Unitil (UTL) 10-Q 2001 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For Quarter Ended March 31, 2001

Commission File Number1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire	02-0381573
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

6 Liberty Lane West, Hampton, New Hampshire	03842-1720
(Address of principal executive office)	(Zip Code)

Registrant's telephone number, including area code: (603) 772-0775

Former name, former address and former fiscal year, if changed since last report:  NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  X      No      

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Class	Outstanding at May 1, 2001
Common Stock, No par value	4,740,574 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended March 31, 2001

Table of Contents

Part I. Financial Information

Item 1.  Financial Statements

Part II. Other Information

PART 1. FINANCIAL INFORMATION

Item 1.  Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF EARNINGS
(000's except common shares and per share data)
(UNAUDITED)

	Three Months Ended March 31,
	2001	2000
Operating Revenues:
Electric	$53,313	$38,958
Gas	11,082	7,320
Other	95	39
Total Operating Revenues	64,490	46,317
Operating Expenses:
Fuel and Purchased Power	40,171	25,853
Gas Purchased for Resale	7,642	4,052
Operation and Maintenance	7,190	6,169
Depreciation and Amortization	3,366	3,040
Provisions for Taxes:
Local Property and Other	1,387	1,377
Federal and State Income	1,003	1,368
Total Operating Expenses	60,759	41,859
Operating Income	3,731	4,458
Non-Operating Expense, Net	46	49
Income Before Interest Expense	3,685	4,409
Interest Expense, Net	1,679	1,745
Net Income	2,006	2,664
Less Dividends on Preferred Stock	67	67
Net Income Applicable to Common Stock	$1,939	$2,597
Average Common Shares Outstanding	4,737,713	4,714,540
Basic Earnings Per Share	$0.41	$0.55
Diluted Earnings Per Share	$0.41	$0.55
Dividends Declared per Share
of Common Stock (Note 2)	$0.69	$0.69

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS(000's)

	(UNAUDITED)		(AUDITED)
	March 31,		December 31,
	2001	2000	2000
ASSETS:
Utility Plant:
Electric	$164,988	$165,194	$173,883
Gas	37,908	34,628	36,996
Common	21,491	21,654	21,602
Construction Work in Progress

1,111

 

2,046

 

1,844

    Utility Plant

225,498

 

223,522

 

234,325

    Less:   Accumulated Depreciation

68,911

 

68,107

 

71,036

      Net Utility Plant

156,587

 

155,415

 

163,289

      

  Other Property and Investments

8,902

 

5,276

 

8,740

            

Current Assets:

     

  Cash

1,390

 

2,730

 

3,060

  Accounts Receivable - Less Allowance

     

    for Doubtful Accounts of $595,

     

    $593 and $596

25,542

 

18,421

 

20,057

  Refundable Taxes

1,564

 

(962)

 

1,980

  Materials and Supplies

2,026

 

2,074

 

2,854

  Prepayments

1,528

 

1,140

 

1,317

  Accrued Revenue

6,714

 

(397)

 

8,602

      Total Current Assets

38,764

 

23,006

 

37,870

                  

Noncurrent Assets:

     

  Regulatory Assets

143,810

 

141,938

 

137,470

  Prepaid Pension Costs

10,169

 

9,349

 

9,996

  Debt Issuance Costs

1,468

 

1,336

 

1,479

  Other Noncurrent Assets

23,119

 

24,629

 

24,123

      Total Noncurrent Assets

178,566

 

177,252

 

173,068

      

TOTAL

$382,819

 

$360,949

 

$382,967

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS (Cont.)(000's)

	(UNAUDITED)		(AUDITED)
	March 31,		December 31,
	2001	2000	2000
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common Stock Equity	$78,678	$78,223	$79,935
Preferred Stock, Non-Redeemable, Non-Cumulative	225	225	225
Preferred Stock, Redeemable, Cumulative	3,465	3,532	3,465
Long-Term Debt, Less Current Portion

93,640

 

81,915

 

81,695

      Total Capitalization

176,008

 

163,895

 

165,320

      

Current Liabilities:

     

  Long-Term Debt, Current Portion

3,211

 

3,195

 

3,207

  Capitalized Leases, Current Portion

928

 

874

 

935

  Accounts Payable

21,587

 

14,222

 

18,539

  Short-Term Debt

21,260

 

12,225

 

32,500

  Dividends Declared and Payable

1,776

 

1,835

 

209

  Refundable Customer Deposits

1,283

 

1,307

 

1,252

  Interest Payable

1,333

 

1,392

 

1,150

  Other Current Liabilities

7,174

 

3,577

 

6,377

      Total Current Liabilities

58,552

 

38,627

 

64,169

      

Deferred Income Taxes

44,133

 

42,352

 

45,859

      

Noncurrent Liabilities:

     

  Power Supply Contract Obligations

95,201

 

103,973

 

97,342

  Capitalized Lease, Less Current Portion

3,030

 

3,654

 

3,259

  Other Noncurrent Liabilities

5,895

 

8,448

 

7,018

      Total Noncurrent Liabilities

104,126

 

116,075

 

107,619

      

TOTAL

$382,819

 

$360,949

 

$382,967

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS(000's)
(UNAUDITED)

	Three Months Ended March 31,
	2001	2000
Cash Flows from Operating Activities:
Net Income	$2, 006	$2,664
Adjustments to Reconcile Net Income to
Cash Provided by Operating Activities:
Depreciation and Amortization	3,366	3,040
Deferred Taxes Provision	1,035	(99)
Amortization of Investment Tax Credit	(38)	(64)
Amortization of Debt Issuance Costs	15	15
Changes in Working Capital:
Accounts Receivable	(5,485)	(1,791)
Materials and Supplies	828	429
Prepayments	(384)	(657)
Accrued Revenue	1,888	2,659
Accounts Payable	3,048	(2,293)
Refundable Customer Deposits	31	5
Taxes and Interest Payable	1,004	2,528
Other, Net	(1,672)	(919)
Net Cash Provided by Operating Activities	5,642	5,517
Cash Flows from Investing Activities:
Acquisition of Property, Plant and Equipment	(6,336)	(4,308)
Proceeds from Sale of Property	342	---
Other Property and Investments	(162)	(226)
Cash (Used) in Investing Activities	(6,156)	(4,534)
Cash Flows from Financing Activities:
Net Increase in Short-Term Debt	3,760	1,725
Repayment of Long-Term Debt	(3,051)	(1,047)
Dividends Paid	(1,767)	(1,704)
Issuance of Common Stock	138	160
Repayment of Capital Lease Obligations	(236)	(234)
Cash (Used) in Financing Activities	(1,156)	(1,100)
Net (Decrease) in Cash	(1,670)	(117)
Cash at Beginning of Year	3,060	2,847
Cash at March 31	$1,390	$2,730
Supplemental Cash Flow Information:
Interest Paid	$2,150	$1,853
The Company recorded the impact of the sale of Millstone 3, related to its Electric Utility Restructuring Plan as required by the MDTE, on March 31, 2001. The non-cash changes related to this sale are as follows:
(Decrease) in Electric Utility Plant-net of accum. depreciation	($7,684)	---
Decrease in related Deferred Taxes	2,686	---
Other Balance Sheet changes	191	---
Increase in Regulatory Asset	$4,807	---

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

UNITIL CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1.

Reclassifications:

In the opinion of the Company, the accompanying unaudited consolidated financial statements contain all adjustments (consisting only of normal recurring accruals) necessary to present fairly the consolidated financial position as of March 31, 2001 and 2000; and results of operations for the three months ended March 31, 2001 and 2000; and consolidated statements of cash flows for the three months ended March 31, 2001 and 2000.

Reclassifications are made periodically to amounts previously reported to conform to current year presentation.

The results of operations for the three months ended March 31, 2001 and 2000 are not necessarily indicative of the results to be expected for the full year.

Note 2.

Dividends Declared Per Share:

Two regular quarterly common stock dividends were declared during the first quarter of 2001 and 2000.

Common Stock Dividend:

On March 15, 2001, the Company's Board of Directors declared its regular quarterly dividend on the Company's Common Stock of $0.345 per share which is payable on May 15, 2001 to shareholders of record as of May 1, 2001.

On January 16, 2001, the Company's Board of Directors declared its regular quarterly dividend on the Company's Common Stock of $0.345 per share which was payable on February 15, 2001 to shareholders of record as of February 1, 2001.

Note 3.

Common Stock:

During the first quarter of 2001, the Company sold 5,657 shares of Common Stock, at an average price of $25.49 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan. Net proceeds of $137,744 were used to reduce short-term borrowings.

Note 4.

Preferred Stock:

Details on preferred stock at March 31, 2001, March 31, 2000 and December 31, 2000 are shown below (000's):

	March 31,		December 31,
	2001	2000	2000
Preferred Stock:
Non-Redeemable, Non-Cumulative,
6%, $100 Par Value	$225	$225	$225
Redeemable, Cumulative,
$100 Par Value:
8.70% Series	215	215	215
5% Dividend Series	91	91	91
6% Dividend Series	168	168	168
8.75% Dividend Series	333	333	333
8.25% Dividend Series	385	385	385
5.125% Dividend Series	973	987	973
8% Dividend Series	1,300	1,353

1,300

      Total Redeemable Preferred Stock

3,465

 

3,532

 

3,465

        Total Preferred Stock

$3,690

 

$3,757

 

$3,690

Note 5.

Long-term Debt:

For presentation purposes, the long-term debt on the Balance Sheet reflects the issuance of $7.5 million of Series K First Mortgage Bonds for Concord Electric Company and $7.5 million of Series M First Mortgage Bonds for Exeter and Hampton Electric Company, which were effective prior to March 31, 2001, with a corresponding decrease to short-term debt. These bonds were approved by the New Hampshire Public Utilities Commission (NHPUC) on March 23, 2001 and subsequently issued.

Details on long-term debt at March 31, 2001, March 31, 2000 and December 31, 2000 are shown below (000's):

	March 31,		December 31,
	2001	2000	2000
Concord Electric Company:
First Mortgage Bonds:
Series I, 8.49%, due October 14, 2024	6,000	6,000	6,000
Series J, 6.96%, due September 1, 2028	10,000	10,000	10,000
Series K, 8.00%, due May 1, 2031	7,500	---	---
Exeter & Hampton Electric Company:
First Mortgage Bonds:
Series K, 8.49%, due October 14, 2024	9,000	9,000	9,000
Series L, 6.96%, due September 1, 2028	10,000	10,000	10,000
Series M, 8.00%, due May 1, 2031	7,500	---	---
Fitchburg Gas and Electric Light Company:
Promissory Notes:
8.55% Notes due March 31, 2004	9,000	12,000	12,000
6.75% Notes due November 30, 2023	19,000	19,000	19,000
7.37% Notes due January 15, 2029	12,000	12,000	12,000
Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes due August 1, 2017	6,851	7,110	6,902
Total	96,851	85,110	84,902
Less: Installments due within one year	3,211	3,195	3,207
Total Long-term Debt	$93,640	$81,915	$81,695

Note 6. 

Segment Information:

The following table provides significant segment financial data for the quarters-ended March 31, 2001 and 2000:

Quarter Ended March 31, 2001(000's)	Electric	Gas	Other	Usource	Eliminations	Total
Revenues
External Customers	$53,313	$11,082	$8	$87		$64,490
Intersegment	----	----	5,024	----	(5,024)	----
Depreciation and Amortization	2,412	401	345	208		3,366
Interest, net	1,067	381	195	36		1,679
Income Taxes	811	437	40	(285)		1,003
Segment Profit (Loss)	1,729	702	51	(543)		1,939
Identifiable Segment Assets	319,646	40,138	39,690	4,207	(20,862)	382,819
Regulatory Assets	143,810	----	----	----		143,810
Capital Expenditures	5,823	292	82	301		6,498
Quarter Ended March 31, 2000(000's)
Revenues
External Customers	$38,858	$7,320	$107	$32		$46,317
Intersegment	----	----	4,761	----	(4,761)	----
Depreciation and Amortization	2,232	377	379	52		3,040
Interest, net	1,229	367	137	12		1,745
Income Taxes	1,106	339	64	(141)		1,368
Segment Profit (Loss)	2,137	652	100	(292)		2,597
Identifiable Segment Assets	300,631	39,258	43,211	1,261	(23,412)	360,949
Regulatory Assets	141,938	----	----	----		141,938
Capital Expenditures	3,339	499	98	598		4,534

Item 2. Management's Discussion and Analysis of Results of Operations and Financial Condition

SAFE HARBOR CAUTIONARY STATEMENT

This report contains forward-looking statements which are subject to the inherent uncertainties in predicting future results and conditions. Certain factors that could cause the actual results to differ materially from those projected in these forward-looking statements include, but are not limited to; variations in weather, changes in the regulatory environment, customers' preferences on energy sources, general economic conditions, increased competition and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company.

RESULTS OF OPERATIONS

Earnings per average common share were $0.41 for the first quarter of 2001, a decrease of $0.14 per share compared to earnings per share of $0.55 for the same three-month period in 2000. For the first quarter of 2001, Utility Operations contributed $0.52 per share to consolidated results, while non-utility operations lost $0.11 per share.

Earnings per share from Utility Operations in the first quarter of 2001 were $0.09 lower than the per-share earnings from this business segment in the same three-month period in 2000. This reduction primarily reflects the loss of a major electrical customer that discontinued operations last year, and increased Operation and Maintenance expenses due to hi gher storm-related maintenance and other operating costs. These factors were partially offset by increased gas margins and decreased Interest Expense, net of Interest Income. Losses from Usource increased $0.05 per share over the same quarter last year, due to costs associated with the operation and development of the business.

Sales (000's)	Three Months Ended
kWh Sales	03/31/01	03/31/00	Change
Residential	167,827	163,836	2.4%
Commercial/Industrial

251,291

255,635

(1.7%)

  Total kWh Sales

419,118

419,471

(0.1%)

    

Firm Therm Sales

    

Residential

5,803

5,526

5.0%

Commercial/Industrial

5,966

5,211

14.5%

  Total Firm Therm Sales

11,769

10,737

9.6%

Segment Information
($000's)

Three Months Ended - 3/31/01

Utility
Operations

Usource

Total

Revenues

$64,403

$87

$64,490

Segment Profit (Loss)

2,482

(543)

1,939

Diluted Earnings per Share

0.52

(0.11)

0.41

    

Three Months Ended - 3/31/00

 

Utility
Operations

Usource

Total

Revenues

$46,285

$32

$46,317

Segment Profit (Loss)

2,889

(292)

2,597

Diluted Earnings per Share

0.61

(0.06)

0.55

During the current three-month period, kilowatt-hour (kWh) sales to Residential customers increased 2.4%, while kWh sales to Commercial and Industrial customers declined 1.7%. This decline in Commercial and Industrial sales is attributable to signs of a slowing economy, coupled with the impact of the bankruptcy of a major customer that occurred in the second quarter of 2000.

Firm Therm gas sales increased 9.6% in the current period, due to more normal average temperatures (approximately 11% colder than the same three-month period a year earlier), and the success of the Company's natural gas sales and marketing programs. Firm Therm gas sales to Residential customers increased 5.0%, and sales to Commercial and Industrial customers increased 14.5% in the current quarter.

Total Operating Revenues increased 39%, or $18.2 million, in the first quarter of 2001 compared to the same three-month period in the prior year, reflecting increased revenues from the recovery of significantly higher electric fuel and purchased power costs and gas purchase costs. These higher revenues do not affect the Company's net income, as they are matched dollar for dollar with the costs incurred by the Company to procure electricity and natural gas for customers.

Fuel and Purchased Power costs and Gas Purchased for Resale costs increased significantly in the quarter, due to spot market increases in the commodity costs. Operation and Maintenance expenses increased in this quarter, largely due to higher storm related maintenance and other operating costs.  Depreciation and Amortization increased due to utility plant additions and the amortization of web-site development software costs. Local Property and Other taxes remained consistent with the previous year. Federal and State Income Taxes decreased due to lower taxable income in this quarter, compared to same quarter last year.

Earnings per share from the Company's non-regulated operations are related to planned operating and development costs of Usource, the Company's Internet-based energy brokering business. For the current quarter, Usource lost $0.11 per share compared to $0.06 per share in the first quarter of 2000. Brokerage activity in the first quarter of 2001 resulted in revenues of $87,000, equal to two-thirds of the total revenues recorded in all of 2000. For the remainder of 2001, Usource expenditures are expected to be significantly reduced and the energy brokering business is projected to experience continued revenue growth. Going forward, the Company expects and improvement in Usource year-to-year results.

The Company continues to hold approximately a 9% equity interest in Enermetrix. This investment is recorded "at cost" by the Company, based on a total investment of $5.4 million. Enermetrix is a service provider and technology enabler for deregulated energy markets and developed The Enermetrix Network, an Internet-based energy procurement bid system that matches buyers and sellers of energy in competitive markets.

On March 31, 2001, the Company completed the sale of its interest in the Millstone 3 Nuclear Generating Station (along with the majority of other owners of the facility) to Dominion Nuclear Connecticut, Inc., a subsidiary of Dominion (NYSE: D). As a result of this sale, the Company's utility subsidiary, Fitchburg Gas and Electric Light Company, completed the divestiture of its 2.5 megawatt interest in Millstone 3 and eliminated all potential future liabilities and contingencies related to this nuclear facility, including environmental and decommissioning liabilities. The sale resulted in net cash proceeds of $342,000. There were various non-cash changes related to this sale, such as reclassification of the undepreciated plant balance of $7,684,000, from Electric Utility Plant to Regulatory Assets. In addition, there was a decrease in Deferred Federal and State Taxes of $2,686,000. The recovery of this regulatory asset balance of $4,807,000 has been approved to be collected in rates over the next nine years by the MDTE. The table below summarizes these non-cash Balance Sheet reclassifications.

Reclassifications related to the sale of Millstone 3(000's)
(Decrease) in Electric Utility Plant-net of accum. depreciation	($7,684)
Decrease in related Deferred Taxes	2,686
Other Balance Sheet changes	191
Increase in Regulatory Asset	$4,807

REGULATORY MATTERS

The Unitil System of Companies is regulated by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), and state regulatory authorities with jurisdiction over the utility industry, including the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (MDTE). In recent years, there has been significant legislative and regulatory activity to introduce greater competition in the supply and sale of electricity and gas, while continuing to regulate the delivery and distribution operations of our utility subsidiaries.

Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. Since March 1, 1998, all electric consumers in Massachusetts served by investor-owned utilities have had the ability to choose their electric energy supplier. FG&E, the Company's Massachusetts utility operating subsidiary, continues to implement its comprehensive electric restructuring plan and divestiture of its entire regulated power supply business, including its nuclear investment.

Since 1997, FG&E has worked in collaboration with the other Massachusetts gas distribution utilities and various other stakeholders to develop and implement the infrastructure to offer gas customers choice of their competitive gas energy supplier and to complete the restructuring of gas service provided by gas utilities. FG&E filed with the MDTE new gas tariffs to implement natural gas unbundling in accordance with Model Terms and Conditions resulting from these collaborative efforts. The MDTE issued an Order approving these tariffs and final regulations effective November 1, 2000.

In New Hampshire, CECo and E&H, our electric utility operating subsidiaries, and Unitil Power Corp., our wholesale power company, continue to prepare for the transition that will move them into this new market structure, pending resolution of certain key restructuring policies and issues. The utility operating companies have also been active participants in the restructuring of the wholesale power market and transmission system in New England. Though retail competition in the sale of electricity has stalled throughout the region, new wholesale markets have been implemented in the New England Power Pool (NEPOOL) under the general supervision of an Independent System Operator (ISO).

Massachusetts Electric Restructuring  - On January 15, 1999, the MDTE approved FG&E's restructuring plan with certain modifications. The Plan provides customers with: a) the ability to choose an energy supplier; b) an option to purchase Standard Offer Service provided by FG&E at regulated rates for up to seven years; and c) a cumulative 15% rate reduction adjusted for inflation. The Order also approved FG&E's power supply divestiture plan for its interest in three generating units and four long-term power supply contracts.

Pursuant to the Plan, on October 30, 1998, FG&E filed a proposed contract with Constellation Power Services Inc. for provision of Standard Offer Service. Constellation began to supply power under that contract on March 1, 1999, and is scheduled to continue through February 28, 2005. The award of this contract was the first successful Standard Offer auction conducted in Massachusetts.

A contract for the sale of FG&E's interest in the New Haven Harbor plant was approved by the MDTE on March 31, 1999, and the sale of the unit closed on April 14, 1999. A contract for the sale of the entire output from FG&E's remaining generating assets and purchased power contracts to Select Energy, Inc. was approved by the MDTE on December 28, 1999, and went into effect February 1, 2000.

On December 22, 1999, FG&E filed with the MDTE new rates for effect January 1, 2000. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved the rates on January 5, 2000, subject to an examination of the Company's filing in which it reconciles its estimated and actual transition costs (the "reconciliation filing").

On February 2, 2000, the MDTE initiated a proceeding to examine FG&E's reconciliation filing and the consistency of the proposed charges and adjustments with the methods approved in FG&E's restructuring plan. The MDTE held four days of hearings in May 2000, and the Company presented testimony in support of its filing. As part of his review of FG&E's filing, the Massachusetts Attorney General has challenged FG&E's recovery of certain transition costs and other cost reconciliation calculations. Management is unable to determine the outcome of the MDTE proceedings. However, if an unfavorable outcome were to occur, there could be an adverse impact on the Company's consolidated financial position.

As a result of restructuring and divestiture of FG&E's generation and purchased power portfolio, FG&E has accelerated the write-off of its electric generation assets and its abandoned investment in Seabrook Station. The MDTE established the return to be earned on the unamortized balance of FG&E's generation plant, reducing FG&E's earnings on those assets. In 2000, Unitil's earnings from this business segment represented approximately 16% of the earnings from utility operations. As this portfolio is amortized over the next 9 years, earnings from this segment of FG&E's utility business will continue to decline and ultimately cease.

On August 2, 2000, FG&E was the first electric company in Massachusetts to file for an increase in its Standard Offer Service rates pursuant to the Fuel Adjustment provision of its Standard Offer Service (SOS) tariff. This adjustment allows an increase in the SOS rate due to increases in the fuel prices of oil and natural gas. Any revenues received as a result of this adjustment are passed on to the Company's wholesale SOS provider. The MDTE suspended the filing for further review. Subsequently, other electric utility companies operating in Massachusetts made similar filings, and the MDTE instituted proceedings in each of those cases. On December 4, 2000, the MDTE issued an order for the utilities authorizing a "fixed" fuel adjustment, calculated based on the most recent 12 months of data. These adjustments took effect on January 1, 2001. FG&E's SOS rate increased from $0.038/kWh to $0.05121/kWh. Unrecovered amounts to date will be recovered, subject to the rate reduction requirements of the Act.

In approving the new SOS rates, the MDTE also directed all electric distribution companies to file a report with the MDTE on their efforts to mitigate transition costs. On January 19, 2001, FG&E filed an extensive report detailing its mitigation activities, including contract restructurings, divestiture of its generating assets, and a variety of initiatives intended to reduce the burden of increasing energy prices on customers. While FG&E has completed the divestiture of its generation assets, the Company continues to seek ways to reduce its transition costs and lower prices for customers.

On December 1, 2000, FG&E filed new electric rates for effect January 1, 2001. The revised rates maintain the required inflation-adjusted 15% rate discount. The MDTE approved final rates on December 29, 2000, subject to reconciliation pursuant to an investigation of actual and estimated transition costs, resulting in an upward inflation adjustment of 3.5% relative to 2000 rates.

New customers, and customers who previously opted to take electric supply service from a competitive provider, may purchase power through FG&E under Default Service. FG&E provides the Default Service through a third party supplier at market-based rates. The Company issued its first Request for Proposals for Default Service in September 2000. FG&E awarded a contract and filed resulting rates, which were approved, effective for the period January through May 2001. The Company issued its second Request for Proposals in March 2001. A contract was awarded and the resulting rates were approved effective for the period June through November 2001.

In June 2000, the MDTE opened an investigation into whether (1) metering, meter maintenance and testing, and customer billing and information services (MBIS) should be unbundled; and (2) the service territories of distribution companies should remain exclusive. On December 29, 2000, the MDTE issued its report recommending that the Legislature not take action to allow for the competitive provision of MBIS in the electric industry. The MDTE also concluded that exclusive service territories should remain intact. Instead, the MDTE would open a proceeding to establish terms and conditions by which distribution companies will install advanced metering equipment, stating that efforts along these lines will likely yield substantial benefits to electricity consumers sooner than would competition. On February 8, 2001 the MDTE opened a proceeding to investigate this matter. During March 2001, the electric utilities, including FG&E, filed model tariffs for advanced metering for consideration by the MDTE. These filings are now pending.

Massachusetts Gas Restructuring  - In mid-1997, the MDTE directed all Massachusetts natural gas Local Distribution Companies (LDCs) to form a collaborative with other stakeholders to develop common principles and appropriate regulations for the unbundling of gas service, and directed FG&E and four other LDCs to file unbundled gas rates for its review. FG&E's unbundled gas rates were filed with, and approved by, the MDTE and implemented in November 1998.

On February 1, 1999, the MDTE issued an order in which it determined that the LDCs would continue to have an obligation to provide gas supply and delivery services for another five years, with a review after three years. This order also set forth the MDTE's decision requiring mandatory assignment by LDCs of their pipeline capacity contracts to competitive marketers. In March 1999, the LDCs and other stakeholders filed a settlement with the MDTE, which set forth rules for implementing an interim firm transportation service through October 31, 2000. The MDTE approved the settlement on April 2, 1999. FG&E has made separate compliance filings that were approved by the MDTE to implement its interim firm gas transportation service for its largest general service customers and to complement this service with a firm gas peaking service. This interim service is now superseded by the permanent transportation service, which was approved for implementation on November 1, 2000.

On November 3, 1999, the Massachusetts LDCs filed Model Terms and Conditions for Gas Service, including provisions for capacity assignment, peaking service, and Default Service. In accordance with the MDTE's approval of these Model Terms and Conditions in January 2000, FG&E filed Company-specific tariffs that implement natural gas unbundling. The MDTE also opened a rulemaking proceeding on proposed regulations that would govern the unbundling of services related to the provision of natural gas. The MDTE has issued an order approving the tariffs and final regulations effective November 1, 2000.

New Hampshire Electric Restructuring  - On February 28, 1997, the NHPUC issued its Final Plan for New Hampshire electric utilities to transition to a competitive electric market in the state (Final Plan). The Final Plan linked the interim recovery of stranded cost by the State's utilities to a comparison of their existing rates with the regional average utility rates. CECo's and E&H's rates are below the regional average; thus, the NHPUC found that CECo and E&H were entitled to full interim stranded cost recovery, as defined by the NHPUC. However, the NHPUC also made certain legal rulings, which could affect CECo's and E&H's long-term ability to recover all of their stranded costs.

Northeast Utilities' affiliate Public Service Company of New Hampshire (PSNH) filed suit in U.S. District Court for protection from the Final Plan and related orders and was granted an indefinite stay. In June 1997, Unitil, and other utilities in New Hampshire, intervened as plaintiffs in the federal court proceeding. In June 1998, the federal court clarified that the injunctions issued by the court in 1997 had effectively frozen the NHPUC's efforts to implement restructuring. This amended injunction has been challenged by the NHPUC, and affirmed by the First Circuit Court of Appeals. Unitil continues to be a plaintiff-intervenor in federal district court.

Unitil has continued to work actively to explore settlement options and to seek a fair and reasonable resolution of key restructuring policies and issues in New Hampshire. The Company is also monitoring the regulatory and legislative proceedings dealing with electric restructuring in the state. In October 2000, the NHPUC approved a settlement for the restructuring of PSNH, which settlement was implemented on May 1, 2001.

Pending Rate Proceedings  - The last formal regulatory filings to increase base electric rates for Unitil's three retail operating subsidiaries occurred in 1985 for CECo, 1984 for FG&E, and 1981 for E&H. A majority of the Company's operating revenues are collected under various periodic rate adjustment mechanisms including fuel, purchased power, cost of gas, energy efficiency, and restructuring-related cost recoverymechanisms. Industry restructuring will continue to change the methods of how certain costs are recovered through the Company's regulated rates and tariffs.

As discussed above, FG&E filed for and received approval of an increase to its electric Standard Offer Service rate reflecting extraordinary increases in the price of oil and natural gas. FG&E also received an increase to its Cost of Gas Adjustment resulting in bill increases of approximately 25%, effective November 1, 2000. FG&E subsequently received another increase of approximately 20% to its Cost of Gas Adjustment for effect February 1, 2001. Wholesale natural gas prices reached record levels in New England and across the United States in response to cold weather and tight supplies. Reflecting a moderation in natural gas prices, FG&E implemented a decrease to its Cost of Gas Adjustment for the summer period, effective May 1, 2001. In New Hampshire, CECo and E&H filed and received approval of increases to their Fuel and Purchased Power Adjustments, resulting in bill increases of 25% to 34%, depending upon usage patterns, effective January 1, 2001. These higher fuel costs are a pass-through without markup or profit. Retail electricity prices for most New England utilities increased this past winter.

On May 15, 1998, FG&E filed a gas base rate case with the MDTE. The last base rate case had been in 1984. After evidentiary hearings, the MDTE issued an Order allowing FG&E to establish new rates, effective November 30, 1998, that would produce an annual increase of approximately $1.0 million in gas revenues. As part of the proceeding, the Massachusetts Attorney General alleged that FG&E had double-collected fuel inventory finance charges, and requested that the MDTE require FG&E to refund approximately $1.6 million in double collections since 1987. The Company believes that the Attorney General's claim is without merit and that a refund was not justified or warranted. The MDTE rejected the Attorney General's request and stated its intent to open a separate proceeding to investigate the Attorney General's claim. On November 1, 1999, the MDTE issued an Order of Notice initiating an investigation of this matter. Hearings were held in early 2000 and were reopened in November 2000 to hear new evidence. Supplemental testimony has been filed and additional hearings were held in February 2001. Briefs were filed during March 2001.

On October 29, 1999, the MDTE initiated a proceeding to implement Performance Based Rate making (PBR) for all electric and gas distribution utilities in Massachusetts. PBR is a method of setting regulated distribution rates that provide incentives for utilities to control costs while maintaining a high level of service quality. Under PBR, a company's earnings are tied to performance targets, and penalties can be imposed for deterioration of service quality. On December 29, 1999, FG&E filed a petition with the MDTE for authority to defer for later recovery costs associated with its preparation of a PBR filing for its gas division and its participation in the MDTE-initiated generic gas and electric PBR proceedings. This petition and the MDTE's generic proceeding are pending. The Company is currently evaluating the impact, if any, that PBR would have on the Company's ability to continue applying the standards of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation."

On December 31, 1999, the Massachusetts Attorney General filed a complaint against FG&E requesting that the MDTE investigate the distribution rates, rate of return, and depreciation accrual rates for FG&E's electric operations in calendar year 1999. The MDTE opened a proceeding in November 2000, held a public hearing and procedural conference in December 2000, and subsequently issued a procedural schedule covering the period January through July 2001. Any order received from the MDTE would apply to the Company's rates prospectively and would not be retroactive. Management is unable to predict the outcome of this proceeding but an unfavorable result could have an adverse impact on the Company's consolidated financial position.

During April 2001, the MDTE held a technical session with the Company and the Attorney General regarding certain costs the Company has recovered through its Local Distribution Adjustment Clause. Approximately $175,000 of costs are in dispute. The Company is preparing written responses to questions posed during the session.

Due to changes in NH tax law, on April 26, 2001, CECo and E&H filed tariff changes with the NHPUC for effect May 1, 2001 to reduce rates by eliminating the State Gross Receipts Franchise Tax, and to increase rates by including a Business Profits Tax factor. The overall impact is a small decrease for most customers. The tariff changes have been suspended and set for hearing.

Millstone Unit No. 3  - FG&E has a 0.217% nonoperating ownership in the Millstone Unit No. 3 (Millstone 3) nuclear generating unit which supplies it with 2.49 megawatts (MW) of electric capacity. In January 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 3 on its Watch List, which calls for increased NRC inspection attention. In March 1996, as a result of engineering evaluations, Millstone 3 was taken out of service. The NRC authorized the restart of Millstone 3 in June 1998.

During the period that Millstone 3 was out of service, FG&E continued to incur its proportionate share of the unit's ongoing Operations and Maintenance (O&M) costs, and may incur additional O&M costs and capital expenditures to meet NRC requirements. FG&E also incurred costs to replace the power that was expected to be generated by the unit. During the outage, FG&E incurred approximately $1.2 million in replacement power costs, and recovered those costs through its electric fuel charge, which is subject to review and reconciliation by the MDTE. Under existing MDTE precedent, FG&E's replacement power costs of $1.2 million could be subject to disallowance in rates.

In August 1997, FG&E, in concert with other non-operating joint owners, filed a demand for arbitration in Connecticut and a lawsuit in Massachusetts, in an effort to recover costs associated with the extended unplanned shutdown. Several preliminary rulings have been issued in the arbitration and legal cases, and both cases are continuing. On March 22, 2000, FG&E entered into a settlement agreement with the defendants under which FG&E agreed to dismiss its lawsuit and arbitration claims. The settlement was generally similar to earlier settlements with the defendants, and three joint owners that own, in the aggregate, approximately 19% of the unit. The settlement provided for FG&E to receive an initial payment of $600,000 and other amounts contingent upon future events and would result in FG&E's entire interest in the unit being included in the auction of the majority interest, and certain of the minority interests, in Millstone 3. FG&E is flowing through the net proceeds of the settlement to its customers.

In August 2000, FG&E entered into an agreement, along with other joint owners, to sell its interest in Millstone 3 to a subsidiary of Dominion Resources, Inc. After filing for review and approval from a number of regulatory agencies, including the MDTE, NHPUC and NRC, FG&E sold all of its interest in Millstone 3 on March 31, 2001. As a result of the settlement and sale, FG&E has been relieved of all residual liabilities, including decommissioning liability, associated with Millstone 3.

CAPITAL REQUIREMENTS

Capital expenditures for the three months ended March 31, 2001 were approximately $6.3 million. This compares to $4.3 million during the same period last year. Annual capital expenditures for the year 2001 are estimated to be approximately $18.5 million as compared to $22.2 million for 2000. This projection reflects normal capital expenditures for utility system expansions, replacements and other improvements.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Although Unitil's utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of fuel and gas costs in rates. Consequently, there is limited commodity price risk after consideration of the related rate-making. As the utility industry deregulates, the Company will be divesting its commodity-related energy businesses and therefore will be further reducing its exposure to commodity-related risk.

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 6.  Exhibits and Reports on Form 8-K.

(a)  Exhibits

Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of	Filed herewith
	Earnings Per Average Common Share
4.1	Tenth Supplemental Indenture dated January 15, 2001 amending CECo's Original First Mortgage Bonds Indenture and all successor supplemental indentures.	Filed herewith
4.2	Eleventh Supplemental Indenture dated April 20, 2001  relating to CECo's First Mortgage Bonds, Series K, 8.0% due May 1, 2031.	Filed herewith
4.3	Bond Purchase Agreement dated April 20, 2001 relating to CECo's First Mortgage Bonds, Series K, 8.0% due May 1, 2031.	Filed herewith
4.4	Twelfth Supplemental Indenture dated April 20, 2001 relating to E&H's First Mortgage Bonds, Series M, 8.0% due May 1, 2031.	Filed herewith
4.5	Bond Purchase Agreement dated April 20, 2001 relating to E&H's First Mortgage Bonds, Series M, 8.0% due May 1, 2031.	Filed herewith

(b)    Reports on Form 8-K

During the quarter ended March 31, 2001, the Company did not file any reports on Form 8-K.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

UNITIL CORPORATION

(Registrant)

Date:   May 14, 2001	/s/ Anthony J. Baratta, Jr.
	Anthony J. Baratta, Jr.
	Chief Financial Officer

Date:   May 14, 2001	/s/ Mark H. Collin
	Mark H. Collin
	Treasurer

EXHIBIT 11.

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

COMPUTATION OF EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING

(000's except for per share data)

(UNAUDITED)

BASIC	Three Months Ended March 31,
EARNINGS PER SHARE	2001	2000
Net Income	$2,006	$2,664
Less: Dividend Requirement
on Preferred Stock

67

 

67

Net Income Applicable

   

    to Common Stock

$1,939

 

$2,597

    

Average Number of Common

   

    Shares Outstanding

4,738

 

4,715

    

Basic Earnings Per Common Share

$0.41

 

$0.55

DILUTED	Three Months Ended March 31,
EARNINGS PER SHARE	2001	2000
Net Income	$2,006	$2,664
Less: Dividend Requirement
on Preferred Stock	67	67
Net Income Applicable
to Common Stock	$1,939	$2,597
Average Number of Common
Shares Outstanding	4,756	4,747
Diluted Earnings Per Common Share	$0.41	$0.55