in the amount of $0.345 per common share, to be paid on August 15, 2008 to common shareholders of record on August 1, 2008. This dividend will not be paid on the shares of common stock offered by this prospectus.

Our current annual dividend is $1.38 per share of common stock, payable quarterly. However, our Board of Directors reviews our dividend policy periodically in light of the factors referred to above, and we cannot assure you of the amount of dividends, if any, that may be paid in the future.

 

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PRO FORMA FINANCIAL DATA

The unaudited pro forma combined financial information and explanatory notes beginning on page F-1 present how the combined financial statements of Unitil Corporation, Northern Utilities and Granite State may have appeared had the businesses actually been combined as of December 31, 2007 and March 31, 2008 (with respect to the balance sheet information using currently available fair value information) and as of January 1, 2007 (with respect to statements of operations information). The unaudited pro forma combined financial information shows the impact of our acquisition of Northern Utilities and Granite State on the companies’ respective historical financial position and results of operations under the purchase method of accounting for business combinations. Under this method of accounting, the assets and liabilities of Northern Utilities and Granite State will be recorded, as of the completion of the Proposed Acquisitions, at their fair values and added to our assets and liabilities. The unaudited pro forma combined balance sheets as of December 31, 2007 and March 31, 2008 assume the Proposed Acquisitions were completed on those dates. The unaudited pro forma combined statement of earnings gives effect to the Proposed Acquisitions as if they had been completed on January 1, 2007.

The unaudited pro forma combined financial information has been derived from and should be read together with our historical consolidated financial statements and the related notes, which are incorporated by reference herein, and the historical financial statements and the related notes of both Northern Utilities and Granite State, which are included in this prospectus. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined and had the impact of possible revenue enhancements, expense efficiencies and asset disposition, among other factors, been considered, and is not intended to be a projection of future results. In addition, as explained in more detail in the accompanying notes to the unaudited pro forma combined financial information, the allocation of the purchase price reflected in the unaudited pro forma combined financial information is subject to adjustment and may vary from the actual purchase price allocation that will be recorded upon the effective completion of the Proposed Acquisitions.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with our historical financial statements and notes, which are incorporated by reference in this prospectus. For an overview of our business and a discussion of the uncertainties relating to our operations, refer to the sections entitled Our Company, Risk Factors — Risks Relating to Our Business, and Cautionary Statement About Forward-Looking Statements.

Three Months Ended March 31, 2008 and 2007

Results of Operations

Our Earnings Applicable to Common Shareholders (Net Income) was $3.3 million for the first quarter of 2008. EPS were $0.57 for the three months ended March 31, 2008, an improvement of $0.11 per share or 24% over the first quarter of 2007.

Our improved first quarter earnings in 2008 over 2007 were driven by higher gas sales margin and lower operating expenses, including the benefit from the proceeds of an insurance settlement associated with environmental remediation costs. These favorable factors were partially offset by higher amortization expense and higher interest expense in the current year.

The following table presents the significant items contributing to the improvement in earnings per share in the first quarter of 2008 compared to the same period in 2007:

 

Three Months Ended March 31, 2007		$	0.46
Electric Sales Margin			(0.04	)
Gas Sales Margin			0.10
Usource Sales Margin			0.01
Operation & Maintenance Expense			0.19
Depreciation, Amortization, Taxes & Other			(0.10	)
Interest Expense, Net			(0.05	)
Three Months Ended March 31, 2008		$	0.57

In the first quarter of 2008, our electric kilowatt hours (kWh) sales decreased 1.4% compared to the same period in 2007. Gas sales in the first quarter of 2008 decreased 1.7% compared to the same period in 2007. The lower unit sales in 2008 compared to 2007 were driven by milder winter weather this year and lower average usage by our customers reflecting a slowing economy and energy conservation.

Electric sales margin was lower by $0.4 million in the three months ended March 31, 2008 compared to the same period in 2007 due to lower electric kWh sales volumes, partially offset by higher electric base rates. Gas sales margin increased $0.9 million in the three months ended March 31, 2008 compared to the same period in 2007 reflecting higher gas base rates, implemented in 2007. Usource, our non-regulated energy brokering business, recorded increased sales margin of $0.1 million in the first quarter of 2008, an increase of 11% over the first quarter of 2007.

Total Operation & Maintenance (O&M) expenses decreased $1.8 million for the three month period ended March 31, 2008 compared to the same period in 2007. This decrease reflects a reduction to operating expenses of $2.8 million from the proceeds of an insurance settlement associated with environmental remediation costs. This reduction to operating expenses was partially offset by annual increases in salary, wage and benefit costs of $0.7 million, higher professional fees of $0.2 million and higher bad debt expenses of $0.1 million.

 

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Depreciation, Amortization, Taxes & Other expenses increased $1.2 million in the three month period ended March 31, 2008 compared to the same period in 2007 primarily reflecting the amortization of $0.7 million of natural gas inventory carrying costs and higher income taxes on higher levels of pre-tax earnings in 2008 compared to 2007.

Interest Expense, Net increased $0.5 million in the three month period ended March 31, 2008 compared to the same period in 2007 primarily reflecting higher debt outstanding.

In 2007, our annual common dividend was $1.38, representing an unbroken record of quarterly dividend payments since trading began in our common stock. At our January 2008 and March 2008 meetings, our Board of Directors declared quarterly dividends on our common stock of $0.345 per share.

A more detailed discussion of our results of operations for the three months ended March 31, 2008 and a period-to-period comparison of changes in financial position are presented below.

Balance Sheet

Our investment in Net Utility Plant increased by $11.7 million as of March 31, 2008 compared to March 31, 2007. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems, including expenditures of approximately $1.0 million for our Advanced Metering Infrastructure (AMI) project.

Regulatory Assets decreased $29.0 million as of March 31, 2008 compared to March 31, 2007, primarily reflecting current year cost recoveries. A significant portion of this decrease is matched by a corresponding decrease of $19.9 million in Power Supply Contract Obligations. The remaining decrease primarily reflects lower levels of Regulatory Assets associated with deferred taxes and RBO as well as recoveries of deferred charges.

Long-Term Debt increased $19.6 million as of March 31, 2008 compared to March 31, 2007, reflecting the issuance and sale on May 2, 2007 by Unitil Corporation of $20.0 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. Short-Term Debt decreased $13.0 million as of March 31, 2008 compared to March 31, 2007, as short-term borrowings were refinanced with the issuance of Senior Long-Term Notes, discussed above.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales. In the first quarter of 2008, our total electric kWh sales decreased 1.4% compared to the first quarter of 2007. Sales to residential and commercial/industrial (C&I) customers decreased 0.9% and 1.7%, respectively, in the first quarter of 2008 compared to the same period in 2007. The lower kWh sales in 2008 compared to 2007 were primarily driven by lower average usage by our customers reflecting a slowing economy and energy conservation.

The following table details total kWh sales for the three months ended March 31, 2008 and 2007 by major customer class:

 

		Three Months Ended March 31,
kWh Sales (millions)		2008		2007		Change			% Change
Residential		182.4		184.0		(1.6	)		(0.9	%)
Commercial / Industrial		261.1		265.6		(4.5	)		(1.7	%)
Total		443.5		449.6		(6.1	)		(1.4	%)

 

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Electric Operating Revenues and Sales Margin. The following table details Total Electric Operating Revenues and Sales Margin for the three months ended March 31, 2008 and 2007:

 

		Three Months Ended March 31,
(millions)		2008			2007			$ Change				% Change(1)
Electric Operating Revenue:
Residential		$	30.3		$	32.8		$	(2.5	)		(4.0	%)
Commercial / Industrial			26.3			29.9			(3.6	)		(5.7	%)
Total Electric Operating Revenue		$	56.6		$	62.7		$	(6.1	)		(9.7	%)
Cost of Electric Sales:
Purchased Electricity		$	42.9		$	48.2		$	(5.3	)		(8.5	%)
Conservation & Load Management			0.6			1.0			(0.4	)		(0.6	%)
Electric Sales Margin		$	13.1		$	13.5		$	(0.4	)		(0.6	%)

 

(1)

Represents change as a percent of Total Electric Operating Revenue.

Total Electric Operating Revenues decreased by $6.1 million, or 9.7%, in the three months ended March 31, 2008 compared to the same period in 2007. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in Operating Expenses. The decrease in Total Electric Operating Revenues in the three months ended March 31, 2008 reflects lower Purchased Electricity costs of $5.3 million, lower C&LM revenues of $0.4 million and lower sales margin of $0.4 million.

Purchased Electricity and C&LM revenues decreased a combined $5.7 million, or 9.1%, of Total Electric Operating Revenues in the three months ended March 31, 2008 compared to the same period in 2007, reflecting lower electric kWh sales, an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower electric commodity prices. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. We recover the cost of Purchased Electricity and C&LM in our rates at cost on a pass-through basis.

Electric sales margin was lower by $0.4 million in the three months ended March 31, 2008 compared to the same period in 2007 due to lower electric kWh sales volumes, partially offset by higher electric base rates.

Gas Sales, Revenues and Margin

Therm Sales. Therm sales of natural gas decreased 1.7% in the three months ended March 31, 2008 compared to the same period in 2007. Sales to residential customers and C&I customers decreased 2.0% and 1.4%, respectively, in the first quarter of 2008 compared to the same period in 2007. The decrease in gas sales in 2008 reflects a milder winter heating season this year and lower average usage by our customers reflecting a slowing economy and energy conservation.

 

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The following table details total firm therm sales for the three months ended March 31, 2008 and 2007, by major customer class:

 

		Three Months Ended March 31,
Therm Sales (millions)		2008		2007		Change			% Change
Residential		4.8		4.9		(0.1	)		(2.0	%)
Commercial / Industrial		6.8		6.9		(0.1	)		(1.4	%)
Total		11.6		11.8		(0.2	)		(1.7	%)

Gas Operating Revenues and Sales Margin. The following table details Total Gas Operating Revenues and Sales Margin for the three months ended March 31, 2008 and 2007:

 

		Three Months Ended March 31,
(millions)		2008			2007			$ Change				% Change(1)
Gas Operating Revenue:
Residential		$	8.0		$	8.1		$	(0.1	)		(0.7	%)
Commercial / Industrial			6.3			6.1			0.2			1.4	%
Total Gas Operating Revenue		$	14.3		$	14.2		$	0.1			0.7	%
Cost of Gas Sales:
Purchased Gas		$	9.0		$	9.8		$	(0.8	)		(5.6	%)
Conservation & Load Management			—			—			—			—
Gas Sales Margin		$	5.3		$	4.4		$	0.9			6.3	%

 

(1)

Represents change as a percent of Total Gas Operating Revenue.

Total Gas Operating Revenues increased $0.1 million, or 0.7%, in the three months ended March 31, 2008 compared to the same period in 2007. Total Gas Operating Revenues include the recovery of the cost of sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The net increase in Total Gas Operating Revenues in the three months ended March 31, 2008 reflects higher sales margin of $0.9 million, offset by lower Purchased Gas costs of $0.8 million.

Operating Expenses

Purchased Gas and C&LM revenues decreased a combined $0.8 million, or 5.6%, of Total Gas Operating Revenues in the three months ended March 31, 2008 compared to the same period in 2007, primarily reflecting lower natural gas sales and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. Purchased Gas revenues include the recovery of the cost of gas supply as well as the other energy supply related costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. We recover the cost of Purchased Gas and C&LM in our rates at cost on a pass-through basis.

Gas sales margin increased $0.9 million in the three months ended March 31, 2008 compared to the same period in 2007 reflecting higher gas base rates, implemented in 2007.

 

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Operating Revenue – Other

The following table details total Other Operating Revenue for the three months ended March 31, 2008 and 2007:

 

		Three Months Ended March 31,
(millions)		2008			2007			$ Change			% Change
Other		$	1.0		$	0.9		$	0.1		11.1	%
Total Other Revenue		$	1.0		$	0.9		$	0.1		11.1	%

Total Other Operating Revenue increased $0.1 million, or 11.1%, in the three month period ended March 31, 2008 compared to the same period in 2007. The increase was the result of growth in revenues from our non-regulated energy brokering business, Usource.

Purchased Electricity. Purchased Electricity expenses include the cost of electric supply as well as the other energy supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity decreased $5.3 million, or 11.0%, in the three month period ended March 31, 2008 compared to the same period in 2007, reflecting lower electric kWh sales, an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower electric commodity prices. We recover the costs of Purchased Electricity in our rates at cost on a pass-through basis and therefore changes in these expenses do not affect Net Income.

Purchased Gas. Purchased Gas expenses include the cost of gas purchased and manufactured to supply our total gas supply requirements. Purchased Gas decreased $0.8 million, or 8.2%, in the three month period ended March 31, 2008 compared to the same period in 2007, primarily reflecting lower natural gas sales and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. We recover the costs of Purchased Gas in our rates at cost on a pass-through basis and therefore changes in these expenses do not affect Net Income.

Operation and Maintenance. O&M expense includes electric and gas utility operating costs, and the operating cost of our unregulated business activities. Total O&M expenses decreased $1.8 million for the three month period ended March 31, 2008 compared to the same period in 2007. This decrease reflects a reduction to operating expenses of $2.8 million from the proceeds of an insurance settlement associated with environmental remediation costs. This reduction to operating expenses was partially offset by annual increases in salary, wage and benefit costs of $0.7 million, higher professional fees of $0.2 million and higher bad debt expenses of $0.1 million.

Conservation & Load Management. C&LM expenses are associated with the development, management and delivery of our Energy Efficiency programs. Energy Efficiency programs are designed, in conformity with state regulatory requirements, to help consumers use electricity and natural gas more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance and rebates that contribute toward the cost of purchasing and installing approved measures. Approximately 90% of these costs are related to electric operations and 10% to gas operations.

Total C&LM expenses decreased by $0.4 million, or 40.0%, in the three month period ended March 31, 2008 compared to the same period in 2007. The decrease reflects the timing of spending on the implementation of Energy Efficiency programs. These costs are collected from customers on a pass-through basis and, therefore, fluctuations in program costs have no impact on Net Income.

 

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Depreciation, Amortization and Taxes

Depreciation and Amortization. Depreciation and Amortization expense increased $0.7 million, or 15.6%, for the three month period ended March 31, 2008 compared to the same period in 2007. This increase primarily reflects the amortization of $0.7 million of natural gas inventory carrying costs deferred under a previous regulatory ruling.

Local Property and Other Taxes. Local Property and Other Taxes increased by $0.2 million, or 13.3%, for the three month period ended March 31, 2008 compared to the same period in 2007. This increase was due to higher property tax rates on increased property assessments and higher payroll taxes on higher compensation expenses.

Federal and State Income Taxes. Federal and State Income Taxes were higher by $0.2 million for the three month period ended March 31, 2008 compared to the same period in 2007 reflecting higher pre-tax earnings.

Other Non-Operating Expense

Other Non-Operating Expense increased by $0.1 million in the three month period ended March 31, 2008 compared to the same period in 2007. This increase reflects an adjustment of $0.1 million in conjunction with our recently approved electric base distribution rate increase in Massachusetts.

Interest Expense, Net

Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. Certain reconciling rate mechanisms used by our distribution operating utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated.

We operate a number of reconciling rate mechanisms to recover specifically identified costs on a pass-through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with our tariff, interest is accrued on these balances and will produce either interest income or interest expense. Interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.

 

		Three Months Ended March 31,
Interest Expense, Net (millions)		2008				2007				Change
Interest Expense
Long-Term Debt		$	2.9			$	2.6			$	0.3
Short-Term Debt			0.2				0.4				(0.2	)
Regulatory Liabilities			—				—				—
Subtotal Interest Expense			3.1				3.0				0.1
Interest Income
Regulatory Assets			(0.6	)			(0.8	)			0.2
AFUDC and Other			0.1				(0.1	)			0.2
Subtotal Interest Income			(0.5	)			(0.9	)			0.4
Total Interest Expense, Net		$	2.6			$	2.1			$	0.5

 

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Interest Expense, Net increased by $0.5 million in the three month period ended March 31, 2008 compared to the same period in 2007. Interest expense on long-term borrowings increased due to the issuance of new long-term debt by us on May 2, 2007. We issued and sold $20 million of Senior Long-Term Notes at a coupon rate of 6.33% through a private placement to institutional investors. We utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of our principal utility subsidiaries. The resulting reduction in average daily short-term bank borrowings lowered short-term interest expense for the first quarter of 2008 compared to the same period in 2007. An adjustment of $0.2 million related to earnings on funds used for capital projects ordered in conjunction with our recently approved electric base distribution rate increase in Massachusetts and lower carrying charges earned on regulatory assets also contributed to the increase in Interest Expense, Net.

Capital Requirements

Sources of Capital

We require capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities, excluding payment of dividends. We initially supplement internally generated funds through bank borrowings, as needed, under unsecured short-term bank lines. We had short-term debt outstanding through bank borrowings of $16.7 and $29.7 at March 31, 2008 and March 31, 2007, respectively. In addition, we had approximately $4.0 million in cash at March 31, 2008. Periodically, we replace portions of our short-term debt with long-term financings more closely matched to the long-term nature of our utility assets.

The continued availability of these methods of financing, as well as our choice of a specific form of security, will depend on many factors including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions, if any; the level of our earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

On February 15, 2008, we entered into a Stock Purchase Agreement with NiSource and Bay State to acquire all of the outstanding stock of Northern Utilities and Granite State. We have a commitment letter to enter into a senior unsecured bridge facility, which may be used to finance the transaction. We anticipate either financing the initial acquisition or refinancing the bridge facility with the issuance of a combination of long-term debt and common equity securities.

We provide limited guarantees on certain energy contracts entered into by our regulated subsidiary companies. Our policy is to limit these guarantees to the duration of the contracts, which can range from less than one month to three years. As of March 31, 2008, there were approximately $6.0 million of guarantees outstanding and the longest term guarantee extends through October 31, 2009.

The tables below summarize the major sources and uses of cash (in millions) for the three months ended March 31, 2008, compared to the same period in 2007.

 

(millions)		2008			2007
Cash Provided by Operating Activities		$	7.9		$	6.1

Cash Provided by Operating Activities. Cash Provided by Operating Activities was $7.9 million during the first three months ended March 31, 2008, an increase of $1.8 million over the comparable period in 2007. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes of $1.0 million, was $1.7 million higher in the first three months of 2008 compared to 2007. Working Capital related cash flows increased by $0.6 million during the first three months of 2008

 

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compared to the same period in 2007. Deferred Restructuring Charges were a $1.0 million source of cash in the first quarter of 2008 compared to the same period in 2007. These charges were deferred in prior periods for collection in current rates. All other changes in operating activities were a net $1.5 million in uses of cash in the first three months of 2008 compared to 2007, including a $2.8 million source of cash from the insurance settlement discussed above.

 

(millions)		2008				2007
Cash (Used in) Investing Activities		$	(4.5	)		$	(9.6	)

Cash (Used in) Investing Activities. Cash (Used in) Investing Activities was $4.5 million for the three months ended March 31, 2008 reflecting a source of cash due to a decrease in capital spending of $5.1 million over the comparable period in 2007 mainly due to the completion of our AMI project. In the first quarter 2007, capital expenditures included approximately $2.8 million of cash outlays for investment in the AMI project. Capital expenditure projections are subject to changes during the fiscal year.

 

(millions)		2008				2007
Cash Provided by (Used in) Financing Activities		$	(4.0	)		$	1.7

Cash Provided by (Used in) Financing Activities. Cash Used in Financing Activities was $4.0 million in the three months ended March 31, 2008, a decrease of $5.7 million over the comparable period in 2007. Cash provided from short-term debt declined by $5.8 million in the first quarter of 2008, principally reflecting the repayment of short-term debt from the proceeds of an insurance settlement. All other cash flows provided from other financing activities aggregated to a net $0.1 million increase in the first three months of 2008 as compared to the same period in 2007.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, management is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in our financial statements. If actual results were to differ significantly from those estimates, assumptions and judgments, our financial statements could be materially different than reported. The following is a summary of our most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of our significant accounting policies, refer to Note 1 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference.

Regulatory Accounting. Our principal business is the distribution of electricity and natural gas by the retail distribution companies: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC, FG&E is regulated by the MDPU, and UES is regulated by the NHPUC. Accordingly, we use the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). In accordance with SFAS No. 71, we have recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

 

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Our principal regulatory assets and liabilities are detailed on our Consolidated Balance Sheet and a summary of our Regulatory Assets is provided below. We receive a return on investment on our regulated assets for which a cash outflow has been made.

Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on our consolidated financial statements. We believe it is probable that our regulated utility companies will recover their investments in long-lived assets, including regulatory assets. We also have commitments under long-term contracts for the purchase of electricity and natural gas from various suppliers. The annual costs under these contracts are included in Purchased Electricity and Purchased Gas in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by the FERC, MDPU and NHPUC.

 

		March 31,						December 31,
Regulatory Assets consist of the following (millions)		2008			2007			2007
Power Supply Buyout Obligations		$	67.7		$	87.6		$	72.7
Deferred Restructuring Costs			29.6			30.9			30.5
Generation-related Assets			1.4			2.1			1.6
Subtotal – Restructuring Related Items			98.7			120.6			104.8
Retirement Benefit Obligations			35.1			37.1			35.1
Income Taxes			14.2			18.7			14.6
Environmental Obligations			13.3			13.0			13.1
Other			3.0			3.9			2.9
Total Regulatory Assets		$	164.3		$	193.3		$	170.5

If we, or a portion of our assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, we would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises – Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In our opinion, our regulated operations will be subject to SFAS No. 71 for the foreseeable future.

Utility Revenue Recognition. Regulated utility revenues are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. The determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

Allowance for Doubtful Accounts. We recognize a provision for doubtful accounts each month. The amount of the monthly provision for doubtful accounts is based upon our experience in collecting electric and gas utility service accounts receivable in prior years. Account write-offs, net of recoveries, are processed monthly. At the end of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. We are authorized by regulators to recover the supply-related portion of our written-off accounts from customers

 

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through periodically reconciling rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with us. Also, we have experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, we adjust the provision for doubtful accounts to maintain an adequate Allowance for Doubtful Accounts balance. It has been our experience that the assumptions we have used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Retirement Benefit Obligations. We sponsor the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of our employees. We also sponsor an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain of our executives and an employee 401(k) savings plan. Additionally, we sponsor the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

In September 2006, the FASB issued SFAS No. 158, an amendment of SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” SFAS No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their RBO based on the projected benefit obligation. We have recognized a corresponding Regulatory Asset to recognize the future collection of these obligations in electric and gas retail rates.

Our reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. We have made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. Our health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. Our RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. Our RBO may also be significantly affected by changes in key actuarial assumptions including anticipated rates of return on plan assets and the discount rates used in determining our RBO.

If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on our financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For the years ended December 31, 2007 and 2006, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2007 and 2006, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $690,000 and $683,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $539,000 and $530,000, respectively. See Note 8 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference.

 

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Income Taxes. Provisions for income taxes are calculated in each of the jurisdictions in which we operate for each period for which a statement of income is presented. This process involves estimating our current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheets. We account for income tax assets, liabilities and expenses in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109), and under FASB Interpretation Number (FIN) 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of Financial Accounting Standards (FAS) 109 (FAS 109).

Depreciation. Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. We conduct independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and consider the results presented in these studies in determining the useful lives of our fixed assets. A change in the estimated useful lives of these assets could have a material impact on our consolidated financial statements.

Commitments and Contingencies. Our accounting policy is to record and/or disclose commitments and contingencies in accordance with FASB Statement No. 5, “Accounting for Contingencies” (SFAS No. 5). SFAS No. 5 applies to an existing condition, situation or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of March 31, 2008, we are not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference.

Refer to “Recently Issued Accounting Pronouncements” in Note 1 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference.

Labor Relations

Labor unions represent approximately 85 of our employees. In May 2005, we reached agreements with our bargaining units for new five-year contracts, effective June 1, 2005. These agreements replace contracts that expired on May 31, 2005.

Interest Rate Risk

The majority of our debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, we periodically repay our short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new long-term debt securities issued by us. In addition, our short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease our interest expense in future periods. For example, if we had an average amount of short-term debt outstanding of $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000 (pre-tax). The average interest rates on our short-term borrowings for the three months ended March 31, 2008 and March 31, 2007 were 3.84% and 5.77%, respectively.

 

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Market Risk

Although our utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, we have divested our commodity-related contracts and therefore, further reduced our exposure to commodity risk.

Regulatory Matters

Please refer to Note 6 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference.

Environmental Matters

Please refer to Note 7 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2008, which is incorporated herein by reference, for a discussion of Environmental Matters.

Fiscal Years Ended December 31, 2007, 2006 and 2005

Results of Operations

Net Income and EPS Overview

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006. Our Net Income was $8.6 million for 2007, an increase of 9% over 2006 Net Income of $7.9 million. EPS were $1.52 for 2007, $0.11 per share higher than last year.

Earnings in 2007 reflect higher electric and gas sales margins, driven by higher rates and increased sales of natural gas, and improved profits from Usource. Partially offsetting these factors were higher operating expenses.

The following table presents the significant items (discussed below) contributing to the change in earnings per share in 2007 as compared to 2006:

2007 Earnings Per Share vs. 2006

 

		2006		$	1.41
Electric Sales Margin					0.21
Gas Sales Margin					0.23
Usource Sales Margin					0.14
Operation & Maintenance Expense					(0.06	)
Depreciation, Amortization & Other					(0.22	)
Interest Expense, Net					(0.19	)
		2007		$	1.52

Our total electric kWh sales decreased 0.5% in 2007 compared to 2006. Electric kWh sales to residential customers increased 0.4% in 2007 compared to 2006. The lower kWh sales in 2007 compared to 2006 were primarily driven by cooler summer weather in 2007, energy conservation by our customers and a slowing economy.

 

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Our total therm sales of natural gas increased 7.6% in 2007 compared to 2006. The increase in gas sales in 2007 reflects a colder winter heating season in 2007 and higher natural gas sales to C&I customers. In 2007, natural gas sales to residential customers increased 4.1% compared to 2006 while sales to C&I customers increased 9.6% compared to 2006, primarily due to a special contract with a large industrial customer.

Total electric and gas sales margin increased $3.9 million in 2007 compared to 2006. This increase reflects higher gas and electric rates and increased sales of natural gas.

Total O&M expense increased $0.5 million, or 1.9%, in 2007 compared to 2006. This increase reflects higher employee and retiree compensation and benefit expenses of $0.8 million, higher bad debt expenses of $0.1 million and an increase in all other operating expenses of $0.2 million, net, offset by lower distribution utility operating expenses of $0.6 million.

Depreciation, Amortization, Taxes and Other expenses increased $2.2 million in 2007 compared to 2006 reflecting higher depreciation on normal utility plant additions in 2007 and income taxes on higher levels of pre-tax earnings in 2007 compared to 2006.

Interest Expense, Net increased $1.8 million in 2007 compared to 2006 reflecting higher debt outstanding, higher interest rates and higher interest expense recorded on reconciling mechanisms.

Usource, our non-regulated energy brokering business, recorded revenues of $3.7 million in 2007, an increase of $1.3 million over 2006. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

In 2007, our annual common dividend was $1.38, representing an unbroken record of quarterly dividend payments since trading began in our common stock. At its January 2008 meeting, our Board of Directors declared a quarterly dividend on our common stock of $0.345 per share.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005. Our Net Income was $7.9 million for 2006. EPS were $1.41 for 2006 compared to $1.51 for 2005. Earnings in 2006 reflect lower electric and gas sales. The lower sales in 2006 were primarily driven by milder weather compared to 2005. Earnings in 2006 also reflect higher operating and maintenance expenses and interest costs. Partially offsetting these factors was an increase in electric distribution rates in 2006 for our utility subsidiary in New Hampshire and increased gas delivery sales under a new contract with a large industrial customer in Massachusetts.

A more detailed discussion of our 2007 and 2006 results of operations and a year-to-year comparison of changes in financial position are presented below.

Balance Sheet

Our investment in Net Utility Plant increased by $17.1 million in 2007 compared to 2006. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems, including expenditures of approximately $6.6 million for our AMI project.

Regulatory Assets decreased $28.3 million in 2007 compared to 2006, primarily reflecting current year cost recoveries. A significant portion of this decrease is matched by a corresponding decrease of $19.9 million in Power Supply Contract Obligations.

Long-Term Debt increased $19.6 million in 2007 compared to 2006 reflecting the issuance and sale on May 2, 2007 by Unitil Corporation of $20.0 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. Short-Term Debt decreased $7.2 million in 2007 compared to 2006, as short-term borrowings were refinanced with the issuance of Senior Long-Term Notes, discussed above.

 

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Electric Sales, Revenues and Margin

Kilowatt-hour Sales. Our total electric kWh sales decreased 0.5% in 2007 compared to 2006. Electric kWh sales to residential customers increased 0.4% in 2007 compared to 2006. The lower total kWh sales in 2007 compared to 2006 were driven by cooler summer weather in 2007, energy conservation by customers in response to higher overall energy prices and environmental concerns, and a slowing economy.

Our total kWh sales decreased 2.2% in 2006 compared to 2005. This decrease reflects a decline in average energy usage per customer, primarily due to milder weather in 2006 compared to 2005 and increased energy conservation by customers.

The following table details total kWh sales for the last three years by major customer class:

 

								2007 vs. 2006						2006 vs. 2005
kWh Sales (millions)		2007		2006		2005		kWh Change			% Change			kWh Change			% Change
Residential		674.8		672.2		688.3		2.6			0.4	%		(16.1	)		(2.3	%)
Commercial / Industrial		1,068.2		1,079.3		1,102.1		(11.1	)		(1.0	%)		(22.8	)		(2.1	%)
Total		1,743.0		1,751.5		1,790.4		(8.5	)		(0.5	%)		(38.9	)		(2.2	%)

Electric Operating Revenues and Sales Margin. The following table details total Electric Operating Revenue and Sales Margin for the last three years by major customer class:

 

											2007 vs. 2006							2006 vs. 2005
(millions)		2007			2006			2005			$ Change				% Change(1)			$ Change				% Change(1)
Electric Operating Revenue:
Residential		$	114.7		$	105.9		$	85.3		$	8.8			3.9	%		$	20.6			10.4	%
Commercial / Industrial			110.3			119.3			112.0			(9.0	)		(4.0	%)			7.3			3.7	%
Total Electric Operating Revenue		$	225.0		$	225.2		$	197.3		$	(0.2	)		(0.1	%)		$	27.9			14.1	%
Cost of Electric Sales:
Purchased Electricity		$	165.4		$	167.3		$	138.1		$	(1.9	)		(0.8	%)		$	29.2			14.8	%
Conservation & Load Management			3.4			3.6			3.8			(0.2	)		(0.1	%)			(0.2	)		(0.1	%)
Electric Sales Margin		$	56.2		$	54.3		$	55.4		$	1.9			0.8	%		$	(1.1	)		(0.6	%)

 

(1)

Represents change as a percent of Total Electric Operating Revenue.

Total Electric Operating Revenues decreased by $0.2 million, or 0.1%, in 2007 compared to 2006. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and C&LM in Operating Expenses. The net decrease in Total Electric Operating Revenues in 2007 reflects lower Purchased Electricity costs of $1.9 million and lower C&LM revenues of $0.2 million, offset by higher sales margin of $1.9 million.

Purchased Electricity and C&LM revenues decreased $2.1 million, or 0.9%, of Total Electric Operating Revenues in 2007 compared to 2006, primarily reflecting an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric commodity prices. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM

 

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revenues include the recovery of the cost of energy efficiency and conservation programs. We recover the cost of Purchased Electricity and C&LM in our rates at cost on a pass-through basis.

Electric sales margin increased $1.9 million in 2007 compared to 2006. The improvement in electric sales margin reflects higher average distribution rates in 2007 compared to 2006, partially offset by lower sales volumes due to cooler summer weather in 2007, energy conservation by customers in response to higher overall energy prices and environmental concerns, and a slowing economy.

In 2006, Total Electric Operating Revenues increased by $27.9 million, or 14.1%, compared to 2005. The net increase in Total Electric Operating Revenues in 2006 reflects higher Purchased Electricity costs of $29.2 million, offset by lower sales margin of $1.1 million and lower C&LM revenues of $0.2 million. Purchased Electricity and C&LM revenues increased a net $29.0 million, or 14.7%, of Total Electric Operating Revenues in 2006 compared to 2005, reflecting higher electric commodity prices.

Electric sales margin was lower by $1.1 million in 2006 compared to 2005, reflecting a decrease in revenue of $3.2 million related to the expiration of the Seabrook Amortization Surcharge (SAS) in late 2005. Absent the decrease in SAS revenues, electric sales margin increased $2.1 million in 2006 compared to 2005. The higher sales margin in 2006 primarily reflects our approved base rate increase in New Hampshire of $2.7 million, partially offset by lower sales margin of $0.6 million resulting from a decline in average energy usage per customer, primarily due to significantly milder weather and energy conservation.

Gas Sales, Revenues and Margin

Therm Sales. Our total therm sales of natural gas increased 7.6% in 2007 compared to 2006. The increase in gas sales in 2007 reflects a colder winter heating season in 2007 and higher natural gas sales to C&I customers. In 2007, natural gas sales to residential customers increased 4.1% compared to 2006 while sales to C&I customers increased 9.6% compared to 2006, primarily due to a special contract with a large industrial customer.

Our total therm sales of natural gas increased 8.6% in 2006 compared to 2005, due to a new gas transportation sales contract with a large industrial customer. Sales to residential customers decreased 10.9% in 2006 compared to 2005 due to a milder winter heating season in 2006 compared to the prior year. Sales to C&I customers increased 24.8% in 2006 compared to 2005. Absent the sales from the new contract, discussed above, sales to C&I customers were 10.4% lower in 2006 compared to 2005 primarily due to a milder winter heating season.

The following table details total therm sales for the last three years by major customer class:

 

								2007 vs. 2006					2006 vs. 2005
Therm Sales (millions)		2007		2006		2005		Change		% Change			Change			% Change(1)
Residential		10.2		9.8		11.0		0.4		4.1	%		(1.2	)		(10.9	%)
Commercial / Industrial		18.2		16.6		13.3		1.6		9.6	%		3.3			24.8	%
Total		28.4		26.4		24.3		2.0		7.6	%		2.1			8.6	%

 

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Gas Operating Revenues and Sales Margin. The following table details total Gas Operating Revenue and Margin for the last three years by major customer class:

 

											2007 vs. 2006							2006 vs. 2005
(millions)		2007			2006			2005			$ Change				% Change(1)			$ Change				% Change(1)
Gas Operating Revenue:
Residential		$	18.8		$	17.2		$	18.1		$	1.6			4.8	%		$	(0.9	)		(2.8	%)
Commercial / Industrial			15.4			16.1			14.7			(0.7	)		(2.1	%)			1.4			4.3	%
Total Gas Operating Revenue		$	34.2		$	33.3		$	32.8		$	0.9			2.7	%		$	0.5			1.5	%
Cost of Gas Sales:
Purchased Gas		$	21.3		$	22.4		$	21.2		$	(1.1	)		(3.3	%)		$	1.2			3.7	%
Conservation & Load Management			0.2			0.2			0.3			—			—				(0.1	)		(0.4	%)
Gas Sales Margin		$	12.7		$	10.7		$	11.3		$	2.0			6.0	%		$	(0.6	)		(1.8	%)

 

(1)

Represents change as a percent of Total Gas Operating Revenue.

Total Gas Operating Revenues increased $0.9 million, or 2.7%, in 2007 compared to 2006. Total Gas Operating Revenues include the recovery of the cost of sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The increase in Total Gas Operating Revenues in 2007 reflects higher sales margin of $2.0 million, partially offset by lower Purchased Gas costs of $1.1 million.

Purchased Gas and C&LM revenues decreased $1.1 million, or 3.3%, of Total Gas Operating Revenues in 2007 compared to 2006, reflecting lower natural gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third-party suppliers. Purchased Gas revenues include the recovery of the cost of gas supply as well as the other energy supply related costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. We recover the cost of Purchased Gas and C&LM in our rates at cost on a pass-through basis.

Natural gas sales margin increased $2.0 million in 2007 compared to 2006 reflecting higher sales and new natural gas distribution rates approved and implemented in 2007.

In 2006, Total Gas Operating Revenues increased $0.5 million, or 1.5%, compared to 2005. The net increase in Total Gas Operating Revenues in 2006 reflects higher Purchased Gas costs of $1.2 million, offset by lower sales margin of $0.6 million and lower C&LM revenues of $0.1 million. Purchased Gas and C&LM revenues increased a net $1.1 million, or 3.3%, of Total Gas Operating Revenues in 2006 compared to 2005, reflecting higher gas commodity prices and higher unit sales during those periods.

Gas sales margin for 2006 decreased $0.6 million compared to 2005. This decline in gas sales margin was due to lower therm sales, which, absent the sales from the new contract were 10.8% lower in 2006 compared to 2005. The lower gas sales were primarily due to a milder winter heating season. The weather in our service territories in the winter of 2006 was approximately 12% warmer than in the same period for 2005, reflecting a record warm winter heating season.

Operating Revenue – Other

Total Other Revenue increased $1.3 million in 2007 compared to 2006 and $0.4 million in 2006 compared to 2005. These increases were the result of growth in revenues from our non-regulated energy

 

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brokering business, Usource. Usource’s revenues are primarily derived from fees and charges billed to suppliers as customers take delivery of energy from these suppliers under term contracts brokered by Usource.

The following table details total Other Revenue for the last three years:

 

											2007 vs. 2006						2006 vs. 2005
(millions)		2007			2006			2005			$ Change			% Change			$ Change			% Change
Usource		$	3.7		$	2.4		$	2.0		$	1.3		54.2	%		$	0.4		20.0	%
Total Other Revenue		$	3.7		$	2.4		$	2.0		$	1.3		54.2	%		$	0.4		20.0	%

Operating Expenses

Purchased Electricity. Purchased Electricity includes the cost of electric supply as well as other energy supply related restructuring costs, including power supply buyout costs. Purchased Electricity decreased $1.9 million, or 1.1%, in 2007 compared to 2006. This decrease reflects lower electric kWh sales and an increase in the amount of electricity purchased by customers directly from third-party suppliers, partially offset by higher electric commodity prices. We recover the costs of Purchased Electricity in our rates at cost and therefore changes in these expenses do not affect earnings.

In 2006, Purchased Electricity expenses increased $29.2 million, or 21.1%, compared to 2005 due to higher electric commodity prices.

Purchased Gas. Purchased Gas includes the cost of natural gas purchased and manufactured to supply our total gas supply requirements. Purchased Gas decreased $1.1 million, or 4.9%, in 2007 compared to 2006. The decrease in Purchased Gas is attributable to lower gas commodity prices and an increase in the amount of natural gas purchased by customers directly from third party suppliers, partially offset by increased therm sales. We recover the costs of Purchased Gas in our rates at cost on a pass-through basis and therefore changes in these expenses do not affect Net Income.

In 2006, Purchased Gas increased by $1.2 million, or 5.7%, compared to 2005, reflecting increased therm sales and higher gas commodity costs.

Operation and Maintenance. O&M expense includes electric and gas utility operating costs, and the operating costs of our non-regulated business activities. Total O&M expense increased $0.5 million, or 1.9%, in 2007 compared to 2006. This increase reflects higher employee and retiree compensation and benefit expenses of $0.8 million, higher bad debt expenses of $0.1 million and an increase in all other operating expenses of $0.2 million, net, offset by lower distribution utility operating expenses of $0.6 million.

In 2006, total O&M expense increased $1.2 million, or 4.9%, compared to 2005. This increase reflects higher retiree and employee compensation and benefit costs of $1.1 million and an increase in all other operating expenses of $0.1 million, net.

Conservation & Load Management. C&LM expenses are expenses associated with the development, management, and delivery of our energy efficiency programs. Energy efficiency programs are designed, in conformity to state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance, and rebates that contribute toward the cost of purchasing and installing approved measures. Approximately 90% of these costs are related to electric operations and 10% to gas operations.

 

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Total C&LM expenses decreased by $0.2 million in 2007 compared to 2006. These costs are collected from customers on a fully reconciling basis and, therefore, fluctuations in program costs do not affect earnings.

Total C&LM expenses decreased $0.3 million in 2006 compared to 2005.

Depreciation and Amortization. Depreciation and Amortization expense increased $1.7 million, or 10.6% in 2007 compared to 2006 reflecting higher depreciation on normal utility plant additions in 2007.

In 2006, Depreciation and Amortization expense decreased $3.0 million, or 15.7%, compared to 2005, reflecting lower amortization on regulatory assets, including Seabrook Station, and lower depreciation rates on utility plant established in our electric rate case settlement in New Hampshire, partially offset by depreciation on normal utility plant additions. Our regulatory asset related to our former abandoned property investment in Seabrook Station became fully-amortized in the third quarter of 2005.

Local Property and Other Taxes. Local Property and Other Taxes increased by $0.1 million, or 1.8%, in 2007 compared to 2006. This increase was due to higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

In 2006, Local Property and Other Taxes increased by $0.2 million, or 3.8%, compared to 2005. This increase was due to higher local property tax rates on higher levels of utility plant in service and higher payroll taxes.

Federal and State Income Taxes. Federal and State Income Taxes increased by $0.2 million in 2007 compared to 2006 due to higher pre-tax operating income in 2007 compared to 2006.

Federal and State Income Taxes were essentially flat in 2006 compared to 2005 due to lower pre-tax operating income in 2006 compared to 2005 offset by a higher effective tax rate in 2006 related to our former abandoned property investment in Seabrook Station, discussed above.

Other Non-operating Expenses (Income)

Other Non-operating Expenses (Income) increased by $0.2 million in 2007 compared to 2006. This change reflects the recognition in 2006 of a gain on the sale of land and timber harvest revenue.

Other Non-operating Expenses (Income) improved to income of $19,000 in 2006 compared to an expense of $147,000 in 2005 due to the gain discussed above.

Interest Expense, net

Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. Certain reconciling rate mechanisms used by our distribution operating utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated. See Note 3 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

In 2007, Total Interest Expense, net, rose by $1.8 million compared to 2006. This increase principally reflects our issuance of new long-term debt on May 2, 2007. We issued and sold $20 million of Senior Long-Term Notes at a coupon rate of 6.33% through a private placement to institutional investors. We utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of our principal utility subsidiaries. The resulting reduction in average daily short-term bank borrowings lowered short-term interest expense for the year which partially offset the increase in long-term interest expense.

 

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In 2006, Total Interest Expense, net, increased by $1.0 million compared to 2005. Interest expense on long-term borrowings increased due to the issuance of new fixed rate long-term debt. Our New Hampshire subsidiary, UES, issued and sold $15 million of Series O, 6.32% First Mortgage Bonds to institutional investors on September 26, 2006. In December 2005, our Massachusetts utility subsidiary, FG&E, issued $15 million of unsecured long-term notes to institutional investors at an interest rate of 5.90%. The proceeds from these long-term financings were used principally to finance utility plant additions that had been previously financed on an interim basis with short-term bank borrowings. Interest expense on short-term debt increased compared to 2005 primarily due to higher variable short-term interest rates. These increases in interest expense were partially offset by an increase in interest income due to higher carrying charges on regulatory assets.

Liquidity, Commitments and Capital Requirements

Sources of Capital

We require capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities, excluding payment of dividends. We initially supplement internally generated funds through bank borrowings, as needed, under unsecured short-term bank lines. At December 31, 2007, we had an aggregate of $30.0 million in unsecured revolving lines of credit with three banks. We anticipate that we will be able to secure renewal or replacement of some or all of our revolving lines of credit, in accordance with projected requirements. We had short-term debt outstanding through bank borrowings of $18.8 million and $26.0 million at December 31, 2007 and December 31, 2006, respectively. In addition, we had approximately $4.6 million in cash at December 31, 2007. Periodically, we replace portions of our short-term debt with long-term financings more closely matched to the long-term nature of our utility assets.

The maximum amount of short-term borrowings that we, along with our subsidiaries, may incur has been subject to periodic approval by our regulatory agencies. At December 31, 2007, we had regulatory authorization to incur total short-term bank borrowings up to a maximum of $55 million, and UES and FG&E had regulatory authorizations to borrow up to a maximum of $16 million and $35 million, respectively. In 2007, UES and FG&E had average short-term debt outstanding of $7.9 million and $18.1 million, respectively.

We, along with our subsidiaries, are individually and collectively members of the Unitil Cash Pool (Cash Pool). The Cash Pool is the financing vehicle for day-to-day cash borrowing and investing. The Cash Pool Agreement allows for an efficient exchange of cash among us and our subsidiaries. The interest rates charged to the subsidiaries for borrowing from the Cash Pool are based on our actual interest costs from our banks under the revolving lines of credit. At December 31, 2007, all of our subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

On May 2, 2007, we completed the sale of $20 million of Senior Long-Term Notes, through a private placement to institutional investors. The Notes have a term of 15 years maturity and a coupon rate of 6.33%. We utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of our principal utility subsidiaries. See Note 3 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

On September 26, 2006, UES issued and sold $15.0 million of Series O 6.32% First Mortgage Bonds, due September 15, 2036, to institutional investors in the form of a private placement. The proceeds from this long-term financing were used to repay short-term bank borrowings and permanently finance utility

 

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plant additions. In December 2005, FG&E issued and sold $15.0 million of 5.90% unsecured long-term notes under a debenture note structure. The proceeds were utilized to repay outstanding short-term indebtedness of FG&E and permanently finance utility plant additions. We expect to continue to be able to satisfy our external financing needs by utilizing additional short-term bank borrowings and to periodically replace short-term debt with long-term financings. See Note 3 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

The continued availability of these methods of financing, as well as our choice of a specific form of security, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions, if any; the level of our earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

Contractual Obligations

The table below lists our significant contractual obligations as of December 31, 2007.

 

					Payments Due by Period
(millions)		Total			2008			2009-2010			2011-2012			2013 and Beyond
Long-Term Debt		$	160.0		$	0.4		$	0.8		$	1.0		$	157.8
Capital Leases			0.8			0.3			0.3			0.2			—
Operating Leases			2.8			0.5			1.0			0.9			0.4
Power Supply Contract Obligations – MA			42.0			8.1			16.7			16.6			0.6
Power Supply Contract Obligations – NH			30.7			11.9			14.4			1.2			3.2
Gas Supply Contracts			23.2			16.0			3.9			3.0			0.3
Total Contractual Cash Obligations		$	259.5		$	37.2		$	37.1		$	22.9		$	162.3

We have material energy supply commitments that are discussed in Note 4 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference. Cash outlays for the purchase of electricity and natural gas to serve our customers are subject to reconciling recovery through periodic changes in rates, with carrying charges on deferred balances. From year to year, there are likely to be timing differences associated with the cash recovery of such costs, creating under- or over-recovery situations at any point in time. Rate recovery mechanisms are typically designed to collect the under-recovered cash or refund the over collected cash over subsequent 6-12 month periods.

We also provide limited guarantees on certain electric supply contracts entered into by the retail distribution utilities. Our policy is to limit these guarantees to the duration of the contracts, which can range from less than one month to three years. As of December 31, 2007 there are $6.5 million of guarantees outstanding and these guarantees extend through March 13, 2009.

Benefit Plan Funding

In 2007 and 2006, we, along with our subsidiaries, made cash contributions to our Pension Plan in the amount of $2.8 million and $2.5 million, respectively. In 2007 and 2006, we, along with our subsidiaries, contributed approximately $2.5 million and $2.2 million, respectively, to Voluntary Employee Benefit Trusts (VEBT). We, along with our subsidiaries, expect to continue to make contributions to our Pension Plan and the VEBT’s in future years in amounts consistent with the amounts recovered in retail distribution utility rates for these other postretirement benefit costs. See Note 8 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

 

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Off-Balance Sheet Arrangements

We do not currently use, and are not dependent on the use of, off-balance sheet financing arrangements such as securitization of receivables or obtaining access to assets or cash through special purpose entities or variable interest entities. We do have an operating lease agreement with a major financial institution. The operating lease is used to finance our utility vehicles. See Note 3 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Cash Flows

The tables below summarize the major sources and uses of cash (in millions) for 2007 compared to 2006.

 

(millions)		2007			2006
Cash Provided by Operating Activities		$	26.8		$	20.4

Cash Provided by Operating Activities. Cash Provided by Operating Activities was $26.8 million in 2007, an increase of $6.4 million compared to 2006. Sources of cash from Net Income were higher by $0.7 million compared to last year and sources of cash from Depreciation and Amortization rose by approximately $1.7 million. An additional $1.4 million of cash was utilized for Deferred Tax Provisions during the current year. Working capital related cash flows decreased $0.8 million in 2007 compared to 2006. Included in this change in working capital cash flows was an increase of $6.0 million year over year from Accrued Revenue, principally due to the recoveries of Accrued Revenues through reconciling cost recovery mechanisms. Sources of cash related to Deferred Restructuring Costs increased by $5.5 million in 2007 year over year, reflecting improvement in net cash flows for the collection of deferred costs related to utility industry restructuring. All other changes in cash flows from operating activities were a net increase of $0.7 million in sources of cash in 2007 compared to 2006.

 

(millions)		2007				2006
Cash (Used in) Investing Activities		$	(32.5	)		$	(33.6	)

Cash (Used in) Investing Activities. Cash (Used in) Investing Activities in 2007 was $32.5 million, a decrease of $1.1 million compared to 2006. Cash used in investing activities is primarily for capital expenditures related to UES’ and FG&E’s electric and gas distribution systems. Capital expenditures are projected to be $29.3 million in 2008, reflecting normal electric and gas utility plant additions. Capital expenditure projections are subject to changes during the fiscal year.

 

(millions)		2007			2006
Cash Provided by Financing Activities		$	5.7		$	14.6

Cash Provided by Financing Activities. Cash Provided by Financing Activities was $5.7 million in 2007, a decrease of $8.9 compared to 2006. Cash provided from short-term debt declined by $14.5 million in 2007, principally reflecting the repayment of short-term debt from the issuance of $20 million in Senior Long-Term Notes by us in May 2007, described above. Proceeds from long-term debt issuances increased by $5.0 million in 2007 as compared to 2006, reflecting the issuance of $20 million in Unitil Notes in 2007 and the $15 million in UES Bond financings in 2006, described above. All other cash flows provided from other financing activities aggregated to a net change in cash flows of $0.6 million in 2007.

 

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Financial Covenants and Restrictions

The agreements under which our long-term debt and that of our retail distribution utilities, UES and FG&E, were issued contain various covenants and restrictions. These agreements do not contain any covenants or restrictions pertaining to the maintenance of financial ratios or the issuance of short-term debt. These agreements do contain covenants relating to, among other things, the issuance of additional long-term debt, cross-default provisions and business combinations. See Note 3 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

The long-term debt and preferred stock of Unitil Corporation, UES and FG&E are privately held, and we do not issue commercial paper. For these reasons, our and our subsidiaries’ debt securities are not publicly rated.

Dividends

Our annualized common dividend was $1.38 per common share in 2007, 2006 and 2005. Our dividend policy is reviewed periodically by the Board of Directors. We have maintained an unbroken record of quarterly dividend payments since trading began in our common stock. At its January 2008 meeting, our Board of Directors declared a quarterly dividend on our common stock of $0.345 per share. The amount and timing of all dividend payments are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.

Regulatory Matters

Overview. Our retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in our franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E recover the cost of providing distribution service to their customers based on a representative test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in Massachusetts and New Hampshire, all of our customers have the opportunity to purchase their electric or natural gas supplies from third-party suppliers. Most small and medium-sized customers, however, continue to purchase such supplies through UES and FG&E as the providers of basic or default service energy supply. UES and FG&E purchase electricity or natural gas for basic or default service from unaffiliated wholesale suppliers and recover the actual costs of these supplies, without profit or markup, through reconciling, pass-through rate mechanisms that are periodically adjusted.

In connection with the implementation of retail choice, Unitil Power and FG&E divested their long-term power supply contracts through the sale of the entitlements to the electricity sold under those contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, is $104.8 million as of December 31, 2007 and is included in Regulatory Assets on our Consolidated Balance Sheet. Our retail distribution companies have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans. See Note 5 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

FG&E – Electric Division. On August 17, 2007, FG&E filed an electric distribution rate increase of $3.3 million, which represents an increase of 4.7% over FG&E’s 2006 total electric operating revenue. The

 

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MDPU has suspended the effective date until March 1, 2008 in order to investigate the propriety of our request. Evidentiary hearings were held in November 2007 and briefing was completed in January 2008. We anticipate that we will receive a final order from the MDPU with an effective date for new electric rates of March 1, 2008.

FG&E – Gas Division. FG&E provides natural gas delivery service to its customers on a firm or interruptible basis under unbundled distribution rates approved by the MDPU. Its current retail distribution rates were approved by the MDPU in 2007. FG&E’s customers may purchase gas supplies from third-party vendors or purchase their gas from FG&E as the provider of last resort. FG&E collects its gas supply costs through a seasonal reconciling Cost of Gas Adjustment Clause and recovers other related costs through a reconciling Local Distribution Adjustment Clause.

On January 26, 2007, the MDPU approved a rate Settlement Agreement (Settlement) between FG&E and the Attorney General of Massachusetts for FG&E’s Gas Division (Gas Division). Under the Settlement, FG&E increased its gas distribution rates by $1.2 million on February 1, 2007, and an additional $1.0 million on November 1, 2007. The Settlement also included agreement on several other rate matters and service quality performance measures for our Gas Division in the areas of safety, customer service and satisfaction.

FG&E – Other. On June 22, 2007, the MDPU opened an inquiry into revenue decoupling, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utility’s distribution revenues on sales. Revenue decoupling is adopted with the intent of removing the disincentive a utility has to administer and promote customer efforts to reduce energy consumption and demand or to install distributed generation to displace electricity delivered by the utility. The order included a straw proposal for a base revenue adjustment mechanism that severs the link between electric and gas companies’ revenues and sales, and instead, ties company revenues to the number of customers served. Many interested parties filed comments on the elements of the straw proposal and on revenue decoupling in general. Several parties also provided comments in panel hearings organized by the MDPU. We filed comments generally supporting revenue decoupling and recommended modifications to the MDPU’s straw proposal. This matter remains pending.

UES. UES provides electric distribution service to its customers pursuant to rates approved by the NHPUC. Its current retail electric distribution rates were approved by the NHPUC in 2006 under a settlement agreement with the NHPUC.

On June 22, 2007, the NHPUC issued an order in its investigation into implementation of the federal Energy Policy Act of 2005 regarding the adoption of standards for time-based metering and interconnection. This order set the framework for implementation of time based rates for utility provided default service. On August 31, 2007, the NHPUC issued an order on motion for rehearing, staying the June 22, 2007 order pending hearing and reconsideration of the issues. An order following hearing was issued on January 22, 2008 finding that it is appropriate to implement time-based metering standards and ordering that the details, including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes shall be determined in separate proceedings to be initiated by the NHPUC.

On May 14, 2007, the NHPUC issued an order opening an investigation into the merits of instituting appropriate rate mechanisms, such as revenue decoupling, which would have the effect of removing obstacles to, and encouraging investment in, energy efficiency. Several parties attended the prehearing conference on June 18, 2007 and subsequent technical sessions. On July 30, 2007, the gas and electric utilities made baseline presentations designed to assist the parties in understanding current regulatory methods and the utilities’ assessment of existing incentives and barriers to energy efficiency investment. On November 7, 2007, the Commission hosted expert presentations about the potential of various regulatory approaches to promote energy efficiency. The proceeding remains open.

 

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Environmental Matters

Our past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. We believe we are in compliance with all applicable environmental and safety laws and regulations, and we believe that as of December 31, 2007, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Sawyer Passway MGP Site. FG&E continues to work with environmental regulatory agencies to identify and assess environmental issues at the former manufactured gas plant (MGP) site at Sawyer Passway, located in Fitchburg, Massachusetts. FG&E has proceeded with site remediation work as specified on the Tier 1B permit issued by the Massachusetts Department of Environmental Protection (DEP), which allows FG&E to work towards temporary closure of the site. A status of temporary closure requires FG&E to monitor the site until a feasible permanent remediation alternative can be developed and completed.

FG&E recovers the environmental response costs incurred at this former MGP site not recovered by insurance or other means in gas rates pursuant to terms of a cost recovery agreement approved by the MDPU. Pursuant to this agreement, FG&E is authorized to amortize and recover environmental response costs from gas customers over succeeding seven-year periods, without carrying costs. In addition FG&E has filed suit against several of its former insurance carriers seeking coverage for past and future environmental response costs at the site. Any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers.

FG&E is in the process of developing long range plans for a feasible permanent remediation solution for the Sawyer Passway site, including alternatives for re-use of the site. Included on our Consolidated Balance Sheet at December 31, 2007 and 2006 in Environmental Obligations is $12.0 million related to estimated future clean up costs for permanent remediation of the site. A corresponding Regulatory Asset was recorded to reflect the future rate recovery for these costs. The amounts recorded do not assume any amounts are recoverable from insurance companies or other third parties.

Our ultimate liability for future environmental remediation costs may vary from estimates, which may be adjusted as new information or future developments become available. Based on our current assessment of its environmental responsibilities, existing legal requirements and regulatory policies, we do not believe that these environmental costs will have a material adverse effect on our consolidated financial position or results of operations.

Employees and Employee Relations

As of December 31, 2007, we, along with our subsidiaries, had 291 employees. We consider our relationships with employees to be good and have not experienced any major labor disruptions.

There are approximately 85 employees represented by labor unions. These employees are covered by collective bargaining agreements, which expire May 31, 2010. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. We expect to successfully negotiate new agreements prior to their expiration dates.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles in the United States of America requires us to make estimates and assumptions that affect the

 

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reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, we are sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in our financial statements. If actual results were to differ significantly from those estimates, assumptions and judgment, our financial position could be materially affected and our results of operations could be materially different than reported. The following is a summary of our most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of our significant accounting policies, refer to the financial statements and Note 1 (Summary of Significant Accounting Policies) to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Regulatory Accounting. Our principal business is the distribution of electricity and natural gas by the retail distribution companies: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC, FG&E is regulated by the MDPU and UES is regulated by the NHPUC. Accordingly, we use the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). In accordance with SFAS No. 71, we have recorded Regulatory Assets and Regulatory Liabilities which will be recovered or refunded in future electric and gas retail rates.

SFAS No. 71 specifies the economic effects that result from the cause and effect relationship of costs and revenues in the rate-regulated environment and how these effects are to be accounted for by a regulated enterprise. Revenues intended to cover some costs may be recorded either before or after the costs are incurred. If regulation provides assurance that incurred costs will be recovered in the future, these costs would be recorded as deferred charges or “regulatory assets” under SFAS No. 71. If revenues are recorded for costs that are expected to be incurred in the future, these revenues would be recorded as deferred credits or “regulatory liabilities” under SFAS No. 71.

If we, or a portion of our assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, we would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises – Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In our opinion, our regulated operations will be subject to SFAS No. 71 for the foreseeable future.

Utility Revenue Recognition. Regulated utility revenues are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. However, the determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

Allowance for Doubtful Accounts. We recognize a provision for doubtful accounts each month. The amount of the monthly Provision is based upon our experience in collecting electric and gas utility service accounts receivable in prior years. Account write-offs, net of recoveries, are processed monthly. At the end

 

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of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. We are authorized by regulators to recover the supply-related portion of our written-off accounts from customers through periodically reconciling rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis. Also, we have experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, we adjust the provision for doubtful accounts to maintain an adequate Allowance for Doubtful Accounts balance.

Retirement Benefit Obligations. We sponsor the following retirement benefit plans to provide certain pension and postretirement benefits for our retirees and current employees: the Pension Plan, a defined benefit pension plan covering substantially all of our employees; the PBOP Plan, which provides health care and life insurance benefits to retirees; and the SERP, an unfunded retirement plan, with participation limited to executives selected by the Board of Directors.

We account for our pension and postretirement benefits in accordance with SFAS No. 158, SFAS No. 87, “Employers’ Accounting for Pensions” and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions.” In applying these accounting policies, we have made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit cost is based on these significant assumptions. SFAS No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their RBO based on the projected benefit obligation. We have recognized corresponding Regulatory Assets, to recognize the future collection of these obligations in electric and gas retail rates. See Notes 1 and 8 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Our reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on our consolidated financial statements. See Note 8 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Income Taxes. Provisions for income taxes are calculated in each of the jurisdictions in which we operate for each period for which a statement of income is presented. This process involves estimating our current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in our consolidated balance sheets. We account for income tax assets, liabilities and expenses in accordance with SFAS No. 109 and FIN 48, an interpretation of FAS 109.

Depreciation. Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. We conduct independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and consider the results presented in these studies in determining the useful lives of our fixed assets. A change in the estimated useful lives of these assets could have a material impact on our consolidated financial statements.

 

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Commitments and Contingencies. Our accounting policy is to record and/or disclose commitments and contingencies in accordance with SFAS No. 5. SFAS No. 5 applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of December 31, 2007, we are not aware of any material commitments or contingencies other than those disclosed in the Significant Contractual Obligations table in the Contractual Obligations section above and the Commitments and Contingencies footnote to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Refer to “Recently Issued Accounting Pronouncements” in Note 1 to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

For further information regarding these types of activities, see Notes 1 (Summary of Significant Accounting Policies), 4 (Energy Supply), 5 (Commitment and Contingencies), 7 (Income Taxes) and 8 (Benefit Plans) to our consolidated financial statements contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, which is incorporated herein by reference.

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk. As discussed above, we meet our external financing needs by issuing short-term and long-term debt. The majority of debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, we periodically repay our short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new issuances of long-term debt securities. In addition, short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease interest expense in future periods. For example, if we had an average amount of short-term debt outstanding of $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000. The average interest rate on short-term borrowings was 5.6%, 5.5% and 3.8% during 2007, 2006 and 2005, respectively.

Market Risk. Although our utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, we have divested our commodity-related contracts and therefore, further reduced our exposure to commodity risk.

Please also see the section entitled Risk Factors.

 

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OUR COMPANY

We are a public utility holding company headquartered in Hampton, New Hampshire. We are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005. We incorporated under the laws of the State of New Hampshire in 1984. We are the parent of the Unitil companies described on the following page.

Our principal business is the retail distribution of electricity in southeastern seacoast and capital city areas of New Hampshire, and the retail distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts. We have two distribution utility subsidiaries, UES, which operates in New Hampshire, and FG&E, which operates in Massachusetts. UES, through its predecessors Concord Electric Company and Exeter & Hampton Electric Company, was incorporated in 1901. FG&E was incorporated in 1852. UES and FG&E are collectively referred to as our “retail distribution utilities.”

Our retail distribution utilities serve approximately 100,000 electric customers and 15,100 natural gas customers in their service territories. Our retail distribution utilities are local “pipes and wires” utility distribution companies with a combined investment in Net Utility Plant of $249.4 million at March 31, 2008. We do not own or operate electric generating facilities or major transmission facilities and substantially all of our utility assets are dedicated to the local delivery of electricity and natural gas to our customers. Our total revenue was $262.9 million in 2007, which includes revenue to recover the cost of purchased electricity and natural gas in rates on a fully reconciling basis. As a result of this reconciling rate structure, our earnings are not affected by changes in purchased electricity and natural gas costs. Earnings applicable to holders of our common stock for 2007 were $8.6 million. Substantially all of our earnings are derived from the return on investment in our local distribution utility operations.

Unitil Power formerly functioned as the full requirements wholesale power supply provider for UES. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of UES on May 1, 2003 and divested substantially all of its long-term power supply contracts through the sale of the entitlements to the electricity associated with those contracts.

We have three additional wholly owned subsidiaries: Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and Unitil Resources, Inc. (Unitil Resources). Unitil Realty owns and manages our corporate office building and property located in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and management services to its affiliated Unitil companies. Unitil Resources is our wholly owned non-utility subsidiary that provides energy brokering, consulting and management related services. The Usource entities are wholly owned subsidiaries of Unitil Resources. Usource provides energy brokering services, as well as various energy consulting services, to large commercial and industrial customers in the northeastern United States.

Our business strategy is to be a leader in the reliable and cost effective management of a growing level of local electric and natural gas distribution assets. Our growth initiatives include evaluation of organic growth opportunities as well as strategic acquisitions. As part of our growth strategy, we have agreed to purchase (i) all of the outstanding capital stock of Northern Utilities, a local natural gas distribution utility serving customers in Maine and New Hampshire, from Bay State and (ii) all of the outstanding capital stock of Granite State, an interstate gas pipeline company primarily serving the needs of Northern Utilities, from NiSource pursuant to, and subject to satisfaction of the terms and conditions of, the Stock Purchase Agreement dated as of February 15, 2008 by and among NiSource, Bay State and us. Bay State is a wholly owned subsidiary of NiSource.

 

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We are the parent of the following wholly owned significant subsidiaries:

We will be the direct parent of Northern Utilities and Granite State following the Proposed Acquisitions.

 

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Our Operations

Our Electric Utility Operations

Our electric utility operations are conducted through our subsidiaries UES and FG&E. For the year ended December 31, 2007 and the three-month period ended March 31, 2008, the revenues from our electric utility operations were approximately $225.0 million and $56.6 million, respectively. Earnings from electric utility operations were $7.3 million for the year ended December 31, 2007, and $0.5 million for the three-month period ended March 31, 2008.

The primary business of our electric utility operations is the local distribution of electricity to customers in our service territories. As a result of the implementation of retail choice in New Hampshire and Massachusetts, our customers are free to contract for their supply of electricity with third-party suppliers. Both UES and FG&E supply electricity to those customers who do not obtain their supply from third-party suppliers, with the costs associated with those company-provided supplies being recovered on a pass-through basis from customers under periodically adjusted rates.

UES is engaged principally in the retail distribution of electricity to approximately 72,200 customers in New Hampshire in the capital city of Concord as well as 12 surrounding towns and all or part of 16 towns in the southeastern and seacoast regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson, and Plaistow. UES’s service territories consist of approximately 408 square miles in the Merrimack River Valley of south central New Hampshire and in southeastern New Hampshire.

The state capital of New Hampshire is located within UES’s service territories, and includes the executive, legislative and judicial branches and offices and facilities for all major state government services as well as several federal government facilities. In addition, UES’s service territories are retail trading and recreation centers for the central and southeastern parts of the state. These areas serve diversified commercial and industrial businesses, including manufacturing firms engaged in the production of electronic components, wires, and plastics. Our service territories include popular resort areas and beaches along the Atlantic Ocean, including the Hampton Beach recreational area. UES’s 2007 retail electric operating revenue was $157.8 million, of which approximately 51% was derived from residential sales and 49% from commercial / industrial sales.

FG&E is engaged principally in the retail distribution of both electricity and natural gas in the city of Fitchburg and several surrounding communities. FG&E’s service territory encompasses approximately 170 square miles. Electricity is supplied and distributed by FG&E to approximately 27,800 customers in the communities of Fitchburg, Ashby, Townsend and Lunenburg. FG&E’s industrial customers include paper manufacturing and paper products companies, rubber and plastics manufacturers, chemical products companies and printing, publishing and associated industries. FG&E’s 2007 retail electric operating revenue was $67.2 million, of which approximately 52% was derived from residential sales and 48% from commercial / industrial sales.

Our Gas Utility Operations

FG&E supplies and distributes natural gas to approximately 15,100 retail customers in the communities of Fitchburg, Lunenburg, Townsend, Ashby, Gardner and Westminster, all located in Massachusetts.

As a result of the introduction of retail choice for all natural gas customers in Massachusetts, our customers are free to contract for their supply of natural gas with third-party suppliers. FG&E continues to provide natural gas supply services to those customers who do not obtain their supply from third-party suppliers. The costs associated with natural gas supplied by FG&E are recovered on a pass-through basis under periodically adjusted rates.

 

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FG&E’s 2007 gas operating revenue was $34.2 million, of which approximately 55% was derived from residential firm sales and 45% from commercial / industrial firm sales. FG&E’s gas operating revenue was $14.3 million for the three months ended March 31, 2008. Earnings from FG&E’s gas utility operations were $1.0 million for the year ended December 31, 2007, and $2.8 million for the three-month period ended March 31, 2008.

Seasonality and Customer Dependence

Natural gas sales in New England are seasonal, and our results of operations reflect this seasonal nature. Accordingly, results of operations are typically positively impacted by gas operations during the five heating season months from November through March of the following year. Electric sales in New England are far less seasonal than natural gas sales; however, the highest usage typically occurs in both the summer months due to air conditioning demand and the winter months due to heating-related requirements and shorter daylight hours. We are not dependent on a single customer or a few customers for our electric and natural gas sales.

Our Non-Regulated and Other Non-Utility Operations

Our non-regulated operations are conducted through Unitil Resources and Usource. Unitil Resources provides energy brokering services, through Usource, as well as various energy consulting services to large commercial and industrial customers in the northeastern United States. For the year ended December 31, 2007 and the three-month period ended March 31, 2008, the revenues from our non-regulated operations were $3.7 million and $1.0 million, respectively. Earnings from Unitil’s non-regulated operations were $0.3 million for the year ended December 31, 2007, and $0.1 million for the three-month period ended March 31, 2008.

Our other non-utility subsidiaries, Unitil Service and Unitil Realty, provide centralized facilities, management and administrative services to our affiliated companies. Unitil Service’s and Unitil Realty’s earnings are principally derived from income earned on short-term investments and real property owned for our and our subsidiaries’ use.

Regulation and Restructuring

We are subject to regulation as a holding company system by the FERC under the Energy Policy Act of 2005 in regards to certain bookkeeping, accounting and reporting requirements. Certain aspects of our electric operations as they relate to wholesale and interstate business activities are also regulated by the FERC. Our retail distribution utilities, UES and FG&E, are subject to regulation by the NHPUC and the MDPU, respectively, in regards to their rates, issuance of securities and other accounting and operational matters. Because our primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect our operations and financial position.

We have the franchise to deliver electricity and/or natural gas to all customers in our franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets. As a result of a restructuring of the utility industry in Massachusetts and New Hampshire, our customers have the opportunity to purchase their electric or natural gas supplies from third party vendors. Most customers, however, continue to purchase such supplies through UES and FG&E as the provider of last resort. UES and FG&E purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

 

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In connection with the implementation of retail choice, we divested substantially all of the long-term power supply contracts and interests in generation assets of Unitil Power and FG&E through the sale of the interest in those assets or the sale of the entitlements to the electricity provided by those generation assets and long-term power supply contracts. UES and FG&E recover in their rates all the costs associated with the divestiture of their power supply portfolios and have secured regulatory approval from the NHPUC and MDPU, respectively, for the recovery of power supply-related stranded costs and other restructuring-related regulatory assets. The remaining balance of these assets, to be recovered principally over the next three to five years, was $104.8 million as of December 31, 2007. UES and FG&E have a continuing obligation to submit filings in both states that demonstrate their compliance with regulatory mandates and provide for timely recovery of costs in accordance with their approved restructuring plans.

Our Strengths

We believe our strengths have enabled us to grow our business profitably and create shareholder value. These strengths include:

Growing Service Territory. Our operations are located in the southeastern seacoast and state capital regions of New Hampshire, as well as in the greater Fitchburg area of north central Massachusetts. Together, these three service territories provide a diverse and growing customer base.

The Proposed Acquisitions provide an attractive opportunity for us to grow our operations within coastal northern New England. Northern Utilities will bring approximately 52,000 additional natural gas retail distribution customers, which will increase our domestic retail customer base to approximately 167,000 customers in the coastal New England region. Given the lower penetration of gas distribution customers among the population in Northern Utilities’ service territory, we believes there are significant opportunities for us to expand Northern Utilities’ operations, particularly in light of our customer driven expertise in serving rural and small metropolitan areas such as Northern Utilities’ service territory.

Regulated Asset Base. Our core assets consist of local distribution facilities (pipes and wires) necessary for the delivery of our customers’ electric and natural gas supply needs within our service territories and regulatory assets related to our regulated utility operations. Our electric and natural gas distribution assets and regulatory assets, from which we derive substantially all of our operating income, provide stable earnings and cash flow. Over the past five years, we have invested $104.7 million and $26.4 million in capital additions and improvements in our electric and natural gas distribution businesses, respectively, and increased our Net Utility Plant by 5.6% on average per year. As a result of the restructuring of our utility operations, we have divested all of our generation assets and our portfolio of long-term power purchase agreements, and we have secured regulatory approval to recover any “stranded costs” related to this divestiture over future periods. We expect the Proposed Acquisitions to increase our asset base by approximately 51% contributing to significant growth of our local gas distribution facilities.

Diversified Customer Base. Our customers are a diversified mix of residential, commercial and industrial customers, with no single customer representing more than 5% of our total revenues. Our sales to large commercial and industrial customers are not concentrated in one industry segment, but vary from government facilities to large retail outlets, colleges, hospitals and a broad range of industrial companies that reflect the diverse nature of the communities that we serve. The Proposed Acquisitions will increase our customer base by approximately 52,000 retail natural gas customers and will provide further diversification to our operations with respect to geography (into Maine) and utility business mix (between our gas and electric divisions).

 

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Efficient and Flexible Operating Structure. We believe that due in part to our size and the local proximity of our utility operations, we are able to expeditiously and effectively respond to changing regulatory and public policy initiatives, to leverage new technology solutions that significantly improve productivity and customer service, and to implement organizational changes that improve our performance. We have a proven track record of successfully transitioning our company to meet the business and operational challenges affecting our industry. The Proposed Acquisitions will bring together similarly sized local utilities that will continue to provide a high level of service to their local communities.

Historic Dividend Stability. Since our incorporation in 1984, we have continuously paid quarterly dividends and we have never reduced our dividend rate, while still increasing our investment in our utility distribution facilities. Upon the completion of the Proposed Acquisitions, we expect to maintain our current dividend policy while providing for future growth of earnings available to shareholders.

Experienced Management Team. Our senior management team is highly experienced in the utility industry. Our Chairman and CEO, Robert Schoenberger, has 30 years of industry experience. Our senior management team as a whole averages approximately 24 years experience in the industry and 16 years experience with us. The current management in place is well equipped and prepared to lead a successful integration of Northern Utilities and Granite State.

Our Properties

As of December 31, 2007, we owned, through our retail distribution utilities, two operation centers, approximately 2,160 pole miles of local transmission and distribution overhead electric lines and 584 conduit bank miles of underground electric distribution lines, along with 49 electric substations, including three mobile electric substations. Our natural gas operations property includes a liquid propane gas plant, a liquid natural gas plant and 264 miles of underground gas mains. In addition, our real estate subsidiary, Unitil Realty, owns our corporate headquarters building and the 12 acres of land on which it is located.

UES owns and maintains distribution operations centers in Concord, New Hampshire and Kensington, New Hampshire. These properties are owned by UES. UES’s 30 electric distribution substations, including a 5,000 kilovolt ampere (kVA) mobile substation, constitute 214,037 kVA of capacity, which excludes capacity of spare transformers, for the transformation of electric energy from the 34.5 kV subtransmission voltage to other primary distribution voltage levels. The electric substations are located on land owned by UES or land occupied by UES pursuant to perpetual easement.

UES has a total of approximately 1,601 pole miles of local transmission and distribution overhead electric lines and a total of 406 conduit bank miles of underground electric distribution lines. The electric distribution lines are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by UES without objection by the owners. In the case of certain distribution lines, UES owns only a part interest in the poles upon which its wires are installed, the remaining interest being owned by telephone companies.

The physical utility properties of UES, with certain exceptions, and its franchises are subject under its indenture of mortgage and deed of trust under which the respective series of first mortgage bonds of UES are outstanding.

FG&E’s electric properties consisted principally of 559 pole miles of local transmission and distribution overhead electric lines, 178 conduit bank miles of underground electric distribution lines and 19 transmission and distribution stations (including two mobile electric substations). The capacity of these substations totals 443,150 kVA, which excludes capacity of spare transformers.

 

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FG&E owns a liquid propane gas plant and a liquid natural gas plant, both of which are located on land owned by FG&E. FG&E also has 264 miles of underground steel, cast iron and plastic gas mains.

FG&E’s electric substations, with minor exceptions, are located on land owned by FG&E or occupied by FG&E pursuant to perpetual easements. FG&E’s electric distribution lines and gas mains are located in, on or under public highways or private lands pursuant to lease, easement, permit, municipal consent, tariff conditions, agreement or license, expressed or implied through use by FG&E without objection by the owners. FG&E leases its distribution operations center located in Fitchburg, Massachusetts.

We believe that our facilities are currently adequate for their intended uses.

Our Employees

As of July 31, 2008, we had 299 full-time and part-time employees. We consider our relationship with our employees to be good and we have not experienced any major labor disruptions since the early 1960s. As of July 31, 2008, we have 81 employees represented by labor unions. These employees are covered by collective bargaining agreements, which expire May 31, 2010. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages. We expect to successfully negotiate new agreements prior to their expiration dates.

Legal Proceedings

We are involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. In the opinion of our management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on our financial position.

 

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PROPOSED ACQUISITIONS

The following is a summary of the material terms of, and other information relating to, the Proposed Acquisitions. This summary is not complete, may not contain all of the information that is important to you, and is qualified in its entirety by reference to additional information in this prospectus and to the complete text of the Stock Purchase Agreement dated February 15, 2008 by and among NiSource, Bay State and us. A copy of the Stock Purchase Agreement was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on February 20, 2008 and is incorporated herein by reference.

Description of the Proposed Acquisitions

On February 15, 2008, we entered into the Stock Purchase Agreement with NiSource and Bay State pursuant to which we agreed to acquire (i) all of the outstanding shares of capital stock of Northern Utilities from Bay State and (ii) all of the outstanding shares of capital stock of Granite State from NiSource. In consideration for the Proposed Acquisitions, we will pay NiSource and Bay State an aggregate of $160 million in cash, subject to a working capital adjustment.

We expect to finance the Proposed Acquisitions and the related costs and expenses with (i) the net proceeds from this offering, (ii) the sale and issuance of up to $90 million of debt at the subsidiary level and (iii) short-term lines of credit. The sale and issuance of long-term indebtedness will not be, and has not been, registered under the Securities Act and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. If the sale and issuance of long-term indebtedness is delayed or is not completed in whole or in part for any reason, then we will use a bridge credit facility or other interim debt financing to finance the Proposed Acquisitions. We have a commitment for a bridge credit facility that provides for a loan of up to eleven months during which period we would need to arrange alternative financing. We expect to commence the offering of our common stock, as described in this prospectus, as soon as practicable after (i) we obtain certain regulatory approvals relating to the Proposed Acquisitions and (ii) the satisfaction of certain other closing conditions relating to the Proposed Acquisitions. The sale and issuance of long-term indebtedness is subject to certain regulatory requirements and approvals and will be subject to certain closing conditions.

At present, our authorized shares of common stock available for issuance are insufficient for this offering. Therefore, we have requested that our shareholders approve and adopt an amendment to our Articles of Incorporation at a special meeting scheduled for September 10, 2008, to increase the authorized number of shares of common stock from 8,000,000 shares to 16,000,000 shares in the aggregate.

We are contractually obligated to complete the Proposed Acquisitions, subject to the receipt of certain regulatory approvals and other closing conditions, regardless of whether we are able to obtain adequate financing. This offering is not conditioned on the closing of the Proposed Acquisitions.

We expect the Proposed Acquisitions to close during the fourth quarter of 2008; however, there is no assurance that the Proposed Acquisitions will close at that time.

The Proposed Acquisitions are subject to certain regulatory requirements and approvals and customary closing conditions. The regulatory requirements and approvals include:

 

(i)

approval by the MPUC;

 

(ii)

approval by the NHPUC;

 

(iii)

compliance with the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, with respect to which early termination of the waiting period was granted effective May 19, 2008;

 

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(iv)

compliance with the Securities Exchange Act of 1934, as amended; and

 

(v)

review by certain federal, state or local regulatory bodies, including the Federal Communications Commission.

The respective obligation of each of NiSource, Bay State, and us to consummate the Proposed Acquisitions is subject to the satisfaction or waiver of certain closing conditions, including:

 

(i)

regulatory requirements and approvals;

 

(ii)

obtaining certain third-party consents;

 

(iii)

our entering into a transition services agreement with NiSource and Bay State; and

 

(iv)

no court or governmental entity having enacted, issued, promulgated, enforced or entered any statute, law, ordinance, rule, regulation, judgment, decree, injunction or other order restraining, enjoining, or otherwise prohibiting consummation of the Proposed Acquisitions.

In addition, our obligation to consummate the Proposed Acquisitions is subject to the satisfaction or waiver of certain closing conditions, including:

 

(i)

the representations and warranties of NiSource and Bay State being true and correct except as would not have, individually or in the aggregate, a material adverse effect on Northern Utilities and Granite State or on the ability to consummate the Proposed Acquisitions (subject to certain exceptions);

 

(ii)

NiSource and Bay State performing, in all material respects, all the covenants and agreements required to be performed by them under the Stock Purchase Agreement; and

 

(iii)

NiSource, Bay State, Northern Utilities, or Granite State delivering certain closing documents to us.

Additionally, the obligation of NiSource and Bay State to consummate the Proposed Acquisitions is subject to the satisfaction or waiver of certain closing conditions, including:

 

(i)

our representations and warranties being true and correct except as would not have, individually or in the aggregate, a material adverse effect on our ability to consummate the Proposed Acquisitions;

 

(ii)

performing in all material respects all the covenants and agreements required to be performed by us under the Stock Purchase Agreement; and

 

(iii)

our delivering certain closing documents to NiSource and Bay State.

The Stock Purchase Agreement provides that NiSource and Bay State will indemnify us for certain losses as described therein. The indemnification provided by NiSource and Bay State is subject to (i) a per claim minimum indemnification limit of $100,000, (ii) an aggregate claims minimum indemnification limit of 1% of the purchase price, and (iii) an aggregate claims maximum indemnification limit of 10% of the purchase price (other than the tax indemnification provided by NiSource and Bay State, which is not subject to any dollar limit). For detailed information regarding indemnification obligations, please see the Stock Purchase Agreement, a copy of which was filed as Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on February 20, 2008 and is incorporated herein by reference.

 

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Reasons for Engaging in, and Estimated Potential Synergies Attributable to,

the Proposed Acquisitions

Our Board of Directors believes that the Proposed Acquisitions and related transactions will result in the following significant benefits to us:

Attractive Local Growth Opportunity Consistent with our Strategy. Northern Utilities and Granite State provide us with an attractive opportunity to grow our operations within coastal northern New England. Northern Utilities will bring approximately 52,000 additional natural gas retail distribution customers, which will increase our domestic retail customer base to approximately 167,000 customers in the coastal New England region. Given the lower penetration of gas distribution customers among the population in Northern Utilities’ service territory, we believe that there are significant opportunities for Northern Utilities to expand its operations, particularly in light of our customer-driven expertise in serving rural and small metropolitan areas such as Northern Utilities’ service territory. Additionally, Northern Utilities will provide further diversification to our operations with respect to geography (into Maine) and utility business mix (between our gas and electric divisions).

Reduced Operating Expenses and Cash Flow Savings. We project that the Proposed Acquisitions will produce annual system-wide synergy savings of approximately $5.6 million, of which approximately $2.3 million will be directly realized by Northern Utilities and Granite State. We expect to begin realizing these synergies within the first full year after integration. These projected savings are primarily due to operating efficiencies obtained from economies of scale, efficient use of our personnel, infrastructure and information systems, achievement of efficiencies associated with the provision of shared utility services and adoption of best practices associated with these shared utility services. Our expected achievement of these system-wide synergies should allow Northern Utilities and our other retail distribution utilities to improve their respective earnings and to stabilize the rates charged to their respective customers.

Opportunity for Improved Regulated Utility Operating Earnings through the Execution of Our Regulatory Plan. We believe there is an opportunity to stabilize and improve the operating earnings of Northern Utilities and Granite State by executing a consistent and well-structured regulatory plan that provides Northern Utilities and Granite State with an opportunity to earn a reasonable rate of return. Northern Utilities has not sought base rate relief since 1983 in Maine or since 2002 in New Hampshire. Our regulatory plan will seek to maximize the benefits of the expected synergies discussed above for Northern Utilities and Granite State and provide Northern Utilities and Granite State with an opportunity to earn a reasonable rate of return on their utility rate base.

Increased Market Capitalization and Liquidity. We expect that the Proposed Acquisitions and this offering will increase our market capitalization by approximately 50% and increase our shareholders’ liquidity. As a result, we and our shareholders should benefit from the long-term financial stability of a larger, more liquid company.

Our Board of Directors also believes that the Proposed Acquisitions and related transactions will result in the following significant benefits to our other stakeholders:

Increased Commitment to Local Communities. We expect the Proposed Acquisitions to demonstrate our increased commitment to local communities in New Hampshire and Maine through the creation of employment opportunities and the expansion of our local presence. We anticipate retaining all of Northern Utilities’ 78 current employees and estimate that we will add approximately 50 new positions, while still achieving the expected synergies discussed above, following the Proposed Acquisitions. The new positions will be primarily in the areas of gas operations and customer service, which are necessary to provide shared utility services previously provided by NiSource and included in the Northern Utilities and Granite State operating expenses.

 

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Improved Customer Convenience and Service. We anticipate that the overlap between portions of our electric service territory in southeastern New Hampshire and portions of Northern Utilities’ natural gas service territory will increase the convenience for many of Northern Utilities’ customers who will be doing business with a single gas and electric distribution utility following the Proposed Acquisitions. Additionally, we estimate that we will add several new positions to our local customer service department following the Proposed Acquisitions.

Accounting Treatment of the Proposed Acquisitions

We intend to account for the Proposed Acquisitions under the purchase method of accounting for business combinations, in accordance with FASB Statement No. 141, “Business Combinations” (SFAS No. 141). In that process, we will recognize and measure the identifiable assets acquired and the liabilities assumed at fair value. Also, we will measure and recognize any acquisition adjustment related to a purchase premium or bargain relative to the fair values acquired against the purchase price.

Pursuant to SFAS No. 141, an acquiring entity shall allocate the cost of an acquired entity to the assets acquired and liabilities assumed based on their fair values as of the acquisition date. Accordingly, any difference between the fair value of acquired assets and liabilities (including identifiable intangible assets) and book value represents a purchase premium or bargain.

If the Proposed Acquisitions are completed subsequent to December 31, 2008, we will account for the Proposed Acquisitions in accordance with FASB Statement No. 141(R), “Business Combinations (Revised)” (SFAS No. 141(R)).

 

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NORTHERN UTILITIES’ FINANCIAL AND OTHER INFORMATION

Description of Business

Northern Utilities is a local natural gas distribution utility serving customers in Maine and New Hampshire. Northern Utilities provides natural gas distribution services to approximately 52,000 customers in 44 New Hampshire and southern Maine communities, stretching from Plaistow, New Hampshire, in the south to Lewiston-Auburn, Maine, in the north.

Northern Utilities was incorporated under the laws of New Hampshire in 1979. Its roots extend back to Portland Gas Light Company in 1849, making it one of the oldest natural gas utilities in New England. It is a wholly owned subsidiary of Bay State, which in turn is a wholly owned subsidiary of NiSource. It has 78 full-time employees and its customers include residences, businesses and organizations.

Northern Utilities had an investment in Net Utility Plant of $163.5 million at December 31, 2007, and net revenues of $44.2 million for 2007. Northern Utilities derives its revenues and earnings from its regulated utility operations. Northern Utilities recovers the cost of natural gas in rates on a fully reconciling basis and, therefore, Northern Utilities’ earnings are not affected by changes in purchased gas costs. Northern Utilities receives centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $8.6 million in 2007.

Selected Financial Data

The following table shows selected historical financial and operating data of Northern Utilities for the periods and as of the dates indicated. The selected historical financial data of Northern Utilities as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 are derived from the historical audited financial statements of Northern Utilities appearing elsewhere in this prospectus. The selected historical financial data of Northern Utilities as of March 31, 2008 and 2007 and for the three months ended March 31, 2008 and 2007 are derived from the historical unaudited financial statements of Northern Utilities appearing elsewhere in this prospectus. The selected historical financial data of Northern Utilities as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 are derived from unaudited financial statements not included herein. The table should also be read together with the section entitled Northern Utilities’ Financial and Other Information — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

		For the Three Months Ended March 31,						For the Year Ended December 31,
(millions)		2008			2007			2007			2006			2005			2004			2003
		(unaudited)
Statements of Earnings:
Net Revenues		$	17.2		$	17.3		$	44.2		$	38.4		$	40.2		$	41.1		$	40.8
Operating Income		$	7.4		$	7.1		$	6.7		$	4.7		$	7.6		$	10.9		$	13.8
Interest Expense, net			0.8			0.7			2.8			2.6			2.4			2.8			3.5
Income Taxes and Other			2.7			2.6			1.7			0.8			2.2			4.2			4.3
Net Income		$	3.9		$	3.8		$	2.2		$	1.3		$	3.0		$	3.9		$	6.0

 

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		As of March 31,						As of December 31,
(millions)		2008			2007			2007			2006			2005			2004			2003
		(unaudited)
Balance Sheet Data:
Utility Plant (Original Cost)		$	222.0		$	209.1		$	219.5		$	205.7		$	193.1		$	184.6		$	176.9
Total Assets		$	311.0		$	318.5		$	314.9		$	327.7		$	313.2		$	278.9		$	280.0
Capitalization:
Common Stock Equity		$	125.5		$	123.2		$	121.6		$	119.6		$	116.9		$	117.9		$	114.9
Long-Term Debt, less current portion			61.7			62.5			61.7			62.5			63.3			64.2			65.0
Total Capitalization		$	187.2		$	185.7		$	183.3		$	182.1		$	180.2		$	182.1		$	179.9
Current Portion of Long-Term Debt		$	0.8		$	0.8		$	0.8		$	0.8		$	0.8		$	0.8		$	0.8
Short-Term Debt		$	7.0		$	26.8		$	31.1		$	39.5		$	30.1		$	14.3		$	16.4

Sales of natural gas and the related results of operations can be significantly affected by seasonal weather conditions. Annual revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, operating results historically are most favorable in the first and fourth calendar quarters. Therefore, fluctuations in seasonal weather conditions between years may have a significant effect on results of operations and cash flows.

Financial Statements

Northern Utilities’ unaudited condensed financial statements as of March 31, 2008 and 2007 and for the three months ended March 31, 2008 and 2007 are set forth beginning on page F-15 of this prospectus.

Northern Utilities’ financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005, together with the independent registered public accounting firm’s report, are set forth beginning on page F-28 of this prospectus.

 

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of financial condition and results of operations should be read in conjunction with Northern Utilities’ historical financial statements and notes included elsewhere in this prospectus.

Three Months Ended March 31, 2008 and 2007

The following table and discussion is a summary of Northern Utilities’ results of operations for the three months ended March 31, 2008 and 2007.

 

		For the Three Months Ended March 31,
(millions)		2008				2007
Net Revenues
Gas Distribution Revenues		$	53.5			$	60.3
Cost of Sales (Excludes Depreciation and Amortization)			36.3				43.0
Total Net Revenues			17.2				17.3
Operating Expenses
Operation and Maintenance			6.3				7.1
Depreciation and Amortization			2.8				2.5
Other Taxes			0.7				0.6
Total Operating Expenses			9.8				10.2
Operating Income			7.4				7.1
Other Income (Deductions)
Interest Expense, Net			(0.8	)			(0.7	)
Total Other Income (Deductions)			(0.8	)			(0.7	)
Income Before Income Taxes			6.6				6.4
Income Taxes			2.7				2.6
Net Income		$	3.9			$	3.8

Three Months Ended March 31, 2008 Compared to the Three Months Ended March 31, 2007

Net Revenues. Net revenues were $17.2 million in the first quarter of 2008 and were consistent with net revenues of $17.3 million in same period of 2007. Decreases in both gross revenues and cost of sales were attributable to lower gas prices in the 2008 period compared to the 2007 period.

Operating Expenses. Operating expenses decreased $0.4 million, or 3.9%, for the quarter ended March 31, 2008 compared to the same period of 2007. This decrease was primarily due to penalties from non-compliance with state regulatory matters incurred in the comparable 2007 period offset by increased depreciation expense in 2008 related to capital investments.

Other Income (Deductions). Interest expense reduced income in the first quarter of 2008 by $0.8 million and was relatively flat compared to the same period in 2007. Northern Utilities incurs interest expense primarily due to short and long-term affiliated borrowings, as well as for customer deposits, deferred gas cost and inventory.

 

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Income Tax Expense. Income tax expense of $2.7 million in the first quarter of 2008 increased $0.1 million over the comparable period in 2007 due to higher pretax income.

Regulatory Matters

Maine Public Utilities Commission Docket Nos. 2007-362, 363 and 364 and Docket Nos. 2008-095, 096, 097, 098, 118 and 122

In October 2007, the MPUC initiated a formal investigation into three Notices of Probable Violation (NOPVs) alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations, as adopted by the MPUC. Specifically, the NOPVs alleged that (1) Northern Utilities had failed to update its Operation and Maintenance Plan (Operation and Maintenance Plan) within the time periods required by the regulations; (2) Northern Utilities had allowed persons to perform certain operation and maintenance tasks without being properly qualified to do so under its Operator Qualification Plan (Operator Qualification Plan); (3) Northern Utilities lacked the necessary documentation concerning the maximum allowable operating pressures of certain distribution piping systems; (4) Northern Utilities had allowed one of its systems to operate above the maximum allowable operating pressure following an upstream regulator failure; and (5) Northern Utilities had failed to properly design one of its regulator stations.

Both Northern Utilities and the MPUC Staff have filed written testimony, and Northern Utilities has responded to extensive discovery requests.

In February and March 2008, the MPUC issued NOPVs with accompanying investigations related to documentation required for Northern Utilities’ triennial inspection (Docket No. 2008-118) and Northern Utilities’ qualification of certain affiliate employees that did work in the past on Northern Utilities’ behalf (Docket No. 2008-122).

In April 2008, the MPUC initiated an investigation into an incident from which an NOPV was issued although the cause was not determined conclusively to be natural gas (Docket No. 2008-95, claiming Northern Utilities failed to complete its investigation of the failure), and into an over pressurization following an upstream regulator failure (Docket No. 2008-96, alleging the same).

In June 2008, the MPUC initiated a formal investigation into two NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations with respect to two separate gas leaks that occurred at two separate residences each in October of 2007.

The formal evidentiary hearings have been postponed, pending settlement discussions with the MPUC’s Prosecutorial Staff (Prosecutorial Staff), which are currently underway. The MPUC’s Prosecutorial Staff has indicated that it believes a fine of approximately $5.9 million, to be advanced at hearing, is appropriate. Northern Utilities vigorously disputes the proposal as flatly inconsistent with reasoned enforcement actions and the criteria governing the discretionary assessment of civil penalties.

As of March 31, 2008, Northern Utilities has recorded an appropriate liability for this matter, and, based upon its analysis of the issues, any penalties imposed in this proceeding should approximate the liability. At this time, however, Northern Utilities cannot predict whether it will be able to reach a settlement with the MPUC’s Prosecutorial Staff, or the amounts of any monetary penalties that may ultimately be imposed.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas

On October 31, 2007, the NHPUC issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that lost

 

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and unaccounted for gas (UAFG) in the 2007-2008 winter cost of gas forecast is approximately one percent of firm sales, compared to a reported 7.59% UAFG for the 12-month period ended March 31, 2007. The NHPUC recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that period, the cause of any misreporting and a solution. The NHPUC ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of Northern Utilities’ internal investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra Energy Corp. (Spectra) at the Maritimes & Northeast (M&NE) / Portland Natural Gas Transmission System’s (PNGTS) Newington Gate Station in Newington, New Hampshire (Newington Gate Station) caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought and obtained from the NHPUC an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct its UAFG levels and associated cost impacts.

On February 15, 2008, Northern Utilities filed its report with the NHPUC. Northern Utilities reported that it is working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005. As a result of these efforts, Northern Utilities received confirmation from Spectra on January 28, 2008, that Granite State was erroneously billed for an additional 758,709 Dth of natural gas between May 2005 and December 2007. As the primary transportation customer of Granite State at the Newington Gate Station, and due to the service arrangements under which Northern Utilities receives service from Granite State, the total amount of the error was passed through to Northern Utilities. Northern Utilities calculates that it was overcharged by approximately $5.7 million for gas purchases directly related to this meter error based on gas prices in effect at the time of the error. This overcharge in turn was passed on to Northern Utilities’ customers through the normal operation of the gas cost recovery mechanism.

Although Northern Utilities anticipates it will have a refund liability for the overcharges, the timing and extent is not clear. The Commission has not yet suggested that Northern Utilities would be liable for refunds in the absence of its receipt of a recovery from a third party. Under the traditional application of the gas cost recovery rules, Northern Utilities would flow through any refund received from a third party. As of June 2008, Northern Utilities has recorded approximately $10.3 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable by Granite State.

Northern Utilities has been informed by Spectra that resolution of the issue and any cash-out or refund that needs to be made to Granite State and/or Northern Utilities, requires the involvement of PNGTS. Although PNGTS has agreed to repay the lost gas to Granite State over an 18-month period, final documents memorializing the payback have not been completed. Northern Utilities has agreed to inform the NHPUC at 120-day intervals until an acceptable resolution is reached.

Liquidity and Capital Resources

Generally, cash flow from operations and short-term borrowings has provided sufficient liquidity to meet Northern Utilities’ operating requirements. Northern Utilities’ operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from gas sales and transportation services typically exceed cash requirements, while in the summer months short-term financing is used to purchase gas to place in storage for heating season deliveries, perform maintenance and make capital improvements.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Working capital requirements are primarily driven by changes in accounts receivable, exchange gas

 

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payable/receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers.

Cash Flow. Net cash provided by operating activities, net cash used in investing activities and financing activities for the three months ended March 31, 2008 and 2007 were as follows:

 

		For the Three Months Ended March 31,
(millions)		2008				2007
Net Cash Provided by Operating Activities		$	24.8			$	14.9
Net Cash Used in Investing Activities		$	—			$	(1.3	)
Net Cash Used in Financing Activities		$	(24.1	)		$	(12.7	)

Net cash flows provided by operating activities increased by $9.9 million for the first quarter of 2008 compared to the same period in 2007 primarily due to changes in working capital including decreases in exchange gas receivables and under-recovered gas and fuel costs, partially offset by increases in accounts receivable.

The changes in cash used for investing activities are driven by the level of capital expenditures from period to period. Funds for such expenditures are provided from funds available at the beginning of the year, cash generated from operations, and other sources as may be required.

Capital expenditures were $1.7 million and $2.8 million for the three months ended March 31, 2008 and 2007, respectively. Capital expenditures included amounts for improvements of system reliability and provision of additional near term capacity for existing customers.

Cash flow used for financing activities primarily consisted of repayment of borrowings from the NiSource Money Pool. NiSource Finance Corporation, a wholly owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Northern Utilities was a participant in the NiSource Money Pool for all of the periods presented in the financial statements.

NiSource will retain responsibility for satisfying the outstanding balance to the NiSource Money Pool.

Off Balance Sheet Arrangements

Northern Utilities does not have off balance sheet financing arrangements with third parties and maintains no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

As a part of normal business, NiSource has entered into various agreements providing financial or performance assurance to third parties on behalf of Northern Utilities. Such agreements include guarantees and stand-by letters of credit.

Critical Accounting Policies and Estimates

There were no changes to Northern Utilities’ critical accounting policies and estimates since December 31, 2007.

Recently Adopted Accounting Pronouncements

SFAS No. 157 – Fair Value Measurements. In September 2006, the FASB issued FASB Statement No. 157, “Fair Value Measurements” (SFAS No. 157), to define fair value, establish a framework for measuring fair value, and to expand disclosures about fair value measurements. SFAS No. 157 defines fair

 

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value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not change the requirements to apply fair value in existing accounting standards.

Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

To increase consistency and comparability in fair value measurements, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The level in the fair value hierarchy disclosed is based on the lowest level of input that is significant to the fair value measurement. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

 

Ÿ

Level 1 inputs are quoted prices (unadjusted) in active markets for identical asset or liabilities that the company has the ability to access as of the reporting date.

 

Ÿ

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data.

 

Ÿ

Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

SFAS No. 157 became effective for Northern Utilities as of January 1, 2008. The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on the following three items, which are required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption: (i) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under Emerging Issues Task Force (EITF) Issue No. 02-3; (ii) existing hybrid financial instruments measured initially at fair value using the transaction price; and (iii) blockage factor discounts. The adoption of SFAS No. 157 did not have an impact on the January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, which delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of non-financial assets and liabilities until fiscal years beginning after November 15, 2008. Northern Utilities has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities.

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Northern Utilities adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 decreased “Other Current Assets” by $0.1 million, increased “Regulatory Assets” by $8.2 million, and decreased “Other Current Liabilities” by $0.3 million. “Pensions and Postretirement Benefits Other than Pensions” were increased by $8.4 million. With the adoption of SFAS No. 158 Northern Utilities determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Northern Utilities recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

 

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Northern Utilities adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the balance sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $0.8 million, a decrease in “Pensions and Postretirement Benefits Other than Pensions” of $0.4 million, and a decrease to “Retained Earnings” of $0.4 million. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

SFAS No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115. In February 2007, the FASB issued FASB Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159), which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment would be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Northern Utilities has chosen not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

FSP FIN 39-1 – FASB Staff Position Amendment of FASB Interpretation No. 39. In April 2007, the FASB posted FSP FIN 39-1 to amend paragraph 3 of FIN 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as subsequently amended by FASB Statement No. 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of the Effective Date of FASB Statement No. 133 — an amendment of FASB Statement No. 133” (SFAS No. 137); FASB Statement No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities — an amendment of SFAS No. 133” (SFAS No. 138); and FASB Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149) (collectively referred to as SFAS No. 133). This FSP also amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP became effective for Northern Utilities as of January 1, 2008. Northern Utilities has not elected to net fair value amounts for its derivative instruments or the fair value amounts recognized for its right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. This is consistent with Northern Utilities current accounting policy prior to the adoption of this amended standard. Northern Utilities discloses amounts recognized for the right to reclaim cash collateral within “Restricted cash” and amounts recognized for the right to return cash collateral within current liabilities on the balance sheets.

FIN 48 – Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

 

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On January 1, 2007, Northern Utilities adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

Recently Issued Accounting Pronouncements

SFAS No. 141R – Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Northern Utilities is currently reviewing the provisions of SFAS No. 141R to determine the impact on future business combinations.

SFAS No. 161 – Disclosures about Derivative Instruments and Hedging – an amendment of SFAS No. 133. In March 2008, the FASB issued SFAS No. 161 to amend and expand the disclosure requirements of SFAS No. 133 with the intent to provide users of the financial statement with an enhanced understanding of how and why an entity uses derivative instruments, how these derivatives are accounted for and how the respective reporting entity’s financial statements are affected. This Statement is effective for fiscal years and interim periods beginning after November 15, 2008, and earlier application is encouraged. Northern Utilities is currently reviewing the provisions of SFAS No. 161 to determine the impact it may have on its disclosures within the Notes to Condensed Financial Statements.

Fiscal Years Ended December 31, 2007, 2006 and 2005

The following table and discussion is a summary of Northern Utilities’ results of operations for the years ended December 31, 2007, 2006, and 2005.

 

		For the Year Ended December 31,
(millions)		2007				2006				2005
Net Revenues
Gas Distribution Revenues		$	129.9			$	118.6			$	127.7
Cost of Sales (Excludes Depreciation and Amortization)			85.7				80.2				87.5
Total Net Revenues			44.2				38.4				40.2
Operating Expenses
Operation and Maintenance			24.7				21.4				20.2
Depreciation and Amortization			10.2				9.7				9.5
Other Taxes			2.6				2.6				2.9
Total Operating Expenses			37.5				33.7				32.6
Operating Income			6.7				4.7				7.6
Other Income (Deductions)
Interest Expense, Net			(2.8	)			(2.5	)			(2.5	)
Other, Net			—				(0.1	)			0.1
Total Other Income (Deductions)			(2.8	)			(2.6	)			(2.4	)
Income Before Income Taxes			3.9				2.1				5.2
Income Taxes			1.7				0.8				2.2
Net Income		$	2.2			$	1.3			$	3.0

 

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Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Net Revenues. Net revenues increased $5.8 million, or 15.1%, for the year ended December 31, 2007 compared to the same period of 2006. This increase was primarily due to an increase in net revenues of approximately $2.5 million resulting from favorable weather in the 2007 period, increased commercial usage of $1.3 million due primarily to customer conversions to gas resulting from high fuel oil costs, and a $1.1 million increase in regulatory trackers, which are offset in operating expenses.

Operating Expenses. Operating expenses increased $3.8 million, or 11.3%, for the year ended December 31, 2007 compared to the same period of 2006. This increase was primarily due to $1.2 million in penalties for non-compliance with state regulatory matters, a $1.1 million increase in regulatory trackers, which are offset in net revenues, increased outside service expense of $0.7 million primarily for outside contractors reviewing construction records and performing inspections, and increased depreciation expense of $0.5 million related to capital investments. Northern Utilities paid management fees of $8.6 million and $8.1 million in 2007 and 2006, respectively, to NiSource and its affiliates for centralized administrative, management, and support services.

Other Income (Deductions). Interest expense increased $0.3 million, or 12%, for the year due to an increase in interest on deferred gas cost and storage inventory, slightly offset by a decrease on interest on long-term debt. Northern Utilities’ incurs interest expense primarily due to short and long-term affiliated borrowings, as well as for customer deposits, deferred gas cost and inventory.

Income Tax Expense. Income taxes increased $0.9 million in 2007 compared to 2006 primarily due to higher pre-tax income and a higher effective tax rate. The 2007 effective income tax rate of 44% was 6.6% higher than the 2006 effective tax rate primarily due to the tax impact of nondeductible penalties recorded in 2007 versus 2006.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

Net Revenues. Net revenues decreased $1.8 million, or 4.5%, for the year ended December 31, 2006 compared to the same period of 2005. This decrease was primarily due to a decrease in net revenues of approximately $2.5 million resulting from unfavorable weather in the 2006 period, partly offset by a $0.4 million increase in regulatory trackers, which are offset in operating expenses, and an increase in customers that resulted in a $0.2 million increase in revenues.

Operating Expenses. Operating expenses increased $1.1 million in 2006, or 3.4%, from 2005. This increase was primarily due to a $0.4 million increase in regulatory trackers, which are offset in net revenues, and an increase in uncollectible expense of $0.3 million. Northern Utilities paid management fees of $8.1 million and $8.4 million in 2006 and 2005, respectively, to NiSource and its affiliates for centralized administrative, management, and support services.

Other Income (Deductions). Interest expense remained flat for the 2006 and 2005 periods. Northern Utilities incurs interest expense primarily due to short and long-term affiliated borrowings, as well as for customer deposits, deferred gas cost and inventory.

Income Tax Expense. Income taxes decreased $1.4 million in 2006 compared to 2005 primarily due to lower pre-tax income in 2006. The 2006 effective income tax rate of 37.5% was 4.4% lower than the 2005 effective tax rate primarily due to the regulatory flow-through of state income tax benefits of $42,000 in 2006 versus the regulatory flow-through of state income tax expense of $81,000 in 2005.

 

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Regulatory Matters

Maine Public Utilities Commission Docket Nos. 2007-362, 363 and 364 and Docket Nos. 2008-095, 096, 097, 098, 118 and 122

In October 2007, the MPUC initiated a formal investigation into three NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations, as adopted by the MPUC. Specifically, the NOPVs alleged that (1) Northern Utilities had failed to update its Operation and Maintenance Plan within the time periods required by the regulations; (2) Northern Utilities had allowed persons to perform certain operation and maintenance tasks without being properly qualified to do so under its Operator Qualification Plan; (3) Northern Utilities lacked the necessary documentation concerning the maximum allowable operating pressures of certain distribution piping systems; (4) Northern Utilities had allowed one of its systems to operate above the maximum allowable operating pressure following an upstream regulator failure; and (5) Northern Utilities had failed to properly design one of its regulator stations.

Both Northern Utilities and the MPUC Staff have filed written testimony, and Northern Utilities has responded to extensive discovery requests.

In February and March 2008, the MPUC issued NOPVs with accompanying investigations related to documentation required for Northern Utilities’ triennial inspection (Docket No. 2008-118) and Northern Utilities’ qualification of certain affiliate employees that did work in the past on Northern Utilities’ behalf (Docket No. 2008-122).

In April 2008, the MPUC initiated an investigation into an incident from which an NOPV was issued although the cause was not determined conclusively to be natural gas (Docket No. 2008-95, claiming Northern Utilities failed to complete its investigation of the failure), and into an over pressurization following an upstream regulator failure (Docket No. 2008-96, alleging the same).

In June 2008, the MPUC initiated a formal investigation into two NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations with respect to two separate gas leaks that occurred at two separate residences each in October of 2007.

The formal evidentiary hearings have been postponed, pending settlement discussions with the Prosecutorial Staff, which are currently underway. The Prosecutorial Staff has indicated that it believes a fine of approximately $5.9 million, to be advanced at hearing, is appropriate. Northern Utilities vigorously disputes the proposal as flatly inconsistent with reasoned enforcement actions and the criteria governing the discretionary assessment of civil penalties.

As of December 31, 2007, Northern Utilities has recorded an appropriate liability for this matter, and, based upon its analysis of the issues, any penalties imposed in this proceeding should approximate the liability. At this time, however, Northern Utilities cannot predict whether it will be able to reach a settlement with the Prosecutorial Staff, or the amounts of any monetary penalties that may ultimately be imposed.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas

On October 31, 2007, the NHPUC issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that UAFG in the 2007-2008 winter cost of gas forecast is approximately one percent of firm sales, compared to a reported 7.59% UAFG for the 12-month period ended March 31, 2007. The NHPUC recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that

 

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period, the cause of any misreporting and a solution. The NHPUC ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of Northern Utilities’ internal investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra at the M&NE / PNGTS Newington Gate Station caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought and obtained from the NHPUC an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct its UAFG levels and associated cost impacts.

On February 15, 2008, Northern Utilities filed its report with the NHPUC. Northern Utilities reported that it is working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005.

Although Northern Utilities anticipates it will have a refund liability for the overcharges, the timing and extent is not clear. The Commission has not yet suggested that Northern Utilities would be liable for refunds in the absence of its receipt of a recovery from a third party. Under the traditional application of the gas cost recovery rules, Northern Utilities would flow through any refund received from a third party.

Liquidity and Capital Resources

Generally, cash flow from operations and short-term borrowings has provided sufficient liquidity to meet Northern Utilities’ operating requirements. Northern Utilities’ operations are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from November through March, cash receipts from gas sales and transportation services typically exceed cash requirements, while in the summer months short-term financing is used to purchase gas to place in storage for heating season deliveries, perform maintenance and make capital improvements.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Working capital requirements are primarily driven by changes in accounts receivable, exchange gas payable/receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers.

Cash Flow. Net cash provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the years ended December 31, 2007, 2006 and 2005 were as follows:

 

		For the Year Ended December 31,
(millions)		2007				2006				2005
Net Cash Provided by Operating Activities		$	24.6			$	11.0			$	1.3
Net Cash Used in Investing Activities		$	(14.2	)		$	(20.0	)		$	(11.9	)
Net Cash Provided by (Used in) Financing Activities		$	(9.3	)		$	8.6			$	10.9

Net cash flows provided by operating activities increased by $13.6 million for 2007 compared to 2006 primarily due to changes in working capital including decreases in exchange gas receivables and under-recovered gas and fuel costs, partially offset by increases in accounts receivable and higher retiree pension and medical payments during 2007.

Net cash provided by operating activities increased by $9.7 million in 2006 compared to 2005 primarily due to changes in working capital including decreases in accounts receivables and exchange gas receivables, partially offset by payments of accounts payable.

 

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The changes in cash used for investing activities are driven by the level of capital expenditures from period to period. Funds for such expenditures are provided from funds available at the beginning of the year, cash generated from operations, and other sources as may be required.

Capital expenditures were $16.7 million, $15.8 million and $13.0 million for the years ended December 31, 2007, 2006 and 2005, respectively. Capital expenditures increased from 2006 to 2007 due primarily to improvements of system reliability and to provide additional near term capacity for existing customers. Capital expenditures increased from 2005 to 2006 due to the Maine cast iron replacement program, with 2006 being the first full year of expenditures for this program.

Cash flow used for financing activities primarily consisted of changes in borrowings from the NiSource Money Pool. NiSource Finance Corporation, a wholly owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Northern Utilities was a participant in the NiSource Money Pool for all of the periods presented in the financial statements.

NiSource will retain responsibility for satisfying the outstanding balance to the NiSource Money Pool.

Total Contractual Cash Obligations. A summary of Northern Utilities total contractual cash obligations as of December 31, 2007, is as follows:

 

(millions)		Total			2008			2009			2010			2011			2012			After
Long-Term Debt		$	62.5		$	0.8		$	0.8		$	0.9		$	—		$	—		$	60.0
Interest Payments on Long-Term Debt			15.9			3.0			3.0			2.9			2.9			2.9			1.2
Operating Leases			1.4			0.4			0.3			0.3			0.2			0.2			—
Energy Commodity Contracts			9.8			9.8			—			—			—			—			—
Other Long-Term Liabilities			0.4			0.4			—			—			—			—			—
Total Contractual Obligations		$	90.0		$	14.4		$	4.1		$	4.1		$	3.1		$	3.1		$	61.2

Interest payments on long-term debt include medium-term notes and an inter-company note. Interest is calculated based on the applicable rates and payment dates.

Northern Utilities has entered into various energy commodity contracts to purchase physical quantities of natural gas. These amounts represent minimum quantities of these commodities that Northern Utilities is obligated to purchase at both fixed and variable prices.

Other long-term liabilities include employer contributions to pension and other postretirement benefits plans expected to be made in 2008. Plan contributions beyond 2008 are dependent upon a number of factors, including actual returns on plan assets, which cannot be reliably estimated.

Off Balance Sheet Arrangements

Northern Utilities does not have off balance sheet financing arrangements with third parties and maintains no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

As a part of normal business, NiSource has entered into various agreements providing financial or performance assurance to third parties on behalf of Northern Utilities. Such agreements include guarantees and stand-by letters of credit.

NiSource has issued guarantees that support up to approximately $12.5 million of commodity-related payments for energy commodity contracts for Northern Utilities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions involving natural gas.

 

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Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of Northern Utilities’ financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on Northern Utilities’ results of operations, equity or cash flows.

Accounting for Regulation. Northern Utilities follows the accounting and reporting requirements of SFAS No. 71. SFAS No. 71 provides that rate-regulated companies account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

Northern Utilities has designed its rates to recover the costs of providing its regulated service and determined it is probable that such rates can be charged and collected. In the event that regulation significantly changes the opportunity for Northern Utilities to recover its costs in the future, Northern Utilities may no longer meet the criteria for the application of SFAS No. 71. In such event, a write-down of all or a portion of Northern Utilities’ existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of SFAS No. 71, Northern Utilities would be required to apply the provisions of SFAS No. 101, “Regulated Enterprises — Accounting for the Discontinuation of Application of FASB Statement No. 71.” In management’s opinion, Northern Utilities will be subject to SFAS No. 71 for the foreseeable future.

Accounting for Risk Management Activities. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value, unless such contracts are designated by Northern Utilities as normal under the provisions of the standard.

Under SFAS No. 133 the accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. Unrealized and realized gains and losses are recognized each period as components of other comprehensive income, earnings, or regulatory assets and liabilities depending on the nature of such derivatives.

Northern Utilities has a regulatory approved hedging program designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, Northern Utilities purchases New York Mercantile Exchange (NYMEX) futures that correspond to the associated delivery month. Any gains or losses on the fair value of these derivatives are passed through to the ratepayer directly through a regulatory commission approved recovery mechanism. As a result of the ratemaking process, Northern Utilities records gains and losses as regulatory liabilities or assets and recognizes such gains or losses in cost of sales when recovered in revenues.

Intangible Assets. At December 31, 2007, Northern Utilities had $72.4 million of intangible assets consisting of franchise rights that were identified as part of the purchase price allocation associated with the acquisition by NiSource. The intangible asset balance at December 31, 2006 was $74.7 million. The gross intangible asset of $92.7 million is being amortized over a forty-year period commencing February 1999, the date of the acquisition by NiSource. The reserve balance was $20.3 million and $18.0 million at December 31, 2007 and 2006, respectively.

 

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Northern Utilities assesses the carrying amount and potential earnings of this intangible asset whenever events or changes in circumstances indicate that the carrying value could be impaired under SFAS No. 144. When an asset’s carrying value exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered to be impaired to the extent that the asset’s fair value is less than its carrying value.

Pensions and Postretirement Benefits. Northern Utilities has defined benefit plans for both pensions and other postretirement benefits. The plans are accounted for under FASB Statement No. 87, “Employers’ Accounting for Pensions” (SFAS No. 87), FASB Statement No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS No. 88), and FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” (SFAS No. 106), as amended by SFAS No. 158. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition.

Contingencies. A contingent liability is recognized when it is probable that an environmental, tax, legal or other liability has been incurred and the amount of loss can reasonably be estimated. Accounting for contingencies requires significant management judgment regarding the estimated probabilities and ranges of exposure to a potential liability. Estimates of the loss and associated probability are made based on the current facts available, including present laws and regulations. Management’s assessment of the contingent liability could change as a result of future events or as more information becomes available. Actual amounts could differ from estimates and can have a material impact on Northern Utilities’ results of operations and financial position.

Recently Adopted Accounting Pronouncements

FIN 48 – Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FIN 48, to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Northern Utilities adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Northern Utilities adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit

 

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obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 decreased “Other Current Assets” by $0.1 million, increased “Regulatory Assets” by $8.2 million, and decreased “Other Current Liabilities” by $0.3 million. “Pensions and Postretirement Benefits Other than Pensions” were increased by $8.4 million. With the adoption of SFAS No. 158 Northern Utilities determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Northern Utilities recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Northern Utilities adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $0.8 million, a decrease in “Pensions and Postretirement Benefits Other than Pensions” of $0.4 million, and a decrease to “Retained Earnings” of $0.4 million. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

SFAS No. 157 – Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions. Northern Utilities adopted this standard during the first quarter of 2008. There was no material impact to the financial statements.

SFAS No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Northern Utilities chose not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

FSP FIN 39-1 – FASB Staff Position Amendment of FASB Interpretation No. 39. In April 2007, the FASB posted FASB Staff Position FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1) to amend paragraph 3 of FIN 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS No. 133. This FSP also amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Northern Utilities adopted this standard during the first quarter of 2008.

Recently Issued Accounting Pronouncements

SFAS No. 141R – Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Northern Utilities is currently reviewing the provisions of SFAS No. 141R to determine the impact on future business combinations.

 

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SFAS No. 161 – Disclosures about Derivative Instruments and Hedging – an amendment of SFAS No. 133. In March 2008, the FASB issued FASB Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of SFAS No. 133” (SFAS No. 161), to amend and expand the disclosure requirements of SFAS No. 133 with the intent to provide users of the financial statement with an enhanced understanding of how and why an entity uses derivative instruments, how these derivatives are accounted for and how the respective reporting entity’s financial statements are affected. This Statement is effective for fiscal years and interim periods beginning after November 15, 2008, and earlier application is encouraged. Northern Utilities is currently reviewing the provisions of SFAS No. 161 to determine the impact it may have on its disclosures within the Notes to Condensed Financial Statements.

Quantitative and Qualitative Disclosures about Market Risk

Risk is an inherent part of Northern Utilities’ business and the extent to which management properly and effectively identifies, assesses, monitors and manages each of the various types of risk involved in the business can significantly impact profitability. Northern Utilities seeks to identify, assess, monitor and manage, in accordance with defined policies and procedures, commodity price risk, credit risk, and interest rate risk. In addition, Northern Utilities is exposed to market risk associated with the supply of, and demand for, natural gas and the impact of changes in natural gas prices, and can also be negatively affected by sustained downturns or sluggishness in the regional economy.

Northern Utilities is exposed to commodity price risk as a result of its operations involving natural gas. Northern Utilities utilizes a regulatory approved hedging program designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, Northern Utilities purchases NYMEX futures that correspond to the associated delivery month. Any gains or losses on the fair value of these derivatives are passed through to the ratepayer directly through a regulatory commission approved recovery mechanism. As a result of the ratemaking process, Northern Utilities records gains and losses as regulatory liabilities or assets and recognizes such gains or losses in cost of sales when recovered in revenues.

Credit risk represents the loss that Northern Utilities would incur if a counterparty fails to perform under its contractual obligations. Exposure to credit risk is measured by summing a counterparty’s current obligations to Northern Utilities and the marked-to-market value of any forward positions with that entity. Credit exposure is generally mitigated by obtaining stand-by letters of credit, deposits, guarantees, or other collateral items. In determining exposure, Northern Utilities considers collateral that it holds to reduce individual counterparty credit exposure.

To the extent Northern Utilities has short-term borrowings, changes in interest rates will impact the cost of its variable rate debt.

 

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GRANITE STATE’S FINANCIAL AND OTHER INFORMATION

Description of Business

Granite State is a natural gas transmission pipeline, regulated by the FERC, operating 86 miles of underground gas transmission pipeline primarily located in Maine and New Hampshire. Granite State provides Northern Utilities with interconnection to three major natural gas pipelines and access to domestic natural gas supplies in the south and Canadian natural gas supplies in the north. Granite State was incorporated under the laws of New Hampshire in 1955. It is a wholly owned subsidiary of NiSource.

Granite State had an investment in Net Utility Plant of $16.5 million at December 31, 2007, and net operating revenue of $3.4 million for 2007. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third party marketers. Granite State receives centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $0.6 million in 2007.

Selected Financial Data

The following table shows selected historical financial and operating data of Granite State for the periods and as of the dates indicated. The selected historical financial data of Granite State as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 are derived from the historical audited financial statements of Granite State appearing elsewhere in this prospectus. The selected historical financial data of Granite State as of March 31, 2008 and 2007 and for the three months ended March 31, 2008 and 2007 are derived from the historical unaudited financial statements of Granite State appearing elsewhere in this prospectus. The selected historical financial data of Granite State as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 are derived from unaudited financial statements not included herein. The table should also be read together with the section entitled Granite State’s Financial and Other Information — Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

		For the Three Months Ended March 31,						For the Year Ended December 31,
(millions)		2008			2007			2007				2006			2005			2004				2003
		(unaudited)
Statements of Earnings(Loss):
Net Operating Revenue		$	1.0		$	1.0		$	3.4			$	4.2		$	4.5		$	4.7			$	4.7
Operating Income		$	0.2		$	0.2		$	0.4			$	0.2		$	0.9		$	0.9			$	0.9
Non-Operating Income			—			0.1			—				0.4			0.2			(0.2	)			0.4
Interest Expense			0.1			0.1			0.6				0.5			0.2			0.1				0.1
Net Income (Loss)		$	0.1		$	0.2		$	(0.2	)		$	0.1		$	0.5		$	0.3			$	0.3

 

		As of March 31,						As of December 31,
(millions)		2008			2007			2007			2006			2005			2004			2003
		(unaudited)
Balance Sheet Data:
Utility Plant (Original Cost)		$	23.9		$	23.0		$	24.0		$	23.2		$	19.5		$	14.5		$	11.6
Total Assets		$	35.4		$	31.0		$	27.3		$	33.3		$	30.0		$	26.7		$	26.2
Capitalization:
Common Stockholders’ Equity		$	13.0		$	13.1		$	12.8		$	13.0		$	12.7		$	12.3		$	12.0
Total Capitalization		$	13.0		$	13.1		$	12.8		$	13.0		$	12.7		$	12.3		$	12.0

 

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Sales of natural gas and the related results of operations can be significantly affected by seasonal weather conditions. Annual revenues are substantially realized during the heating season as a result of higher sales of natural gas due to cold weather. Accordingly, operating results historically are most favorable in the first and fourth calendar quarters. Therefore, fluctuations in seasonal weather conditions between years may have a significant effect on results of operations and cash flows.

Financial Statements

Granite State’s unaudited financial statements as of March 31, 2008 and 2007 and for the three months ended March 31, 2008 and 2007 are set forth beginning on page F-49 of this prospectus.

Granite State’s financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005, together with the independent registered public accounting firm’s report, are set forth beginning on page F-60 of this prospectus.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of financial condition and results of operations should be read in conjunction with Granite State’s historical financial statements and notes included elsewhere in this prospectus.

Three Months Ended March 31, 2008 and 2007

The following table and discussion is a summary of Granite State’s results of operations for the three months ended March 31, 2008 and 2007.

 

		For the Three Months Ended March 31,
(millions)		2008				2007
Net Revenues		$	1.0			$	1.0
Operating Expenses
Operation and Maintenance			0.4				0.4
Depreciation and Amortization			0.2				0.2
Other Taxes			0.1				0.1
Total Operating Expenses			0.7				0.7
Operating Income			0.3				0.3
Other Income (Deductions)
Interest Expense, Net			(0.1	)			(0.1	)
Other, Net			—				0.1
Total Other Income (Deductions)			(0.1	)			—
Income Before Income Taxes			0.2				0.3
Income Taxes			0.1				0.1
Net Income		$	0.1			$	0.2

Three Months Ended March 31, 2008 Compared to the Three Months Ended March 31, 2007

Net Revenues. Net revenues of $1.0 million for the quarter ended March 31, 2008 were consistent with net revenues of $1.0 million for the same period of 2007.

 

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Operating Expenses. Operating expense was $0.7 million for quarter ended March 31, 2008 and was flat compared to the same period in 2007.

Other Income (Deductions). Other Income (Deductions) reduced income in the first quarter of 2008 by $0.1 million and was relatively flat compared to the same period in 2007. Other Income (Deductions) includes contingent tax interest income.

Income Tax Expense. Income tax expense was $0.1 million for the quarters ended March 31, 2008 and 2007.

Regulatory Matters

General

Granite State’s interstate natural gas transportation system operations are regulated by the FERC under the Natural Gas Act, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Granite State’s system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, and terms and conditions of service for its customers. Generally, the FERC’s authority extends to:

 

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transportation of natural gas;

 

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rates and charges for natural gas transportation;

 

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certification and construction of new facilities;

 

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initiation, extension or abandonment of services;

 

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maintenance of accounts and records;

 

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commercial relationships and communications between pipelines and certain affiliates;

 

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terms and conditions of service and service contracts with customers;

 

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depreciation and amortization policies; and

 

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acquisition, extension and abandonment of facilities.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas

On October 31, 2007, the NHPUC issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that UAFG in the 2007-2008 winter cost of gas forecast is approximately 1% of firm sales, compared to a reported 7.59% UAFG for the 12-month period ending April 2007. The NHPUC recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that period, the cause of any misreporting, and a solution. The NHPUC ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of its investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra at the M&NE / PNGTS Newington Gate Station caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought from the NHPUC and obtained an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct Northern Utilities’ UAFG levels and associated cost impacts.

 

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On February 15, 2008, Northern Utilities filed its report with the NHPUC. Northern Utilities reported that it was working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005. As a result of these efforts, Northern Utilities received confirmation from Spectra on January 28, 2008, that Granite State was erroneously billed for an additional 758,709 Dth of natural gas between May 2005 and December 2007. As the primary transportation customer of Granite State at the Newington Gate Station, and due to the service arrangements under which Northern Utilities receives service from Granite State, the total amount of the error was passed through to Northern Utilities. Northern Utilities calculates that it was overcharged by approximately $5.7 million for gas purchases directly related to this meter error based on gas prices in effect at the time of the error.

As of June 2008, Granite State has recorded approximately $10.3 million reflecting the anticipated liability of the future refund amount to Northern Utilities based on current market prices.

Northern Utilities has been informed by Spectra that resolution of the issue and any cash-out or refund that needs to be made to Granite State and/or Northern Utilities requires the involvement of PNGTS. PNGTS has agreed to repay the lost gas to Granite State over an 18-month period, but final documents memorializing the payback have not been completed. Northern Utilities has agreed to inform the NHPUC at 120-day intervals until an acceptable resolution is reached.

Liquidity and Capital Resources

Generally, cash flow from operations and short-term borrowings has provided sufficient liquidity to meet Granite State’s operating requirements. Historically, cash receipts were generally deposited in NiSource’s money pool accounts and cash disbursements were made from those accounts.

Working Capital. Granite State’s working capital requirements are primarily driven by changes in accounts receivable, exchange gas payable/receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers.

Cash Flow. Net cash provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the three months ended March 31, 2008 and 2007 were as follows:

 

		For the Three Months Ended March 31,
(millions)		2008				2007
Net Cash Provided by (Used in) Operating Activities		$	0.2			$	(1.3	)
Net Cash Used in Investing Activities		$	—			$	(0.2	)
Net Cash Provided by (Used in) Financing Activities		$	(0.2	)		$	1.6

Net cash flows provided by operating activities increased by $1.5 million for the first quarter of 2008 compared to the first quarter of 2007.

The changes in cash used for investing activities were driven by the level of capital expenditures from period to period. Funds for such expenditures were provided from funds available at the beginning of the year, cash generated from operations, and other sources as may have been required.

Capital expenditures were zero and $0.2 million for the three months ended March 31, 2008 and 2007, respectively.

Cash flow used for financing activities primarily consisted of changes in borrowings from the NiSource Money Pool.

 

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NiSource Finance Corporation, a wholly owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Granite State was a participant in the NiSource Money Pool for all of the periods presented in the financial statements.

NiSource will retain responsibility for satisfying the outstanding balance to the NiSource Money Pool.

Critical Accounting Policies and Estimates

There were no changes to Granite State’s critical accounting policies and estimates since December 31, 2007.

Off Balance Sheet Arrangements

Granite State does not have off balance sheet financing arrangements with third parties and maintains no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

Recently Adopted Accounting Pronouncements

SFAS No. 157 – Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not change the requirements to apply fair value in existing accounting standards.

Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

To increase consistency and comparability in fair value measurements, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The level in the fair value hierarchy disclosed is based on the lowest level of input that is significant to the fair value measurement. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

 

Ÿ

Level 1 inputs are quoted prices (unadjusted) in active markets for identical asset or liabilities that the company has the ability to access as of the reporting date.

 

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Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data.

 

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Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

SFAS No. 157 became effective for Granite State as of January 1, 2008. The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on the following three items, which are required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption: (i) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF Issue No. 02-3; (ii) existing hybrid financial instruments measured initially at fair value using the transaction price; and (iii) blockage factor discounts. The adoption of SFAS No. 157 did not have an impact on the January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

 

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In February 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157” (FSP FAS 157-2), which delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of non-financial assets and liabilities until fiscal years beginning after November 15, 2008. Granite State has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities.

SFAS No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Granite State chose not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

FIN 48 – Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Granite State adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Granite State adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 increased “Prepayments” by $2,437, increased “Regulatory Assets” by $628,963, and decreased “Other Current Liabilities” by $19,057. “Pension and Postretirement Benefits” were increased by $650,457. With the adoption of SFAS No. 158 Granite State determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Granite State recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Granite State adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $127,074, an increase to “Other Deferred Charges” of $53,996, an increase in

 

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“Pension and Postretirement Benefits” of $35,619, a decrease to “Retained Earnings” of $18,573, a decrease to “Accounts and Notes Receivable” of $7,061, an increase to “Accounts Receivable from Affiliated Companies” of $99,072, and an increase to “Accounts Payable to Affiliated Companies” of $1,887. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

Recently Issued Accounting Pronouncements

SFAS No. 141R – Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Granite State is currently reviewing the provisions of SFAS No. 141R to determine the impact on future business combinations.

Fiscal Years Ended December 31, 2007, 2006 and 2005

The following table and discussion is a summary of Granite State’s results of operations for the years ended December 31, 2007, 2006 and 2005.

 

		For the Year Ended December 31,
(millions)		2007				2006				2005
Net Revenues		$	3.4			$	4.2			$	4.5
Operating Expenses
Operation and Maintenance			1.9				2.9				2.7
Depreciation and Amortization			0.8				0.8				0.7
Other Taxes			0.3				0.2				0.2
Total Operating Expenses			3.0				3.9				3.6
Operating Income			0.4				0.3				0.9
Other Income (Deductions)
Interest Expense, Net			(0.6	)			(0.5	)			(0.2	)
Other, Net			—				0.4				0.2
Total Other Income (Deductions)			(0.6	)			(0.1	)			—
Income Before Income Taxes			(0.2	)			0.2				0.9
Income Taxes			—				0.1				0.4
Net (Loss) Income		$	(0.2	)		$	0.1			$	0.5

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Net Revenues. Net revenues decreased $0.8 million, or 19.0%, for the year ended December 31, 2007 compared to the same period of 2006. This decrease was primarily due to a $0.7 million decrease in regulatory trackers, which are offset in operating expenses, and a decrease of $0.6 million in firm capacity reservation revenues partially offset by a $0.4 million increase of commodity margin revenues.

Operating Expenses. Operating expenses decreased $0.9 million, or 23.1%, for the year ended December 31, 2007 compared to the same period of 2006. This decrease was primarily due to a $0.7 million

 

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decrease in regulatory trackers, which are offset in net revenues, and decreased pipeline integrity related costs of $0.2 million. Granite State paid management fees of $0.6 million and $0.7 million in 2007 and 2006, respectively, to NiSource and its affiliates for centralized administrative, management, and support services.

Other Income (Deductions). Other Income (Deductions) in 2007 reduced income by $0.6 million compared to a reduction in income of $0.1 million in 2006 due primarily to $0.3 million of contingent tax interest income in the 2006 period and higher interest expense of $0.1 million during 2007.

Income Tax Expense. Income tax benefits were effectively zero in 2007 because of a pretax loss of $0.2 million due to the reversal of $0.2 million of interest receivable on IRS refunds recorded through income tax expense. Income tax expense of $0.1 million was recorded in 2006 on pre-tax income of $0.2 million. The 2007 effective income tax rate of (10.1)% was 63.1% lower than the 2006 tax rate primarily due to the reversal of the $0.2 million of interest receivable on IRS refunds in 2007.

Year Ended December 31, 2006 Compared to the Year Ended December 31, 2005

Net Revenues. Net revenues decreased $0.3 million, or 6.7%, for the year ended December 31, 2006 compared to the same period of 2005. This decrease was primarily due to lower firm capacity reservation revenues.

Operating Expenses. Operating expenses increased $0.3 million in 2006, or 8.3%, from 2005. This increase was primarily due to increased pipeline integrity management costs of $0.4 million, partly offset by $0.1 million of decreased employee and administrative expenses. Granite State paid management fees of $0.7 million and $0.7 million in 2006 and 2005, respectively, to NiSource and its affiliates for centralized administrative, management, and support services.

Other Income (Deductions). Other Income (Deductions) in 2006 reduced income by $0.1 million compared to zero in 2005. The change between periods was primarily due to lower interest expense in 2005.

Income Tax Expense. Income taxes decreased $0.3 million in 2006 compared to 2005 primarily due to lower pre-tax income in 2006. The 2006 effective income tax rate of 53.1% was 7.3% higher than the 2005 effective tax rate primary due to the recording of regulatory flow through of state tax benefits in the 2005 period.

Regulatory Matters

General

Granite State’s interstate natural gas transportation system operations are regulated by the FERC under the Natural Gas Act, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. Granite State’s system operates under a tariff approved by the FERC that establishes rates, cost recovery mechanisms, and terms and conditions of service for its customers. Generally, the FERC’s authority extends to:

 

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transportation of natural gas;

 

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rates and charges for natural gas transportation;

 

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certification and construction of new facilities;

 

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initiation, extension or abandonment of services;

 

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maintenance of accounts and records;

 

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commercial relationships and communications between pipelines and certain affiliates;

 

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Ÿ

terms and conditions of service and service contracts with customers;

 

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depreciation and amortization policies; and

 

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acquisition, extension and abandonment of facilities.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas

On October 31, 2007, the NHPUC issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that UAFG in the 2007-2008 winter cost of gas forecast is approximately 1% of firm sales, compared to a reported 7.59% UAFG for the 12-month period ending April 2007. The NHPUC recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that period, the cause of any misreporting, and a solution. The NHPUC ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of its investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra at the M&NE / PNGTS Newington Gate Station caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought from the NHPUC and obtained an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct Northern Utilities’ UAFG levels and associated cost impacts.

On February 15, 2008, Northern Utilities filed its report with the NHPUC. Northern Utilities reported that it was working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005.

Significant FERC Developments

On June 30, 2005, the FERC issued the “Order on Accounting for Pipeline Assessment Costs.” This guidance was issued by the FERC to address consistent application across the industry for accounting for the costs of implementing the Department of Transportation’s Integrity Management Rule. The effective date of the guidance was January 1, 2006 after which all assessment costs have been recorded as operating expenses. The rule specifically provides that amounts capitalized in periods prior to January 1, 2006 will be permitted to remain as recorded.

Liquidity and Capital Resources

Generally, cash flow from operations and short-term borrowings has provided sufficient liquidity to meet Granite State’s operating requirements. Historically, cash receipts were generally deposited in NiSource’s money pool accounts and cash disbursements were made from those accounts.

Working Capital. Granite State’s working capital requirements are primarily driven by changes in accounts receivable, exchange gas payable/receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers.

 

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Cash Flow. Net cash provided by operating activities, net cash used in investing activities and net cash provided by (used in) financing activities for the years ended December 31, 2007, 2006 and 2005 were as follows:

 

		For the Year Ended December 31,
(millions)		2007				2006				2005
Net Cash Provided by Operating Activities		$	2.2			$	2.9			$	3.3
Net Cash Used in Investing Activities		$	(1.6	)		$	(3.7	)		$	(4.5	)
Net Cash (Used in) Provided by Financing Activities		$	(0.6	)		$	0.8			$	1.1

Net cash flows provided by operating activities decreased by $0.7 million for 2007 compared to 2006 primarily due to changes in working capital including payments of accounts payable and accrued expenses, partially offset by the collection of tax and interest receivables.

Net cash provided by operating activities decreased by $0.4 million in 2006 compared to 2005 primarily due to changes in working capital and higher tax receivables.

The changes in cash used for investing activities were driven by the level of capital expenditures from period to period. Funds for such expenditures were provided from funds available at the beginning of the year, cash generated from operations, and other sources as may have been required.

Capital expenditures of $1.6 million, $3.7 million and $4.5 million for the years ended December 31, 2007, 2006 and 2005, respectively, were primarily for capital maintenance expenditures.

Cash flow used for financing activities primarily consisted of changes in borrowings from the NiSource Money Pool.

NiSource Finance Corporation, a wholly owned subsidiary of NiSource, administers short-term financing and short-term investment opportunities for NiSource’s participating subsidiaries through a money pool. Granite State was a participant in the NiSource Money Pool for all of the periods presented in the financial statements.

NiSource will retain responsibility for satisfying the outstanding balance to the NiSource Money Pool.

Total contractual cash obligations consist of vehicle leases with estimated payments of $26,808, $29,777 and $25,731 for 2008, 2009 and 2010, respectively, and other postretirement benefit plan contributions of approximately $60,000 in 2008.

Off Balance Sheet Arrangements

Granite State does not have off balance sheet financing arrangements with third parties and maintains no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of Granite State’s financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on Granite State’s results of operations, equity or cash flows.

 

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Accounting for Regulation. Granite State follows the accounting and reporting requirements of SFAS No. 71. SFAS No. 71 provides that rate-regulated companies account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

Granite State has designed its rates to recover the costs of providing regulated service and determined it is probable that such rates can be charged and collected. In the event that regulation significantly changes the opportunity for Granite State to recover its costs in the future, Granite State may no longer meet the criteria for the application of SFAS No. 71. In such event, a write-down of all or a portion of Granite State’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of SFAS No. 71, Granite State would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71” (SFAS No. 101). In management’s opinion, Granite State will be subject to SFAS No. 71 for the foreseeable future.

Intangible Assets. Intangible assets include $10.5 million related to the allocation of the purchase price resulting from NiSource’s purchase of the individual units of Bay State. Granite State was part of the Bay State at the time of this purchase. The amount is being amortized to operating expense over a forty-year period, and is not currently a component of Granite State’s rates. Granite State’s balance sheet dated as of December 31, 2007 and 2006 contains intangible assets discussed above which are not subject to recovery under SFAS No. 71. As a result, Granite State assesses the carrying amount and potential earnings of these assets whenever events or changes in circumstances indicate that the carrying value could be impaired as per FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144).

Pensions and Postretirement Benefits. Granite State has defined benefit plans for both pensions and other postretirement benefits. The plans are accounted for under SFAS No. 87, SFAS No. 88 and SFAS No. 106, as amended by SFAS No. 158. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition.

Contingencies. A contingent liability is recognized when it is probable that an environmental, tax, legal or other liability has been incurred and the amount of loss can reasonably be estimated. Accounting for contingencies requires significant management judgment regarding the estimated probabilities and ranges of exposure to a potential liability. Estimates of the loss and associated probability are made based on the current facts available, including present laws and regulations. Management’s assessment of the contingent liability could change as a result of future events or as more information becomes available. Actual amounts could differ from estimates and can have a material impact on Granite State’s results of operations and financial position.

Recently Adopted Accounting Pronouncements

SFAS No. 157 – Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be

 

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applied prospectively, with limited exceptions. Granite State adopted this standard during the first quarter of 2008. There was no material impact to the Financial Statements.

SFAS No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Granite State chose not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

FIN 48 – Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Granite State adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

SFAS No. 158 – Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Granite State adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 increased “Prepayments” by $2,437, increased “Regulatory Assets” by $628,963, and decreased “Other Current Liabilities” by $19,057. “Pension and Postretirement Benefits” were increased by $650,457. With the adoption of SFAS No. 158 Granite State determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Granite State recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Granite State adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $127,074, an increase to “Other Deferred Charges” of $53,996, an increase in “Pension and Postretirement Benefits” of $35,619, a decrease to “Retained Earnings” of $18,573, a decrease to “Accounts and Notes Receivable” of $7,061, an increase to “Accounts Receivable from Affiliated

 

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Companies” of $99,072, and an increase to “Accounts Payable to Affiliated Companies” of $1,887. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

Recently Issued Accounting Pronouncements

SFAS No. 141R – Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Granite State is currently reviewing the provisions of SFAS No. 141R to determine the impact on future business combinations.

Quantitative and Qualitative Disclosures about Market Risk

Risk is an inherent part of Granite State’s business and the extent to which management properly and effectively identifies, assesses, monitors and manages each of the various types of risk involved in the business can significantly impact profitability. Granite State seeks to identify, assess, monitor and manage, in accordance with defined policies and procedures, credit risk and interest rate risk. In addition, Granite State is exposed to market risk associated with the supply of, and demand for, natural gas and the impact of changes in natural gas prices, and can also be negatively affected by sustained downturns or sluggishness in the regional economy.

Credit risk represents the loss that Granite State would incur if a counterparty fails to perform under its contractual obligations. Exposure to credit risk is measured by summing a counterparty’s current obligations to us and the marked-to-market value of any forward positions with that entity. Credit exposure is generally mitigated by obtaining stand-by letters of credit, deposits, guarantees, or other collateral items. In determining exposure, Granite State considers collateral that Granite State holds to reduce individual counterparty credit exposure. As Granite State’s primary customer is Northern Utilities, an affiliate, credit risk is deemed to be minimal.

To the extent Granite State has short-term borrowings, changes in interest rates will impact the cost of this variable rate debt.

 

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MANAGEMENT

The following table provides information about our directors and senior management as of July 28, 2008.

 

Name		Age		Years of Service to Unitil Corporation		Position
Robert G. Schoenberger		57		11		Chairman of the Board and Chief Executive Officer
Mark H. Collin		49		20		Senior Vice President, Chief Financial Officer, and Treasurer
Thomas P. Meissner, Jr.		45		14		Senior Vice President and Chief Operating Officer
George R. Gantz		57		25		Senior Vice President, Unitil Service
Todd R. Black		44		10		President, Usource
Laurence M. Brock		55		13		Controller and Chief Accounting Officer
George E. Long		51		14		Vice President, Unitil Service
Raymond J. Morrissey		60		23		Vice President, Unitil Service
Sandra L. Whitney		45		18		Corporate Secretary
Dr. Robert V. Antonucci		62		4		Director
David P. Brownell		64		7		Director
Michael J. Dalton		67		24		Director
Albert H. Elfner, III		63		9		Director
Edward F. Godfrey		59		6		Director
Michael B. Green		58		7		Director
Eben S. Moulton		62		8		Director
M. Brian O’Shaughnessy		65		10		Director
Charles H. Tenney, III		60		16		Director
Dr. Sarah P. Voll		65		5		Director

Robert G. Schoenberger has been our Chairman of the Board and Chief Executive Officer since 1997, as well as our president since 2003. Prior to his employment with us, Mr. Schoenberger was president and chief operating officer of the New York Power Authority (a state-owned utility operating 6,000 Mw of generation and 1,400 miles of high voltage transmission) from 1993 until 1997. Mr. Schoenberger also serves as chairman and trustee of Exeter Health Resources, Exeter, New Hampshire, since 1998, and as a director of SatCon Technology Corporation, Boston, Massachusetts (a company engaged in the development and manufacture of power electronics and control systems) since 2007. Mr. Schoenberger was director of the Greater Seacoast (New Hampshire) United Way from 1998 until 2004, the New England Gas Association from 1999 until 2002 and the Southwest Power Pool from 2003 until 2005.

Mark H. Collin has been our Senior Vice President and Chief Financial Officer since February 2003. Mr. Collin has also served as our Treasurer since 1998. Mr. Collin joined us in 1988, and served as our Vice President of Finance from 1995 until 2003.

Thomas P. Meissner, Jr. has been our Senior Vice President and Chief Operating Officer since June 2005. Mr. Meissner served as our Senior Vice President, Operations, from February 2003 until June 2005. Mr. Meissner joined us in 1994 and served as our Director of Engineering from 1998 until 2003.

 

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George R. Gantz has been our Senior Vice President, Unitil Service, since January 2003. Mr. Gantz joined us in 1983 and served as our Senior Vice President, Communication and Regulation, from 1994 until 2003.

Todd R. Black has been President of Usource since June 2003. Mr. Black joined us in 1998 and served as Vice President, Sales and Marketing, for Usource from 1998 until 2003.

Laurence M. Brock has been our Controller and Chief Accounting Officer since June 2005. Mr. Brock joined us in 1995 as Vice President and Controller, and is a certified public accountant in the state of New Hampshire.

George E. Long, Jr. has been our Vice President, Unitil Service, since February 2003. Mr. Long joined us in 1994 and was Director, Human Resources, from 1998 until 2003.

Raymond J. Morrissey has our Vice President, Unitil Service, since February 2003. Mr. Morrissey served as our Vice President of Customer Service from 1992 until 2003, and general manager of FG&E from 1991 until 1992. Mr. Morrissey joined us in 1985.

Sandra L. Whitney has been our Corporate Secretary and secretary of our Board of Directors since February 2003. Ms. Whitney joined us in 1990 and has been the Corporate Secretary of our subsidiary companies, FG&E, UES, Unitil Power, Unitil Realty and Unitil Service since 1994.

Dr. Robert V. Antonucci has been a member of our Board of Directors since 2004. Dr. Antonucci has been the president of Fitchburg State College (FSC) in Fitchburg, Massachusetts since 2003. Prior to his employment with FSC, Dr. Antonucci was president of the School Group of Riverdeep, Inc., San Francisco, California, from 2001 until 2003 and president and chief executive officer of Harcourt Learning Direct and Harcourt Online College, Chestnut Hill, MA from 1998 until 2001. Dr. Antonucci also served as the commissioner of education for the Commonwealth of Massachusetts from 1992 until 1998. Dr. Antonucci also serves as a trustee of Eastern Bank (formerly Plymouth (Massachusetts) Savings Bank) since 1988.

David P. Brownell has been a member of our Board of Directors since 2001. Mr. Brownell has been a retired senior vice president of Tyco International Ltd. (Tyco) (a diversified global manufacturing and service company), Portsmouth, New Hampshire, since 2003. Mr. Brownell had been with Tyco since 1984. Mr. Brownell was also interim president of the University of New Hampshire Foundation (UNHF), former vice chairman of the board of UNHF, former volunteer board president of the United Way of the Greater Seacoast, and a former board member of the NH Junior Achievement Advisory Council.

Michael J. Dalton has been a member of our Board of Directors since 1984. Mr. Dalton has been the retired president and chief operating officer of Unitil since 2003. Mr. Dalton has been a member of the Industrial Advisory Board of the University of New Hampshire College of Engineering and Physical Sciences since 2003. Mr. Dalton was a director of the New England Gas Association from 2002 until 2003, the Electric Council of New England, the UNHF, the University of New Hampshire Alumni Association, and the University of New Hampshire President’s Council.

Albert H. Elfner, III has been a member of our Board of Directors since 1999. Mr. Elfner was the chairman of Evergreen Investment Management Company, Boston, MA from 1994 until 1999 and its chief executive officer from 1995 until 1999. Mr. Elfner is also a director of NGM Insurance Company (NGM), Jacksonville, FL, as well as a member of the NGM finance committee.

Edward F. Godfrey has been a member of our Board of Directors since 2002. Mr. Godfrey was the executive vice president and chief operating officer of Keystone Investments, Incorporated (Keystone), Boston, Massachusetts, from 1997 until 1998. Mr. Godfrey was senior vice president, chief financial officer and treasurer of Keystone from 1988 until 1996. Mr. Godfrey is also a director of VehiCare, LLC, Charlotte, North Carolina, since 2006.

 

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Michael B. Green has been a member of our Board of Directors since 2001. Mr. Green has been the president and chief executive officer of Capital Region Health Care and Concord Hospital, Concord, New Hampshire, since 1992. Mr. Green is also a member of the adjunct faculty, Dartmouth Medical School, Dartmouth College, Hanover, New Hampshire. In addition, Mr. Green also currently serves on the board of the Foundation for Healthy Communities, is a director of the New Hampshire Hospital Association, a director of New Hampshire Business Committee for the Arts, and a director of Merrimack County Savings Bank including membership on the bank’s investment and audit committees.

Eben S. Moulton has been a member of our Board of Directors since 2000. Mr. Moulton has been the managing partner of Seacoast Capital Corporation, Danvers, Massachusetts (a private investment company) since 1995. Mr. Moulton is also a director of IEC Electronics (a complex circuit boards manufacturer), a director of six private companies, and a trustee of Colorado College, Colorado Springs, Colorado.

M. Brian O’Shaughnessy has been a member of our Board of Directors since 1998. Mr. O’Shaughnessy has been the chairman of the board of Revere Copper Products, Inc. (Revere), Rome, New York, since 1988. Mr. O’Shaughnessy also served as chief executive officer and president of Revere from 1988 until 2007. Mr. O’Shaughnessy also serves on the Board of Directors of the Coalition for a Prosperous America, three copper industry trade associations, three manufacturing associations in New York State regarding energy-related issues, and the Economic Development Growth Enterprise of Mohawk Valley.

Charles H. Tenney III has been a member of our Board of Directors since 1992. Mr. Tenney has been the director of operations of BrainShift.com, Inc., Medford, Massachusetts (a learning technology development company) since 2002. Mr. Tenney is also a director and treasurer of The BrainShift Foundation. Mr. Tenney also served as a member of the board of overseers of the Huntington Theater Company, Boston, Massachusetts, from 2004 until 2006.

Dr. Sarah P. Voll has been a member of our Board of Directors since 2003. Dr. Voll has been a retired vice president, National Economic Research Associates, Inc. (NERA), Washington, District of Columbia, a firm of consulting economists specializing in industrial and financial economics, since 2007. Dr. Voll had been with NERA in the position of vice president since 1999, and in the position of senior consultant from 1996 until 1999. Prior to her employment with NERA, Dr. Voll was a staff member at the NHPUC from 1980 until 1996.

 

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VOTING SECURITIES AND PRINCIPAL HOLDERS THEREOF

No person owns of record and, to our knowledge, no person owns beneficially, more than five percent of our common stock.

The following table sets forth information on the beneficial ownership of our common stock by each director, each executive officer named in the Summary Compensation Table contained in our proxy statement dated as of February 12, 2008 and all directors and executive officers as a group, in each case as of July 28, 2008. To our knowledge, each director and executive officer has sole voting and investment power with respect to the shares reported, except as otherwise noted in the footnotes to the following table. The address of each of our directors and executive officers is c/o Unitil Corporation, 6 Liberty Lane West, Hampton, New Hampshire 03842-1720.

 

Name of Person or Group		Amount and Nature of Beneficial Ownership of Common Stock(1)		Percent of Class
Dr. Robert V. Antonucci Director		832		*
David P. Brownell Director		2,637		*
Michael J. Dalton(2) Director		37,082		*
Albert H. Elfner, III Director		6,549		*
Edward F. Godfrey Director		2,058		*
Michael B. Green Director		1,687		*
Eben S. Moulton Director		2,994		*
M. Brian O’Shaughnessy Director		3,834		*
Charles H. Tenney III(3) Director		148,659		2.6	%
Dr. Sarah P. Voll Director		1,641		*
Robert G. Schoenberger(4) Chairman of the Board, Chief Executive Officer and President		99,388		1.7	%
Mark H. Collin(5) Senior Vice President, Chief Financial Officer and Treasurer		15,126		*
Thomas P. Meissner, Jr.(6) Senior Vice President and Chief Operating Officer		12,570		*
George R. Gantz(7) Senior Vice President, Unitil Service Corp.		17,722		*
Todd R. Black(8) President, Usource, Inc.		10,965		*
All Directors and Executive Officers as a Group (19 Persons)(9)		393,607		6.8	%

 

*

Represents less than 1% of our outstanding common stock.

 

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(1)

Based on information furnished to us by our directors and executive officers.

 

(2)

Included are 8,088 shares held by a member of Mr. Dalton’s family. Mr. Dalton has no voting rights or investment power with respect to, and no beneficial interest in, such shares.

 

(3)

Included are 1,294 shares that are held in trust for Mr. Tenney under the terms of the Unitil Tax Deferred Savings and Investment Plan (401(k)). Mr. Tenney has voting power only with respect to the shares credited to his account. Also included are 142,986 shares that are held by The Charles H. Tenney, II 1995 Trust, of which Mr. Tenney is the co-trustee. Mr. Tenney has shared voting power and shared dispositive power with respect to such shares and a 50% pecuniary interest in such shares. Does not include (i) 7,378 shares that are held by The Tenney Trust or (ii) 2,261 shares that are held by The Trust under the Will of Charles H. Tenney, II, in each case in which Mr. Tenney has a pecuniary interest in such shares but does not have voting power or dispositive power with respect to such shares.

 

(4)

Included are 3,476 shares that are held in trust for Mr. Schoenberger under the terms of the 401(k). Mr. Schoenberger has voting power only with respect to the shares credited to his account. Also included are 60,000 fully vested option shares that Mr. Schoenberger has the right to purchase upon the exercise of that option under the terms of our 1998 Stock Option Plan, and 11,475 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan.

 

(5)

Included are 1,838 shares that are held in trust for Mr. Collin under the terms of the 401(k). Mr. Collin has voting power only with respect to the shares credited to his account. Also included are 5,000 option shares that Mr. Collin has the right to purchase upon the exercise of that option under the terms of our 1998 Stock Option Plan, and 3,684 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan.

 

(6)

Included are 680 shares that are held in trust for Mr. Meissner under the terms of the 401(k). Mr. Meissner has voting power only with respect to the shares credited to his account. Also included are 3,000 option shares that Mr. Meissner has the right to purchase upon the exercise of that option under the terms of our 1998 Stock Option Plan, and 3,834 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan.

 

(7)

Included are 7,500 option shares that Mr. Gantz has the right to purchase upon the exercise of that option under the terms of our 1998 Stock Option Plan, and 2,150 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan.

 

(8)

Included are 855 shares that are held in trust for Mr. Black under the terms of the 401(k). Mr. Black has voting power only with respect to the shares credited to his account. Also included are 6,000 option shares that Mr. Black has the right to purchase upon the exercise of that option under our 1998 Stock Option Plan, and 1,351 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan.

 

(9)

Included are 93,500 option shares that executive officers have the right to purchase upon the exercise of options under the terms of our 1998 Stock Option Plan, and 26,020 shares of unvested restricted stock granted under the terms and conditions of our Restricted Stock Plan. No director or executive officer has pledged any shares of common stock.

 

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DESCRIPTION OF COMMON STOCK

The following description of our common stock summarizes general terms that apply to our common stock. Because this is only a description, it does not contain all of the information that may be important to you. This summary is subject to and qualified in its entirety by reference to our Articles of Incorporation, Articles of Amendment to the Articles of Incorporation and By-Laws, which are incorporated by reference as exhibits to the registration statement of which this prospectus is a part. See the section entitled Where You Can Find More Information. This section also summarizes relevant provisions of statutes with which we must comply. The terms of these statutes are more detailed than the general information provided below; therefore, you should carefully consider the actual provisions of each of the statutes referenced below.

Authorized and Outstanding Shares

Our authorized capital stock consists of 8,000,000 shares of common stock, no par value. As of             , 2008,             shares of common stock were outstanding and our subsidiaries UES and FG&E have preferred stock outstanding. Unitil Corporation is not authorized to issue any shares of preferred stock. All of the common stock outstanding is fully paid and nonassessable.

At present, our authorized shares of common stock available for issuance are insufficient for this offering. Therefore, we have requested that our shareholders approve and adopt an amendment to our Articles of Incorporation at a special meeting scheduled for September 10, 2008 to increase the authorized numbers of shares of common stock from 8,000,000 shares to 16,000,000 shares in the aggregate.

If our shareholders approve and adopt the amendment, approximately             shares of common stock will be available for issuance under our Articles of Incorporation after giving effect to the equity offering described in this prospectus. Except in connection with this offering, our Board of Directors has no immediate plans, intentions, or commitments to issue additional shares of common stock for any purpose, including, without limitation, rendering more difficult or discouraging a merger, tender offer, proxy contest or other change in control of us (collectively referred to as change in control transactions). However, the availability of additional authorized shares of common stock could render more difficult, discourage, or delay a change in control transaction, which may adversely affect the ability of our shareholders to obtain a premium for their shares of common stock. Our Board of Directors is not aware of any pending or proposed change in control transactions.

We will not seek further shareholder authorization for issuances of additional authorized shares of common stock unless deemed advisable by our Board of Directors or required by law, rule, or regulation. In some instances, the SEC or stock exchanges or over-the-counter markets on which our securities may then be listed may need to approve such issuances.

Dividend Rights

Holders of our common stock are entitled to those dividends as may be declared from time to time by our Board of Directors. We may pay dividends on our common stock from any funds, property or shares legally available for this purpose.

Voting Rights and Cumulative Voting

Each holder of our common stock is entitled to one vote per share on all matters submitted to a vote of the holders of our common stock. Holders of common stock do not have cumulative voting rights.

 

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Preemptive Rights

The holders of our common stock have no preemptive rights to purchase additional shares of common stock or any other of our securities.

Liquidation Rights

In the event that we are liquidated, after payment of our debts and liabilities, the holders of our common stock are entitled to share equally in the balance of our remaining assets, if any.

Transfer Agent and Registrar

Computershare Trust Company, N.A. serves as the transfer agent and registrar of our common stock.

Staggered Board of Directors

Our By-Laws provide for a Board of Directors of between nine and fifteen directors divided into three classes, each class being as nearly equal in number as possible, and each with their respective terms of office arranged so that the term of office of one class expires in each year, at which time a corresponding number of directors is elected for a term of three years. We currently have eleven directors.

Our staggered Board of Directors and the statutory provisions described above may delay, deter or prevent a tender offer or takeover attempt that a holder of shares of our common stock might consider is in his or her best interest, including those attempts that might result in a premium over the market price of the shares of our common stock.

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated                      , 2008, we have agreed to sell to the underwriters named below, for whom RBC Capital Markets Corporation is acting as representative, the following respective numbers of shares of common stock:

 

Underwriter		Number of Shares
RBC Capital Markets Corporation
Janney Montgomery Scott LLC
Oppenheimer & Co.
Brean Murray, Carret & Co, LLC
Edward D. Jones & Co., L.P.
Total

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to              additional shares at the offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock directly to the public at the offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $             per share. After the offering, RBC Capital Markets Corporation may change the offering price and concession and discount to broker/dealers. The underwriters and selling group members may allow a discount of $             per share on sales to other broker/dealers. The expenses of the offering that are payable by us are estimated to be $             (exclusive of underwriting discounts and commissions).

The following table summarizes the compensation and estimated expenses we will pay:

 

Per Share

Total

Without Over- allotment

With Over- allotment

Without Over- allotment

With Over- allotment

Underwriting Discounts and Commissions paid by us

$

$

$

$

We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement or amendment to a registration statement under the Securities Act relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any such offer, sale, pledge, disposition or filing, without the prior written consent of RBC Capital Markets Corporation for a period of 90 days after the date of this prospectus, except (i) issuances pursuant to the exercise of options outstanding on the date hereof, (ii) grants of employee stock options and restricted stock and other securities issuances pursuant to the terms of a plan in effect on the date hereof, (iii) issuances pursuant to the exercise of such options, (iv) issuances to our employees under the terms of the employee stock purchase plan in effect on the date hereof, (v) issuances pursuant to our 401(k) plan, (vi) issuances to directors pursuant to the incentive plan in effect on the date hereof, (vii) the filing of registration statements on Form S-8 and

 

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amendments thereto in connection with those securities and plans, and (viii) the taking any of the foregoing actions in connection with the issuance of shares or other securities in connection with acquisitions and private placements by us.

Our executive officers and directors have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of RBC Capital Markets Corporation for a period of 90 days after the date of this prospectus, provided, however, that the foregoing shall not apply to (i) any transfer that is a bona fide gift or any transfer to a trust for the benefit of the officer or director or an immediate family member, provided the transferee agrees to be bound in writing by the terms of the agreement, or (ii) any sales or option exercises pursuant to Rule 10b5-1 trading plans in effect as of the date of this prospectus.

The 90-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 90-day restricted period we issue an earnings release or announce material news or a material event; or (2) prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 15-day period following the last day of the 90-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release of the announcement of the material news or material event.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

Our common stock is currently listed on the American Stock Exchange under the symbol “UTL.” Our common stock has been authorized for listing on the New York Stock Exchange effective August 21, 2008 under the symbol “UTL.”

In the ordinary course of business, certain of the underwriters and their affiliates have provided and may in the future provide financial advisory, investment banking and general financing and banking services for us and our affiliates for customary fees.

RBC Capital Markets Corporation:

 

Ÿ

has acted as a placement agent in connection with the private placement of our debt securities;

 

Ÿ

is a lender in connection with the commitment letter relating to our bridge credit facility; and

 

Ÿ

is a placement agent in connection with the offering of debt securities by Northern Utilities and Granite State.

We expect to use the proceeds from this offering to partially finance the Proposed Acquisitions, to pay fees and expenses related to the Proposed Acquisitions and for other general corporate purposes.

 

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In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

 

Ÿ

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

Ÿ

Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by exercising their over-allotment option and/or purchasing shares in the open market.

 

Ÿ

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

 

Ÿ

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and if commenced, may be discontinued at any time.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters or selling group members, if any, participating in this offering. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make Internet distributions on the same basis as other allocations.

 

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LEGAL MATTERS

The validity of the shares of the common stock to be sold in the offering will be passed upon for us by Dewey & LeBoeuf LLP, New York, New York. Certain legal matters in connection with the offering will be passed upon for the underwriters by Vinson & Elkins L.L.P., New York, New York.

EXPERTS

The financial statements incorporated in this prospectus by reference to our Annual Report on Form 10-K for the year ended December 31, 2007 have been so incorporated in reliance on the report of Vitale, Caturano & Company, Ltd., independent registered public accountants, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Northern Utilities as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007 included in this Prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of Granite State as of December 31, 2007 and 2006, and for each of the three years in the period ended December 31, 2007 included in this Prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings are available to the public over the internet at the SEC’s web site at http://www.sec.gov. You may also read and copy any document we file with the SEC at its public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. You can obtain further information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. Our common stock is currently listed on the American Stock Exchange under the symbol “UTL.” Our common stock has been authorized for listing on the New York Stock Exchange effective August 21, 2008 under the symbol “UTL.”

This prospectus is part of a registration statement that we filed with the SEC on Form S-3. This prospectus does not contain all of the information set forth in the registration statement and its exhibits, portions of which have been omitted as permitted by the rules and regulations of the SEC. You may refer to the registration statement and the exhibits for more information about the securities and us. You may inspect the registration statement and exhibits without charge at the SEC’s public reference room or at the SEC’s website.

The SEC allows us to “incorporate by reference” into this prospectus the information we file with it, which means that we can disclose important information to you by referring to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede information in this prospectus. We incorporate by reference the documents listed below into this prospectus, and any future filings made by us with the

 

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SEC under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as amended, until this offering is complete. The documents we incorporate by reference are:

 

Ÿ

our Annual Report on Form 10-K for the fiscal year ended December 31, 2007;

 

Ÿ

our Quarterly Report on Form 10-Q for the quarter ended March 31, 2008;

 

Ÿ

our Current Reports on Form 8-K filed with the SEC on January 31, 2008, February 20, 2008, March 21, 2008, April 8, 2008, June 20, 2008 and July 30, 2008; and

 

Ÿ

the description of our common stock, no par value, contained in the registration statement on Form 8-A filed with the SEC on February 8, 1985.

You may request a copy of any of these documents at no cost (other than an exhibit to the filing unless we have specifically incorporated that exhibit by reference into the filing), by writing or telephoning us at the following address:

Shareholder Relations

Unitil Corporation

6 Liberty Lane West

Hampton, NH 03842-1720

Telephone (800) 999-6501

http://www.unitil.com

 

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UNITIL CORPORATION

 

 

PRO FORMA FINANCIAL STATEMENTS AS OF MARCH 31, 2008 AND FOR THE

THREE MONTHS ENDED MARCH 31, 2008 AND 2007, AND AS OF

DECEMBER 31, 2007 AND FOR

THE YEAR ENDED DECEMBER 31, 2007

 

 

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The following summary unaudited pro forma combined selected financial data has been prepared to give effect to the acquisition by Unitil Corporation (“Unitil”) of Northern Utilities, Inc. (“Northern Utilities” or “NU”) and Granite State Gas Transmission, Inc. (“Granite State” or “GS”) as if the businesses had actually been combined as of December 31, 2007 and March 31, 2008 (with respect to the balance sheet information using currently available fair value information) and as of January 1, 2007 (with respect to statements of operations information).

The summary unaudited pro forma combined selected financial data includes adjustments for the acquisition purchase accounting and the replacement of the predecessor owner’s equity and debt amounts with the new equity and debt capitalization proposed by Unitil. The debt and equity adjustments included in the pro forma financial statements reflect the amount necessary to finance the acquisition. The actual amounts of the debt and equity offering sizes may vary. The summary unaudited pro forma combined selected financial data excludes adjustments to recognize the estimated operating expense savings of $5.6 million annually due to the achievement of efficiencies associated with the provision of shared utility services and the adoption of best practices associated with these shared utility services and also excludes a reduction in operating expenses of $1.2 million related to compliance violation penalties incurred by Northern Utilities in 2007. The summary unaudited pro forma combined selected financial data also excludes adjustments to recognize the enhancements to revenue of Northern Utilities and Granite State that may occur from the execution of Unitil’s regulatory plan.

The summary unaudited pro forma combined selected financial data is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined and had the impact of possible revenue enhancements, expense efficiencies and asset disposition, among other factors, been considered, and is not intended to be a projection of future results. The summary unaudited pro forma combined selected financial data should be read in conjunction with the unaudited pro forma combined financial statements and the notes thereto included elsewhere in the proxy statement.

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED STATEMENTS OF EARNINGS

(millions except common shares and per share data)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS														PRO FORMA UNITIL
March 31, 2008
Operating Revenues:
Electric		$	56.6		$	0.0					$	0.0						$	0.0			$	56.6
Gas			14.3			54.5																	68.8
Other			1.0			0.0																	1.0
Total Operating Revenues			71.9			54.5						0.0							0.0				126.4
Operating Expenses:
Purchased Electricity			42.9			0.0																	42.9
Purchased Gas			9.0			36.3																	45.3
Operation and Maintenance			4.7			6.7																	11.4
Conservation & Load Management			0.6			0.0																	0.6
Depreciation and Amortization			5.2			3.0		(N	)			(0.6	)		(O	)			(0.4	)			7.2
Provisions for Taxes:
Local Property and Other			1.7			0.8																	2.5
Federal and State Income			1.8			2.8		(P	)			0.7			(P	)			(0.6	)			4.7
Total Operating Expenses			65.9			49.6						0.1							(1.0	)			114.6
Operating Income			6.0			4.9						(0.1	)						1.0				11.8
Non-Operating Expenses			0.1			0.0																	0.1
Income Before Interest Expense			5.9			4.9						(0.1	)						1.0				11.7
Interest Expense, net			2.6			0.9		(Q	)			(1.1	)		(R	)			1.9				4.3
Net Income			3.3			4.0						1.0							(0.9	)			7.4
Less: Dividends on Preferred Stock			0.0			0.0																	0.0
Net Income Applicable to Common Shareholders		$	3.3		$	4.0					$	1.0						$	(0.9	)		$	7.4
Average Common Shares Outstanding — Basic (000s)			5,719					(S	)			3,090											8,809
Average Common Shares Outstanding — Diluted (000s)			5,724									3,090											8,814
Earning per Common Share
Basic		$	0.57																			$	0.84
Diluted		$	0.57																			$	0.84

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED STATEMENTS OF EARNINGS

(millions except common shares and per share data)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS														PRO FORMA UNITIL
March 31, 2007
Operating Revenues:
Electric		$	62.7		$	0.0					$	0.0						$	0.0			$	62.7
Gas			14.2			61.3																	75.5
Other			0.9			0.0																	0.9
Total Operating Revenues			77.8			61.3						0.0							0.0				139.1
Operating Expenses:
Purchased Electricity			48.2			0.0																	48.2
Purchased Gas			9.8			43.0																	52.8
Operation and Maintenance			6.5			7.5																	14.0
Conservation & Load Management			1.0			0.0																	1.0
Depreciation and Amortization			4.5			2.7		(N	)			(0.6	)		(O	)			(0.4	)			6.2
Provisions for Taxes:
Local Property and Other			1.5			0.7																	2.2
Federal and State Income			1.6			2.7		(P	)			0.8			(P	)			(0.6	)			4.5
Total Operating Expenses			73.1			56.6						0.2							(1.0	)			128.9
Operating Income			4.7			4.7						(0.2	)						1.0				10.2
Non-Operating Expenses			0.0			0.0																	0.0
Income Before Interest Expense			4.7			4.7						(0.2	)						1.0				10.2
Interest Expense, net			2.1			0.8		(Q	)			(1.4	)		(R	)			1.8				3.3
Net Income			2.6			3.9						1.2							(0.8	)			6.9
Less: Dividends on Preferred Stock			0.0			0.0																	0.0
Net Income Applicable to Common Shareholders		$	2.6		$	3.9					$	1.2						$	(0.8	)		$	6.9
Average Common Shares Outstanding — Basic (000s)			5,627					(S	)			3,090											8,717
Average Common Shares Outstanding — Diluted (000s)			5,644									3,090											8,734
Earning per Common Share
Basic		$	0.46																			$	0.79
Diluted		$	0.46																			$	0.79

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA UNITIL
March 31, 2008
ASSETS
Property, Plant and Equipment:
Electric		$	271.3		$	0.0					$	0.0						$	0.0						$	0.0		$	271.3
Gas			69.2			247.5																							316.7
Common			27.2			0.0																							27.2
Plant Acquisition Adjustment															(M	)			(21.7	)		(G	)			6.6			(15.1	)
Construction Work in Progress			4.9			3.4																							8.3
Property, Plant and Equipment			372.6			250.9						0.0							(21.7	)						6.6			608.4
Less: Accumulated Depreciation			123.2			65.2																							188.4
Net Property, Plant and Equipment			249.4			185.7						0.0							(21.7	)						6.6			420.0
Current Assets:
Cash			4.0			2.1									(A	)			(177.6	)		(H	)			175.5			4.0
Accounts Receivable — Net of Allowance for Doubtful Accounts			28.9			34.4																							63.3
Accrued Revenue			14.0			9.3																							23.3
Exchange Gas Receivable			0.0			8.4																							8.4
Prepayments and Other			3.7			5.6																							9.3
Total Current Assets			50.6			59.8						0.0							(177.6	)						175.5			108.3
Noncurrent Assets:
Regulatory Assets			164.3			20.3		(B	)			(4.9	)																179.7
Other Noncurrent Assets			5.0			80.6		(B	)			(0.5	)		(C	)			(79.9	)		(I	)			0.6			5.8
Total Noncurrent Assets			169.3			100.9						(5.4	)						(79.9	)						0.6			185.5
TOTAL		$	469.3		$	346.4					$	(5.4	)					$	(279.2	)					$	182.7		$	713.8

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS — (Continued)

(millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA UNITIL
March 31, 2008
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock Equity		$	100.0		$	138.6		(B	)		$	(0.3	)		(D	)		$	(138.3	)		(J	)		$	81.2		$	181.2
Preferred Stock			2.1			0.0																							2.1
Long-Term Debt, Less Current Portion			159.6			61.7									(E	)			(61.7	)		(K	)			86.0			245.6
Total Capitalization			261.7			200.3						(0.3	)						(200.0	)						167.2			428.9
Current Liabilities:
Long-Term Debt, Current Portion			0.4			0.8									(E	)			(0.8	)									0.4
Short-Term Debt			16.7			14.7									(E	)			(14.7	)		(L	)			15.5			32.2
Accounts Payable			15.6			14.3																							29.9
Exchange Gas Payable			0.0			8.4																							8.4
Other Current Liabilities			11.9			20.5		(B	)			(1.1	)																31.3
Total Current Liabilities			44.6			58.7						(1.1	)						(15.5	)						15.5			102.2
Deferred Income Taxes			31.9			63.7									(F	)			(63.7	)									31.9
Noncurrent Liabilities:
Power Supply Contract Obligations			67.7			0.0																							67.7
Retirement Benefit Obligations			49.6			4.2		(B	)			(3.7	)																50.1
Environmental Obligations			12.0			1.3																							13.3
Asset Retirement Obligation			0.0			1.4																							1.4
Regulatory Liabilities and Cost of Removal			0.0			16.2		(B	)			(0.3	)																15.9
Other Noncurrent Liabilities			1.8			0.6																							2.4
Total Noncurrent Liabilities			131.1			23.7						(4.0	)						0.0							0.0			150.8
TOTAL		$	469.3		$	346.4					$	(5.4	)					$	(279.2	)					$	182.7		$	713.8

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED STATEMENTS OF EARNINGS

(millions except common shares and per share data)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS														PRO FORMA UNITIL
December 31, 2007
Operating Revenues:
Electric		$	225.0		$	0.0					$	0.0						$	0.0			$	225.0
Gas			34.2			133.3																	167.5
Other			3.7			0.0																	3.7
Total Operating Revenues			262.9			133.3						0.0							0.0				396.2
Operating Expenses:
Purchased Electricity			165.4			0.0																	165.4
Purchased Gas			21.3			85.7																	107.0
Operation and Maintenance			26.2			26.6																	52.8
Conservation & Load Management			3.6			0.0																	3.6
Depreciation and Amortization			17.8			11.0		(N	)			(2.6	)		(O	)			(1.4	)			24.8
Provisions for Taxes:
Local Property and Other			5.6			2.8																	8.4
Federal and State Income			4.5			1.7		(P	)			3.1			(P	)			(2.5	)			6.8
Total Operating Expenses			244.4			127.8						0.5							(3.9	)			368.8
Operating Income			18.5			5.5						(0.5	)						3.9				27.4
Non-Operating Expenses			0.2			0.1																	0.3
Income Before Interest Expense			18.3			5.4						(0.5	)						3.9				27.1
Interest Expense, net			9.6			3.4		(Q	)			(5.1	)		(R	)			7.7				15.6
Net Income			8.7			2.0						4.6							(3.8	)			11.5
Less: Dividends on Preferred Stock			0.1			0.0																	0.1
Net Income Applicable to Common Shareholders		$	8.6		$	2.0					$	4.6						$	(3.8	)		$	11.4
Average Common Shares Outstanding — Basic (000s)			5,659					(S	)			3,090											8,749
Average Common Shares Outstanding — Diluted (000s)			5,672									3,090											8,762
Earning per Common Share
Basic		$	1.52																			$	1.30
Diluted		$	1.52																			$	1.30

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS

(millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA UNITIL
December 31, 2007
ASSETS
Property, Plant and Equipment:
Electric		$	266.2		$	0.0					$	0.0						$	0.0						$	0.0		$	266.2
Gas			67.8			245.1																							312.9
Common			26.2			0.0																							26.2
Plant Acquisition Adjustment			0.0			0.0									(M	)			(21.2	)		(G	)			6.6			(14.6	)
Construction Work in Progress			20.3			4.4																							24.7
Property, Plant and Equipment			380.5			249.5						0.0							(21.2	)						6.6			615.4
Less: Accumulated Depreciation			131.6			63.4																							195.0
Net Property, Plant and Equipment			248.9			186.1						0.0							(21.2	)						6.6			420.4
Current Assets:
Cash			4.6			3.1									(A	)			(197.7	)		(H	)			194.6			4.6
Accounts Receivable — Net of Allowance for Doubtful Accounts			24.9			18.0																							42.9
Accrued Revenue			12.7			14.0																							26.7
Exchange Gas Receivable			0.0			13.4																							13.4
Prepayments and Other			6.7			6.2																							12.9
Total Current Assets			48.9			54.7						0.0							(197.7	)						194.6			100.5
Noncurrent Assets:
Regulatory Assets			170.5			20.4		(B	)			(5.0	)																185.9
Other Noncurrent Assets			6.3			81.0		(B	)			(0.5	)		(C	)			(80.5	)		(I	)			0.6			6.9
Total Noncurrent Assets			176.8			101.4						(5.5	)						(80.5	)						0.6			192.8
TOTAL		$	474.6		$	342.2					$	(5.5	)					$	(299.4	)					$	201.8		$	713.7

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES

UNAUDITED PRO FORMA COMBINED BALANCE SHEETS — (Continued)

(millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA UNITIL
December 31, 2007
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock Equity		$	100.4		$	134.4		(B	)		$	(0.4	)		(D	)		$	(134.0	)		(J	)		$	81.2		$	181.6
Preferred Stock			2.1			0.0																							2.1
Long-Term Debt, Less Current Portion			159.6			61.7									(E	)			(61.7	)		(K	)			86.0			245.6
Total Capitalization			262.1			196.1						(0.4	)						(195.7	)						167.2			429.3
Current Liabilities:
Long-Term Debt, Current Portion			0.4			0.8									(E	)			(0.8	)									0.4
Short-Term Debt			18.8			39.0									(E	)			(39.0	)		(L	)			34.6			53.4
Accounts Payable			17.6			11.1																							28.7
Other Current Liabilities			7.3			7.0		(B	)			(0.5	)																13.8
Total Current Liabilities			44.1			57.9						(0.5	)						(39.8	)						34.6			96.3
Deferred Income Taxes			33.4			63.9									(F	)			(63.9	)									33.4
Noncurrent Liabilities:
Power Supply Contract Obligations			72.7			0.0																							72.7
Retirement Benefit Obligations			48.2			4.7		(B	)			(4.3	)																48.6
Environmental Obligations			12.0			1.8																							13.8
Asset Retirement Obligation			0.0			1.3																							1.3
Regulatory Liabilities and Cost of Removal			0.0			15.9		(B	)			(0.3	)																15.6
Other Noncurrent Liabilities			2.1			0.6																							2.7
Total Noncurrent Liabilities			135.0			24.3						(4.6	)						0.0							0.0			154.7
TOTAL		$	474.6		$	342.2					$	(5.5	)					$	(299.4	)					$	201.8		$	713.7

(The accompanying Notes are an integral part of these unaudited pro forma financial statements.)

 

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UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

MARCH 31, 2008 AND DECEMBER 31, 2007

Note 1 Basis of Presentation

The accompanying unaudited pro forma combined financial statements present how the combined financial statements of Unitil, Northern Utilities and Granite State may have appeared had the businesses actually been combined as of December 31, 2007 and March 31, 2008 (with respect to the balance sheet information using currently available fair value information) or as of January 1, 2007 (with respect to statements of earnings). The unaudited pro forma combined financial statements show the impact of the acquisition of Northern Utilities and Granite State by Unitil on the companies’ respective historical financial position and results of operations under the purchase method of accounting. Under this method of accounting, the assets and liabilities of Northern Utilities and Granite State will be recorded, as of the completion of the acquisition, at their fair values and added to those of Unitil. The unaudited pro forma combined balance sheets as of December 31, 2007 and March 31, 2008 assumes the acquisition was completed on those dates. The unaudited pro forma combined statement of earnings give effect to the acquisition as if it had been completed on January 1, 2007.

The unaudited pro forma combined selected financial data includes adjustments for the acquisition purchase accounting and the replacement of the predecessor owner’s equity and debt amounts with the new equity and debt capitalization proposed by Unitil. The debt and equity adjustments included in the pro forma financial statements reflect the amount necessary to finance the acquisition. The actual amounts of the debt and equity offering sizes may vary. The unaudited pro forma combined selected financial data excludes adjustments to recognize the estimated operating expense savings of $5.6 million annually due to the achievement of efficiencies associated with the provision of shared utility services and the adoption of best practices associated with these shared utility services and also excludes a reduction in operating expenses of $1.2 million related to compliance violation penalties incurred by Northern Utilities in 2007. The unaudited pro forma combined selected financial data also excludes adjustments to recognize the enhancements to revenue of Northern Utilities and Granite State that may occur from the execution of Unitil’s regulatory plan.

Note 2 Method of Accounting for the Acquisition

Unitil intends to account for the acquisition of Northern Utilities and Granite State under the purchase method of accounting for business combinations, in accordance with Financial Accounting Standards Board Statement No. 141, “Business Combinations” (SFAS No. 141). In that process, Unitil will recognize and measure the identifiable assets acquired and the liabilities assumed at fair value. Also, Unitil will measure and recognize any acquisition adjustment related to a purchase premium or bargain relative to the fair values acquired against the purchase price.

Pursuant to SFAS 141, an acquiring entity shall allocate the cost of an acquired entity to the assets acquired and liabilities assumed based on their fair values as of the acquisition date. Accordingly, any difference between the fair value of acquired assets and liabilities (including identifiable intangible assets) and book value represents a purchase premium or bargain.

If the acquisition of Northern Utilities and Granite State is completed subsequent to December 31, 2008, Unitil will account for acquisition in accordance with Financial Accounting Standards Board Statement No. 141 (Revised 2007), “Business Combinations.”

 

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UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

MARCH 31, 2008 AND DECEMBER 31, 2007

 

Note 3 Purchase Price Allocation

The following table represents the preliminary allocation of the total purchase price of Northern Utilities and Granite State to the acquired assets and liabilities of Northern Utilities and Granite State. The preliminary allocation of the total purchase price assumes that the acquisition will be accounted for in accordance with Financial Accounting Standards Board Statement No. 141, “Business Combinations.” If the acquisition is completed subsequent to December 31, 2008, Unitil will account for the acquisition in accordance with Financial Accounting Standards Board Statement No. 141 (Revised 2007), “Business Combinations” and the amounts may change.

The allocation represents the fair values assigned to each of the assets acquired and liabilities assumed. The purchase price allocation is preliminary and is subject to change due to several factors, including, but not limited to: (1) changes in the fair values of Northern Utilities’ and Granite State’s assets and liabilities as of the effective time of the acquisition; (2) the actual transaction costs incurred; and (3) changes in Unitil’s valuation estimates that may be made between now and the time the purchase price allocation is finalized. These changes will not be known until after the closing date of the acquisition.

Additionally, the following allocation for accounting purposes is not determinative for purposes of an election to be made by Unitil and NiSource Inc. pursuant to Section 338(h)(10) of the Internal Revenue Code. Pursuant to Section 5.4(b) of the Stock Purchase Agreement, the purchase price allocation for purposes of such election is subject to consultation and agreement between Unitil and NiSource Inc.

Purchase Price Allocation (millions)

 

		December 31, 2007				March 31, 2008
Equity Purchase Price		$	160.0			$	160.0
Plus: Working Capital Adjustment			37.7				17.6
Asset Purchase Price			197.7				177.6
Plus: Transaction Fees			6.6				6.6
Total Cash Purchase Price			204.3				184.2
Less: Book Value of Net Property Plant and Equipment			(186.1	)			(185.7	)
Less: Current Assets			(54.7	)			(59.8	)
Less: Other Long-term Assets (Excluding Intangibles)			(15.4	)			(15.6	)
Less: Transaction Fees			(6.6	)			(6.6	)
Plus: Accounts Payable			11.1				14.3
Plus: Other Current Liabilities			6.5				27.8
Plus: Non-Current Liabilities (Excluding Deferred Taxes)			19.7				19.7
Bargain Purchase Price — Plant Acquisition Adjustment		$	(21.2	)		$	(21.7	)

 

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UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

MARCH 31, 2008 AND DECEMBER 31, 2007

 

Note 4 Combined Pro Forma Adjustments

 

(A)

To record purchase price and working capital adjustment.

 

(B)

To adjust for pension/PBOP and accrued interest in accordance with the Stock Purchase Agreement.

 

(C)

To eliminate predecessor’s intangible asset.

 

(D)

To eliminate predecessor’s common equity.

 

(E)

To eliminate predecessor’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate predecessor’s deferred taxes.

 

(G)

To record transaction costs.

 

(H)

To record cash received from equity offering and issuance of debt.

 

(I)

To record debt issuance costs.

 

(J)

To record the issuance of new equity less capital stock expense.

 

(K)

To record new long term debt.

 

(L)

To record short term debt raised to replace working capital.

 

(M)

To record plant acquisition adjustment.

 

(N)

To eliminate predecessor’s plant acquisition premium amortization.

 

(O)

To amortize plant acquisition adjustment and transaction costs over 10 years.

 

(P)

To provide for the income tax effect of the pro forma adjustments at statutory rates.

 

(Q)

To eliminate predecessor’s interest expense.

 

(R)

To adjust interest expense due to issuance of new debt.

 

(S)

To adjust outstanding common shares for issuance of new common stock.

 

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NORTHERN UTILITIES, INC.

 

 

UNAUDITED CONDENSED FINANCIAL STATEMENTS AS OF MARCH 31, 2008 AND 2007 AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

 

 

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NORTHERN UTILITIES, INC.

CONDENSED BALANCE SHEETS — UNAUDITED

(in thousands)

 

		As of March 31,
		2008				2007
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
Gas utility plant		$	221,988			$	209,102
Less: accumulated depreciation and amortization			(57,586	)			(52,725	)
Net utility plant			164,402				156,377
Other property, at cost, less accumulated depreciation			1,012				1,148
Construction work in progress			3,236				2,715
Net property, plant and equipment			168,650				160,240
CURRENT ASSETS:
Cash and cash equivalents			2,090				1,179
Restricted cash			—				2,635
Accounts and notes receivable, net of reserve of $1,555 in 2008 and $1,034 in 2007			23,063				24,488
Unbilled revenue, net of reserve of $152 in 2008 and $152 in 2007			9,179				9,096
Receivables from affiliated companies			10,340				3,902
Gas inventory			302				251
Under-recovered gas and fuel costs			—				2,766
Materials and supplies, at average cost			1,485				1,527
Prepaid income taxes			121				2,374
Exchange gas receivable			—				11,140
Regulatory assets			1,072				1,549
Price risk assets			1,917				349
Other current assets			498				430
Total current assets			50,067				61,686
DEFERRED CHARGES:
Regulatory assets			19,843				22,324
Intangible assets, net of amortization			71,809				74,138
Other deferred charges			660				132
Total deferred charges			92,312				96,594
TOTAL ASSETS		$	311,029			$	318,520

The accompanying notes to condensed financial statements are an integral part of these unaudited statements.

 

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NORTHERN UTILITIES, INC.

CONDENSED BALANCE SHEETS — UNAUDITED — (Continued)

(in thousands)

 

		As of March 31,
		2008			2007
CAPITALIZATION AND LIABILITIES
COMMON STOCKHOLDER’S EQUITY
Common Stock — $10 par value		$	1		$	1
Additional paid in capital			109,175			109,175
Retained earnings			16,387			14,022
Total common stock equity			125,563			123,198
LONG-TERM DEBT TO PARENT COMPANY			60,000			60,000
LONG-TERM UNAFFILIATED DEBT			1,667			2,500
Total capitalization			187,230			185,698
CURRENT LIABILITIES:
Current maturities of long-term debt			833			833
Short-term debt — affiliated			6,979			26,843
Payable to affiliated companies			2,573			3,302
Accounts payable			11,205			7,432
Accrued taxes			3,267			2,285
Price risk liabilities			—			—
Deferred income taxes			1,920			4,005
Regulatory liabilities			3,976			2,117
Customer deposits			1,562			1,397
Other current liabilities			11,598			4,137
Total current liabilities			43,913			52,351
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred income taxes			56,429			54,585
Deferred investment tax credits			135			159
Postretirement benefits other than pensions			3,365			5,572
Asset retirement obligations			1,250			1,350
Regulatory liabilities and other removal costs			16,246			14,951
Environmental accruals			1,339			1,198
Pensions			493			1,868
Other			629			788
Total other liabilities and deferred credits			79,886			80,471
TOTAL CAPITALIZATION AND LIABILITIES		$	311,029		$	318,520

The accompanying notes to condensed financial statements are an integral part of these unaudited statements.

 

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NORTHERN UTILITIES, INC.

CONDENSED STATEMENTS OF INCOME — UNAUDITED

(in thousands)

 

		For the Three Months Ended March 31,
		2008				2007
NET REVENUES
Gas distribution		$	53,491			$	60,302
Cost of sales (excludes depreciation and amortization)			36,258				42,980
Total net revenues			17,233				17,322
OPERATING EXPENSES:
Operations and maintenance			6,345				7,098
Depreciation and amortization			2,754				2,490
Taxes other than income			683				611
Total operating expenses			9,782				10,199
OPERATING INCOME			7,451				7,123
OTHER INCOME (DEDUCTIONS):
Interest expense, net			(782	)			(739	)
Other, net			(19	)			(17	)
Total other income (deductions)			(801	)			(756	)
INCOME BEFORE TAX			6,650				6,367
INCOME TAX			2,722				2,615
NET INCOME		$	3,928			$	3,752

The accompanying notes to condensed financial statements are an integral part of these unaudited statements.

 

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NORTHERN UTILITIES, INC.

CONDENSED STATEMENTS OF CASH FLOWS — UNAUDITED

(in thousands)

 

		For the Three Months Ended March 31,
		2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	3,928			$	3,752
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			2,754				2,490
Deferred income taxes and investment tax credits			(125	)			502
Changes in assets and liabilities:
Accounts receivable and unbilled revenue			(6,231	)			(14,893	)
Accounts payable			3,535				(2,584	)
Accrued taxes			2,886				2,182
Regulatory assets/liabilities			762				1,218
Pension and other postretirement benefits			(599	)			(649	)
Exchange gas payable/receivable			13,378				15,280
Overrecovered gas and fuel costs			2,904				6,107
Other — net			1,617				1,510
Net cash provided by operating activities			24,809				14,915
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(1,671	)			(2,828	)
Restricted cash			1,655				1,570
Net cash used in investing activities			(16	)			(1,258	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt — unaffiliated			—				—
Short-term debt — affiliated			(24,079	)			(12,668	)
Dividends paid			—				—
Net cash used in financing activities			(24,079	)			(12,668	)
NET INCREASE IN CASH AND CASH EQUIVALENTS			714				989
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			1,376				190
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	2,090			$	1,179
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid for interest			397.3				645.3
Interest capitalized			6.0				15.2
Cash paid for taxes			—				—

The accompanying notes to condensed financial statements are an integral part of these unaudited statements.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

Note 1 Basis of Accounting Presentation

The accompanying unaudited condensed financial statements for Northern Utilities, Inc. (“Northern Utilities” or the “Company”) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with generally accepted accounting principles in the United States of America.

The accompanying unaudited condensed financial statements should be read in conjunction with the financial statements and notes included in the Northern Utilities audited financial statements for the fiscal year ended December 31, 2007. Income for the interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The accompanying unaudited condensed financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to those rules and regulations, although the Company believes that the disclosures made are adequate to make the information not misleading.

Note 2 Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not change the requirements to apply fair value in existing accounting standards.

Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability.

To increase consistency and comparability in fair value measurements, SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The level in the fair value hierarchy disclosed is based on the lowest level of input that is significant to the fair value measurement. The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

 

Ÿ

Level 1 inputs are quoted prices (unadjusted) in active markets for identical asset or liabilities that the company has the ability to access as of the reporting date.

 

Ÿ

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly through corroboration with observable market data.

Ÿ

Level 3 inputs are unobservable inputs, such as internally developed pricing models for the asset or liability due to little or no market activity for the asset or liability.

SFAS No. 157 became effective for Northern Utilities as of January 1, 2008. The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on the following three items, which are

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

required to be recorded as an adjustment to the opening balance of retained earnings in the year of adoption: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF Issue No. 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts. The adoption of SFAS No. 157 did not have an impact on the January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

In February 2008, the FASB issued FSP FAS 157-2, which delays the effective date of SFAS No. 157 for all nonrecurring fair value measurements of non-financial assets and liabilities until fiscal years beginning after November 15, 2008. Northern Utilities has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities.

See Note 6, “Derivatives and Hedging—Price Risk Management” for additional information regarding SFAS No. 157.

SFAS No. 158 — Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158). In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Northern Utilities adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 decreased “Other Current Assets” by $0.1 million, increased “Regulatory Assets” by $8.2 million, and decreased “Other Current Liabilities” by $0.3 million. “Pensions and Postretirement Benefits Other than Pensions” were increased by $8.4 million. With the adoption of SFAS No. 158 Northern Utilities determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Northern Utilities recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Northern Utilities adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $0.8 million, a decrease in “Pensions and Postretirement Benefits Other than Pensions” of $0.4 million, and a decrease to “Retained Earnings” of $0.4 million. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

See Note 7 “Accounting for Pensions” and Note 8 “Accounting for Other Postemployment Benefits (OPEB)” for additional information regarding SFAS No. 158.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment would be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Northern Utilities has chosen not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

FSP FIN 39-1 — FASB Staff Position Amendment of FASB Interpretation No. 39. In April 2007, the FASB posted FSP FIN 39-1 to amend paragraph 3 of FIN 39 to replace the terms conditional contracts and exchange contracts with the term derivative instruments as defined in SFAS No. 133. This FSP also amends paragraph 10 of FIN 39 to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This FSP became effective for Northern Utilities as of January 1, 2008. Northern Utilities has not elected to net fair value amounts for its derivative instruments or the fair value amounts recognized for its right to receive cash collateral or obligation to pay cash collateral arising from those derivative instruments recognized at fair value, which are executed with the same counterparty under a master netting arrangement. This is consistent with Northern Utilities current accounting policy prior to the adoption of this amended standard. Northern Utilities discloses amounts recognized for the right to reclaim cash collateral within “Restricted cash” and amounts recognized for the right to return cash collateral within current liabilities on the Balance Sheets.

FIN 48 — Accounting for Uncertainty in Income Taxes. In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006.

On January 1, 2007, Northern Utilities adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the implementation of FIN 48.

Recently Issued Accounting Pronouncements

SFAS No. 161 — Disclosures about Derivative Instruments and Hedging — an amendment of SFAS No. 133. In March 2008, the FASB issued SFAS No. 161 to amend and expand the disclosure requirements of SFAS No. 133 with the intent to provide users of the financial statement with an enhanced understanding of how and why an entity uses derivative instruments, how these derivatives are accounted for and how the respective reporting entity’s financial statements are affected. This Statement is effective for fiscal years and interim periods beginning after November 15, 2008, and earlier application is encouraged. The Company is currently reviewing the provisions of SFAS No. 161 to determine the impact it may have on its disclosures within the Notes to Condensed Financial Statements.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

SFAS No. 141R — Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including the recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. The Company is currently reviewing the provisions of SFAS. No. 141R to determine the impact on future business combinations.

Note 3 Intangible Assets

At March 31, 2008, the Company has $71.8 million of intangible assets consisting of franchise rights that were identified as part of the purchase price allocations associated with its acquisition by NiSource. The intangible asset balance at March 31, 2007 was $74.1 million. The gross intangible asset of $92.7 million is being amortized over a forty-year period commencing February 1999, the date of acquisition by NiSource. The reserve balance is $20.9 million and $18.6 million at March 31, 2008 and March 31, 2007, respectively.

The Company assesses the carrying amount and potential earnings of this intangible asset whenever events or changes in circumstances indicate that the carrying value could be impaired as per SFAS No. 144. When an asset’s carrying value exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered to be impaired to the extent that the asset’s fair value is less than its carrying value.

Amortization expense for three months ended March 31, 2008 and March 31, 2007 was $0.6 million and $0.6 million, respectively.

Note 4 Asset Retirement Obligations

The Company has accounted for retirement obligations on its assets using Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). This accounting standard and the related interpretation require entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted and the capitalized cost is depreciated over the useful life of the related asset. The Company defers the difference between the amount recognized for depreciation and accretion and the amount collected in rates, as required pursuant to SFAS No. 71, for those amounts it has collected in rates or expects to collect in future rates. The asset retirement obligations liability totaled $1.3 million and $1.3 million at March 31, 2008 and 2007, respectively. The changes in the asset retirement obligation for the three months ended March 31, 2008 and 2007 are presented in the table below (in whole dollars):

 

		Three Months Ended March 31,
		2008			2007
Beginning balance		$	1,229,242		$	1,328,309
Accretion			20,851			21,428
Ending balance		$	1,250,093		$	1,349,737

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

Note 5 Income Taxes

The Company’s interim effective tax rates reflect the estimated annual effective tax rate for 2008 and 2007, respectively, adjusted for tax expense associated with certain discrete items. The effective tax rates for the quarter ended March 31, 2008 and March 31, 2007 were 40.93% and 41.06%, respectively. The effective tax rates differ from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, and other permanent book-to-tax differences.

Note 6 Derivatives and Hedging — Price Risk Management

Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as subsequently amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149, collectively referred to as SFAS No. 133, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value, unless such contracts designated by the Company as normal under the provisions of the standard.

Under SFAS No. 133, as amended, the accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. Unrealized and realized gains and losses are recognized each period as components of other comprehensive income, earnings, or regulatory assets and liabilities depending on the nature of such derivatives.

The Company has a regulatory approved hedging program designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases NYMEX futures that correspond to the associated delivery month. Any gains or losses on the fair value of these derivatives are passed through to the ratepayer directly through a regulatory commission approved recovery mechanism. As a result of the ratemaking process, the Company records gains and losses as regulatory liabilities or assets and recognizes such gains or losses in cost of sales when recovered in revenues.

The Company considers the price risk management assets and liabilities as Level 2 inputs as described in SFAS No. 157. As such, the values are measured using the gas futures exchange rates.

The accompanying balance sheets include a price risk management asset related to net unrealized gains on current futures contracts of $1.9 million and $0.3 million at March 31, 2008 and March 31, 2007, respectively. Additionally, the balance sheet includes price risk management assets related to net unrealized gains on non-current futures contracts of $0.1 million and $0.1 million at March 31, 2008 and March 31, 2007, respectively.

Note 7 Accounting for Pensions

The Company provides pension benefits to employees with at least 5 years of service. There are three types of pension plans: (1) union employee plan, (2) non-union employee plan and (3) Supplemental Executive Retirement Plan (SERP). The first two plans are noncontributory, qualified pension plans and the third is a nonqualified pension plan that provides benefits to some employees in excess of the qualified plan’s Federal tax limits.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

The Company’s pension plans are part of the parent company pension plan (Bay State Gas Company). The pension balance sheet accounts and ongoing expense amounts reflect the Company’s allocation of the total pension plan activity that includes the other operating companies included in the plan, namely Bay State Gas Company and Gas Power Energy (GPE).

The Company’s pension expense was approximately $65 thousand for three months ended March 31, 2008. Pension expense was a credit of approximately $22 thousand for the three months ended March 31, 2007.

The Company has not made any contributions to the Pension trust in 2008.

On January 1, 2007, the Company adopted the SFAS No. 158 measurement date provisions requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The pre-tax impact of adopting SFAS No. 158 measurement date provisions for pensions decreased regulatory assets by $0.6 million, decreased retained earnings by $0.2 million, and decreased accrued liabilities for post-employment benefits by $0.4 million. The Company also recorded a reduction in deferred income taxes of approximately $0.1 million. In addition, 2007 expense for pension benefits reflects the updated measurement date valuations.

Note 8 Accounting for Other Postemployment Benefits (OPEB)

The Company provides medical and life insurance benefits to retirees. The Company, as part of Bay State Gas Company, has contributed to an OPEB trust fund specifically created for post-employment benefits.

The Company’s OPEB expense was approximately $0.1 million and $0.2 million for three months ended March 31, 2008 and 2007, respectively.

Contributions of approximately $0.7 million were made in the first quarter of 2008. No contributions were made in the first quarter of 2007.

On January 1, 2007, the Company adopted the SFAS No. 158 measurement date provisions requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The pre-tax impact of adopting SFAS No. 158 measurement date provisions for other post retirement benefits decreased regulatory assets by $0.2 million and decreased retained earnings by $0.2 million. In addition, 2007 expense for other postretirement benefits reflects the updated measurement date valuations.

Note 9 Regulatory Matters

On February 15, 2008, NiSource (parent company of Bay State Gas Company which is parent company of Northern Utilities) reached a definitive agreement under which Unitil Corporation (“Unitil”) will acquire NiSource subsidiaries Northern Utilities and Granite State Gas Transmission, Inc. (“Granite State”) for $160 million plus net working capital at the time of closing. Historically, net working capital has averaged approximately $25 million. Under the terms of the transaction, Unitil will acquire Northern Utilities, a local gas distribution company serving 52 thousand customers in 44 communities in Maine and New Hampshire and Granite State, an 86-mile FERC regulated gas transmission pipeline primarily located in Maine and New Hampshire. The transaction, expected to be complete by the end of 2008, is subject to

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

regulatory approvals. NiSource recorded an after tax loss of approximately $48.8 million related to the pending sale of Northern Utilities.

Maine Public Utilities Commission Docket Nos. 2007-362, 363 & 364: Docket Nos. 2008-095, 96, 97 & 098; and, Docket Nos. 2008-118 & 122. In October 2007, the Maine Public Utilities Commission (“Maine Commission”) initiated a formal investigation into three Notices of Probable Violation (“NOPVs”) (Docket Nos. 2007-362, 363 & 364) alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations, as adopted by the Maine Commission. Specifically, the NOPVs alleged that (1) Northern Utilities had failed to update its Operation and Maintenance Plan within the time periods required by the state regulations; (2) Northern Utilities had allowed persons to perform certain operation and maintenance tasks without being properly qualified to do so under Northern Utilities’ Operator Qualification plan; (3) Northern Utilities lacked the necessary documentation concerning the maximum allowable operating pressures of certain distribution piping systems; (4) Northern Utilities had allowed one of Northern Utilities’ systems to operate above the maximum allowable operating pressure following an upstream regulator failure; and (5) Northern Utilities had failed to properly design one of Northern Utilities’ regulator stations.

Both Northern Utilities and the Maine Commission Staff have filed written testimony, and Northern Utilities has responded to extensive discovery requests.

In February and March 2008, the Maine Commission issued NOPVs with accompanying investigations related to documentation required for Northern Utilities’ triennial inspection (Docket No. 2008-118) and Northern Utilities’ qualification of certain affiliate employees that did work in the past on Northern Utilities’ behalf (Docket No. 2008-122).

In April 2008, the Maine Commission initiated an investigation into an incident from which an NOPV was issued although the cause was not determined conclusively to be natural gas (Docket No. 2008-95, claiming Northern Utilities failed to complete its investigation of the failure), and into an over pressurization following an upstream regulator failure (Docket No. 2008-96, alleging the same).

In June 2008, the Maine Commission initiated a formal investigation into two NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations with respect to two separate gas leaks that occurred at two separate residences each in October of 2007.

The formal evidentiary hearings have been postponed, pending settlement discussions with the Maine Commission’s Prosecutorial Staff, which are currently underway. The Maine Commission’s Prosecutorial Staff has indicated that it believes a fine of approximately $5.9 million, to be advanced at hearing, is appropriate; Northern Utilities vigorously disputes the proposal as flatly inconsistent with reasoned enforcement actions and the criteria governing the discretionary assessment of civil penalties.

As of March 31, 2008, Northern Utilities has recorded an appropriate liability for this matter, and, based upon its analysis of the issues, any penalties imposed in this proceeding should approximate the liability. At this time, however, Northern Utilities cannot predict whether it will be able to reach a settlement with the Maine Commission Prosecutorial Staff, or the amounts of any monetary penalties that may ultimately be imposed.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the State of New Hampshire’s Public Utilities

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

Commission (“New Hampshire Commission”) issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the New Hampshire Commission noted that lost and unaccounted for gas (“UAFG”) in the 2007-2008 winter cost of gas forecast is approximately 1 percent of firm sales, compared to a reported 7.59 percent UAFG for the 12-month period ending April 2007. The New Hampshire Commission recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that period, the cause of any misreporting and a solution. The New Hampshire Commission ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of its investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra Energy (“Spectra”) at the Maritimes & Northeast (“M&NE”) / Portland Natural Gas Transmission System’s (“PNGTS”) Newington Gate Station in Newington, New Hampshire (“Newington Gate Station”) caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought from the New Hampshire Commission and obtained an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct Northern Utilities’ UAFG levels and associated cost impacts.

On February 15, 2008, Northern Utilities filed its report with the New Hampshire Commission. Northern Utilities reported that it was working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005. As a result of these efforts, Northern Utilities received confirmation from Spectra on January 28, 2008, that Granite State was erroneously billed for an additional 758,709 Dth of natural gas between May 2005 and December 2007. As the primary transportation customer of Granite State at the Newington station, and due to the service arrangements under which Northern Utilities receives service from Granite State, the total amount of the error was passed through to Northern Utilities. Northern Utilities calculates that it was overcharged by approximately $5.7 million for gas purchases directly related to this meter error based on gas prices in effect at the time of the error. This overcharge in turn was passed on to Northern Utilities customers through the normal operation of the gas cost recovery mechanism.

Although Northern Utilities anticipates it will have a refund liability for the overcharges, the timing and extent is not clear. The New Hampshire Commission has not yet suggested that Northern Utilities would be liable for refunds in the absence of its receipt of a recovery from a third party. Under the traditional application of the gas cost recovery rules, Northern Utilities would flow through any refund received from a third party. As of June 2008, Northern Utilities has recorded approximately $10.3 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.

Northern Utilities has been informed by Spectra that resolution of the issue and any cash-out or refund that needs to be made to Granite State and/or Northern Utilities, requires the involvement of PNGTS. Although PNGTS has agreed to repay the lost gas to Granite State over an 18 month period, final documents memorializing the payback have not been completed. Northern Utilities has agreed to inform the New Hampshire Commission at 120-day intervals until an acceptable resolution is reached.

 

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NORTHERN UTILITIES, INC.

 

 

FINANCIAL STATEMENTS AS OF DECEMBER 31, 2007 AND 2006 and FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

TOGETHER WITH INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S REPORT

 

 

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INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S REPORT

Northern Utilities, Inc.

We have audited the accompanying balance sheets of Northern Utilities, Inc. (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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 the 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.

As explained in Notes 4 and 5 to the financial statements, in the fourth quarter of 2006, the Company adopted the provisions of Financial Accounting Standards Board (FASB) Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” requiring employers to recognize in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, and effective January 1, 2007, the Company adopted the measurement date provisions of FASB Statement No. 158.

/s/ Deloitte & Touche LLP

Columbus, Ohio

May 15, 2008

 

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NORTHERN UTILITIES, INC.

BALANCE SHEETS

(in thousands)

 

		As of December 31,
		2007				2006
ASSETS
Property, Plant and Equipment:
Gas utility plant		$	219,464			$	205,682
Less: accumulated depreciation and amortization			(55,969	)			(51,422	)
Net utility plant			163,495				154,260
Other property, at cost, less accumulated depreciation			1,037				1,191
Construction work in progress			4,286				3,490
Net property, plant and equipment			168,818				158,941
Current Assets:
Cash and cash equivalents			1,376				190
Restricted cash			1,655				4,205
Accounts and notes receivable, net of reserve of $852 and $762, respectively			15,995				12,273
Unbilled revenue, net of reserve of $152 and $145, respectively			10,160				8,764
Receivables from affiliated companies			1,067				1,714
Gas inventory			1,379				1,628
Under-recovered gas and fuel costs			3,725				6,786
Materials and supplies, at average cost			1,401				1,482
Prepaid income taxes			121				2,375
Exchange gas receivable			13,378				26,420
Regulatory assets			2,493				4,997
Other current assets			463				525
Total current assets			53,213				71,359
Deferred Charges:
Regulatory assets			19,943				22,707
Intangible assets, net of amortization			72,391				74,721
Other deferred charges			519				3
Total deferred charges			92,853				97,431
Total Assets		$	314,884			$	327,731

The accompanying notes to financial statements are an integral part of these statements.

 

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Table of Contents

NORTHERN UTILITIES, INC.

BALANCE SHEETS — (Continued)

(in thousands)

 

		As of December 31,
		2007			2006
CAPITALIZATION AND LIABILITIES
Common Stock Equity:
Common stock — $10 par value		$	1		$	1
Additional paid in capital			109,175			109,175
Retained earnings			12,459			10,458
Total common stock equity			121,635			119,634
Long-Term Debt to Parent Company			60,000			60,000
Long-Term Unaffiliated Debt			1,667			2,500
Total capitalization			183,302			182,134
Current Liabilities:
Current maturities of long term debt			833			833
Short term debt — affiliated			31,058			39,511
Payables to affiliated companies			2,391			5,037
Accounts payable			7,879			8,281
Accrued taxes			380			103
Price risk management liabilities			584			2,735
Deferred income taxes			1,920			3,352
Regulatory liabilities			1,922			286
Customer deposits			1,586			1,363
Other current liabilities			2,437			2,256
Total current liabilities			50,990			63,757
Other Liabilities and Deferred Credits:
Deferred income taxes			56,589			54,881
Deferred investment tax credits			141			166
Postretirement benefits other than pensions			3,974			5,596
Asset retirement obligations			1,229			1,328
Regulatory liabilities and other removal costs			15,797			14,462
Environmental accruals			1,765			2,268
Pensions			468			2,349
Other			629			790
Total other liabilities and deferred credits			80,592			81,840
Total Capitalization And Liabilities		$	314,884		$	327,731

The accompanying notes to financial statements are an integral part of these statements.

 

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NORTHERN UTILITIES, INC.

STATEMENTS OF INCOME

(in thousands)

 

		For the Years Ended December 31,
		2007				2006				2005
Net Revenues:
Gas Distribution		$	129,862			$	118,606			$	127,687
Cost of sales (excludes depreciation and amortization)			85,680				80,234				87,513
Total net revenues			44,182				38,372				40,174
Operating Expenses:
Operations and maintenance			24,716				21,359				20,213
Depreciation and amortization			10,193				9,710				9,512
Taxes other than income			2,528				2,625				2,837
Total operating expenses			37,437				33,694				32,562
Operating Income			6,745				4,678				7,612
Other Income (Deductions):
Interest expense, net			(2,821	)			(2,494	)			(2,528	)
Other, net			(8	)			(118	)			97
Total other income (deductions)			(2,829	)			(2,612	)			(2,431	)
Income Before Tax			3,916				2,066				5,181
Income Tax			1,727				775				2,170
Net Income		$	2,189			$	1,291			$	3,011

The accompanying notes to financial statements are an integral part of these statements.

 

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NORTHERN UTILITIES, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS’

EQUITY AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

(in thousands)

 

		Shares Out-Standing (***)		Par Value ($10)			Additional Paid-in Capital			Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total				Comprehensive Income
BALANCE AT DECEMBER 31, 2004		100		$	1		$	109,138		$	10,156			$	(1,360	)		$	117,935
Net Income											3,011								3,011			$	3,011
Unrecognized Pension Benefit costs															(102	)			(102	)			(102	)
Total comprehensive income																						$	2,909
Tax benefit allocation								27											27
Dividend											(4,000	)							(4,000	)
BALANCE AT DECEMBER 31, 2005		100		$	1		$	109,165		$	9,167			$	(1,462	)		$	116,871
Net Income											1,291								1,291			$	1,291
Unrecognized Pension Benefit costs															1,462				1,462				1,462
Total comprehensive income																						$	2,753
Tax benefit allocation								10											10
BALANCE AT DECEMBER 31, 2006		100		$	1		$	109,175		$	10,458			$	—			$	119,634
Net Income											2,189								2,189			$	2,189
Total comprehensive income																						$	2,189
Adoption of SFAS 158 measurement date provisions											(188	)							(188	)
BALANCE AT DECEMBER 31, 2007		100		$	1		$	109,175		$	12,459			$	—			$	121,635

 

***

200 shares authorized and issued

The accompanying notes to financial statements are an integral part of these statements.

 

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NORTHERN UTILITIES, INC.

STATEMENTS OF CASH FLOWS

(in thousands)

 

		For the Years Ended December 31,
		2007			2006			2005
Cash Flows from Operating Activities:
Net income		2,189			1,291			3,011
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		10,193			9,710			9,512
Deferred income taxes and investment tax credits		426			910			1,398
Changes in assets and liabilities:
Accounts receivable and unbilled revenue		(3,570	)		7,135			(7,788	)
Accounts payable		(2,711	)		(3,636	)		6,317
Accrued taxes		2,531			(1,898	)		(360	)
Regulatory assets/liabilities		2,891			(1,737	)		(3,452	)
Pension and other postretirement benefits		(4,075	)		498			583
Exchange gas payable/receivable		13,042			622			(6,669	)
(Under) overrecovered gas and fuel costs		3,061			(1,759	)		(375	)
Other — net		667			(143	)		(869	)
Net cash provided by operating activities		24,644			10,993			1,308
Cash Flows from Investing Activities:
Capital expenditures — utility plant		(16,722	)		(15,828	)		(12,990	)
Restricted cash		2,550			(4,205	)		1,043
Net cash used in investing activities		(14,172	)		(20,033	)		(11,947	)

The accompanying notes to financial statements are an integral part of these statements.

 

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NORTHERN UTILITIES, INC.

STATEMENTS OF CASH FLOWS — (Continued)

FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006 AND 2005

(in thousands)

 

		For the Years Ended December 31,
		2007				2006				2005
Cash Flows from Financing Activities:
Retirement of long-term debt — unaffiliated			(833	)			(833	)			(833	)
Short term debt — affiliated			(8,453	)			9,442				15,762
Dividends paid			—				—				(4,000	)
Net cash (used in) provided by financing activities			(9,286	)			8,609				10,929
Net Increase (Decrease) in Cash and Cash Equivalents			1,186				(431	)			290
Cash and Cash Equivalents at Beginning of Year			190				621				331
Cash and Cash Equivalents at End of Year		$	1,376			$	190			$	621
Supplemental Disclosure:
Cash Paid during year for interest		$	4,397			$	4,292			$	3,444
Income taxes paid (refunded)		$	(1,154	)		$	1,612			$	1,228
Allowance for funds used during construction — debt		$	97			$	75			$	52

The accompanying notes to financial statements are an integral part of these statements.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2007, 2006 AND 2005

Note 1 Business Organization and Operations

Northern Utilities, Inc. (“Northern Utilities” or the “Company”) is a wholly owned subsidiary of Bay State Gas Company (“Bay State”). Bay State is a wholly owned subsidiary of NiSource Inc. (“NiSource”).

Northern Utilities provides regulated natural gas distribution services to approximately 50,000 customers in 44 communities located in Maine and New Hampshire.

Note 2 Summary of Significant Accounting Policies

Basis of Accounting

The Company follows the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), which provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

Information regarding assets and liabilities subject to utility regulation and rate determination is as follows (in whole $):

 

		2007			2006
At December 31,
ASSETS:
Unrecognized pension benefit and other post retirement benefit costs (SFAS No. 158)		$	6,322,475		$	8,264,946
Debt redemption premium			230,372			269,084
Price risk management			584,030			2,741,920
FAS 109 taxes			3,379,639			3,098,170
Environmental costs			11,792,946			12,449,004
Under-recovered purchased gas costs			3,724,967			6,786,137
Other			126,915			881,202
Total			26,161,344			34,490,463
Current			6,218,113			11,783,199
Long-Term		$	19,943,231		$	22,707,264
LIABILITIES:
Over-collection — demand side management costs		$	566,711		$	171,965
Price risk management			21,220			—
Cost of removal			15,315,569			14,348,563
OPEB medicare subsidy			362,932			—
Regulatory liability FAS 109 taxes			96,801			113,553
Service Quality & other penalties			1,232,750			1,500
Other			122,512			112,920
Total			17,718,495			14,748,501
Current			1,921,973			286,385
Long-Term		$	15,796,522		$	14,462,116

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Regulatory assets of approximately $26.0 million are not presently included in the rate base and consequently are not earning a return at December 31, 2007. These regulatory assets are being recovered through cost of service over a remaining life of up to 30 years. Regulatory assets of approximately $0.2 million require specific rate action. All regulatory assets are probable of recovery. Regulatory assets of approximately $34.4 million were not included in the rate base and were not earning a return at December 31, 2006. Regulatory assets of approximately $0.1 million required specific rate action at December 31, 2006.

Intangible Assets

At December 31, 2007, the Company had $72.4 million of intangible assets consisting of franchise rights that were identified as part of the purchase price allocations associated with its acquisition by NiSource. The intangible asset balance at December 31, 2006 was $74.7 million. The gross intangible asset of $92.7 million is being amortized over a forty-year period commencing February 1999, the date of acquisition by NiSource. The reserve balance is $20.3 million and $18.0 million at December 31, 2007 and 2006, respectively.

The Company assesses the carrying amount and potential earnings of this intangible asset whenever events or changes in circumstances indicate that the carrying value could be impaired as per SFAS No. 144. When an asset’s carrying value exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered to be impaired to the extent that the asset’s fair value is less than its carrying value.

Amortization expense for the Company in 2007, 2006 and 2005 was approximately $2.3 million. The estimated amortization expense for 2008 through 2012 is approximately $2.3 million annually.

Utility Plant and Other Property and Related Depreciation

Property, plant and equipment (principally utility plant) are stated at original cost. Improvements and replacements of retirement units are capitalized at cost. When units of property are retired, the accumulated provision for depreciation is charged with the cost of the units and the cost of removal, net of salvage. Maintenance, repairs and minor replacements of property are charged to expense.

The Company provides for annual depreciation on a composite, straight-line basis. The annual depreciation rate for the Company was approximately 3.40% for 2007, 3.41% for 2006 and 3.47% for 2005.

An allowance for funds used during construction (AFUDC) is capitalized on all classes of property except organization, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is completed and placed in service, reducing gross interest expense during the respective construction period. AFUDC rates are based on the NiSource short term borrowing rates. The pre-tax rate for AFUDC was 5.69% in 2007, 5.11% in 2006 and 2.77% in 2005.

The recoverability of utility plant and other property is evaluated by an analysis of operating results and consideration of other significant events or changes in the operating environment.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Gas Inventory

Gas inventory is carried at weighted average cost.

Accounting for Exchange Gas

The Company has an exchange gas agreement whereby natural gas purchases during the months of April through October are delivered to a third party. The third party delivers back to the Company during the following months of November through March. The exchange volumes are carried at weighted average cost.

Under — recovered Gas and Fuel Costs

The Company defers differences between gas purchase costs and the recovery of such costs included in revenues to Under-recovered Gas and Fuel Costs on the balance sheet, and adjusts future billings for such deferrals on a basis consistent with applicable tariff provisions.

Revenue Recognition

The Company bills customers on a monthly cycle billing basis. Revenues are recorded on the accrual basis including an estimate for gas delivered and customer charges earned but unbilled at the end of each accounting period. Cash received in advance from sales of gas to be delivered in the future is deferred and recognized as income upon delivery of the commodity.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Income Taxes and Investment Tax Credits

The Company records income taxes to recognize full inter-period tax allocation. Under the liability method of income tax accounting, deferred income taxes are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates, applicable to future years, to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

Previously recorded investment tax credits were deferred and are being amortized over the life of the related properties to conform to regulatory policy.

Pursuant to the Internal Revenue Code and relevant state taxing authorities, NiSource files consolidated income tax returns for federal and certain state jurisdictions. The Company is a party to an agreement (Tax Allocation Agreement) that provides for the allocation of consolidated tax liabilities. The Tax Allocation Agreement generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to the other members.

In 2007, no tax savings were allocated to the Company. Tax savings of less than $0.1 million were allocated to the Company in 2006 and 2005, respectively. These amounts were recorded in equity.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

The total effective tax rate on income before tax differs from the Federal statutory rate (35%) as follows (in whole $):

 

		2007				2006				2005
Book income before tax		$	3,916,359			$	2,065,611			$	5,180,757
Expected tax expense			1,370,726				722,964				1,813,265
Reconciling items:
State taxes			148,504				10,757				193,675
Deferred investment tax credit			(24,444	)			(24,444	)			(24,444	)
Permanent differences			271,931				549				(238	)
Regulatory: excess/deficient taxes			106,680				106,680				106,680
Tax accrual adjustments			(146,313	)			(41,784	)			81,098
Other			—				(43	)			(130	)
Total income tax expense		$	1,727,084			$	774,679			$	2,169,906

Federal and state income taxes, as set forth in the Statement of Income, are comprised of the following (in whole $):

 

		2007				2006				2005
Current:
Federal		$	1,075,081			$	(44,566	)		$	646,510
State			225,657				(90,641	)			125,613
			1,300,738				(135,207	)			772,123
Deferred:
Federal			447,981				827,139				1,249,878
State			2,809				107,191				172,349
			450,790				934,330				1,422,227
Investment tax credits			(24,444	)			(24,444	)			(24,444	)
Total income tax expense		$	1,727,084			$	774,679			$	2,169,906

The components of deferred tax assets and deferred tax liabilities at December 31 are as follows (in whole $):

 

		2007			2006
Deferred tax liabilities:
Plant acquisition/merger		$	29,115,931		$	30,052,636
Other property related			21,137,124			20,089,663
Environmental			3,930,965			3,550,591
Regulatory liability tax			2,605,204			2,136,375
Various other items			2,166,103			2,730,385
Total deferred tax liabilities			58,955,327			58,559,650
Deferred tax asset:			446,713			326,079
Less deferred income taxes related to current assets and liabilities			1,919,905			3,352,456
Non-current deferred tax liability		$	56,588,709		$	54,881,115

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

To the extent certain deferred income taxes of the Company are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets for income taxes are primarily attributable to income tax timing differences for which deferred taxes had not been provided in the past, because regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities are primarily attributable to unamortized deferred investment tax credits and the federal Medicare subsidy for providers of healthcare benefits for retirees. It is probable that these liabilities will be passed back to customers.

Because NiSource is part of the IRS’s Large and Mid-Size Business program, each year’s federal income tax return is typically audited by the IRS. The audit of tax years 2005 and 2006 is expected to commence in 2008.

The statute of limitations in each of the state jurisdictions in which NiSource operates remain open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. There are no state income tax audits currently in progress.

Environmental Expenditures

The Company accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated, regardless of when expenditures are made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and, when possible, site-specific costs. The accrued liability is adjusted as further information is developed or circumstances change. The Company establishes a regulatory asset on the balance sheet to the extent that future recovery of environmental remediation cost is probable through the regulatory process.

The Company had current and non-current accrued liabilities totaling $2.1 million and $3.7 million, as of December 31, 2007 and 2006, respectively. These liabilities reflect estimated expenditures for six former Manufactured Gas Plant (MGP) sites, of which three sites are in Maine and three sites are in New Hampshire, as of December 31, 2007 and 2006.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. In addition, the Company has amounts deposited in trust to satisfy requirements for its hedging program, which is classified as restricted cash and disclosed as an investing cash flow on the Statements of Cash Flows.

Derivatives and Hedging — (Price Risk Management)

Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as subsequently amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149, collectively referred to as SFAS No. 133, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS No. 133 requires an entity to recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value, unless such contracts designated by the Company as normal under the provisions of the standard.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Under SFAS No. 133, as amended, the accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. Unrealized and realized gains and losses are recognized each period as components of other comprehensive income, earnings, or regulatory assets and liabilities depending on the nature of such derivatives.

The Company has a regulatory approved hedging program designed to fix a portion of its gas supply costs for the coming year of service. In order to fix these costs, the Company purchases NYMEX futures that correspond to the associated delivery month. Any gains or losses on the fair value of these derivatives are passed through to the ratepayer directly through a regulatory commission approved recovery mechanism. As a result of the ratemaking process, the Company records gains and losses as regulatory liabilities or assets and recognizes such gains or losses in cost of sales when recovered in revenues.

The accompanying balance sheet includes price risk management liabilities related to net unrealized losses on current futures contracts of $584,030 and $2,735,270 at December 31, 2007 and 2006, respectively. Additionally, the balance sheet includes a price risk management asset of $21,220 related to net unrealized gains on non-current futures contracts at December 31, 2007 and a price risk management liability of $6,650 related to net unrealized losses on non-current futures contracts at December 31, 2006.

Asset Retirement Obligations

The Company has accounted for retirement obligations on its assets using Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). In the fourth quarter 2005, the Company adopted the provisions of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), which broadened the scope of SFAS No. 143 to include contingent asset retirement obligations and also provided additional guidance for the measurement of the asset retirement obligations. The impact of adopting FIN 47 was an increase in Gas Utility Plant in Service of $0.9 million, an increase in Asset Retirement Obligation liabilities of $1.4 million, decrease in Regulatory Liabilities of $0.5 million, increase in Regulatory Assets of $0.1 million and an increase to Accumulated Depreciation of $0.1 million. This accounting standard and the related interpretation require entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted and the capitalized cost is depreciated over the useful life of the related asset. The Company defers the difference between the amount recognized for depreciation and accretion and the amount collected in rates, as required pursuant to SFAS No. 71, for those amounts it has collected in rates or expects to collect in future rates. The asset retirement obligations liability totaled $1.2 million and $1.3 million at December 31, 2007 and December 31, 2006, respectively. The changes in the asset retirement obligation for the years 2007 and 2006 are presented in the table below (in whole $):

 

		2007				2006
Beginning Balance		$	1,328,309			$	1,358,673
Additions			—				10,190
Revisions			(42,342	)			—
Settlements			(94,012	)			(94,510	)
Accretion			37,287				53,956
Ending Balance		$	1,229,242			$	1,328,309

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Recent Accounting Standards

FIN 48 — Accounting for Uncertainty in Income Taxes. In June 2006, the Financial Accounting Standards Board (FASB) issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The determination of whether a tax position meets the more-likely-than-not recognition threshold is based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. On January 1, 2007, the Company adopted the provisions of FIN 48. As a result of the implementation of FIN 48, the Company was not required to record any liability for unrecognized tax benefits. The Company has no uncertain tax position as of December 31, 2007.

SFAS No. 157 — Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions. SFAS No. 157 became effective for the Company as of January 1, 2008. The adoption of this standard did not have an impact on the Company’s January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

In February 2008, the FASB issued FSP FAS 157-2, which delays the effective date of SFAS No. 157 until fiscal years beginning after November 15, 2008. The Company has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. The Company has chosen not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

Note 3 Financial Instruments

Short-Term Financial Instruments.

As cash and cash equivalents, current receivables, current payables, and certain other short-term financial instruments are all short-term in nature, their carrying amount approximates fair value.

Long-Term Debt.

The Company has a $60 million note payable to NiSource Inc. due in June 2013. The fair value of this note was $53.0 million and $52.1 million at December 31, 2007 and 2006, respectively.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

The Company has a 6.93% note totaling $2.5 million and $3.3 million as of December 31, 2007 and 2006, respectively, with maturity payments due every September through maturity in 2010. The fair value of this note was $2.6 million and $3.5 million at December 31, 2007 and 2006, respectively.

Note 4 Accounting for Pensions

The Company provides pension benefits to employees with at least 5 years of service. There are three types of pension plans: (1) union employee plan, (2) non-union employee plan and (3) Supplemental Executive Retirement Plan (SERP). The first two plans are noncontributory, qualified pension plans and the third is a nonqualified pension plan that provides benefits to some employees in excess of the qualified plan’s Federal tax limits.

The Company’s pension plans are part of the parent company pension plan (Bay State Gas Company). The pension balance sheet accounts and ongoing expense amounts reflect the Company’s allocation of the total pension plan activity that includes the other operating companies included in the plan, namely Bay State Gas Company and Gas Power Energy (GPE).

Pension expense for the Company in 2007 was approximately $0.3 million. The pension expense was approximately $0.4 million and $0.6 million for 2006 and 2005, respectfully.

The Company made contributions to the Pension trust in 2007 of approximately $1.6 million. No contributions to the Pension trust were made in 2006 and 2005.

In the fourth quarter of 2006, the Company adopted the provisions of Statement of Financial Accounting Standard No. 158 requiring employers to recognize in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the defined benefit pension plan assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 related to pensions increased regulatory assets by $4.1 million and increased other deferred credits by $4.1 million.

On January 1, 2007, the Company adopted the SFAS No. 158 measurement date provisions requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The pre-tax impact of adopting SFAS No. 158 measurement date provisions for pensions decreased regulatory assets by $0.6 million, decreased retained earnings by $0.2 million, and decreased accrued liabilities for post-employment benefits by $0.4 million. The Company also recorded a reduction in deferred income taxes of approximately $0.1 million. In addition 2007 expense for pension benefits reflects the updated measurement date valuations.

Note 5 Accounting for Other Post Employment Benefits (OPEB)

 

The Company provides medical and life insurance benefits to retirees. The Company, as a subsidiary of Bay State Gas Company, has contributed to an OPEB trust fund specifically created for post-employment benefits.

OPEB expense for the Company in 2007 was approximately $0.5 million. The OPEB expense was approximately $1.0 million and $0.5 million for 2006 and 2005, respectfully.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

The Company made contributions to the OPEB trust in 2007 of approximately $1.6 million. No contributions to the OPEB trust were made in 2006 and 2005.

In the fourth quarter of 2006, the Company adopted the provisions of SFAS No. 158 (see Accounting for Pensions). Based on the measurement of plan assets and benefit obligations at September 30, 2006 for defined benefit post-employment plans other than pensions, the pretax impact of adopting SFAS No. 158 decreased prepayments by $0.1 million, increased regulatory assets by $4.1 million, decreased current and accrued liabilities by $0.3 million, and increased other deferred credits by $4.3 million.

On January 1, 2007, the Company adopted the SFAS No. 158 measurement date provisions requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The pre-tax impact of adopting SFAS No. 158 measurement date provisions for other post retirement benefits decreased regulatory assets by $0.2 million, decreased retained earnings by $0.2 million, and minimally decreased accrued liabilities for post-employment benefits. The Company also recorded a reduction in deferred income taxes of approximately $0.1 million. In addition, 2007 expense for other postretirement benefits reflects the updated measurement date valuations.

Note 6 Leases

The Company’s lease activity is primarily related to vehicles and equipment. At December 31, 2007, 2006 and 2005, the Company had lease agreements for 120, 110 and 91 units, respectively. Total rental payments were $515,878, $515,874 and $479,772 for 2007, 2006 and 2005, respectively, and are treated as operating leases.

The amount of future rental payments required under the non-cancellable operating leases is as follows (in whole $):

 

2008		$	361,015
2009			359,765
2010			283,331
2011			216,635
2012			164,774
Thereafter			35,531
Total		$	1,421,051

Note 7 Transactions with Affiliates

Approximately 2% and approximately 6% of the Company’s gas purchases for 2007 and 2006, respectively, were from an affiliate, Granite State Gas Transmission, Inc. (“Granite State”), that acquired gas from Canadian sources. The total affiliated gas purchase expense for 2007 and 2006 was $1.4 million and $5.0 million, respectively. Approximately 6% of the 2005 gas purchases, totaling $5.3 million, were from Granite State.

The Company’s operating expenses include a management fee for services provided by Bay State Gas Company amounting to $2.8 million in 2007, $2.7 million in 2006 and $2.7 million in 2005.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

The Company’s operating expenses also include a management fee for services provided by NiSource Corporate Services amounting to $5.8 million, $5.4 million and $5.7 million in 2007, 2006 and 2005, respectively.

The Company has payables to associated companies as of December 31, 2007 primarily related to short term debt of approximately $31.1 million, management fees and other general services from Bay State Gas Company of approximately $1.1 million, management fees from NiSource Corporate Services of approximately $0.6 million and other affiliated payables of approximately $0.6 million.

The Company has payables to associated companies as of December 31, 2006 primarily related to short term debt of approximately $39.5 million, gas purchase costs from Granite State of approximately $2.4 million, management fees and other general services from Bay State Gas Company of approximately $1.2 million, management fees from NiSource Corporate Services of approximately $0.5 million and other affiliated payables of approximately $0.9 million.

The Company has receivables from associated companies as of December 31, 2007 primarily related to a reallocation of OPEB liabilities from NiSource of approximately $0.5 million, management fees and other general services to Bay State Gas Company of approximately $0.5 million and other affiliated receivables of approximately $0.1 million.

The Company has receivables from associated companies as of December 31, 2006 primarily related to management fees and other general services to Bay State Gas Company of approximately $1.7 million.

The total affiliated interest expense was approximately $4.1 million, $4.1 million and $3.2 million in 2007, 2006 and 2005, respectively.

Note 8 Short-Term Debt

The Company participates in the NiSource Money Pool arrangement. This arrangement provides the Company with internal financing for seasonal working capital requirements. While the current capital markets have been adversely impacted by a variety of negative economic indicators, the Company believes that it will not impact its continued access to traditional capital markets.

At December 31, 2007 and 2006, the Company had outstanding short-term debt of $31.1 million and $39.5 million, respectively.

Note 9 Long-Term Debt

The Company’s outstanding long-term debt matures at various dates through 2013.

Long-term debt is as follows (in whole $):

 

Interest rate and final installment date		2007
6.93% due September 2010 — nonaffiliated		$	2,500,000
4.80% due June 2013 — affiliated			60,000,000
Total outstanding debt			62,500,000
Less: current maturities of long term debt			(833,333	)
Total non-current debt		$	61,666,667

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

The scheduled maturities of long-term debt at December 31, 2007 are as follows (in whole $):

 

2008		$	833,333
2009			833,333
2010			833,334
2011			—
2012			—
2013			60,000,000
Total		$	62,500,000

Note 10 Commitments and Contingencies

Capital Expenditures

Capital expenditures for 2008 are currently estimated at $17.9 million. Funds for such expenditures will be provided from funds available at the beginning of the year, cash generated from operations, and other sources as may be required.

Legal Matters

In the normal course of its business, the Company has been named as defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material adverse impact on the Company’s financial position or results of operations.

Regulatory Matters

On February 15, 2008, NiSource reached a definitive agreement under which Unitil Corporation (“Unitil”) will acquire NiSource subsidiaries Northern Utilities and Granite State for $160 million plus net working capital at the time of closing. Historically, net working capital has averaged approximately $25 million. Under the terms of the transaction, Unitil will acquire Northern Utilities, a local gas distribution company serving 52 thousand customers in 44 communities in Maine and New Hampshire and Granite State, an 86-mile FERC regulated gas transmission pipeline primarily located in Maine and New Hampshire. The transaction, expected to be complete by the end of 2008, is subject to regulatory approvals. NiSource recorded an after tax loss of approximately $48.8 million related to the pending sale of Northern Utilities in 2008.

The Maine Commission has approved a stipulation for the Company to accelerate the replacement of its cast iron distribution piping located in the towns of Lewiston and Auburn between April 1, 2005 and December 1, 2008. The Maine Commission’s order approving the stipulation also provides the Company with the opportunity to propose a mechanism to recover the costs associated with the incremental rate base additions as part of its next base rate case.

In 2005, the Maine Commission and the New Hampshire Commission concluded parallel investigations into the allocation between Northern Utilities’ Maine and New Hampshire Divisions of pipeline and underground storage capacity and supply demand-related costs by approving a Settlement Agreement. The Settlement Agreement resolves all claims that have been or may be asserted related to past, present and future allocation, recovery and reconciliation of capacity-related costs and revenues between the

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Company’s Maine and New Hampshire Divisions for any period prior to November 1, 2005. In Maine Commission Docket Nos. 2005-87 and 2005-273, the Settling Parties agreed to address, as part of a future Integrated Resource Plan (IRP) filing, the Maine Commission Staff’s concerns regarding the reasonableness of recovering certain contracts designed to replace gas supplies that were going to be provided via the Wells LNG facility but are now being provided by the Maritimes/PNGTS Joint Facilities (Wells Replacement Contracts).

On October 27, 2006, the Company received an Order from the New Hampshire Commission in Docket No. DG 06-129 regarding the Company’s Cost of Gas (COG) and Local Distribution Adjustment Clause (LDAC) rates. In that Order, the Commission directed the Company, Office of Consumer Advocate, and Commission Staff to investigate whether carrying costs on the monthly balance of under/over gas cost collections that are recovered through the COG mechanism could result in over-collecting carrying costs on purchased gas costs through the combination of the interest calculation and the recovery of gas supply cost working capital expense.

On October 12, 2007, the MPUC opened an investigation (Investigation into Northern Utilities, Inc.’s Safety Operations and Practices, Docket No. 2007-529) in which it ordered an independent management audit pursuant to 35-A M.R.S.A. § 113 to examine the Company’s gas safety operations and practices. The audit is underway and is expected to conclude during 2008.

On December 7, 2006, the Company received a Notice of Probable Violation (NOPV) from the Director of Technical Analysis of the MPUC alleging violations of three sections of the federal gas safety regulations.

The Company has also received NOPVs from the Director of the Technical Analysis Division of the MPUC related to various alleged operating and record keeping deficiencies. The Company is opposing the allegations.

The Company is currently negotiating with the MPUC Staff regarding the imposition of a penalty for failure to read a number of meters within a twelve month period. A $0.4 million accrued liability for this penalty has been established in 2007.

During an investigation of unusually high unaccounted for gas in the Company’s New Hampshire Division, the Company discovered an apparent metering error by Spectra Energy at the Maritimes & Northeast/Portland Natural Gas Transmission System’s Newington Gate Station in Newington, New Hampshire. The Company is actively engaged in discussions with Spectra and the upstream supplying pipelines to determine the magnitude of the billing error and the method for providing an appropriate refund to the Company’s customers.

 

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NORTHERN UTILITIES, INC.

NOTES TO FINANCIAL STATEMENTS — (Continued)

DECEMBER 31, 2007, 2006 AND 2005

 

Note 11 Long-Term Gas Purchases

The Company has entered into long-term purchase obligations for gas purchases, transportation and storage agreements. Certain gas purchase obligations meet the definition of a derivative under the provisions of SFAS No. 133, Accounting for Derivatives, as amended. The Company has elected to treat such contracts as normal purchases under the provisions of SFAS 133. As a result, the fair values of such contracts are not reported on the balance sheets at December 31, 2007 and 2006. The obligations to the Company under these contracts as of December 31, 2007 are as follows:

 

		Annual Demand Quantities (MDth)		Annual Demand Costs ($ millions)			Annual Commodity Quantities (MDth)		Annual Commodity Costs ($ millions)
2008
Gas transportation		48.3		$	22.1		0.0		$	0.0
Storage		4.7			4.2		0.0			0.0
Gas purchases		1.8			3.8		1.2			9.8
Total		54.8			30.1		1.2			9.8
2009
Gas transportation		47.4			21.7		0.0			0.0
Storage		3.7			3.0		0.0			0.0
Gas purchases		2.0			4.1		0.0			0.0
Total		53.1			28.8		0.0			0.0
2010
Gas transportation		46.8			21.6		0.0			0.0
Storage		3.7			3.0		0.0			0.0
Gas purchases		2.0			4.3		0.0			0.0
Total		52.5			28.9		0.0			0.0
2011
Gas transportation		46.6			21.6		0.0			0.0
Storage		3.7			3.0		0.0			0.0
Gas purchases		1.6			3.5		0.0			0.0
Total		51.9			28.1		0.0			0.0
2012
Gas transportation		45.1			21.4		0.0			0.0
Storage		3.7			2.9		0.0			0.0
Gas purchases		0.0			0.0		0.0			0.0
Total		48.8			24.3		0.0			0.0
Thereafter
Gas transportation		156.3			95.1		0.0			0.0
Storage		12.8			9.4		0.0			0.0
Gas purchases		0.0			0.0		0.0			0.0
Total		169.1			104.5		0.0			0.0
Total all agreements		430.2		$	244.7		1.2		$	9.8

 

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GRANITE STATE GAS TRANSMISSION, INC.

 

 

UNAUDITED CONDENSED FINANCIAL STATEMENTS

AS OF MARCH 31, 2008 AND 2007 AND FOR THE THREE MONTHS ENDED

MARCH 31, 2008 AND 2007

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED BALANCE SHEETS

AS OF MARCH 31, 2008 AND MARCH 31, 2007

 

		Unaudited
		2008				2007
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
Utility plant		$	23,939,835			$	22,961,713
Less: accumulated depreciation and amortization			(7,599,439	)			(7,315,272	)
Net utility plant			16,340,396				15,646,441
Other property			600,000				600,000
Construction work in progress			159,009				51
Net property, plant and equipment			17,099,405				16,246,492
CURRENT ASSETS:
Cash and cash equivalents			38,074				54,502
Accounts and notes receivable, net of reserve of $4,200 in 2008 and $10,000 in 2007			63,878				88,736
Receivables from affiliated companies			931,074				544,980
Exchange gas receivable			8,427,997				—
Regulatory assets			55,467				57,294
Prepayments			18,382				10,738
Prepayments — affiliated			5,414				6,082
Taxes receivable			120,576				42,519
Taxes receivable from affiliated companies			97,443				5,055,357
Total current assets			9,758,305				5,860,208
DEFERRED CHARGES:
Regulatory assets			470,694				584,232
Intangible assets, net of amortization			8,062,359				8,324,549
Other deferred charges			53,996				—
Total deferred charges			8,587,049				8,908,781
TOTAL ASSETS		$	35,444,759			$	31,015,481

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED BALANCE SHEETS — (Continued)

AS OF MARCH 31, 2008 AND MARCH 31, 2007

 

		Unaudited
		2008				2007
STOCKHOLDERS’ EQUITY AND LIABILITIES
COMMON STOCKHOLDERS’ EQUITY
Common Stock		$	29,900			$	29,900
Other paid in capital			26,494,541				26,494,541
Accumulated deficit			(13,557,593	)			(13,377,635	)
Total stockholders’ equity			12,966,848				13,146,806
CURRENT LIABILITIES:
Payables to affiliated companies			111,436				1,065,178
Exchange gas payable — affiliated			8,427,997				—
Short term borrowings from affiliated companies			7,714,646				10,030,037
Accounts payable			401,284				302,465
Interest accrued			—				3,892
Customer deposits			9,894				9,894
Other current liabilities			90,401				59,535
Total current liabilities			16,755,658				11,471,001
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred income taxes			5,235,920				5,765,249
Deferred investment tax credits			12,663				13,983
Asset retirement obligations			129,458				122,261
Regulatory liabilities			29,646				—
Pensions and other postretirement benefits			314,566				496,181
Total other liabilities and deferred credits			5,722,253				6,397,674
COMMITMENTS AND CONTINGENCIES			—				—
TOTAL STOCKHOLDERS’ EQUITY AND LIABILITIES		$	35,444,759			$	31,015,481

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED STATEMENTS OF INCOME

FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

		Unaudited
		2008				2007
NET REVENUES
Net gas transportation revenues			146,458				167,208
Net affiliated revenues			824,848				807,169
Total net revenues			971,306				974,377
OPERATING EXPENSES:
Operations and maintenance			226,339				192,181
Operations and maintenance — affiliated			121,462				167,905
Depreciation and amortization			227,750				203,552
Accretion Expense			1,362				1,852
Taxes other than income			77,070				70,301
Total operating expenses			653,983				635,791
OPERATING INCOME			317,323				338,586
OTHER INCOME (DEDUCTIONS):
Interest income and other, net			5,529				73,958
Interest expense — affiliated			(84,316	)			(144,862	)
Total other income (deductions)			(78,787	)			(70,904	)
INCOME BEFORE TAX			238,536				267,682
INCOME TAX			94,934				114,188
NET INCOME		$	143,602			$	153,494

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED STATEMENTS OF CASH FLOWS

FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

		Unaudited
		2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	143,602			$	153,494
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			227,750				203,552
Deferred income taxes and investment tax credits			26,115				96,952
Accretion expense			1,362				1,852
Changes in assets and liabilities:
Accounts receivable			(58,740	)			1,872,491
Accounts payable and accrued expenses			(236,835	)			(3,632,876	)
Regulatory assets/liabilities			8,011				(101,406	)
Pension and other postretirement benefits			1,775				121,000
Taxes receivable			62,451				(54,648	)
Other — net			(2,433	)			8,640
Net cash provided by (used in) operating activities			173,058				(1,330,949	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(47,882	)			(200,991	)
Net cash used in investing activities			(47,882	)			(200,991	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Changes in Affiliated Borrowings (Short-term debt)			(153,061	)			1,559,925
Net Cash (used in) provided by financing activities			(153,061	)			1,559,925
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(27,885	)			27,985
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			65,959				26,517
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	38,074			$	54,502
SUPPLEMENTAL DISCLOSURE INFORMATION:
Cash paid during year for interest		$	95,483			$	134,390
Income taxes (refunded) paid		$	—			$	—
Capital expenditures included in accounts payable		$	25,410			$	192,717

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

Note 1 Nature of Operations and Basis of Accounting

Basis of accounting presentation

The accompanying unaudited condensed financial statements for Granite State Gas Transmission, Inc. (“Granite” or the “Company”) reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with generally accepted accounting principles in the United States of America.

The accompanying unaudited condensed financial statements should be read in conjunction with the financial statements and notes included in the Granite’s audited financial statements for the fiscal year ended December 31, 2007. Income for the interim periods may not be indicative of results for the calendar year due to weather variations and other factors.

The accompanying unaudited condensed financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in the annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to those rules and regulations, although Granite believes that the disclosures made are adequate to make the information not misleading.

Note 2 Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions. The adoption of SFAS No. 157 did not have an impact on Granite’s January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities —  Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Granite has chosen not to elect to measure any applicable financial assets or liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

SFAS No. 158 — Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158). In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Granite adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting SFAS No. 158 increased “Prepayments” by $2,437, increased “Regulatory Assets” by $628,963, and decreased “Other Current Liabilities” by $19,057. “Pension and Postretirement Benefits” were increased by $650,457. With the adoption of SFAS No. 158 Granite determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Granite recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Granite adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $127,074, an increase to “Other Deferred Charges” of $53,996, an increase in “Pension and Postretirement Benefits” of $35,619, a decrease to “Retained Earnings” of $18,573, a decrease to “Accounts and Notes Receivable” of $7,061, an increase to “Accounts Receivable from Affiliated Companies” of $99,072, and an increase to “Accounts Payable to Affiliated Companies” of $1,887. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

FIN 48 — Accounting for Uncertainty in Income Taxes (FIN 48). In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. When determining whether a tax position meets the more-likely-than-not recognition threshold, it is to be based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

On January 1, 2007, Granite adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the adoption of FIN 48.

Recently Issued Accounting Pronouncements

SFAS No. 141R — Business Combinations. In December 2007, the FASB issued SFAS No. 141R to improve the relevance, representational faithfulness, and comparability of information that a reporting entity provides in its financial reports regarding business combinations and its effects, including recognition of assets and liabilities, the measurement of goodwill and required disclosures. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 and earlier adoption is prohibited. Granite is currently reviewing the provisions of SFAS No. 141R to determine the impact on future business combinations.

Note 3 Asset Retirement Obligations

Granite accounts for retirement obligations on its assets in accordance with SFAS No. 143, “Accounting for Asset Retirements Obligations.” This accounting standard and the related interpretation requires entities to record the fair value of a liability for an asset retirement obligation in the period in which

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Granite defers the difference between the amount recognized for depreciation and accretion and the amount collected in rates as required pursuant to SFAS No. 71 for those amounts it has collected in rates or expects to collect in future rates. Currently, the deferred amount for this difference is zero.

Granite has recognized asset retirement obligations associated with various obligations including, certain costs to retire pipeline, and removal of certain pipelines known to contain polychlorinated biphenyl contamination as well as some other nominal asset retirement obligations. The asset retirement obligation totaled $129,458 at March 31, 2008 and $122,261 at March 31, 2007. For the first quarter 2008 and 2007 Granite recognized accretion expense of $1,362 and $1,852, respectively

Note 4 Income Taxes

Total income taxes were different from the amount that would be computed by applying the statutory Federal income tax rate to book income before income tax. The major reasons for this difference were as follows:

 

		Three Months Ended March 31, 2008				Three Months Ended March 31, 2007
Book income before income taxes		$	238,536			$	267,682
Tax expense at statutory Federal income tax rate		$	83,488			$	93,689
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit			11,776				14,159
Deferred investment tax credit			(330	)			(330	)
Amortization of regulatory asset FAS-109			—				7,068
Other			—				(398	)
Income Tax Expense		$	94,934			$	114,188

There was no impact to the opening balance of retained earning as a result of the adoption of FIN 48 and there are no uncertain tax positions as of March 31, 2008. As of March 31, 2007 and prior to the adoption of FIN 48, Granite had an uncertain tax position of $276,968. Granite settled the uncertain tax position with the IRS in second quarter 2007.

Note 5 Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover its employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for Granite. The expected cost of such benefits is accrued during the employees’ years of service. Granite’s current rates include postretirement benefit costs on an accrual basis, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. Cash contributions are remitted to grantor trusts. As of December 31, 2007, Granite uses December 31 as its measurement date for its pension and postretirement benefit plans, in accordance with SFAS No. 158.

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

Pension expense for Granite, as allocated by NiSource, was $1,463 and $1,703 for first quarter 2008 and 2007, respectively. Postretirement benefits expense for Granite was $8,323 and $17,891 for first quarter 2008 and 2007, respectively. These allocations were based on expenses, net of assets returns, as actuarially determined for employees associated with Granite. Granite made cash contributions to the pension plan totaling zero and zero for first quarter 2008 and 2007, respectively. Cash contributions to the post retirement plan were zero, and zero for first quarter 2008 and 2007, respectively.

Note 6 Short-Term Borrowings

Granite satisfies its liquidity requirements primarily through internally generated funds and through intercompany borrowings from the NiSource Money Pool. As of March 31, 2008, Granite had short-term NiSource Money Pool borrowings of $7,714,646 at an interest rate of 3.55 percent. As of March 31, 2007, Granite had $10,030,037 of NiSource Money Pool borrowings at an interest rate of 5.77 percent.

Note 7 Affiliated Company Transactions

Granite receives executive, financial, and administrative and general services from an affiliate, NiSource Corporate Services. The costs of these services are charged to Granite based on payroll costs and expenses incurred by NiSource Corporate Services employees for the benefit of Granite. These costs which totaled $77,915 and $94,544 for first quarter 2008 and 2007, respectively, consist primarily of employee compensation and benefits and are recorded within, “Operation Expenses” on the Statements of Income. Granite also incurred expenses from an affiliate, Columbia Gas Transmission Corporation, for various routine administrative activities totaling $34,619 and $64,435 during first quarter 2008 and 2007, respectively. Granite incurred office rental expense of $8,927 from affiliate, Northern Utilities, Inc. (“Northern Utilities”), for both first quarter 2008 and 2007.

Granite recorded gas transportation revenues from affiliates of $824,848 and $807,169 for first quarter 2008 and 2007, respectively.

The March 31, 2008 and 2007 accounts receivable balance includes $931,074 and $544,980 respectively, due from associated companies.

The March 31, 2008 and 2007 accounts payable balance reflects $111,436 and $1,065,178, respectively, due to associated companies, separate from the NiSource Money Pool.

The March 31, 2008 and 2007 exchange gas payable balance reflects $8,427,997 and zero, respectively, due to associated companies.

The March 31, 2008 and 2007 Taxes receivable balance includes $97,443 and $5,055,357, respectively, of federal and state income taxes that are receivable from to NiSource in accordance with its tax-sharing agreement.

Note 8 Intangible Assets

Intangible assets includes $10,487,621 related to the allocation of the purchase price resulting from NiSource’s purchase of the individual units of Bay State Gas Company. Granite was part of Bay State Gas Company at the time of this purchase. The amount is being amortized to operating expense over a forty-year period, and is not currently a component of Granite’s rates. Granite’s Balance Sheet contains intangible

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

assets discussed above which are not subject to recovery under SFAS No. 71. As a result, Granite assesses the carrying amount and potential earnings of these assets whenever events or changes in circumstances indicate that the carrying value could be impaired as per SFAS No. 144.

Amortization expense for the Company in first quarter 2008 and 2007 was approximately $65,548. The estimated amortization expense for 2008 through 2012 is approximately $262,191 annually. The balance of Granite’s intangible assets, net of amortization, as of March 31, 2008 was $8,062,359 and was $8,324,549 as of March 31, 2007.

Note 9 Regulatory Matters

Sale of Granite

On February 15, 2008, NiSource reached a definitive agreement under which Unitil Corporation (“Unitil”) will acquire Northern Utilities and Granite for $160 million plus net working capital at the time of closing. Historically, net working capital has averaged approximately $25 million. Under the terms of the transaction, Unitil will acquire Northern Utilities, a local gas distribution company serving 52 thousand customers in 44 communities in Maine and New Hampshire and Granite, an 86-mile FERC regulated gas transmission pipeline primarily located in Maine and New Hampshire. The transaction, expected to be completed by the end of 2008, is subject to federal and state regulatory approvals.

NiSource recorded an after tax loss of $14,730,425 related to the pending sale of Granite.

New Hampshire Public Utilities Commission Docket Nos. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas

On October 31, 2007, the New Hampshire Commission issued Order DG 07-102 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the New Hampshire Commission noted that lost and UAFG in the 2007-2008 winter cost of gas forecast is approximately 1% of firm sales, compared to a reported 7.59% UAFG for the 12-month period ending April 2007. The New Hampshire Commission recognized that Northern Utilities had previously opened an internal investigation to determine the actual UAFG for that period, the cause of any misreporting, and a solution. The New Hampshire Commission ordered Northern Utilities to file a detailed report by December 31, 2007 regarding the results of its investigation into UAFG as reported in its 2006-2007 winter cost of gas reconciliation filing.

In early December 2007, Northern Utilities identified what appears to be the single largest contributing cause of its New Hampshire Division’s unusually high reported UAFG levels. The apparent cause appeared to be incorrect metering by Spectra at the M&NE / PNGTS Newington Gate Station caused by an erroneous meter module change on May 25, 2005. Because of the recent discovery of this cause, Northern Utilities sought from the New Hampshire Commission and obtained an extension until February 15, 2008 to file the requested report showing accurate volumetric adjustments to correct Northern Utilities’ UAFG levels and associated cost impacts.

On February 15, 2008, Northern Utilities filed its report with the New Hampshire Commission. Northern Utilities reported that it was working with Granite State and Spectra to determine the exact volume of gas that was over-recorded as a result of Spectra erroneously updating its Newington Gate Station meter module in May 2005. As a result of these efforts, Northern Utilities received confirmation from Spectra on

 

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GRANITE STATE GAS TRANSMISSION, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE THREE MONTHS ENDED MARCH 31, 2008 AND 2007

 

January 28, 2008, that Granite State was erroneously billed for an additional 758,709 Dth of natural gas between May 2005 and December 2007. As the primary transportation customer of Granite State at the Newington Gate Station, and due to the service arrangements under which Northern Utilities receives service from Granite State, the total amount of the error was passed through to Northern Utilities. Northern Utilities calculates that it was overcharged by approximately $5.7 million for gas purchases directly related to this meter error based on gas prices in effect at the time of the error.

As of June 2008, Granite State has recorded approximately $10.3 million reflecting the anticipated liability of the future refund amount to Northern Utilities based on current market prices.

Northern Utilities has been informed by Spectra that resolution of the issue and any cash-out or refund that needs to be made to Granite State and/or Northern Utilities requires the involvement of PNGTS. PNGTS has agreed to repay the lost gas to Granite State over an 18-month period, but final documents memorializing the payback have not been completed. Northern Utilities has agreed to inform the New Hampshire Commission at 120-day intervals until an acceptable resolution is reached.

 

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GRANITE STATE GAS TRANSMISSION, INC.

 

 

FINANCIAL STATEMENTS AS OF DECEMBER 31, 2007 AND 2006 AND FOR

THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

TOGETHER WITH INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S REPORT

 

 

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INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM’S REPORT

Granite State Gas Transmission

We have audited the accompanying balance sheets of Granite State Gas Transmission (the “Company”) as of December 31, 2007 and 2006, and the related statements of (loss) income, changes in stockholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing 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 include 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 Granite State Gas Transmission as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the 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.

As explained in Note 2 to the financial statements, in the fourth quarter of 2006, the Company adopted the provisions of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” requiring employers to recognize in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, and effective January 1, 2007, the Company adopted the measurement date provisions of FASB Statement No. 158.

/s/ Deloitte & Touche LLP

Columbus, Ohio

May 27, 2008

 

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GRANITE STATE GAS TRANSMISSION, INC.

BALANCE SHEETS

AS OF DECEMBER 31, 2007 AND 2006

 

		2007				2006
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
Utility plant		$	23,968,179			$	23,195,931
Less: accumulated depreciation and amortization			(7,438,548	)			(7,177,269	)
Net utility plant			16,529,631				16,018,662
Other property			600,000				600,000
Construction work in progress			118,901				—
Net property, plant and equipment			17,248,532				16,618,662
CURRENT ASSETS:
Cash and cash equivalents			65,959				26,517
Accounts and notes receivable, net of reserve of $4,200 in 2007 and $10,000 in 2006			547,360				119,215
Receivables from affiliated companies			388,853				2,391,984
Regulatory assets			55,467				57,294
Prepayments			11,701				13,295
Prepayments — affiliated			9,662				12,164
Taxes receivable			36,957				40,310
Taxes receivable from affiliated companies			243,513				5,002,918
Total current assets			1,359,472				7,663,697
DEFERRED CHARGES:
Regulatory assets			478,705				662,819
Intangible assets, net of amortization			8,127,906				8,390,097
Other deferred charges			53,995				—
Total deferred charges			8,660,606				9,052,916
TOTAL ASSETS		$	27,268,610			$	33,335,275

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

BALANCE SHEETS — (Continued)

AS OF DECEMBER 31, 2007 AND 2006

 

		2007				2006
CAPITALIZATION AND LIABILITIES
COMMON STOCKHOLDERS’ EQUITY
Common Stock		$	29,900			$	29,900
Other paid in capital			26,494,541				26,494,541
Retained earnings			(13,701,195	)			(13,519,973	)
Total capitalization			12,823,246				13,004,468
CURRENT LIABILITIES:
Payables to affiliated companies			745,793				5,281,722
Short term borrowings from affiliated companies			7,867,706				8,470,112
Accounts payable			55,971				174,332
Interest accrued			—				3,677
Customer deposits			9,894				9,894
Other current liabilities			72,999				36,169
Total current liabilities			8,752,363				13,975,906
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred income taxes			5,209,475				5,689,165
Deferred investment tax credits			12,993				14,313
Asset retirement obligations			128,096				120,409
Regulatory liabilities			29,646				—
Pensions and other postretirement benefits			312,791				531,014
Total other liabilities and deferred credits			5,693,001				6,354,901
COMMITMENTS AND CONTINGENCIES			—				—
TOTAL CAPITALIZATION AND LIABILITIES		$	27,268,610			$	33,335,275

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

STATEMENTS OF (LOSS) INCOME

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

 

		2007				2006				2005
NET REVENUES
Net gas transportation revenues			512,106				456,363				484,760
Net affiliated revenues			2,851,768				3,706,319				3,982,134
Total net revenues			3,363,874				4,162,682				4,466,894
OPERATING EXPENSES:
Operations and maintenance			1,198,193				2,152,171				1,763,079
Operations and maintenance — affiliated			658,546				685,789				868,232
Depreciation and amortization			841,559				784,431				702,499
Accretion Expense			7,687				7,226				—
Taxes other than income			292,398				252,998				215,361
Total operating expenses			2,998,383				3,882,615				3,549,171
OPERATING INCOME			365,491				280,067				917,723
OTHER INCOME (DEDUCTIONS):
Interest income and other, net			—				371,586				228,547
Interest expense — affiliated			(554,559	)			(456,951	)			(188,793	)
Total other income (deductions)			(554,559	)			(85,365	)			39,754
(LOSS) INCOME BEFORE TAX			(189,068	)			194,702				957,477
INCOME TAX			(19,002	)			103,454				438,208
NET (LOSS) INCOME		$	(170,066	)		$	91,248			$	519,269

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

 

		Common Stock Shares Issued and Outstanding ***		Par Value $1			Additional Paid in Capital			Accumulated Deficit				Accumulated Other Comprehensive Income (Loss)				Total				Comprehensive Income (Loss)
BALANCE AT DECEMBER 31, 2004		29,900		$	1		$	26,479,920		$	(14,130,490	)		$	(120,725	)		$	12,258,605
Net Income											519,269								519,269			$	519,269
Unrecognized Pension Benefit costs, net of tax															(29,446	)			(29,446	)		$	(29,446	)
Total comprehensive income																						$	489,823
Tax benefit allocation								4,843											4,843
BALANCE AT DECEMBER 31, 2005		29,900		$	1		$	26,484,763		$	(13,611,221	)		$	(150,171	)		$	12,753,271
Net Income											91,248								91,248			$	91,248
Unrecognized Pension Benefit costs, net of tax															150,171				150,171			$	150,171
Total comprehensive income																						$	241,419
Tax benefit allocation								9,778											9,778
BALANCE AT DECEMBER 31, 2006		29,900		$	1		$	26,494,541		$	(13,519,973	)		$	0			$	13,004,468
Net Loss											(170,066	)							(170,066	)		$	(170,066	)
Total comprehensive loss																						$	(170,066	)
Adoption of SFAS 158 measurement date provisions, net of tax											(11,156	)							(11,156	)		$	(11,156	)
BALANCE AT DECEMBER 31, 2007		29,900		$	1		$	26,494,541		$	(13,701,195	)		$	0			$	12,823,246

 

***

50,000 shares authorized

The accompanying notes to financial statements are an integral part of these statements.

 

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GRANITE STATE GAS TRANSMISSION, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

 

		2007				2006				2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income		$	(170,066	)		$	91,248			$	519,269
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			841,559				784,431				702,499
Amortization of regulatory asset			—				708,340				850,008
Deferred income taxes and investment tax credits			(410,845	)			193,172				(44,139	)
Accretion expense			7,687				7,226				—
Changes in assets and liabilities:
Accounts receivable			1,662,129				53,409				(381,152	)
Accounts payable and accrued expenses			(4,256,253	)			1,773,594				1,586,961
Regulatory assets/liabilities			25,011				16,221				(142,339	)
Pension and other postretirement benefits			(253,842	)			33,153				42,882
Taxes receivable			4,762,758				(747,838	)			232,903
Other — net			(1,702	)			14,717				(22,117	)
Net cash provided by operating activities			2,206,436				2,927,673				3,344,775
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(1,564,588	)			(3,673,883	)			(4,471,535	)
Net cash used in investing activities			(1,564,588	)			(3,673,883	)			(4,471,535	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Changes in Affiliated Borrowings
(Short-term debt)			(602,406	)			757,177				1,126,737
Net Cash (used in) provided by financing activities			(602,406	)			757,177				1,126,737
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			39,442				10,967				(23	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			26,517				15,550				15,573
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	65,959			$	26,517			$	15,550
SUPPLEMENTAL DISCLOSURE INFORMATION:
Cash paid during year for interest		$	562,337			$	444,732			$	174,817
Income taxes (refunded) paid		$	(3,500,946	)		$	434,565			$	102,987

The accompanying notes to financial statements are an integral part of these statements.

 

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Note 1 Nature of Operations and Basis of Accounting

Company Structure

Granite State Gas Transmission, Inc. (“Granite” or the “Company”) is a wholly owned subsidiary of NiSource Inc. (“NiSource”). Granite is engaged in the transportation of natural gas through an interstate pipeline system consisting of 86 miles of FERC-regulated gas transmission pipeline primarily located in Maine and New Hampshire.

Granite’s costs of doing business are reflected in the financial statements for the periods presented. These costs include direct charges and allocations from NiSource subsidiaries for:

 

Ÿ

Corporate services, such as human resources, finance and accounting, legal and senior executives;

 

Ÿ

Business services, including payroll, accounts payable and information technology; and

 

Ÿ

Pension and other post-retirement benefit costs.

Transactions between Granite and other NiSource subsidiaries have been identified in the financial statements as affiliated transactions. Please refer to Note 9.

Use of Estimates

The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Basis of Accounting

Granite follows the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). SFAS No. 71 provides that rate-regulated companies account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Comparative Balance Sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.

Regulatory assets and liabilities were comprised of the following items:

 

		2007			2006
Year Ended December 31,
Assets
FERC Annual Charge Assessment (ACA)		$	55,467		$	57,294
Regulatory effect of SFAS 109			—			33,856
SFAS 158 — Benefit Pension and Other Retirement Plans			478,705			628,963
Total Assets		$	534,172		$	720,113
		2007			2006
Liabilities
OPEB Medical Subsidy		$	29,646		$	—
Total Liabilities		$	29,646		$	—

 

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Regulatory assets of $534,172 are not included in rate base and consequently are not earning a return on investment. Regulatory assets of $55,467 are covered by specific regulatory orders and are being recovered as components of cost of service over one year. Regulatory assets of $478,705 require specific rate action. Although recovery of these amounts is not guaranteed, Granite believes that these costs meet the requirements for deferral as regulatory assets as defined by the FERC. If Granite determined that the amounts included as regulatory assets were not recoverable, a charge to income would immediately be required to the extent of the unrecoverable amounts.

Utility Plant and Related Depreciation

Utility plant is stated at cost. Such costs include materials, payroll and related costs such as taxes, pensions and other employee benefits, general and administrative costs and include allowance for funds used during construction (AFUDC). Granite’s Utility Plant is comprised as follows:

 

		2007				2006
At December 31,
Pipelines		$	18,229,369			$	17,225,810
Facilities, structures and other			5,406,714				5,652,308
Other			332,096				317,813
Accumulated provision for depreciation and amortization			(7,438,548	)			(7,177,269	)
Net utility plant			16,529,631				16,018,662
Other property			600,000				600,000
Construction work in progress			118,901				0
Net property, plant and equipment		$	17,248,532			$	16,618,662

Granite follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal net of salvage, is charged to the accumulated provision for depreciation.

Granite recorded depreciation on a composite straight-line basis at an annual rate of 2.7 percent for 2007, 2006, and 2005, respectively.

Intangible Assets

Intangible assets includes $10,487,621 related to the allocation of the purchase price resulting from NiSource’s purchase of the individual units of Bay State Gas Company. Granite was part of Bay State Gas Company at the time of this purchase. The amount is being amortized to operating expense over a forty-year period, and is not currently a component of Granite’s rates. Granite’s Balance Sheet contains intangible assets discussed above which are not subject to recovery under SFAS No. 71. As a result, Granite assesses the carrying amount and potential earnings of these assets whenever events or changes in circumstances indicate that the carrying value could be impaired as per SFAS No. 144.

Amortization expense for the Company in 2007, 2006 and 2005 was approximately $262,191. The estimated amortization expense for 2008 through 2012 is approximately $262,191 annually. The balance of Granite’s intangible assets, net of amortization, as of December 31, 2007 and 2006 was $8,127,906 and $8,390,097, respectively.

 

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Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value:

1. Short-Term Financial Instruments

As cash and cash equivalents, accounts and notes receivable, and accounts payable, are all short-term in nature, their carrying amount approximates fair value.

Financing to meet current operating needs is also obtained from NiSource through an intercompany money pool from which Granite can borrow funds or invest excess funds. While the current capital markets have been adversely impacted by a variety of negative economic indicators, NiSource believes that it will not impact its continued access to traditional capital markets.

Revenue Recognition

Revenues are recognized as services are provided and customers are billed on a monthly basis. Revenues from long-term contracts are recognized in accordance with the accrual basis of accounting and are recognized over the term of the contract as services are provided. Estimates may be used for determining the services provided. Differences between actual and estimated revenues are immaterial.

Estimated Rate Refunds

Granite collects revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome. There were no rate refunds in 2007, 2006, and 2005, respectively.

Income Taxes and Investment Tax Credits

For income tax purposes, Granite is included in the consolidated federal and various state returns filed by NiSource. Granite participates in the NiSource Tax Allocation Agreement, which generally provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax, including the tax benefits of operating losses and credits. Any net benefit attributable to the parent is reallocated to other members.

Please refer to Note 5, “Income Taxes,” in the Notes to Financial Statements for additional information.

Note 2 Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

SFAS No. 158 — Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS No. 158). In September 2006, the FASB issued SFAS No. 158 to improve existing reporting for defined benefit postretirement plans by requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, among other changes. In the fourth quarter of 2006, Granite adopted the provisions of SFAS No. 158 requiring employers to recognize in the statement of financial position the overfunded or underfunded status of a defined benefit postretirement plan, measured as the difference between the fair value of the plan assets and the benefit obligation. Based on the measurement of the various defined benefit pension and other postretirement plans’ assets and benefit obligations at September 30, 2006, the pretax impact of adopting

 

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SFAS No. 158 increased “Prepayments” by $2,437, increased “Regulatory Assets” by $628,963, and decreased “Other Current Liabilities” by $19,057. “Pension and Postretirement Benefits” were increased by $650,457. With the adoption of SFAS No. 158 Granite determined that the future recovery of pension and other postretirement plans costs is probable in accordance with the requirements of SFAS No. 71. Granite recorded regulatory assets and liabilities that would otherwise have been recorded to accumulated other comprehensive income.

Granite adopted the SFAS No. 158 measurement date provisions in the first quarter of 2007 requiring employers to measure plan assets and benefit obligations as of the fiscal year-end. The total change to the Balance Sheet for the year 2007, related to the adoption of SFAS No. 158, was a decrease to “Regulatory Assets” of $127,074, an increase to “Other Deferred Charges” of $53,996, an increase in “Pension and Postretirement Benefits” of $35,619, a decrease to “Retained Earnings” of $18,573, a decrease to “Accounts and Notes Receivable” of $7,061, an increase to “Accounts Receivable from Affiliated Companies” of $99,072, and an increase to “Accounts Payable to Affiliated Companies” of $1,887. In addition, 2007 expense for pension and postretirement benefits reflected the updated measurement date valuations.

FIN 48 — Accounting for Uncertainty in Income Taxes (FIN 48). In June 2006, the FASB issued FIN 48 to reduce the diversity in practice associated with certain aspects of the recognition and measurement requirements related to accounting for income taxes. Specifically, this interpretation requires that a tax position meet a “more-likely-than-not recognition threshold” for the benefit of an uncertain tax position to be recognized in the financial statements and requires that benefit to be measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. When determining whether a tax position meets the more-likely-than-not recognition threshold, it is to be based on whether it is probable of being sustained on audit by the appropriate taxing authorities, based solely on the technical merits of the position. Additionally, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

On January 1, 2007, Granite adopted the provisions of FIN 48. There was no impact to the opening balance of retained earnings as a result of the adoption of FIN 48. See note 5, Income Taxes, in the Notes to the Financial Statements for additional information. There are no uncertain tax positions as of December 31, 2007.

Recently Issued Accounting Pronouncements

SFAS No. 157 — Fair Value Measurements (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157 to define fair value, establish a framework for measuring fair value and to expand disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and should be applied prospectively, with limited exceptions. The adoption of SFAS No. 157, in first quarter 2008, did not have an impact on Granite’s January 1, 2008 balance of retained earnings and is not anticipated to have a material impact prospectively.

SFAS No. 159 — The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. In February 2007, the FASB issued SFAS No. 159 which permits entities to choose to measure certain financial instruments at fair value that are not currently required to be measured at fair value. Upon adoption, a cumulative adjustment will be made to beginning retained earnings for the initial fair value option remeasurement. Subsequent unrealized gains and losses for fair value option items will be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007 and should not be applied retrospectively, except as permitted for certain conditions for early adoption. Granite has chosen not to elect to measure any applicable financial assets of liabilities at fair value pursuant to this standard when SFAS No. 159 was adopted on January 1, 2008.

 

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Note 3 Asset Retirement Obligations

Granite accounts for retirement obligations on its assets in accordance with SFAS No. 143, “Accounting for Asset Retirements Obligations.” In the fourth quarter 2005, Granite adopted the provisions of FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which broadened the scope of SFAS No. 143 to include contingent asset retirement obligations and it also provided additional guidance for the measurement of the asset retirement liabilities. The initial impact of adopting FIN 47 was $113,183. This accounting standard and the related interpretation requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost, thereby increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Granite defers the difference between the amount recognized for depreciation and accretion and the amount collected in rates as required pursuant to SFAS No. 71 for those amounts it has collected in rates or expects to collect in future rates. Currently the deferred amount for this difference is zero.

Granite has recognized asset retirement obligations associated with various obligations including, certain costs to retire pipeline, and removal of certain pipelines known to contain PCB contamination as well as some other nominal asset retirement obligations. The asset retirement obligation totaled $128,096 and $120,409, at December 31, 2007 and 2006, respectively. For the years ended December 31, 2007, 2006, and 2005 Granite recognized accretion expense of $7,687, $7,226, and zero respectively.

Changes in Granite’s liability for asset retirement obligations for the years 2007 and 2006 are presented in the table below:

 

		2007			2006
Beginning Balance		$	120,409		$	113,183
Accretion			7,687			7,226
Ending Balance		$	128,096		$	120,409

Note 4 Regulatory Matters

Significant FERC Developments

On June 30, 2005, the FERC issued the “Order on Accounting for Pipeline Assessment Costs.” This guidance was issued by the FERC to address consistent application across the industry for accounting of the United States Department of Transportation’s (“DOT”) Integrity Management Rule. The effective date of the guidance was January 1, 2006 after which all assessment costs have been recorded as operating expenses. The rule specifically provides that amounts capitalized in periods prior to January 1, 2006 will be permitted to remain as recorded. Granite incurred Integrity Management Program costs of $191,921, $224,211 and $138,469 in 2007, 2006, and 2005, respectively. Beginning January 1, 2006, according to the FERC order, these costs began being expensed; prior to 2006 these amounts were being capitalized.

 

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Note 5 Income Taxes

The components of income tax expense (benefit) were as follows:

 

		2007				2006				2005
Year Ended December 31
Current — Federal		$	290,238			$	(59,752	)		$	428,551
— State			(67,503	)			(29,966	)			53,796
Total Current			222,735				(89,718	)			482,347
Deferred — Federal			(339,143	)			150,139				(46,031	)
— State			(70,382	)			44,353				3,212
Total Deferred			(409,525	)			194,492				(42,819	)
Investment Tax Credits			(1,320	)			(1,320	)			(1,320	)
Provision recorded as change in accrued interest			169,108				—				—
Income Tax Expense (Benefit)		$	(19,002	)		$	103,454			$	438,208

Total income taxes were different from the amount that would be computed by applying the statutory Federal income tax rate to book income before income tax. The major reasons for this difference were as follows:

 

		2007				2006				2005
Year Ended December 31,
Book income (loss) before income taxes		$	(189,068	)		$	194,702			$	957,477
Tax expense (benefit) at statutory Federal income tax rate			(66,174	)			68,146				335,117
Prior Year Tax Adjustments			—				—				37,834
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit			(89,625	)			9,352				37,055
Deferred investment tax credit			(1,320	)			(1,320	)			(1,320	)
Provision recorded as change in accrued interest			169,108				—				—
Other			(30,991	)			27,276				29,522
Income Tax Expense (Benefit)		$	(19,002	)		$	103,454			$	438,208

Deferred income taxes resulted from temporary differences between the financial statement carrying amount and the tax basis of existing assets and liabilities. The components of non-current deferred tax liabilities at December 31 are as follows:

 

		2007				2006
Deferred Tax Liabilities —
Historical plant related differences		$	1,881,338			$	1,679,206
Plant acquisition adjustment and regulatory assets			3,246,079				3,350,791
Interest on Contingent Taxes			16,526				431,259
Pensions and OPEB			74,599				132,436
Other, net			(9,067	)			95,473
Total Deferred Tax Liabilities		$	5,209,475			$	5,689,165

As discussed at Note 2, there was no impact to the opening balance of retained earnings as a result of the adoption of FIN 48 and there are no uncertain tax positions as of December 31, 2007. As of December 31, 2006 and prior to the adoption of FIN 48, Granite had an uncertain tax position of $287,880. Granite settled the uncertain tax position with the IRS in 2007.

 

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Effective January 1, 2007, Granite recognizes accrued interest and penalties related to uncertain tax positions in income tax expense. In prior years, Granite recognized such accrued interest liability in interest expense and accrued interest receivable in interest income. During the years ended December 31, 2006, and December 31, 2005, Granite recognized $225,415 and $151,410, respectively, of interest income in the Statements of Income. Granite also had $1,083,154 of accrued interest receivable on the Balance Sheet at December 31, 2006, and $3,677 accrued interest payable related to uncertain tax positions. Upon adoption of FIN 48 on January 1, 2007, Granite did not decrease its accrual for interest on unrecognized tax benefits. As of December 31, 2007, there is $41,390 of accrued interest receivable on the balance sheet. During 2007, $869,350 was received by Granite as a result of settlements with the IRS and $169,108 of interest receivable was reversed through income tax expense. No amounts have been recorded for penalties in 2007, 2006, and 2005.

Because NiSource is part of the IRS’s Large and Mid-Size Business program, each year’s federal income tax return is typically audited by the IRS. The audit of tax years 2005 and 2006 is expected to commence in the first quarter of 2008. Effective January 1, 2007 Granite recognizes accrued interest and penalties related to unrecognized tax benefits in income tax expense.

During the year ended December 31, 2007, Granite received income tax refunds of $3,500,946 which primarily includes the settlement of the 1999 through 2004 federal returns.

The statute of limitations in each of the state jurisdictions in which NiSource operates remains open until the years are settled for federal income tax purposes, at which time amended state income tax returns reflecting all federal income tax adjustments are filed. There are no state income tax audits currently in progress.

Note 6 Pension and Other Postretirement Benefits

NiSource provides defined contribution plans and noncontributory defined benefit retirement plans that cover its employees. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, NiSource provides health care and life insurance benefits for certain retired employees. The majority of employees may become eligible for these benefits if they reach retirement age while working for Granite. The expected cost of such benefits is accrued during the employees’ years of service. Granite’s current rates include postretirement benefit costs on an accrual basis, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. Cash contributions are remitted to grantor trusts. As of December 31, 2007, Granite uses December 31 as its measurement date for its pension and postretirement benefit plans, in accordance with SFAS No. 158.

Granite’s employees are included in the plans mentioned above. Costs are allocated to Granite. Related assets, etc. are commingled and are not allocated to individual sponsors. Granite’s employees account for 0.08%, 0.08%, and 0.06% of the employees participating in the plans in 2007, 2006, and 2005, respectively.

Pension expense for Granite, as allocated by the Parent Company was $18,533, $19,386, and $33,800 for the years 2007, 2006, and 2005, respectively. Postretirement benefits expense for Granite was $44,762, $30,358, and $32,800 in 2007, 2006, and 2005, respectively. These allocations were based on expenses, net of assets returns, as actuarially determined for employees associated with Granite. Granite made cash contributions to the pension plan totaling $176,627, $73,117, and zero for 2007, 2006, and 2005, respectively. Cash contributions to the post-retirement plan were $117,326, zero, and zero in 2007, 2006, and 2005, respectively.

 

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Note 7 Short-Term Borrowings

Granite satisfies its liquidity requirements primarily through internally generated funds and through intercompany borrowings from the NiSource Money Pool. As of December 31, 2007 and 2006 Granite had short-term NiSource Money Pool borrowings of $7,867,706 at a weighted average interest rate of 5.35 percent and $8,470,112 at a weighted average interest rate of 5.46 percent, respectively. Interest expense on Money Pool borrowings was $554,559, $456,951, and $188,793 for 2007, 2006, and 2005, respectively.

Note 8 Operating Leases

Granite leases assets in several areas of its operations. Payments made in connection with operating leases were $37,207, $35,878, and $36,105 in 2007, 2006, and, 2005, respectively, and are primarily charged to operation and maintenance expense as incurred. There are no minimum lease payments in 2008 and going forward.

Note 9 Affiliated Company Transactions

Granite receives executive, financial, and administrative and general services from an affiliate, NiSource Corporate Services. The costs of these services are charged to Granite based on payroll costs and expenses incurred by NiSource Corporate Services employees for the benefit of Granite. These costs which totaled $304,332, $312,383, and $543,657 for years 2007, 2006, and 2005, respectively, consist primarily of employee compensation and benefits and are recorded within, “Operations and maintenance expenses — affiliated” on the Statements of Income (Loss). Granite also incurred expenses from an affiliate, Columbia Gas Transmission Corporation (“Columbia Transmission”), for various routine administrative activities totaling $318,505, $337,697, and $290,040 during the years 2007, 2006, and 2005, respectively. Granite incurred office rental expense from an affiliate, Northern Utilities, Inc. (“Northern Utilities”), of $35,709 for 2007 and 2006, and $34,535 for 2005.

Granite recorded affiliated gas sales of zero, $14,629,314, and $24,198,828 during the years ended 2007, 2006 and 2005 respectively, under contracted agreements with Bay State Gas Company (“Bay State”) and Northern Utilities at no markup. These transactions are recorded net on the statements of (loss) income. Under these agreements, Granite purchases gas from a third party supplier and subsequently sells the gas to Bay State and Northern Utilities. Granite also charges a fee to Bay State and Northern Utilities under these agreements, of which zero, $64,976, and $64,976 was recorded in net affiliated revenues during the years 2007, 2006, and 2005 respectively. These agreements expired in December 2006.

Acting on behalf of Bay State and Northern Utilities, Granite has Operational Balancing Agreements (“OBAs”) with third party transportation companies. Under these OBAs, on a monthly basis, Granite will settle in cash the outstanding gas balances of the OBAs with the third parties, and in turn refund the cash or be refunded cash by Bay State and Northern Utilities, dependent on the position of the OBAs. As of December 31, 2007, included in accounts and notes receivable, Granite has recorded a receivable from the third party transportation companies of $502,939 for the cash out of the imbalance, and a corresponding payable to affiliated companies. As of December 31, 2006, included in accounts payable, Granite has recorded a payable to the third party transportation companies of $87,542 for the cash out of the imbalance, and a corresponding receivable from affiliated companies. The OBAs are recorded net within the statements of (loss) income.

Granite recorded gas transportation revenues from affiliates of $2,851,768, $3,641,343 and $3,917,158 for years ended 2007, 2006, and 2005 respectively.

The December 31, 2007 and 2006 accounts receivable balance includes $388,853 and $2,391,984, respectively, due from affiliated companies, under the agreements discussed above.

 

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The December 31, 2007 and 2006 accounts payable balance reflects $745,793 and $5,281,722, respectively, due to affiliated companies, separate from the NiSource Money Pool.

The December 31, 2007 and 2006 taxes receivable balance includes $243,513, and $5,002,918, respectively, of federal and state income taxes receivable that are due from NiSource in accordance with its tax-sharing agreement.

Note 10 Subsequent Events

Sale of Granite

On February 15, 2008, NiSource reached a definitive agreement under which Unitil Corporation (“Unitil”) will acquire Northern Utilities, an affiliated company, and Granite for $160 million plus net working capital at the time of closing. Historically, net working capital has averaged approximately $25 million. Under the terms of the transaction, Unitil will acquire Northern Utilities, a local gas distribution company serving 52 thousand customers in 44 communities in Maine and New Hampshire and Granite, an 86-mile FERC regulated gas transmission pipeline primarily located in Maine and New Hampshire. The transaction, expected to be completed by the end of 2008, is subject to federal and state regulatory approvals. NiSource recorded an after tax loss of $14,730,425 related to the pending sale of Granite.

 

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Through and including                     , 2008 (the 25^th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

             Shares

Common Stock

 

 

PRICE $             PER SHARE

 

 

RBC CAPITAL MARKETS
JANNEY MONTGOMERY SCOTT LLC		OPPENHEIMER & CO.
BREAN MURRAY, CARRET & CO, LLC		EDWARD JONES

 

 

PROSPECTUS

 

                    , 2008

 

 

 

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PART II. INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. Other Expenses of Issuance and Distribution

The following table sets forth the expenses in connection with the sale and distribution of the common stock offered by this prospectus, other than underwriting discounts and commissions (all of which are to be paid by the Registrant). All amounts shown are estimates except for the SEC registration fee.

 

SEC Registration Fee		$
Legal Fees and Expenses
Accounting Fees and Expenses
Transfer Agent and Registrar Fees and Expenses
Printing, Engraving and Mailing Expenses
Stock Exchange Listing Fee
Miscellaneous
Total		$

ITEM 15. Indemnification of Directors and Officers.

The Registrant is organized under the laws of the State of New Hampshire. The New Hampshire Business Corporation Act (NHBCA) provides that a corporation may indemnify an individual made a party to a proceeding because he is or was a director against liability incurred in the proceeding if: (1) he conducted himself in good faith; and (2) he reasonably believed (i) in the case of conduct in his official capacity with the corporation, that his conduct was in its best interests; and (ii) in all other cases, that his conduct was at least not opposed to its best interests; and (3) in the case of any criminal proceeding, he had no reasonable cause to believe his conduct was unlawful. A corporation may pay for or reimburse the reasonable expenses incurred by a director who is a party to a proceeding in advance of the final disposition of the proceeding if (1) the director furnishes the corporation a written affirmation of his good faith belief that he has met the standard of conduct described in the preceding sentence, (2) the director furnishes the corporation an undertaking, executed personally or on his behalf, to repay the advance if it is ultimately determined that he did not meet the standard of conduct and (3) a determination is made that the facts then known to those making the determination would not preclude indemnification. Unless a corporation’s Articles of Incorporation provide otherwise, the corporation may indemnify and advance expenses to an officer, employee or agent of the corporation who is not a director to the same extent as to a director. A corporation may not indemnify a director (x) in connection with a proceeding by or in the right of the corporation in which the director was adjudged liable to the corporation; or (y) in connection with any other proceeding charging improper personal benefit to him, whether or not involving action in his official capacity, in which he was adjudged liable on the basis that personal benefit was improperly received by him. Unless limited by its Articles of Incorporation, a corporation shall indemnify a director or officer who was wholly successful, on the merits or otherwise, in the defense of any proceeding to which he was a party because he is or was a director or officer of the corporation against reasonable expenses incurred by him in connection with the proceeding. A corporation may purchase and maintain insurance on behalf of an individual who is or was a director, officer, employee, or agent of the corporation, or who, while a director, officer, employee or agent of the corporation, is or was serving at the request of the corporation as a director, officer, partner, trustee, employee, or agent of another foreign or domestic corporation, partnership, joint venture, trust, employee benefit plan, or other enterprise, against liability asserted against or incurred by him in that capacity or arising from his status as a director, officer, employee, or agent, whether or not the corporation would have power to indemnify him against the same liability under the NHBCA.

 

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Article X of the Registrant’s By-Laws provides that the Registrant shall indemnify any person who was or is a party or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the person’s having served as, or by reason of the person’s alleged acts or omissions while serving as a director, officer, employee or agent of the Registrant, or while serving at the request of the Registrant as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement or otherwise actually and reasonably incurred by such person in connection with the action, suit or proceeding, if the person acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the Registrant, and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful, said indemnification to be to the full extent permitted by law under the circumstances, including, without limitation, by all applicable provisions of the NHBCA. Any indemnification under Article X shall be made by the Registrant with respect to Directors or other persons after a determination that the person to be indemnified has met the standards of conduct set forth in the NHBCA, such determination to be made by the Board of Directors, by majority vote of a quorum, or by other persons authorized to make such a determination under the NHBCA.

The right of indemnification arising under Article X was adopted for the purpose of inducing persons to serve and to continue to serve the Registrant without concern that their service may expose them to personal financial harm. It is to be broadly construed, applied and implemented in light of that purpose. It is not to be exclusive of any other right to which any such person is entitled under any agreement, vote of the stockholders or the Board of Directors, statute, or as a matter of law, or otherwise, nor is it to be construed to limit or confine in any respect the power of the Board of Directors to grant indemnity pursuant to any applicable statutes or laws of the State of New Hampshire. The provisions of Article X are separable, and, if any provision or portion thereof is for any reason held inapplicable, illegal or ineffective, such holding will not affect any other right of indemnification existing under Article X or otherwise. As used in Article X, the term “person” includes heirs, executors, administrators or other legal representatives. As used in Article X, the terms “Director” and “officer” include persons elected or appointed as officers by the Board of Directors, persons elected as Directors by the stockholders or by the Board of Directors, and persons who serve by vote or at the request of the Registrant as directors, officers or trustees of another organization in which the Registrant has any direct or indirect interest as a shareholder, creditor or otherwise.

Article X of the Registrant’s By-Laws also allows the Registrant to purchase and maintain insurance on behalf of any person who was or is a Director, officer or employee of the Registrant or any of its subsidiaries, or who was or is serving at the request of the Registrant as a fiduciary of any employee benefit plan of the Registrant or any subsidiary, against any liability asserted against, and incurred by, such person in any such capacity, or arising out of such person’s status as such, whether or not the Registrant would have the power to indemnify such person against such liability under the provisions of the NHBCA. The obligation to indemnify and reimburse such person under the Registrant’s By-Laws, if applicable, will be reduced by the amount of any such insurance proceeds paid to such person, or the representatives or successors of such person.

 

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ITEM 16. Exhibits.

 

Exhibit No:		Description of Exhibit		Reference
1.1		Underwriting Agreement		To be filed by amendment.
2.1		Stock Purchase Agreement		Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed February 20, 2008.
3.1		Articles of Incorporation of Unitil Corporation		Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-14, No. 2-93769.
3.2		Articles of Amendment to the Articles of Incorporation of Unitil Corporation		Incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991.
3.3		By-Laws of Unitil Corporation		Incorporated by reference to Exhibit 4 to the Registrant’s Registration Statement on Form S-8, No. 333-73327.
5.1		Opinion of Dewey & LeBoeuf LLP		To be filed by amendment.
23.1		Consent of Dewey & LeBoeuf LLP		Included in Exhibit 5.1.
23.2		Consent of Vitale, Caturano & Company, Ltd.		Filed herewith.
23.3		Consent of Deloitte & Touche LLP		Filed herewith.
23.4		Consent of Deloitte & Touche LLP		Filed herewith.
24.1		Powers of Attorney		See page II-5.

ITEM 17. Undertakings.

The undersigned Registrant hereby undertakes as follows:

 

(1)

That, for purposes of determining any liability under the Securities Act of 1933, each filing of the Registrant’s annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

(2)

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will,

 

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unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

 

(3)

The undersigned Registrant hereby undertakes that:

 

(i)

For the purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

(ii)

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Robert G. Schoenberger and Mark H. Collin, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, from such person and in each person’s name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to the registration statement and any registration statement relating to this registration statement under Rule 462 and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-3 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the Town of Hampton, State of New Hampshire, on this 6th day of August, 2008.

 

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated:

 

Signature		Title		Date
/s/    ROBERT G. SCHOENBERGER         Robert G. Schoenberger		Director, Chairman of the Board, Chief Executive Officer and President		August 5, 2008
/s/    MARK H. COLLIN         Mark H. Collin		Senior Vice President, Chief Financial Officer and Treasurer		August 5, 2008
/s/    LAURENCE M. BROCK         Laurence M. Brock		Controller and Chief Accounting Officer		August 5, 2008
/s/    DR. ROBERT V. ANTONUCCI         Dr. Robert V. Antonucci		Director		August 5, 2008
/s/    DAVID P. BROWNELL         David P. Brownell		Director		August 5, 2008

 

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Signature		Title		Date
/s/    MICHAEL J. DALTON         Michael J. Dalton		Director		August 5, 2008
Albert H. Elfner, III		Director
/s/    EDWARD F. GODFREY         Edward F. Godfrey		Director		August 5, 2008
/s/    MICHAEL B. GREEN         Michael B. Green		Director		August 5, 2008
Eben S. Moulton		Director
/s/    M. BRIAN O’SHAUGHNESSY         M. Brian O’Shaughnessy		Director		August 5, 2008
/s/    CHARLES H. TENNEY, III         Charles H. Tenney, III		Director		August 5, 2008
/s/    DR. SARAH P. VOLL         Dr. Sarah P. Voll		Director		August 5, 2008

 

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EXHIBIT INDEX

 

Exhibit No:		Description of Exhibit		Reference
1.1		Underwriting Agreement		To be filed by amendment.
2.1		Stock Purchase Agreement		Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed February 20, 2008.
3.1		Articles of Incorporation of Unitil Corporation		Incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-14, No. 2-93769.
3.2		Articles of Amendment to the Articles of Incorporation of Unitil Corporation		Incorporated by reference to Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the fiscal year ended December 31, 1991.
3.3		By-Laws of Unitil Corporation		Incorporated by reference to Exhibit 4 to the Registrant’s Registration Statement on Form S-8, No. 333-73327.
5.1		Opinion of Dewey & LeBoeuf LLP		To be filed by amendment.
23.1		Consent of Dewey & LeBoeuf LLP		Included in Exhibit 5.1.
23.2		Consent of Vitale, Caturano & Company, Ltd.		Filed herewith.
23.3		Consent of Deloitte & Touche LLP		Filed herewith.
23.4		Consent of Deloitte & Touche LLP		Filed herewith.
24.1		Powers of Attorney		See page II-5.

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in this Registration Statement of Unitil Corporation and subsidiaries (the Company) on Form S-3 of our report dated February 8, 2008, relating to the consolidated financial statements of the Company as of and for the three years ended December 31, 2007 appearing in the Annual Report on Form 10-K of Unitil Corporation and subsidiaries for the year ended December 31, 2007 and to the reference to our Firm under the caption “Experts” in the Prospectus, which is part of such Registration Statement.

/s/ VITALE, CATURANO & COMPANY, LTD.

August 5, 2008

Boston, Massachusetts

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Registration Statement on Form S-3 of our report dated May 15, 2008 relating to the financial statements of Northern Utilities, Inc. appearing in the Prospectus, which is part of this Registration Statement.

We also consent to the reference to us under the heading “Experts” in such Prospectus.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

August 6, 2008

Exhibit 23.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this Registration Statement on Form S-3 of our report dated May 27, 2008 relating to the financial statements of Granite State Gas Transmission Inc. appearing in the Prospectus, which is part of this Registration Statement.

We also consent to the reference to us under the heading “Experts” in such Prospectus.

/s/ DELOITTE & TOUCHE LLP

Columbus, Ohio

August 6, 2008