<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>4
<FILENAME>ex992.txt
<DESCRIPTION>EXHIBIT B
<TEXT>
Exhibit B


                          Bangor Hydro-Electric Company



                          2003 Annual Financial Report




<PAGE>


                          TABLE OF CONTENTS


<TABLE>
<CAPTION>
                                                                                               Page

<S>                                                                                              <C>
Selected Financial Data                                                                          3

Management's Discussion and Analysis of Results of Operations and Financial Condition            5

Consolidated Statements of Income                                                                13

Consolidated Balance Sheets                                                                      14

Consolidated Statements of Capitalization                                                        16

Consolidated Statements of Cash Flows                                                            17

Consolidated Statements of Common Stock Investment                                               18

Notes to Consolidated to Financial Statements                                                    19

Report of Independent Auditors                                                                   43

Principal Executive Officer's and Chief Financial Officer's Certifications                       45
</TABLE>


                                       2
<PAGE>

<TABLE>
<CAPTION>
Selected Financial Data
Five-Year Statistical Summary
(Unaudited)
                                                                 2003         2002           2001           2000           1999
                                                                 ----         ------         ------         ------         ----
Megawatt Hours (MWH) Generated And Purchased
<S>                                                         <C>            <C>            <C>            <C>            <C>
        Hydro Generation ***                                   99,834         84,436         65,392         90,719        205,265
        Oil (Company)                                           1,409            868          2,435          3,142         69,026
        Biomass/Refuse (Purchased)                            159,421        154,832        150,401        152,060        137,384
        NEPOOL/Other Purchases                              2,189,881      2,333,428      1,782,797      1,914,615      1,629,643
                                                         -------------------------------------------------------------------------
             Total Generated & Purchased                    2,450,545      2,573,564      2,001,025      2,160,536      2,041,318
                  Less Line Losses and Company Use            154,493        128,282        130,067        140,470        143,198
                                                         -------------------------------------------------------------------------
        Remainder-MWH sold                                  2,296,052      2,445,282      1,870,958      2,020,066      1,898,120
                                                         -------------------------------------------------------------------------
Classification of Sales-MWH
        Residential                                           584,294        556,462        546,144        558,596        533,566
        Commercial                                            588,094        571,372        583,829        570,963        545,087
        Industrial                                            353,323        449,170        462,792        604,959        667,059
        Lighting                                                8,684          8,719          8,742          8,859          8,911
        Wholesale                                               3,093          2,925          2,676          2,799          2,716
                                                         -------------------------------------------------------------------------
             Total MWH Billed to Customers                  1,537,488      1,588,648      1,604,183      1,746,176      1,757,339
                  Unbilled Sales-Net (Decrease) Increase       (9,940)        13,071          4,343          2,629         11,772
                                                         -------------------------------------------------------------------------
             Total Delivered Sales (MWH)                    1,527,548      1,601,719      1,608,526      1,748,805      1,769,111
             Off-System Sales                                 768,504        843,563        262,432        271,261        129,009
                                                         -------------------------------------------------------------------------
        Total Energy Sales (MWH)                            2,296,052      2,445,282      1,870,958      2,020,066      1,898,120
                                                         -------------------------------------------------------------------------
Operating Revenues (000's)
        Electric Operating Revenue
           Residential                                       $ 55,000       $ 52,219       $ 50,264       $ 57,746       $ 73,304
           Commercial                                          41,095         39,645         37,795         44,329         63,093
           Industrial                                          15,176         15,879         15,516         23,749         43,560
           Lighting                                             1,876          1,888          1,837          1,929          2,268
           Wholesale                                               19             18             19             63            220
           Unbilled Sales-Net (Decrease) Increase              (1,017)         1,245            815         (5,014)         2,042
                                                         -------------------------------------------------------------------------
                Subtotal                                    $ 112,149      $ 110,894      $ 106,246      $ 122,802      $ 184,487
        Other Miscellaneous Revenues                            4,910          5,522          7,620          4,050            561
                                                         -------------------------------------------------------------------------
        Total Electric Operating Revenue                    $ 117,059      $ 116,416      $ 113,866      $ 126,852      $ 185,048
        Off-System Revenue                                     25,995         39,712         18,952         19,352         12,947
        Standard Offer Service Revenue                              7         12,196         84,589         66,134              -
                                                         -------------------------------------------------------------------------
             Total Operating Revenues                       $ 143,061      $ 168,324      $ 217,407      $ 212,338      $ 197,995
                                                         -------------------------------------------------------------------------
Operating Expenses (000's)
        Fuel for Generation and Purchased Power              $ 54,440       $ 61,670       $ 34,649       $ 44,509       $ 80,748
        Standard Offer Service Purchased Power                     (1)        11,508         82,839         65,553              -
        Operating and Maintenance Expense                      31,460         34,573         36,800         35,311         36,492
        Depreciation and Regulatory Amortizations              19,604         25,123         27,751         28,312         30,565
        Taxes                                                  13,043         11,413         11,752         12,228         14,032
                                                         -------------------------------------------------------------------------
             Total Operating Expenses                       $ 118,546      $ 144,287      $ 193,791      $ 185,913      $ 161,837
                                                         -------------------------------------------------------------------------
Summary of Operations (000's)
        Operating Revenue                                   $ 143,061      $ 168,324      $ 217,407      $ 212,338      $ 197,995
        Operating Expenses                                    118,546        144,287        193,791        185,913        161,837
        Other Income (Loss) (including equity AFDC)             1,652          1,303           (655)           613          2,805
        Interest Expense (net of borrowed AFDC)                11,728         12,879         14,273         15,936         20,683
                                                         -------------------------------------------------------------------------
             Net Income                                      $ 14,439       $ 12,461       $  8,690       $ 11,102       $ 18,280
                  Less Preferred Dividends                         81            266            266            266            945
                                                         -------------------------------------------------------------------------
             Earnings Applicable to Common Stock             $ 14,358       $ 12,195       $  8,424       $ 10,836       $ 17,335
                                                         -------------------------------------------------------------------------
</TABLE>



                                       3
<PAGE>

<TABLE>
<CAPTION>
Five-Year Statistical Summary
(Unaudited)
                                                               2003         2002            2001           2000            1999
                                                               ----         ----            ----           ----            ----
<S>                                                        <C>            <C>             <C>            <C>             <C>
Selected Financial Data
        Total Assets (000's)                               $ 563,880      $ 640,731       $ 678,245      $ 532,220       $ 543,950
                                                        ---------------------------------------------------------------------------
Electric Plant (000's)
        Total Electric Plant                               $ 361,829      $ 344,382       $ 341,143      $ 327,247       $ 318,435
        Depreciation Reserve                                 105,942         97,473          93,985         86,684          84,825
                                                        ---------------------------------------------------------------------------
             Net Electric Plant                            $ 255,887      $ 246,909       $ 247,158      $ 240,563       $ 233,610
                                                        ---------------------------------------------------------------------------
Capitalization (000's)
        Short-Term Debt                                      $ 4,000       $ 16,000        $  8,000      $       -       $       -
        Long-Term Debt                                       147,744        118,059         131,968        161,960         183,300
        Preferred Stock                                          628          4,734           4,734          4,734           4,734
        Common Equity                                        192,886        206,266         205,557        137,420         132,722
                                                        ---------------------------------------------------------------------------
             Total                                         $ 345,258      $ 345,059       $ 350,259      $ 304,114       $ 320,756
                                                        ---------------------------------------------------------------------------
Capital Structure Ratios (%)
        Short-Term Debt                                         1.2%           4.6%            2.3%             -%              -%
        Long-Term Debt                                         42.8%          34.2%           37.7%          53.2%           57.1%
        Preferred Stock                                          .2%           1.4%            1.3%           1.6%            1.5%
        Common Stock                                           55.8%          59.8%           58.7%          45.2%           41.4%
                                                        ---------------------------------------------------------------------------
             Total                                            100.0%         100.0%          100.0%         100.0%          100.0%
                                                        ---------------------------------------------------------------------------
Miscellaneous Statistics
        Shares Outstanding (Average and Year End)          7,363,424      7,363,424       7,363,424      7,363,424       7,363,424
        Basic Earnings Per Common Share                     $   1.95       $   1.66        $   1.14       $   1.47        $   2.35
        Diluted Earnings Per Common Share                   $   1.95       $   1.66        $   1.08       $   1.30        $   2.08
        Dividends Declared Per Common Share                 $   3.28       $   1.29        $   0.60       $   0.80        $   0.45
        Book Value Per Common Share                         $  16.25       $  17.65        $  17.26       $  18.66        $  18.02
        Return on Common Equity                               11.05%          9.46%           6.30%          7.98%          13.81%
        Ratio of AFDC to Common Stock Earnings                    3%             8%             14%             3%            (4)%
        Ratio of Earnings to Fixed Charges                     2.91%          2.35%           1.89%          2.11%           2.25%
        Payout Ratio                                            168%            78%             53%            54%             26%
        Percentage of Construction Expenditures
             Funded Internally                                  100%           100%            100%           100%            100%
                                                        ---------------------------------------------------------------------------
Residential Customer Data
        Average Number of Customers                           95,632         94,510          93,398         92,656          91,726
        Kilowatt-Hours per Customer                            6,110          5,888           5,847          6,029           5,817
        Revenue per Customer                                $ 575.12       $ 552.52        $ 538.17       $ 623.23        $ 799.16
        Revenue per Kilowatt-Hour in Cents                      9.41           9.38            9.20          10.34           13.74
                                                        ---------------------------------------------------------------------------
Miscellaneous System Data
        Net System Capability at Time of Peak
             (MW) Firm*                                          n/a            n/a          182.23          98.98          273.72
        System Peak Demand (MW)                               280.88         290.26          290.37         304.71          293.08
        Reserve Margin at Time of Peak**                         n/a            n/a         (37.2)%        (67.5)%          (6.6)%
        System Load Factor                                     68.4%          68.0%           68.4%          70.8%           74.5%
                                                        ---------------------------------------------------------------------------
</TABLE>

        *     The net system capability was reduced subsequent to the
                generation asset sale, which occurred in May 1999. As of 2002,
                BHE no longer provides generation capability to serve load.
        **    While the reserve margin at time of peak in 2001, 2000 and 1999
                was negative, the system requirements were met through spot
                market purchases. As of 2002, BHE no longer provides generation
                capability to serve load.
        ***   Subsequent to the generation asset sale in May 1999, hydro
                generation was purchased.


                                       4
<PAGE>

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

Recent Events Affecting the Company

     Workforce Reductions - The Company's long-term strategy to provide lower
     rates to customers while maintaining and improving service quality levels
     has continued to evolve. Staged implementation of an Asset Management model
     has resulted in streamlined processes and improved efficiencies. Efficiency
     gains and a more integrated approach to capital and maintenance programs,
     combined with the loss of certain customers and a reduction in customer
     initiated work, necessitated a reduction in employee levels. To accomplish
     this, the Company restructured several areas, including Information
     Technology, Customer Service, Planning & Engineering, Operations Support,
     and Project Services Departments. As part of this restructuring, the
     Company's workforce was reduced by 19 employees in May 2003. The affected
     employees received an enhanced severance package, which included severance
     pay, two years of medical benefits, education benefits, and employment
     counseling. The total costs associated with the severance packages amounted
     to approximately $1.1 million and have been recorded as a regulatory asset.
     The Company's Alternative Rate Plan (ARP) Order from the Maine Public
     Utilities Commission (MPUC) allowed the deferral of these restructuring
     costs, with a ten-year amortization period.

     Transmission Line Project - In May 2003, a joint project between the
     Company and Great Lakes Hydro America (GLHA) to build a new transmission
     line system, interconnected with the New England power grid, was completed
     and became operational. The new line stretches 25 miles and includes two
     new substations, with 126-megawatts of capacity. The Company's total cost
     associated with the construction project was approximately $10 million.
     Under the Company's transmission rate tariff, GLHA will pay for this
     investment over a 15-year period, including a return on investment of 11
     1/4%. The Company also realized a one-time $800,000 bonus as a result of
     meeting the construction deadlines through its construction management
     efforts in the second quarter of 2003.

Results of Operations

     Earnings - Basic earnings per common share were $1.95 and $1.66 for the
     years ended 2003 and 2002, respectively. The earned return on average
     common equity was 11.1% in 2003 and 9.5% in 2002.

     As a result of increased energy sales, and absent an unbilled revenue
     adjustment in the third quarter of 2003 discussed below, electric operating
     revenues for the non-large special rate contract customers were
     approximately $3.2 million higher in 2003 than in 2002. The increased sales
     were principally a function of more favorable weather conditions in the
     winter of 2003 relative to 2002. Principally as a result of the Company's
     workforce reductions in the second quarter of 2002 and in May 2003, labor
     expense was approximately $1.9 million lower in 2003 as compared to 2002.
     Earnings were also positively benefited in 2003 as a result of the
     previously discussed $800,000 transmission project bonus. Also positively
     impacting earnings in 2003 relative to 2002 was reduced interest expense on
     borrowings. Finally, earnings were enhanced in 2003 by reduced other
     operation and maintenance (O&M) expense associated with increased
     capitalized construction overheads, principally resulting from the
     previously discussed major transmission power line construction project.

     These earnings benefits were offset by a one-time $1.6 million after-tax
     adjustment to unbilled revenue in 2003. Earnings in 2003 were also
     negatively affected by a $1.3 million increase in pension costs. The
     increased expense is principally attributable to a decrease in the discount
     rate used to actuarially compute the expense as well as the impact of
     reduced returns on pension plan assets.

     Revenues - With the implementation of competition in the electric utility
     industry in the state of Maine starting March 1, 2000, and excluding the
     provision of standard-offer service through February 2002, the Company no
     longer sells electricity to customers. The Company's transmission and


                                       5
<PAGE>

     distribution (T&D) and stranded cost charges to customers, though, continue
     to be based on customers' electricity usage measured in kilowatt-hours
     (kWh). Consequently, discussion related to electric operating revenues will
     continue to have a kWh sales, or hereafter referred to as "energy sales"
     component.

     Electric operating revenues ($ in 000's) and energy sales volume by
     megawatt hours (mWh's) were as follows for the years ending December 31,
     2003 and 2002:

<TABLE>
<CAPTION>
        Electric Operating Revenue:                        2003             2002        Change
        --------------------------                         ----             ----        ------
<S>                                                    <C>              <C>              <C>
        Residential                                    $ 53,597         $ 53,460         $ 137
        Commercial                                       41,191           39,991         1,200
        Industrial                                       10,897           10,335           562
        Other                                             1,871            1,945           (74)
                                               ----------------- ---------------- --------------
        Subtotal                                      $ 107,556        $ 105,731       $ 1,825
        Large Special Contracts                           4,593            5,163          (570)
                                               ----------------- ---------------- -------------
        Total Related to Energy Sales                 $ 112,149        $ 110,894       $ 1,255
        Other Miscellaneous Revenues                      4,910            5,521          (611)
                                               ----------------- ---------------- --------------
        Total Electric Operating Revenue              $ 117,059        $ 116,415         $ 644
                                               ----------------- ---------------- -------------


        Energy Sales:   (in mWh's)                         2003             2002        Change
        ------------                                       ----             ----        ------
        Residential                                     572,188          566,630         5,558
        Commercial                                      585,219          583,508         1,711
        Industrial                                      198,416          196,479         1,937
        Other                                            11,625           11,868          (243)
                                               ----------------- ---------------- --------------
        Subtotal                                      1,367,448        1,358,485         8,963
        Large Special Contracts                         160,100          243,234       (83,134)
                                               ----------------- ---------------- --------------
        Total Energy Sales                            1,527,548        1,601,719       (74,171)
                                               ----------------- ---------------- --------------
</TABLE>

     Positively impacting the increased revenues in 2003 was an approximately 1%
     increase in energy sales, which excludes energy sales to certain large
     special contract customers. As previously discussed, favorable weather
     conditions positively impacted energy sales in the winter of 2003. The
     increased revenues in 2003 were also affected by a 6.5% rate increase on
     March 1, 2002 in connection with the recovery of stranded costs. The
     Company's distribution electric rates were decreased by 2.5%, and
     transmission electric rates were increased by approximately 18% on July 1,
     2003. The net impact of these two rate changes resulted in a small increase
     in electric operating revenues. Also, in November 2003, the Company's
     transmission electric rates were increased by an additional 5.8%. As
     previously discussed, electric operating revenues were negatively impacted
     by the $2.7 million one-time adjustment to unbilled revenue in the third
     quarter of 2003. Excluding this adjustment, energy sales and associated
     electric operating revenues, excluding certain large special contract
     customers, were approximately 3% and 4% higher, respectively, in 2003 as
     compared to 2002.


                                       6
<PAGE>

     While energy sales to large special rate contract customers decreased by
     approximately 83,000 mWh's in 2003, associated electric operating revenues
     only decreased by approximately $570,000. The reduced energy sales are
     principally a result of the financial difficulties in the paper industry.
     The minimal revenue impact is principally a result of the significantly
     reduced electric rates for these large special rate contract customers.
     These customers make a small contribution to the Company's fixed costs.
     Also, Effective July 1, 2001, the Company entered into a special rate
     contract with a large industrial customer to provide fully bundled electric
     service (both T&D and energy) to this customer. Formerly, the Company was
     only providing T&D service to this customer. The Company entered into a
     power purchase contract to procure the power necessary to serve this
     customer under this contract. Principally as a result of the new contract,
     which ended in March 2002, the Company recognized approximately $875,000 in
     greater electric operating revenues associated with this customer in 2002
     as compared to 2003.

     Other miscellaneous revenues were lower in 2003 as a result of an
     approximately $1.5 million reduction in certain stranded cost related
     revenue deferrals. This decrease was offset somewhat by increased
     transmission wheeling revenues associated with the completion of the
     previously discussed major transmission line construction project in the
     second quarter of 2003.

     Off-system sales, which are resales of purchased power, were approximately
     $13.7 million lower in the 2003 in relation to 2002. One of the Company's
     power sale contracts ended in February 2003, and as a result, associated
     revenues were approximately $11.8 million lower in 2003. The Company's
     stranded cost rates that were set on March 1, 2002 were adjusted to take
     into consideration the end of this long-term power sales contract.
     Effective March 1, 2002, the Company was no longer responsible for being
     the standard-offer service provider. The Company, though, still has a
     standard-offer related power supply commitment with a third party through
     February 2004 amounting to approximately $54 million for the full contract
     period. The power delivered under this contract is being resold to one of
     the new standard-offer service providers, with estimated revenues to be
     realized of approximately $40 million for the full contract period. The
     difference between the cost of the power and the resale revenues are being
     recovered in the Company's stranded cost rates starting March 1, 2002. The
     power resales associated with this contract were approximately $3.1 million
     lower in 2003 as compared to 2002.

     The $12.2 million decrease in standard-offer service revenues in 2003 is
     due mostly to the Company no longer being the standard-offer provider
     effective March 1, 2002.

     Expenses - Purchased power and fuel for generation expense decreased $7.2
     million in 2003 as compared to 2002. Impacting this decrease in 2003 was a
     $5.7 million reduction in power purchases in 2003 associated with the
     previously discussed former standard offer power supply contract. In 2002,
     the Company incurred approximately $2.2 million of expense in connection
     with supplying a portion of the power under the previously discussed power
     sales contract that ended in February 2003. Also, in connection with the
     previously discussed special rate contract with a large industrial customer
     that ended in March 2002, in 2002 the Company incurred approximately
     $872,000 of purchased power expense associated with serving the customer.
     No such expenses were incurred in 2003. Finally, transmission related
     expenses associated with congestion management charges from the ISO New
     England were approximately $1.2 million lower in 2003 in relation to 2002.
     This reduction is due primarily to the implementation of new rules in March
     2003 that resulted in the Company no longer being responsible for these
     charges.

     The decrease in standard-offer service purchased power in 2003 is due to
     the fact the Company was the standard-offer service provider for the first
     two months of 2002.

     Other O&M expense decreased by approximately $3.2 million in 2003 in
     comparison to 2002. Principally as a result of the previously discussed
     workforce reductions, labor expense reductions were approximately $1.9
     million in 2003. Principally as a result of the previously discussed major
     transmission line construction project, the reduction in other O&M
     associated with the capitalized


                                       7
<PAGE>

     construction overheads was $2 million greater in 2003 as compared to 2002.
     Other O&M expense in 2003 was also positively benefited by a $643,000
     reduction in bad debt expense. This is due mostly to the Company no longer
     being the standard-offer service provider effective in March 2002. Finally
     reducing O&M expense in 2003 was the deferral of approximately $615,000 of
     costs in connection with the Company's ARP Order. Under this Order, to the
     extent certain annual weather related or other mandated costs are in excess
     of a $750,000 threshold, the Company is allowed to establish a regulatory
     asset for this amount and recover over a one-year period starting with the
     ARP annual rate change on July 1st of the next year. Management believes
     that these were prudently incurred costs and are properly deferrable for
     future rate recovery. Management cannot, though, predict if the MPUC will
     allow the full recovery of these costs.

     Offsetting these other O&M reductions, and as a result of reasons
     previously discussed, pension benefit costs were $1.3 million greater in
     2003 relative to 2002. Other O&M was also increased in 2003 in connection
     with a higher level of employee incentive bonuses, which resulted from a
     greater level of achievement of certain performance measures in 2003 as
     compared to 2002.

     Depreciation and amortization expense decreased by approximately $959,000
     in 2003 relative to 2002 due principally to the impact of certain electric
     plant retirements made in 2002, and the end of the depreciable lives of
     certain computer and other shorter-lived assets in 2003. These reductions
     were offset to some extent by the effect of plant additions in 2003. The
     Company is in the process of conducting a depreciation study to determine
     the appropriate useful lives for its plant assets as well as the propriety
     of the level of the Company's depreciation reserve, with an anticipated
     completion in 2004. While the preliminary results of the study reflect that
     the Company's depreciation reserve is understated, and future depreciation
     expense will be increased, management cannot predict the final results of
     the study or how the results will be implemented within the context of the
     Company's ARP and annual transmission rate proceedings with the Federal
     Energy Regulatory Commission.

     The Company's expenses in 2002-2003 have been significantly affected by
     amortizations authorized by the MPUC and charged annually against earnings.
     The MPUC has specifically authorized the inclusion of these expenses in the
     Company's electric rates. Absent such regulatory authority, the expenses
     that gave rise to the amortizations would have been charged to operations
     when incurred. Instead, the recognition of such expenses have been
     deferred, and appear on the Consolidated Balance Sheets as assets on the
     strength of the regulatory authority to amortize them and to collect these
     amounts from customers (thus the term "regulatory assets"). Although there
     are a number of such authorized amortizations, the major ones include the
     amortization of purchased power contract buyouts/restructurings, Seabrook
     investment, deferred asset sale gain, and deferred employee transition
     costs. For a discussion of these regulatory assets and liabilities, see
     Notes 6 and 9 to the consolidated financial statements. Effective March 1,
     2000, and further adjusted on March 1, 2002, in connection with the
     implementation of new electric rates associated with the electric utility
     industry restructuring, the Company began amortizing certain stranded cost
     related regulatory assets and liabilities that had been previously deferred
     on the Company's balance sheets. The following summarizes the components of
     the regulatory amortizations for 2003 and 2002:

<TABLE>
<CAPTION>
                                                                            2003          2002
                                                                            ----          ----
<S>                                                                  <C>           <C>
        Contract buyouts and restructuring                           $16,828,947   $20,274,191
        Seabrook investment                                            1,699,050     1,699,050
        Deferred asset sale gain                                      (9,030,600)   (4,681,324)
        Other stranded cost related regulatory assets and
        liabilities                                                   (1,082,638)   (4,335,047)
        Distribution related regulatory assets and liabilities           750,858     1,159,530
        Employee transition costs                                        848,478       458,021
                                                                  --------------- -------------
        Total Regulatory Amortizations                               $10,014,095   $14,574,421
                                                                  --------------- -------------
</TABLE>


                                       8
<PAGE>

     The reduction in the amortization of contract buyouts and restructuring was
     due to the end of the amortization period in the first quarter of 2003 of
     deferred costs associated with a 1993 purchased power contract buyout. The
     deferred asset sale gain amortization schedule was set in an uneven manner
     in the Company's stranded cost rate order effective March 1, 2000, in order
     to levelize the Company's revenue requirement over the amortization period.
     Consequently, this amortization varies in 2003 as compared to 2002. The
     approximately $3.3 million increase in amortization expense associated with
     other stranded cost related regulatory assets and liabilities resulted
     principally from an amortization designed to levelize the Company's
     stranded cost revenues over the period from March 1, 2002 to February 28,
     2005. As with the asset sale gain, this amortization varies from year to
     year. Offsetting this to some extent is a higher level of amortization in
     2003 associated with certain regulatory liabilities that began to be
     amortized in March 2002. The reduction in the amortization of distribution
     related regulatory assets and liabilities was due mostly to the end of the
     amortization of deferred ice storm costs in May 2003. The amortization of
     employee transition costs was greater in 2003, as this amortization started
     in June 2002 when the initial deferral of employee transition costs was
     recorded.

     The decrease in property and other taxes in 2003 in comparison to 2002 was
     principally due to a reduction in payroll taxes, resulting from the
     previously workforce reductions in the second quarter of 2002 and in May
     2003. This was offset somewhat by increased property taxes in 2003 caused
     by increases to electric plant in service and higher property tax rates.

     The increase in total federal and state income taxes in 2003 relative to
     2002 was primarily a result of higher earnings in 2003 in relation to 2002.
     See Footnote 2 to the Consolidated Financial Statements for a
     reconciliation of the Company's effective income tax rate.

     In December 2002, the Company filed with the Internal Revenue Service (IRS)
     a request for a change in the accounting for costs capitalized for income
     tax reporting purposes, resulting in an approximately $6.6 million
     reduction in current income tax obligations. While the IRS has not accepted
     the Company's request, based on recommendations from the Company's tax
     advisors, this deduction was included in the filing of the Company's 2002
     federal and state income tax returns, and the resulting income tax refunds
     were received in 2003. As a result of regulatory accounting for state
     income taxes, this deduction resulted in an approximately $650,000
     reduction in income tax expense in 2003.

     Other Income and (Deductions) and Interest Expense - Allowance for funds
     used during construction (AFDC), which includes carrying costs on certain
     regulatory assets and liabilities, decreased by approximately $445,000 in
     2003 relative to 2002. The decrease was the result of several factors,
     including the implementation of new stranded cost rates on March 1, 2002,
     whereby the rate recovery of various regulatory assets began and the
     accrual of carrying costs ended. Also, while construction expenditures were
     greater in 2003 than in 2002, AFDC on construction work in progress was
     lower in 2003, as the previously discussed major transmission line project
     was funded by GLHA until the end of the construction activities occurred.
     AFUDC was also lower in 2003 as a result of carrying costs recorded on the
     previously discussed regulatory liability designed to levelize the
     Company's stranded cost revenues over the period from March 1, 2002 to
     February 28, 2005.

     Other income, net of income taxes, increased by approximately $568,000 in
     2003 compared to 2002 principally as a result of previously discussed
     $800,000 one-time transmission project bonus.

     Long-term debt interest expense decreased $1.2 million in 2003 relative to
     2002 due principally to repayments on the Company's long-term debt in each
     year. In June 2003 and 2002, the Company made $17.2 million and $16.1
     million in principal payments, respectively, on the Company's Finance
     Authority of Maine (FAME) Revenue Notes. Also reducing 2003 long-term debt
     interest expense was the retirement of the $15 million in 7.3% first
     mortgage bonds at the end of May 2003 and the $20 million in 7.38% first
     mortgage bonds at the end of July 2002. These decreases were offset to some
     extent by additional interest expense in 2003 resulting from the issuance
     of $20 million in 6.09%


                                       9
<PAGE>

     senior unsecured notes in December 2002, $30 million in 5.31% senior
     unsecured notes in August 2003, and $20 million in 5.31 senior unsecured
     notes in December 2003.

     Other interest expense decreased approximately $194,000 in 2003 relative to
     2002. While weighted average 2003 borrowings under the Company's revolving
     credit facility were higher in 2003, associated interest expense was lower,
     as a result of lower short-term borrowing rates in 2003. Also reducing
     other interest expense in 2003 was a reduction in the amortization of debt
     issuance costs, primarily attributable to the end of the amortization
     period of certain deferred debt issuance costs.

Liquidity, Capital Requirements, and Capital Resources

     The Consolidated Statements of Cash Flows reflect events in 2003 and 2002
     as they affect the Company's liquidity. Net increase in cash from operating
     activities was $45.6 million in 2003 as compared to $33.4 million in 2002.
     Increased earnings positively impacted the increased operating cash flows
     in 2003. Also increasing cash flows from operations in 2003 relative to
     2002 was approximately $8 million in income tax refunds received in 2003,
     principally as a result of the previously discussed tax accounting change.
     Also there was as an approximately $1.5 million decrease in income tax
     payments in 2003 compared to 2002. In each year, cash flows were negatively
     affected by severance related payments to employees in connection with the
     previously discussed workforce reductions. In 2003, there were $2.1 million
     of such payments as compared to $3.5 million in 2002. Offsetting these
     improvements in operating cash flows in 2003 somewhat was a $1.9 million
     contribution to the Company's defined benefit pension plan in the third
     quarter of 2003.

     Construction expenditures were approximately $9.1 million higher in 2003 as
     compared to 2002 due principally to the previously discussed major
     transmission line capital project that was completed in 2003.

     The following summarizes the Company's capital expenditures for each of
     2003 and 2002:

      ($000's)                                                2003        2002

      Electric distribution system                          $8,146     $ 7,916
      Electric transmission system                          10,454       1,415
      Other, including general property and software           601         763
                                                        -----------------------
      Total capital expenditures                           $19,201     $10,094
                                                        -----------------------

     In 2003 and 2002, the Company received $735,000 and $525,000, respectively,
     in proceeds from Maine Yankee Atomic Power Company (Maine Yankee) in
     connection with the redemption of common stock. The Company is a 7% owner
     of the Maine Yankee nuclear plant. Maine Yankee, starting in 2001, began a
     program of systematically redeeming its common stock from its owners in
     connection with the decommissioning of the plant.

     In 2003 the Company has made $24.1 million in common dividend payments to
     its parent company, Emera, Inc. as compared to a $9.5 million in such
     payments in the 2002 period.

     As discussed in the 2002 Form 10-K, in the first quarter of 2003, the
     Company completed the redemption of a significant portion of its
     outstanding preferred stock, at a total cost of $4.6 million. As a result
     of the decrease in preferred shareholders, the Company filed with the
     Securities and Exchange Commission for de-registration of its preferred
     stock.

     The $8.9 million decrease in payments on long-term debt is due principally
     to the final maturity of the $20 million 7.38% first mortgage bonds in 2002
     and $5.5 million in principal payments on the $24.8


                                       10
<PAGE>

     million medium term notes in 2002. This was offset somewhat by the final
     maturity of the $15 million of 7.3% first mortgage bonds in May 2003, and a
     $1.1 million increase in the annual principal payment of the FAME revenue
     notes in 2003 as compared to 2002. Also in 2003, the Company made
     approximately $1.9 million in principal payments on its 5% Municipal Review
     Committee Note, as compared to $1.5 million in payments in 2002. In August
     2003 and December 2003, the Company issued $30 million and $20 million,
     respectively, in medium term notes at a fixed interest rate of 5.31%. The
     notes have a final maturity in 2018, with sinking fund requirements
     beginning in year five. In December 2002, the Company received $20 million
     in proceeds in connection with the issuance of 6.09% senior unsecured
     notes.

     In connection with the final principal and interest payment on the $24.8
     million medium term notes in 2002, the Company utilized $1.5 million of
     funds that had been maintained in a capital reserve fund since this debt
     had been issued in 1998.

     The decrease in borrowings under the Company's revolving credit facility in
     2003 was principally a result of the utilization of the proceeds from the
     $50 million medium term notes and $8 million in income tax refunds to
     paydown outstanding amounts on the Company's revolving credit facility. The
     borrowing under the revolving credit facility had increased in 2003
     necessitated by the $24.1 million in common dividend payments to Emera; a
     $17.2 million principal payment plus interest on the FAME revenue notes at
     the end of June 2003; the $15 million maturity of the 7.3% first mortgage
     bonds in May 2003; the financing of the previously discussed major
     transmission line construction project in 2003; and the $4.6 million cash
     outflow in the first quarter of 2003 in connection with the preferred stock
     redemption. The increased borrowings in the 2002 period were primarily
     attributable to the $16.1 million principal payment plus interest on the
     FAME revenue notes at the end of June 2002.

     The Company's revolving credit facility expired at the end of June 2003,
     but the bank group had extended the expiration date while the parties
     negotiated a new revolving credit agreement. On August 27, 2003, the
     Company entered into an Amended and Restated Revolving Credit Agreement
     (the Agreement) with the bank group. This Agreement expires at the end of
     June 2004. The terms of this Agreement are similar to the prior revolving
     credit agreement, although interest pricing is now tied to the achievement
     of certain financial covenants as opposed to the prior pricing based on the
     level of financial credit ratings. The Company believes that it will have
     adequate access to capital through this facility to provide funding where
     necessary for current operations and a base level of capital expenditures.
     For additional capital needs, the Company believes it has sufficient access
     to competitively priced funds in the unsecured debt market.

     The Company has approximately $52.6 million of long-term debt maturities in
     the period 2004-2008.

Other Matters

     Environmental Matters - The Company is regulated by the United States
     Environmental Protection Agency (EPA) as to compliance with the Federal
     Water Pollution Control Act, the Clean Air Act, and several federal
     statutes governing the treatment and disposal of hazardous wastes. The
     Maine Department of Environmental Protection (DEP) under various Maine
     environmental statutes also regulates the Company. The Company is actively
     engaged in complying with these federal and state acts and statutes, and it
     has not, to date, encountered material difficulties in connection with such
     compliance.

     In 1992, the Company received notice from the DEP that it was investigating
     the cleanup of several sites in Maine that were used in the past for the
     disposal of waste oil and other hazardous substances, and that the Company,
     as a generator of waste oil that was disposed at those sites, may be liable
     for certain cleanup costs. The Company learned in October 1995 that the EPA
     placed one of those sites on the National Priorities List under the
     Comprehensive Environmental Response, Compensation and Liability Act and
     would pursue potentially responsible parties. With respect to this site,
     the Company is one of a number of waste generators under investigation.


                                       11
<PAGE>

     The Company has recorded a liability, based upon currently available
     information, for what it believes are the estimated environmental
     remediation costs that the Company expects to incur for this waste disposal
     site. Additional future environmental cleanup costs are not reasonably
     estimable due to a number of factors, including the unknown magnitude of
     possible contamination, the appropriate remediation methods, the possible
     effects of future legislation or regulation and the possible effects of
     technological changes. At December 31, 2003, the liability recorded by the
     Company for its estimated environmental remediation costs amounted to
     approximately $340,000. The Company's actual future environmental
     remediation costs may be different, as additional factors become known.

     New Accounting Pronouncement - In November 2002, the Financial Accounting
     Standards Board issued Interpretation No. 45, "Guarantor's Accounting and
     Disclosure Requirements for Guarantees, Including Indirect Guarantees of
     Indebtedness of Others" (FIN 45). Along with new disclosure requirements,
     FIN 45 requires guarantors to recognize at the inception of certain
     guarantees a liability for the fair value of the obligation undertaken in
     issuing the guarantee. This differs from the current practice to record a
     liability only when a loss is probable and reasonably estimable. The
     recognition and measurement provisions of FIN 45 are applicable on a
     prospective basis to guarantees issued or modified after December 31, 2002.
     The adoption of FIN 45 did not have a material effect on the Company's
     results of operations or financial position.

     In December 2002, the Financial Accounting Standards Board issued
     Interpretation No. 46, "Consolidation of Variable Interest Entities, an
     Interpretation of ARB No. 51" (FIN 46). FIN 46 requires certain variable
     interest entities to be consolidated by the primary beneficiary of the
     entity if the equity investors in the entity do not have the
     characteristics of a controlling financial interest or do not have
     sufficient equity at risk for the entity to finance its activities without
     additional subordinated financial support from the other parties. FIN 46 is
     effective for all new variable interest entities created or acquired after
     January 31, 2003. For variable interest entities created or acquired before
     February 1, 2003, the provisions of FIN 46 must be applied for the first
     interim or annual period beginning after June 15, 2003. The adoption of FIN
     46 did not have a material effect on the Company's result of operations or
     financial position.

     Forward Looking Statements - Management's discussion and analysis of
     results of operations and financial condition contains items that are
     "forward-looking" as defined in the Private Securities Litigation Reform
     Act of 1995. These statements are subject to certain risks and
     uncertainties that could cause actual results to differ materially from
     those anticipated in the forward-looking statements. Readers should not
     place undue reliance on forward-looking statements, which reflect
     management's view only as of the date hereof. The Company undertakes no
     obligation to publicly revise these forward-looking statements to reflect
     subsequent events or circumstances. Factors that might cause such
     differences include, but are not limited to, future economic conditions,
     relationships with lenders, and developments in the legislative, regulatory
     and competitive environments in which the Company operates and other
     circumstances that could affect revenues and costs.


                                       12
<PAGE>


                         BANGOR HYDRO-ELECTRIC COMPANY
                        CONSOLIDATED STATEMENTS OF INCOME
                        For the Years Ended December 31,

<TABLE>
<CAPTION>
                                                                              2003                   2002
                                                                -------------------    -------------------
Operating Revenues:
<S>                                                                <C>                    <C>
  Electric operating revenue (Note 1)                              $   117,058,679        $   116,415,181
  Off-system sales (Note 6)                                             25,994,849             39,712,482
  Standard offer service (Note 9)                                            7,214             12,195,953
                                                                  -------------------    -------------------
                                                                   $   143,060,742        $   168,323,616
                                                                  -------------------    -------------------
Operating Expenses:
  Fuel for generation and purchased power (Note 1)                 $    54,440,026        $    61,670,112
  Standard offer service purchased power (Note 9)                             (679)            11,507,606
  Other operation and maintenance (Notes 1 and 5)                       31,459,809             34,572,636
  Depreciation and amortization (Note 1)                                 9,589,649             10,549,148
  Regulatory amortizations (Notes 6, 7 and 9)                           10,014,095             14,574,421
  Taxes -
     Local property and other                                            4,864,612              4,859,734
     Income (Note 2)                                                     8,178,070              6,553,102
                                                                  -------------------    -------------------
                                                                   $   118,545,582        $   144,286,759
                                                                  -------------------    -------------------
Operating Income                                                   $    24,515,160        $    24,036,857

Other Income And (Deductions):
  Allowance for equity funds used during construction (Note 1)             277,877                497,920
  Other, net of applicable income taxes (Note 4)                         1,373,726                805,363
                                                                  -------------------    -------------------
Income Before Interest Expense                                     $    26,166,763        $    25,340,140
                                                                  -------------------    -------------------
Interest Expense:
  Long-term debt (Note 4)                                          $    10,963,193        $    12,145,601
  Other (Note 4)                                                           985,458              1,179,320
  Allowance for borrowed funds used during construction (Note 1)          (220,628)              (446,083)
                                                                  -------------------    -------------------
                                                                   $    11,728,023        $    12,878,838
                                                                   -------------------    -------------------
Net Income                                                         $    14,438,740        $    12,461,302


Dividends On Preferred Stock                                                80,944                265,570
                                                                   -------------------    -------------------
Earnings Applicable To Common Stock                                $    14,357,796        $    12,195,732
                                                                   -------------------    -------------------


Weighted Average Number Of Shares Outstanding                            7,363,424              7,363,424
                                                                  -------------------    -------------------

Basic Earnings Per Common Share                                    $          1.95         $         1.66
                                                                  -------------------    -------------------
</TABLE>

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


                                       13
<PAGE>

                          BANGOR HYDRO-ELECTRIC COMPANY
                           CONSOLIDATED BALANCE SHEETS
                                December 31,

<TABLE>
<CAPTION>
Assets                                                                     2003                   2002
                                                             -------------------    -------------------

<S>                                                               <C>                     <C>
Investment In Utility Plant (Note 1):
    Electric plant in service, at original cost (Note 10)         $ 355,506,973           $333,410,221

    Less - Accumulated depreciation and amortization                105,942,123             97,473,295
                                                             -------------------    -------------------
                                                                  $ 249,564,850           $235,936,926

    Construction work in progress                                     2,219,024              5,933,988
                                                             -------------------    -------------------
                                                                  $ 251,783,874           $241,870,914
    Investments in corporate joint ventures: (Note 6)
       Maine Yankee Atomic Power Company                              3,109,708              4,033,846

       Maine Electric Power Company, Inc.                               993,366              1,004,473
                                                             -------------------    -------------------
                                                                  $ 255,886,948           $246,909,233
                                                             -------------------    -------------------
Other Investments, at cost (Note 8)                                $  2,583,866           $  3,590,720
                                                             -------------------    -------------------
Funds held by trustee, at cost (Notes 4 and 8)                     $ 21,191,940           $ 21,191,940
                                                             -------------------    -------------------

Current Assets:
    Cash and cash equivalents (Notes 1 and 8)                      $  2,881,954            $   988,752
    Accounts receivable, net
       of reserve ($1,488,803 in 2003 and $1,085,052 in 2002)        19,856,427             21,027,291

    Unbilled revenue receivable (Note 1)                              7,302,294              8,318,821
    Inventories, at average cost:

       Material and supplies and fuel oil                             2,368,695              2,511,848

    Prepaid expenses                                                    313,460                285,212
    Current income taxes refundable (Note 2)                            986,889                355,008
                                                             -------------------    -------------------
       Total current assets                                        $ 33,709,719           $ 33,486,932
                                                             -------------------    -------------------

Regulatory Assets and Deferred Charges:
    Goodwill-EMERA Acquisition (Note 1)                            $ 82,537,291           $ 82,537,291

    Investment in Seabrook nuclear project (Notes 7 and 9)           20,173,629             21,872,679
    Costs to terminate/restructure purchased power (Notes 6
    and 9)                                                           55,846,984             72,675,931

    Maine Yankee decommissioning costs (Notes 6 and 9)               27,125,179             31,101,273
    Above-market purchased power contract obligation (Notes
    9 and 11)                                                                 -             63,341,000

    Other regulatory assets (Notes 2, 5, 6 and 9)                    58,436,415             57,843,677

    Other deferred charges (Note 5)                                   7,375,154              6,535,328
                                                             -------------------    -------------------
       Total regulatory assets and deferred charges               $ 251,494,652           $335,907,179
                                                             -------------------    -------------------
          Total Assets                                            $ 564,867,125           $641,086,004
                                                             ===================    ===================
</TABLE>

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


                                       14
<PAGE>

                          BANGOR HYDRO-ELECTRIC COMPANY
                           CONSOLIDATED BALANCE SHEETS
                                  December 31,

<TABLE>
<CAPTION>
Stockholders' Investment and Liabilities                                   2003                   2002
                                                             -------------------    -------------------

<S>                                                               <C>                     <C>
Capitalization: (see accompanying statement)
    Common stock investment (Notes 3 and 5)                       $ 192,886,077           $206,266,149

    Preferred stock  (Note 3)                                           627,700              4,734,000
    Long-term debt, net of current portion (Notes 4 and 8)          147,744,265            118,058,636
                                                             -------------------    -------------------
         Total capitalization                                     $ 341,258,042           $329,058,785
                                                             -------------------    -------------------

Current Liabilities:
    Notes payable - banks (Note 4)                                  $ 4,000,000           $ 16,000,000
                                                             -------------------    -------------------

    Other current liabilities -
      Current portion of long-term debt  (Notes 4 and 8)           $ 20,314,357           $ 34,137,342

      Accounts payable                                               19,443,433             20,281,376

      Dividends payable                                                  11,671                 66,429

      Accrued interest                                                3,441,683              2,092,608

      Customers' deposits                                               765,748                572,291
                                                             -------------------    -------------------
         Total other current liabilities                           $ 43,976,892           $ 57,150,046
                                                             -------------------    -------------------
         Total current liabilities                                 $ 47,976,892           $ 73,150,046
                                                             -------------------    -------------------

Regulatory and Other Long-term Liabilities (Note 2):
    Deferred income taxes - Seabrook (Note 7)                      $ 10,454,583           $ 11,337,954

    Other accumulated deferred income taxes                          57,902,439             48,947,440

    Maine Yankee decommissioning liability (Note 6)                  27,125,179             31,101,273

    Deferred gain on asset sale (Note 9)                                846,574              9,888,574

    Above-market purchased power contract obligation (Note 11)                -             63,341,000

    Other regulatory liabilities (Note 9)                            11,345,947             11,264,848

    Unamortized investment tax credits                                1,090,179              1,185,596

    Accrued pension and postretirement benefit costs (Note 5)        55,929,414             50,494,119

    Other long-term liabilities (Notes 6 and 10)                     10,937,876             11,316,369
                                                             -------------------    -------------------
         Total regulatory and other long-term liabilities         $ 175,632,191           $238,877,173
                                                             -------------------    -------------------
            Total Stockholders' Investment and Liabilities        $ 564,867,125           $641,086,004
                                                             ===================    ===================
</TABLE>

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


                                       15
<PAGE>



                          BANGOR HYDRO-ELECTRIC COMPANY
                    CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                  December 31,

<TABLE>
<CAPTION>
                                                                                                      2003                    2002
                                                                                      ---------------------     -------------------

<S>                                                                                        <C>                     <C>
Common Stock Investment (Notes 1 and 3)
     Common stock, no par value, stated value  $5 per share-                                $   36,817,120          $   36,817,120
          Authorized - 10,000,000 shares
          Outstanding - 7,363,424 shares
     Amounts paid in excess of par value                                                       155,352,312             165,352,312
     Accumulated other comprehensive loss (Note 5)                                              (5,093,684)             (2,033,534)
     Retained earnings                                                                           5,810,329               6,130,251
                                                                                      ---------------------     -------------------
          Total common stock investment                                                    $   192,886,077         $   206,266,149
                                                                                      ---------------------     -------------------
Preferred Stock, Non-participating, cumulative, par value $100 per share,
     Authorized 600,000 shares (Note 3):
          Not redeemable or redeemable solely at the option of the issuer-
               7%, Noncallable, Authorized - 25,000 shares                                   $     627,700          $    2,500,000
                    Outstanding - 6,277 shares in 2003 and 25,000 shares in 2002
               4.25%, Callable at $100, Authorized - 4,840 shares                                        -                 484,000
                    Outstanding - 4,840 shares in 2002
               4%, Series A, Callable at $110, Authorized - 17,500 shares                                -               1,750,000
                    Outstanding - 17,500 shares in 2002
                                                                                      ---------------------     -------------------
                                                                                             $     627,700          $    4,734,000
                                                                                      ---------------------     -------------------
Long-Term Debt (Notes 4 and 8)
     First Mortgage Bonds-
         10.25%  Series due 2020                                                            $   30,000,000          $   30,000,000
          8.98%  Series due 2022                                                                20,000,000              20,000,000
          7.30%  Series due 2003                                                                         -              15,000,000
                                                                                      ---------------------     -------------------
                                                                                            $   50,000,000          $   65,000,000
                                                                                      ---------------------     -------------------
     Other Long-Term Debt-
         Finance Authority of Maine - Taxable Electric Rate
              Stabilization Revenue Notes, 7.03% Series 1995A, due 2005                     $   38,200,000          $   55,400,000
         Municipal Review Committee Note, 5%, due 2008                                           9,847,470              11,780,660
         Senior unsecured note, 6.09%, due 2012                                                 20,000,000              20,000,000
         Senior unsecured notes, 5.31%, due 2018                                                50,000,000                       -
         Other miscellaneous notes payable, 3.90%, due 2006                                         11,152                  15,318
                                                                                      ---------------------     -------------------
                                                                                           $   118,058,622          $   87,195,978
              Less:  Current portion of long-term debt                                          20,314,357              34,137,342
                                                                                      ---------------------     -------------------
                                                                                            $   97,744,265          $   53,058,636
                                                                                      ---------------------     -------------------
              Total Long-Term Debt                                                         $   147,744,265         $   118,058,636
                                                                                      ---------------------     -------------------
                   Total Capitalization                                                    $   341,258,042         $   329,058,785
                                                                                      =====================     ===================
</TABLE>


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


                                       16
<PAGE>

                          BANGOR HYDRO-ELECTRIC COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                        For the years ended December 31,

<TABLE>
<CAPTION>
                                                                                                   2003                     2002
                                                                                      ------------------     --------------------

Cash Flows From Operating Activities:
<S>                                                                                       <C>                      <C>
  Net income                                                                              $  14,438,740            $  12,461,302
    Adjustments to reconcile net income to net cash from operating activities:
           Depreciation and amortization                                                      9,589,649               10,549,148
           Amortization of Seabrook nuclear project (Note 7)                                  1,699,050                1,699,050
           Amortization of contract buyouts and restructuring (Note 6)                       16,828,947               20,274,191
           Amortization of deferred asset sale gain (Note 9)                                 (9,030,600)             (4,681,324)
           Other amortizations                                                                  502,961              (3,330,048)

           Allowance for equity funds used during construction (Note 1)                        (277,877)               (497,920)
           Deferred income tax provision and amortization of investment
               tax credits (Note 2)                                                           9,631,913                1,625,652
    Changes in assets and liabilities:
           Costs to restructure purchased power contract (Note 6)                                     -                (750,000)
           Deferred standard-offer service costs (Note 9)                                       (17,698)             (2,138,380)
           Deferred special rate contract revenues (Note 9)                                     683,548                (115,711)
           Employee transition costs (Note 9)                                                (2,101,929)             (3,535,097)
           Accounts receivable, net and unbilled revenue                                      2,187,391                5,302,486
           Accounts payable                                                                   1,263,986              (3,759,662)
           Accrued interest                                                                   1,349,075                (570,617)
           Current income taxes                                                                (631,881)             (2,271,900)
           Accrued pension and postretirement benefit costs (Note 5)                          2,803,367                4,294,357
           Other current assets and liabilities, net                                            308,362                  458,802
           Other, net                                                                        (3,589,598)             (1,611,811)
                                                                                      ------------------     --------------------
Net Increase in Cash From Operating Activities:                                           $  45,637,406            $  33,402,518
                                                                                      ------------------     --------------------
Cash Flows From Investing Activities:
     Construction expenditures                                                            $ (19,201,115)          $ (10,094,378)
     Proceeds from redemption of Maine Yankee common stock                                      734,614                  525,388
     Allowance for borrowed funds used during construction (Note 1)                            (220,628)               (446,083)
                                                                                      --------------------   ---------------------
Net Decrease in Cash From Investing Activities                                            $ (18,687,129)          $ (10,015,073)
                                                                                      --------------------   ---------------------
Cash Flows From Financing Activities:
     Dividends on preferred stock                                                          $   (135,701)           $   (265,570)
     Dividends on common stock                                                              (24,135,533)             (9,500,000)
     Redemption of preferred stock                                                           (4,648,485)                       -
     Payments on long-term debt (Note 4)                                                    (34,137,356)            (43,017,740)
     Capital reserve funds used in repayment on long-term debt                                        -                1,500,000
     Proceeds from issuance of long-term debt (Note 4)                                       50,000,000               20,000,000
     Short-term debt, net (Note 4)                                                          (12,000,000)               8,000,000
                                                                                      --------------------   ---------------------
Net Decrease in Cash From Financing Activities                                            $ (25,057,075)          $ (23,283,310)
                                                                                      --------------------   ---------------------
Net Increase in Cash and Cash Equivalents                                                 $   1,893,202             $    104,135
Cash and Cash Equivalents at Beginning of Year                                                  988,752                  884,617
                                                                                      ------------------     --------------------
Cash and Cash Equivalents at End of Year                                                  $   2,881,954             $    988,752
                                                                                       =================     ====================
</TABLE>

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


                                       17
<PAGE>

                          BANGOR HYDRO-ELECTRIC COMPANY
               CONSOLIDATED STATEMENTS OF COMMON STOCK INVESTMENT


<TABLE>
<CAPTION>
                                                                                                  Accumulated
                                                               Amounts Paid                             Other          Total Common
                                                    Common     in Excess of       Retained      Comprehensive                 Stock
                                                     Stock        Par Value        Earnings              Loss            Investment
                                             --------------  ---------------   --------------  -----------------  -----------------

<S>                                           <C>             <C>                <C>              <C>                <C>
Balance December 31, 2001                     $ 36,817,120    $ 165,352,312      $ 3,434,519      $  (47,278)        $205,556,673

Net income                                               -                -       12,461,302                -          12,461,302
Other comprehensive loss net of taxes:

     Unrealized gain on interest rate swap               -                -                -          47,278               47,278

     Minimum pension liability (Note 5)                  -                -                -      (2,033,534)         (2,033,534)
                                                                                                                ------------------
         Total comprehensive income                                                                                    10,475,046
                                                                                                                ------------------
Cash dividends declared on-

     Preferred stock                                     -                -        (265,570)               -            (265,570)

     Common stock                                        -                -      (9,500,000)               -          (9,500,000)
                                             --------------  ---------------   --------------  ---------------- ------------------
Balance December 31, 2002                     $ 36,817,120    $ 165,352,312      $ 6,130,251     $(2,033,534)        $206,266,149

Net income                                               -                -       14,438,740                           14,438,740
Other comprehensive loss net of taxes:

     Minimum pension liability (Note 5)                  -                -                -      (3,060,150)         (3,060,150)
                                                                                                                ------------------
         Total comprehensive income                                                                                    11,378,590
                                                                                                                ------------------
Loss on redemption of preferred stock                    -                -        (542,185)               -            (542,185)
Cash dividends declared on-

     Preferred stock                                     -                -         (80,944)               -             (80,944)

     Common stock (Note 3)                               -      (10,000,000)    (14,135,533)               -         (24,135,533)
                                             --------------  ---------------   --------------  ---------------- ------------------
Balance December 31, 2003                      $36,817,120    $ 155,352,312      $ 5,810,329     $(5,093,684)        $192,886,077
                                             --------------  ---------------   --------------  ---------------- ------------------
</TABLE>


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


                                       18
<PAGE>



Note 1.  Nature of Operations and Summary of Significant Accounting Policies

     Nature of Operations - Bangor Hydro-Electric Company (the Company) is a
     wholly-owned subsidiary of Emera, Inc. (Emera) and is a public utility
     engaged in the transmission and distribution of electric energy and other
     energy related services, with a service area of approximately 5,275 square
     miles having a population of approximately 190,000 people. The Company
     serves approximately 107,000 customers in portions of the Maine counties of
     Penobscot, Hancock, Washington, Waldo, Piscataquis, and Aroostook. The
     Company's regulated operations are subject to the regulatory authority of
     the Maine Public Utilities Commission (MPUC) as to retail rates,
     accounting, service standards, territory served, the issuance of securities
     and other matters. The Company is also subject to the jurisdiction of the
     Federal Energy Regulatory Commission (FERC) as to certain matters,
     including rates for transmission services. The Company is a member of the
     New England Power Pool (NEPOOL), and is interconnected with other New
     England utilities to the south and with New Brunswick Power Corporation to
     the north.

     Basis of Consolidation - The Consolidated Financial Statements of the
     Company include its wholly- owned subsidiaries, Bangor Var Co., Inc. (BVC),
     Bangor Energy Resale, Inc. (BERI), CareTaker, Inc. (CareTaker), Bangor
     Fiber Co., Inc. (Bangor Fiber), and Bangor Line Co., Inc. (Bangor Line).
     BERI was formed in 1997 as a special purpose vehicle to permit Bangor
     Hydro's use of a power sales agreement as collateral for a bank loan.
     CareTaker was incorporated in 1997 and provides security alarm services on
     a retail basis to residential and commercial customers. Bangor Fiber was
     formed in 2000 to supply fiber optic communications cable to communications
     companies and cable service providers and other related activities. Bangor
     Line was formed in 2001 to provide engineering, permitting and design,
     geographic information system and construction services to third parties.
     See Note 6 for additional information with respect to BVC. All significant
     intercompany balances and transactions have been eliminated. The accounts
     of the Company are maintained in accordance with the Uniform System of
     Accounts prescribed by the regulatory bodies having jurisdiction.

     Equity Method of Accounting - The Company accounts for its investments in
     the common stock of Maine Yankee Atomic Power Company (Maine Yankee) and
     Maine Electric Power Company, Inc. (MEPCO) under the equity method of
     accounting, and records its proportionate share of the net earnings of
     these companies as a reduction of fuel for generation and purchased power
     expense. See Note 6 for additional information with respect to these
     investments.

     Electric Operating Revenue - Electric Operating Revenue, including that
     associated with standard offer service (See Note 9) consists primarily of
     amounts charged for electricity delivered to customers during the period.
     The Company records unbilled revenue, based on estimates of electric
     service rendered and not billed at the end of an accounting period, in
     order to match revenue with related costs. As of March 1, 2000, the Company
     bills customers for the energy supplied by competitive energy providers
     (See Note 9). Competitive energy providers are paid only after the funds
     are collected from customers. The Company records accounts receivable for
     the amounts billed to competitive energy customers and a corresponding
     accounts payable for the amounts due to the energy supplier. No revenue is
     recognized as the Company is acting as an agent. Also, effective March 1,
     2002, as a result of new bids received from competitive energy providers,
     the Company is no longer serving as the standard offer service provider.
     The Company is, though, serving as the billing and collection agent under
     the standard offer program.

     Depreciation of Electric Plant and Maintenance Policy- Depreciation of
     electric plant is provided using the straight-line method at rates designed
     to allocate the original cost of properties over their estimated service
     lives. The composite depreciation rate (excluding intangible assets)
     expressed, as a percentage of average depreciable plant in service, was
     approximately 2.5% in 2003 and 2.9% in 2002.


                                       19
<PAGE>

Note 1. Nature of Operations and Summary of Significant Accounting Policies,
Continued:

     The Company follows the practice of charging to maintenance the cost of
     repairs, replacements and renewals of minor items considered to be less
     than a unit of property. Costs of additions, replacements and renewals of
     items considered to be units of property are charged to the utility plant
     accounts, and any items retired are removed from such accounts. The
     original costs of units of property retired and removal costs, less
     salvage, are charged to the depreciation reserve.

     Depreciation, local property taxes and other taxes not based on income,
     which were charged to operating expenses, are stated separately in the
     Consolidated Statements of Income. Rents, advertising and research and
     development expenses are not significant. No royalty expenses were
     incurred.

     Maintenance expense was $7.3 million in 2003 and $7.8 million in 2002.

     Goodwill -In connection with the acquisition of the Company's common stock
     by Emera in October 2001, the excess of the cost over the fair value of the
     net assets of the Company has been recorded as goodwill on the Company's
     consolidated balance sheet. In accordance with the implementation of
     Statement of Financial Accounting Standards No. 141, "Business
     Combinations", goodwill is no longer amortized but instead is subject to an
     impairment test at least annually in accordance with the provisions of
     Statement of Financial Accounting Standards No. 142, "Goodwill and Other
     Intangible Assets". Goodwill associated with the Emera acquisition was not
     adjusted for any impairment losses in 2003 or 2002.

     Allowance for Funds Used During Construction (AFDC) - In accordance with
     regulatory requirements of the MPUC, the Company capitalizes as AFDC
     financing costs related to portions of its construction work in progress,
     at a rate equal to its weighted cost of capital, into utility plant with
     offsetting credits to other income and interest. This cost is not an item
     of current cash income, but is recovered over the service life of plant in
     the form of increased revenue collected as a result of higher depreciation
     expense and return. In addition, carrying costs on certain regulatory
     assets and liabilities, including the deferred asset sale gain (see Note
     9), were also capitalized and included in AFDC in the Consolidated
     Statements of Income. The average AFDC (carrying costs) rates computed by
     the Company were 8.6% in 2003 and 8.8% for 2002.

     Cash and Cash Equivalents - The Company considers all highly liquid debt
     instruments purchased with an original maturity of three months or less to
     be cash equivalents.

     Use of Estimates - The preparation of financial statements in conformity
     with generally accepted accounting principles requires management to make
     estimates and assumptions that affect the reported amounts of assets and
     liabilities and disclosure of contingent liabilities at the date of the
     Consolidated Financial Statements and the reported amounts of revenues and
     expenses during the reporting period. Actual results could differ from
     those estimates.

     Supplemental Disclosure of Cash Flow Information - Cash paid for interest,
     net of amounts capitalized was approximately $9.8 million in 2003 and $12.6
     million in 2002. Cash paid for income taxes was approximately $8.2 million
     in 2003 and $9.6 million in 2002.

     Risk Management and Derivative Financial Instruments - The Company's major
     financial market risk exposure is changing interest rates. Changing
     interest rates will affect interest paid on variable rate debt and the fair
     value of fixed rate debt. The Company manages interest rate risk through a
     combination of both fixed and variable rate debt instruments. The Company
     did not hold any derivative financial instruments at December 31, 2003.

     In December 2003 the Company entered into a weather insurance contract for
     the 2003-2004 heating season. This insurance is designed to protect against
     the negative impacts of warmer than normal weather on the Company's
     electric operating revenues. No income was recognized in 2003 associated
     with this insurance policy, as any claims payout will only occur at the end
     of the contract depending on the weather results for the full term of the
     insurance policy. In November 2002, the Company


                                       20
<PAGE>

Note 1.  Nature of Operations and Summary of Significant Accounting Policies,
Continued:

     purchased a weather hedge for the 2002-2003 heating season, similarly
     designed to protect against the impacts of warm weather. No income was
     recognized for this weather hedge in 2003 or 2002 due to the colder than
     normal weather. The costs of the weather insurance policy and the hedge are
     amortized over the associated heating seasons. See Note 11.

     Reclassifications-Certain prior year amounts have been reclassified to
     conform to the presentation used in the 2003 Consolidated Financial
     Statements.


Note 2.  Income Taxes

     In accordance with Statement of Financial Accounting Standards No. 109
     "Accounting for Income Taxes" (FAS 109), the Company recorded cumulative
     net additional deferred income tax liabilities of approximately $11 million
     as of December 31, 2003 and $10.5 million as of December 31, 2002. These
     additional deferred income tax liabilities have resulted from the accrual
     of deferred taxes on temporary differences on which deferred taxes had not
     been previously accrued ($15.9 million and $15.7 million as of December 31,
     2003 and 2002, respectively), offset by the effect of the 1987 change to
     lower income tax rates (reduced by the 1% increase in the federal income
     tax rate in 1993) that will be refunded to customers over time ($4.3
     million and $4.5 million as of December 31, 2003 and 2002, respectively),
     and the establishment of deferred tax assets on unamortized investment tax
     credits ($644,000 and $701,000 as of December 31, 2003 and 2002,
     respectively). These latter amounts have been recorded in Other Regulatory
     Liabilities at December 31, 2003 and 2002. The accrual of the additional
     amount of deferred tax liabilities have been offset by regulatory assets
     which represent the customers' future payment of these income taxes when
     the taxes are, in fact, expensed. As a result of this accounting, the
     Consolidated Statements of Income are not affected by the implementation of
     FAS 109. The rate-making practices followed by the MPUC permit the Company
     to recover federal and state income taxes payable currently, and to recover
     some, but not all, deferred taxes that would otherwise be recorded in
     accordance with FAS 109 in the absence of regulatory accounting.

     The individual components of other accumulated deferred income taxes are as
     follows at December 31, 2003 and 2002:

<TABLE>
<CAPTION>
                                                                        2003               2002
                                                                   ---------------     -------------
     Deferred Income Tax Liabilities:
<S>                                                              <C>                 <C>
        Excess book over tax basis of electric plant in service  $     55,265,213    $   42,237,261
        Costs to terminate/restructure purchased power contracts       12,678,730        18,877,652
        Other regulatory assets                                         5,849,527         4,177,045
        Investment in jointly-owned companies                           1,032,150         1,676,838
        Other                                                               7,823            93,100
                                                                 -----------------  ----------------
                                                                 $     74,833,443    $   67,061,896
                                                                 -----------------  ----------------

     Deferred Income Tax Assets:
        Accrued pension and postretirement benefit costs         $      8,164,417    $    7,486,547
        Other regulatory liabilities                                    2,186,241         2,312,651
        Deferred asset sale gain                                          697,156         4,255,984
        Other                                                           5,883,190         4,059,274
                                                                 -----------------  ----------------
                                                                 $     16,931,004    $   18,114,456
                                                                 -----------------  ----------------
     Total other accumulated deferred income taxes               $     57,902,439    $   48,947,440
                                                                 =================  ================
</TABLE>


                                       21
<PAGE>

Note 2.  Income Taxes, Continued:

     The individual components of federal and state income taxes reflected in
     the Consolidated Statements of Income for 2003 and 2002 are stated in the
     table below.

                     Year Ended December 31,       2003              2002
     ---------------------------------------------------------------------------

     Current Income Tax Provision                 $ (419,393)       $ 5,481,256
     Deferred Income Tax Provision                  9,727,330         1,751,984
     Investment Tax Credits, Net                     (95,417)          (126,332)
                                               ---------------  ----------------
        Total Provision                           $ 9,212,520       $ 7,106,908
     Less Allocated to Other Income                 1,034,450           553,806
                                               ---------------  ----------------
     Charged to Operating Expense                 $ 8,178,070       $ 6,553,102
                                               ---------------  ----------------

     The Company's effective tax rate differed from the statutory
     rate of 35% due to the following:

<TABLE>
<CAPTION>
                                                                                 2003                           2002
                                                                      --------------------------------------------------------------
                                                                                          (Dollars in Thousands)
                                                                         Amount             %            Amount            %
                                                                      --------------------------------------------------------------

<S>                                                                         <C>             <C>              <C>           <C>
     Federal income tax provision at statutory rate                         $ 8,278         35.0 %           $6,849        35.0 %
     Plus (Less) permanent differences in tax expense
        resulting from statutory exclusions from taxable
        income:
        Asset sale gain permanent differences                                   372          1.6                201         1.0
        Amortization of equity component of AFDC
           on recoverable Seabrook investment                                   160           .7                160          .8
        Other                                                                  (579)        (2.5)              (468)        (2.3)
                                                                      --------------------------------------------------------------

     Federal income tax provision before effect of
        Timing differences                                                  $ 8,231         34.8 %           $6,742        34.5 %
     Plus (Less) timing differences that are flowed
        through for rate-making and accounting purposes:
           Amortization of debt component of AFDC and
              capitalized overheads on recoverable Seabrook
              Investment                                                        151           .6                151          .7
           State income tax liability deducted for federal
              income tax purposes                                              (755)        (3.2)              (591)       (3.0)
           Reversal of excess deferred income taxes                            (225)         (.9)              (319)       (1.6)
           Amortization of investment tax credits                               (95)         (.4)              (126)        (.6)
           Other                                                                819          3.5                 18          .0
                                                                      --------------------------------------------------------------
        Federal income tax provision                                        $ 8,126         34.4 %           $5,875        30.0 %
                                                                      ==============================================================
</TABLE>

     In December 2002, the Company filed with the Internal Revenue Service (IRS)
     a request for a change in the accounting for costs capitalized for income
     tax reporting purposes, resulting in an approximately $6.6 million
     reduction in current income tax obligations. While the IRS has not accepted
     the Company's request, based on recommendations from the Company's tax
     advisors, this deduction was


                                       22
<PAGE>

Note 2. Income Taxes, Continued:

     included in the filing of the Company's 2002 federal and state income tax
     returns, and the resulting income tax refunds were received in 2003. As a
     result of regulatory accounting for state income taxes, this deduction
     resulted in an approximately $650,000 reduction in income tax expense in
     2003.


Note 3.  Common and Preferred Stock

     Common Stock - In connection with the Company's merger with Emera on
     October 10, 2001, Emera owns all of the Company's outstanding common
     shares. The common stock has general voting rights of one vote per twelve
     shares owned. In December 2003, the Company made a $10 million distribution
     to Emera, payable from pre-acquisition retained earnings. In connection
     with the merger accounting in 2001, the Company's retained earnings balance
     as of the acquisition date was reclassified as a component of additional
     paid-in capital.

     Preferred Stock - Authorized but unissued shares of 593,723 (plus
     additional shares equal in number to such presently outstanding shares as
     may be retired) may be issued with such preferences, restrictions or
     qualifications as the board of directors may determine. Any new shares so
     issued will be required to be issued with per share voting rights no
     greater than that of the common stock. The callable preferred stock may be
     called in whole or in part upon any dividend date by appropriate resolution
     of the board of directors. The currently outstanding preferred stock has
     general voting rights of one vote per share. With regard to payment of
     dividends or assets available in the event of liquidation, preferred stock
     ranks prior to common stock.

     As discussed in the 2002 Form 10-K, in the first quarter of 2003, the
     Company completed the redemption of a significant portion of its
     outstanding preferred stock, at a total cost of $4.6 million. As a result
     of the decrease in preferred shareholders, the Company filed with the
     Securities and Exchange Commission for de-registration of its preferred
     stock.


Note 4.  Lending Agreements

     In connection with financing the costs of the purchased power contract
     buyback accomplished in June 1995 (see Note 6), the Company entered into a
     Loan Agreement with the Finance Authority of Maine (FAME), a body corporate
     and politic and public instrumentality of the state of Maine. Pursuant to
     authorizing legislation in Maine, FAME issued $126 million of notes through
     a private placement, the repayment of which is the responsibility of the
     Company under the terms of the Loan Agreement. Of that amount,
     approximately $105 million was made available to the Company to finance a
     portion of the buyback and approximately $21 million was set aside in a
     capital reserve fund. The notes bear interest at an annual rate of 7.03%,
     mature on July 1, 2005 and are subject to a schedule of annual principal
     payments, which began on July 1, 1998. The amount held in the capital
     reserve fund will be used to pay the final installment of principal and
     interest due in 2005. The assets in the capital reserve fund are held by a
     third party trustee and invested in a guaranteed investment contract,
     earning interest at an annual rate of 6.51%. The interest earnings are
     utilized to offset the semiannual interest payments on the FAME notes.

     In order to secure the FAME notes, the Company executed a General and
     Refunding Mortgage Indenture and Deed of Trust establishing a lien on the
     Company's property junior to the lien under the Company's First Mortgage
     Bonds Indenture. The Company may not issue any additional First Mortgage
     Bonds in the future. The Company issued bonds to FAME under the new
     mortgage in the amount of $126 million. Under the provisions of the first
     mortgage bond indenture, substantially all of the Company's plant and
     property have been mortgaged to secure the Company's first mortgage bonds.


                                       23
<PAGE>

Note 4.  Lending Agreements, Continued:

     On October 10, 2001, the Company issued an unsecured promissory note to the
     MRC for the amount of $13,667,550 (MRC Promissory Note). The Company and
     the MRC agreed to terms and conditions of the MRC Promissory Note under
     which the Company shall make a series of cash payments to the MRC upon the
     exercise of warrants on the closing of the merger with Emera, Inc. The MRC
     Promissory Note has a term of seven years, a fixed interest rate of 5%, and
     payments of interest and principal on a quarterly basis. The MRC has the
     right to defer some or all of any of the quarterly payments within the same
     Note Year (August 1 to July 31), upon at least a 14 days' prior written
     notice to the Company.

     On December 20, 2002, the Company received proceeds from the private
     placement issuance of a $20 million senior unsecured note. The note has a
     term of ten years, a fixed interest rate of 6.09% and payments of interest
     on a semiannual basis. The $20 million principal borrowing is to be paid at
     maturity.

     On August 7, 2003, the Company received proceeds from the private placement
     issuance of $30 million in senior unsecured notes. The notes have a term of
     15 years, a fixed interest rate of 5.31% and payments of interest on a
     semiannual basis. Sinking fund payment requirements begin in year five. On
     December 12, 2003, the Company received $20 million in proceeds from an
     additional issuance of senior unsecured notes under this same private
     placement. The notes have a term of 15 years, with interest payable
     semiannually at a fixed interest rate of 5.31%. The notes were issued at a
     discount, resulting in an effective interest rate of 5.76%. The discount of
     approximately $652,000 has been deferred, and is being amortized over the
     life of the debt.

     Current maturities of the first mortgage bonds and other long-term debt for
     the five years subsequent to December 31, 2003, amounting to $52,604,087,
     are $20,314,371 in 2004, $21,830,717 in 2005, $2,318,968 in 2006,
     $2,637,837 in 2007, and $5,502,194 in 2008.

     On June 29, 1998, the Company entered into an Amended and Restated
     Revolving Credit and Term Loan Agreement with a new group of lenders that
     provided a two-year term loan of $45 million and a three-year revolving
     credit commitment of $30 million. The amended credit agreement is secured
     by $82.5 million of non-interest bearing First Mortgage Bonds. The term
     loan was fully repaid in May of 1999, and the First Mortgage Bonds have
     expired.

     On June 29, 2001, the Company extended the revolving credit agreement until
     October 1 and then until March 31, 2002, and the agreement was further
     extended until June 30, 2003 with some modifications. The facility was
     increased to $60 million to accommodate certain debt retirements in 2002;
     another pricing level was added to recognize the Company's improved credit
     and certain modifications were made to some of the financial covenants. The
     revolving credit facility expired at the end of June 2003, but the
     agreement was extended again, while the parties negotiated a new revolving
     credit agreement. On August 27, 2003, the Company entered into an Amended
     and Restated Revolving Credit Agreement (the Agreement) with the bank
     group. This Agreement expires at the end of June 2004. The terms of this
     Agreement are similar to the prior revolving credit agreement, although
     interest pricing is now tied to the achievement of certain financial
     covenants as opposed to the prior pricing based on the level of financial
     credit ratings.

     By the terms of the credit agreement, the Company may borrow, at its
     option, and at rates as defined in the agreement, based either on the
     London Interbank Offered (LIBO) rate, or the agent bank's defined base
     rate. The applicable risk premium, based on the Company's pricing ratios as
     defined in the agreement, is added to the core interest rate, which results
     in the total combined interest rate for borrowing under the agreement. An
     unused commitment fee, based on the Company's available revolving credit
     commitment, is also priced according to the Company's pricing ratios.

     On June 29, 2001, the Company, as permitted under the Amended and Restated
     Credit and Term Loan


                                       24
<PAGE>

Note 4.  Lending Agreements, Continued:

     Agreement, entered into a Promissory Note with a financial institution that
     allows the Company to borrow up to an additional $10 million. This
     unsecured facility is used by the Company to manage working capital needs,
     and the interest rate setting mechanism and other major terms of the Note
     are similar to terms in the Amended and Restated Credit and Term Loan
     Agreement. The original facility expired on October 1, 2001, but has also
     subsequently been extended to June 30, 2003. As with the revolving credit
     facility, this agreement was amended when, on August 27, 2003, the Company
     entered into the previously discussed Agreement with the bank group.

     In connection with debt agreements the Company must comply with certain
     financial covenants related to the Company's debt ratio, fixed charge
     coverage, net worth, and limitation on the payment of common dividends. The
     Company complied with all covenants associated with its lending agreements
     in 2003 and 2002.

     As a result of limitations imposed by the Securities and Exchange
     Commission (SEC) in connection with Emera's Public Utility Holding Company
     Act filings with the SEC, the Company's maximum short-term borrowings
     outstanding at any time are limited to $60 million.

     Certain information related to the Company's short-term credit facilities
     is as follows:

<TABLE>
<CAPTION>
                                                                             2003             2002
                                                                        ---------------   -------------
<S>                                                                       <C>             <C>
     Total short-term borrowings available under credit agreements
        at end of period                                                  $ 70,000,000    $ 70,000,000
                                                                        -------------------------------
     SEC limitation on maximum short-term borrowings                      $ 60,000,000    $ 60,000,000
     Letter of credit outstanding securing obligations under
        supplemental pension plan (See Note 5)                               3,500,000       3,500,000
     Borrowings outstanding at end of period                                 4,000,000      16,000,000
                                                                        -------------------------------
     Maximum borrowing capacity available at end of period                $ 52,500,000    $ 50,500,000
                                                                        -------------------------------

     Effective interest rate (exclusive of fees) on borrowings                     1.9%            2.4%
        outstanding at end of period
                                                                                                     $
     Average daily outstanding borrowings for the period                  $ 22,843,836    $ 21,782,192
     Weighted daily average annual interest rate (exclusive of fees)               2.2%            2.8%
     Highest level of borrowings outstanding at any month-end
        during the period                                                 $ 55,000,000      45,000,000
</TABLE>


Note 5.  Postretirement Benefits

     The Company has a noncontributory pension plan covering substantially all
     of its employees. Benefits under the plan are generally based on the
     employee's years of service and compensation during the years preceding
     retirement. The Company's general policy is to contribute to the funds the
     amounts deductible for federal income tax purposes. The Company also has an
     unfunded noncontributory supplemental non-qualified pension plan that
     provides additional retirement benefits to certain former senior
     executives.

     The Company made a $1.9 million cash contribution to the noncontributory
     pension plan in 2003, while in 2002, no employer contributions were made.
     The plan's assets are composed of fixed income securities, equity
     securities and cash equivalents. In 2002, as a result of a corporate
     restructuring, the Company implemented an early retirement program that
     provided for enhanced pension benefits for the early retirees.


                                       25
<PAGE>

Note 5. Postretirement Benefits, Continued:

     The following tables detail the funded status of the plan, the amounts
     recognized in the Company's Consolidated Financial Statements, the
     components of pension expense for 2003 and 2002 and the major assumptions
     used to determine these amounts (includes both the funded and unfunded
     plans).

     Total pension expense included the following components:

<TABLE>
<CAPTION>
                                                                   2003              2002
                                                             -----------------------------------
<S>                                                                <C>               <C>
     Service cost-benefits earned during the period                $ 1,100,311       $  916,726
     Interest cost on projected benefit obligation                   3,977,852        3,920,015
     Expected return on plan assets                                (3,642,787)       (3,925,587)
     Amortization of unrecognized prior service cost                   224,943         (420,266)
     Amortization of unrecognized net loss (gain)                        4,919         (148,377)
                                                             -----------------------------------
        Total pension expense                                      $ 1,655,238       $  342,511
                                                             ===================================
</TABLE>

     The following table sets forth the plans' funded status at December 31,
     2003 and 2002:

<TABLE>
<CAPTION>
                                                                   2003              2002
                                                             -----------------------------------
<S>                                                                <C>             <C>
     Change in Projected Benefit Obligation
        Balance as of December 31, 2002 and 2001                   $60,768,187     $ 53,382,582
        Service cost                                                 1,100,311          916,726
        Interest cost                                                3,977,852        3,920,015
        Benefits paid                                               (3,829,519)      (3,396,922)
        Amendments                                                           -        2,054,108
        Losses                                                      10,139,999        2,278,722
        Other-Special termination charge                                     -        1,612,956
                                                             -----------------------------------
        Balance as of December 31, 2003 and 2002                   $72,156,830     $ 60,768,187
                                                             -----------------------------------

     Change in Plan Assets
        Balance as of December 31, 2002 and 2001                  $ 34,463,933     $ 41,430,955
        Employer contributions                                       2,072,130          130,441
        Benefits paid                                               (3,829,519)      (3,396,922)
        Actual return, less expenses                                 7,403,170       (3,700,541)
                                                             -----------------------------------
        Balance as of December 31, 2003 and 2002                  $ 40,109,714     $ 34,463,933
                                                                -----------------------------------

        Funded status                                             $(32,047,116)    $(26,304,254)
        Unrecognized prior service cost                              2,249,431        2,474,374
        Unrecognized loss                                           15,247,157        8,872,460
                                                             ------------------------------------
        Accrued pension at December 31, 2003 and 2002             $(14,550,528)    $(14,957,420)
                                                             ------------------------------------

     Amounts recognized in the statement of financial
        Position consist of:
           Accrued benefit liability                              $(25,404,155)    $(20,866,817)
           Intangible asset                                          2,249,431        2,474,374
           Accumulated other comprehensive income                    8,604,196        3,435,023
                                                             ------------------------------------
           Net amount recognized                                  $(14,550,528)    $(14,957,420)
                                                             ------------------------------------
</TABLE>


                                       26
<PAGE>

Note 5.  Postretirement Benefits, Continued:

     The discount rate and rate of increase in future compensation levels used
     to determine pension obligations, effective January 1, 2004, are 6.25% and
     4%, respectively, and were used to calculate the plans' funded status at
     December 31, 2003. Significant assumptions used to determine the pension
     expense for each year were as follows:

                                                            2003          2002
                                                         ----------   ---------
     Discount rate                                          6.75 %       7.25 %
     Rate of increase in future compensation levels          4.0 %        4.0 %
     Expected long-term rate of return on plan assets        8.0 %        8.0 %

     The provisions of Financial Accounting Standards Board Statement No. 87,
     "Employers' Accounting for Pensions", requires the Company to record an
     additional minimum liability of $10,853,627 and $5,909,397 at December 31,
     2003 and 2002, respectively. This liability represents the amount by which
     the accumulated benefit obligation exceeds the sum of the fair market value
     of plan assets and accrued amounts previously recorded. The additional
     liability may be offset by an intangible asset to the extent of previously
     unrecognized prior service cost. The intangible asset of $2,249,431 and
     $2,474,374 at December 31, 2003 and 2002, respectively, is included in
     Other Deferred Charges on the Consolidated Balance Sheets. The remaining
     amounts of $8,604,196 and $3,435,023 are recorded as a component of
     stockholders' equity, net of related tax benefits of $3,510,512 and
     $1,401,489, are included in Accumulated Other Comprehensive Loss on the
     Consolidated Statement of Common Stock Investment at December 31, 2003 and
     2002, respectively.

     As a result of regulatory accounting as approved in the Company's
     Alternative Rate Plan (See Note 9), the Company deferred $1,612,956, as a
     regulatory asset, related to this special termination charge. As a result
     of this accounting, the pension expense for 2002 was unaffected, while the
     pension liability was increased at December 31, 2002.

     In 2001, as a result of purchase accounting, all unrecognized actuarial
     gains and losses, prior service cost and the net transition asset were
     eliminated as of the merger with Emera. As a result of regulatory
     accounting, a regulatory asset of $10.4 million, equal to these
     unrecognized amounts, was established at the merger date. The Company is
     amortizing this balance over the same period at which the corresponding
     gains and losses were being amortized when they were a component of pension
     expense. Amortization expense amounted to $1,182,155 in 2003 and $1,214,065
     in 2002.

     The accumulated benefit obligation for the unfunded supplemental pension
     plan with accumulated benefit obligations in excess of plan assets was
     $2,600,315 and $2,501,699 as of December 31, 2003 and 2002, respectively.
     The Company maintains a $3.5 million letter of credit to secure obligations
     under this unfunded supplemental pension plan.

     In addition to pension benefits, the Company provides certain health care
     and life insurance benefits to its retired employees. Substantially all of
     the Company's employees may become eligible for retiree benefits if they
     reach normal retirement age while working for the Company.

     The Company maintains an irrevocable external Voluntary Employee Benefit
     Association Trust Fund (VEBA) to fund the payment of postretirement medical
     and life insurance benefits. Company contributions to the VEBA amounted to
     approximately $1.7 million in 2003 and $864,000 in 2002. The VEBA's assets
     are composed of United States Treasury money market funds. The Company's
     general policy is to contribute to the VEBA amounts necessary to fund
     claims and administrative costs.

     The actuarially determined net periodic postretirement benefit cost for
     2003 and 2002 and the major assumptions used to determine these amounts are
     shown in the following tables:


                                       27
<PAGE>

Note 5.  Postretirement Benefits, Continued:

<TABLE>
<CAPTION>
                                                                   2003              2002
                                                             -----------------------------------
<S>                                                                  <C>              <C>
     Service cost of benefits earned                                 $ 698,490        $ 583,496
     Interest cost on accumulated postretirement
        benefit obligation                                           1,924,782        2,043,548
     Expected return on plan assets                                   (25,000)          (25,000)
                                                             -----------------------------------
     Net periodic postretirement benefit cost                       $2,598,272       $2,602,044
                                                             ===================================
</TABLE>

     The following table sets forth the benefit plan's funded
     status at December 31, 2003 and 2002.

<TABLE>
<CAPTION>
                                                                   2003              2002
                                                             -----------------------------------
<S>                                                               <C>              <C>
     Change in Accumulated Postretirement Benefit Obligation
        Balance as of December 31, 2002 and 2001                  $ 31,961,402     $ 27,488,444
        Service cost                                                   698,490          583,496
        Interest Cost                                                1,924,782        2,043,548
        Claims paid                                                (1,814,366)       (1,053,187)
        Gain and losses                                            (3,446,941)        1,532,744
        Other-Special termination charge                                     -        1,366,357
                                                             -----------------------------------
        Balance as of December 31, 2003 and 2002                  $ 29,323,367     $ 31,961,402
                                                             -----------------------------------
     Change in Plan Assets
        Balance as of December 31, 2002 and 2001                    $  922,539      $ 1,014,038
        Employer contributions                                       1,700,315          863,969
        Retiree contributions                                          106,323           81,529
        Claims/benefit payments and administrative fees            (1,814,366)       (1,053,187)
        Actual return                                                   10,000           16,190
                                                             -----------------------------------
        Balance as of December 31, 2003 and 2002                    $  924,811       $  922,539
                                                             -----------------------------------
     Funded status                                               $(28,398,556)     $(31,038,863)
     Unrecognized (gain) loss                                      (2,126,704)        1,411,561
                                                             -----------------------------------
     Accrued postretirement benefit cost at
        December 31, 2003 and 2002                               $(30,525,260)     $(29,627,302)
                                                             ====================================
</TABLE>

     The discount rate and near-term and long-term health care cost trend rates
     used to determine postretirement benefit obligations, effective January 1,
     2004, and the Plan's funded status at December 31, 2003, were 6.75%, 9% and
     5%, respectively.

     Significant assumptions used to determine the net periodic postretirement
     benefit cost for each year were as follows:

                                                      2003          2002
                                                --------------   --------------
     Discount rate                                    6.75 %       7.25 %
     Health care cost trend rate-
           Near-term                                  9.0 %        9.0 %
           Long-term                                  5.0 %        5.0 %
     Rate of return on plan assets                    5.0 %        5.0 %


                                       28
<PAGE>

Note 5.  Postretirement Benefits, Continued:

     It is assumed that the near-term health care cost trend rate of 9% will
     gradually decrease to 5% by the year 2008.

     As a result of purchase accounting, all unrecognized actuarial gains and
     losses, prior service cost and the unrecognized net transition obligation
     were eliminated as of October 10, 2001, the merger date with Emera. As a
     result of regulatory accounting, a regulatory asset of $14.6 million, equal
     to these unrecognized amounts, was established at the merger date. The
     Company is amortizing this balance over the same period at which the
     corresponding gains and losses were being amortized when they were a
     component of the net periodic postretirement benefit cost. Amortization
     expense amounted to approximately $1.13 million in each of 2003 and 2002.

     Assumed health care cost trend rates have a significant effect on the
     amounts reported for the health care plan. A one-percentage-point change in
     assumed health care cost trend rates would have the following effect:

                                                      1% Decrease    1% Increase
                                                   -----------------------------
     Effect on total of service and interest cost    $ (391,652)      $ 518,767
       components

     Effect on postretirement benefit obligation     (3,903,615)      5,025,678

     On December 8, 2003, the Medicare Prescription Drug, Improvement and
     Modernization Act of 2003 (the Act) was signed into law. The Act introduces
     a prescription drug benefit under Medicare (Medicare Part D) as well as a
     federal subsidy to sponsors of retiree health care benefit plans that
     provide a benefit that is at least actuarially equivalent to Medicare Part
     D. In accordance with Financial Accounting Standards Board Staff Position
     No. FAS 106-1, any measures of the accumulated postretirement benefit
     obligation or net periodic postretirement benefit cost in the 2003
     financial statements or accompanying notes do not reflect the effects of
     the Act on the plan. Specific authoritative guidance on the accounting for
     the federal subsidy is pending and that guidance, when issued, could
     require the Company to change previously reported information.

     The estimates of the Company's accrued pension and postretirement benefit
     costs involve the utilization of significant assumptions. Changes in any
     one of these assumptions could impact the liabilities in the near term.

     The Company also provides a defined contribution 401(k) savings plan for
     substantially all of its employees. The Company's matching of employee
     voluntary contributions amounted to approximately $244,000 in 2003 and
     $271,000 in 2002.


Note 6.  Jointly Owned Facilities and Power Supply Commitments

     Maine Yankee - The Company owns 7% of the common stock of Maine Yankee,
     which owns and, prior to its permanent closure in 1997, operated an
     880-megawatt (MW) nuclear generating plant (the Plant) in Wiscasset, Maine.
     Maine Yankee, which had commenced commercial operation on January 1, 1973,
     is the only nuclear facility in which the Company has an ownership
     interest. The Company's equity ownership in the plant had entitled the
     Company to about 7% of the output pursuant to a cost-based power contract.
     Pursuant to a contract with Maine Yankee, the Company is obligated to pay
     its pro rata share of Maine Yankee's operating expenses, including
     decommissioning costs. In addition, under a Capital Funds Agreement entered
     into by the Company and the other sponsor utilities, the Company may be
     required to make its pro rata share of future capital contributions to
     Maine Yankee if needed to finance capital expenditures.


                                       29
<PAGE>

Note 6.  Jointly Owned Facilities and Power Supply Commitments, Continued:

     On August 6, 1997, the board of directors of Maine Yankee voted to
     permanently cease power operations at the Plant and to begin
     decommissioning the Plant. The Plant had experienced a number of
     operational and regulatory problems and did not operate after December 6,
     1996. The decision to close the Plant permanently was based on an economic
     analysis of the costs, risks and uncertainties associated with operating
     the Plant compared to those associated with closing and decommissioning it.

     The entire output of the Plant had been sold at wholesale by Maine Yankee
     to ten New England electric utilities, which collectively own all of the
     common equity of Maine Yankee; a portion of that output (approximately
     6.2%) was in turn resold by certain of the owner utilities to 29 municipal
     and cooperative utilities in New England. Maine Yankee, since the shutdown
     decision, has continued to recover its costs of providing service through a
     formula rate filed with the FERC and contained in Power Contracts with its
     utility purchasers.

     In 1999, issues surrounding decommissioning costs, the prudence of the
     management, operation and decision to permanently cease operation of the
     plant, and state of Maine ratemaking were settled in proceedings at the
     FERC and MPUC. The Company believes that the settlements constituted a
     reasonable resolution of the issues raised and eliminated significant
     uncertainties concerning the Company's future financial performance. Under
     an agreement, the Company will continue to recover its Maine Yankee costs,
     although the allowed return on equity associated with the Company's equity
     balance in Maine Yankee was set at 6.50%. As part of a further settlement
     with the MPUC, the Company recorded a regulatory liability of $2.2 million
     associated with Maine Yankee replacement power costs subsequent to the
     plant shutdown. This was reflected as a reduction in stranded costs
     effective March 1, 2002.

     Maine Yankee's most recent estimate of the total costs of decommissioning
     and plant closure, for the period from 2002 to 2008, excluding funds
     already collected, is approximately $502 million (undiscounted). The
     Company's share of the estimated cost at December 31, 2003 is approximately
     $27.1 million and is recorded as a regulatory asset and decommissioning
     liability. The regulatory asset was recorded for the full amount of the
     decommissioning and plant closure costs due to the state's industry
     restructuring legislation (see Note 9) allowing the Company future recovery
     of nuclear decommissioning expenses related to Maine Yankee, as well as the
     Company being allowed a recovery mechanism in its February 2002 rate order
     for Maine Yankee non-decommissioning plant closure costs.

     Maine Yankee, starting in 2001, began a program of systematically redeeming
     its common stock from its owners. In 2001, the Company received
     approximately $703,000 in proceeds associated with the redemption of 5,264
     common shares; in 2002 the Company received $525,000 in connection with the
     redemption of 3,955 common shares; and in 2003 the Company received an
     additional $735,000 in connection with the redemption of 5,530 common
     shares. At December 31, 2003, the Company holds 20,251 common shares of
     Maine Yankee.

     MEPCO - The Company owns 14.2% of the common stock of MEPCO. MEPCO owns and
     operates electric transmission facilities from Wiscasset, Maine, to the
     Maine-New Brunswick border. Information relating to the operations and
     financial position of Maine Yankee and MEPCO appears later in Note 6. In
     connection with the Company's generation asset sale in May 1999 (see Note
     9), the Company sold certain of its rights to MEPCO transmission capacity.

     Bangor Var Co. - In 1990, the Company formed BVC, whose sole function is to
     be a 50% general partner in Chester, a partnership which owns a static var
     compensator (SVC), which is electrical equipment that supports the Phase 2
     transmission line. A wholly-owned subsidiary of Central Maine Power Company
     owns the other 50% interest in Chester. Chester has financed the
     acquisition and construction of the SVC through the issuance of $33 million
     in principal amount of 10.48% senior notes due 2020, and up to $3.25
     million in principal amount of additional notes due 2020 (collectively, the
     SVC Notes). The holders of the SVC Notes are without recourse against the
     partners or their


                                       30
<PAGE>

Note 6. Jointly Owned Facilities and Power Supply Commitments, Continued:

     parent companies and may only look to Chester and to the collateral for
     payment. The New England utilities which participate in Phase 2 have agreed
     under a FERC approved contract to bear the cost of Chester, on a cost of
     service basis, which includes a return on and of all capital costs.

     Summary Financial Information for Maine Yankee and MEPCO is as follows
     (dollars in thousands):

<TABLE>
<CAPTION>
                                                             Maine Yankee                  MEPCO
                                                        -------------------------------------------------
                                                           2003        2002           2003       2002
                                                        ------------------------   ----------------------
        Operation:
<S>                                                        <C>         <C>            <C>        <C>
           As reported by investee-
              Operating revenue                            $ 53,222    $ 58,924       $ 3,792    $ 4,066
                                                        ========================   ======================
              Earnings applicable to common stock          $  3,217    $  3,947       $ 1,258    $ 1,068
                                                        ========================   ======================

           Amounts reported by the Company-
              Purchased power costs                        $  3,976    $  4,068         $   -     $    -
              Equity in net income                             (236)       (280)        (177)       (168)
                                                        ------------------------   -----------------------
              Net purchased power expense                  $  3,740    $  3,788       $ (168)    $  (168)
                                                        ========================   =======================

        Financial Position:
           As reported by investee-
              Total assets                                 $561,523    $681,782       $ 8,063    $ 7,680
              Less-

                 Long-term debt                               2,680      21,600             -          -
                 Other liabilities and deferred credits    $514,424     602,463         1,080        608
                                                        ------------------------   ----------------------
                 Net assets                                $ 44,419    $ 57,719       $ 6,983    $ 7,072
                                                        ========================   ======================

        Company's reported equity-
              Equity in net assets                         $  3,109    $  4,040        $  992    $ 1,004
              Adjust Company's estimate to actual                 1          (6)            1          -
                                                        ------------------------   ----------------------
              Equity in net assets as reported             $  3,110    $  4,034        $  993    $ 1,004
                                                        ========================   ======================
</TABLE>

     NEPOOL/Hydro-Quebec Project - The Company is a 1.6% participant in the
     NEPOOL/Hydro-Quebec Phase 1 project (Phase 1), a 690 MW DC intertie between
     the New England utilities and Hydro-Quebec constructed by a subsidiary of
     another New England utility at a cost of about $140 million. The
     participants receive their respective share of savings from energy
     transactions with Hydro-Quebec, and are obliged to pay for their respective
     shares of the costs of ownership and operation whether or not any savings
     are realized.

     The Company is also a 1.5% participant in the NEPOOL/Hydro-Quebec Phase 2
     project (Phase 2), which involves an increase to the capacity of the Phase
     1 intertie to 2,000 MW. As in the Phase 1 project, the Company receives a
     share of the anticipated energy cost savings derived from purchases from
     Hydro-Quebec and capacity benefits provided by the intertie and is required
     to pay its share of the costs of ownership and operation whether or not any
     savings are obtained. In connection with the generation asset sale in May
     1999, the Company sold its rights as a participant in the regional
     utilities agreement with Hydro-Quebec (see Note 9). The Company, though, is
     still required to pay its share of the costs of ownership and operation of
     the Hydro-Quebec intertie. Also in connection with the asset sale, PP&L
     Global (PP&L) has agreed to pay the Company $400,000 per year to partially
     offset the Company's on-going Hydro-Quebec support payments. Since the
     Company still has an obligation for the costs of the Hydro-Quebec intertie,
     but it has sold the rights to the benefits as a participant, liabilities of
     approximately $5.1 million and $5.6 million (included in Other Long-term
     Liabilities) and corresponding regulatory assets (included in Other
     Regulatory Assets) have been recorded as of


                                       31
<PAGE>

Note 6. Jointly Owned Facilities and Power Supply Commitments, Continued:

     December 31, 2003 and 2002, respectively, on the Consolidated Balance
     Sheets. These amounts represent the present value of the Company's
     estimated future payments (net of the $400,000 to be received from PP&L)
     for costs of ownership and operation of the Hydro-Quebec intertie.

     Power Supply Commitments - As of the end of 2002, the Company had long-term
     power supply contracts with six independent, non-utility power producers
     known as "small power production facilities." The West Enfield Project,
     described below, is one such facility. There are four other relatively
     small hydroelectric facilities, and a 20 MW facility fueled by municipal
     solid waste (see PERC discussion below). The cost of power from the small
     power production facilities is more than the Company would incur from other
     sources if it were not obligated under these contracts, and, in the case of
     the solid waste plant, substantially more. The prices were negotiated at a
     time when oil prices were much higher than at present, and when forecasts
     for the costs of the Company's long-term power supply were higher than
     current forecasts. As discussed below, the power purchased under these
     contracts are resold to third parties under separate contracts.

     West Enfield Project - In 1986, the Company entered into a joint venture
     with a development subsidiary of Pacific Lighting Corporation for the
     purpose of financing and constructing the redevelopment of an old 3.8 MW
     hydroelectric plant which the Company owned on the Penobscot River in
     Enfield and Howland, Maine, into a 13 MW facility for the purpose of
     operating the facility once it was completed. Commercial operation of the
     redeveloped project began in April 1988. Penobscot Hydro Co. (PHC) was
     formed to own the Company's 50% interest in the joint venture,
     Bangor-Pacific. Bangor-Pacific financed the cost of the redevelopment
     through the issuance in a privately placed transaction of $40 million of
     fixed rate term notes and a commitment for up to $5 million of floating
     rate notes. The notes are secured by a mortgage on the project and a
     security interest in a 50-year purchased power contract, and the revenues
     expected thereunder, between the Company and Bangor-Pacific. The Company's
     purchased power expense under this contract was approximately $6.7 million
     in 2003 and $6.3 million in 2002, and is projected to be approximately $6.5
     to 7 million in each of 2004 and 2005 and to steadily decrease over the
     remainder of the contract down to approximately $4 million in the last full
     year, 2023.

     In late July 1999, in connection with the generation asset sale, the
     Company sold PHC to PP&L and received $10 million in proceeds. The sale
     resulted in a gain of approximately $5.2 million, of which $4.7 million was
     deferred as part of the deferred asset sale gain (see Note 9). The
     remaining $.5 million of the gain related to the portion of the gain on
     sale of PHC which was allocable to shareholders.

     PERC - PERC owns a 20 MW waste-to-energy facility in Orrington, Maine that
     provides solid waste disposal services to many communities in central,
     eastern, and northern Maine. The contract requires the Company to purchase
     the electricity output of the plant until 2018 at a price that is presently
     above the cost of alternative sources of power, and, in the Company's
     opinion, is likely to remain so. A portion of the PERC output is resold to
     a third party under a power sales contract that ends in February 2003
     (discussed below). The Company's purchased power expense under this
     contract was approximately $21.2 million in 2003, $20.2 million in 2002,
     and is projected to is projected to be approximately $21 to 22 million in
     each of 2004 and 2005, and to increase over the remainder of the contract
     up to approximately $27 million in the last full year, 2017.

     Also as a result of a 1998 contract restructuring (discussed below), PERC
     will share the net revenues generated by the facility on a pro rata basis
     with the Company and the MRC, which represents over 130 Maine
     municipalities receiving waste disposal service from PERC. In 2003 and
     2002, the Company realized approximately $3.5 million and $3.6 million,
     respectively, in savings associated with its share of PERC net revenues.


                                       32
<PAGE>

Note 6.  Jointly Owned Facilities and Power Supply Commitments, Continued:

     Other Power Supply Commitments - The Company entered into a contract, which
     started on March 1, 2001, for the delivery of up to 160 MW of power from a
     third party, ending February 28, 2004. The energy delivered in connection
     with the contract was used to serve a portion of the standard-offer service
     customer load through February 28, 2002. Subsequent to this date, the
     Company has resold this power to one of the new standard offer service
     providers in the Company's service territory. The Company's purchased power
     expense under this contract was approximately $24.1 million in 2003 and
     $37.5 million in 2002, and is estimated to be approximately $3.6 million in
     2004. The non-standard offer related revenues associated with the resale of
     power amounted to $17.1 in 2003 and $20.2 million in 2002, and it is
     estimated to be approximately $2.7 million in 2004. This resale of power is
     recorded as a component of Off-system Sales in the Consolidated Statements
     of Income for 2002. See Note 9 for a discussion of the standard offer
     service.

     In late 1999 the Company selected the winning bidder for all of the
     capacity and energy from its six purchased power contracts being auctioned
     off pursuant to Chapter 307 of the MPUC's rules for regulation of electric
     utilities. The contract commenced March 1, 2000, the date when retail
     customer choice for power supply commenced in Maine, and continued through
     February 28, 2002. The Company recorded $1.4 million in revenues from the
     resale of power under this contract in 2002. This revenue is recorded as a
     component of Off-system Sales in the Consolidated Statements of Income for
     2002.

     In the fall of 2001, the MPUC selected the winning bidder to supply the
     small customer class of standard-offer service starting in March 2002.
     Their bid was contingent upon being selected as buyer of all of the
     capacity and energy from the Company's previously discussed six purchased
     power contracts, two-year standard offer related energy supply contract and
     the output of the Company's diesel units. The period of sale commenced on
     March 1, 2002, and will continue for a period of three years. The revenues
     realized under this contract (excluding the portion related to the two-year
     standard offer related energy supply contract discussed above), as well as
     the final two months in 2002 of the previous Chapter 307 sales related
     contract, were approximately $8.4 million in 2003 and $5.8 million in 2002,
     and they are estimated to be $8.2 million 2004 and $1.2 million in 2005.
     This resale of power is recorded as a component of Off-system Sales in the
     Consolidated Statements of Income.

     The Company was also party to a power sales contract with another utility
     that ended in February 2003. The source of the power to supply this
     customer was from a portion of the PERC purchased power contract and from
     market purchases. The portion of the power sales contract associated with
     market purchases ended in August 2002. The Company realized $499,000 and
     $12.3 million of revenues under this contract in 2003 and 2002, and these
     amounts are reflected recorded as a component of Off-system Sales in the
     Consolidated Statements of Income.

     Rate Recovery - For a discussion of the rate recovery associated with these
     power supply commitments, see Note 9.

     Purchased Power Contract Buyouts and Restructuring - During the 1990's, the
     Company attempted to alleviate the adverse impact of high-cost contracts
     with small power production facilities. One method for doing so was to pay
     a fixed sum in return for terminating the contract. The first such
     transaction was accomplished in 1993, and in 1995 the Company succeeded in
     accomplishing two more.

     In the 1993 transaction, the Company negotiated an agreement to cancel its
     long-term purchased power agreement with one of the biomass plants, the
     Beaver Wood Joint Venture (Beaver Wood), in June 1993. In connection with
     the cancellation, the Company paid Beaver Wood $24 million in cash and
     issued a new series of 12.25% First Mortgage Bonds due July 15, 2001 to the
     holders of Beaver Wood's debt in the amount of $14.3 million in
     substitution for Beaver Wood's previously outstanding 12.25% Secured Notes.


                                       33
<PAGE>

Note 6.  Jointly Owned Facilities and Power Supply Commitments, Continued:

     Also, in connection with the cancellation agreement, a reconstituted Beaver
     Wood partnership paid the Company an additional $6.75 million over a
     six-year period. The Company established a regulatory asset associated with
     the cost of the buyout, and with the implementation of new base rates on
     March 1, 1994, the Company began recovering over a nine-year period the
     deferred balance, net of the additional funds to be collected from Beaver
     Wood. This regulatory asset was being amortized at an annual rate of $3.9
     million and was fully amortized in February 2003.

     The 1995 transactions involved a "buyback" of the contracts for the
     purchase of power from two biomass-fueled generating plants in West Enfield
     and Jonesboro, Maine, which are identical plants under common ownership.
     The buyback cost, which was financed entirely by new debt instruments (See
     Note 4) was approximately $170 million, including transaction costs. The
     buyback costs were deferred and recorded as a regulatory asset and are
     being amortized and collected over a ten-year period, beginning July 1,
     1995, at an annual expense of $17 million. Effective with the
     implementation of new stranded cost rates on March 1, 2002, the
     amortization period for this regulatory asset was extended until February
     28, 2006, and the annual expense was reduced to $14.2 million. The
     unamortized balance of this regulatory asset amounted to approximately
     $30.8 million and $45 million at December 31, 2003 and 2002, respectively.

     In June 1998 the Company successfully completed a major restructuring of
     its obligations under various agreements with PERC. It is anticipated that
     the restructuring will result in substantial savings for the Company. As
     previously discussed, in connection with this restructuring, PERC will
     share the net revenues generated by the facility on a pro rata basis with
     the Company and the MRC over the remaining term of the PERC contract, which
     represents over 130 Maine municipalities receiving waste disposal service
     from PERC. The Company also made a one-time payment of $6 million to PERC
     in June 1998 and made additional quarterly payments, starting in October
     1998, of $250,000 for four years totaling $4 million. These amounts were
     recorded as regulatory assets when the payments were made.

     Finally, in connection with the PERC contract restructuring in 1998, the
     Company issued two million warrants to purchase common stock, one million
     each to PERC and the MRC. Each warrant entitled the warrant holder to
     acquire one share of the Company's common stock at a price of $7 per share.
     No warrants could be exercised within the first nine months after their
     issuance, and they were exercisable in 500,000 share blocks following the
     expiration of nine months, 21 months, 33 months, and 45 months from the
     closing date. Upon exercise, the Company had the option, instead of
     providing common stock, to pay cash equal to the difference between the
     then market price of the stock and the exercise price of $7 per share times
     the number of shares as to which exercise was made. The MPUC established a
     cap on ratepayers' exposure to the cost of the warrants. Ratepayer costs
     were limited to the difference between the higher of $15 per share or the
     book value per share at the time the warrants were exercised and the $7
     exercise price. This cap was further modified by the MPUC in 2001 in
     connection with the approval of the Company's merger with Emera. For any
     warrants that were exercised after the merger approval in January 2001, the
     cap on the ratepayers' exposure was set at $10.50 per share ($17.50 per
     share less the $7 exercise price). The Company will not recover any costs
     above the cap from ratepayers.

     In connection with the Company's merger with Emera, in 2001, the remaining
     outstanding common stock warrants were exercised. For a portion of these
     warrants, the Company exercised its option to pay cash to the holders of
     the warrants instead of actually issuing shares of common stock. These
     payments amounted to approximately $14.2 million. For the unexercised
     warrants associated with the MRC, the Company and the MRC entered into an
     agreement whereby the Company, instead of issuing shares or paying cash,
     established the previously discussed note payable to the MRC.

     As a result of the exercise of the warrants during 1999 through 2001 and
     the affects of the cap on the ratepayers' exposure as set by the MPUC, the
     Company increased its regulatory asset associated with the PERC contract
     restructuring by approximately $18.5 million.


                                       34
<PAGE>

Note 6.  Jointly Owned Facilities and Power Supply Commitments, Continued:

     In its stranded cost rates, the Company is recovering, over the remaining
     term of the PERC contract, the full amount of deferred PERC restructuring
     costs, including the value of warrants exercised and the additional
     $250,000 quarterly payments discussed above, amounting to an annual
     amortization of $1.7 million per year. As of December 31, 2003 and 2002,
     the unamortized balance of the PERC contract restructuring regulatory asset
     amounted to approximately $25.1 million and $26.8 million respectively.


Note 7.  Recovery of Seabrook Investment and Sale of Seabrook Interest

     The Company was a participant in the Seabrook nuclear project in Seabrook,
     New Hampshire. On December 31, 1984, the Company had almost $87 million
     invested in Seabrook, but because the uncertainties arising out of the
     Seabrook Project were having an adverse impact on the Company's financial
     condition, an agreement for the sale of Seabrook was reached in mid-1985
     and was finally consummated in November 1986. During 1985, a comprehensive
     agreement was negotiated among the Company, the MPUC staff, and the Maine
     Public Advocate addressing the recovery through rates of the Company's
     investment in Seabrook (the Seabrook Stipulation). This negotiated
     agreement was approved by the MPUC in late 1985. Although the
     implementation of the Seabrook Stipulation significantly improved the
     Company's financial condition, substantial write-offs were required as a
     result of the determination that a portion of the Company's investment in
     Seabrook would not be recovered. In addition to the disallowance of certain
     Seabrook costs, the Seabrook Stipulation also provided for the recovery
     through customer rates of 70% of the Company's year-end 1984 investment in
     Seabrook Unit 1 over 30 years, and 60% of the Company's investment in Unit
     2 over seven years, with base rate treatment on the unamortized balances.
     As of December 31, 1992, the Company's investment in Seabrook Unit 2 was
     fully amortized. The regulatory asset is being recovered as a component of
     the Company's stranded costs, and the annual amortization expense amounts
     to approximately $1.7 million.


Note 8.  Fair Value of Financial Instruments

     The following represents the estimated fair value at December 31, 2003 of
     each class of financial instrument based upon similar issuances of
     comparable companies:

<TABLE>
<CAPTION>
     (In Thousands)                                        Carrying Amount       Fair Value
                                                           ---------------       ----------
<S>                                                           <C>              <C>
     Assets:
     Cash and cash equivalents - including money
     market funds and repurchase agreements                   $ 2,882          $ 2,882
     Other investments, associated with miscellaneous
     special deposits- U.S. Treasury Bills                        104              104
     Funds held by trustee-guaranteed investment
     contract                                                  21,192           22,659

     Liabilities:
     First Mortgage Bonds                                      50,000           51,925
     FAME Revenue Notes                                        38,200           40,046
     Senior Unsecured Notes                                    70,000           71,004
     Municipal Review Committee Note Payable                    9,847           10,279
     Short-term debt                                            4,000            4,000
</TABLE>


                                       35
<PAGE>

Note 9.  Industry Restructuring and Rate Regulation

     In 1997, the Maine legislature enacted a comprehensive law providing for
     the restructuring of the electric industry in Maine. The principal aspects
     of the law were as follows:

     o   Effective March 1, 2000, retail consumers of electricity had the right
         to purchase energy supply directly from competitive electricity
         suppliers;
     o   Electric utilities were required to divest of their generating assets
         and restrictions were imposed limiting their participation in
         generation and marketing activities;
     o   Electric utilities were provided with the opportunity to recover their
         prudently incurred stranded costs; and
     o   The MPUC was directed to conduct a competitive solicitation process to
         select a standard-offer provider to serve the needs of customers unable
         to find a competitive supplier or uninterested in doing so.

     The Maine restructuring law has essentially been fully implemented.

     As a result of the industry restructuring, the Company has been primarily
     engaged in the transmission and distribution of electric energy. Electric
     rates for the Company's customers are divided into four components, which
     are discussed below, (i) transmission, (ii) distribution, (iii) stranded
     costs, and (iv) energy service. The rates charged to customers for
     transmission, distribution and stranded costs are established in distinct
     regulatory proceedings. The Company's revenues are generated by a delivery
     charge encompassing transmission, distribution and stranded costs, and the
     Company is not presently involved in supplying energy to retail customers.
     The delivery charge, though, continues to be based on customer's
     electricity usage measured in kilowatt-hours ("kWh").

     Sales of the Company's Generating Assets - In September 1998, the Company
     sold certain property and equipment at its Graham Station site in Veazie,
     Maine, to Casco Bay Energy for $6.2 million. On May 27, 1999, the Company
     completed most of the transaction for the sale of its electric generating
     assets and certain transmission rights to PP&L. The purchase price for the
     assets transferred was $79 million. The sale involved all but one of the
     Company's hydroelectric plants on the Penobscot, Piscataquis, and Union
     rivers and Bangor Hydro's 8.33% ownership interest in the Wyman Unit #4
     oil-fired plant in Yarmouth, Maine-a total base load capacity of 83
     megawatts. The sale also involved a transfer by the Company of rights to
     transmit power over the MEPCO transmission facilities connecting NEPOOL to
     New Brunswick Canada; the Company's rights as a participant in the regional
     utilities' agreement with Hydro-Quebec pursuant to an agency agreement; and
     the Company's rights to develop a second high voltage transmission line
     that will connect NEPOOL to New Brunswick, Canada.

     The Company realized a net gain on the sale related to these sales of
     approximately $29.8 million, and $29.3 million of this amount was recorded
     as a deferred liability at February 29, 2000, on the Consolidated Balance
     Sheets. As discussed in Note 6, the other $.5 million of the gain on the
     sale of PHC that was allocable to shareholders, pursuant to orders of the
     MPUC, was recorded as other income in 1999. Effective with the March 1,
     2000 rate change, the Company began amortizing the deferred asset sale gain
     over a 70-month period. The annual amortization amounts are being recorded
     in an uneven manner in order to levelize the Company's revenue requirement
     over this period. As a result of an increase in the Company's FERC
     regulated transmission rates on June 1, 2000, and the desire to not
     increase rates to its retail customers so close to the implementation of
     electric industry restructuring, which occurred on March 1, 2000, the
     Company agreed to reduce its MPUC jurisdictional distribution rates in an
     amount equal to the increase in its transmission rates. The reduction in
     the distribution rates was accomplished by accelerating the amortization of
     the deferred asset sale gain through May 2001 by an annualized total of
     $2.5 million.

     Effective April 15, 2001, and through February 28, 2002, in an effort to
     mitigate the effects of increased energy prices for the Company's large
     customers, the MPUC ordered the Company to reduce its distribution and
     stranded cost electric rates to certain large customers by $.008/kWh. To


                                       36
<PAGE>

Note 9. Industry Restructuring and Rate Regulation, Continued:

     fund this rate reduction and corresponding decrease in revenues, the MPUC
     ordered the Company to accelerate the amortization of the deferred asset
     sale gain in an amount necessary to offset the estimated decrease in
     revenues caused by the rate reduction. The asset sale gain amortization was
     increased by approximately $2.5 million over the 10 1/2 month period the
     reduced rates were in effect. Also, the Company's FERC jurisdictional
     transmission rates changed on June 1, 2001. Consistent with 2000, the
     Company reduced its distribution rates via an adjustment to the asset sale
     gain amortization to offset the change in the transmission rates effective
     June 1, 2001. The annualized accelerated amortization associated with the
     transmission rate change amounted to approximately $1.6 million and ended
     in May 2002.

     In April 1999 Central Maine Power Company (CMP), sold all of its interest
     in the Wyman generating units and ancillary property, including its 59%
     interest in Unit 4. On August 31, 1999, 11 minority owners of Wyman #4,
     including Bangor Hydro, served a Demand for Arbitration on CMP with respect
     to the sale of Wyman #4. The Demand asserted that the minority owners were
     entitled to a share of the proceeds from CMP's sale of Wyman. On April 23,
     2001, CMP and the minority owners reached a settlement agreement to dispose
     of all claims raised in the Demand for Arbitration. Under the terms of the
     agreement, CMP agreed to pay the minority owners $12 million in exchange
     for a full release from all claims arising from CMP's sale of Wyman. In
     July 2001 the MPUC issued an order approving the settlement agreement, and
     in October 2001 the Company received its share of the settlement from CMP
     amounting to approximately $2.6 million. This amount was deferred as a
     regulatory liability per the MPUC order, and the Company began returning
     this amount to customers starting March 1, 2002 over a two year period in
     connection with a change in its stranded cost rates.

     Distribution Service
     Distribution revenues represent approximately 50% of the Company's total
     electric operating revenues. On June 6, 2002, the MPUC approved an
     Alternative Rate Plan (ARP) and dismissed a pending management
     investigation of the Company. The terms of the ARP include a rate plan to
     be in effect through December 31, 2007, with the Company's core
     distribution rates being adjusted downward on July 1 of each year from 2003
     to 2007, at annual rates ranging from 2% to 2 3/4%. The Company is also
     allowed rate adjustments associated with certain specified categories of
     costs. The ARP also includes a mechanism whereby distribution returns on
     common equity below 17% and above 5% in any given year will be retained by
     the Company. Earnings in excess of this range and earnings shortfalls below
     the range will be shared evenly between the Company and ratepayers. The
     Company is also required to meet certain customer service quality standards
     during the term of the ARP, and rate reduction penalties will result from
     not meeting the various performance measures as set forth in the
     stipulation. Finally, the ARP provides the Company with an accounting order
     allowing for the deferral and ten-year amortization of employee transition
     costs during 2002 and 2003 in connection with reductions in the cost of
     operations.

     Successful implementation of the ARP necessitated a significant decrease in
     the Company's operating costs, and as a result, the Company reorganized its
     operations in 2002. The internal restructuring, which encompassed all
     aspects of the Company, has reduced operating costs by approximately
     20%-25%. The Company is also beginning to transfer a portion of its fixed
     costs to variable costs, and improve processes to enhance long-term
     performance. As part of the restructuring, employment levels were reduced
     by approximately 25% in the second and third quarters of 2002 through early
     retirement and severance arrangements. The total employee transition costs
     incurred in 2002 were approximately $8.1 million and are recorded as a
     component of Other Regulatory Assets on the consolidated balance sheets at
     December 31, 2002. As part of an additional restructuring, the Company's
     workforce was further reduced by 19 employees in May 2003. The affected
     employees received an enhanced severance package, which included severance
     pay, two years of medical benefits, education benefits, and employment
     counseling. The total costs associated with the severance packages amounted
     to approximately $1.1 million and were recorded as a component of Other
     Regulatory Assets on the consolidated balance sheets in 2003. The cost
     deferrals associated with the corporate restructurings are being amortized
     over a ten-year period. The total amortization


                                       37
<PAGE>

Note 9. Industry Restructuring and Rate Regulation, Continued:

     expense amounted to approximately $848,000 in 2003 and $458,000 in 2002. As
     of December 31, 2003 and 2002, the unamortized balance of this regulatory
     asset amounted to approximately $7.8 million and $7.6 million respectively.

     As discussed above, the Company is also allowed annual rate adjustments
     under the ARP associated with certain specified categories of costs. To the
     extent certain annual weather related or other mandated costs are in excess
     of a $750,000 threshold, the Company is allowed to establish a regulatory
     asset for this amount and recover over a one-year period starting with the
     ARP annual rate change on July 1st of the next year. As a result of
     increased regulatory assessments and significant storm related electric
     service restoration activities in 2003, the Company recorded a regulatory
     asset of approximately $615,000 associated with 2003 costs which were in
     excess of the $750,000 threshold.

     Stranded Cost Service
     Stranded cost revenues represent approximately 40% of the Company's total
     electric operating revenues. Pursuant to the Maine restructuring law,
     electric utilities are entitled to recover all prudently incurred stranded
     costs that cannot reasonably be mitigated. In February 2002, the MPUC
     issued an order allowing the Company to increase its rates to recover the
     stranded costs created as a result of the restructuring of the electric
     utility industry in the State of Maine. The stranded cost rate increase,
     effective March 1, 2002, resulted in the Company's total electric rates
     increasing by approximately 6.5%. The stranded cost rates are set for a
     period not to exceed three years, although the Company has the right to
     seek adjustments to these rates if certain economic situations occur.
     Customers reducing or eliminating their consumption of electricity by
     switching to self-generation, conversion to alternative fuels or utilizing
     demand-side management measures cannot be assessed exit or entry fees.

     In connection with the Company's stranded cost rate proceeding with the
     MPUC the principal regulatory assets and liabilities being recovered
     from/returned to customers as stranded costs are as follows:

     o   Maine Yankee decommissioning and other closure costs (See Note 6)
     o   Obligations associated with Hydro-Quebec (See Note 6)
     o   The cost of energy and capacity associated with the power purchase
         contracts, net of revenues from resale (See Note 6)
     o   Purchased power contract buyout and restructuring costs (See Note 6)
     o   Seabrook investment (See Note 7)
     o   Deferred special rate contract revenues (See below in Note 9)
     o   Deferred asset sale gain (See above in Note 9)
     o   Deferred Wyman #4 litigation settlement proceeds (See above in Note 9)
     o   Deferred standard offer costs (See below in Note 9)
     o   Deferred Maine Yankee replacement power cost write-off (See Note 6)

     Deferred Special Rate Contract Revenues - Also in connection with the
     February 2000 rate order from the MPUC, and starting March 1, 2000, the
     Company was granted a deferral mechanism for the difference in actual
     revenues realized from customers under special rate contracts as compared
     to the estimated revenues from these customers utilized in setting the
     Company's new electric rates starting March 1, 2000. Under this deferral
     mechanism, the Company recorded a regulatory asset of approximately $3.6
     million for the period from March 1, 2000 through February 28, 2002.
     Effective March 1, 2002, with the implementation of new stranded cost
     rates, these deferrals ceased, and the Company began amortizing the
     deferred special rate contract revenue regulatory asset balance over a
     four-year period.

     Effective March 1, 2002, the Company began recording new special rate
     contract revenue deferrals in connection with a new rate contract with a
     large industrial customer. The Company is realizing stranded cost related
     revenues from this customer that are in excess of amounts assumed in the
     latest


                                       38
<PAGE>

Note 9. Industry Restructuring and Rate Regulation, Continued:

     stranded cost rate proceeding. As a result, and as ordered by the MPUC, the
     Company is recording a reduction in the deferred special rate contract
     revenue regulatory asset and a reduction in revenues.

     The revenue deferrals associated with this customer amounted to $.5 million
     for the period from March 2002 to December 2002, and amounted to an
     additional $.7 million in 2003. The net deferred special rate contract
     revenue regulatory asset balance amounted to $.8 million and $2.5 million
     at December 31, 2003 and 2002, respectively, and is included as a component
     of Other Regulatory Assets in the Consolidated Balance Sheets.

     Transmission Service
     Transmission revenues represent approximately 10% of the Company's total
     electric operating revenue. The regulation of electric transmission has
     also been undergoing substantial restructuring. In New England, these
     changes have included the restructuring of NEPOOL and the formation of the
     New England Independent System Operator, ISO-New England (ISO-NE) in March
     1997. ISO-NE is an independent entity operating under contract with NEPOOL
     to manage the New England region's electric bulk power generation and
     transmission systems and administering the region's open access
     transmission tariff. The Company's transmission facilities are already
     under the operational control of ISO-New England and rates for retail
     transmission service are subject to FERC jurisdiction.

     In February 2001, the FERC last issued an order approving transmission
     rates for service provided on or after March 1, 2000. Under the FERC Order
     approving these transmission rates, a "formula" rate was approved, allowing
     the Company to adjust its rates annually to reflect changes in the
     Company's costs and its sales volume during the preceding calendar year.
     The Company's transmission rate formula was reviewed by FERC during 2003,
     and certain minor changes were made to the formula. In addition, ongoing
     FERC initiatives to restructure the transmission industry may ultimately
     result in a different transmission cost recovery structure.

     Energy Service
     The Company is not presently engaged in selling energy to customers.
     Pursuant to the Maine restructuring law, all customers have the right to
     select a competitive energy supplier to serve their energy requirements.
     For customers unable to do so, or uninterested in doing so, standard offer
     service is provided by default. The MPUC is responsible for selecting a
     standard offer provider through a competitive solicitation process. The
     solicitation process is anticipated to be conducted every three years for
     residential and small commercial customers and every year for large
     commercial and industrial customers. For the period March 2000 through
     February 2002, the MPUC rejected results of the competitive solicitation
     process for the Company's customers and directed the Company to arrange for
     standard offer service. The MPUC established the schedule of rates the
     Company could charge for this service starting March 1, 2000.

     The Company entered into arrangements with third parties to purchase the
     energy to serve the standard-offer customers. The Company was allowed by
     the MPUC to defer, for future ratemaking treatment, the difference between
     revenues realized from the standard-offer sales and the costs incurred to
     provide this service, including carrying costs on the deferred balance.
     From March 1, 2000, when new rates went into effect, through February 2002,
     on a cumulative basis, the revenues realized from standard offer customers
     exceeded the costs of providing the standard offer service, and
     consequently, the Company recorded a regulatory liability. Effective March
     1, 2002, with the implementation of new stranded cost rates as approved by
     the MPUC, the Company began amortizing the deferred standard-offer
     liability balance over a two-year period. Principally as a result of
     true-up adjustments to standard offer revenues, for the period from March
     1, 2002 to December 31, 2002, standard offer costs exceeded standard offer
     revenues by approximately $3.1 million. As of December 31, 2002, the
     regulatory liability balance amounted to approximately $1 million (which is
     included in Other Regulatory Liabilities on the Consolidated Balance
     Sheets). Resulting primarily from $3.5 million in amortization recorded in
     2003 the deferred standard offer cost balance represented a


                                       39
<PAGE>

Note 9.  Industry Restructuring and Rate Regulation, Continued:

     regulatory asset of approximately $2.8 million at December 31, 2003.
     (Included in Other Regulatory Assets on the Consolidated Balance Sheets).

     Also, as previously discussed, effective March 1, 2002, as a result of new
     bids received from competitive energy providers, the Company is no longer
     serving as the standard offer service provider. The Company is, though,
     serving as the billing and collection agent under the standard offer
     program.

     As a result of the previously discussed reconciliation mechanism,
     standard-offer related revenues and expenses do not have any impact on the
     Company's earnings, although they did result in increases in both
     categories in the Company's Consolidated Statements of Income in 2002.

     Regulatory Assets and Meeting the Requirements of SFAS 71 - The Company is
     subject to the provisions of Statement of Financial Accounting Standards
     No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS
     71). SFAS 71 allows the establishment of regulatory assets for costs
     accumulated for certain items other than the usual and customary capital
     assets, and allows the deferral of the income statement impact of those
     costs if they are expected to be recovered in future rates. As of December
     31, 2003 and 2002, the Company had regulatory assets, net of regulatory
     liabilities, of approximately $149.4 million and $225.7 million,
     respectively. The Company continues to meet the requirements of SFAS 71
     since the Company's rates are intended to recover the cost of service plus
     a rate of return on the Company's investment, as well as providing specific
     recovery of costs deferred in prior periods.

     The legislation enacted in Maine associated with industry restructuring
     specifically addressed the issue of cost recovery of regulatory assets
     stranded as a result of industry restructuring. Specifically, the
     legislation requires the MPUC, when retail access begins, to provide a
     "reasonable opportunity" for the recovery of stranded costs through the
     rates of the transmission and distribution company, comparable to the
     utility's opportunity to recover stranded costs before the implementation
     of retail access under the legislation. The final rate orders from the MPUC
     effective March 1, 2000 and March 1, 2002 did not result in the Company
     writing off any stranded costs, but if the Company had not been allowed
     full recovery of its stranded costs, it would be required to write-off any
     disallowed costs. As provided for in Emerging Issues Task Force Issue No.
     97-4, "Deregulation of the Pricing of Electricity," the Company will
     continue to record regulatory assets in a manner consistent with SFAS 71 as
     long as future recovery is probable, since the Maine legislation provides
     the opportunity to recover regulatory assets including stranded costs
     through the rates of the T&D company. The Company anticipates, based on
     current generally accepted accounting principles that SFAS 71 will continue
     to apply to the regulated T&D segments of its business.

     If the Company failed to meet the requirements of SFAS 71, due to
     legislative or regulatory initiatives, the Company would be required to
     apply Statement of Financial Accounting Standards No. 101, "Regulated
     Enterprises-Accounting for the Discontinuation of Application of FASB No.
     71" (SFAS 101). If legislative or regulatory changes and/or competition
     result in electric rates which do not fully recover the Company's costs, a
     write-down of regulatory assets would be required. The Company does not
     anticipate any write-down of assets at this time.

Note 10.  Construction of Facilities for Casco Bay Energy

     The Company entered into an agreement with Casco Bay whereby the Company
     agreed to construct various transmission facilities required to allow a
     generating facility being constructed in Veazie, Maine to interconnect with
     the Company's electrical system and deliver its output to the New England
     Power Pool Transmission Facility (PTF) grid. Under this agreement, Casco
     Bay agreed to advance funds necessary to pay for such construction.
     Pursuant to a FERC order approving an amendment to the NEPOOL Agreement,
     approximately 50% of the construction funds advanced are being refunded to
     Casco Bay by customers of NEPOOL over an approximately 30-year period. The
     Company began


                                       40
<PAGE>

Note 10. Construction of Facilities for Casco Bay Energy, Continued:

     refunding such construction costs to Casco Bay starting in June 2000. The
     refunds amounted to approximately $657,000 in 2003 and $582,000 in 2002.
     The Company has recorded approximately $4 million of electric plant in
     service for these PTF facilities, and a corresponding long-term payable of
     $3.7 million and $3.8 million has been recorded as of December 31, 2003 and
     2002, respectively. The long-term payable is included on the Consolidated
     Balance Sheets as a component of Other Long-term Liabilities.

Note 11.  Derivative Financial Instruments

     Effective January 1, 2001, the Company adopted Statement of Financial
     Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments
     and Hedging Activities," as amended by SFAS No. 138. This accounting
     standard requires that all derivative instruments be recorded on the
     balance sheet at fair value and establishes criteria for designation and
     effectiveness of hedging relationships. The effect of adopting this
     standard was not material to the Company's consolidated financial
     statements. The accounting for derivative financial instruments can change
     based on guidance received from the Derivatives Implementation Group (DIG).
     The DIG identifies practice issues that arise from applying the
     requirements of SFAS 133 and SFAS 138 and advises the Financial Accounting
     Standards Board on how to resolve those issues.

     Purchased Power Contracts - As discussed in Note 12 to the 2002 Form 10-K,
     the Company had two power contracts (one purchase and one sale) that
     qualified for derivative accounting under SFAS 133 and SFAS 138. The power
     sales contract ended in the first quarter of 2003, and hence there is no
     longer any SFAS No. 133 applicability. In connection with the power
     purchase contract, certain criteria that resulted in the contract
     qualifying for derivative accounting were also determined to no longer be
     applicable in 2003. As a result, the fair value of the above-market portion
     of these contracts, which represented a liability and corresponding
     regulatory asset of approximately $63.3 million at December 31, 2002,
     reflects a zero balance at December 31, 2003.

     Weather Hedge - In November 2002 the Company purchased a weather hedge for
     the 2002-2003 heating season. The hedge was designed to protect against the
     negative impacts of warmer than normal weather on the Company's electric
     operating revenues. The cost of the weather hedge was approximately
     $87,000, which was amortized over the 2002-2003 heating season. No income
     was recognized for this weather hedge in 2002 or 2003 due to the colder
     than normal weather. The fair value of this financial instrument at
     December 31, 2002 was de minimus.


Note 12.  Contingencies

     Environmental Matters - In 1992, the Company received notice from the Maine
     Department of Environmental Protection that it was investigating the
     cleanup of several sites in Maine that were used in the past for the
     disposal of waste oil and other hazardous substances, and that the Company,
     as a generator of waste oil that was disposed at those sites, may be liable
     for certain cleanup costs. The Company learned in October 1995 that the
     United States Environmental Protection Agency placed one of those sites on
     the National Priorities List under the Comprehensive Environmental
     Response, Compensation, and Liability Act and will pursue potentially
     responsible parties. With respect to this site, the Company is one of a
     number of waste generators under investigation.

     The Company has recorded a liability, based upon currently available
     information, for what it believes are the estimated environmental
     remediation costs that the Company expects to incur for this waste disposal
     site. Additional future environmental cleanup costs are not reasonably
     estimable due to a number of factors, including the unknown magnitude of
     possible contamination, the appropriate remediation methods, the possible
     effects of future legislation or regulation and the possible effects of


                                       41
<PAGE>

Note 12. Contingencies, Continued:

     technological changes. At December 31, 2003 and 2002, the liability
     recorded by the Company for its estimated environmental remediation costs
     amounted to approximately $340,000 and $411,000, respectively. The
     Company's actual future environmental remediation costs may be different,
     as additional factors become known.

Note 13.  New Accounting Pronouncement

     In June 2002, the Financial Accounting Standards Board issued Statement No.
     143, "Accounting for Asset Retirement Obligations". This Statement
     addresses financial accounting and reporting for obligations associated
     with the retirement of tangible long-lived assets and the associated asset
     retirement costs. It applies to legal obligations associated with the
     retirement of long-lived assets that result from acquisition, construction,
     development and (or) the normal operation of a long-lived asset, except for
     certain obligations of lessees. This Statement is effective for financial
     statements issued for fiscal years beginning after June 15, 2002.

     The implementation of this Statement did not materially impact the
     Company's financial position, earnings or cash flows, principally as a
     result of the regulatory accounting utilized by the Company. The Company
     recorded asset retirement obligations and associated long-lived assets in
     2003 principally associated with certain property and equipment where
     certain regulations require removal of these assets at a future date.

     The following represents a reconciliation of the beginning and ending
     aggregate carrying amounts of asset retirement obligations (Dollars in
     Thousands).


     Asset Retirement Obligation - January 1, 2003               $       393

     Liabilities Incurred in the Current Period                            -

     Liabilities Settled in the Current Period                             -

     Accretion Expense in the Current Period                              32

     Revisions in Estimated Cash Flows                                     -
                                                                    ---------
     Asset Retirement Obligation - December 31, 2003             $       425
                                                                    =========


                                       42
<PAGE>


[OBJECT OMITTED]

      Ernst & Young LLP                   Phone:(617) 266-2000
      200 Clarendon Street                Fax:  (617) 266-5843
      Boston, Massachusetts 02116-5072    www.ey.com



                    Report of Independent Auditors


To the Stockholders and Directors of
Bangor Hydro-Electric Company

We have audited the accompanying consolidated balance sheets of Bangor
Hydro-Electric Company as of December 31, 2003 and 2002, and related
consolidated statements of income, capitalization and cash flows for the years
then ended. 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 auditing standards generally accepted
in the 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. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes 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, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Bangor
Hydro-Electric Company at December 31, 2003 and 2002, and the consolidated
results of its operations and its cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States.


February 5, 2004



                                        /s/ Ernst & Young LLP


                                       43
<PAGE>

                                 CERTIFICATIONS


In connection with the Annual Financial Report of Bangor Hydro-Electric Company
(the Company) for the year ending December 31, 2003, we, the undersigned,
certify that:

     (1)  The information contained in the Report fairly presents, in all
          material respects, the financial condition and result of operations of
          the Company.



-------------------------------
David R. Black
Chief Financial Officer
February 20, 2004


-------------------------------
Raymond R. Robinson
Principal Executive Officer
February 20, 2004


                                       44
<PAGE>

I, David R. Black, certify that:

1.   I have reviewed this annual financial report of Bangor Hydro-Electric
     Company;

2.   Based on my knowledge, this annual financial report does not contain any
     untrue statement of a material fact or omit to state a material fact
     necessary to make the statements made, in light of the circumstances under
     which such statements were made, not misleading with respect to the period
     covered by this quarterly report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual financial report, fairly present in all
     material respects the financial condition, results of operations and cash
     flows of the Company as of, and for, the periods presented in this annual
     financial report;

4.   The Company's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures for the
     Company and we have:

     a)  designed such disclosure controls and procedures to ensure that
         material information relating to the registrant, including its
         consolidated subsidiaries, is made known to us by others within those
         entities, particularly during the period in which this annual financial
         report is being prepared;

     b)  evaluated the effectiveness of the registrant's disclosure controls and
         procedures as of a date within 90 days prior to the filing date of this
         annual financial report (the "Evaluation Date"); and

     c)  presented in this annual financial report our conclusions about the
         effectiveness of the disclosure controls and procedures based on our
         evaluation as of the Evaluation Date;

5.   The Company's other certifying officer and I have disclosed,
     based on our most recent evaluation, to the registrant's auditors
     and the audit committee of Company's board of directors (or
     persons performing the equivalent function):

     a)  all significant deficiencies in the design or operation of internal
         controls which could adversely affect the Company's ability to record,
         process, summarize and report financial data and have identified for
         the Company's auditors any material weaknesses in internal controls;
         and

     b)  any fraud, whether or not material, that involves management or other
         employees who have a significant role in the Company's internal
         controls; and

6.   The Company's other certifying officer and I have indicated in
     this annual financial report whether or not there were
     significant changes in internal controls or in other factors that
     could significantly affect internal controls subsequent to the
     date of our most recent evaluation, including any corrective
     actions with regard to significant deficiencies and material
     weaknesses.


Date: February 20, 2004


----------------------------
David R. Black
Chief Financial Officer


                                       45
<PAGE>

I, Raymond R. Robinson, certify that:

1.   I have reviewed this annual financial report of Bangor Hydro-Electric
     Company;

2.   Based on my knowledge, this annual financial report does not contain any
     untrue statement of a material fact or omit to state a material fact
     necessary to make the statements made, in light of the circumstances under
     which such statements were made, not misleading with respect to the period
     covered by this quarterly report;

3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual financial report, fairly present in all
     material respects the financial condition, results of operations and cash
     flows of the Company as of, and for, the periods presented in this annual
     financial report;

4.   The Company's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures for the
     Company and we have:

     c)  designed such disclosure controls and procedures to ensure that
         material information relating to the registrant, including its
         consolidated subsidiaries, is made known to us by others within those
         entities, particularly during the period in which this annual financial
         report is being prepared;

     d)  evaluated the effectiveness of the registrant's disclosure controls and
         procedures as of a date within 90 days prior to the filing date of this
         annual financial report (the "Evaluation Date"); and

     c)  presented in this annual financial report our conclusions
         about the effectiveness of the disclosure controls and
         procedures based on our evaluation as of the Evaluation Date;

5.   The Company's other certifying officer and I have disclosed, based on our
     most recent evaluation, to the registrant's auditors and the audit
     committee of Company's board of directors (or persons performing the
     equivalent function):

     a)  all significant deficiencies in the design or operation of internal
         controls which could adversely affect the Company's ability to record,
         process, summarize and report financial data and have identified for
         the Company's auditors any material weaknesses in internal controls;
         and

     b)  any fraud, whether or not material, that involves management or other
         employees who have a significant role in the Company's internal
         controls; and

6.   The Company's other certifying officer and I have indicated in this annual
     financial report whether or not there were significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.


Date: February 20, 2004


-------------------------------------
Raymond R. Robinson
Principal Executive Officer


                                       46

</TEXT>
</DOCUMENT>
