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Filed Pursuant to Rule 424(b)(5)
Registration No. 333-152823

PROSPECTUS SUPPLEMENT (To Prospectus dated December 10, 2008)

2,000,000 Shares

Common Stock

 

 

Unitil Corporation is offering 2,000,000 shares of its common stock.

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.” The last reported sale price of our common stock on December 10, 2008 was $20.35 per share.

Investing in our common stock involves risks that are described in the section entitled Risk Factors beginning on page S-15 of this prospectus supplement and on page 2 of the accompanying prospectus.

 

 

PRICE $20.00 PER SHARE

 

 

		Per Share			Total
Public offering price		$	20.00		$	40,000,000
Underwriting discount		$	1.05		$	2,100,000
Proceeds, before expenses, to Unitil Corporation		$	18.95		$	37,900,000

The underwriters may also purchase up to an additional 300,000 shares from us at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus supplement 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 supplement 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 December 15, 2008.

 

 

 

RBC CAPITAL MARKETS

 

 

 

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

December 10, 2008

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Map of Service Territory⁽¹⁾

 

(1)

This map is presented to illustrate the effects of Unitil Corporation’s acquisition of all of the outstanding capital stock of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., as discussed in the prospectus supplement. For the purposes of this map, “Overlapping Service Territory” illustrates service territories served by Unitil Corporation prior to the consummation of the acquisition and Northern Utilities, Inc.

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We provide information to you about this offering of shares of our common stock in two separate documents that are bound together: (i) this prospectus supplement, which described the specific details regarding this offering; and (ii) the accompanying prospectus, which provides general information, some of which may not apply to this offering. Generally, when we refer to this “prospectus,” we are referring to both documents combined. If information in this prospectus supplement is inconsistent with the accompanying prospectus, you should rely on this prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying 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 supplement and the accompanying 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, excluding Northern Utilities, Inc. and Granite State Gas Transmission, Inc., 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 supplement and the accompanying 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 our Quarterly Report on Form 10-Q for the three months ended September 30, 2008, each of which is specifically incorporated by reference into this prospectus. See the section entitled Where You Can Find More Information in this prospectus supplement. 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 in this prospectus supplement.

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, the MDPU and, with respect to Northern Utilities operations in Maine, 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. 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. Additionally,

 

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our other restructuring-related regulatory assets for which regulatory approval has been obtained for recovery were approximately $32.1 million in the aggregate as of December 31, 2007.

Substantially all of FG&E’s stranded costs relate to owned generation assets and power purchase agreements divested by 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 territory. The level of economic growth in our electric and natural gas distribution service territory directly affects our potential for future growth in our business. As a result, adverse changes in the economy, including the significant adverse changes in the economy in 2008, 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 territory, and adverse changes in the economy, including the significant adverse changes in the economy in 2008, may negatively affect their revenues, operating results and financial condition.

We may not be able to obtain debt financing, obtain debt financing on acceptable terms, or obtain debt financing under our current credit facilities because of the deterioration of the credit and capital markets, which could have an adverse affect on our operating results and financial condition. We, along with Northern Utilities and Granite State, require capital to fund utility plant additions, working capital and other utility expenditures. While the capital necessary to meet these requirements is derived primarily from internally-generated funds, we initially supplement internally generated funds through short-term debt financings, as needed, and periodically replace portions of our short-term debt with long-term debt. General economic conditions, including recent distress in the financial markets, have had an adverse impact on the availability of credit resources generally, which could negatively affect our ability to obtain short- and long-term debt financings and the terms of such financings. In addition, we may be unable to obtain debt financing under our current credit facilities because our lending counterparties may be unwilling or unable to meet their funding obligations. In each case, this could hinder or prevent us from meeting our future capital needs, which could correspondingly have an adverse affect on our operating results and financial condition. In addition, the material terms of our existing indebtedness will also restrict our ability to incur any material amount of additional indebtedness, which could negatively impact our operating results and financial condition. Please see the section entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

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 (the “PPA”) was signed into law. Included in the PPA are new minimum funding rules which came 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 provided pursuant to the PPA.

 

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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. Recent and future declines in the valuation of capital markets could require us to make cash contributions to our pension plans substantially in excess of our cash contributions in prior years, which could adversely affect our financial condition.

In September 2006, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial 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. Please 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.

Weather conditions may cause our sales to vary from year to year. Sales by our retail distribution utilities and by Northern Utilities vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual natural gas sales were temperature sensitive prior to the closing of the Acquisitions. 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 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, FG&E, 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 (including the long-term notes to be issued by Northern Utilities and Granite State) 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 (including the

 

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agreements under which the long-term notes of Northern Utilities and Granite State are to be issued); and

 

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limitations that may be imposed by New Hampshire, Massachusetts and 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, including the bridge credit facility that we used to partially finance the Acquisitions and the long-term notes issued by Northern Utilities and to be issued by Granite State, 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, including those of Northern Utilities and Granite State, 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.

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, including those of Northern Utilities, 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, including Northern Utilities and Granite State, 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.

 

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Our business could be adversely affected if we are unable to retain our existing customers or attract new customers. The success of our business depends, in part, on our ability to maintain and increase our customer base. Our failure to maintain or attract customers could have a material adverse effect on our business, financial condition and operating results. Similarly, the success of Northern Utilities’ and Granite State’s businesses depends, in part, on their ability to maintain and increase their customer base. Their failure to maintain or attract customers could have a material adverse effect on our business, financial condition and operating results.

Risks Relating to the Acquisitions

If we are not successful in effectively integrating Northern Utilities and Granite State, we may not be able to operate cost-efficiently. Achieving the benefits of the 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 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, which may adversely affect our results of operations and financial condition. 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.

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

Our ability to execute a reasonable regulatory plan for Northern Utilities and Granite State 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. Also, pursuant to the MPUC’s and NHPUC’s orders authorizing our acquisition of Northern Utilities, we cannot seek base rate relief in Maine or New Hampshire until November 1, 2010, subject to certain exceptions.

 

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The trading price of our common stock may be affected by factors different from those that affected the trading price of our common stock prior to the closing the Acquisitions. The Acquisitions increased our assets by approximately 52%, increased our customer base by approximately 52,000 natural gas customers to 167,000 total natural gas and electric customers, and further diversified our operations with respect to geography (into Maine) and utility mix (between our gas and electric divisions). Therefore, our results of operations, as well as the trading price of our common stock, may be affected by factors different from those that affected the results of operations and the trading price of our common stock prior to the closing of the Acquisitions.

Increases in interest rates could have a negative effect on our cost to finance a portion of the Acquisitions with borrowings under a bridge credit facility. We financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract.

As of December 10, 2009, we had approximately $85.7 million outstanding under the bridge credit facility, which provides for a loan for up to eleven months. We expect to repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million, as soon as practicable using the net proceeds from (i) the offering of our common stock, as described in this prospectus and (ii) the anticipated sale and issuance by Granite State of $10.0 million aggregate principal amount of long-term unsecured notes. We expect to repay the estimated $38.9 million balance outstanding under the bridge credit facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt or using borrowings under a revolving credit facility.

We expect to guarantee the payment of principal, interest and other amounts payable on the Granite State notes. This guarantee will terminate if Granite State reorganizes and merges into Northern Utilities.

There is no assurance that the sale and issuance of the long-term unsecured notes as described above, will close in a timely manner or at all. Changes in interest rates will affect the interest rate and corresponding interest expense associated with amounts outstanding under the bridge credit facility. We will be required to repay amounts outstanding under the bridge credit facility on or before its maturity date of November 1, 2009. If we repay all or any portion of the amounts that may be outstanding under the bridge credit facility using borrowings under a revolving credit facility, changes in interest rates will affect the interest expense associated with amounts outstanding under the revolving credit facility. In each case, increases in interest rates generally will increase our financing costs associated with the Acquisitions and could adversely affect our financial condition and results of operations.

Please see the section entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

Amounts outstanding under the bridge credit facility or a revolving credit facility could adversely affect our cash flow. We financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract.

As of December 10, 2008, we had approximately $85.7 million outstanding under the bridge credit facility, which provides for a loan for up to eleven months. We expect to repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million, as soon as practicable using the net proceeds from (i) the offering of our common stock, as described in this prospectus and (ii) the anticipated sale and issuance by Granite State of $10.0 million aggregate principal amount of long-term unsecured notes. We expect to repay any balance outstanding under the bridge credit facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt or using borrowings under a revolving credit facility. However, there is no assurance that we will be able to do so in a timely manner. Therefore, we may need to

 

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use a significant portion of our cash flow to repay the balance outstanding under the bridge credit facility, which would limit the amount of cash we have available for working capital, capital expenditures and other general corporate purposes and could negatively affect our liquidity, financial condition and results of operations. Also, if we repay all or any portion of the amounts that may be outstanding under the bridge credit facility using borrowings under a revolving credit facility, we may need to use a significant portion of our cash flow to pay interest on the revolving credit facility and to repay the principal amount outstanding under the revolving credit facility when required, which would limit the amount of cash we have available for working capital, capital expenditures and other general corporate purposes and could negatively affect our liquidity, financial condition and results of operations.

Please see the section entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

Amounts outstanding under the bridge credit facility and the sale and issuance of long-term unsecured notes by Northern Utilities and Granite State could restrict our business operations and adversely affect our cash flow.

We may be restricted from engaging in certain business operations because of financial covenants associated with the above-referenced bridge credit facility, which could negatively affect our financial condition and results of operations. These financial covenants include, without limitation, restrictions relating to paying dividends, incurring indebtedness and liens, merging or consolidating with another entity or selling, leasing or otherwise disposing of all or substantially all of our assets.

We repaid a portion of the above-referenced bridge credit facility using the net proceeds from the sale and issuance of long-term unsecured notes by Northern Utilities and expect to repay an additional portion using the net proceeds from the anticipated sale and issuance of long-term unsecured notes by Granite State. We may be restricted from engaging in certain business operations because of financial covenants associated with these notes, which could negatively affect our financial condition and results of operations. These financial covenants include, without limitation, restrictions relating to paying dividends, incurring indebtedness and liens, merging or consolidating with another entity or selling, leasing or otherwise disposing of all or substantially all of our assets.

In addition, we may need to use a significant portion of our cash flow to pay interest on amounts outstanding under the bridge credit facility and the notes and to repay the amount outstanding under the bridge credit facility and the principal amount of the notes when required, which would limit the amount of cash we have available for working capital, capital expenditures and other general corporate purposes and could negatively affect our liquidity, financial condition and results of operations.

Please see the section entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

The Acquisitions will result in significant costs to us, which will result in a reduction in our income and cash flows. We will be required to pay our costs relating to the Acquisitions and such costs will be significant. 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 have assumed 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. Please see the section entitled The Acquisitions – Description of the Acquisitions.

 

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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 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 we or our existing shareholders sell a large number of shares of our common stock or the public market perceives that we or our 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 supplement 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 reduce the proportionate share of the holdings of our current shareholders. As of December 10, 2008, we had 5,788,440 shares of common stock outstanding. If the proposed sale and issuance of common stock is consummated, we will have approximately 7,788,440 shares of common stock outstanding (8,088,440 shares if the underwriters exercise their over-allotment option). As a result, our shareholders’ proportionate holding in us would be reduced by approximately 25.7% (28.4% if the underwriters exercise their over-allotment option).

 

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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, as amended, 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 in this prospectus supplement and the following:

 

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our ability to integrate the business, operations, and personnel of Northern Utilities and Granite State and to achieve the estimated potential synergy savings attributable to the Acquisitions;

 

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our, Northern Utilities’, and Granite State’s ability to retain existing customers and gain new customers;

 

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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 including recent distress in the financial markets that has had an adverse impact on the availability of credit and liquidity resources generally and could jeopardize certain of our counterparty obligations, including those of our insurers and financial institutions;

 

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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 $36.8 million (approximately $42.5 million if the underwriters’ over-allotment option is exercised in full), after deducting the underwriting discounts and our estimated offering expenses, based on an offering price of $20.00 per share.

We intend to use the net proceeds from this offering (including the proceeds from any exercise by the underwriters of their over-allotment option) and the anticipated sale and issuance of long-term unsecured notes by Granite State (i) to repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million, that we used to partially finance the Acquisitions and the related costs and expenses and (ii) for other general corporate purposes. Please see the sections entitled (i) The Acquisitions and (ii) Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

 

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CAPITALIZATION

The table below shows our capitalization as of September 30, 2008:

 

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on an actual consolidated basis; and

 

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on a pro forma basis to give effect to:

 

(i)

the receipt of the estimated net proceeds of approximately $36.8 million from the issuance of 2,000,000 shares of common stock in this offering at a public offering price of $20.00 per share and the application of the estimated net proceeds from this offering (see the section entitled Use of Proceeds in this prospectus supplement);

 

(ii)

the sale and issuance by Northern Utilities of $80.0 million aggregate principal amount of long-term unsecured notes, which closed on December 3, 2008;

 

(iii)

the anticipated sale and issuance by Granite State of $10.0 million aggregate principal amount of long-term unsecured notes, which is not contingent on this offering; and

 

(iv)

the anticipated utilization of a bridge credit facility to fund the residual portion of the Acquisitions of $38.9 million as of September 30, 2008 (please see the section entitled Prospectus Summary—The Acquisitions).

The table below (i) reflects that we financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract and (ii) assumes that we will use the net proceeds from the sale and issuance of our common stock, as described in this prospectus, and the sale and issuance of the above-referenced long-term unsecured notes to promptly repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million. Please see the section entitled Risk Factors—Risks Relating to the Acquisitions in this prospectus supplement.

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

 

		(unaudited) As of September 30, 2008
		Actual			Adjustments for Issuances of Notes and Short-Term Debt			Adjustments for this Offering			Pro forma
(in millions)
Common stock equity		$	99.9		$	—		$	36.8		$	136.7
Preferred stock, non-redeemable, non-cumulative			0.2			—			—			0.2
Preferred stock, redeemable, cumulative			1.8			—			—			1.8
Long-Term debt, less current portion			159.4			90.0			—			249.4
Short-Term debt(1)			22.1			38.9			—			61.0
Total capitalization, including short-term debt		$	283.4		$	128.9		$	36.8		$	449.1

 

(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 listed on the New York Stock Exchange under the symbol “UTL.”

As of December 10, 2008, there were 1,661 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 $20.35 on December 10, 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
		High			Low			Dividends Per Share
2005:
First Quarter		$	28.70		$	25.40		$	0.345
Second Quarter			28.75			25.35			0.345
Third Quarter			28.90			27.00			0.345
Fourth Quarter			28.17			24.15			0.345
2006:
First Quarter		$	26.11		$	24.22		$	0.345
Second Quarter			26.08			23.63			0.345
Third Quarter			25.00			23.80			0.345
Fourth Quarter			26.35			23.81			0.345
2007:
First Quarter		$	27.35		$	25.08		$	0.345
Second Quarter			28.40			26.55			0.345
Third Quarter			34.60			27.00			0.345
Fourth Quarter			30.17			25.50			0.345
2008:
First Quarter		$	29.00		$	25.55		$	0.345
Second Quarter			28.80			26.12			0.345
Third Quarter			28.05			25.40			0.345
Fourth Quarter (through December 10, 2008)			27.00			19.90			n/a

On September 25, 2008, our Board of Directors declared a dividend in the amount of $0.345 per common share, which was paid on October 31, 2008 to common shareholders of record on October 17, 2008.

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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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations, which generally relates to periods preceding the Acquisitions, 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 (i) Risk Factors—Risks Relating to Our Business, (ii) Cautionary Statement about Forward-Looking Statements and (iii) Our Company in this prospectus supplement.

Three and Nine Months Ended September 30, 2008 and 2007

Results of Operations

Our Earnings Applicable to Common Shareholders (“Net Income”) were $1.5 million for the third quarter of 2008, compared to $1.6 million for the third quarter of 2007. Earnings per common share (“EPS”) were $0.27 for the three months ended September 30, 2008 compared with $0.28 in the third quarter of 2007. Earnings for the third quarter of 2008 reflect higher operating expenses and interest expense in the quarter offset by higher electric and gas utility sales margins. For the nine months ended September 30, EPS were $1.12 for 2008 compared to $1.04 for 2007, an increase of $0.08 per share, or 8%.

The following table presents the significant items (discussed below) contributing to the change in EPS in the three and nine month periods ended September 30, 2008:

 

		Three Months Ended September 30,				Nine Months Ended September 30,
2007		$	0.28			$	1.04
Electric Sales Margin			0.01				(0.03	)
Gas Sales Margin			0.03				0.15
Usource Sales Margin			0.01				0.01
Operation and Maintenance Expense			(0.05	)			0.12
Depreciation, Amortization, and Other			—				(0.12	)
Interest Expense, Net			(0.01	)			(0.05	)
2008		$	0.27			$	1.12

Our total electric kilowatt-hour (“kWh”) sales decreased 2.0% and 2.1% in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. Natural gas sales in the three month period ended September 30, 2008 increased 5.7% compared to the same period in 2007 and decreased 0.5% in the nine month period ended September 30, 2008 compared to the same period in 2007. The lower kWh sales in 2008 compared to 2007 reflect milder summer weather in 2008 and lower average usage by our customers reflecting a slowing economy and energy conservation. The increased natural gas sales in the three month period reflect increased consumption by C&I customers for production operations. The lower natural gas sales in the nine month period reflect a milder winter heating season earlier this year and lower average usage by our customers reflecting a slowing economy and energy conservation.

Electric sales margin increased $0.1 million in the three month period ended September 30, 2008 compared to the same period in 2007, reflecting higher electric base rates partially offset by lower sales volumes. For the nine month period ended September 30, 2008, electric sales margin decreased $0.3 million

 

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compared to the same period in 2007. The decrease in electric sales margin in the nine month period primarily reflects lower sales volumes, partially offset by higher electric base rates, which were implemented in March 2008.

Gas sales margin increased $0.2 million and $1.3 million in the three and nine months ended September 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period reflects gas base rates implemented in November 2007 and higher natural gas sales to C&I customers. The increased sales margin in the nine month period reflects higher rates, partially offset by lower sales.

Revenues of Usource, Inc. and Usource LLC (collectively, “Usource”) increased by $0.1 million and $0.1 million in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007 reflecting higher revenues from energy brokering.

Operation & Maintenance (“O&M”) expenses increased $0.5 million for the three month period ended September 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher salary and benefit costs of $0.3 million, higher bad debt expenses of $0.2 million and higher utility operating costs of $0.2 million, partially offset by lower professional fees of $0.2 million. For the nine month period ended September 30, 2008, O&M expenses decreased $1.1 million compared to the same period in 2007, including a reduction of $2.8 million from the proceeds of an insurance settlement, lower utility operating costs of $0.1 million and lower professional fees of $0.1 million, partially offset by increases in salary and benefit costs of $1.5 million and higher bad debt expenses of $0.4 million.

Depreciation, Amortization & Other expenses decreased $0.1 million in the three month period ended September 30, 2008, reflecting lower amortization of information systems related costs and lower income tax expense in the current quarter compared to the same period in 2007, partially offset by higher depreciation on normal utility plant additions. For the nine month period ended September 30, 2008, Depreciation, Amortization & Other expenses increased $1.2 million, primarily reflecting the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory carrying costs deferred under a previous regulatory ruling and higher depreciation on normal utility plant additions.

Interest Expense, Net increased $0.1 million and $0.5 million for the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007, reflecting higher overall debt outstanding.

Also in the third quarter, our Board of Directors declared the regular quarterly dividend on our common stock of $0.345 per share. This quarterly dividend results in a current effective annual dividend rate of $1.38 per share representing an unbroken record of quarterly dividend payments since trading began in our common stock.

A more detailed discussion of our results of operations for the three and nine months ended September 30, 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 $9.4 million as of September 30, 2008 compared to September 30, 2007. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems, including expenditures of approximately $0.5 million for our Advanced Metering Infrastructure (“AMI”) project, which was substantially completed in the first quarter of 2008.

Regulatory Assets decreased by $30.5 million as of September 30, 2008 compared to September 30, 2007, primarily reflecting current year cost recoveries. A significant portion of this decrease is matched by a corresponding decrease of $20.0 million in Power Supply Contract Obligations. The remaining decrease

 

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primarily reflects lower levels of Regulatory Assets associated with RBO as well as recoveries of deferred charges. Please see the section entitled Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Regulatory Accounting.

Other Noncurrent Assets increased by $6.8 million as of September 30, 2008 compared to September 30, 2007, including the deferral of $3.9 million of transaction costs and $0.6 million of financing costs in connection with our pending acquisition of Northern Utilities and Granite State, discussed above, $1.6 million of pre-acquisition information system development costs and $0.7 million of other items unrelated to the acquisition.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales. Our total electric kWh sales decreased 2.0% and 2.1% in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. Electric kWh sales to residential customers in the three and nine month periods ended September 30, 2008 decreased 1.9% and 1.8%, respectively, compared to the same periods in 2007 while sales to C&I customers decreased 2.0% and 2.3%, respectively, compared to the same periods in 2007. The lower electric kWh sales in 2008 compared to 2007 were driven by lower average usage per customer reflecting milder summer temperatures, a slowing economy and energy conservation.

The following table details total electric kWh sales for the three and nine months ended September 30, 2008 and 2007 by major customer class:

 

		Three Months Ended September 30,										Nine Months Ended September 30,
kWh Sales (millions)		2008		2007		Change			% Change			2008		2007		Change			% Change
Residential		176.3		179.7		(3.4	)		(1.9	%)		506.2		515.6		(9.4	)		(1.8	%)
Commercial / Industrial		279.4		285.1		(5.7	)		(2.0	%)		794.5		813.2		(18.7	)		(2.3	%)
Total		455.7		464.8		(9.1	)		(2.0	%)		1,300.7		1,328.8		(28.1	)		(2.1	%)

Electric Operating Revenues and Sales Margin. The following table details Total Electric Operating Revenues and Sales Margin for the three and nine month periods ended September 30, 2008 and 2007:

 

		Three Months Ended September 30,													Nine Months Ended September 30,
Electric Operating Revenues and Sales Margin (millions)		2008			2007			$ Change				% Change(1)			2008			2007			$ Change				% Change(1)
Electric Operating Revenues:
Residential		$	30.9		$	28.6		$	2.3			4.0	%		$	87.0		$	87.2		$	(0.2	)		(0.1	%)
Commercial / Industrial			32.7			28.3			04.4			7.8	%			85.2			84.1			1.1			0.6	%
Total Electric Operating Revenues		$	63.6		$	56.9		$	6.7			11.8	%		$	172.2		$	171.3		$	0.9			0.5	%
Cost of Electric Sales:
Purchased Electricity		$	48.7		$	41.9		$	6.8			12.0	%		$	128.4		$	126.4		$	2.0			1.2	%
Conservation and Load Management			0.6			0.8			(0.2	)		(0.4	%)			2.0			2.8			(0.8	)		(0.5	%)
Electric Sales Margin		$	14.3		$	14.2		$	0.1			0.2	%		$	41.8		$	42.1		$	(0.3	)		(0.2	%)

 

(1)

Represents change as a percent of Total Electric Operating Revenues.

 

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Total Electric Operating Revenues, increased by $6.7 million, or 11.8%, and $0.9 million, or 0.5%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation and Land Management (“C&LM”) in Operating Expenses. The net increase in Total Electric Operating Revenues in the three month period reflects higher Purchased Electricity costs of $6.8 million and higher sales margin of $0.1 million, partially offset by lower C&LM revenues of $0.2 million. The net increase in Total Electric Operating Revenues in the nine month period reflects higher Purchased Electricity costs of $2.0 million, lower C&LM revenues of $0.8 million and lower sales margin of $0.3 million.

Purchased Electricity and C&LM revenues increased a net $6.6 million, or 11.6%, and $1.2 million, or 0.7%, of Total Electric Operating Revenues in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period primarily reflects higher electric commodity prices, partially offset by lower sales volumes. The increase in the nine month period reflects higher electric commodity prices, largely offset by lower sales volumes and lower spending on energy efficiency and conservation programs. 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 increased $0.1 million in the three month period ended September 30, 2008 compared to the same period in 2007, reflecting higher electric base rates partially offset by lower sales volumes. For the nine month period ended September 30, 2008, electric sales margin decreased $0.3 million compared to the same period in 2007. The decrease in electric sales margin in the nine month period primarily reflects lower sales volumes, partially offset by higher electric base rates, which were implemented in March 2008. Total electric kWh sales decreased 2.0% and 2.1% in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007, driven by milder weather and lower average usage per customer reflecting a slowing economy and energy conservation.

Gas Sales, Revenues and Margin

Therm Sales. Our total therm sales of natural gas increased 5.7% in the three month period ended September 30, 2008 compared to the same period in 2007. Gas sales to residential customers in the three month period ended September 30, 2008 were flat compared to the same period in 2007 while sales to C&I customers increased 7.1% in that period compared to the same period in 2007. The increase in gas sales to C&I customers in the three month period reflects increased usage of natural gas in their production operations.

Total therm sales of natural gas in the nine month period ended September 30, 2008 decreased 0.5% compared to the same period in 2007. Gas sales to residential customers in the nine month period ended September 30, 2008 decreased 2.5% compared to the same period in 2007 while sales to C&I customers increased 0.7% in that period compared to the same period in 2007. The lower sales to residential customers in 2008 reflects a milder winter heating season earlier this year and lower average usage by our customers reflecting a slowing economy and energy conservation. The increase in gas sales to C&I customers in the nine month period reflects increased usage of natural gas in those customers’ production operations.

 

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The following table details total therm sales for the three and nine months ended September 30, 2008 and 2007 by major customer class:

 

		Three Months Ended September 30,									Nine Months Ended September 30,
Therm Sales (millions)		2008		2007		Change		% Change			2008		2007		Change			% Change
Residential		0.7		0.7		—		—			7.7		7.9		(0.2	)		(2.5	%)
Commercial / Industrial		3.0		2.8		0.2		7.1	%		13.9		13.8		0.1			0.7	%
Total		3.7		3.5		0.2		5.7	%		21.6		21.7		(0.1	)		(0.5	%)

Gas Operating Revenues and Sales Margin. The following table details Total Gas Operating Revenues and Sales Margin for the three and nine months ended September 30, 2008 and 2007:

 

		Three Months Ended September 30,												Nine Months Ended September 30,
Gas Operating Revenues and Sales Margin (millions)		2008			2007			$ Change			% Change(1)			2008			2007			$ Change				% Change(1)
Gas Operating Revenues:
Residential		$	2.1		$	1.8		$	0.3		7.7	%		$	13.7		$	13.6		$	0.1			0.4	%
Commercial / Industrial			2.3			2.1			0.2		5.1	%			11.6			10.9			0.7			2.9	%
Total Gas Operating Revenues		$	4.4		$	3.9		$	0.5		12.8	%		$	25.3		$	24.5		$	0.8			3.3	%
Cost of Gas Sales:
Purchased Gas		$	2.4		$	2.1		$	0.3		7.7	%		$	15.3		$	15.8		$	(0.5	)		(2.0	%)
Conservation and Load Management			—			—			—		—				0.1			0.1			—			—
Gas Sales Margin		$	2.0		$	1.8		$	0.2		5.1	%		$	9.9		$	8.6		$	1.3			5.3	%

 

(1)

Represents change as a percent of Total Gas Operating Revenues.

Total Gas Operating Revenues increased $0.5 million, or 12.8%, and $0.8 million, or 3.3%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. Total Gas Operating Revenues include the recovery of the cost of gas sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The net increase in Total Gas Operating Revenues in the three month period reflects higher Purchased Gas costs of $0.3 million and higher gas sales margin of $0.2 million. The net increase in Total Gas Operating Revenues in the nine month period reflects higher gas sales margin of $1.3 million, partially offset by lower Purchased Gas costs of $0.5 million.

Purchased Gas and C&LM revenues increased by $0.3 million, or 7.7% of Total Gas Operating Revenues in the three month period ended September 30, 2008 compared to the same period in 2007 and decreased $0.5 million, or 2.0% of Total Gas Operating Revenues in the nine month period ended September 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher sales volumes and higher natural gas commodity prices. The decrease in the nine month period reflects lower sales volumes and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher natural gas commodity prices. Purchased Gas revenues include the recovery of the cost of gas purchased and manufactured to supply our total gas supply requirements as well as 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.

 

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Gas sales margin increased $0.2 million and $1.3 million in the three and nine months ended September 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period reflects gas base rates implemented in November 2007 and higher natural gas sales to C&I customers. The increased gas sales margin in the nine month period reflects higher rates, partially offset by lower sales.

Operating Revenue – Other

The following table details total Other Operating Revenue for the three and nine months ended September 30, 2008 and 2007:

 

		Three Months Ended September 30,												Nine Months Ended September 30,
(millions)		2008			2007			$ Change			% Change			2008			2007			$ Change			% Change
Other		$	1.1		$	1.0		$	0.1		10.0	%		$	2.9		$	2.8		$	0.1		3.6	%
Total Other Operating Revenue		$	1.1		$	1.0		$	0.1		10.0	%		$	2.9		$	2.8		$	0.1		3.6	%

Total Other Operating Revenue increased by $0.1 million, or 10.0%, and $0.1 million, or 3.6%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. These increases reflect higher revenues from our non-regulated energy brokering business, Usource.

Operating Expenses

Purchased Electricity. Purchased Electricity expenses include the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity increased $6.8 million, or 16.2%, and $2.0 million, or 1.6%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. These increases reflect higher electric commodity prices, partially offset by lower sales volumes. 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 expenses increased by $0.3 million, or 14.3%, in the three month period ended September 30, 2008 compared to the same period in 2007 and decreased $0.5 million, or 3.2% in the nine month period ended September 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher sales volumes and higher natural gas commodity prices. The decrease in the nine month period reflects lower sales volumes and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher natural gas commodity prices. 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. O&M expenses increased $0.5 million for the three month period ended September 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher salary and benefit costs of $0.3 million, higher bad debt expenses of $0.2 million and higher utility operating costs of $0.2 million, partially offset by lower professional fees of $0.2 million. For the nine month period ended September 30, 2008, O&M expenses decreased $1.1 million compared to the same period in 2007, including a reduction of $2.8 million from the proceeds of an insurance settlement, lower utility operating costs of $0.1 million and lower professional fees of $0.1 million, partially offset by increases in salary and benefit costs of $1.5 million and higher bad debt expenses of $0.4 million.

 

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Conservation and 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 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.

Total C&LM expenses decreased $0.2 million, or 25.0% and $0.8 million, or 27.6%, in the three and nine month periods ended September 30, 2008 compared to the same periods in 2007. These changes reflect 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.

Depreciation, Amortization and Taxes

Depreciation and Amortization. Depreciation and Amortization expense increased by $0.1 million, or 2.2%, and $0.9 million, or 6.7%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period primarily reflects higher depreciation on normal utility plant additions, partially offset by lower amortization of information systems related costs. The increase in the nine month period primarily reflects the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory carrying costs deferred under a previous regulatory ruling and higher depreciation on normal utility plant additions.

Local Property and Other Taxes. Local Property and Other Taxes increased by $0.1 million, or 7.7%, and by $0.3 million, or 7.1%, in the three and nine month periods ended September 30, 2008, respectively, compared to the same periods in 2007. These increases were 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 lower by $0.3 million in the three month period ended September 30, 2008 compared to the same period in 2007 reflecting lower pre-tax earnings and a lower effective tax rate year over year due to the recognition of higher permanent book/tax differences, including higher tax credits and prior year tax return true-up adjustments, in the third quarter of 2008. Federal and State Income Taxes were lower by $0.2 million in the nine month period ended September 30, 2008 compared to the same period in 2007 reflecting a lower effective tax rate year over year due to the same items discussed above.

Other Non-Operating Expense (Income)

Other Non-Operating Expenses (Income) were flat in the three month period ended September 30, 2008 compared to the same period in 2007 and increased by $0.2 million in the nine month period ended September 30, 2008 compared to the same period in 2007. The increase in the nine month period reflects an adjustment of $0.1 million in conjunction with our electric base distribution rate increase in Massachusetts which was implemented in March 2008.

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 retail distribution utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated.

 

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We operate a number of reconciling rate mechanisms to recover from our customers 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 September 30,												Nine Months Ended September 30,
Interest Expense, Net (millions)		2008				2007				Change				2008				2007				Change
Interest Expense
Long-Term Debt		$	2.9			$	2.9			$	—			$	8.6			$	8.2			$	0.4
Short-Term Debt			0.1				0.1				—				0.5				0.8				(0.3	)
Regulatory Liabilities			—				0.1				(0.1	)			0.1				0.4				(0.3	)
Subtotal Interest Expense			3.0				3.1				(0.1	)			9.2				9.4				(0.2	)
Interest Income
Regulatory Assets			(0.6	)			(0.7	)			0.1				(1.9	)			(2.2	)			0.3
AFUDC and Other(1)			—				(0.1	)			0.1				—				(0.4	)			0.4
Subtotal Interest Income			(0.6	)			(0.8	)			0.2				(1.9	)			(2.6	)			0.7
Total Interest Expense, Net		$	2.4			$	2.3			$	0.1			$	7.3			$	6.8			$	0.5

 

(1)

AFUDC means Allowance for Funds Used During Construction.

Interest Expense, Net increased $0.1 million for the three month period ended September 30, 2008 compared to the same period in 2007. The increase in the three month period reflects lower Allowance for Funds Used During Construction (“AFUDC”) and interest earned on regulatory assets . For the nine month period ended September 30, 2008, Interest Expense, Net increased $0.5 million compared to the same period in 2007, reflecting higher interest expense associated with an increase in long-term debt outstanding and lower AFUDC and interest earned on regulatory assets compared to the prior period.

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, please refer to the financial statements and 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.

 

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Regulatory Accounting

Our principal business is the distribution of electricity and natural gas by our retail distribution utilities: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and 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.

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 distribution utilities 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.

 

		September 30,						December 31,
Regulatory Assets consist of the following (millions)		2008			2007			2007
Power Supply Buyout Obligations		$	57.7		$	77.7		$	72.7
Deferred Restructuring Costs			28.1			29.5			30.5
Generation-related Assets			1.0			1.8			1.6
Subtotal – Restructuring Related Items			86.8			109.0			104.8
Retirement Benefit Obligations			35.2			37.3			35.1
Income Taxes			13.4			17.9			14.6
Environmental Obligations			11.6			13.1			13.1
Other			3.3			3.5			2.9
Total Regulatory Assets		$	150.3		$	180.8		$	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” (“SFAS No. 101”). 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

 

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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 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, 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 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”), FASB Statement No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” (SFAS No. 106”), and FASB Statement 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 RBOs 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

 

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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. Please see Note 8 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2008, 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 FASB Statement No. 109, “Accounting for Income Taxes” (“SFAS No. 109”) and under FASB Interpretation No. (“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 September 30, 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 September 30, 2008, which is incorporated herein by reference.

Please see Note 1 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2008, which is incorporated herein by reference.

Labor Relations

As of September 30, 2008, we had 305 employees, of which 82 were represented by labor unions. 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.

 

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Quantitative and Qualitative Disclosures about Market Risk

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 September 30, 2008 and 2007 were 3.03% and 5.71%, respectively. The average interest rates on our short-term borrowings for the nine months ended September 30, 2008 and 2007 were 3.28% and 5.75%, respectively.

Market Risk

Although our retail distribution utilities 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, we have divested our commodity-related contracts and therefore further reduced our exposure to commodity risk.

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 was $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 EPS in 2007 as compared to 2006:

2007 Earnings Per Common Share vs. 2006

 

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

 

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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 electric 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.

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 per share, 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.

 

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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.

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 electric 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 electric 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 electric 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 Electric 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 and 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.

 

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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 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.

 

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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	%

Gas Operating Revenues and Sales Margin. The following table details Total Gas Operating Revenue and Gas 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)
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 and 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.

 

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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 territory 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 Operating 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 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 Operating 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 Operating 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 earnings.

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.

 

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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 and 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.

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

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

 

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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 retail distribution utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated. Please 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 retail distribution utilities. 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.

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.

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.

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.

As of December 31, 2007, there were approximately 85 employees represented by labor unions. These employees are covered by collective bargaining agreements, which expire on 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 management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the

 

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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, please refer to the financial statements and 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.

Regulatory Accounting

Our principal business is the distribution of electricity and natural gas by our retail distribution utilities: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the MDPU and UES is regulated by the NHPUC. Accordingly, we use the provisions of 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 SFAS No. 101. 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.

 

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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 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, and SFAS No. 106. 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. Please 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. Please 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 earnings 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.

 

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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 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.

Please refer to 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, 4, 5, 7, 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.

Liquidity, Commitments and Capital Requirements

Sources of Capital

We, along with Northern Utilities and Granite State, 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. 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.

At September 30, 2008 and December 31, 2007, we had an aggregate of $37 million and $30.0 million, respectively, in unsecured revolving lines of credit. We had short-term debt outstanding through bank borrowings of $21.7 million and $13.0 million at September 30, 2008 and 2007, respectively. 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. On November 26, 2008, we entered into a $60 million, 364-day revolving credit agreement with Bank of America, as administrative agent, and a syndicate of lenders. This facility replaces certain bilateral credit agreements with Bank of America and RBS Citizens, N.A. Borrowings under the revolving credit agreement bear interest at a floating annual rate equal to the daily

 

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LIBOR (the London Interbank Offered Rate) reported by the British Banking Association plus the applicable margin. We have the option of locking in the daily rate applicable to outstanding loans for one-, two-, three- or six-month interest periods. The “applicable margin” is initially equal to 1.75%, but may be increased over time if we do not meet specified conditions with respect to our equity capital. As of December 10, 2008, we had approximately $30.3 million outstanding under our revolving credit agreement.

The revolving credit agreement contains customary terms and conditions for credit facilities of this type, including certain financial covenants, including, without limitation, covenants restricting our ability to incur liens, merge or consolidate with another entity or change our line of business. The revolving credit agreement also contains a covenant restricting our ability to permit long-term debt to exceed 65% of our capitalization at the end of each fiscal quarter until the revolving credit agreement terminates and all amounts borrowed under the revolving credit agreement are paid in full.

The events of default under the revolving credit agreement include, but are not limited to, the following: (i) failure to pay outstanding principal or interest, (ii) failure of representations or warranties to be correct, in any material respects, (iii) failure to perform any other term, covenant or agreement and such failure is not remedied within 30 days of notice of such failure, (iv) a cross-default with other debt in certain circumstances, (v) a change of control, (vi) non-appealable judgments in excess of an agreed amount, (vii) certain defaults on obligations under the Employee Retirement Income Security Act or (viii) bankruptcy. Such events of default would require the repayment of any outstanding borrowings and the termination of the right to borrow additional funds under the revolving credit agreement.

Upon completion of the offering of common stock, as described in this prospectus supplement, and the sale and issuance of the Granite State notes, we believe that we will be in compliance with the debt to capitalization ratio covenant contained in the revolving credit agreement at December 31, 2008. However, unless we are able to raise funds by issuing additional common stock or to negotiate a waiver or amendment to this covenant, we will be restricted in our ability to incur any material amount of additional indebtedness in future quarters in compliance with this covenant.

Certain of our or our subsidiaries’ outstanding notes and agreements for indebtedness have similar debt to capitalization ratios that may restrict our or their ability to incur additional indebtedness.

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 financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility, as described below, coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract. We closed the Acquisitions on December 1, 2008.

We expect to repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million, as soon as practicable using the net proceeds from: (i) the offering of our common stock, as described in this prospectus; and (ii) the anticipated sale and issuance by Granite State to institutional investors in a private placement of $10.0 million aggregate principal amount of long-term unsecured notes on December 15, 2008. We expect to repay the estimated $38.9 million balance outstanding under the bridge credit facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt or using borrowings under a revolving credit facility. Please see Note 4 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2008, which is incorporated herein by reference.

As of December 10, 2008, we had approximately $85.7 million outstanding under the bridge credit facility, which provides for a loan for up to eleven months. Amounts outstanding under the bridge credit

 

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facility accrue interest at either the Eurodollar Rate or the base rate, in each case plus the applicable margin. The Eurodollar Rate is based on an applicable LIBOR (the London Interbank Offered Rate) as increased by statutory reserve requirements. The base rate is the higher of (i) the rate of interest announced publicly by Royal Bank of Canada from time to time and (ii) the Federal Funds Rate plus 0.50%. The applicable margin is a range of interest rates that varies from 2.50% to 5.00% depending on the remaining term of the borrowings. The bridge credit facility also contains customary terms and conditions, including, without limitation, covenants restricting our ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all substantially all of our assets.

On September 12, 2008, we priced the sale and issuance of $80.0 million aggregate principal amount of senior unsecured notes by Northern Utilities, which we closed on December 3, 2008, and the anticipated sale and issuance of $10.0 million aggregate principal amount of senior unsecured notes by Granite State, subject to the conditions discussed below. The notes consist of:

 

(i)

$30.0 million aggregate principal amount of 6.95% senior unsecured notes of Northern Utilities, which are due in 2018;

 

(ii)

$50.0 million aggregate principal amount of 7.72% senior unsecured notes of Northern Utilities, which are due in 2038; and

 

(iii)

$10.0 million aggregate principal amount of 7.15% senior unsecured notes of Granite State, which are due in 2018, along with a guarantee from us for the payment of principal, interest and other amounts payable on the Granite State notes.

We agreed to guarantee the payment of principal, interest and other amounts payable on the Granite State notes. This guarantee will terminate if Granite State is reorganized and merges with and into Northern Utilities.

The foregoing is not intended to, and does not, constitute an offering of the notes described above. The sale and issuance of the Granite State notes (i) is subject to the execution of a definitive note purchase agreement by Granite State and the prospective purchasers of the notes and satisfaction of closing conditions and (ii) will not be, and has not been, registered under the Securities Act and the notes may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements. We have received the required regulatory approvals from the NHPUC and the MPUC for the sale and issuance of the notes.

We, along with our subsidiaries, are individually and collectively members of the Unitil Cash Pool (the “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 September 30, 2008 and December 31, 2007, all of our subsidiaries were in compliance with the regulatory requirements to participate in the Cash Pool.

 

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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 provide limited guarantees on certain energy contracts entered into by our regulated subsidiaries. Our policy is to limit these guarantees to the duration of the contracts. As of September 30, 2008, there were approximately $6.0 million of guarantees outstanding and the longest term guarantee extends through October 31, 2009.

We also guarantee the payment of principal, interest and other amounts payable on the notes issued by Unitil Realty. As of September 30, 2008, the principal amount outstanding for the 8% Unitil Realty notes was $4.8 million.

In addition, Northern Utilities entered into a gas storage management agreement pursuant to which (i) Northern Utilities released certain pipeline and storage capacity to an asset manager from November 1, 2008 through March 31, 2009 or April 30, 2009 and (ii) the asset manager financed inventories associated with the released storage capacity from Northern Utilities contemporaneously with the closing of the Acquisitions. The agreement also requires Northern Utilities to repurchase quantities of natural gas over the 2008/2009 winter heating season at a specified price and any remaining balance of the gas inventories on April 30, 2009 at the same price initially paid by the asset manager. The agreement provides for us to issue a guarantee of payment of $15 million for the term of the agreement.

We expect to guarantee the payment of principal, interest and other amounts payable on the $10 million Granite State notes due 2018, as described above. This guarantee will terminate if Granite State reorganizes and merges with and into Northern Utilities, as discussed in Note 4 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2008, which is incorporated herein by reference.

 

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Benefit Plan Funding

In September 2008, we, along with our subsidiaries (other than Northern Utilities and Granite State), made cash contributions to our Pension Plan in the amount of $2.8 million. In 2007 and 2006, we, along with our subsidiaries (other than Northern Utilities and Granite State), made cash contributions to our Pension Plan in the amount of $2.8 million and $2.5 million, respectively. Through September 30, 2008, we, along with our subsidiaries (other than Northern Utilities and Granite State), contributed approximately $1.6 million to Voluntary Employee Benefit Trusts (“VEBT”). We project additional contributions of approximately $1.1 million in the fourth quarter of 2008. In 2007 and 2006, we, along with our subsidiaries (other than Northern Utilities and Granite State), contributed approximately $2.5 million and $2.2 million, respectively, to VEBTs. We, along with our subsidiaries, expect to continue to make contributions to our Pension Plan and the VEBTs in future years in amounts consistent with the amounts recovered in retail distribution utility rates for these other postretirement benefit costs. Please 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.

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. Please 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 for the Nine Months Ended September 30

The tables below summarize the major sources and uses of cash (in millions) for the nine months ended September 30, 2008 compared to the same period in 2007.

 

(millions)		2008			2007
Cash Provided by Operating Activities		$	27.1		$	23.6

Cash Provided by Operating Activities

Cash Provided by Operating Activities was $27.1 million during the nine months ended September 30, 2008, an increase of $3.5 million over the comparable period in 2007. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes was $23.2 million and $16.9 million in the first nine months of 2008 and 2007, respectively. Changes in Current Assets and Liabilities (working capital) provided $1.2 million and $3.5 million in cash flow in the 2008 and 2007 nine-month periods, respectively. Deferred Restructuring Charges provided $2.4 million and $1.5 million in cash in the first nine months of 2008 and the same period in 2007, respectively. All other items resulted in net sources of cash of $0.3 million and $1.7 million in the first nine months of 2008 and 2007, respectively.

 

(millions)		2008				2007
Cash (Used in) Investing Activities		$	(20.6	)		$	(25.9	)

 

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Cash (Used in) Investing Activities

Cash used in Investing Activities was $20.6 million for the nine months ended September 30, 2008, a decrease in capital spending of $5.3 million over the comparable period in 2007. This is mainly due to the funding in 2007 and the completion in 2008 of our AMI project. In the first nine months of 2007, capital expenditures included approximately $5.9 million of cash outlays for investment in the AMI project.

 

(millions)		2008				2007
Cash Provided by (Used in) Financing Activities		$	(6.1	)		$	1.9

Cash Provided by (Used in) Financing Activities

Cash used in Financing Activities was $6.1 million in the nine months ended September 30, 2008. Uses of cash primarily reflect our regular quarterly dividend payments on common and preferred stock, expenditures related to our acquisition of Northern Utilities and Granite State, discussed above, and the scheduled repayment of long-term debt. Proceeds from the issuance of common stock through our stock plans and additional short-term debt provided $3.6 million of cash in 2008. In the second quarter of 2007, we received cash proceeds of $20.0 million from the issuance of senior long-term notes, which were used to pay down short-term debt.

Cash Flows for the Twelve Months Ended December 31

The tables below summarize the major sources and uses of cash 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	)

 

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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 Senior Long-Term Notes in 2007 and the $15 million in of Series O, 6.32% First Mortgage Bonds 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.

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. We expect to issue the notes for Northern Utilities and Granite State with similar covenants and restrictions, including, without limitation, covenants restricting our ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all of our assets. Please 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. We expect that the long-term debt for Northern Utilities and Granite State will also be privately held. For these reasons, our and our subsidiaries’ debt securities are not publicly rated, and we do not expect the debt securities of Northern Utilities and Granite State to be publicly rated.

We financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility, coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract. The bridge credit facility contains customary terms and conditions, including, without limitation, covenants restricting our ability to (i) pay dividends, (ii) incur indebtedness and liens, (iii) merge or consolidate with another entity or (iv) sell, lease or otherwise dispose of all or substantially all of our assets.

On November 26, 2008, we entered into a $60 million, 364-day revolving credit agreement. The revolving credit agreement contains customary terms and conditions, including certain financial covenants, including, without limitation, covenants restricting our ability to incur liens, merge or consolidate with

 

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another entity or change our line of business. The revolving credit agreement also contains a covenant restricting our ability to permit long-term debt to exceed 65% of our capitalization until the revolving credit agreement terminates and all amounts borrowed under the revolving credit agreement are paid in full.

Quantitative and Qualitative Disclosures about Market Risk

Interest Rate Risk

As discussed above, we, along with Northern Utilities and Granite State, 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, including Northern Utilities, 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, we have divested our commodity-related contracts and therefore further reduced our exposure to commodity risk.

Please also see the section entitled Risk Factors in this prospectus supplement.

 

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OUR COMPANY

The following is a description of our company as it existed prior to the consummation of the Acquisitions, which we closed on December 1, 2008. As such, the description generally excludes information about Northern Utilities and Granite State. For a description of Northern Utilities and Granite State, please see the sections entitled (i) Prospectus Summary—The Acquisitions, (ii) The Acquisitions, (iii) Northern Utilities and (iv) Granite State.

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 companies described on the following page (the “Unitil companies”).

Our principal business is the retail distribution of electricity in the southeastern seacoast and state capital regions 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 territory. Our retail distribution utilities are local “pipes and wires” utility distribution companies with a combined investment in Net Utility Plant of $256.0 million at September 30, 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 and $200.4 million for the nine months ended September 30, 2008, 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 the cost of purchased electricity and natural gas. Earnings applicable to common shareholders for 2007 were $8.6 million and for the nine months ended September 30, 2008 were $6.4 million. Substantially all of our earnings are derived from the return on investment in our retail distribution utilities.

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 C&I 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, on December 1, 2008,

 

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we purchased (i) all of the outstanding capital stock of Northern Utilities, a retail 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 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. Please see the sections entitled (i) Risk Factors—Risks Relating to the Acquisitions in this prospectus supplement, (ii) Prospectus Summary—Summary Unaudited Pro Forma Combined Financial Data and (iii) The Acquisitions.

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

We became the direct parent of Northern Utilities and Granite State upon the closing of the 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 nine months ended September 30, 2008, the revenues from our electric utility operations were approximately $225.0 million and $172.2 million, respectively. Earnings from our electric utility operations were $7.3 million for the year ended December 31, 2007 and $4.4 million for the nine months ended September 30, 2008.

The primary business of our electric utility operations is the retail distribution of electricity to customers in our service territory. 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 electricity supplied by UES and FG&E 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 seacoast and state capital regions of New Hampshire, including the towns of Hampton, Exeter, Atkinson, and Plaistow. UES’ service territory consists 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’ service territory and includes the executive, legislative and judicial branches and offices and facilities for all major state government agencies as well as several federal government facilities. In addition, UES’ service territory includes retail trading and recreation centers for the central and southeastern parts of the state. These areas serve diversified C&I businesses, including manufacturing firms engaged in the production of electronic components, wires, and plastics. Our service territory includes popular resort areas and beaches along the Atlantic Ocean, including the Hampton Beach recreational area. UES’ 2007 retail electric operating revenue was $157.8 million, of which approximately 51% was derived from residential sales and 49% from C&I sales.

FG&E is engaged principally in the retail distribution of both electricity and natural gas in the city of Fitchburg in north central Massachusetts 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 C&I sales.

Our Gas Utility Operations Prior to the Acquisitions

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 from customers 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 C&I firm sales. FG&E’s gas operating revenue was $25.3 million for the nine months ended September 30, 2008. Earnings from FG&E’s gas utility operations were $1.0 million for the year ended December 31, 2007, and $1.9 million for the nine months ended September 30, 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, non-utility operations are conducted through Unitil Resources. Unitil Resources 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 C&I customers in the northeastern United States. For the year ended December 31, 2007 and the nine months ended September 30, 2008, the revenues from our non-regulated operations were $3.7 million and $2.9 million, respectively. Earnings from our non-regulated operations were $0.3 million for the year ended December 31, 2007, and $0.3 million for the nine months ended September 30, 2008.

Our other non-utility subsidiaries are Unitil Realty and Unitil Service. 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 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 energy supply 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. Granite State, as an interstate natural gas pipeline, is regulated by the FERC.

Our retail distribution utilities deliver electricity and/or natural gas to all customers in our service territory, 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

 

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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, on a pass-through basis from customers, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

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. Please 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.

On March 31, 2008, we, along with Northern Utilities, filed joint petitions and supporting testimony with the MPUC and the NHPUC requesting approval of our acquisition of Northern Utilities. On May 30, 2008, we, along with Northern Utilities, filed joint petitions with the MPUC and NHPUC requesting authority for Northern Utilities to issue unsecured long-term debt to assist in financing our acquisition of Northern Utilities. On August 22, 2008 and August 15, 2008, we, along with Northern Utilities and the active parties to the respective Maine and New Hampshire proceedings, filed with the MPUC and the NHPUC, respectively, unopposed settlement agreements resolving all outstanding issues and recommending approval of our acquisition of Northern Utilities and the financing petitions.

Although separately negotiated and filed with the MPUC and the NHPUC, the settlement agreements reflect several common topics (including regulatory authorizations, matters affecting rates, customer service provisions, service quality, gas safety and reliability, agreements regarding Granite State and reporting requirements) as follows:

Authorizations

The settlement agreements include the following authorizations and approvals:

 

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approval of our acquisition of Northern Utilities;

 

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approval of the amended Unitil Service Agreement adding Northern Utilities as a party;

 

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approval of the amended Unitil Cash Pooling Agreement adding Northern Utilities as a party; and

 

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approval of Northern Utilities’ accounting deferral and 10-year amortization of transaction costs and transition costs resulting from our acquisition of Northern Utilities on condition of our agreement that we will not seek recovery of these costs, or the transaction or transition costs of any other utility subsidiary, in rates.

 

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Rate Matters

The settlement agreements include the following commitments related to rates:

 

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agreement that synergy savings resulting from our acquisition of Northern Utilities will be retained by us until the next base rate change and then will flow to ratepayers;

 

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agreement not to request a base rate change for Northern Utilities before November 1, 2010 unless (i) Northern Utilities’ projected annual revenues are more than 8% below the level of total 2007 distribution revenues or (ii) the MPUC or NHPUC, as applicable, approves a plan to subject Granite State’s rates to state regulation;

 

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agreement to allow Northern Utilities to recover prudently incurred integration costs for capitalized expenditures to build or upgrade systems or facilities required to independently operate Northern Utilities;

 

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agreement not to seek recovery in Northern Utilities’ rates of any acquisition premium resulting from our acquisition of Northern Utilities and that any acquisition adjustment (positive or negative) shall be accounted for over a 10-year period and accrue to our shareholders;

 

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agreement to hold Northern Utilities’ customers harmless for the elimination of historical accumulated deferred income tax (“ADIT”) liabilities resulting from its Internal Revenue Service Section 338(h)(10) election by maintaining pro forma regulatory accounting for use in setting rates until such time as the level of ADIT balances at closing are reconciled;

 

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agreement to use an imputed weighted cost of debt for ratemaking purposes until Northern Utilities’ existing debt instruments would have matured, and not to seek recovery of any equity issuance costs for the proposed transaction; and

 

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agreement not to change Northern Utilities’ existing depreciation rates for its Maine division until approved in the next general rate case.

Customer Provisions

The settlement agreements also contain the following commitments related to customers:

 

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agreement to implement a Low Income Program for Northern Utilities’ Maine division, to provide additional customer payment options (including credit or debit cards and by internet and telephone) for Maine customers and to continue low income programs in Northern Utilities’ New Hampshire division;

 

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agreement to review with the parties to the settlements communications that we develop to inform Northern Utilities’ customers about our acquisition of Northern Utilities and to keep them apprised of the transition; and

 

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with respect to Maine, agreement to conduct a study of alternatives for the sale, lease, or use of the unused Portland manufactured gas site property that would best serve ratepayers’ interests.

Service Quality, Gas Safety and Reliability

The settlement agreements contain the following commitments related to service quality, gas safety and reliability:

 

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agreement to improve and adhere to Northern Utilities’ existing service quality plans in each jurisdiction; and

 

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agreement to provide notifications and safety reports based on several service quality and gas safety metrics, as well as implementing gas operations programs and practices.

Granite State

The settlement agreements contain the following commitments related to Granite State:

 

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agreement to work collaboratively with the parties to the settlements to design and to conduct a comprehensive study of the issues and costs for modification of the physical, operational, regulatory, and corporate structure necessary for state regulation of Granite State and to provide a report within one year of the closing; and

 

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authorization for Northern Utilities to execute a firm service contract with Granite State for 100,000 Dekatherms (“Dth”) of capacity at Granite State’s current recourse rate of $1.6666/ Dth for the period November 1, 2008 through October 31, 2010.

Reporting

The settlement agreements contain the following commitments regarding affiliate books and records and transaction reporting:

 

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agreement to provide timely access to the books and records of any of Northern Utilities’ affiliates at the discretion of the MPUC or the NHPUC, as applicable;

 

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agreement to file reports on our transition progress, business integration, costs, the Transition Services Agreement and costs while our acquisition of Northern Utilities was pending; and

 

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agreement to notify the MPUC and the NHPUC of any substantial changes in the financing terms.

On October 10, 2008, the NHPUC issued orders approving the settlement agreement and the financing petition and authorizing our acquisition of Northern Utilities. The NHPUC approved the settlement agreement in its entirety without conditions. Northern Utilities will continue to be regulated by the NHPUC.

On October 6, 2008, the MPUC publicly deliberated the matter and voted to approve the joint petition filed on March 31, 2008 and settlement agreement with conditions, subject to its issuance of a final written order. On October 22, 2008, the MPUC issued a written decision approving the settlement agreement and authorizing our acquisition of Northern Utilities, subject to several conditions related to: (i) our commitment to implement the MPUC’s Management Audit recommendations regarding Northern Utilities’ Operations and Safety Practices; (ii) Northern Utilities’ compliance with certain gas safety-related obligations of Northern Utilities under a stipulation in separate proceedings (the “NOPV Stipulation”), and placing all of the cost responsibility on NiSource; and (iii) our commitment to evaluate the costs and benefits of state regulation of Granite State. One condition would have potentially contravened the allocation of risks agreed to in the settlement agreement and the Stock Purchase Agreement with regard to several pending regulatory safety and compliance proceedings involving Northern Utilities that were addressed in the NOPV Stipulation. On October 28, 2008, we filed a joint petition with Northern Utilities for reconsideration of the October 22, 2008 decision on narrow grounds requesting clarification and/or modification of a condition of approval contained in the decision regarding the allocation of risk between NiSource and us for certain future compliance costs under the NOPV Stipulation. On November 5, 2008, the MPUC issued an Order on Reconsideration Modifying Conditions, which modified the allocation of risk established in the October 22, 2008 decision. On November 10, 2008, we filed a joint Emergency Petition with Northern Utilities for reconsideration of the November 5, 2008 Order seeking clarification or modification of the modified condition addressing the allocation of risk between NiSource and us for certain compliance costs under the NOPV Stipulation, which petition was withdrawn on November 20, 2008. On November 20, 2008, the

 

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MPUC also orally approved a Stipulation and Agreement (the “November 20 Stipulation”) to resolve certain outstanding issues raised by Northern Utilities in its pending Motion for Reconsideration regarding the NOPV Stipulation. Under the November 20 Stipulation, we, Northern Utilities and prosecutorial staff agreed to an estimate and allocation of costs for future compliance activities. On November 21, 2008, the MPUC issued its order approving the November 20 Stipulation in which the parties agreed on what regulator station improvements recommended by SEA Consulting will be implemented. As part of the November 21, 2008 order, the MPUC rescinded the condition limiting Northern Utilities’ ability to challenge the recommendation of SEA Consulting because the condition is no longer necessary as a result of the November 20 Stipulation. The November 5, 2008 Order on Reconsideration Modifying Conditions in the acquisition proceeding is final, as the appeal period has expired. Northern Utilities will continue to be regulated by the MPUC. See the section entitled Northern Utilities, Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As a result of statutory changes in Massachusetts, on August 13, 2008, we, along with Bay State, filed a joint petition with the MDPU requesting an advisory ruling that Massachusetts law is not applicable to the acquisition of Northern Utilities, or, in the alternative, that the MDPU approve the acquisition as consistent with the public interest. The Massachusetts Attorney General asserted that Massachusetts law grants the MDPU jurisdiction to review the transaction and argued that Bay State’s customers will be harmed by the sale. We, along with Bay State, disputed the Attorney General’s assertions. On October 1, 2008, the MDPU held a hearing on the joint petition, and on October 10, 2008 and October 17, 2008, Unitil and Bay State and the Attorney General filed their initial and reply briefs, respectively. On November 18, 2008, the MDPU issued an order approving our acquisition of Northern Utilities. The order is final, as the appeal period has expired.

Regulatory Matters

FG&E – Electric Division

On August 17, 2007, FG&E filed an electric distribution rate increase of $3.3 million, which represented an increase of 4.7% over FG&E’s 2006 total electric operating revenue. The MDPU 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 received a final order from the MDPU on February 29, 2008 approving an electric rate increase of $2.1 million, which represented a 3.0% increase over test year levels, with an effective date for new electric rates of March 1, 2008. On December 3, 2007, FG&E submitted its annual reconciliation of costs and revenues for Transition, Transmission, Standard Offer Service, and Default Service filed under its restructuring plan. The rates were approved effective January 1, 2008, subject to reconciliation pursuant to the MDPU’s investigation. On June 6, 2008, FG&E submitted a revised Transition Charge reducing the recovery of net costs associated with the sale of FG&E’s 0.1822% interest in Wyman IV, an oil-fired electric generating station in Yarmouth, Maine, by $36,762 pursuant to an agreement with the Attorney General. This filing was approved on August 19, 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.

 

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On January 26, 2007, the MDPU approved a rate settlement agreement between FG&E and the Attorney General of Massachusetts for FG&E’s gas division (the “Gas Division”). Under the settlement agreement, 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 agreement 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 for gas and electric distribution utilities, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utility’s distribution revenues on sales. Revenue decoupling is intended to remove 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. On July 16, 2008, the MDPU issued an order establishing a comprehensive plan for decoupling to be adopted by gas and electric distribution utilities on a going-forward basis. Company specific rate cases will be required. Lost base revenue recovery associated with incremental energy efficiency savings will be allowed through 2012 consistent with the MDPU’s expectation that, with limited exceptions, distribution companies will be operating under decoupling plans by year-end 2012. Within 45 days of this order, each distribution company was to notify the MDPU of when the company expects to file a rate case to implement decoupling. FG&E notified the MDPU that it will be prepared to file rate cases for each of its divisions by the third quarter of 2009, based upon a calendar 2008 test year, along with a comprehensive decoupling proposal and associated base rate adjustment mechanism. This matter remains pending before the MDPU.

On July 2, 2008, Massachusetts Senate Bill No. 2768 (the “Green Communities Act”) was signed into law. The Green Communities Act is intended to increase energy efficiency, update the renewable energy portfolio standard, increase public oversight of utilities, increase service quality of power companies, assist low-income energy customers, and increase the use of renewable generation and energy efficiency products. The Green Communities Act requires electric companies to boost investment in energy efficiency measures that reduce energy demand and deliver savings to customers; provides a new funding source for efficiency measures through the auction of pollution allowances by power plants through the Regional Greenhouse Gas Initiative; creates stronger incentives for the development of renewable energy, like wind and solar, by requiring 15% of electricity to be supplied by new green power facilities by 2020 and establishing a pilot program for utilities to enter into long-term contracts with renewable energy projects; expressly authorizes cities and towns to own renewable energy facilities; and encourages green building design through updated codes, training and assistance. The MDPU has begun to initiate regulatory proceedings to implement various sections of the Green Communities Act. The impact of any new measures to be required of FG&E in compliance with the Green Communities Act cannot be estimated at this time.

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.

In July 2008, the State of New Hampshire passed a law that allows electric utilities to make investments in distributed energy resources including energy efficiency and demand reduction technologies as well as clean cogeneration and renewable generation. In June 2008, the State of New Hampshire also passed a law approving state participation in the Regional Greenhouse Gas Initiative (the “RGGI”). The RGGI program begins in 2009 and requires large electric generators in 10 northeast and mid-Atlantic states

 

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to purchase allowances for their carbon emissions. These allowances are being sold through a regional auction process and the funds will be used by the states for investments in energy efficiency and alternative energy.

On March 14, 2008, UES made its annual reconciliation and rate filing with the NHPUC under its restructuring plan, for rates effective May 1, 2008, including reconciliation of prior year costs and revenues, power supply and power supply-related stranded costs. The filing was approved on April 23, 2008. On July 9, 2008, UES proposed an increase to its External Delivery Charge, effective September 1, 2008, reflecting higher transmission costs. The filing was approved on August 29, 2008.

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. 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 rehearing was issued on January 22, 2008 finding that it is appropriate to implement some form of 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. In a decision issued on September 15, 2008, the NHPUC ordered the establishment of a working group to facilitate the evaluation and implementation of advanced metering infrastructure and time-based rates and that such working group make a report to the NHPUC by December 1, 2008 with regard to next steps toward utility specific cost-benefit analyses regarding such implementation. The NHPUC also found that additional review of the energy standards for net metering, fuel diversity and fossil fuel generation efficiency as proposed in the Energy Policy Act of 2005 is not required due to action of the New Hampshire legislature and the NHPUC in adopting comparable standards.

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. This matter is pending before the NHPUC.

Environmental Matters

Our past and present operations include activities that are generally subject to extensive and complex federal and state environmental laws and regulations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where wastes or hazardous substances have been disposed or released into the environment. Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, or criminal sanctions, including monetary fines or penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting certain activities or operations. We believe we are in compliance with applicable environmental and safety laws and regulations, and we believe that as of September 30, 2008, there were no material losses reasonably likely to be incurred 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, which allows FG&E to work towards

 

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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 September 30, 2008 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 our 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.

Please refer to Note 7 to our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2008, which is incorporated herein by reference.

Our Strengths

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

Growing Service Territory. Prior to the closing of the Acquisitions, our operations were located in the southeastern seacoast and state capital regions of New Hampshire, as well as in the greater Fitchburg area of north central Massachusetts. This service territory provides a diverse and growing customer base.

The Acquisitions provide an attractive opportunity for us to grow our operations within coastal northern New England. Northern Utilities brings approximately 52,000 additional natural gas retail distribution customers, which increases our retail customer base to approximately 167,000 customers in our service territory in the New England region. Given the lower penetration of gas distribution customers among the population in Northern Utilities’ service territory, we believe 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 retail distribution facilities necessary for the delivery of our customers’ electric and natural gas supply needs within our service territory 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

 

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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 Acquisitions to increase our assets by approximately 52% contributing to significant growth of our retail distribution facilities.

Diversified Customer Base. Our customers are a diversified mix of residential and C&I customers, with no single customer representing more than 5% of our total revenues. Our sales to large C&I 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 Acquisitions have increased our customer base by approximately 52,000 natural gas customers and have provided further diversification to our operations with respect to geography (into Maine) and utility business mix (between our gas and electric divisions).

Efficient and Flexible Operating Structure. We believe that due in part to our size and the proximity of our utility operations, we are able (i) to expeditiously and effectively respond to changing regulatory and public policy initiatives, (ii) to leverage new technology solutions that significantly improve productivity and customer service, and (iii) 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 Acquisitions bring together similarly sized local utilities that will continue to provide a high level of service to their 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. 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 Chief Executive Officer, 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. Our management team is well-equipped and prepared to lead the 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. UES’ 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 power 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,

 

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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 to 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.

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 September 30, 2008, we had 305 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 September 30, 2008, we had 82 employees represented by labor unions. These employees are covered by collective bargaining agreements, which expire on 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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THE ACQUISITIONS

The following is a summary of the material terms of, and other information relating to, the 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. Please see the sections entitled (i) Northern Utilities’ Business and Financial Information and (ii) Granite State’s Business and Financial Information.

Description of the 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 Acquisitions, we paid NiSource and Bay State an aggregate of $160 million in cash, plus an additional $41.6 million in cash as a working capital adjustment, including approximately $33.9 million of natural gas storage inventory. We closed the Acquisitions on December 1, 2008.

We financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility, as described below, coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract.

As of December 1, 2008, we had $165 million outstanding under the bridge credit facility, which provides for a loan for up to eleven months. We subsequently repaid approximately $79.3 million of the amount outstanding under the bridge credit facility using the net proceeds from the sale and issuance by Northern Utilities of $80.0 million aggregate principal amount of long-term unsecured notes, which closed on December 3, 2008.

As of December 10, 2008, we had approximately $85.7 million outstanding under the bridge credit facility. We expect to repay amounts outstanding under the bridge credit facility, except for an estimated $38.9 million, as soon as practicable using the net proceeds from:

 

(i)

the offering of our common stock, as described in this prospectus; and

 

(ii)

the anticipated sale and issuance by Granite State to institutional investors in a private placement of $10.0 million aggregate principal amount of long-term unsecured notes on December 15, 2008.

We expect to repay the estimated $38.9 million balance outstanding under the bridge credit facility prior to its maturity date of November 1, 2009 by issuing additional equity or debt or by using borrowings under a revolving credit facility.

We expect to guarantee the payment of principal, interest and other amounts payable on the Granite State notes. This guarantee will terminate if Granite State reorganizes and merges with and into Northern Utilities.

The foregoing is not intended to, and does not, constitute an offering of the notes described above. The sale and issuance of the Granite State notes (i) is subject to the execution of a definitive note purchase agreement by Granite State and the prospective purchasers of the notes and satisfaction of closing conditions and (ii) will not be, and has not been, registered under the Securities Act and the notes may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements.

 

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Please see the sections entitled (i) Prospectus Summary—Recent Developments and (ii) Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Commitments and Capital Requirements.

The Acquisitions were subject to certain regulatory requirements and approvals and customary closing conditions, including entering into a Transition Services Agreement with NiSource and Bay State. In connection with the closing of the Acquisitions, we obtained the following regulatory approvals and clearances:

 

(i)

approval by the MDPU;

 

(ii)

approval by the MPUC;

 

(iii)

approval by the NHPUC;

 

(iv)

early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and

 

(v)

approval by the Federal Communications Commission of certain license transfers.

All applicable appeal periods on the above approval orders have expired.

On October 28, 2008, we, along with Northern Utilities, filed a joint petition requesting clarification and/or modification of a condition in the MPUC approval order that purported to change the parties’ agreed-upon sharing of risk under the Stock Purchase Agreement relating to several pending regulatory safety and compliance proceedings involving Northern Utilities. On November 5, 2008, the MPUC issued an Order on Reconsideration Modifying Conditions, which is final, as the appeal period has expired. See the sections entitled (i) Prospectus Summary—Recent Developments and (ii) Northern Utilities’ Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The Stock Purchase Agreement provides that NiSource and Bay State will indemnify us for certain losses as described therein, including certain losses arising from the breach of representations and warranties contained therein, the breach of covenants contained therein, and liabilities relating to certain regulatory proceedings. 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.

Reasons for Engaging in, and Estimated Potential Synergy Savings Attributable to,

the Acquisitions

We believe that the 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 brings approximately 52,000 additional natural gas distribution customers, which has increased our customer base to approximately 167,000 customers in our service territory in the New

 

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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 provides 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 Acquisitions will produce annual system-wide synergy savings of approximately $5.6 million, of which approximately $2.4 million is expected to be directly realized by Northern Utilities and Granite State. We expect to begin realizing these synergy savings within the first 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 synergy savings 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.

Pursuant to the MPUC’s and NHPUC’s orders authorizing our acquisition of Northern Utilities, we will retain these system-wide synergy savings until the time of the next rate case for Northern Utilities. In this way, these synergy savings will help to extend the period between rate cases and stabilize rates for our retail distribution utilities and Northern Utilities by reducing their costs of service and improving operating results. At the time of the next base rate case, these synergy savings will be reflected in the cost of service used to determine Northern Utilities’ revenue requirements for ratemaking purposes.

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 synergy savings 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.

Pursuant to the MPUC’s and NHPUC’s orders authorizing our acquisition of Northern Utilities, we cannot seek base rate relief in Maine or New Hampshire until November 1, 2010, subject to certain exceptions. At such time, the system-wide synergy savings discussed above will be reflected in the cost of service used to determine Northern Utilities’ revenue requirements for ratemaking purposes.

Increased Market Capitalization and Liquidity. We expect that the Acquisitions and this offering will increase our market capitalization by approximately 34.6% 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.

We also believe that the Acquisitions and related transactions will result in the following significant benefits to our other stakeholders:

Increased Commitment to Local Communities. We expect the 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’ employees and estimate that we will add approximately 65 new positions, while still achieving the expected synergy savings discussed above. The new positions will be primarily in the areas of gas

 

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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.

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 are now doing business with a single gas and electric distribution utility as a result of the Acquisitions. Additionally, we estimate that we will add several new positions to our customer service department.

Accounting Treatment of the Acquisitions

We accounted for the 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 recognized and measured the identifiable assets acquired and the liabilities assumed at fair value. Also, we measured and recognized 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.

 

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NORTHERN UTILITIES’ BUSINESS AND FINANCIAL INFORMATION

Description of Business

Business Overview

Northern Utilities is a retail 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, from Plaistow, New Hampshire in the south to Lewiston-Auburn, Maine in the north.

Northern Utilities had an investment in Net Utility Plant of $163.5 million at December 31, 2007 and $169.4 million at September 30, 2008, and net revenues of $44.2 million for 2007 and $31.0 million for the nine months ended September 30, 2008. Northern Utilities derives its revenues and earnings from its regulated utility operations. Northern Utilities recovers the cost of purchased natural gas in rates on a fully reconciling basis and, therefore, Northern Utilities’ earnings are not affected by changes in the cost of purchased gas. Prior to the closing of the Acquisitions, Northern Utilities received centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $8.6 million in 2007 and $6.8 million for the nine months ended September 30, 2008.

Corporate History

Northern Utilities was incorporated under the laws of New Hampshire in 1979. In 1979, Northern Utilities became a wholly owned subsidiary of Bay State. NiSource completed its acquisition of Bay State in 1999. We acquired Northern Utilities on December 1, 2008.

Description of the System

Northern Utilities’ distribution system is comprised of 932 miles of gas mains and 37,506 service pipes as of December 31, 2007. The gas mains are primarily made up of polyethylene plastic (64%), coated and wrapped cathodically protected steel (22%), cast/wrought iron (9%), and unprotected bare and coated steel (5%). Northern Utilities’ distribution system provides natural gas to approximately 52,000 customers in 44 New Hampshire and southern Maine communities.

Northern Utilities’ New Hampshire division serves approximately 27,000 customers in 21 communities. The New Hampshire division has 469 miles of distribution gas mains as of year end 2007, of which bare steel and cast iron pipe comprised 47 miles, or approximately 10% of the New Hampshire system. In addition, the New Hampshire division had 19,009 service pipes as of year end 2007 of which 468 are bare steel and cast iron service pipes, or approximately 2% of the New Hampshire system.

Northern Utilities’ Maine division serves approximately 25,000 customers in 23 communities. The Maine division had 463 miles of distribution gas mains as of year end 2007, of which bare steel and cast iron pipe comprised 78 miles, or approximately 17% of the Maine system. Of these 78 miles, only 4 miles consist of bare steel and the remaining 74 miles consist of cast iron. In addition, the Maine division had 18,497 service pipes as of year end 2007 of which 830 are bare steel, or approximately 4% of the Maine system.

Northern Utilities utilizes Itron remote meter reading technology which provides for cost-effective monthly remote meter reading via a drive-by van. The automated meter reading has been fully deployed in New Hampshire and is in the process of being deployed in the Maine system.

 

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Customers

Key Customers

Northern Utilities serves a diverse base of residential and commercial customers. The following table shows the top five customers by revenue for 2007 in Northern Utilities’ Maine division and in its New Hampshire division. Together, these customers represented approximately 9% of Northern Utilities’ net revenues in 2007.

 

		Northern Utilities – Maine		Northern Utilities – New Hampshire
		1. Portsmouth Naval Shipyard 2. Knight Celotex, LLC 3. Maine Medical Center 4. Fairchild Semiconductor 5. Pioneer Plastics Corporation		1. University of New Hampshire – Cogen 2. National Gypsum Company 3. Foss Manufacturing 4. University of New Hampshire 5. Lonza Biologics

Customer Base

The following table shows the breakdown of Northern Utilities’ residential and commercial customers from 2000 to 2007:

 

		2000		2001		2002		2003		2004		2005		2006		2007
Residential Customers		35,863		36,580		37,272		37,796		37,962		38,166		38,497		38,983
Commercial Customers		12,836		12,898		13,087		13,127		13,188		13,705		13,848		13,899
Total Customers		48,699		49,478		50,359		50,923		51,150		51,871		52,345		52,882

Seasonality

Natural gas sales in New England are seasonal, and Northern Utilities’ results of operations, like all New England gas companies, reflect this seasonal dependency. Annual revenues are substantially realized during the heating season as a result of higher sales of natural gas due to winter weather. Accordingly, operating results historically are higher in the first and fourth calendar quarters. Therefore, fluctuations in seasonal weather among years may have a significant effect on Northern Utilities’ results of operations and cash flows.

Gas Supply Resources

Northern Utilities’ supply portfolio is made up of a combination of long-term supply, transportation and storage and peaking contracts that serve the combined New Hampshire and Maine system.

Supply Resources

Northern Utilities’ service territory has access to major interstate pipelines via Granite State, facilitating security, diversity and competitiveness of gas supply. Northern Utilities currently has long-term transportation contracts with Tennessee Gas Pipeline, TransCanada Pipeline, and Portland Natural Gas Transmission Systems (“PNGTS”).

A significant portion of Northern Utilities’ revenue is related to the recovery of all incurred gas costs, the review and recovery of which occurs through standard semi-annual regulatory proceedings. Northern Utilities recovers the cost of purchased natural gas in rates on a fully reconciling basis, and therefore earnings are not affected by changes in purchased gas costs.

 

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Transportation Resources

Northern Utilities has upstream transportation paths that deliver supply to its gates. The upstream pipelines that transport supply to Northern Utilities are Granite State, PNGTS, Tennessee Gas Pipeline, Texas Eastern, TransCanada Pipeline, Union, and Vector.

Storage Resources

Northern Utilities’ contracts for underground storage facilities located in Michigan and Pennsylvania and a small facility in the West Virginia / Pennsylvania area located off of Texas Eastern. Together, these assets provide Northern Utilities with approximately 66% of its winter gas supply requirements and provide the opportunity for a physical hedge against price volatility.

Lewiston LNG and Portland LPG Facilities

Northern Utilities owns two peak-shaving gas production facilities. The Lewiston LNG Plant, located in Maine, is a liquid methane storage and vaporization facility rated at 1400 thousand cubic feet per hour. The Portland LPG Plant, also located in Maine, is a liquid petroleum storage and vaporization facility rated at 300 thousand cubic feet per hour.

Regulatory Matters

Northern Utilities’ Maine and New Hampshire divisions deliver natural gas to all customers in their service territory. Effective September 21, 2001, the MPUC authorized any natural gas utility providing gas distribution service in Maine to provide gas distribution service to any municipality in Maine that is not already being served by another natural gas utility.

Northern Utilities provides service at rates established under traditional cost of service regulation. Under this regulatory structure, Northern Utilities recovers the cost of providing distribution service to its customers based on a historical test year, in addition to earning a return on its capital investment in utility assets. As a result of a restructuring of the utility industry in Maine and New Hampshire, Northern Utilities’ retail and C&I customers have the opportunity to purchase their natural gas supplies from third party vendors. Most customers, however, continue to purchase such supplies through Northern Utilities as the provider of last resort. Northern Utilities purchases natural gas from unaffiliated wholesale suppliers and recovers the actual costs of these supplies on a pass-through basis through reconciling rate mechanisms that are periodically adjusted.

The NHPUC approved a settlement agreement in 2002 setting base rates for Northern Utilities’ New Hampshire division, which reflected an overall rate of return of 7.85% and a return on equity of 9.67%. Northern Utilities has not sought base rate relief since 1983 in Maine.

For additional information regarding Northern Utilities’ regulatory matters, please see the section entitled Northern Utilities’ Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Environmental Matters

For over 10 years, Northern Utilities has had an extensive program to identify, investigate and remediate former MGPs. These plants were operated from the mid 1800s through the mid 1900s. This program has documented the presence of MGPs in Lewiston and Portland, Maine. In New Hampshire, MGPs were identified in Dover, Exeter, Portsmouth, Rochester and Somersworth. A former MGP disposal site was also identified in Scarborough, Maine. Northern Utilities has worked with the environmental regulatory agencies in both Maine and New Hampshire to address environmental concerns with these sites.

 

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Northern Utilities or others have substantially completed remediation of the Exeter, Rochester, Somersworth, Portsmouth, and Scarborough sites. The sites in Lewiston and Portland have been investigated and remedial activities are currently underway. Future operation, maintenance and remedial costs have been accrued although there will be uncertainty regarding future costs until all remedial activities are completed.

The MPUC and NHPUC have approved the recovery of MGP environmental costs. For Northern Utilities’ Maine division, the MPUC authorized the recovery of environmental remediation costs over a rolling five-year amortization schedule. For Northern Utilities’ New Hampshire division, the NHPUC approved the recovery of MGP environmental costs over a seven-year amortization period. Northern Utilities believes material future costs will be recovered.

Northern Utilities accrues liabilities for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated, regardless of when the 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. Northern Utilities establishes a regulatory asset on the balance sheet to the extent that future recovery of environmental remediation cost is probable through the regulatory process.

Northern Utilities had current and non-current accrued liabilities totaling $1.7 million, $2.1 million and $3.7 million as of September 30, 2008, December 31, 2007 and December 31, 2006, respectively. These liabilities reflect estimated expenditures for six former MGP sites, of which three sites are in Maine and three sites are in New Hampshire, as of September 30, 2008, December 31, 2007 and December 31, 2006.

Legal Proceedings

In the normal course of its business, Northern Utilities has been named as defendant in various legal proceedings. In the opinion of Northern Utilities management, as discussed in Note 10 to its financial statements at December 31, 2007, the ultimate disposition of these currently asserted claims will not have a material adverse impact on Northern Utilities’ financial position or results of operations.

Employees

As of September 30, 2008, Northern Utilities had 76 full-time employees. Northern Utilities considers its relationship with employees to be good and has not experienced any major labor disruptions. We anticipate retaining all of Northern Utilities’ employees, of which 57 employees were subject to collective bargaining agreements as of September 30, 2008. The agreements provide discreet salary adjustments, established work practices and uniform benefit packages.

The current agreement with the Utility Workers Union of America is set to expire on March 31, 2009 and covered 28 employees in Northern Utilities’ Maine division as of September 30, 2008. The current agreement with the United Steel Workers of America is set to expire June 5, 2010 and covered 29 employees in Northern Utilities’ New Hampshire division as of September 30, 2008.

 

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Selected Historical Financial Data

The following table shows selected historical financial 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 audited historical financial statements of Northern Utilities appearing elsewhere in this prospectus. The selected historical financial data of Northern Utilities as of September 30, 2008 and 2007 and for the nine months ended September 30, 2008 and 2007 are derived from the unaudited condensed 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’ Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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.

 

		For the Nine Months Ended September 30,							For the Year Ended December 31,
(millions)		2008				2007			2007			2006			2005			2004			2003
		(unaudited)																(unaudited)			(unaudited)
Statements of Earnings:
Net Revenues		$	31.0			$	31.4		$	44.2		$	38.4		$	40.2		$	41.1		$	40.8
Operating Income		$	0.6			$	4.1		$	6.7		$	4.7		$	7.6		$	10.9		$	13.8
Interest Expense, net and other			2.1				2.1			2.8			2.6			2.4			2.8			3.5
Income Taxes			(0.3	)			1.1			1.7			0.8			2.2			4.2			4.3
Net (Loss) Income		$	(1.2	)		$	0.9		$	2.2		$	1.3		$	3.0		$	3.9		$	6.0
		As of September 30,							As of December 31,
(millions)		2008				2007			2007			2006			2005			2004			2003
		(unaudited)													(unaudited)			(unaudited)			(unaudited)
Balance Sheet Data:
Utility Plant (Original Cost)		$	229.5			$	216.4		$	219.5		$	205.7		$	193.1		$	184.6		$	176.9
Total Assets		$	327.4			$	304.6		$	314.9		$	327.7		$	313.2		$	278.9		$	280.0
Capitalization:
Common Stock Equity		$	120.4			$	120.3		$	121.6		$	119.6		$	116.9		$	117.9		$	114.9
Long-Term Debt, less Current Portion			—				61.7			61.7			62.5			63.3			64.2			65.0
Total Capitalization		$	120.4			$	182.0		$	183.3		$	182.1		$	180.2		$	182.1		$	179.9
Current Portion of Long-Term Debt		$	61.7			$	0.8		$	0.8		$	0.8		$	0.8		$	0.8		$	0.8
Short-Term Debt		$	35.5			$	26.0		$	31.1		$	39.5		$	30.1		$	14.3		$	16.4

 

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Financial Statements

Northern Utilities’ unaudited condensed financial statements as of and for nine months ended September 30, 2008 and 2007 are set forth beginning on page F-20 of this prospectus supplement.

Northern Utilities’ audited 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-34 of this prospectus supplement.

Recent Developments

On October 28, 2008, in its approval of Northern Utilities’ Cost of Gas Factor (CGF) for the 2008-2009 Winter Period, Docket 2008-343, the MPUC approved Northern Utilities’ “in-kind reimbursement” gas arrangement with Granite State to correct for a meter pulse factor error that had occurred between June 2005 and December 2007 at the Newington Gate Station. The metering equipment was operated and maintained by a third party, Spectra, the parent company of M&NE. PNGTS and M&NE share joint ownership of the section of the pipeline connected to Granite State at the Newington Gate Station. The error caused Granite State to be billed for 758,702 Dth of natural gas, with Granite State then billing Northern Utilities for an equivalent amount, although the volumes of gas were not actually consumed. The meter error was corrected and Northern Utilities, Granite State, Spectra and PNGTS reached an agreement where PNGTS would return to Northern Utilities, through Granite State, the gas “in-kind” over a period of approximately 18 months, subject to curtailment due to the unavailability of gas. The MPUC approved the arrangement, as well as Northern Utilities’ methodology for allocating the “in-kind” gas received to its Maine and New Hampshire divisions based upon the actual gas use over the period the meters were misread.

In the MPUC’s October 28, 2008 approval, the MPUC also approved recovery of an additional $0.5 million of annual demand costs that had been inadvertently omitted from Northern Utilities’ reconciliation of the 2008-2009 Winter Period rates, although analogous costs had been included in its calculation of 2007-2008 Winter Period rates. The MPUC determined that recovery of these Local Production Capacity Costs was consistent with the stipulation approved in Northern Utilities’ rate design case in Docket No. 1997-393, Northern Utilities, Inc., Request for Approval of Rate Design and Partial Unbundling Proposal, Part One Order Approving Stipulation, September 3, 1999.

On October 31, 2008, in its approval of Northern Utilities’ cost of gas and other rate adjustments for the 2008-2009 Winter Period (DG 08-155), the NHPUC approved Northern Utilities’ “in-kind reimbursement” gas arrangement with Granite State to correct for a meter pulse factor error that had occurred between June 2005 and December 2007. The error caused Granite State to be billed for 758,702 Dth of natural gas, with Granite State then billing Northern Utilities for an equivalent amount, although the volumes of gas were not actually consumed. The meter error was corrected and Northern Utilities, Granite State, Spectra and PNGTS reached an agreement where PNGTS would return to Northern Utilities, through Granite State, the gas “in-kind” over a period of approximately 18 months, subject to curtailment due to the unavailability of gas. The NHPUC approved the arrangement, as well as Northern Utilities’ proposal to file semi annual reports with the NHPUC indicating the status of repayment of “in kind” volumes.

Please see the section entitled Northern Utilities’ Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

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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 supplement.

Three and Nine Months Ended September 30, 2008 and 2007

The following table and discussion is a summary of Northern Utilities’ results of operations for the three and nine months ended September 30, 2008 and 2007.

 

		(unaudited)
		Three months ended September 30,								Nine months ended September 30,
(in millions)		2008				2007				2008				2007
Net Revenues
Gas distribution revenues		$	12.4			$	11.3			$	85.6			$	93.5
Cost of sales (excludes depreciation and amortization)			6.4				5.7				54.6				62.1
Total Net Revenues			6.0				5.6				31.0				31.4
Operating Expenses
Operations and maintenance			6.9				5.1				20.0				17.9
Depreciation and amortization			2.7				2.5				8.2				7.5
Taxes, other than income			0.8				0.7				2.2				1.9
Total Operating Expenses			10.4				8.3				30.4				27.3
Operating (Loss) Income			(4.4	)			(2.7	)			0.6				4.1
Other Income (Deductions)
Interest expense, net			(0.7	)			(0.7	)			(2.1	)			(2.1	)
Total other income (deductions)			(0.7	)			(0.7	)			(2.1	)			(2.1	)
(Loss) Income Before Income Taxes			(5.1	)			(3.4	)			(1.5	)			2.0
Income Tax (Benefit) Expense			(2.0	)			(1.3	)			(0.3	)			1.1
Net (Loss) Income		$	(3.1	)		$	(2.1	)		$	(1.2	)		$	0.9

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Net Revenues. Net revenues increased by $0.4 million, or 7.1%, in the three months ended September 30, 2008 compared to the same period of 2007. This increase was due primarily to increases in other gas distribution revenues.

Operating Expenses. Operating expenses increased $2.1 million, or 25.3%, for the three months ended September 30, 2008 compared to the same period of 2007. This increase was primarily due to penalties and compliance costs arising from the Maine Notices of Probable Violation (“NOPVs”) regulatory matter of $0.8 million, higher employee and administrative expenses (including management fees) of $0.5 million and higher uncollectible expense of $0.3 million. Depreciation expense increased $0.2 million in the 2008 period due to increases in capital investments. Additionally, other tax expense increased $0.3 million due to higher property and payroll taxes.

 

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Other Income (Deductions). Interest expense was $0.7 million for both the three months ended September 30, 2008 and 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.

Income Tax Expense. The income tax benefit of $2.0 million in the three months ended September 30, 2008 increased $0.7 million from the comparable period in 2007 due to a higher pretax loss in the 2008 period.

Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Net Revenues. Net revenues decreased by $0.4 million, or 1.3%, in the first nine months of 2008 compared to the same period of 2007. This decrease was primarily due to unfavorable weather in the 2008 period compared to the 2007 period.

Operating Expenses. Operating expenses increased $3.1 million, or 11.4%, for the nine months ended September 30, 2008 compared to the same period of 2007. This increase was primarily due to penalties and compliance costs arising from the Maine NOPVs regulatory matter of $1.6 million, and employee and administrative expenses (including management fees) increases of $0.8 million. Depreciation expense increased $0.7 million in the 2008 period due to increases in capital investments. Other tax expense increased $0.3 million due to higher property and payroll taxes.

Other Income (Deductions). Interest expense reduced income in the first nine months of 2008 by $2.1 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.

Income Tax Expense. Income tax expense for the first nine months of 2008 decreased $1.4 million, from the comparable period in 2007 due primarily to pretax loss in 2008 compared to pretax income in 2007. The effective tax rates for the nine months ended September 30, 2008 and September 30, 2007 were 21.9% and 55.1%, respectively. Non-deductible expenses were approximately $300,000 in both 2007 and 2008. Non-deductible expenses reduced the effective tax rate on the pre-tax loss in the nine months ended September 30, 2008 causing a lower effective tax rate; whereas in 2007, the non-deductible expenses had the effect of increasing the effective tax rate on 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 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 a regulator failure; and (5) Northern Utilities had failed to properly design one of its regulator stations.

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

 

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(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 (Docket Nos. 2008-095, 097 and 098), the MPUC initiated a formal investigation into three NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations. Northern Utilities has responded to each of these NOPVs in a timely manner.

Northern Utilities and the MPUC engaged in extensive settlement discussions regarding all of the dockets identified herein and, on September 8, 2008, filed a comprehensive settlement (“Settlement”) with the MPUC. Under the Settlement, Northern Utilities would incur total expenditures of $3.2 million, comprised of (i) a monetary penalty, (ii) certain safety-related improvements to Northern Utilities’ pipeline system and (iii) obligations to be undertaken for Northern Utilities’ distribution system to ensure compliance with the relevant gas safety laws of the State of Maine and the U.S. Code. Approximately $0.5 million has been incurred to date.

The MPUC considered the Settlement at a deliberative meeting on October 6, 2008. At that meeting, the MPUC approved the Settlement with several modifications, including one limiting Northern Utilities’ ability to challenge or delay implementation of any recommendation made by a consultant (“SEA Consulting”) engaged by Northern Utilities’ and the MPUC, which will impair Northern Utilities’ ability to recover any costs for regulator station improvements recommended by SEA Consulting from customers. The SEA Consulting report was delivered in draft form on October 17, 2008. Northern Utilities is presently reviewing SEA Consulting’s draft report to determine whether it can comply with the MPUC’s condition on the Settlement and is considering legal options with regard to the MPUC’s order on the Settlement.

New Hampshire Public Utilities Commission Docket No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the NHPUC issued Order No. 24,798 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that lost and unaccounted for gas (“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 ended 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 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 cause appears to be incorrect metering by Spectra Energy Corp. (“Spectra”) at the Maritimes & Northeast (“M&NE”) / 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 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 758,702 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

 

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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. This overcharge in turn was passed on to Northern Utilities’ customers through the normal operation of the gas cost recovery mechanism.

In September 2008, Northern Utilities received information that Spectra, PNGTS and Granite State had agreed to resolve the matter by flowing the 758,702 Dth back through the imbalance provisions of the respective tariffs in force between the parties (“in-kind reimbursement”). Upon receiving this information, Northern Utilities filed with the NHPUC and the MPUC for approval of this method of reimbursement for the metering error. In October 2008, Northern Utilities received permission from both the NHPUC and the MPUC for the rate treatment of the in-kind reimbursement through the Northern Utilities’ cost of gas adjustment and approval of the commencement of the flow-back of natural gas starting November 1, 2008. As of September 30, 2008, Northern Utilities has recorded approximately $7.6 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.

Liquidity and Capital Resources

Generally, cash flow from operations and short-term borrowings from an affiliated entity 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, affiliated short-term financing is used to purchase gas to place in storage for heating season deliveries, perform maintenance and make capital improvements.

As of September 30, 2008, Northern Utilities reclassified all long-term debt to a current liability. Unaffiliated debt of $1.7 million was fully paid in advance in October 2008. Affiliated debt to a NiSource subsidiary with an outstanding balance of $60 million is scheduled to be fully paid in advance with the proceeds of the sale of Northern Utilities to Unitil Corporation within the next twelve months.

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 nine months ended September 30, 2008 and 2007 were as follows:

 

		Nine Months Ended September 30,
(in millions)		2008				2007
Net cash provided by operating activities		$	10.0			$	24.9
Net cash used in investing activities		$	(14.6	)		$	(10.3	)
Net cash provided by (used in) financing activities		$	3.6			$	(14.3	)

Net cash provided by operating activities decreased by $14.9 million for the first nine months of 2008 compared to the same period in 2007 primarily due to decreases in cash from prepaid gas costs and from over/under-recovered gas and fuel costs, both of which are attributable to the increased price of gas purchased, partially offset by an increases in cash from accounts receivable and exchange gas receivables.

 

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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 $11.5 million and $12.1 million for the nine months ended September 30, 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 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.

 

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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 such as intangible assets.

In October 2008, the FASB issued FSP 157-d, “Determining the Fair Value of a Financial Asset in a Market that is Not Active” which clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued.

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.

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

 

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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 FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (“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.

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.

 

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Recently Issued Accounting Pronouncements

SFAS No. 141(R) – 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 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 its unaudited condensed financial statements as of September 30, 2008.

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
Operations and Maintenance			24.7				21.4				20.2
Depreciation and Amortization			10.2				9.7				9.5
Taxes other than Income			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 (i) Northern Utilities had failed to update its Operation and Maintenance Plan within the time periods required by the regulations; (ii) Northern Utilities had allowed persons to perform certain O&M tasks without being properly qualified to do so under its Operator Qualification Plan; (iii) Northern Utilities lacked the necessary documentation concerning the maximum allowable operating pressures of certain distribution piping systems; (iv) Northern Utilities had allowed one of its systems to operate above the maximum allowable operating pressure following an upstream regulator failure; and (v) 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 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 No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the NHPUC issued Order No. 24,798 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 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.

 

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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 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.

Although Northern Utilities anticipates it will have a refund liability for the overcharges, the timing and extent is not clear. The NHPUC 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.

Please see the section entitled Northern Utilities—Recent Developments.

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 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. 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.

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 FASB Statement

 

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No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“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 participates in defined benefit pension and other post-retirement benefit plans. 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 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 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

 

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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 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. 141(R)—Business Combinations. In December 2007, the FASB issued SFAS No. 141(R) 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. 141(R) 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

 

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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 the condensed financial statements as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005.

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 BUSINESS AND FINANCIAL INFORMATION

Description of Business

Business Overview

Granite State is a natural gas transportation pipeline, regulated by the FERC, operating 87 miles of underground gas transportation 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 had an investment in Net Utility Plant of $16.5 million at December 31, 2007 and $16.1 million at September 30, 2008, and net operating revenue of $3.4 million for 2007 and $2.1 million for the nine months ended September 30, 2008. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third -party marketers. Prior to the closing of the Acquisitions, Granite State received centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $0.6 million in 2007 and $0.5 million for the nine months ended September 30, 2008.

Corporate History

Granite State was incorporated under the laws of New Hampshire in 1955. After its formation, Granite State’s distribution system was reconfigured to allow natural gas to move between two states to service both Northern Utilities’ New Hampshire division and its Maine division. Accordingly, in 1965, Granite State filed an application with the FERC to become an interstate transportation pipeline, which was granted on November 15, 1965. Granite State was acquired by NiSource in 1999 through its acquisition of Bay State. We acquired Granite State on December 1, 2008.

Description of the System

Granite State’s transmission system connects with Tennessee Gas Pipeline Company in Haverhill, Massachusetts, near the Massachusetts-New Hampshire border. From this point, Granite State’s pipeline extends northeasterly through the coastal areas of New Hampshire and Maine to its northern terminus at Portland, Maine. Granite State also interconnects with the PNGTS and M&NE – Joint Facilities at Newington, New Hampshire and Westbrook, Maine. In addition to these three receipt points, Granite State’s system has 34 delivery points along Northern Utilities’ distribution system. Granite State’s estimated peak day capacity of the pipeline system is 150,196 Dekatherms per day (“Dth/day”). Granite State neither owns nor operates any natural gas storage facilities or compressor stations.

Customers

As of September 30, 2008, Granite State had over 70% of its estimated peak day capacity under firm contract. Northern Utilities is a captive customer on Granite State’s pipeline, and its current firm transportation capacity contract is for 100,000 Dth/day, or 67% of Granite State’s capacity. Northern Utilities has negotiated a new contract with Granite State that was effective November 1, 2008. The former contract provided Northern Utilities a discount from the firm tariff rate, which was eliminated under the new contract. Returning to the full firm tariff rate will increase Granite State’s revenues by approximately $500,000 annually. Northern Utilities recovers its transportation costs of natural gas in rates on a fully reconciling basis and, therefore, Northern Utilities’ earnings are not affected by this change. Northern Utilities anticipates it will require approximately 100,000 Dth/day of firm transportation capacity on Granite State’s system for the foreseeable future.

 

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Seasonality

A substantial portion of Granite State’s revenues are based on levelized firm transportation capacity contracts and therefore revenues do not generally vary by seasonal weather conditions. However, annual revenues associated with short-term non-firm transportation services may vary from year to year and have an incremental effect on results of operations and cash flows.

Regulatory Matters

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.

Additionally, interstate pipeline companies such as Granite State are subject to regulation by the U.S. Department of Transportation pursuant to the Natural Gas Pipeline Safety Act, which authorizes safety requirements in the design, construction, operations and maintenance of interstate natural gas transmission facilities.

The FERC has jurisdiction over, among other things, the construction and operation of pipelines and related facilities used in the transportation, storage and sale for resale of natural gas in interstate commerce, including the extension, enlargement and abandonment of such facilities. The FERC also has jurisdiction over the rates and charges for the transportation of natural gas in interstate commerce and the sale for resale of natural gas by a natural gas pipeline company in interstate commerce. These rates are a function of the cost of providing services to customers, including the ability to recover prudently incurred operations and maintenance costs, taxes, interest, depreciation, and amortization and reasonable return on equity. In addition, certain operations are subject to oversight by state regulatory commissions.

Granite State’s last base rate case was approved by the FERC on October 20, 1997, with approval of a stipulation and agreement among the parties. Granite State’s Phase II rates, consistent with the stipulation and agreement, were effective May 1, 1998.

Employees

As of September 30, 2008, Granite State had five full-time employees. Granite State considers its relationship with employees to be good and has not experienced any major labor disruptions. We anticipate retaining all of Granite State’s employees, of which three were subject to a collective bargaining agreement as of September 30, 2008. The agreement with the Utility Workers Union of America expires March 31, 2009 and provides discreet salary adjustments, established work practices, and uniform benefits packages.

 

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Selected Historical Financial Data

The following table shows selected historical financial 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 audited historical financial statements of Granite State appearing elsewhere in this prospectus. The selected historical financial data of Granite State as of and for the nine months ended September 30, 2008 and 2007 are derived from the unaudited historical condensed 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 Business and Financial Information—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

		For the Nine Months Ended September 30,								For the Year Ended December 31,
(millions)		2008				2007				2007				2006			2005			2004				2003
						(unaudited)														(unaudited)				(unaudited)
Statements of Earnings (Loss):
Net Operating Revenue		$	2.1			$	2.2			$	3.4			$	4.2		$	4.5		$	4.7			$	4.7
Operating Income (Loss)		$	(0.1	)		$	0.1			$	0.4			$	0.3		$	0.9		$	0.9			$	0.9
Non-Operating Income (Expense)			—				—				—				0.4			0.2			(0.2	)			0.4
Interest Expense, net			0.2				0.4				0.6				0.5			0.2			0.1				0.1
Income Taxes and Other			(0.1	)			—				—				0.1			0.4			0.3				0.9
Net Income (Loss)		$	(0.2	)		$	(0.3	)		$	(0.2	)		$	0.1		$	0.5		$	0.3			$	0.3
		As of September 30,								As of December 31,
(millions)		2008				2007				2007				2006			2005			2004				2003
		(unaudited)															(unaudited)			(unaudited)				(unaudited)
Balance Sheet Data:
Utility Plant (Original Cost)		$	23.9			$	23.8			$	24.0			$	23.2		$	19.5		$	14.5			$	11.6
Total Assets		$	34.4			$	27.4			$	27.3			$	33.3		$	30.0		$	26.7			$	26.2
Capitalization:
Common Stockholders Equity		$	12.7			$	12.7			$	12.8			$	13.0		$	12.7		$	12.3			$	12.0
Total Capitalization		$	12.7			$	12.7			$	12.8			$	13.0		$	12.7		$	12.3			$	12.0

Financial Statements

Granite State’s unaudited condensed financial statements as of and for the nine months ended September 30, 2008 and 2007 are set forth beginning on page F-55 of this prospectus supplement.

Granite State’s audited 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-67 of this prospectus supplement. The following discussion of financial condition and results of operations gives effect to the restatement discussed in Note 11 of such financial statements.

 

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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 Granite State’s historical financial statements and notes included elsewhere in this prospectus.

Three and Nine Months Ended September 30, 2008 and 2007

The following table and discussion is a summary of Granite State’s results of operations for the three and nine months ended September 30, 2008 and 2007.

 

		(unaudited)
		Three Months Ended September 30,								Nine Months Ended September 30,
		2008				2007				2008				2007
(in millions)
Net Revenues
Total Net Revenues		$	0.5			$	0.7			$	2.1			$	2.2
Operating Expenses
Operation and maintenance			0.5				0.4				1.3				1.2
Depreciation and amortization			0.2				0.2				0.7				0.7
Taxes, other than income			0.1				0.1				0.2				0.2
Total Operating Expenses			0.8				0.7				2.2				2.1
Operating Income (Loss)			(0.3	)			—				(0.1	)			0.1
Other Deductions
Interest expense, net			—				(0.2	)			(0.2	)			(0.4	)
Other, net			—				—				—				—
Total Other Deductions			—				(0.2	)			(0.2	)			(0.4	)
Loss Before Income Taxes			(0.3	)			—				(0.3	)			(0.3	)
Income Tax Benefit			(0.1	)			(0.1	)			(0.1	)			—
Net Loss		$	(0.2	)		$	(0.1	)		$	(0.2	)		$	(0.3	)

Three Months Ended September 30, 2008 Compared to the Three Months Ended September 30, 2007

Net Revenues. Net revenues of $0.5 million for the three months ended September 30, 2008 were relatively flat compared to the net revenues of $0.7 million for the same period of 2007.

Operating Expenses. Operating expense was $0.8 million for the three months ended September 30, 2008 and was relatively flat compared to operating expense of $0.7 million for the same period of 2007.

Other Deductions. Interest expense was less than $0.1 million for the three months ended September 30, 2008 compared to interest expense of $0.2 million in the comparable period of 2007. The $0.2 million decrease was due to lower borrowings from the NiSource money pool in the first three months of 2008.

Income Taxes. The income tax benefit of $0.1 million in the three months ended September 30, 2008 was flat compared to the same period of 2007.

 

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Nine Months Ended September 30, 2008 Compared to the Nine Months Ended September 30, 2007

Net Revenues. Net revenues of $2.1 million for the nine months ended September 30, 2008 were consistent with net revenues of $2.2 million for the same period of 2007.

Operating Expenses. Operating expense was $2.2 million for the nine months ended September 30, 2008 and was relatively flat compared to $2.1 million in the same period of 2007.

Other Deductions. Interest expense was $0.2 million for the nine months ended September 30, 2008 compared to interest expense of $0.4 million in the comparable period of 2007. The $0.2 million decrease was due to lower borrowings from the NiSource money pool in the first nine months of 2008.

Income Taxes. Income tax benefit was $0.1 million for the first nine months of 2008 compared to an income tax benefit of less than $0.1 million for the same period in 2007. This increase in tax benefit is due to a contingent tax expense in 2007 of $0.1 million that offset the income tax benefit in the first nine months of 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:

 

Ÿ

transportation of natural gas;

 

Ÿ

rates and charges for natural gas transportation;

 

Ÿ

certification and construction of new facilities;

 

Ÿ

initiation, extension or abandonment of services;

 

Ÿ

maintenance of accounts and records;

 

Ÿ

commercial relationships and communications between pipelines and certain affiliates;

 

Ÿ

terms and conditions of service and service contracts with customers;

 

Ÿ

depreciation and amortization policies; and

 

Ÿ

acquisition, extension and abandonment of facilities.

New Hampshire Public Utilities Commission Docket No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the NHPUC issued Order No. 24,798 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 ended 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 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 cause appears to be incorrect metering by Spectra at the M&NE / PNGTS Newington Gate Station caused by an erroneous

 

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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 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 758,702 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. This overcharge in turn was passed on to Northern Utilities’ customers through the normal operation of the gas cost recovery mechanism.

In September 2008, Northern Utilities received information that Spectra, PNGTS and Granite State had agreed to resolve the matter by flowing the 758,702 Dth back through the imbalance provisions of the respective tariffs in force between the parties (“in-kind reimbursement”). Upon receiving this information, Northern Utilities filed with the NHPUC and the MPUC for approval of this method of reimbursement for the metering error. In October 2008, Northern Utilities received permission from both the NHPUC and the MPUC for the rate treatment of in-kind reimbursement through the Northern Utilities’ cost of gas adjustment and approval of the commencement of the flow-back of natural gas starting November 1, 2008. As of September 30, 2008, Northern Utilities has recorded approximately $7.6 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.

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 financing activities for the nine months ended September 30, 2008 and 2007 were as follows:

 

		Nine Months Ended September 30,
(in millions)		2008				2007
Net cash provided by operating activities		$	1.0			$	4.7
Net cash used in investing activities		$	(0.3	)		$	(4.0	)
Net cash used in financing activities		$	(0.6	)		$	(0.7	)

Net cash provided by operating activities decreased by $3.7 million for the first nine months of 2008 compared to the same period in 2007 primarily due to the settlement of an uncertain tax position in the amount of $3.9 million during the third quarter of 2007.

 

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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 $0.3 million and $4.0 million for the nine months ended September 30, 2008 and 2007. The $3.7 million decrease was due to lower capital expenditures relating to the Integrity Management 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. 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.

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

There were no changes to Granite State’s 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 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.

 

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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 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.

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. Granite State has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities such as intangible assets.

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, an increase in Accumulated Deficit of $18,573, a decrease to Accounts and Notes Receivable of $7,061, an increase to Receivable from Affiliated Companies of $99,072, and an increase to Payable to Affiliated Companies of $1,887. 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 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

 

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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 accumulated deficit as a result of the implementation of FIN 48.

Recently Issued Accounting Pronouncements

SFAS No. 141(R) – Business Combinations. In December 2007, the FASB issued SFAS No. 141(R) 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. 141(R) 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
Operations and Maintenance			1.9				2.9				2.7
Depreciation and Amortization			0.8				0.8				0.7
Taxes other than Income			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

 

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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 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 Internal Revenue Service (“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 effective 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 primarily 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:

 

Ÿ

transportation of natural gas;

 

Ÿ

rates and charges for natural gas transportation;

 

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Ÿ

certification and construction of new facilities;

 

Ÿ

initiation, extension or abandonment of services;

 

Ÿ

maintenance of accounts and records;

 

Ÿ

commercial relationships and communications between pipelines and certain affiliates;

 

Ÿ

terms and conditions of service and service contracts with customers;

 

Ÿ

depreciation and amortization policies; and

 

Ÿ

acquisition, extension and abandonment of facilities.

New Hampshire Public Utilities Commission Docket No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the NHPUC issued Order No. 24,798 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 and obtained from the NHPUC 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		$	4.7			$	1.2			$	2.3
Net Cash Used in Investing Activities		$	(4.1	)		$	(1.9	)		$	(3.4	)
Net Cash (Used in) Provided by Financing Activities		$	(0.6	)		$	0.8			$	1.1

Net cash provided by operating activities increased by $3.5 million for 2007 compared to 2006 primarily due to the collection of tax and interest receivables.

Net cash provided by operating activities decreased by $1.1 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 $4.1 million, $1.9 million and $3.4 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 Obligations. 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.

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.

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

 

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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 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 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 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 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 SFAS No. 144.

Pensions and Postretirement Benefits. Granite State participates in defined benefit pension and other post-retirement benefit plans. 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

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

 

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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 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. 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. 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.

 

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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 Granite State 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 December 10, 2008.

 

Name		Age		Years of Service to Unitil		Position
Robert G. Schoenberger		58		11		Chairman of the Board, Chief Executive Officer and President
Mark H. Collin		49		20		Senior Vice President, Chief Financial Officer and Treasurer
Thomas P. Meissner, Jr.		46		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, Jr.		52		14		Vice President, Unitil Service
Raymond J. Morrissey		61		23		Vice President, Unitil Service
Sandra L. Whitney		45		18		Corporate Secretary
Dr. Robert V. Antonucci		63		4		Director
David P. Brownell		64		7		Director
Michael J. Dalton		67		24		Director
Albert H. Elfner, III		64		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		61		16		Director
Dr. Sarah P. Voll		66		5		Director

Robert G. Schoenberger has been Chairman of our Board of Directors and our 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.

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.

 

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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 been 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 currently serves on the board of the Foundation for Healthy Communities, is a director of the New Hampshire Hospital Association, is a director of New Hampshire Business Committee for the Arts, and is 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 was the director of operations of BrainShift.com, Inc., Medford, Massachusetts (a learning technology development company) from 2002 until 2008. Mr. Tenney is currently a director and treasurer of The BrainShift Foundation (a non-profit division of BrainShift.com, Inc.). 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 5% 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 December 10, 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		11,832		*
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		3,936		*
Charles H. Tenney III(3) Director		148,680		2.6	%
Dr. Sarah P. Voll Director		1,641		*
Robert G. Schoenberger(4) Chairman of the Board, Chief Executive Officer and President		100,444		1.7	%
Mark H. Collin(5) Senior Vice President, Chief Financial Officer and Treasurer		15,400		*
Thomas P. Meissner, Jr.(6) Senior Vice President and Chief Operating Officer		12,581		*
George R. Gantz(7) Senior Vice President, Unitil Service		17,722		*
Todd R. Black(8) President, Usource		10,789		*
All Directors and Executive Officers as a Group (19 Persons)(9)		371,893		6.4	%

 

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*

Represents less than 1% of our outstanding common stock.

 

(1)

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

 

(2)

Included are 7,838 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 1,315 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, 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 3,532 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 1,867 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 fully vested 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 691 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 fully vested 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 fully vested 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 873 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 5,700 fully vested 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 93,200 fully vested 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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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated December 10, 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		1,000,000
Janney Montgomery Scott LLC		340,000
Oppenheimer & Co. Inc		340,000
Brean Murray, Carret & Co., LLC		160,000
Edward D. Jones & Co., L.P.		160,000
Total		2,000,000

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 300,000 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 $0.63 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 $0.10 per share on sales to other broker/dealers. The expenses of the offering that are payable by us are estimated to be $1.125 million (exclusive of underwriting discounts and commissions).

The following table summarizes the compensation 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		$	1.05		$	1.05		$	2,100,000		$	2,415,000

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 pursuant to our 401(k) plan, (v) the filing of registration statements on Form S-8 and amendments thereto in connection with those securities and plans, (vi) grants of common stock as

 

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employee length of service awards, (vii) grants of common stock to members of our Board of Directors as a portion of their compensation for service on the Board of Directors, and (viii) issuances pursuant to dividend reinvestment plans and the filing of registration statements and amendments related thereto in connection with the sale and issuance of securities under such plans.

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 paragraphs will be automatically extended if: (i) 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 (ii) 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.

The underwriters have not reserved any shares of common stock for sale, at the public offering price, to our directors, officers, employees, or any other individuals. One of our directors, however, has a preexisting relationship with a broker affiliated with an underwriter and intends to purchase up to 7,500 shares of common stock in this offering.

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 listed on the New York Stock Exchange 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

has acted as financial advisor in connection with the Acquisitions;

 

Ÿ

is the lender under our bridge credit facility; and

 

Ÿ

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

We intend to use the net proceeds from this offering (including the proceeds from any exercise by the underwriters of their overallotment option) and the anticipated sale and issuance of long-term unsecured notes by Granite State (i) to repay amounts outstanding under the bridge credit

 

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facility, except for an estimated $38.9 million, that we will use to partially finance the Acquisitions and the related costs and expenses and (ii) for other general corporate purposes. Because more than 10% of the proceeds of this offering, not including underwriting compensation, may be received by an affiliate of RBC Capital Markets Corporation in connection with its participation as a lender in our bridge credit facility, this offering is being conducted in compliance with National Association of Securities Dealers Conduct Rule 2710(h). Pursuant to that rule, the appointment of a qualified independent underwriter is not necessary in connection with this offering.

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.

We have been advised by the underwriters that, prior to purchasing the shares being offered pursuant to this prospectus supplement, on December 9, 2008 and December 10, 2008, one of the underwriters purchased, on behalf of the syndicate, 19,625 shares at an average price of $20.00 per share in stabilizing transactions.

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 Gary Epler, our Chief Regulatory Counsel. As of December 1, 2008, Mr. Epler beneficially owned approximately 2,283 shares of our common stock.

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 and elsewhere in this registration statement (which report expresses an unqualified opinion on the financial statements and includes an explanatory paragraph referring to the adoption of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”). 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 and elsewhere in this registration statement (which report expresses an unqualified opinion on the financial statements and includes explanatory paragraphs referring to the adoption of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and the restatement of the financial statements discussed in Note 11). 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.

 

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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 listed on the New York Stock Exchange 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 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 quarters ended March 31, 2008, June 30, 2008, and September 30, 2008;

 

Ÿ

our Current Reports on Form 8-K filed with the SEC on February 20, 2008, March 21, 2008, April 8, 2008, June 20, 2008, July 30, 2008 (other than the press release furnished thereunder), August 22, 2008 (other than the press release furnished thereunder), August 27, 2008 (other than the press release furnished thereunder), September 11, 2008, October 17, 2008, December 3, 2008, and December 4, 2008; and

 

Ÿ

the description of our common stock, no par value, contained in the registration statement on Form 8-A/A filed with the SEC on August 13, 2008.

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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INDEX TO FINANCIAL STATEMENTS

 

Pro Forma Unaudited Financial Statements of Unitil Corporation as of September 30, 2008 and December  31, 2007, for the Nine Months Ended September 30, 2008 and 2007, and for the year ended December 31, 2007		F-1
Unaudited Condensed Financial Statements of Northern Utilities, Inc. as of and for the Nine Months Ended September 30, 2008 and 2007		F-21
Financial Statements of Northern Utilities, Inc. 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		F-35
Unaudited Condensed Financial Statements of Granite State Gas Transmission, Inc. as of and for the Nine Months Ended September 30, 2008 and 2007		F-57
Financial Statements (Restated) of Granite State Gas Transmission, Inc. 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		F-69

 

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UNITIL CORPORATION

 

 

PRO FORMA FINANCIAL STATEMENTS AS OF AND FOR THE

NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007, AND AS OF                     

AND FOR

THE YEAR ENDED DECEMBER 31, 2007

 

 

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The following Unaudited Pro Forma Combined Financial Statements have been prepared to give effect to the acquisition (the “Acquisitions”) 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 September 30, 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 earnings).

The Unaudited Pro Forma Combined Financial Statements include adjustments for the Acquisitions pursuant to the purchase method of accounting for business combinations (pursuant to which the assets and liabilities of Northern Utilities and Granite State were recorded, as of the closing of the Acquisitions, at their fair values and added to our assets and liabilities) and the replacement of the predecessor owner’s equity and debt amounts with the new equity and debt capitalization, as described below. The Unaudited Pro Forma Combined Financial Statements include adjustments to give effect to:

 

(i)

the receipt of the estimated net proceeds of approximately $42.4 million from the issuance of 2,000,000 shares of common stock in this offering at an assumed public offering price of $22.95 per share, which was the closing price of Unitil’s common stock on November 17, 2008 and the application of the estimated net proceeds from this offering;

 

(ii)

the sale and issuance by Northern Utilities of $80.0 million aggregate principal amount of long-term unsecured notes, which closed on December 3, 2008;

 

(iii)

the anticipated sale and issuance by Granite State of $10.0 million aggregate principal amount of long-term unsecured notes;

 

(iv)

the receipt of proceeds from the financing by Northern Utilities of its natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007;

 

(v)

the anticipated utilization of a bridge credit facility to fund the residual portion of the Acquisitions of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007;

 

(vi)

certain other adjustments related to assets and liabilities retained by NiSource, Inc. (“NiSource”, the ultimate parent company of Northern Utilities and Granite State); and

 

(vii)

to record Northern Utilities’ financing obligation for natural gas in storage.

The Unaudited Pro Forma Combined Financial Statements exclude adjustments to recognize:

 

(i)

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;

 

(ii)

a reduction in operating expenses of $1.7 million, after tax, related to compliance violation penalties incurred by Northern Utilities in 2007 and $2.0 million, after tax, related to compliance violation penalties incurred by Northern Utilities in the first nine months of 2008;

 

(iii)

a reduction in Purchased Gas costs of $0.5 million and a resulting increase in gross operating margin for 2007 to reflect an error in a prior regulatory filing for which Northern Utilities has been granted recovery; and

 

(iv)

adjustments to recognize the enhancements to revenue of Northern Utilities and Granite State that may occur from the execution of our regulatory plan.

The Unaudited Pro Forma Combined Financial Statements (i) reflect that we financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility coupled with

 

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proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract and (ii) assume that we will use the net proceeds from the sale and issuance of Unitil’s common stock and the sale and issuance of the above-referenced long-term unsecured notes to promptly repay amounts outstanding under the bridge credit facility, except for $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007.

The Unaudited Pro Forma Combined Financial Statements are presented for illustrative purposes only and do not indicate the financial results of the combined companies had the companies actually been combined and had the impact of possible revenue enhancements and expense efficiencies, among other factors, been considered, and is not intended to be a projection of future results. The Unaudited Pro Forma Combined Financial Statements should be read in conjunction with the notes thereto included in this prospectus.

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED BALANCE SHEETS

(Millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA
								For the Acquisitions														For the Offering and Related Financing Transactions
ASSETS
September 30, 2008
Property Plant and Equipment:
Electric		$	275.5		$	0.0		$	0.0						$	0.0						$	0.0					$	275.5
Gas			71.3			254.9			0.0							0.0							0.0						326.2
Common			27.3			0.0			0.0							0.0							0.0						27.3
Plant Acquisition Adjustment			0.0			0.0			0.0							(28.2	)		(M	)			6.6			(G)			(21.6	)
Construction Work in Progress			10.9			5.2			0.0							0.0							0.0						16.1
Property, Plant and Equipment			385.0			260.1			0.0							(28.2	)						6.6						623.5
Less: Accumulated Depreciation			129.0			68.0			0.0							0.0							0.0						197.0
Net Property, Plant and Equipment			256.0			192.1			0.0							(28.2	)						6.6						426.5
Current Assets:
Cash			5.0			5.1			0.0							(194.4	)		(A	)			189.8			(H)			5.5
Accounts Receivable—Net of Allowance for Doubtful Accounts			23.2			6.9			0.0							0.0							0.0						30.1
Accrued Revenue			14.7			2.9			0.0							0.0							0.0						17.6
Exchange Gas Receivable			0.0			7.6			0.0							0.0							0.0						7.6
Gas Inventory			0.0			30.5			0.0							0.0							0.0						30.5
Prepayments and Other			6.6			8.8			0.0							0.0							0.0						15.4
Total Current Assets			49.5			61.8			0.0							(194.4	)						189.8						106.7
Noncurrent Assets:
Regulatory Assets			150.3			20.5			(4.7	)		(B	)			0.0							0.0						166.1
Other Noncurrent Assets			11.7			79.2			(0.6	)		(B	)			(78.5	)		(C	)			0.7			(I)			12.5
Total Noncurrent Assets			162.0			99.7			(5.3	)						(78.5	)						0.7						178.6
TOTAL		$	467.5		$	353.6		$	(5.3	)					$	(301.1	)					$	197.1					$	711.8

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

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED BALANCE SHEETS

(Millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA
								For the Acquisitions														For the Offerings and Related Financing Transactions
CAPITALIZATION AND LIABILITIES
September 30, 2008
Capitalization:
Common Stock Equity		$	99.9		$	133.1		$	(0.4	)		(B	)		$	(132.7	)		(D	)		$	42.4		(J	)		$	142.3
Preferred Stock			2.0			0.0			0.0							0.0							0.0						2.0
Long-Term Debt, Less Current Portion			159.4			0.0			0.0							0.0							90.0		(K	)			249.4
Total Capitalization			261.3			133.1			(0.4	)						(132.7	)						132.4						393.7
Current Liabilities:
Long-Term Debt, Current Portion			0.4			61.7			0.0							(61.7	)		(E	)			0.0						0.4
Short-Term Debt			21.7			42.8			0.0							(42.8	)		(E	)			34.2		(L	)			55.9
Accounts Payable			18.0			12.6			(1.0	)		(B	)			0.0							0.0						29.6
Over Recovered Gas Costs			0.0			3.5			0.0							0.0							0.0						3.5
Other Current Liabilities			10.2			11.4			(0.1	)		(B	)			0.0							0.0						21.5
Total Current Liabilities			50.3			132.0			(1.1	)						(104.5	)						34.2						110.9
Deferred Income Taxes			34.4			63.9			0.0							(63.9	)		(F	)			0.0						34.4
Noncurrent Liabilities:
Energy Supply Contract Obligations			57.7			0.0			0.0							0.0							30.5		(N	)			88.2
Retirement Benefit Obligations			49.5			4.1			(3.4	)		(B	)			0.0							0.0						50.2
Environmental Obligations			12.0			1.3			0.0							0.0							0.0						13.3
Asset Retirement Obligation			0.0			1.4			0.0							0.0							0.0						1.4
Regulatory Liabilities and Cost of Removal			0.0			16.9			(0.4	)		(B	)			0.0							0.0						16.5
Other Noncurrent Liabilities			2.3			0.9			0.0							0.0							0.0						3.2
Total Noncurrent Liabilities			121.5			24.6			(3.8	)						0.0							30.5						172.8
TOTAL		$	467.5		$	353.6		$	(5.3	)					$	(301.1	)					$	197.1					$	711.8

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

 

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(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

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UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED STATEMENTS OF EARNINGS

(Millions except common shares and per share data)

 

		UNITIL			NU & GS				PRO FORMA ADJUSTMENTS																					PRO FORMA
									For the Acquisitions														For the Offering and Related Financing Transactions
Nine Months Ended September 30, 2008
Operating Revenues:
Electric		$	172.2		$	0.0			$	0.0						$	0.0						$	0.0						$	172.2
Gas			25.3			87.7				0.0							0.0							0.0							113.0
Other			2.9			0.0				0.0							0.0							0.0							2.9
Total Operating Revenues			200.4			87.7				0.0							0.0							0.0							288.1
Operating Expenses:
Purchased Electricity			128.4			0.0				0.0							0.0							0.0							128.4
Purchased Gas			15.3			54.5				0.0							0.0							0.0							69.8
Operation and Maintenance			18.7			21.4				0.0							0.0							0.0							40.1
Conservation & Load Management			2.1			0.0				0.0							0.0							0.0							2.1
Depreciation and Amortization			14.3			8.9				(2.1	)		(O	)			(1.9	)		(Q	)			0.5			(T	)			19.7
Provisions for Taxes:
Local Property and Other			4.5			2.3				0.0							0.0							0.0							6.8
Federal and State Income			3.0			(0.4	)			0.9			(P	)			1.9			(P	)			(2.8	)		(P	)			2.6
Total Operating Expenses			186.3			86.7				(1.2	)						0.0							(2.3	)						269.5
Operating Income			14.1			1.0				1.2							0.0							2.3							18.6
Non-Operating Expenses			0.3			0.0				0.0							0.0							0.0							0.3
Income Before Interest Expense			13.8			1.0				1.2							0.0							2.3							18.3
Interest Expense, net			7.3			2.4				0.0							(2.8	)		(R	)			6.6			(U	)			13.5
Net Income			6.5			(1.4	)			1.2							2.8							(4.3	)						4.8
Less: Dividends on Preferred Stock			0.1			0.0				0.0							0.0							0.0							0.1
Earnings Applicable to Common Shareholders		$	6.4		$	(1.4	)		$	1.2						$	2.8						$	(4.3	)					$	4.7
Average Common Shares Outstanding—Basic (000s)			5,733														2,000			(S	)										7,733
Average Common Shares Outstanding—Diluted (000s)			5,738														2,000														7,738
Earning per Common Share ($)
Basic		$	1.12																											$	0.61
Diluted		$	1.12																											$	0.61

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

 

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(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

F-8

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Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED STATEMENTS OF EARNINGS

(Millions except common shares and per share data)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																					PRO FORMA
								For the Acquisitions														For the Offering and Related Financing Transactions
Nine Months Ended September 30, 2007
Operating Revenues:
Electric		$	171.3		$	0.0		$	0.0						$	0.0						$	0.0						$	171.3
Gas			24.5			95.8			0.0							0.0							0.0							120.3
Other			2.8			0.0			0.0							0.0							0.0							2.8
Total Operating Revenues			198.6			95.8			0.0							0.0							0.0							294.4
Operating Expenses:
Purchased Electricity			126.4			0.0			0.0							0.0							0.0							126.4
Purchased Gas			15.8			62.2			0.0							0.0							0.0							78.0
Operation and Maintenance			19.8			19.1			0.0							0.0							0.0							38.9
Conservation & Load Management			2.9			0.0			0.0							0.0							0.0							2.9
Depreciation and Amortization			13.4			8.2			(2.1	)		(O	)			(1.9	)		(Q	)			0.5			(T	)			18.1
Provisions for Taxes:
Local Property and Other			4.2			2.1			0.0							0.0							0.0							6.3
Federal and State Income			3.2			1.1			0.8			(P	)			2.3			(P	)			(3.4	)		(P	)			4.0
Total Operating Expenses			185.7			92.7			(1.3	)						0.4							(2.9	)						274.6
Operating Income			12.9			3.1			1.3							(0.4	)						2.9							19.8
Non-Operating Expenses			0.1			0.0			0.0							0.0							0.0							0.1
Income Before Interest Expense			12.8			3.1			1.3							(0.4	)						2.9							19.7
Interest Expense, net			6.8			2.5			0.0							(3.7	)		(R	)			7.8			(U	)			13.4
Net Income			6.0			0.6			1.3							3.3							(4.9	)						6.3
Less: Dividends on Preferred Stock			0.1			0.0			0.0							0.0							0.0							0.1
Earnings Applicable to Common Shareholders		$	5.9		$	0.6		$	1.3						$	3.3						$	(4.9	)					$	6.2
Average Common Shares Outstanding—Basic (000s)			5,643													2,000			(S	)										7,643
Average Common Shares Outstanding—Diluted (000s)			5,659													2,000														7,659
Earning per Common Share ($)
Basic		$	1.04																										$	0.81
Diluted		$	1.04																										$	0.81

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

 

F-9

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Table of Contents

 

(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

F-10

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[THIS PAGE INTENTIONALLY LEFT BLANK]

 

 

 

F-11

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Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED BALANCE SHEETS

(Millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																					PRO FORMA
								For the Acquisitions														For the Offering and Related Financing Transactions
ASSETS
December 31, 2007
Property Plant and Equipment:
Electric		$	266.2		$	0.0		$	0.0						$	0.0						$	0.0						$	266.2
Gas			67.8			245.1			0.0							0.0							0.0							312.9
Common			26.2			0.0			0.0							0.0							0.0							26.2
Plant Acquisition Adjustment			0.0			0.0			0.0							(21.2	)		(M	)			6.6			(G	)			(14.6	)
Construction Work in Progress			20.3			4.4			0.0							0.0							0.0							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			0.0							0.0							0.0							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			0.0							(197.7	)		(A	)			195.8			(H	)			5.8
Accounts Receivable—Net of allowance for
Doubtful Accounts			24.9			18.0			0.0							0.0							0.0							42.9
Accrued Revenue			12.7			14.0			0.0							0.0							0.0							26.7
Gas Inventory			0.0			13.4			0.0							0.0							0.0							13.4
Prepayments and Other			6.7			6.2			0.0							0.0							0.0							12.9
Total Current Assets			48.9			54.7			0.0							(197.7	)						195.8							101.7
Noncurrent Assets:
Regulatory Assets			170.5			20.4			(5.0	)		(B	)			0.0							0.0							185.9
Other Noncurrent Assets			6.3			81.0			(0.5	)		(B	)			(80.5	)		(C	)			0.7			(I	)			7.0
Total Noncurrent Assets			176.8			101.4			(5.5	)						(80.5	)						0.7							192.9
TOTAL		$	474.6		$	342.2		$	(5.5	)					$	(299.4	)					$	203.1						$	715.0

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

 

F-12

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Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED BALANCE SHEETS — (Continued)

(Millions)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																				PRO FORMA
								For the Acquisitions														For the Offering and Related Financing Transactions
CAPITALIZATION AND LIABILITIES
December 31, 2007
Capitalization:
Common Stock Equity		$	100.4		$	134.4		$	(0.4	)		(B	)		$	(134.0	)		(D	)		$	42.4			(J)		$	142.8
Preferred Stock			2.1			0.0			0.0							0.0							0.0						2.1
Long-Term Debt, Less Current Portion			159.6			61.7			0.0							(61.7	)		(E	)			90.0			(K)			249.6
Total Capitalization			262.1			196.1			(0.4	)						(195.7	)						132.4						394.5
Current Liabilities:
Long-Term Debt, Current Portion			0.4			0.8			0.0							(0.8	)		(E	)			0.0						0.4
Short-Term Debt			18.8			39.0			0.0							(39.0	)		(E	)			57.3			(L)			76.1
Accounts Payable			17.6			11.1			0.0							0.0							0.0						28.7
Other Current Liabilities			7.3			7.0			(0.5	)		(B	)			0.0							0.0						13.8
Total Current Liabilities			44.1			57.9			(0.5	)						(39.8	)						57.3						119.0
Deferred Income Taxes			33.4			63.9			0.0							(63.9	)		(F	)			0.0						33.4
Noncurrent Liabilities:
Energy Supply Contract Obligations			72.7			0.0			0.0							0.0							13.4			(N)			86.1
Retirement Benefit Obligations			48.2			4.7			(4.3	)		(B	)			0.0							0.0						48.6
Environmental Obligations			12.0			1.8			0.0							0.0							0.0						13.8
Asset Retirement Obligation			0.0			1.3			0.0							0.0							0.0						1.3
Regulatory Liabilities and Cost of Removal			0.0			15.9			(0.3	)		(B	)			0.0							0.0						15.6
Other Noncurrent Liabilities			2.1			0.6			0.0							0.0							0.0						2.7
Total Noncurrent Liabilities			135.0			24.3			(4.6	)						0.0							13.4						168.1
TOTAL		$	474.6		$	342.2		$	(5.5	)					$	(299.4	)					$	203.1					$	715.0

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

 

F-13

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Table of Contents

 

 

(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

F-14

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Table of Contents

UNITIL CORPORATION AND SUBSIDIARY COMPANIES (includes NU & GS)

PRO FORMA COMBINED STATEMENTS OF EARNINGS

(Millions except common shares and per share data)

 

		UNITIL			NU & GS			PRO FORMA ADJUSTMENTS																					PRO FORMA
								For the Acquisitions														For the Offering and Related Transactions
Twelve Months Ended December 31, 2007
Operating Revenues:
Electric		$	225.0		$	0.0		$	0.0						$	0.0						$	0.0						$	225.0
Gas			34.2			133.3			0.0							0.0							0.0							167.5
Other			3.7			0.0			0.0							0.0							0.0							3.7
Total Operating Revenues			262.9			133.3			0.0							0.0							0.0							396.2
Operating Expenses:
Purchased Electricity			165.4			0.0			0.0							0.0							0.0							165.4
Purchased Gas			21.3			85.7			0.0							0.0							0.0							107.0
Operation and Maintenance			26.2			26.6			0.0							0.0							0.0							52.8
Conservation & Load Management			3.6			0.0			0.0							0.0							0.0							3.6
Depreciation and Amortization			17.8			11.0			(2.1	)		(O	)			(2.6	)		(Q	)			0.7			(T	)			24.8
Provisions for Taxes:
Local Property and Other			5.6			2.8			0.0							0.0							0.0							8.4
Federal and State Income			4.5			1.7			0.8			(P	)			2.8			(P	)			(4.4	)		(P	)			5.4
Total Operating Expenses			244.4			127.8			(1.3	)						0.2							(3.7	)						367.4
Operating Income			18.5			5.5			1.3							(0.2	)						3.7							28.8
Non-Operating Expenses			0.2			0.1			0.0							0.0							0.0							0.3
Income Before Interest Expense			18.3			5.4			1.3							(0.2	)						3.7							28.5
Interest Expense, net			9.6			3.4			0.0							(4.9	)		(R	)			10.1			(U	)			18.2
Net Income			8.7			2.0			1.3							4.7							(6.4	)						10.3
Less: Dividends on Preferred Stock			0.1			0.0			0.0							0.0							0.0							0.1
Earnings Applicable to Common Shareholders		$	8.6		$	2.0		$	1.3						$	4.7						$	(6.4	)					$	10.2
Average Common Shares Outstanding—Basic (000s)			5,659													2,000			(S	)										7,659
Average Common Shares Outstanding—Diluted (000s)			5,672													2,000														7,672
Earning per Common Share ($)
Basic		$	1.52																										$	1.33
Diluted		$	1.52																										$	1.33

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

 

F-15

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Table of Contents

 

 

(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

F-16

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Table of Contents

UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

SEPTEMBER 30, 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 September 30, 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 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 Acquisitions, at their fair values and added to those of Unitil. The Unaudited Pro Forma Combined Balance Sheets as of December 31, 2007 and September 30, 2008 assume the Acquisitions were completed on those dates. The Unaudited Pro Forma Combined Statements of Earnings give effect to the Acquisitions as if they had been completed on January 1, 2007.

The Unaudited Pro Forma Combined Financial Statements include adjustments for the Acquisitions pursuant to the purchase method of accounting for business combinations (pursuant to which the assets and liabilities of Northern Utilities and Granite State were recorded, as of the closing of the Acquisitions, at their fair values and added to our assets and liabilities) and the replacement of the predecessor owner’s equity and debt amounts with the new equity and debt capitalization, as described below. The Unaudited Pro Forma Combined Financial Statements include adjustments to give effect to:

 

(i)

the receipt of the estimated net proceeds of approximately $42.4 million from the issuance of 2,000,000 shares of common stock in this offering at an assumed public offering price of $22.95 per share, which was the closing price of Unitil’s common stock on November 17, 2008, and the application of the estimated net proceeds from this offering;

 

(ii)

the sale and issuance by Northern Utilities of $80.0 million aggregate principal amount of long-term unsecured notes, which closed on December 3, 2008;

 

(iii)

the anticipated sale and issuance by Granite State of $10.0 million aggregate principal amount of long-term unsecured notes;

 

(iv)

the receipt of proceeds from the financing by Northern Utilities of its natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007;

 

(v)

the anticipated utilization of a bridge credit facility to fund the residual portion of the Acquisitions of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007;

 

(vi)

certain other adjustments related to assets and liabilities retained by NiSource; and

 

(vii)

to record Northern Utilities’ financing obligation for natural gas in storage.

The Unaudited Pro Forma Combined Financial Statements exclude adjustments to recognize:

 

(i)

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;

 

(ii)

a reduction in operating expenses of $1.7 million, after tax, related to compliance violation penalties incurred by Northern Utilities in 2007 and $2.0 million, after tax, related to compliance violation penalties incurred by Northern Utilities in the first nine months of 2008;

 

F-17

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Table of Contents

UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

SEPTEMBER 30, 2008 AND DECEMBER 31, 2007

 

(iii)

a reduction in Purchased Gas costs of $0.5 million and a resulting increase in gross operating margin for 2007 to reflect an error in a prior regulatory filing for which Northern Utilities has been granted recovery; and

 

(iv)

adjustments to recognize the enhancements to revenue of Northern Utilities and Granite State that may occur from the execution of our regulatory plan.

The Unaudited Pro Forma Combined Financial Statements (i) reflect that Unitil financed the Acquisitions and the related costs and expenses using borrowings under a bridge credit facility coupled with proceeds from the contemporaneous financing of Northern Utilities’ gas inventory pursuant to a gas storage management contract and (ii) assume that we will use the net proceeds from the sale and issuance of Unitil’s common stock and the sale and issuance of the above-referenced long-term unsecured notes to promptly repay amounts outstanding under the bridge credit facility, except for an estimated except for $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007.

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 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 the Acquisitions in accordance with Financial Accounting Standards Board Statement No. 141 (Revised 2007), “Business Combinations.”

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 Acquisitions will be accounted for in accordance with Financial Accounting Standards Board Statement No. 141, “Business Combinations.” If the Acquisitions are completed subsequent to December 31, 2008, Unitil will account for the Acquisitions in accordance with Financial Accounting Standards Board Statement No. 141 (Revised 2007), “Business Combinations” and the amounts may change.

 

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UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

SEPTEMBER 30, 2008 AND DECEMBER 31, 2007

 

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 Acquisitions; (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 Acquisitions.

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				September 30, 2008
Equity Purchase Price		$	160.0			$	160.0
Plus: Working Capital Adjustment			37.7				34.4
Asset Purchase Price			197.7				194.4
Plus: Transaction Fees			6.6				6.6
Total Cash Purchase Price			204.3				201.0
Less: Book Value of Net Property Plant and Equipment			(186.1	)			(192.1	)
Less: Current Assets			(54.7	)			(61.8	)
Less: Other Long-term Assets (Excluding Intangibles)			(15.4	)			(15.9	)
Less: Transaction Fees			(6.6	)			(6.6	)
Plus: Accounts Payable			11.1				11.6
Plus: Other Current Liabilities			6.5				14.8
Plus: Non-Current Liabilities (Excluding Deferred Taxes)			19.7				20.8
Bargain Purchase Price –Plant Acquisition Adjustment		$	(21.2	)		$	(28.2	)

Note 4 Combined Pro Forma Adjustments

 

(A)

To record purchase price of $160 million and working capital adjustments of $34.4 million as of September 30, 2008 and $37.7 million as of December 31, 2007 for the Acquisitions.

 

(B)

To adjust pension / post-retirement benefits other than pension and accrued interest to reflect liabilities retained by NiSource.

 

(C)

To eliminate Northern Utilities’ and Granite State’s intangible assets retained by NiSource.

 

(D)

To eliminate Northern Utilities’ and Granite State’s common stock equity.

 

(E)

To eliminate Northern Utilities’ and Granite State’s short and long term debt, which will not transfer to Unitil.

 

(F)

To eliminate Northern Utilities’ and Granite State’s deferred taxes due to 338(h)(10) election.

 

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UNITIL CORPORATION

NOTES TO UNAUDITED PRO FORMA

COMBINED FINANCIAL STATEMENTS — (Continued)

SEPTEMBER 30, 2008 AND DECEMBER 31, 2007

 

(G)

To record transaction costs associated with the Acquisitions.

 

(H)

To record cash received from: (a) Unitil’s common stock offering of $42.4 million, net of issuance costs; (b) the issuance by Northern Utilities and Granite State of long-term debt of $89.3 million, net of issuance costs; (c) proceeds from the financing of natural gas storage inventory of $30.5 million as of September 30, 2008 and $13.4 million as of December 31, 2007; (d) the unpaid portion of the bridge facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007; and (e) net of cash paid for transaction costs of $6.6 million.

 

(I)

To record costs associated with the issuance of Northern Utilities’ and Granite State’s new long-term debt.

 

(J)

To record the effect of Unitil’s common stock offering, net of related underwriters’ commissions and fees and other expenses.

 

(K)

To record the issuance of new long term debt by Northern Utilities and Granite State.

 

(L)

To record the residual unpaid portion of the bridge credit facility of $34.2 million as of September 30, 2008 and $57.3 million as of December 31, 2007 used to finance the Acquisitions.

 

(M)

To record plant acquisition adjustment in connection with the Acquisitions.

 

(N)

To record Northern Utilities’ financing obligation for natural gas in storage.

 

(O)

To amortize plant acquisition adjustment over 10 years as authorized by utility regulators.

 

(P)

To provide for the income tax effect of the pro forma adjustments at an assumed tax rate of 40%.

 

(Q)

To eliminate Northern Utilities’ and Granite State’s plant acquisition premium amortization in connection with the Acquisitions.

 

(R)

To eliminate Northern Utilities’ and Granite State’s interest expense in connection with Northern Utilities’ and Granite State’s short and long-term debt, which will not transfer to Unitil.

 

(S)

To adjust outstanding common shares for issuance of Unitil’s new common stock.

 

(T)

To amortize transaction costs over 10 years as authorized by utility regulators.

 

(U)

To adjust interest expense due to issuance of new long-term debt by Northern Utilities and Granite State and interest related to the utilization of Unitil’s revolving line of credit to finance working capital.

 

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NORTHERN UTILITIES, INC.

 

 

UNAUDITED CONDENSED FINANCIAL STATEMENTS AS OF

AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

 

 

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NORTHERN UTILITIES, INC.

CONDENSED BALANCE SHEETS — UNAUDITED

(in thousands)

 

		As of September 30, 2008				As of September 30, 2007
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
Gas utility plant		$	229,463			$	216,380
Less: accumulated depreciation and amortization			(60,107	)			(54,725	)
Net utility plant			169,356				161,655
Other property, at cost, less accumulated depreciation			943				1,077
Construction work in progress			4,777				3,425
Net property, plant and equipment			175,076				166,157
CURRENT ASSETS:
Cash and cash equivalents			304				464
Restricted cash			4,727				2,380
Accounts and notes receivable, net of reserve of $1,497 and $888, respectively			4,425				4,988
Unbilled revenue, net of reserve of $37 and $32, respectively			2,781				2,371
Receivables from associated companies			9,976				624
Gas inventory			2,771				1,721
Prepaid gas costs			30,450				—
Materials and supplies, at average cost			1,491				1,428
Prepaid income taxes			818				2,353
Exchange gas receivable			—				24,467
Regulatory assets			2,812				1,790
Other current assets			484				640
Total current assets			61,039				43,226
DEFERRED CHARGES:
Regulatory assets			20,043				22,191
Intangible assets, net of amortization			70,645				72,974
Other deferred charges			573				6
Total deferred charges			91,261				95,171
TOTAL ASSETS		$	327,376			$	304,554

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

 

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NORTHERN UTILITIES, INC.

CONDENSED BALANCE SHEETS — UNAUDITED — (Continued)

(in thousands)

 

		As of September 30, 2008			As of September 30, 2007
CAPITALIZATION AND LIABILITIES
COMMON STOCK EQUITY:
Common stock — $10 par value, 100 common shares issued and outstanding		$	1		$	1
Additional paid in capital			109,175			109,175
Retained earnings			11,242			11,154
Total common stock equity			120,418			120,330
LONG-TERM DEBT TO PARENT COMPANY			—			60,000
LONG-TERM UNAFFILIATED DEBT			—			1,667
Total capitalization			120,418			181,997
CURRENT LIABILITIES:
Current maturities of long term debt			61,667			833
Short term debt — affiliated			35,459			26,038
Payables to affiliated companies			5,169			3,088
Accounts payable			7,145			6,468
Accrued taxes			351			1,425
Price risk liabilities			2,538			1,035
Deferred income taxes			1,920			1,873
Regulatory liabilities			3,671			1,356
Customer deposits			1,639			1,409
Over recovered gas costs			3,506			227
Other current liabilities			3,024			2,121
Total current liabilities			126,089			45,873
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred income taxes			56,560			53,690
Deferred investment tax credits			123			147
Postretirement benefits other than pensions			3,229			4,098
Asset retirement obligations			1,292			1,393
Regulatory liabilities and other removal costs			16,925			15,459
Environmental accruals			1,277			938
Pensions			543			291
Other			920			668
Total other liabilities and deferred credits			80,869			76,684
TOTAL CAPITALIZATION AND LIABILITIES		$	327,376		$	304,554

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

 

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NORTHERN UTILITIES, INC.

CONDENSED STATEMENTS OF (LOSS) INCOME — UNAUDITED

(in thousands)

 

		Nine Months Ended September 30,
		2008				2007
NET REVENUES:
Gas Distribution		$	85,574			$	93,563
Cost of sales (excludes depreciation and amortization)			54,558				62,148
Total net revenues			31,016				31,415
OPERATING EXPENSES:
Operations and maintenance			20,072				17,878
Depreciation and amortization			8,229				7,533
Taxes other than income			2,156				1,901
Total operating expenses			30,457				27,312
OPERATING INCOME			559				4,103
OTHER INCOME (DEDUCTIONS):
Interest expense, net			(2,152	)			(2,117	)
Other, net			34				(17	)
Total other income (deductions)			(2,118	)			(2,134	)
(LOSS) INCOME BEFORE TAX			(1,559	)			1,969
INCOME TAX (BENEFIT) EXPENSE			(342	)			1,085
NET (LOSS) INCOME		$	(1,217	)		$	884

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

 

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NORTHERN UTILITIES, INC.

CONDENSED STATEMENTS OF CASH FLOWS — UNAUDITED

(in thousands)

 

		Nine Months Ended September 30,
		2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income		$	(1,217	)		$	884
Adjustments to reconcile net (loss) income to net cash flows from operating activities:
Depreciation and amortization			8,229				7,533
Deferred income taxes and investment tax credits			75				(1,978	)
Changes in assets and liabilities:
Accounts receivable and unbilled revenue			18,096				14,864
Accounts payable			2,066				(4,069	)
Accrued taxes			(725	)			1,343
Regulatory assets/liabilities			3,077				1,168
Pension and other postretirement benefits			(714	)			(3,701	)
Exchange gas payable/receivable			13,378				1,953
Over (under) recovered gas and fuel costs			(366	)			7,013
Prepaid gas costs			(30,450	)			—
Gas Inventory			(1,393	)			(93	)
Other — net			(93	)			(60	)
Net cash provided by operating activities			9,963				24,857
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(11,531	)			(12,103	)
Restricted cash			(3,072	)			1,826
Net cash used in investing activities			(14,603	)			(10,277	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt — unaffiliated			(833	)			(833	)
Short term debt — affiliated			4,401				(13,473	)
Net cash provided by (used in) financing activities			3,568				(14,306	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS			(1,072	)			274
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD			1,376				190
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	304			$	464
Cash paid during period for interest		$	2,017			$	2,624
Allowance for funds used during construction — debt		$	57			$	70
Income taxes paid		$	258			$	1,724

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

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 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 Financial Accounting Standards Board (“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 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 NINE MONTHS ENDED SEPTEMBER 30, 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 Emerging Issues Task Force (“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 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 such as intangible assets.

In October 2008, the FASB issued FSP 157-d, “Determining the Fair Value of a Financial Asset in a Market that is Not Active” which clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued.

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. 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 “Accounting for the Effects of Certain Types of Regulation”. 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.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

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 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 FASB Interpretation (“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.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

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 Unaudited Condensed Financial Statements.

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 September 30, 2008, the Company has $70.6 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 September 30, 2007 was $73.0 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 accumulated amortization balance is $22.1 million and $19.7 million at September 30, 2008 and September 30, 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 nine months ended September 30, 2008 and September 30, 2007 was $1.7 million and $1.7 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

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

or expects to collect in future rates. The asset retirement obligations liability totaled $1.3 million and $1.4 million at September 30, 2008 and 2007, respectively. The changes in the asset retirement obligation for the nine months ended September 30, 2008 and 2007 are presented in the table below (in whole dollars):

 

		Nine Months Ended September 30,
		2008			2007
Beginning Balance		$	1,229,242		$	1,328,309
Accretion			62,546			64,287
Ending Balance		$	1,291,788		$	1,392,596

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 nine months ended September 30, 2008 and September 30, 2007 were 21.9% and 55.1%, respectively. The decrease in the effective tax rate was due primarily to the tax expense associated with non-deductible expenses (recorded through operating expenses) as a ratio to pre-tax income. The pre-tax loss for the nine months ended September 30, 2008 dilutes the effect of this additional tax expense resulting in a lower effective tax rate. 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.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

The accompanying balance sheets include a price risk management liability related to net unrealized losses on current futures contracts of $2.5 million and $1.0 million at September 30, 2008 and September 30, 2007, respectively. Additionally, the balance sheet includes price risk management liabilities related to net unrealized losses on non-current futures contracts of $0.4 million and zero million at September 30, 2008 and September 30, 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.

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 $0.2 million for nine months ended September 30, 2008. Pension expense was approximately $0.2 million for the nine months ended September 30, 2007.

The Company has not made any contributions to the Pension trust in 2008. Contributions of approximately $1.6 million were made for the nine months ended September 30, 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 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 the Bay State Gas Company, has contributed to an OPEB trust fund specifically created for post-employment benefits.

The Company’s OPEB expense was approximately $0.4 million and $0.5 million for the nine months ended September 30, 2008 and 2007, respectively.

Contributions of approximately $0.9 million and $1.5 million were made in the first nine months of September 2008 and 2007, respectively.

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

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

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 Prepaid Gas

Due to expiration of a storage contract early in 2008, the Company is using prepaid gas contracts as a means of filling storage. The Company is accounting for the ratable payment of the gas as a prepayment and will transfer the prepayment to a storage asset account in November’s business when the Company assumes title to the gas.

Note 10 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 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 Corporation 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. As of September 30, 2008, NiSource has recorded an after tax loss of approximately $56.7 million related to the pending sale of Northern Utilities.

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 Maine Public Utilities Commission (“MPUC”) initiated a formal investigation into three Notices of Probable Violations (“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 a regulator failure; and (5) Northern Utilities had failed to properly design one of its regulator stations.

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 (Docket Nos. 2008-095, 097 and 098), the MPUC initiated a formal investigation into three NOPVs alleging that Northern Utilities had violated various provisions of the federal pipeline safety regulations. Northern Utilities has responded to each of these NOPVs in a timely manner.

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

Northern Utilities and the MPUC engaged in extensive settlement discussions regarding all of the dockets identified herein and, on September 8, 2008, filed a comprehensive settlement (“Settlement”) with the MPUC. Under the Settlement, Northern Utilities would incur total expenditures of $3.2 million, comprised of (i) a monetary penalty, (ii) certain safety-related improvements to Northern Utilities’ pipeline system and (iii) obligations to be undertaken for Northern Utilities’ distribution system to ensure compliance with the relevant gas safety laws of the State of Maine and the U.S. Code. Approximately $0.5 million has been incurred to date.

The MPUC considered the Settlement at a deliberative meeting on October 6, 2008. At that meeting, the MPUC approved the Settlement with several modifications, including one limiting Northern Utilities’ ability to challenge or delay implementation of any recommendation made by a consultant (“SEA Consulting”) engaged by Northern Utilities and the MPUC which will impair Northern Utilities’ ability to recover any costs for regulator station improvements recommended by SEA Consulting from customers. The SEA Consulting report was delivered in draft form on October 17, 2008. Northern Utilities is presently reviewing SEA Consulting’s draft report to determine whether it can comply with the MPUC’s condition on the Settlement and is considering legal options with regard to the MPUC’s order on the Settlement.

New Hampshire Public Utilities Commission Docket No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the New Hampshire Public Utilities Commission (“NHPUC”) issued Order No. 24,798 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that lost and unaccounted for gas (“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 ended 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 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 cause appears 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 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 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 758,702 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. This

 

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NORTHERN UTILITIES, INC.

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)

AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

overcharge in turn was passed on to Northern Utilities’ customers through the normal operation of the gas cost recovery mechanism.

In September 2008, Northern Utilities received information that Spectra, PNGTS and Granite State had agreed to resolve the matter by flowing the 758,702 Dth back through the imbalance provisions of the respective tariffs in force between the parties (“in-kind reimbursement”). Upon receiving this information, Northern Utilities filed with the NHPUC and the MPUC for approval of this method of reimbursement for the metering error. In October 2008, Northern Utilities received permission from both the NHPUC and the MPUC for the rate treatment of in-kind reimbursement through the Northern Utilities’ cost of gas adjustment and approval of the commencement of the flow-back of natural gas starting November 1, 2008. As of September 30, 2008, Northern Utilities has recorded approximately $7.6 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.

Note 11 Long-term debt

As of September 30, 2008, Northern Utilities reclassified all long-term debt to a current liability. Unaffiliated debt of $1.7 million was fully paid in advance in the fourth quarter of 2008. Affiliated debt to a NiSource subsidiary with an outstanding balance of $60 million is scheduled to be fully paid in advance with the proceeds of the sale of Northern Utilities to Unitil Corporation within the next twelve months.

 

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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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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 AND FOR THE NINE MONTHS ENDED

SEPTEMBER 30, 2008 AND 2007

 

 

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED BALANCE SHEETS (UNAUDITED)

		As of September 30, 2008				As of September 30, 2007
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
Utility plant		$	23,930,948			$	23,784,837
Less: accumulated depreciation and amortization			(7,866,691	)			(7,622,221	)
Net utility plant			16,064,257				16,162,616
Other property			600,000				600,000
Construction work in progress			374,461				87,910
Net property, plant and equipment			17,038,718				16,850,526
CURRENT ASSETS:
Cash and cash equivalents			126,604				33,931
Accounts and notes receivable, net of reserve of $4,200 in 2008 and $10,000 in 2007			101,613				42,542
Receivables from affiliated companies			586,938				458,689
Exchange gas receivable			7,596,445				—
Regulatory assets			55,561				112,761
Prepayments			12,144				21,318
Prepayments — affiliated			5,359				11,243
Taxes receivable			145,728				132,633
Taxes receivable from affiliated companies			288,289				964,885
Total current assets			8,918,681				1,778,002
DEFERRED CHARGES:
Regulatory assets			454,672				548,574
Intangible assets, net of amortization			7,931,263				8,193,454
Other deferred charges			53,996				—
Total deferred charges			8,439,931				8,742,028
TOTAL ASSETS		$	34,397,330			$	27,370,556

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED BALANCE SHEETS (UNAUDITED) — (Continued)

 

		As of September 30, 2008				As of September 30, 2007
STOCKHOLDER’S EQUITY AND LIABILITIES
COMMON STOCKHOLDER’S EQUITY
Common Stock		$	29,900			$	29,900
Other paid in capital			26,494,541				26,494,541
Accumulated deficit			(13,866,826	)			(13,823,716	)
Total stockholder’s equity			12,657,615				12,700,725
CURRENT LIABILITIES:
Payables to affiliated companies			763,574				459,318
Exchange gas payable — affiliated			7,596,445				—
Short term borrowings from affiliated companies			7,313,057				7,794,881
Accounts payable			68,753				161,626
Interest accrued			—				3,892
Customer deposits			9,894				9,894
Other current liabilities			227,549				100,785
Total current liabilities			15,979,272				8,530,396
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred income taxes			5,272,691				5,750,490
Deferred investment tax credits			12,003				13,323
Asset retirement obligations			133,658				126,151
Regulatory liabilities			29,646				25,489
Pensions and other postretirement benefits			312,445				223,982
Total other liabilities and deferred credits			5,760,443				6,139,435
COMMITMENTS AND CONTINGENCIES			—				—
TOTAL STOCKHOLDER’S EQUITY AND LIABILITIES		$	34,397,330			$	27,370,556

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED STATEMENTS OF LOSS (UNAUDITED)

 

		Nine Months Ended September 30,
		2008				2007
NET REVENUES
Net gas transportation revenues		$	340,560			$	406,655
Net affiliated revenues			1,770,752				1,834,737
Total net revenues			2,111,312				2,241,392
OPERATING EXPENSES:
Operations and maintenance			720,454				728,462
Operations and maintenance — affiliated			538,431				499,642
Depreciation and amortization			705,454				656,507
Accretion Expense			5,562				5,742
Taxes other than income			241,828				213,946
Total operating expenses			2,211,729				2,104,299
OPERATING (LOSS) INCOME			(100,417	)			137,093
OTHER INCOME (DEDUCTIONS):
Interest income and other, net			14,461				—
Interest expense — affiliated			(197,077	)			(453,916	)
Total other income (deductions)			(182,616	)			(453,916	)
LOSS BEFORE TAX			(283,033	)			(316,823	)
INCOME TAX			(117,402	)			(24,236	)
NET LOSS		$	(165,631	)		($	292,587	)

 

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

		For the Nine Months Ended September 30, 2008				For the Nine Months Ended September 30, 2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		($	165,631	)		($	292,587	)
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization			705,454				656,508
Deferred income taxes and investment tax credits			62,226				126,344
Accretion expense			5,562				5,742
Changes in assets and liabilities:
Accounts receivable			247,664				2,002,907
Accounts payable and accrued expenses			231,612				(1,490,140	)
Regulatory assets/liabilities			23,939				(39,130	)
Pension and other postretirement benefits			(346	)			(252,606	)
Taxes receivable			(153,547	)			3,949,602
Other — net			3,860				(7,102	)
Net cash provided by operating activities			960,793				4,659,538
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(345,499	)			(3,976,894	)
Net cash used in investing activities			(345,499	)			(3,976,894	)

 

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) — (Continued)

 

		For the Nine Months Ended September 30, 2008				For the Nine Months Ended September 30, 2007
CASH FLOWS FROM FINANCING ACTIVITIES:
Changes in Affiliated Borrowings (Short-term debt)			(554,649	)			(675,230	)
Net Cash used in financing activities			(554,649	)			(675,230	)
NET INCREASE IN CASH AND CASH EQUIVALENTS			60,645				7,414
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			65,959				26,517
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	126,604			$	33,931
SUPPLEMENTAL DISCLOSURE INFORMATION:
Cash paid during year for interest		$	212,633			$	443,263
Income taxes (refunded)		($	46,292	)		($	3,232,550	)
Capital expenditures included in accounts payable		$	106,496			$	89,636

 

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 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 State”) 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 State audited financial statements for the fiscal year ended December 31, 2007. Income (loss) 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 State 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 Financial Accounting Standards Board (“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 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 State’s January 1, 2008 balance of accumulated deficit 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. Granite State has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities such as intangible assets.

In October 2008, the FASB issued FSP 157-d, “Determining the Fair Value of a Financial Asset in a Market that is Not Active” which clarifies the application of SFAS 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. The FSP was effective upon issuance, including prior periods for which financial statements have not been issued.

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

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

accumulated deficit 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 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. 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, an increase to “Accumulated Deficit” of $18,573, a decrease to “Accounts and Notes Receivable” of $7,061, an increase to “Receivable from Affiliated Companies” of $99,072, and an increase to “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. 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 State adopted the provisions of FIN 48. There was no impact to the opening balance of accumulated deficit as a result of the adoption of FIN 48.

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

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.

Note 3 Asset Retirement Obligations

Granite State 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 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 State 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 State 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 $133,658 at September 30, 2008 and $126,151 at September 30, 2007. For the first three quarters 2008 and 2007 Granite State recognized accretion expense of $5,562 and $5,742 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:

 

		Nine Months Ended September 30, 2008				Nine Months Ended September 30, 2007
Book income (loss) before income taxes		$	(283,033	)		$	(316,823	)
Tax expense (benefit) at statutory Federal income tax rate			(99,062	)			(110,888	)
Increases (reductions) in taxes resulting from:
State income taxes, net of Federal income tax benefit			(14,417	)			(58,147	)
Deferred investment tax credit			(990	)			(990	)
Tax on contingent interest			—				114,007
Prior year taxes			—				13,912
Amortization of regulatory asset — FAS 109			—				16,492
Other			(2,933	)			1,378
Income tax expense (benefit)		$	(117,402	)		$	(24,236	)

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

There was no impact to the opening balance of accumulated deficit as a result of the adoption of FIN 48 and there are no uncertain tax positions as of September 30, 2008 and 2007. $114,007 of contingent expense, net of tax, for the nine months ended September 30, 2007 represents the reversal of interest receivable for the impact of settlements reached with the Internal Revenue Service in 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 State. The expected cost of such benefits is accrued during the employees’ years of service. Granite State’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 State uses December 31 as its measurement date for its pension and postretirement benefit plans, in accordance with SFAS No. 158.

Pension expense for Granite State, as allocated by NiSource was $4,388 and $12,923 for the first three quarters 2008 and 2007, respectively. Postretirement benefits expense for Granite State was $24,968 and $35,805 for the first three quarters 2008 and 2007, respectively. These allocations were based on expenses, net of assets returns, as actuarially determined for employees associated with Granite State. Granite State made cash contributions to the pension plan totaling zero and $176,627 for the first three quarters 2008 and 2007, respectively. Cash contributions to the post retirement plan were zero and $117,326 for the first three quarters 2008 and 2007, respectively.

Note 6 Short-Term Borrowings

Granite State satisfies its liquidity requirements primarily through internally generated funds and through intercompany borrowings from the NiSource Money Pool. As of September 30, 2008, Granite State had short-term NiSource Money Pool borrowings of $7,313,057 at an interest rate of 3.22 percent. As of September 30, 2007, Granite State had $7,794,881 of NiSource Money Pool borrowings at an interest rate of 5.89 percent.

Note 7 Affiliated Company Transactions

Granite State receives executive, financial, and administrative and general services from an affiliate, NiSource Corporate Services. The costs of these services are charged to Granite State based on payroll costs and expenses incurred by NiSource Corporate Services employees for the benefit of Granite State. These costs which totaled $339,702 and $239,045 for the first three quarters 2008 and 2007, respectively, consist primarily of employee compensation and benefits and are recorded within, “Operation and maintenance —affiliated” on the Statements of Loss. Granite State also incurred expenses from an affiliate, Columbia Gas Transmission Corporation, for various routine administrative activities totaling $171,947 and $233,815 during the first three quarters 2008 and 2007, respectively. Granite State incurred office rental expense of $26,782 from affiliate, Northern Utilities, Inc. (“Northern Utilities”), for the first three quarters 2008 and 2007.

Granite State recorded gas transportation revenues from affiliates of $1,770,752 and $1,834,737 for the first three quarters 2008 and 2007, respectively.

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

The September 30, 2008 and 2007 accounts receivable — affiliated balance includes $586,938 and $458,689 respectively, due from affiliated companies.

The September 30, 2008 and 2007 accounts payable — affiliated balance reflects $763,574 and $459,318, respectively, due to affiliated companies, separate from the NiSource Money Pool.

The September 30, 2008 and 2007 exchange gas payable — affiliated balance reflects $7,596,445 and zero, respectively, due to affiliated companies.

The September 30, 2008 and 2007 Taxes Receivable from affiliated companies balance includes $228,289 and $964,885, respectively, of accrued federal and state income taxes that are payable 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 State was part of the 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 State’s rates. Granite State’s Balance Sheet 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 SFAS No. 144.

Amortization expense for Granite State in the first three quarters 2008 and 2007 was approximately $196,643. The estimated amortization expense for 2008 through 2012 is approximately $262,191 annually. The balance of Granite State’s intangible assets, net of amortization, as of September 30, 2008 was $7,931,263 and was $8,193,454 as of September 30, 2007.

Note 9 Regulatory Matters

Sale of Granite State

On February 15, 2008, NiSource reached a definitive agreement under which Unitil Corporation will acquire 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 Corporation 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 87-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.

In the first quarter of 2008, NiSource recorded an after tax loss of $14,938,299 related to the pending sale of Granite State.

Exchange gas receivable — Spectra Energy

New Hampshire Public Utilities Commission Docket No. DG 07-102 Northern Utilities, Inc 2007/2008 Winter Cost of Gas. On October 31, 2007, the State of New Hampshire’s Public Utilities Commission (the “NHPUC”) issued Order No. 24,798 concerning the 2007/2008 winter cost of gas proceeding for Northern Utilities’ New Hampshire division. In that order, the NHPUC noted that lost and unaccounted for gas

 

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GRANITE STATE GAS TRANSMISSION, INC.

CONDENSED NOTES TO FINANCIAL STATEMENTS (UNAUDITED) — (Continued)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007

 

(“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 ended 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 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 cause appears 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 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 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 758,702 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. This overcharge in turn was passed on to Northern Utilities’ customers through the normal operation of the gas cost recovery mechanism.

In September 2008, Northern Utilities received information that Spectra, PNGTS and Granite State had agreed to resolve the matter by flowing the 758,702 Dth back through the imbalance provisions of the respective tariffs in force between the parties (“in-kind reimbursement”). Upon receiving this information, Northern Utilities filed with the NHPUC and the Maine Public Utilities Commission (the “MPUC”) for approval of this method of reimbursement for the metering error. In October 2008, Northern Utilities received permission from both the NHPUC and MPUC for the rate treatment of in-kind reimbursement through the Northern Utilities’ cost of gas adjustment and approval of the commencement of the flow-back of natural gas starting November 1, 2008. As of September 30, 2008, Northern Utilities has recorded approximately $7.6 million reflecting the anticipated liability of the future refund amount based on current market prices with an offsetting receivable from Granite State.

 

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GRANITE STATE GAS TRANSMISSION, INC.

 

 

FINANCIAL STATEMENTS (RESTATED) 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 overfunded 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.

As explained in Note 11 to the financial statements, the accompanying financial statements have been restated.

/s/ Deloitte & Touche LLP

May 27, 2008 (September 12, 2008 as to the effects of the restatement discussed in Note 11)

 

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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

AS OF DECEMBER 31, 2007 AND 2006

(CONTINUED)

 

		2007				2006
CAPITALIZATION AND LIABILITIES
COMMON STOCKHOLDERS’ EQUITY
Common Stock—29,900 shares, issued and outstanding		$	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 (as restated, see Note 11)				2006 (as restated, see Note 11)				2005 (as restated, see Note 11)
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			(1,729,884	)			39,793				506,535
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			4,732,805				1,193,872				2,264,349
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures — utility plant			(4,090,957	)			(1,940,082	)			(3,391,109	)
Net cash used in investing activities			(4,090,057	)			(1,940,082	)			(3,391,109	)
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
Capital expenditures included in payables to affiliated companies		$	59,995			$	2,941,714			$	1,207,913

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 87 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.

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.

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. Granite State has elected to defer the adoption of the nonrecurring fair value measurement disclosures of non-financial assets and liabilities such as intangible assets.

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

 

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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 chose 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.

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:

 

		Year Ended December 31,
		2007				2006				2005
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:

 

		Year Ended December 31,
		2007				2006				2005
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 87-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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Note 11 Restatement

Subsequent to the issuance of Granite’s 2007 financial statements, Granite’s management determined that certain capital expenditures included in payables to affiliated companies had not been properly identified and accounted for in the calculation of cash paid for capital expenditures in the statements of cash flows. As a result, the statements of cash flows for the years ended December 31, 2007, 2006 and 2005 have been restated. This restatement resulted in adjustments of equal and opposite amounts, to net cash provided by operating activities and net cash used in investing activities for each year presented. This restatement did not impact Granite’s previously reported balance sheets, statements of (loss) income, statements of stockholder’s equity and comprehensive income (loss). Granite also did not disclose capital expenditures included in payables to affiliated companies in the supplemental disclosures section of the statement of cash flows. These amounts are now included in the supplemental disclosures on the face of the statement of cash flows for all periods presented.

The following table sets forth the effects of the restatement on certain line items within Granite’s previously reported statements of cash flows:

 

		Year Ended December 31, 2007
		As previously reported				Adjustments				As restated
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in assets and liabilities:
Accounts payable and accrued expenses		$	(4,256,253	)		$	2,526,369			$	(1,729,884	)
Net cash provided by operating activities			2,206,436				2,526,369				4,732,805
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures—utility plant			(1,564,588	)			(2,526,369	)			(4,090,957	)
Net cash used in investing activities			(1,564,588	)			(2,526,369	)			(4,090,957	)
		Year Ended December 31, 2006
		As previously reported				Adjustments				As restated
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in assets and liabilities:
Accounts payable and accrued expenses		$	1,773,594			$	(1,733,801	)		$	39,793
Net cash provided by operating activities			2,927,673				(1,733,801	)			1,193,872
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures—utility plant			(3,673,883	)			1,733,801				(1,940,082	)
Net cash used in investing activities			(3,673,883	)			1,733,801				(1,940,082	)
		Year Ended December 31, 2005
		As previously reported				Adjustments				As restated
CASH FLOWS FROM OPERATING ACTIVITIES
Changes in assets and liabilities:
Accounts payable and accrued expenses		$	1,586,961			$	(1,080,426	)		$	506,535
Net cash provided by operating activities			3,344,775				(1,080,426	)			2,264,349
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures—utility plant			(4,471,535	)			1,080,426				(3,391,109	)
Net cash used in investing activities			(4,471,535	)			1,080,426				(3,391,109	)

 

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PROSPECTUS

 

4,000,000 Shares

 

 

Common Stock

 

 

By this prospectus, Unitil Corporation may offer from time to time, in one or more offerings, up to 4,000,000 shares of its common stock.

We will provide the specific terms of any offering in supplements to this prospectus. We can only use this prospectus to offer and sell our common stock by also including a prospectus supplement relating to that offer and sale.

We may sell the common stock directly to you, through agents that we select or through underwriters and dealers that we select. If we use agents, underwriters or dealers to sell the securities, we will name them and describe their compensation in a prospectus supplement.

Our common stock is listed on the New York Stock Exchange under the symbol “UTL.”

Investing in our common stock involves risks. Please see the section entitled Risk Factors beginning on page 2 of this prospectus.

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 date of this prospectus is December 10, 2008.

 

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ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission (the “SEC”) using a “shelf” registration process. Under this shelf registration process, we may sell the common stock described in this prospectus from time to time in one or more offerings. This prospectus provides you with a general description of the common stock that we may offer. We may also add, update or change information contained in this prospectus through one or more supplements to this prospectus. Any statement that we make in this prospectus will be modified or superseded by any inconsistent statement made by us in a prospectus supplement. The rules of the SEC allow us to incorporate by reference information into this prospectus. This information incorporated by reference is considered to be a part of this prospectus, and information that we file later with the SEC will automatically update and supersede this information. You should read both this prospectus and any prospectus supplement together with additional information described in the section entitled Where You Can Find More Information.

No person has been authorized to give any information or to make any representations other than those contained or incorporated by reference in this prospectus and, if given or made, such information or representation must not be relied upon as having been authorized by us or any underwriter, agent, or dealer. Neither the delivery of this prospectus nor any sale made hereunder shall under any circumstances create any implication that there has been no change in our affairs since the date hereof or that the information contained or incorporated by reference herein is correct as of any time subsequent to the date of such information. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any shares of common stock by anyone in any jurisdiction in which such offer or solicitation is not authorized or in which the person making such offer or solicitation is not qualified to do so or to any person to whom it is unlawful to make such offer or solicitation.

The information in this prospectus is accurate as of its date. Therefore, before you invest in our common stock, you should carefully read this prospectus and any prospectus supplement relating to the common stock offered to you together with the additional information described in the section entitled Where You Can Find More Information.

In this prospectus, the “company,” “Unitil,” “we,” “us,” and “our” refer to Unitil Corporation and its subsidiaries, excluding Northern Utilities, Inc. and Granite State Gas Transmission, Inc., unless the context otherwise requires.

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 listed on the New York Stock Exchange 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

 

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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 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:

 

(i)

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

 

(ii)

our Quarterly Report on Form 10-Q for the quarters ended March 31, 2008, June 30, 2008, and September 30, 2008;

 

(iii)

our Current Reports on Form 8-K filed with the SEC on February 20, 2008, March 21, 2008, April 8, 2008, June 20, 2008, July 30, 2008 (other than the press release furnished thereunder), August 22, 2008 (other than the press release furnished thereunder), August 27, 2008 (other than the press release furnished thereunder), September 11, 2008, October 17, 2008, December 3, 2008, and December 4, 2008; and

 

(iv)

the description of our common stock, no par value, contained in the registration statement on Form 8-A/A filed with the SEC on August 13, 2008.

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

RISK FACTORS

Investing in our common stock involve risks. You should carefully consider the risks described in our filings with the SEC referred to in the section entitled Where You Can Find More Information and in the section entitled Cautionary Statement about Forward-Looking Statements, as well as those included in any prospectus supplement hereto. For example, our Annual Report on Form 10-K for the year ended December 31, 2007 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 contain a discussion of significant risks, which could be relevant to your investment in our common stock. Subsequent filings with the SEC may contain amended and updated discussions of significant risks.

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, as amended, 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,”

 

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“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 referred to in the section entitled Risk Factors and the following:

 

Ÿ

our ability to integrate the business, operations, and personnel of Northern Utilities (as defined below) and Granite State (as defined below) and achieve the estimated potential synergy savings attributable to the Acquisitions (as defined below);

 

Ÿ

our, Northern Utilities’, and Granite State’s ability to retain existing customers and gain new customers;

 

Ÿ

variations in weather;

 

Ÿ

changes in the regulatory environment;

 

Ÿ

customers’ preferences on energy sources;

 

Ÿ

interest rate fluctuation and credit market concerns;

 

Ÿ

general economic conditions including recent distress in the financial markets that has had an adverse impact on the availability of credit and liquidity resources generally and could jeopardize certain of our counterparty obligations, including those of our insurers and financial institutions;

 

Ÿ

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

 

Ÿ

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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OUR COMPANY

The following is a description of our company as it existed prior to the consummation of our purchase of (i) all of the outstanding capital stock of Northern Utilities, Inc. (“Northern Utilities”) and (ii) all of the outstanding capital stock of Granite State Gas Transmission, Inc. (“Granite State”), which we closed on December 1, 2008. As such, the description generally excludes information about Northern Utilities and Granite State. For a description of Northern Utilities and Granite State, please see the section entitled (i) Our Company—Description of Northern Utilities and Granite State.

We are a public utility holding company headquartered in Hampton, New Hampshire. We are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (the “FERC”) under the Energy Policy Act of 2005.

Our principal business is the retail distribution of electricity in the southeastern seacoast and state capital regions 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, Unitil Energy Systems, Inc. (“UES”), which operates in New Hampshire, and Fitchburg Gas and Electric Light Company (“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 territory. Our retail distribution utilities are local “pipes and wires” utility distribution companies with a combined investment in Net Utility Plant of $256.0 million at September 30, 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 and $200.4 million for the nine months ended September 30, 2008, 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 the cost of purchased electricity and natural gas. Earnings applicable to common shareholders for 2007 were $8.6 million and for the nine months ended September 30, 2008 were $6.4 million. Substantially all of our earnings are derived from the return on investment in our retail distribution utilities.

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, on December 1, 2008, we purchased (i) all of the outstanding capital stock of Northern Utilities, Inc. (“Northern Utilities”), a retail natural gas distribution utility serving customers in Maine and New Hampshire, from Bay State Gas Company (“Bay State”) and (ii) all of the outstanding capital stock of Granite State Gas Transmission, Inc. (“Granite State”), an interstate gas pipeline company primarily serving the needs of Northern Utilities, from NiSource Inc. (“NiSource”) pursuant to the Stock Purchase Agreement dated as of February 15, 2008 by and among NiSource, Bay State and us (the “Stock Purchase Agreement”). Bay State is a wholly owned subsidiary of NiSource. We refer to these transactions as the “Acquisitions.”

Descriptions of Northern Utilities and Granite State

Northern Utilities

Northern Utilities is a retail 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.

 

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Northern Utilities was incorporated under the laws of New Hampshire in 1979. It is a wholly owned subsidiary of Unitil Corporation. As of September 30, 2008, it had 76 full-time employees. Northern Utilities’ customers include residences, businesses and organizations.

Northern Utilities had an investment in Net Utility Plant of $163.5 million at December 31, 2007 and $169.4 million at September 30, 2008, and net revenues of $44.2 million for 2007 and $31.0 million for the nine months ended September 30, 2008. Northern Utilities derives its revenues and earnings from its regulated utility operations. Northern Utilities recovers the cost of purchased natural gas in rates on a fully reconciling basis and, therefore, Northern Utilities’ earnings are not affected by changes in the cost of purchased gas. Prior to the closing of the Acquisitions, Northern Utilities received centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $8.6 million in 2007 and $6.8 million for the nine months ended September 30, 2008.

Granite State

Granite State is a natural gas transmission pipeline, regulated by the FERC, operating 87 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 pipeline supplies.

Granite State was incorporated under the laws of New Hampshire in 1955. It is a wholly owned subsidiary of Unitil Corporation. As of September 30, 2008, it had five full-time employees.

Granite State had an investment in Net Utility Plant of $16.5 million at December 31, 2007 and $16.1 million at September 30, 2008, and net operating revenue of $3.4 million for 2007 and $2.1 million for the nine months ended September 30, 2008. Granite State derives its revenues principally from the transportation services provided to Northern Utilities and, to a lesser extent, third-party marketers. Prior to the closing of the Acquisitions, Granite State received centralized administrative, management, and support services from NiSource and its affiliates, the cost of which amounted to $0.6 million in 2007 and $0.5 million for the nine months ended September 30, 2008.

 

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USE OF PROCEEDS

Unless we specify otherwise in the applicable prospectus supplement accompanying this prospectus, we intend to use the net proceeds that we receive from the sale of the common stock covered by this prospectus for general corporate purposes, including repayment of debt, acquisitions and capital expenditures and additions to working capital.

The actual application of proceeds that we receive from the sale of any particular offering of common stock using this prospectus will be described in the applicable prospectus supplement relating to such offering.

 

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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 filed, or 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.

Authorized and Outstanding Shares

On September 10, 2008, our shareholders approved an amendment to our Articles of Incorporation to increase the authorized number of shares of our common stock from 8,000,000 shares to 16,000,000 shares in the aggregate. On September 23, 2008, we filed the amendment to our Articles of Incorporation with the Department of State of New Hampshire.

Our authorized capital stock consists of 16,000,000 shares of common stock, no par value. As of December 10, 2008, 5,788,440 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.

Approximately 6,211,560 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 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 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.

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.

 

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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 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, her or its 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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PLAN OF DISTRIBUTION

We may sell our common stock to one or more purchasers, through agents, to or through underwriters or dealers, or through a combination of any such methods of sale. The distribution of our common stock may be effected from time to time in one or more transactions at fixed prices, which may be changed, at market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. The prospectus supplement will set forth the terms of the offering, including the names of any underwriters, dealers or agents, the purchase price of our common stock and the proceeds to us from such sale, any underwriting discounts and commissions or agency fees and other items constituting underwriters’ or agents’ compensation and any discounts or concessions allowed or paid to dealers or any securities exchange on which such securities may be listed. Any discounts or concessions allowed or paid to dealers may be changed from time to time.

Any discounts, concessions or commissions received by underwriters or agents and any profits on the resale of our common stock by them may be deemed to be underwriting discounts and commissions under the Securities Act of 1933. Unless otherwise set forth in the applicable prospectus supplement, the obligations of underwriters to purchase our offered common stock will be subject to certain conditions precedent, and such underwriters will be obligated to purchase all such common stock, if any are purchased. Unless otherwise indicated in the applicable prospectus supplement, any agent will be acting on a best efforts basis for the period of its appointment.

We may authorize underwriters, dealers or other persons acting as agents for us to solicit offers by certain institutions to purchase our common stock from us, pursuant to contracts providing for payment and delivery on a future date. Institutions with which such contracts may be made include commercial and savings banks, insurance companies, pension funds, investment companies, educational and charitable institutions and others, but in all cases such institutions must be approved by us. The obligations of any purchaser under any such contract will be subject to the conditions that the purchase of the offered common stock shall not at the time of delivery be prohibited under the laws of the jurisdiction to which such purchaser is subject. The underwriters and such other agents will not have any responsibility in respect of the validity or performance of such contracts.

In connection with the offering of our common stock, we may grant to the underwriters an option to purchase additional securities to cover over-allotments at the public offering price, with an additional underwriting commission, as may be set forth in the accompanying prospectus supplement. If we grant any over-allotment option, the terms of such over-allotment option will be set forth in the prospectus supplement for such common stock.

We may indemnify agents, underwriters and dealers against certain liabilities, including liabilities under the Securities Act of 1933. Our agents, underwriters and dealers, or their affiliates, may be customers of, engage in transactions with or perform services for us, in the ordinary course of business.

 

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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 Gary Epler, our Chief Regulatory Counsel. As of December 1, 2008, Mr. Epler beneficially owned approximately 2,283 shares of our common stock.

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 and elsewhere in this registration statement (which report expresses an unqualified opinion on the financial statements and includes an explanatory paragraph referring to the adoption of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”). 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 and elsewhere in this registration statement (which report expresses an unqualified opinion on the financial statements and includes explanatory paragraphs referring to the adoption of FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” and the restatement of the financial statements discussed in Note 11). 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.

 

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Table of Contents

 

 

Through and including January 4, 2009 (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.

2,000,000 Shares

Common Stock

 

 

PRICE $20.00 PER SHARE

 

 

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

 

 

PROSPECTUS SUPPLEMENT

 

December 10, 2008