<DOCUMENT>
<TYPE>EX-99.3
<SEQUENCE>4
<FILENAME>ex99-3.txt
<DESCRIPTION>EXHIBIT H
<TEXT>

Exhibit H


2004 Nova Scotia Power Inc.
Management's Discussion & Analysis
As at February 11, 2005

Management's Discussion and Analysis ("MD&A") provides a review of the results
of operations of Nova Scotia Power Inc. ("Nova Scotia Power" or "NSPI") during
the fourth quarter of 2004 relative to 2003, the full year 2004 relative to 2003
and its financial position at December 31, 2004. Certain factors that may impact
future operations are also discussed. Such comments will be affected by, and may
involve, known and unknown risks and uncertainties that may cause the actual
results of the company to be materially different from those expressed or
implied. Those risks and uncertainties include, but are not limited to, weather,
commodity prices, interest rates, foreign exchange, regulatory requirements and
general economic conditions.

This discussion and analysis should be read in conjunction with the Nova Scotia
Power Inc. 2004 annual audited financial statements and supporting notes. NSPI's
accounting policies are subject to examination and approval by the Nova Scotia
Utility and Review Board ("UARB") and are similar to those being used by other
companies in the electric utility industry in Canada. As a result, the
rate-regulated accounting policies may differ from Canadian Generally Accepted
Accounting Principles ("GAAP") for non rate-regulated companies.

All amounts are in Canadian dollars.

Additional information related to Nova Scotia Power Inc. including the company's
Annual Information Form is available on SEDAR at www.sedar.com.



INTRODUCTION

Nova Scotia Power Inc., a wholly-owned subsidiary of Emera Inc., is a fully
integrated, regulated electric utility, with $3 billion of assets, serving
460,000 customers. NSPI is the primary electricity supplier in Nova Scotia,
providing the vast majority of the generation, transmission and distribution of
electricity in the province.

NSPI is a regulated monopoly which can generally be expected to result in
relatively stable earnings streams. Sustaining that privileged position depends
on continuing to satisfy customers with the right combination of price and
service quality. Accordingly, cost management, including generating capacity
management/asset utilization, reliability, quality customer service and
management of regulatory relationships are key success factors for NSPI's
business.

Overview

NSPI is the primary electricity supplier in Nova Scotia, providing over 95% of
the electricity generation, transmission and distribution in the province. The
company owns 2,293 megawatts ("MW") of generating capacity. Approximately 54% is
coal-fired; oil and natural gas fired facilities together comprise another 28%
of capacity; and hydro and wind production provide the remainder. In 2003, NSPI
contracted with an independent power producer for approximately 100 gigawatt
hours per year of wind power annually. NSPI also owns approximately 5,000
kilometres of transmission facilities, and 25,000 kilometres of distribution
facilities. The company has a workforce of approximately 1,600 people.

NSPI is a public utility as defined in the Public Utilities Act (Nova Scotia)
and is subject to regulation under the Act by the UARB. The Act gives the UARB
supervisory powers over NSPI's operations and


<PAGE>


expenditures. Electricity rates for NSPI's customers are also subject to UARB
approval. The company is not subject to an annual rate review process, but
rather participates in hearings from time to time at the company's or the
regulator's request.

Currently, NSPI's allowed return on common equity ("ROE") range is 9.9% to
10.4%. In 2004, NSPI earned within its allowed range. Equity is deemed to be 35%
of total capitalization for rate-making purposes, but the company is permitted
to maintain common equity up to 40%.

In 2004, NSPI filed for new rates, effective 2005, primarily to incorporate
substantially higher corporate taxes into its rate structure. The company
requested an additional $101.9 million in annual revenue, which translates to an
average rate increase of 12.4% for customers. NSPI requested a range of return
of 10.2% - 11.2% on a common equity component of 37.5%. Hearings were conducted
in November. In December, NSPI, with the support of several key stakeholders,
filed a negotiated Settlement Agreement with the UARB in connection with the
rate application. NSPI agreed to several concessions in the course of settlement
negotiations, including reducing its ROE request to a range of 9.3% to 10.3%,
and recovery of its pre-2003 income tax deposit over 17 years instead of the
seven years proposed in the original rate application. As a result, the proposed
Settlement Agreement reduces the average rate increase for customers to 7.3%.
Hearings into the proposed Settlement Agreement were held in early January. The
UARB is under no obligation to accept the Settlement Agreement. A decision on
the Rate Application/Settlement Agreement is pending.

In the meantime, beginning on January 1, 2005, the UARB has agreed to allow NSPI
to defer new taxes not presently in rates until rates allowed by the UARB in the
2005 Rate Application become effective. The amount of the deferral will be
determined after year end, and the period over which the deferral will be
amortized will be determined at that time.


Structure of MD&A

This annual MD&A has been prepared in accordance with the Canadian Securities
Administrators National Instrument 51-102 Management's Discussion & Analysis.

This Management's Discussion and Analysis begins with an overview of the
company's annual results then continues with significant changes in the balance
sheets, liquidity and capital resources, cash flow highlights, financial and
commodity instruments, transactions with related parties, critical accounting
estimates, changes in accounting policies, business risk and enterprise risk
management and selected quarterly trend information.


Significant Items

2004
There were no significant items in 2004.

2003
Unbilled revenue adjustment

The company recognizes electric revenues on the accrual basis, which includes an
estimate of electricity consumed by customers in the period but billed
subsequently ("unbilled revenue"). In Q2 2003, the company improved its process
for estimating its unbilled revenue. The change resulted in a $10.0 million
($6.5 million after tax) reduction in the unbilled revenue accrual, with a
corresponding charge against revenues.


                                                                               2

<PAGE>


Hurricane Juan

In Q3, 2003 Nova Scotia was struck by Hurricane Juan, a Category Two hurricane
causing extensive damage to Nova Scotia Power's transmission and distribution
system. The total cost of the hurricane to the company was $12.6 million,
specifically $4.0 million of net after-tax operating costs that were recorded in
Q3 2003, and $8.6 million in capital costs.

Site restoration costs

Prior to 2003, Nova Scotia Power estimated and accrued site restoration costs
for the Glace Bay generating station. The costs to complete the restoration were
expected to be $3.8 million lower than estimated. Nova Scotia Power reduced its
provision accordingly, with a corresponding reduction in depreciation expense in
Q4, 2003.

2002
Contract termination fee

In October 2002, as part of its decision on Nova Scotia Power's 2002 Rate
Application, the Nova Scotia Utility and Review Board disallowed recovery from
ratepayers of a $13.4 million contract termination fee paid to the Cape Breton
Development Corporation ("CBDC") in 2001 to terminate its coal supply contract,
which otherwise extended to 2010. As a result, NSPI expensed this fee in Q4,
2002.


Review of 2004

<TABLE>
<CAPTION>
                                          ------------------------- -------------------------
Net Earnings
                                                Three months ended                Year ended
(millions of dollars)                                  December 31               December 31
------------------------------------------------------------------- -------------------------
                                                     2004     2003     2004     2003    2002
-------------------------------------------------- ------- -------- -------- -------- -------
<S>                                             <C>      <C>      <C>     <C>      <C>
Electric revenue                                   $237.8   $231.2   $926.9   $895.6  $869.1
-------------------------------------------------- ------- -------- -------- -------- -------
Fuel for generation and purchased power              86.9     63.5    303.1    277.8   335.6
Operating, maintenance and general                   46.4     45.1    177.5    186.0   176.4
Provincial grants and taxes                           9.9      8.3     39.5     33.4    22.0
Depreciation                                         28.2     23.2    116.0    101.7   103.9
Regulatory amortization                               1.5      1.5      6.2      6.2     1.0
Other                                               (2.5)    (4.4)   (10.4)   (13.5)  (10.8)
-------------------------------------------------- ------- -------- -------- -------- -------
Earnings before the following                        67.4     94.0    295.0    304.0   241.0
Interest                                             24.6     26.6    100.1    104.3   109.6
Amortization of defeasance costs                      3.8      4.1     15.1     16.7    19.4
-------------------------------------------------- ------- -------- -------- -------- -------
Earnings before income taxes                         39.0     63.3    179.8    183.0   112.0
Income taxes                                         10.7     18.3     59.2     57.8    15.7
-------------------------------------------------- ------- -------- -------- -------- -------
Earnings before preferred dividends                  28.3     45.0    120.6    125.2    96.3
Preferred dividends                                   3.3      3.3     13.3     13.1    10.2
-------------------------------------------------- ------- -------- -------- -------- -------
Net earnings applicable to common shares            $25.0    $41.7   $107.3   $112.1   $86.1
-------------------------------------------------- ------- -------- -------- -------- -------
</TABLE>

NSPI's net earnings were $25.0 million in Q4, 2004, compared to $41.7 million in
Q4, 2003. The quarter over quarter change primarily reflects a $16.8 million
decrease in the electric margin as a result of higher fuel costs.

For the year ended December 31, 2004, NSPI's net earnings were $107.3 million,
compared to $112.1 million in 2003 and $86.1 million in 2002. Highlights of the
earnings changes are summarized in the following table:


                                                                               3

<PAGE>


<TABLE>
<CAPTION>
(millions of dollars)
-------------------------------------------------------------------------------------------------
<S>                                                                                    <C>
Net earnings, December 31, 2002                                                             $86.1
Increased electric revenues, reflecting 3% rate increase late in 2002                        36.5
Decreased fuel costs, including an additional $41.3 million of net gas sales proceeds        44.4
Increased provincial grants and taxes                                                      (11.4)
Increased amortization of Glace Bay generating station                                      (5.2)
Increased income taxes as NSPI becomes fully taxable                                       (42.1)
Decreased interest, reflecting $75 million equity infusion and debt refinancing               5.3
Write-off of CBDC contract termination fee in 2002                                           13.4
Adjustment to the company's unbilled revenues in 2003                                      (10.0)
Hurricane Juan operating expenses in 2003                                                   (6.0)
All other                                                                                     1.1
-------------------------------------------------------------------------------------------------
Net earnings, December 31, 2003                                                            $112.1
Increased electric revenues, largely reflecting load growth                                  21.3
Increased fuel expenses, due to reduced gas sales margin and higher coal costs in Q4       (25.3)
Increased depreciation, reflecting updated rates, and capital investment                   (14.3)
Increased provincial grants and taxes                                                       (6.1)
Adjustment to the company's unbilled revenues in 2003                                        10.0
Hurricane Juan operating expenses in 2003                                                     6.0
All other                                                                                     3.6
-------------------------------------------------------------------------------------------------
Net earnings, December 31, 2004                                                            $107.3
-------------------------------------------------------------------------------------------------
</TABLE>


Revenue

<TABLE>
Q4 Electric Sales Volume                          Q4 Electric Sales Revenues
(GWh)                                            (millions of dollars)
-----------------------------------------         ---------------------------------------
                   2004     2003     2002                         2004     2003     2002
--------------- -------- -------- --------        ------------ -------- -------- --------
<S>            <C>     <C>       <C>             <C>          <C>     <C>      <C>
Residential       1,052    1,049    1,066         Residential   $103.4   $102.8   $103.3
Commercial          754      744      733         Commercial      66.3     64.6     63.8
Industrial        1,068    1,037      988         Industrial      55.3     53.5     55.8
Other               153      119      164         Other           12.8     10.3     16.2
--------------- -------- -------- --------        ------------ -------- -------- --------
Total             3,027    2,949    2,951         Total         $237.8   $231.2   $239.1
--------------- -------- -------- --------        ------------ -------- -------- --------


YTD Electric Sales Volume                         YTD Electric Sales Revenues
(GWh)                                             (millions of dollars)
--------------- -------- ---------- ----------    ------------ -------- -------- --------
                   2004       2003       2002                     2004     2003     2002
--------------- -------- ---------- ----------    ------------ -------- -------- --------
Residential       4,039      3,819      3,835     Residential   $402.9   $375.8   $370.7
Commercial        2,965      3,001      2,818     Commercial     258.3    253.4    241.9
Industrial        4,196      4,091      3,786     Industrial     222.5    218.5    203.3
Other               473        586        767     Other           43.2     47.9     53.2
--------------- -------- ---------- ----------    ------------ -------- -------- --------
Total            11,673     11,497     11,206     Total         $926.9   $895.6   $869.1
--------------- -------- ---------- ----------    ------------ -------- -------- --------
</TABLE>

Q4 Average Revenue / MWh
--------------------------- ----------------------------
                      2004           2003          2002
--------------------------- ----------------------------
Dollars per MWh        $79            $78           $81
--------------------------- ----------------------------


YTD Average Revenue/ MWh
--------------------------- ----------------------------
                      2004           2003          2002
--------------------------- ----------------------------
Dollars per MWh        $79            $78           $78
--------------------------- ----------------------------


Electric sales volume is primarily driven by general economic conditions,
population and weather. Electricity pricing in Nova Scotia is regulated, and
therefore stays stable for extended periods of time,


                                                                               4

<PAGE>


only changing as new regulatory decisions are implemented. The exceptions are
Annually Adjusted Rates, subscribed to by larger industrial customers, which
apply to approximately 20% of NSPI sales volume; and export sales, which
typically comprise approximately 5% of NSPI sales volume, and are priced at
market. Of late, export sales have been lower as available capacity is used to
service in-province load. Residential and commercial electricity sales are
seasonal in Nova Scotia, with Q1 and Q4 the strongest periods, reflecting colder
weather, and fewer daylight hours in the winter season.

NSPI's residential load generally comprises individual homes, apartments and
condominiums. Commercial customers include everything from small retail
operations to large office and commercial complexes, and the province's
universities and hospitals. Industrial customers include manufacturing
facilities and other large volume operations. Other consists of export sales,
sales to municipal electric utilities and load from street lighting.

Electric revenues increased by $6.6 million to $237.8 million in Q4, 2004 from
$231.2 million for the same period in 2003. Sales volume increases are
substantially due to the expansion of a large industrial customer, and higher
exports.

For the year ended December 31, 2004, electric revenues increased $31.3 million
to $926.9 million from $895.6 million in 2003. Of the difference, $10.0 million
relates to a charge against revenue in the 2003 comparative amounts, due to an
adjustment to the company's unbilled revenue accrual. In addition to normal
growth, a cold Q1, 2004 increased sales volumes. Export sales volumes were
lower, as available capacity was used to service in-province load.

For the year ended December 31, 2003, electric revenues increased $26.5 million
to $895.6 million from $869.1 million in 2002. The revenue increase is primarily
due to the 3% rate increase, implemented in November 2002. The positive impact
of the price increase was partially offset by the adjustment to unbilled
revenue, which lead to a reallocation of revenue from residential to other
customer classes.

Outlook

In 2005, volume growth is expected to increase electric revenues by
approximately 2%. The overall revenue outlook is substantially dependent on the
outcome of the company's rate application. The magnitude of any approved
increase, as well as the timing of implementation will affect revenues, and
could have a material impact on earnings. The company is awaiting the decision
of its regulator in this matter.


Fuel for Generation and Purchased Power

Capacity

To ensure reliability of service, NSPI maintains a generating capacity greater
than firm peak demand. In 2004 a second LM6000 gas turbine, with a nameplate
capacity of 50 MW, was installed at the Tuft's Cove Plant. That brought the
total company owned generation capacity to 2,293 MW, which is supplemented by 25
megawatts contracted with independent power producers. NSPI meets the planning
criteria for reserve capacity established by the Maritime Control Area in order
to meet the North-East Power Coordinating Council criteria.

Management of capacity / capacity utilization is a critical element of operating
efficiency. The provision of sufficient generating capacity to meet peak demand
inevitably results in excess capacity in non-peak periods. NSPI's daily load is
highest in the early evening; its seasonal load is highest through the winter
months. Summer cooling load is not a significant factor. Maximizing capacity
utilization has a positive impact on earnings, and helps defer significant
investment in additional generation capacity. Maximizing capacity utilization
primarily depends on three factors:


                                                                               5

<PAGE>


          o    Moving demand from peak to non-peak periods - NSPI encourages
               customers to move some electricity demand from high cost to lower
               cost periods by offering customers various pricing alternatives.
               Energy taken under NSPI's residential Time of Use rate has
               increased by 7% from 2003, effectively shifting electric space
               heat load for these customers. NSPI offers the 2-Part Real-Time
               Pricing and the Extra Large Industrial Interruptible Rate
               ("ELIIR") to encourage industrial customers to maintain high load
               factors and shift load based on pricing signals. Over 300 MW of
               interruptible electric load exists.

          o    Increasing export sales - Increasing export sales when margins
               are satisfactory allows excess capacity to be sold when not
               required in province. In 2004 NSPI established a 24-hour energy
               marketing desk to optimize commercial opportunities for NSPI.

          o    Ensuring generating plants are consistently available to service
               demand - NSPI conducts ongoing planned maintenance programs, and
               has managed to sustain NSPI's high availability over the past
               several years. In addition, an indicator of the effectiveness of
               NSPI's plant maintenance is the company's improved unplanned
               outage rate, which was 2.7% in 2004 (2003 - 2.5%).


<TABLE>
<CAPTION>
NSPI Thermal Capacity Utilization
----------------- --------------- -------------- --------------- --------------- --------------
            1999            2000           2001            2002            2003           2004
----------------- --------------- -------------- --------------- --------------- --------------
<S>             <C>             <C>            <C>             <C>             <C>
             70%             74%            77%             77%             78%            82%
----------------- --------------- -------------- --------------- --------------- --------------
</TABLE>

NSPI's generating capacity utilization has grown 17% since 1999, from 70% to 82%
in 2004. That utilization is made possible by increased availability
performance, which reached 92% in 2004.

<TABLE>
<CAPTION>
NSPI Generating Capacity Availability
----------------- --------------- -------------- --------------- --------------- --------------
            1999            2000           2001            2002            2003           2004
----------------- --------------- -------------- --------------- --------------- --------------
<S>             <C>             <C>            <C>             <C>             <C>
             81%             88%            91%             91%             91%            92%
----------------- --------------- -------------- --------------- --------------- --------------
</TABLE>


Fuel Expense

Q4 Production Volume
(GWh)
------------------------------------------------------------
                       2004            2003            2002
------------------- -------- ------ -------- ----- ---------
Coal and petcoke      2,471           2,398           2,300
Natural gas              26              65             277
Oil                     433             288             222
Renewable               265             276             307
Purchased power          91             111              72
------------------- -------- ------ -------- ----- ---------
Total                 3,286           3,138           3,178
------------------- -------- ------ -------- ----- ---------


YTD Production Volume
(GWh)
------------------------------------------------------------
                       2004            2003            2002
------------------- -------- ------ -------- ----- ---------
Coal and petcoke      9,490           9,219           8,862
Natural gas              97             119           1,579
Oil                   1,698           1,536             288
Renewable               889           1,080           1,025
Purchased power         391             375             277
------------------- -------- ------ -------- ----- ---------
Total                12,565          12,329          12,031
------------------- -------- ------ -------- ----- ---------


                                                                               6

<PAGE>


Q4 Average Unit Fuel Costs
------------------- -------- ------ -------- ----- ---------
                       2004            2003            2002
------------------- -------- ------ -------- ----- ---------
Dollars per MWh         $26             $20             $31
------------------- -------- ------ -------- ----- ---------

YTD Average Unit Fuel Costs
------------------- -------- ------ -------- ----- ---------
                       2004            2003            2002
------------------- -------- ------ -------- ----- ---------
Dollars per MWh         $24             $23             $28
------------------- -------- ------ -------- ----- ---------


Coal is NSPI's dominant fuel source, supplying approximately 55% of the
company's annual generation. Petroleum coke ("petcoke") fuels approximately 21%
of generation. These solid fuels have the lowest per unit fuel cost, after hydro
and wind production, which have no fuel cost component. Oil and natural gas are
next, depending on the relative pricing. Purchased power is generally the most
expensive option. Economic dispatch of the generating fleet brings the lowest
cost options on stream first with the result that the incremental cost of
production increases as sales volume increases.

A substantial amount of NSPI's fuel supply comes from international suppliers,
and is subject to commodity price and foreign exchange risk. The company manages
exposure to commodity price risk utilizing a combination of physical fixed-price
fuel contracts and financial instruments providing fixed or maximum prices.
Foreign exchange risk is managed through forward and option contracts. Further
details on the company's fuel cost risk management strategies are included in
the Business Risks and Enterprise Risk Management section.

Fuel for generation and purchased power expense increased $23.4 million, or 37%,
to $86.9 million in Q4, 2004 compared to $63.5 million in the fourth quarter of
2003. Unit production costs increased 30%, from $20 per MWh in Q4, 2003 to $26
per MWh in Q4, 2004. This is substantially due to reduced gas resale margins
resulting from changes to the pricing structure in the supply contract; and
higher commodity prices, including costs to source replacement fuel associated
with a supplier's default on contracted deliveries.

For the year ended December 31, 2004 fuel for generation and purchased power was
$303.1 million, compared to $277.8 million in 2003, and $335.6 million in 2002.
Highlights of the year over year changes are summarized in the following table:

(millions of dollars)
-------------------------------------------------------------------------------
Fuel for generation and purchased power, December 31, 2002               $335.6
Higher net proceeds from resale of natural gas                           (41.3)
Increased production                                                       18.0
Lower commodity pricing                                                  (20.6)
Write off of CBDC contract termination fee in 2002                       (13.4)
All other                                                                 (0.5)
-------------------------------------------------------------------------------
Fuel for generation and purchased power, December 31, 2003               $277.8
Lower net proceeds from resale of natural gas                              32.0
Decreased export volumes                                                 (11.4)
Decreased renewable production volumes                                     11.9
Increased production                                                       16.9
Commodity pricing, including favourable exchange rates                   (16.7)
All other                                                                 (7.4)
-------------------------------------------------------------------------------
Fuel for generation and purchased power, December 31, 2004               $303.1
-------------------------------------------------------------------------------


                                                                               7

<PAGE>



Outlook

NSPI's fuel expense in 2005 in expected to be approximately $393 million. The
increase is primarily due to three factors:

     o    higher prices for coal and oil;

     o    an increase in the amount of higher cost, lower sulphur coal in the
          fuel mix to meet environmental requirements; and

     o    reduced net proceeds from the resale of natural gas due to the
          renegotiation of the supply contract.

Substantially all of these increased costs are addressed in NSPI's proposed rate
Settlement Agreement for 2005. A decision on the Rate Application/Settlement
Agreement is pending.


Operating, Maintenance and General Expenses

NSPI's operating, maintenance and general expenditures ("OM&G") were $46.4
million in Q4, 2004 compared to $45.1 million in Q4, 2003 primarily as a result
of higher storm related expenses. An increase in pension expense was
substantially offset by cost control in other areas.

For the year ended December 31, 2004, NSPI's OM&G expenditures were $177.5
million, compared to $186.0 million for 2003 and $176.4 million in 2002. OM&G
expenditures decreased $8.5 million in 2004 from 2003 levels primarily as a
result of a continued focus on controlling costs including labour and materials.
The increase in OM&G costs in 2003 over 2002 is driven by increased pension
costs and costs incurred during the repair and restoration work resulting from
Hurricane Juan.


Outlook

2005 OM&G expenditures are expected to be approximately $180 million.


Provincial Grants and Taxes

NSPI pays annual grants to the Province of Nova Scotia, in lieu of all municipal
taxation other than deed transfer tax. Provincial grants and taxes increased
$1.6 million in Q4, 2004, to $9.9 million, compared to $8.3 million in Q4, 2003.
The increase reflects the quarterly impact of the $4.6 million increase in
NSPI's annual provincial grants levied in the spring of 2003, which took effect
in Q1, 2004; and the increase in the provincial capital tax rate from 0.25% to
0.3%, effective April 1, 2004.

For the year ended December 31, 2004, provincial grants and taxes increased $6.1
million to $39.5 million compared to $33.4 million in 2003, reflecting the tax
increases referred to above. The 2003 amount was $11.4 million higher than 2002,
reflecting an additional tax increase of $11.0 million which took effect in Q1
2003.

Outlook

Provincial grants and taxes are expected to increase slightly in 2005,
reflecting the increase in the provincial capital tax rate and inflationary
adjustments.


                                                                               8

<PAGE>


Depreciation

Depreciation expense increased $5.0 million in Q4, 2004, to $28.2 million,
compared to $23.2 million in Q4, 2003. The quarter over quarter difference is
primarily due to a $3.8 million reduction in depreciation expense in Q4, 2003
because actual site restoration costs for the Glace Bay generating station were
lower than estimated.

For the year ended December 31, 2004, depreciation increased $14.3 million to
$116.0 million, compared to $101.7 million in 2003. The increase reflects the
change in depreciation rates approved by the UARB in its 2003 depreciation
order, the reduction in depreciation expense in Q4, 2003 noted above, and normal
increases due to planned capital spending. The 2003 amount was $2.2 million
lower than 2002, reflecting the $3.8 million reduction in depreciation expense
in Q4, 2003.

Outlook

During 2003, following completion of a depreciation study, and a negotiated
agreement with stakeholders, NSPI's regulator approved a $20 million increase in
annual depreciation expense, to be phased in over four years beginning in 2004.
Revised depreciation rates were incorporated in NSPI's rate application for
2005. As part of the proposed Settlement Agreement, NSPI has requested a
one-year delay in the phase-in of the new depreciation rates, which would amount
to approximately $5 million in depreciation expense. Under the Settlement
Agreement depreciation expense is expected to approximate $122 million in 2005.


Regulatory Amortization

The Glace Bay generating station has been permanently shut down and is being
written off through 2008, if required, at an annual minimum rate of $6.2
million. The amount remaining to be written off is $17.8 million. Regulatory
amortization is included in NSPI's revenue requirement.


Interest

Interest expense decreased $2.0 million, to $24.6 million in Q4, 2004 compared
to $26.6 million in Q4, 2003 due to the refinancing of a $140 million mid-term
note with short-term debt in 2004.

For the year ended December 31, 2004, interest expense decreased $4.2 million,
to $100.1 million compared to $104.3 million in 2003. This decrease is due to
the refinancing noted above. The 2003 amount was $5.3 million lower than 2002,
reflecting lower rates on debt refinanced and reduced debt levels as a result of
a $75 million common equity issue to Emera Inc. in December 2002.

The company manages exposure to interest rate risk through a combination of
fixed and floating borrowing, and hedging. Interest rate swaps are the principal
instrument used to hedge interest rate risk.

Outlook

In 2005, interest expense is expected to approximate 2004 levels.


                                                                               9

<PAGE>


Income Taxes

In accordance with ratemaking regulations established by the UARB, NSPI uses the
taxes-payable method of accounting for income taxes.

NSPI is subject to provincial capital tax (0.288%), large corporations tax
(0.2%), corporate income tax (38.12%) and Part VI.1 tax relating to preferred
dividends (40%).

In 2003, NSPI became fully taxable. Prior to that, NSPI used sufficient capital
cost allowance, cumulative eligible capital deductions and loss carry-forwards
to eliminate corporate income tax. As a result, through 2002 income tax costs
consisted only of Part VI.1 tax on NSPI preferred dividends.

NSPI had filed income tax returns for previous years to claim deductions related
to the capitalization of interest on assets constructed by its predecessor, Nova
Scotia Power Corporation ("NSPC"). The Canada Customs and Revenue Agency, (now
the Canada Revenue Agency ("CRA")) disallowed the deductions claimed, and NSPI
pursued the issue through to the Supreme Court of Canada ("the Supreme Court").
In June 2004 the Supreme Court dismissed Nova Scotia Power's appeal to allow
income tax deductions the company had claimed between 1998 and 2002. The
deductions represented approximately $129 million in income tax otherwise
payable ($150 million including interest).

NSPI deposited the amount owing with CRA in 2001 and 2003 in order to avoid
incurring non-deductible interest charges in the event its Supreme Court appeal
was unsuccessful. The UARB provided an accounting order allowing NSPI to defer
the amount while the matter was before the Supreme Court and recognized that
depending on the outcome, NSPI could apply to the UARB to amortize the deferred
amounts.

In its Rate Application for 2005, NSPI requested rates that would enable
amortization of the tax deposit over a seven-year period starting in 2005. In a
component of the proposed Settlement Agreement filed in December, NSPI proposes
the amortization period be extended to 17 years instead of the seven years
proposed in the original rate application, to reduce the impact on rates. The
UARB's decision is pending, and until such time, the deposit continues to be
deferred.

In the meantime, beginning on January 1, 2005, the UARB has agreed to allow NSPI
to defer new taxes not presently in rates until rates allowed by the UARB in the
2005 Rate Application become effective. The amount of the deferral will be
determined after year end, and the period over which the deferral will be
amortized will be determined at that time.

Balance Sheets

Balance Sheets
(millions of dollars)
-------------------------------------------------------------------------------
                                                     2004       2003      2002
-------------------------------------------------------------------------------
Assets
Current assets                                     $154.5    $ 189.6   $ 242.5
Deferred charges                                    390.0      399.0     256.3
Property, plant & equipment                       2,443.4    2,416.2   2,384.5
-------------------------------------------------------------------------------
                                                 $2,987.9   $3,004.8  $2,883.3
-------------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities                                $244.3    $ 296.3   $ 390.6
Asset retirement obligations and deferred            73.6       73.7      33.1
credits
Long-term debt                                    1,357.0    1,276.0   1,146.0
Preferred shares                                    260.0      260.0     260.0
Shareholders' equity                              1,053.0    1,098.8   1,053.6
-------------------------------------------------------------------------------
                                                 $2,987.9   $3,004.8  $2,883.3
-------------------------------------------------------------------------------


                                                                              10

<PAGE>


Significant changes in the balance sheets between December 31, 2003 and December
31, 2004 include:

     o    $35.1 million decrease in current assets due mostly to a $19.1 million
          decrease in accounts receivable, reflecting an increase in the amount
          of accounts receivable securitized, offset by an increase in sales and
          a $16.8 million decrease in inventory, reflecting a reduction in coal
          inventory levels.

     o    $9.0 million decrease in deferred charges, reflecting the amortization
          of defeasance costs and a decrease in deferred hedging premiums offset
          by an increase in pension contributions.

     o    $27.2 million increase in property, plant and equipment due to the
          acquisition of a 50 MW gas turbine generating unit and construction of
          a marine terminal offset by increased depreciation.

     o    $81.0 million increase in long-term debt is offset by the $40 million
          decrease in the current portion of long-term debt included in current
          liabilities. Overall debt level has increased due to increased capital
          spending.

     o    $45.8 million decrease in shareholders' equity due to increased
          dividend payments to bring the capital structure in line with approved
          levels.

Significant changes in the balance sheets between December 31, 2002 and December
31, 2003 include:

     o    $52.9 million decrease in current assets due mostly to a $15.5 million
          decrease in inventory, reflecting a reduction of coal inventory, and
          lower fuel prices and a decrease of $26.5 million in income taxes
          receivable.

     o    $142.7 million increase in deferred charges reflecting the pre-2003
          income tax deposit, partially offset by amortization of defeasance
          costs.

     o    $94.3 million decrease in current liabilities due to $120 million
          decrease in short-term debt reflecting increased long-term financing
          offset by $29.1 million increase in accounts payable and accrued
          charges reflecting increased fuel related payables.

     o    $31.7 million increase in property, plant and equipment and $40.6
          million increase in asset retirement obligations reflecting mostly the
          $43.9 million retroactive application of the new accounting standard
          relating to asset retirement obligations. Further details are included
          in the Change in Accounting Policies section.


Liquidity and Capital Resources

The company generates funds primarily through the generation, transmission and
distribution of electricity. Circumstances that could affect the company's
ability to generate funds include fuel commodity price changes, general economic
downturns in Nova Scotia and regulatory decisions affecting customer rates. In
addition to internally generated funds, the company has access to debt capital
markets, through operating lines of credit, an accounts receivable
securitization program and a commercial paper program. The company's financing
facilities are expected to provide sufficient access to money markets and
capital markets necessary to maintain acceptable levels of liquidity relative to
current cash forecasts. The company has filed a renewal preliminary debt shelf
prospectus in the amount of $400 million to provide the company with long-term
debt access.


Debt Management

In 2004, a $140.0 million 7.3% mid-term note matured and was refinanced with
short-term debt.

In 2003, a $150.0 million 7.7% debenture matured; and $300.0 million of
medium-term notes were issued, with the proceeds used to refinance the maturing
debenture, and pay down short-term debt.


                                                                              11

<PAGE>


The weighted-average coupon rate on NSPI's outstanding medium-term and debenture
notes at December 31, 2004, was 7.32% (2003 - 7.32%). Approximately 37% of the
debt matures over the next ten years; 59% matures between 2015 and 2036; and
$50.0 million, or 4% matures in 2097. The quoted market-weighted-average
interest rate for the same or similar issues of the same remaining maturities
was 5.14% as of December 31, 2004 (2003 - 5.39%).


NSPI has established the following available credit facilities:

<TABLE>
<CAPTION>
(millions of dollars)                                                       Maturity               Maximum Amount
--------------------------------------------------------------------- --------------------- ----------------------
<S>                                                                 <C>                   <C>
Short-term
Commercial paper, with 100% backup line of credit                       1 year revolving                   $350.0
Operating credit facility                                               1 year revolving                   $100.0
--------------------------------------------------------------------- --------------------- ----------------------
</TABLE>

NSPI has the following available credit ratings:

<TABLE>
<CAPTION>
                                           DBRS                          S&P                    Moodys
     --------------------------- ---------------------------- ------------------------- ------------------------
                                          2004          2003         2004         2003         2004        2003
     --------------------------- ---------------------------- ------------------------- ------------------------
<S>                             <C>                         <C>                       <C>
     Long term corporate               A (low)       A (low)         BBB+         BBB+           na          na
     Senior unsecured debt             A (low)       A (low)         BBB+         BBB+         Baa1        Baa1
     Preferred stock               Pfd-2 (low)   Pfd-2 (low)    P-2 (Low)    P-2 (Low)           na          na
     Commercial paper                R-1 (low)     R-1 (low)    A-1 (Low)    A-1 (Low)    P-2 (Baa)   P-2 (Baa)
     --------------------------- ---------------------------- ------------------------- ------------------------
</TABLE>


Based on the company's available credit and credit ratings, and past experience
in public financing since privatization, NSPI expects to have access to capital
when needed.


Accounts Receivable Securitization

NSPI has an agreement with an independent trust administered by a major Canadian
chartered bank whereby it can sell accounts receivable to the trust on a
revolving basis. As of December 31, 2004, the company had sold $80.0 million of
net accounts receivable (2003 - $50 million). The net proceeds from the sale
were used to repay a portion of the company's debt. The agreement is in place
until May 2009, with the intention that it will be renewed at that time.
Securitization provides NSPI with an alternative source of short-term funding.
For the year ended December 31, 2004, the average all-in cost of this funding
was 2.64% (2003 - 3.52%). In the event of termination of this arrangement NSPI
would utilize another liquidity facility to meet the ongoing operations of the
business.

Outlook

In May 2005, $100.0 million of NSPI's long-term debt will mature. The maturing
debt bears interest at 8.38%. Based on NSPI's credit rating and current market
conditions, NSPI expects to refinance this maturity in 2005 at favourable rates.
Pending a decision on its Rate Application/Settlement Agreement, NSPI's capital
structure is expected to remain essentially unchanged in 2005.


                                                                              12

<PAGE>


Off- Balance Sheet Arrangements

NSPI is responsible for managing a portfolio of approximately $1.1 billion of
defeasance securities held in trust, which arose in the course of the
privatization of the company in 1992. The defeasance securities must provide the
principal and interest streams of the related defeased debt. Approximately 69%,
or $735 million, of the defeasance portfolio consists of investments in the
related debt, eliminating all risk associated with this portion of the
portfolio, the remaining defeasance portfolio consists of investments with
market values higher than the related debt reducing the future risk of this
portion of the portfolio.


Cash Flow Highlights

<TABLE>
<CAPTION>
                                                -------------------------- --------------------
                                                       Three months ended           Year ended
(millions of dollars)                                         December 31          December 31
----------------------------------------------- -------------------------- --------------------
                                                        2004         2003       2004      2003
----------------------------------------------- ------------- ------------ ---------- ---------
<S>                                           <C>           <C>          <C>        <C>
Net cash provided by operating activities              $35.5        $66.6     $228.9    $177.6
Net cash provided by (used in) financing                 1.2      (163.0)     (84.5)    (96.0)
activities
Net cash used in investing activities                 (36.7)       (27.9)    (144.4)    (94.9)
----------------------------------------------- ------------- ------------ ---------- ---------
Decrease in cash and short-term investments               $-     $(124.3)         $-   $(13.3)
----------------------------------------------- ------------- ------------ ---------- ---------
</TABLE>

Significant changes in the cash flows between December 31, 2003 and December 31,
2004 include:

     o    Net cash provided by operating activities decreased by $31.1 million
          quarter over quarter due mostly to higher fuel costs. The increase
          year over year of $51.3 million reflects a total of $133.0 million
          deposited with CRA in 2003 relating to pre-2003 income taxes offset by
          higher fuel costs and increased income and capital tax installments in
          2004.

     o    Net cash used in financing activities decreased by $164.2 million
          quarter over quarter reflecting the 2003 debenture retirement of
          $150.0 million utilizing short-term investments. The decrease year
          over year of $11.5 million is due to increased long-term financing and
          use of accounts receivable securitization offset by increased dividend
          payments to bring the capital structure in line with approved levels.

     o    Net cash used in investing activities increased by $8.8 million
          quarter over quarter and $49.5 million year over year reflecting the
          acquisition of a 50 MW gas turbine generating unit and construction of
          a marine terminal.


Contractual Obligations

<TABLE>
<CAPTION>
(millions of dollars)
------------------------------- -------------------------------------------------------------
                                                   Payments Due by Period
------------------------------- -------------------------------------------------------------
                                                                                  After 2009
                                      Total         2005  2006-2007 2008-2009
------------------------------- ------------ ------------ --------- ---------- --------------
<S>                           <C>          <C>          <C>       <C>        <C>
Long-term debt                     $1,457.0       $362.0        $-     $240.0         $855.0
Operating leases                       31.1          5.2      10.4       10.4            5.1
Purchase obligations                1,810.1        385.8     458.5      393.9          571.9
Other long-term obligations           308.7            -       0.5          -          308.2
------------------------------- ------------ ------------ --------- ---------- --------------
Total contractual obligations      $3,606.9       $753.0    $469.4     $644.3       $1,740.2
------------------------------- ------------ ------------ --------- ---------- --------------
</TABLE>


                                                                              13

<PAGE>


Capital Expenditures

Capital expenditures amounted to $145 million in 2004, of which approximately
$34 million relates to the acquisition and installation of a second 50 MW LM6000
combustion turbine and approximately $27 million relates to spending on a marine
terminal to allow increased access to international coal basins. Despite
increased spending relating to storm damage, capital expenditures are basically
as previously estimated.

Outlook

NSPI's capital expenditure will be approximately $112 million in 2005, which
will be spent on planned and preventative maintenance and productivity related
investments. Financing for these expenditures is expected to come from a
combination of cash from operations and short-term debt.


Financial and Commodity Instruments

The company manages its exposure to foreign exchange, interest rate, and
commodity risks in accordance with established risk management policies and
procedures. The company uses derivative instruments consisting mainly of foreign
exchange forward contracts, interest options and swaps, and oil and gas options
and swaps.

Hedges that meet stringent documentation requirements, and can be proven to be
effective both at the inception and over the term of the instrument qualify for
hedge accounting. Specifically, amounts paid or received are deferred and
recognized in earnings in the same period the related hedged item is realized.
Where the documentation or effectiveness requirements are not met, the
non-qualifying hedges are marked to market and recognized in earnings in the
reporting period.

As at December 31, 2004, the company had deferred payments and receipts on
derivative instruments that are designated and effective as hedges and are
recognized in the following categories in the balance sheet:

Deferred Hedging Losses (Gains) Recognized on the Balance Sheet
(millions of dollars)
------------------------------------- ----------
Deferred charges                           $0.1
Inventory                                   1.6
Accounts payable and accrued charges      (0.3)
------------------------------------- ----------
Deferred hedging losses                    $1.4
------------------------------------- ----------

For the three-month period and year ended December 31, 2004 the impacts of
effective hedges recognized in earnings were recorded in the following
categories:

Hedging Impact Recognized in Earnings
(millions of dollars)
----------------------------------------- --------- --------
                                                Q4  YTD
                                              2004     2004
----------------------------------------- --------- --------
Fuel and purchased power increase           $(3.7)   $(4.9)
Interest expense increase                    (1.0)    (4.7)
----------------------------------------- --------- --------
Hedging earnings impact                     $(4.7)   $(9.6)
----------------------------------------- --------- --------

In addition, in Q4 2004 the company recognized mark-to-market losses in fuel and
purchased power expense of $3.3 million to bring the year to date impact to nil.

In determining the fair value of derivative financial instruments, the company
has relied on quoted market prices as of December 31, 2004.


                                                                              14

<PAGE>


Regulatory Developments

Beginning in 2003, NSPI implemented a stakeholder consultation process in an
effort to improve the efficiency and effectiveness of its regulatory process.
This new practice includes technical conferences with stakeholders, during which
information is exchanged, issues are identified and discussed, and where
possible proposals for resolution can be developed for consideration by the
UARB. In 2003, NSPI successfully used this process to resolve issues related to
the adoption of the Extra Large Industrial Interruptible Rate, Generic Rate
Design, depreciation, Annually Adjusted Rates, and the development of a two-part
Real Time Pricing (RTP) rate. In 2004, NSPI continued this approach in its Open
Access Transmission Tariff filing, new generation capacity process and its rate
application. Customers and other stakeholders including the UARB have publicly
complimented NSPI on this more consultative approach.

Outlook

Key elements of NSPI's regulatory plans for 2005 include:

     o    hearing for the Open Access Transmission Tariff filing;

     o    hearing regarding the November 2004 storm. The company is not able to
          forecast the outcome of this hearing at this time; and

     o    working with the UARB on its review to improve the regulatory process
          and make it more efficient and effective.


Transactions With Related Parties

The company enters into various transactions with its affiliates in the normal
course of operations. All transactions are recorded subject to terms in the Code
of Conduct, approved by the UARB, at the exchange value generally based on
normal commercial rates or as agreed to by the parties.

<TABLE>
<CAPTION>
Q4 Related Party Transactions
(millions of dollars)
------------------------------------- ------------------------------- ---------- ----------
Affiliate                             Purpose of Transaction               2004       2003
------------------------------------- ------------------------------- ---------- ----------
<S>                                <C>                              <C>        <C>
Emera Fuels                           Net purchase of bunker C oil         $1.1       $3.1
Emera Energy Services                 Net sale of gas and                 $36.3      $34.1
                                      electricity
Maritimes and Northeast Pipeline      Purchase of transportation           $4.1       $4.3
                                      capacity
Emera Utility Services                Purchase and maintenance of
                                      transformers                         $1.2       $1.4
Emera Inc. and affiliate under        Dividends paid                      $80.0         $-
common control
Emera Inc.                            Allocation of common costs           $1.1       $1.4
------------------------------------- ------------------------------- ---------- ----------

YTD Related Party Transactions
(millions of dollars)
------------------------------------- ------------------------------- ---------- ----------
Affiliate                             Purpose of Transaction               2004       2003
------------------------------------- ------------------------------- ---------- ----------
Emera Fuels                           Net purchase of bunker C oil         $8.6       $8.3
Emera Energy Services                 Net sale of gas and                $157.0     $104.8
                                      electricity
Maritimes and Northeast Pipeline      Purchase of transportation          $16.4      $17.0
                                      capacity
Emera Utility Services                Purchase and maintenance of
                                      transformers                         $4.6       $4.6
Emera Inc. and affiliate under        Dividends paid                     $153.1      $70.0
common control
Emera Inc.                            Purchase of LM6000 gas turbine      $22.1         $-
                                      Allocation of common costs           $5.8       $5.2
------------------------------------- ------------------------------- ---------- ----------
</TABLE>


                                                                              15

<PAGE>


The company also provide services to other various affiliates in the normal
course of operations amounting to $1.5 million (2003 - $1.0 million) and
receives services from other various affiliates in the normal course of
operations amounting to $3.5 million (2003 - $2.4 million).


Critical Accounting Estimates

The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities,
related amounts of revenues and expenses, and disclosure of contingent assets
and liabilities. Significant areas requiring the use of management estimates
relate to rate regulation, the determination of pension and other employee
benefits, unbilled revenue, asset retirement obligations and useful lives for
depreciable assets. Actual results may differ from these estimates.

Rate Regulation

NSPI's accounting policies are subject to examination and approval by the UARB.
As a result, NSPI's rate-regulated accounting policies may differ from
accounting policies for non rate-regulated companies. These differences
generally involve the timing of revenue and expense recognition.

The accounting for these items is based on an expectation of the future actions
of the regulator. For example, the company does not record future income taxes
as the taxes payable method is prescribed by the regulator for rate-making
purposes and there is reasonable expectation that the regulator will provide for
all such future income taxes to be recovered in rates when they become payable.
Similarly, the deferral of differences between the amounts included in rates and
actual experience for specified expenses is based on the expectation that the
regulator will approve the refund to or recovery from ratepayers of the deferred
balance.

If the regulator's future actions are different from the company's expectations,
the timing and amount of the recovery of liabilities and refund of assets,
recorded or unrecorded, could be significantly different from that reflected in
the financial statements.

Pension and Other Post-Retirement  Employee Benefits

The company provides post-retirement benefits to employees, including a defined
benefit pension plan. The cost of providing these benefits is dependent upon
many factors that result from actual plan experience and assumptions of future
experience.

The benefit cost and accrued benefit obligation for employee future benefits
included in annual compensation expenses are affected by employee demographics,
including age, compensation levels, employment periods, contribution levels and
earnings on plan assets.

Changes to the provisions of the plan may also affect current and future pension
costs. Benefit costs may also be significantly affected by changes in key
actuarial assumptions, including anticipated rates of return on plan assets and
discount rates used in determining the accrued benefit obligation and benefit
costs.

The pension plan assets are comprised primarily of equity and fixed income
investments. Fluctuations in actual equity market returns and changes in
interest rates may result in increased or decreased pension costs in future
periods.

The following table reflects the sensitivities associated with a change in
certain actuarial assumptions. If both the expected rate of return on plan
assets or the discount rate were increased by 0.5%, the


                                                                              16

<PAGE>


impact on the 2005 benefit cost and accrued benefit asset recorded in the year
end financial statements would be as follows:

(millions of dollars)                                                    2004
------------------------------------------------------------------------------
Impact of increasing the rate of return assumption by 0.5%
  Benefit cost                                                          $(2.7)
  Accrued benefit asset                                                  $2.7

Impact of increasing the discount rate assumption by 0.5%
   Benefit cost                                                         $(5.0)
   Accrued benefit asset                                                 $5.0
------------------------------------------------------------------------------

The discount rate is based on long-term Canadian corporate bonds, which have the
same duration as the accrued benefit obligation, as of the end of the fiscal
year rounded to the nearest 25 basis points. The rate was 6.0% for 2003 and
2004. The expected rate to be used for 2005 is also 6.0%.

The expected rate of return on plan assets is based on past performance and
economic forecasts for the types of investments held by the plan. The 2003 and
2004 benefit cost calculations assumed that plan assets would earn a rate of
return of 7.5%. The 2005 benefit cost calculation is expected to use the same
asset return assumption.

Unbilled Revenue

Approximately 75% of electric revenues are billed on a systematic basis over a
two-month period. At the end of each month the company must make an estimate of
energy delivered to customers since the date of their last meter reading and of
related revenues earned but not yet billed. The unbilled revenue is estimated
based on several factors including current month's generation, estimated
customer usage by class, weather, line losses and applicable customer rates.
Based on the extent of the estimates included in the determination of unbilled
revenue, actual results may differ from the estimate. As of December 31, 2004,
unbilled revenues amount to $65.8 million on a base of annual electric revenues
of approximately $930 million.

During 2003, the company improved its process for estimating its unbilled
revenue. The change resulted in reductions in unbilled revenue accruals and
related revenues of $10.0 million ($6.5 million after-tax).

Asset Retirement Obligations

The company recognizes asset retirement obligations for property, plant and
equipment in the period in which they are incurred if a reasonable estimate of
fair value can be determined. The fair value of the liability is described as
the amount at which the liability could be settled in a current transaction
between willing parties. Expected values are discounted at the risk-free
interest rate adjusted to reflect the market's evaluation of the company's
credit standing. Determining asset retirement obligations requires estimating
the life of the related asset and the costs of activities such as demolition,
dismantling, restoration and remedial work based on present day methods and
technologies.

In 2003, the UARB approved the amount of future expenditures associated with the
removal of generation facilities. The company believes that it will continue to
be able to recover asset retirement obligations through rates. Accordingly,
changes to the asset retirement obligations or cost recognition attributable to
changes in the factors discussed above, should not impact the results of
operations of the company.

At December 31, 2004, the asset retirement obligations recorded on the balance
sheet were $67.8 million (2003 - $64.4 million). The company estimates the
undiscounted amount of cash flow required to settle the obligations is
approximately $308.2 million, which will be incurred between 2007 and 2061. The
majority of these costs will be incurred between 2028 and 2039.


                                                                              17

<PAGE>


Property, Plant and Equipment

Property, plant and equipment represents 80% of total assets recognized on the
company's balance sheet. Included in property, plant and equipment are the
generation, transmission and distribution and other assets of the company. Due
to the size of the company's property, plant and equipment, changes in estimated
depreciation rates can have a significant impact on depreciation expense.

Depreciation is calculated on a straight-line basis over the estimated service
life of the asset. The estimated useful lives of the assets are based on formal
depreciation studies which are conducted from time to time. In 2002, NSPI
commissioned a Depreciation Study by an external consultant at the direction of
the UARB. The Study was filed with the UARB in 2003, following which a
stakeholder consultation process was conducted. A settlement agreement on the
matter was reached with all intervenors, which recommended an increase in
depreciation expense of $5.0 million per year beginning in 2004, to reach an
overall increase of $20 million by 2007. The UARB approved the settlement. The
next depreciation study is scheduled for 2006.


Change In Accounting Policies

In 2004, the company adopted the new accounting standard related to asset
retirement obligations and the new accounting guideline related to hedging
relationships. There were no changes in accounting policies in 2003.

Asset retirement obligations
In 2004, the company retroactively adopted the new accounting standard related
to asset retirement obligations. Previously the company had accrued its
obligations in annual increments based on the expected settlement date of the
obligation using estimated current costs. The new standard requires the company
to determine the fair value of the future expenditures required to settle legal
obligations to remove fixed assets. The present value of this estimated future
expenditure is recognized as a liability with an equivalent amount added to the
carrying amount of the associated fixed asset.

As a result of adopting the new standard, as at December 31, 2003, property,
plant and equipment and asset retirement obligations have increased by $43.9
million. The impact to 2004 net earnings was a decrease in depreciation expense
of $0.4 million (2003 - nil).

Some of the company's transmission and distribution assets may also have asset
retirement obligations. As the company expects to use the majority of these
installed assets for an indefinite period, no removal date can be determined and
consequently a reasonable estimate of the fair value of any related asset
retirement obligation cannot be made at this time.

Rate-regulated accounting:
Any difference between the amount approved by the UARB as depreciation expense
and the amount that would have been calculated under the new accounting standard
is recognized as a regulatory asset in property, plant and equipment.
Differences are deferred and will be included in future depreciation studies.

Hedging relationships
In 2004, the company prospectively adopted the new accounting guideline related
to hedging relationships. The company is now documenting and testing the
effectiveness of its hedging relationships in accordance with the new guideline.
Where the new requirements are not met, the hedging items are marked to market.
The adoption of this guideline had no impact on 2004 net earnings.


                                                                              18

<PAGE>


Business Risks and Enterprise Risk Management

Risk Management

The company's risk management activities are focused on those areas that most
significantly impact profitability and quality of earnings. These risks include,
but are not limited to, exposure to commodity prices, foreign exchange, credit
risk and interest rates.

Commodity Prices

Substantially all of the company's annual fuel requirement for 2005 is subject
to fluctuations in commodity market prices, prior to any commodity price risk
management activities.

Coal / Petroleum Coke

Substantially all of the company's coal supply comes from international
suppliers at prevailing market prices. The company has entered into fixed-price
contractual arrangements with several coal suppliers to ensure reliability of
both fuel supply and price. Physical contracts are used to hedge coal price risk
due to the lack of liquidity in the financial markets for coal. Approximately
85% of coal and petroleum coke requirements for 2005 had been contracted as at
December 31, 2004.

Heavy Fuel Oil

Nova Scotia Power manages exposure to changes in the market price of heavy fuel
oil through the use of swaps, options and futures contracts. As at December 31,
2004, the price for approximately 50% of heavy fuel oil purchases for 2005 had
been contracted.

Natural Gas

The company has entered into two multi-year contracts to purchase approximately
65 million cubic feet of natural gas per day. One contract that covers over 60
million cubic feet per day was subject to a price reopening in Q4, 2004 and is
currently in arbitration. It is anticipated that the outcome will result in the
majority of gas volumes under this contract being more exposed to market
fluctuations. The volumes exposed to market prices will be managed using
financial instruments where required for generation; and sold against floating
market prices where available for resale. Fixed price gas volumes not required
for generation will be resold into the gas market with the margin managed also
using financial instruments. Approximately 70% of 2005 gas sales and purchases
had been contracted as of December 31, 2004.

Fuel Mix

The risk inherent in the Canadian dollar cost of fuel is measured and managed on
a portfolio basis. The ability to switch fuel provides a dynamic, operational
and effective option in managing commodity price and supply risk.

Foreign Exchange

In 2005, the company expects approximately 80% of its anticipated net fuel costs
to be denominated in U.S. dollars, as $US income from sales of surplus natural
gas will provide a natural hedge against a portion of $US denominated fuel
costs. Forward and option contracts are used to manage the exposure to
fluctuating $US exchange rates. Forward contracts are in place for approximately
65% of 2005 anticipated $US net fuel costs.


                                                                              19

<PAGE>


Interest Rates

Nova Scotia Power manages interest rate risk through a combination of fixed and
floating borrowing and a hedging program. Prior to hedging, floating rate debt
is estimated to represent approximately 18% of total debt in 2004. Interest
forward rate agreements and swaps are used to fix rates on part of the floating
rate debt, while interest rate caps are used to limit exposure to movements of
interest rates on floating debt. For 2005, interest on approximately 17% of the
company's anticipated floating debt is fixed through swap contracts at an
average rate of 6.81% and another 34% is capped at a rate of 3.45%.

Interest rate collars are used to partially hedge reinvestment risk on long-term
fixed-rate debt. Fixed-rate debt maturities are limited in any one year and are
continually monitored to reduce rollover exposure. For 2005 approximately 25% of
the company's maturing long-term fixed rate debt has been collared with rates of
4.89% - 5.30%.

Credit Risk

Credit risk arising as a result of contractual obligations between the
corporation and other counterparties is managed by assessing the counterparties'
financial creditworthiness prior to assigning credit limits based upon Board of
Directors approved credit policies. The corporation frequently uses master
agreements to further mitigate credit exposure.

Regulatory Risk

In December 2001 the Nova Scotia government released Seizing the Opportunity:
Nova Scotia's Energy Strategy. The strategy for the electricity industry is to
carefully increase competition over a prudent time frame. In addition,
consistent with recommendations put forward by Emera, the strategy indicates
government will provide policy direction to the UARB to authorize open access
transmission on NSPI facilities, and introduce competition in the wholesale
market by 2005. The wholesale market comprises six municipal electric utilities,
and represents approximately 1.6% of NSPI's revenues. These two recommendations
will help Nova Scotia meet United States and other Canadian market reciprocity
requirements, and thus facilitate electricity exports.

An Electricity Marketplace Governance Committee ("EMGC") was established, to
recommend to the Minister of Energy the implementation, development, structure
and rules for the future electricity sector. During 2003, EMGC concluded its
work and the Nova Scotia Government has accepted its recommendations in
principal. Its report provides no material change to the Province's energy
strategy.

Broader restructuring of the electricity industry in Nova Scotia is not on the
horizon in the medium term. The province's geographic location, the limits of
inter-provincial transmission links, and the diversity of our customer base will
help to reduce the impact of a more significant move to restructuring on NSPI.
In addition, the company is committed to enhancing its strong competitive and
financial position by:

     o    managing costs through enhanced capacity management, reduced fuel and
          operating costs and efficient capital investment;

     o    working with customers to help them reduce energy costs, including
          providing them with greater access to time-of-use pricing; and

     o    continuously improving customer service.

Labour

In June 2004, NSPI reached a fifty-two month agreement with 800 employees. This
brings labour stability to the organization well into 2007.


                                                                              20

<PAGE>


Environmental Protection

Environmental Governance
NSPI is committed to meeting its business objectives in a manner that is
respectful and protective of the environment, and in full compliance with legal
requirements and company policy. For several years, NSPI has implemented this
policy through development and application of environmental management systems
("EMS"). The program continued in 2004 with alignment of EMS objectives across
NSPI.

Conformance with legislative and company requirements is verified through an
extensive environmental audit program. The 2004 program, which included three
NSPI operating areas, maintained an objective to review all operations within a
three-year cycle. Where non-conformity is identified, effective action
strategies are developed and implementation closely monitored.

Atmospheric Emissions
In 2004, the government of Nova Scotia proposed a number of amendments to the
Air Quality Regulations under the Nova Scotia Environment Act. Beginning in
2005, and through the end of the decade, the amendments require substantial
reductions of sulphur dioxide (SO2), oxides of nitrogen (NOx) and mercury
emitted from Nova Scotia Power facilities. NSPI will meet its 2005 limits, and
implementation plans are being prepared to address medium term requirements
based on an Air Emissions Strategy which comprehensively deals with the entire
suite of air emissions, including those linked to climate change.

When the Canadian government ratified the Kyoto Protocol, it set an aggressive
greenhouse gas reduction target for the country. NSPI supports prudent Canadian
abatement efforts and continues to work with federal and provincial governments
to develop an implementation plan that considers the potential impacts on the
company and its customers.


Summary of Quarterly Results

For the quarter ended
(millions of dollars)
------------------------------------------------------------------------------
                                     Total Revenues   Net earnings applicable
                                                          to common shares
------------------------------------------------------------------------------
December 31, 2004                            $239.0                     $25.0
September 30, 2004                           $213.4                     $18.5
June 30, 2004                                $222.3                     $25.0
March 31, 2004                               $259.4                     $38.8

December 31, 2003                            $234.8                     $41.7
September 30, 2003                           $213.1                     $11.6
June 30, 2003                                $201.9                     $12.9
March 31, 2003                               $254.8                     $45.9
------------------------------------------------------------------------------


                                                                              21

<PAGE>


Quarterly revenues and quarterly net earnings applicable to common shares are
affected by seasonality, with Q1 and Q4 the strongest periods, reflecting colder
weather and fewer daylight hours at those times of the year.

2003 quarterly net earnings applicable to common shares were also affected by
the following:

     o    In Q2, the company improved its process for estimating its unbilled
          revenue. The change resulted in reductions in unbilled revenue
          accruals of $10.0 million ($6.5 million after-tax).

     o    In Q3, Nova Scotia was struck by Hurricane Juan, a Category Two
          hurricane causing extensive damage to NSPI's transmission and
          distribution system. The total cost of the hurricane was $12.6
          million, specifically $6.0 million of operating costs ($4.0 million
          after-tax) and $8.6 million in capital costs.

     o    In Q4, the company revised its site restoration accrual for the Glace
          Bay generating station as the actual costs were expected to be lower
          than estimated. As a result, depreciation expense was decreased by
          $3.8 million ($3.8 million after-tax).


                                                                              22

<PAGE>



                             NOVA SCOTIA POWER INC.

                              FINANCIAL STATEMENTS

                           DECEMBER 31, 2004 AND 2003



<PAGE>


                                MANAGEMENT REPORT

Management's Responsibility for Financial Reporting

The accompanying financial statements of Nova Scotia Power Inc. ("Nova Scotia
Power" or "NSPI") and the information in this annual report are the
responsibility of management and have been approved by the Board of Directors
("Board").

The financial statements have been prepared by management in accordance with
Canadian generally accepted accounting principles. When alternative accounting
methods exist, management has chosen those it deems most appropriate in the
circumstances. Nova Scotia Power Inc. is regulated by the Nova Scotia Utility
and Review Board, which also examines and approves NSPI's accounting policies
and practices. In preparation of these financial statements, estimates are
sometimes necessary when transactions affecting the current accounting period
cannot be finalized with certainty until future periods. Management believes
that such estimates, which have been properly reflected in the accompanying
financial statements, are based on careful judgements and are within reasonable
limits of materiality. Management has determined such amounts on a reasonable
basis in order to ensure that the financial statements are presented fairly in
all material respects. Management has prepared the financial information
presented elsewhere in the annual report and has ensured that it is consistent
with that in the financial statements.

Nova Scotia Power Inc. maintains effective systems of internal accounting and
administrative controls, consistent with reasonable cost. Such systems are
designed to provide reasonable assurance that the financial information is
relevant, reliable and accurate and that Nova Scotia Power Inc.'s assets are
appropriately accounted for and adequately safeguarded.

The Board is responsible for ensuring that management fulfils its
responsibilities for financial reporting and is ultimately responsible for
reviewing and approving the financial statements. The Board carries out this
responsibility principally through its Audit Committee.

The Audit Committee is appointed by the Board, and its members are directors who
are not officers or employees of Nova Scotia Power Inc. The Committee meets
periodically with management, as well as with the internal auditors and with the
external auditors, to discuss internal controls over the financial reporting
process, auditing matters and financial reporting issues, to satisfy itself that
each party is properly discharging its responsibilities, and to review the
annual report, the financial statements and the external auditors' report. The
Audit Committee reports its findings to the Board for consideration when
approving the financial statements for issuance to the shareholders. The
Committee also considers, for review by the Board and approval by the
shareholders, the appointment of the external auditors.

The financial statements have been audited by Grant Thornton LLP, the external
auditors, in accordance with Canadian generally accepted auditing standards.
Grant Thornton LLP has full and free access to the Audit Committee.

January 31, 2005


"Chris Huskilson"                                   "Randy Henderson, CA"
President and Chief Executive Officer               Senior Vice President and
                                                    Chief Financial Officer


<PAGE>



                                AUDITORS' REPORT

To the Shareholders of Nova Scotia Power Inc.

We have audited the balance sheets of Nova Scotia Power Inc. as at December 31,
2004 and 2003 and the statements of earnings, retained earnings 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 audit.

We conducted our audit in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance 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.

In our opinion, these financial statements present fairly, in all material
respects, the financial position of the Company as at December 31, 2004 and 2003
and the results of its operations and its cash flows for the years then ended in
accordance with Canadian generally accepted accounting principles.





Halifax, Canada
January 31, 2005


"Grant Thornton LLP"
Chartered Accountants


<PAGE>


NOVA SCOTIA POWER INC.
STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
For the year ended December 31
(millions of dollars)
------------------------------------------------------------------------------------------
                                                                  2004               2003
                                                                          (restated - see
                                                                                  note 3)
--------------------------------------------------- ------------------- ------------------
<S>                                               <C>                 <C>
Revenue
    Electric                                                    $926.9             $895.6
    Other                                                          7.2                9.0
--------------------------------------------------- ------------------- ------------------
                                                                 934.1              904.6
--------------------------------------------------- ------------------- ------------------
Cost of operations
    Fuel for generation and purchased power                      303.1              277.8
    Operating, maintenance and general                           177.5              186.0
    Provincial grants and taxes                                   39.5               33.4
    Depreciation                                                 116.0              101.7
--------------------------------------------------- ------------------- ------------------
                                                                 636.1              598.9
--------------------------------------------------- ------------------- ------------------
Earnings from operations                                         298.0              305.7
Regulatory amortization                                          (6.2)              (6.2)
Allowance for funds used during construction                       3.2                4.5
--------------------------------------------------- ------------------- ------------------
Earnings before the following                                    295.0              304.0
Interest (note 6)                                                100.1              104.3
Amortization of defeasance costs                                  15.1               16.7
--------------------------------------------------- ------------------- ------------------
Earnings before income taxes                                     179.8              183.0
Income taxes (note 7)                                             59.2               57.8
--------------------------------------------------- ------------------- ------------------
Net earnings before preferred dividends                          120.6              125.2
Preferred dividends (note 7)                                      13.3               13.1
--------------------------------------------------- ------------------- ------------------
Net earnings applicable to common shares                        $107.3             $112.1
--------------------------------------------------- ------------------- ------------------
</TABLE>
See accompanying notes to the financial statements.


STATEMENTS OF RETAINED EARNINGS

<TABLE>
<CAPTION>
For the year ended December 31
(millions of dollars)
------------------------------------------------------------------------------------------
                                                                  2004               2003
                                                                          (restated - see
                                                                                  note 3)
--------------------------------------------------- ------------------- ------------------
<S>                                               <C>                 <C>
Retained earnings, beginning of year                            $268.2             $226.1
Net earnings applicable to common shares                         107.3              112.1
--------------------------------------------------- ------------------- ------------------
                                                                 375.5              338.2
Dividends                                                        153.1               70.0
--------------------------------------------------- ------------------- ------------------
Retained earnings, end of year                                  $222.4             $268.2
--------------------------------------------------- ------------------- ------------------
</TABLE>

See accompanying notes to the financial statements.


<PAGE>


NOVA SCOTIA POWER INC.
BALANCE SHEETS

<TABLE>
<CAPTION>
As at December 31
(millions of dollars)
------------------------------------------------------------------------------------------
                                                                  2004               2003
                                                                          (restated - see
                                                                                  note 3)
--------------------------------------------------- ------------------- ------------------
<S>                                               <C>                 <C>
Assets
Current assets
    Accounts receivable (note 8)                                 $68.9              $88.0
  Due from associated companies (note 9)                          13.9               12.7
  Income taxes receivable                                          0.2                  -
    Fuel inventory                                                41.6               57.2
  Materials and supplies inventory                                25.4               26.6
    Prepaid expenses                                               4.5                5.1
--------------------------------------------------- ------------------- ------------------
                                                                 154.5              189.6
--------------------------------------------------- ------------------- ------------------
Deferred charges (note 10)                                       390.0              399.0
--------------------------------------------------- ------------------- ------------------
Property, plant & equipment (note 11)                          2,385.5            2,379.3
Construction work in progress                                     57.9               36.9
--------------------------------------------------- ------------------- ------------------
                                                               2,443.4            2,416.2
--------------------------------------------------- ------------------- ------------------
                                                              $2,987.9           $3,004.8
--------------------------------------------------- ------------------- ------------------


Liabilities & Shareholders' Equity
Current liabilities
    Current portion of long-term debt (note 13)                 $100.0             $140.0
    Short-term debt (note 14)                                      4.7                7.1
    Accounts payable and accrued charges                         136.4              144.4
    Income taxes payable                                             -                1.6
    Dividends payable                                              3.2                3.2
--------------------------------------------------- ------------------- ------------------
                                                                 244.3              296.3
--------------------------------------------------- ------------------- ------------------
Asset retirement obligations (note 12)                            67.8               64.4
--------------------------------------------------- ------------------- ------------------
Deferred credits (note 10)                                         5.8                9.3
--------------------------------------------------- ------------------- ------------------
Long-term debt (note 13)                                       1,357.0            1,276.0
--------------------------------------------------- ------------------- ------------------
Preferred shares (note 15)                                       260.0              260.0
--------------------------------------------------- ------------------- ------------------
Shareholders' equity
    Common shares (note 16)                                      830.6              830.6
    Retained earnings                                            222.4              268.2
--------------------------------------------------- ------------------- ------------------
                                                               1,053.0            1,098.8
--------------------------------------------------- ------------------- ------------------
                                                              $2,987.9           $3,004.8
--------------------------------------------------- ------------------- ------------------
</TABLE>

See accompanying notes to the financial statements.

Contingency (note 10)
Commitments (note 20)
Guarantees (note 21)




Approved on behalf of the Board of Directors


"Derek Oland"                              "Chris Huskilson"


Derek Oland,                               Chris Huskilson,
Chairman                                   President and Chief Executive Officer


<PAGE>


NOVA SCOTIA POWER INC.
STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
For the year ended December 31
(millions of dollars)
------------------------------------------------------------------------------------------
                                                                  2004               2003
                                                                          (restated - see
                                                                                  note 3)
--------------------------------------------------- ------------------- ------------------
<S>                                               <C>                 <C>
Operating Activities
    Cash received from customers                                $922.2             $921.7
    Cash paid to suppliers and employees                       (506.1)            (453.8)
    Cash paid to preferred shareholders                         (14.1)             (14.1)
--------------------------------------------------- ------------------- ------------------
Cash provided by operations, before interest and                 402.0              453.8
taxes
    Interest paid                                              (104.1)             (99.0)
    Income and capital taxes paid                               (69.0)             (44.2)
    Pre-2003 income tax assessment                                   -            (133.0)
--------------------------------------------------- ------------------- ------------------
Net cash provided by operating activities (note 22)              228.9              177.6
--------------------------------------------------- ------------------- ------------------

Financing Activities
    Retirements of long-term debt                              (140.0)            (150.0)
    Issue of long-term debt                                          -              300.0
    Increase (decrease) in short-term debt                       178.6            (145.0)
    Dividends paid on common shares                            (153.1)             (70.0)
    Other financing activities                                    30.0             (31.0)
--------------------------------------------------- ------------------- ------------------
Net cash used in financing activities                           (84.5)             (96.0)
--------------------------------------------------- ------------------- ------------------

Investing Activities
    Property, plant and equipment                              (142.5)             (94.0)
    Cost of removal, net of salvage                              (1.9)              (0.9)
--------------------------------------------------- ------------------- ------------------
Net cash used in investing activities                          (144.4)             (94.9)
--------------------------------------------------- ------------------- ------------------
Decrease in cash and cash equivalents                                -             (13.3)
Cash and cash equivalents, beginning of year                         -               13.3
--------------------------------------------------- ------------------- ------------------
Cash and cash equivalents, end of year                              $-                 $-
--------------------------------------------------- ------------------- ------------------
</TABLE>

See accompanying notes to the financial statements.


<PAGE>


NOVA SCOTIA POWER INC.
NOTES TO THE FINANCIAL STATEMENTS

December 31, 2004

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     Nova Scotia Power Inc. ("NSPI", "Nova Scotia Power", or the "Company"),
     incorporated in the Province of Nova Scotia, is engaged in the production
     and sale of electric energy, and is regulated by the Nova Scotia Utility
     and Review Board ("UARB"). The financial statements of the Company are
     prepared in accordance with Canadian generally accepted accounting
     principles ("GAAP").

     a.   Regulated Accounting

          The Company's accounting policies are subject to regulation by the
          Nova Scotia Utility and Review Board. The UARB exercises statutory
          authority over matters such as construction, rates and underlying
          accounting practices. In order to recognize the economic effects of
          the actions of the regulator, the timing of recognition of certain
          revenues and expenses in these operations may differ from that
          otherwise expected under generally accepted accounting principles.
          Where these differences are considered significant, disclosure of the
          policy has been made in these notes to the financial statements.

     b.   Measurement Uncertainty

          The preparation of financial statements in accordance with generally
          accepted accounting principles requires management to make estimates
          and assumptions that affect the reported amounts of assets and
          liabilities at the date of the financial statements and the reported
          amounts of revenues and expenses during the reporting periods.

          At the end of each month, amounts of energy delivered to customers
          since the date of their last meter reading are estimated along with
          the associated unbilled revenues. This estimate is based on several
          different factors including generation, estimated usage by customer
          class, weather and line losses.

          Actual results may differ from these estimates.

     c.   Revenue Recognition

          The Company's revenue recognition policies are as follows:

               o    Electric revenues are recognized on the accrual basis, which
                    includes an estimate of electricity consumed by customers in
                    the year but billed subsequent to year-end.

               o    Other revenues are recognized on the accrual basis, which
                    includes an estimate for services performed and goods
                    delivered during the year but billed subsequent to year-end.
                    Unearned revenue is recorded as a deferred credit.

     d.   Regulatory Amortization

          In accordance with regulations of the UARB, significant assets of
          NSPI, which are not currently being used and are not expected to
          provide service to customers in the foreseeable future are amortized
          over five years. In 2000 the UARB approved NSPI's request to amortize
          the Glace Bay generating station over five years. The UARB had allowed
          Nova Scotia Power flexibility in determining the annual amount to be
          written off in order to support rate stability. On July 28, 2003 the
          UARB approved the Company's request to extend the write-off period
          through 2008, if necessary, with an annual minimum amortization of
          $6.2 million.


<PAGE>


     e.   Property, Plant and Equipment

          Property, plant and equipment are recorded at original cost net of
          contributions in aid of construction. When depreciable property, plant
          and equipment are replaced or retired, the original cost plus any
          removal costs incurred (net of salvage) are charged to accumulated
          depreciation, with no gain or loss reflected in results of operations.
          Gains and losses will be charged to results of operations in the
          future through depreciation expense.

          During construction, regulated operations capitalize to the cost of
          the asset constructed an allowance for funds used ("AFUDC") using the
          Company's weighted average cost-of-capital. This AFUDC will be charged
          to operations through depreciation over the service life of the
          related assets.

          Depreciation is normally calculated on a straight-line basis over the
          estimated service lives of the assets. The service lives of regulated
          assets are determined based on formal depreciation studies which
          require UARB approval.

          During 2003, following completion of a depreciation study, and a
          negotiated agreement with stakeholders, NSPI's regulator approved new
          depreciation rates which will be phased in over four years beginning
          in 2004. Depreciation is now computed on the straight-line basis over
          the estimated remaining service lives of depreciable assets in each
          category based on the phase-in period contained within the settlement
          agreement. Depreciation expense will increase by $5.0 million per year
          beginning in 2004, to reach an overall increase of $20.0 million by
          2007.

          When indicators of impairment exist, NSPI determines whether the net
          carrying amount of property, plant and equipment is recoverable from
          future undiscounted cash flows. Factors, which could indicate an
          impairment exists include significant changes in regulation, a change
          in the Company's strategy or underperformance relative to projected
          future operating results.

     f.   Income Taxes and Investment Tax Credits

          In accordance with the ratemaking policies established by the UARB,
          income taxes on earnings are determined using the taxes-payable method
          of accounting. Accordingly, NSPI does not provide for future income
          taxes.

          Investment tax credits arise as a result of incurring qualifying
          scientific research and development expenditures and are recorded in
          the year as a reduction from the related expenditures where there is
          reasonable assurance of collection.

     g.   Employee Future Benefits

          Pension obligations, and obligations associated with non-pension
          post-retirement benefits such as health benefits to retirees and
          retirement awards, are actuarially determined using the projected
          benefit method prorated on services and management's best estimate
          assumptions. The accrued benefit obligation is valued based on market
          interest rates at the valuation date.

          Pension fund asset values are calculated using market values at
          year-end. The expected return on pension assets is determined based on
          market-related values. The market-related values are determined in a
          rational and systematic manner so as to recognize asset gains and
          losses over a five-year period.

          Adjustments to the accrued benefit obligation arising from plan
          amendments are amortized on a straight-line basis over the expected
          average remaining service period ("ARSP") of active employees.


<PAGE>


          For any given year, when NSPI's net actuarial gain (loss), less the
          actuarial gain (loss) not yet included in the market-related value of
          plan assets, exceeds 10% of the greater of the accrued benefit
          obligation and the market-related value of the plan assets, an amount
          equal to the excess divided by the ARSP is amortized on a
          straight-line basis. The ARSP of the active employees is 10 years as
          at December 31, 2004 (2003 - 11 years).

          On January 1, 2000, NSPI adopted the new accounting standard on
          employee future benefits using the prospective application method. The
          transitional obligation (asset) resulting from the initial application
          is amortized linearly over 13 years, which was the expected ARSP of
          active employees at the transition date.

          The difference between pension expense and pension funding is recorded
          as a deferred asset on the balance sheet.

     h.   Inventory

          Inventories of materials and supplies are valued at the lower of
          average cost and market. Fuel inventory is valued at the lower of
          cost, using the first-in, first-out method, and net realizable value.

     i.   Debt Financing and Defeasance Costs

          Financing costs pertaining to debt issues are amortized over the life
          of the related debt.

          NSPI is responsible for managing a portfolio of approximately $1.1
          billion of defeasance securities held in trust, which arose in the
          course of the privatization of the Company in 1992. The excess of the
          cost of defeasance investments over the face value of the related debt
          is deferred on the balance sheet and amortized over the life of the
          defeased debt.

     j.   Derivative Financial Instruments

          The Company uses various derivative financial instruments to hedge its
          exposure to foreign exchange, interest rate, and commodity price
          risks. If documentation and effectiveness requirements are met, gains
          and losses on these instruments are deferred and recognized in
          earnings in the same period the related hedged risk is realized
          (settlement accounting). Amounts received or paid related to
          instruments used to hedge foreign exchange and commodity price risks,
          including any gains and losses, are recognized in the cost of the fuel
          purchases. Amounts received or paid, including any gains and losses on
          instruments used to hedge interest rate risks are recognized over the
          term of the hedged item in interest expense. The derivatives are not
          recorded on the balance sheet.

     k.   Foreign Currency Translation

          Monetary assets and liabilities denominated in foreign currencies are
          translated to Canadian dollars at rates of exchange in effect at the
          period end date. The resulting gains and losses between the
          translation at the original transaction date and the balance sheet
          date are included in earnings.

     l.   Research & Development Costs

          All research and development costs are expensed in the year incurred
          unless they can be deferred as part of the cost of capital assets.

     m.   Restructuring Costs

          In order to provide rate stability, the UARB allows the Company to
          defer the cost of large early retirement and severance programs, and
          amortize the resulting deferred charges on a straight-line basis over
          a three-year period, commencing in the period in which the program is
          initiated.


<PAGE>


     n.   Share-Based Compensation

          The Company has share-based compensation plans consisting of an
          employee common share purchase plan, a deferred share units plan, and
          a restricted share units plan. The Company accounts for its plans in
          accordance with the fair value based method of accounting for
          share-based compensation.

2.   CHANGE IN ACCOUNTING ESTIMATE

     Electric revenues are recognized on the accrual basis, which includes an
     estimate of electricity consumed by customers in the period but billed
     subsequent to the period. During 2003, the Company improved its process for
     estimating unbilled revenue and as a result, decreased electric revenues by
     approximately $10 million.


3.   CHANGE IN ACCOUNTING POLICIES

     In January 2004 the Company retroactively adopted the new accounting
     standard, Handbook Section 3110, issued by the Canadian Institute of
     Chartered Accountants ("CICA") related to asset retirement obligations.
     Previously the Company had accrued its obligations in annual increments
     based on the expected settlement date of the obligation using estimated
     current costs. The new standard requires the Company to determine the fair
     value of the future expenditures required to settle legal obligations to
     remove fixed assets. The present value of this estimated future expenditure
     was recognized as a liability with an equivalent amount added to the
     carrying amount of the associated fixed asset. As a result, property, plant
     and equipment and asset retirement obligations have increased by $43.9
     million as of December 31, 2003. The UARB provided a depreciation order
     effective January 1, 2004 approving the amount of future expenditures
     associated with the removal of generation facilities. Any difference
     between the amount approved by the UARB as depreciation expense and the
     amount that would have been calculated under the new accounting standard
     will be recognized as a regulated asset in property, plant and equipment.
     The impact to 2004 earnings was a decrease in depreciation expense of $0.4
     million (2003 - nil).

     Some of the Company's transmission and distribution assets may also have
     asset retirement obligations. As the Company expects to use the majority of
     its installed assets for an indefinite period, no removal date can be
     determined and consequently a reasonable estimate of the fair value of any
     related asset retirement obligation cannot be made at this time.

     In January 2004 the Company prospectively adopted the CICA's new accounting
     guideline, AcG-13, related to hedging relationships. The Company is
     documenting and testing the effectiveness of its hedging relationships in
     accordance with the new guideline. Where the new requirements are not met,
     the hedging items are marked to market. There was no impact to 2004
     earnings.


4.   ACQUISITIONS

     During 2003 Nova Scotia Power acquired an affiliate company for share
     consideration of $3.1 million. The assets purchased consisted of an income
     tax receivable ($3.6 million) and a liability to ratepayers ($0.5 million).
     The affiliate company purchased was subsequently wound up. The acquisition
     was accounted for under the purchase method of accounting.


5.   EMPLOYEE FUTURE BENEFITS

     NSPI maintains contributory defined-benefit and defined-contribution
     pension plans, which cover substantially all of its employees, and plans
     providing non-pension benefits for its retirees.


<PAGE>


     Defined benefit pension plans are based on the years of service and average
     salary at the time the employee terminates employment and provide annual
     post-retirement indexing equal to the change in the Consumer Price Index up
     to a maximum increase of 6% per year.

     Other retirement benefit plans include; unfunded pension arrangements (with
     same indexing formula as the funded pension arrangements), unfunded long
     service award (which is impacted by expected future salary levels) and
     contributory health care plan.

     The measurement date for the assets and obligations of each benefit plan is
     December 31, 2004.

     Valuation date for defined-benefit plans

     NSPI has a December 31 valuation date for accounting purposes. The most
     recent and the next required actuarial valuation dates for funding purposes
     are the following:

                                                Most recent        Next required
                                        actuarial valuation  actuarial valuation
     ---------------------------------------------------------------------------

     Employee pension plan                December 31, 2004   December 31, 2007
     Acquired companies pension plan      December 31, 2004   December 31, 2007
     ---------------------------------------------------------------------------

     Total cash amount

     Total cash amount for 2004, made up of NSPI contributions to its funded
     defined-benefit pension plans, contributions to its defined-contribution
     pension plan, employer paid premiums for its post-retirement health care
     plan, and amounts paid directly to retirees and beneficiaries in other
     plans, was $34.2 million ($22.7 million in 2003).

     Accrued benefit asset components

<TABLE>
<CAPTION>
     millions of dollars                                   2004                       2003
     ---------------------------------------- --------------------------- -------------------------
                                                  Defined-   Non-         Defined      Non-
                                                  benefit    pension      benefit      pension
                                                  pension    benefits     pension      benefits
                                                  plans      plans        plans        plans
     ---------------------------------------- -------------- ------------ ------------ ------------
<S>                                         <C>            <C>          <C>          <C>
     Assumptions (weighted-average)
     Accrued benefit obligation, December 31
       Discount rate                                   6.0%         6.0%         6.0%         6.0%
       Rate of compensation increase                3.0% to      3.0% to      3.0% to      3.0% to
                                                       5.5%         5.5%         5.5%         5.5%


       Health care trend
         - initital                                       -        10.0%            -        11.0%
         - ultimate                                       -         4.0%            -         4.0%
         - year ultimate reached                          -         2010            -         2010
     ---------------------------------------- -------------- ------------ ------------ ------------


<PAGE>


     Benefit cost for year ending, December 31
       Discount rate                                   6.0%         6.0%         6.5%         6.5%
       Expected  long-term  return  on  plan           7.5%            -         7.5%            -
       assets
       Rate of compensation increase                3.0% to      3.0% to      3.0% to      3.0% to
                                                       5.5%         5.5%         5.5%         5.5%
       Health care trend
         - initital                                       -        11.0%            -        12.0%
         - ultimate                                       -         4.0%            -         4.0%
         - year ultimate reached                          -         2010            -         2010
     ---------------------------------------- -------------- ------------ ------------ ------------

     Accrued benefit obligations
     reconciliation
       Balance, January 1                            $624.0        $31.2       $549.8        $33.7
       Employer current service cost                   10.0          1.2          8.6          1.2
       Employee contributions                           5.0            -          4.7            -
       Interest cost                                   36.8          1.9         35.2          2.2
       Past service amendments                        (7.3)            -          6.1            -
       Actuarial losses (gains)                         1.3        (1.4)         48.3        (4.5)
       Benefits paid                                 (29.5)        (1.8)       (28.7)        (1.4)
     ---------------------------------------- -------------- ------------ ------------ ------------
     Balance, December 31                            $640.3        $31.1       $624.0        $31.2
     ---------------------------------------- -------------- ------------ ------------ ------------

     Fair value of plan assets
     reconciliation
       Balance, January 1                            $471.3           $-       $406.8           $-
       Contributions by NSPI                           31.6          1.8         20.6          1.4
       Employee contributions                           5.0            -          4.7            -
       Actual investment income                        37.6            -         67.9            -
       Benefits paid                                 (29.5)        (1.8)       (28.7)        (1.4)
     ---------------------------------------- -------------- ------------ ------------ ------------
     Balance, December 31                            $516.0           $-       $471.3           $-
     ---------------------------------------- -------------- ------------ ------------ ------------

     Reconciliation of financial status to
     accrued benefit asset, December 31
         Fair value of plan assets                   $516.0           $-       $471.3           $-
         Accrued benefit obligations                  640.3         31.1        624.0         31.2

     ---------------------------------------- -------------- ------------ ------------ ------------
       Plan deficit                                $(124.3)      $(31.1)      $(152.7)     $(31.2)
       Unamortized past service costs (gains)         (0.6)            -          7.0            -
       Unamortized actuarial losses (gains)           191.3        (5.2)        196.8        (4.1)
       Unamortized transitional obligation              0.2         17.9          0.2         20.1
     ---------------------------------------- -------------- ------------ ------------ ------------
     Accrued benefit asset                            $66.6      $(18.4)        $51.3      $(15.2)
     ---------------------------------------- -------------- ------------ ------------ ------------
</TABLE>



     The expected return on plan assets is determined based on the
     market-related value of plan assets of $519.8 million at January 1, 2004
     (January 1, 2003 - $506.2 million) adjusted for interest on certain cash
     flows during the year.


<PAGE>


     Defined-benefit plans asset allocation

<TABLE>
<CAPTION>
                                             2004                            2003
     -------------------------------------------------------------------------------------------
                                                   Acquired                         Acquired
                                   Employee        companies        Employee        companies
     (in % of plan assets)       pension plan    pension plan     pension plan    pension plan
     -------------------------------------------------------------------------------------------
<S>                           <C>              <C>              <C>             <C>
     Equity securities                      67%             56%               65%           60%
     Debt securities                        31%             41%               32%           39%
     Cash                                    2%              3%                3%            1%
     -------------------------------------------------------------------------------------------
     Total                                 100%            100%              100%          100%
     -------------------------------------------------------------------------------------------
</TABLE>

     As at December 31, 2004, the pension funds do not hold any material
     investments in Emera Inc. or NSPI securities. Any such investment would
     primarily be held indirectly through pooled investment funds.

     Plans with accrued benefit obligation in excess of assets

     As at December 31, 2004, all post-retirement benefit plans have accrued
     benefit obligations in excess of assets.

     Benefit expense components

<TABLE>
<CAPTION>
     millions of dollars                              2004                      2003
     --------------------------------------- ------------------------ -------------------------
                                               Defined-    Non-        Defined      Non-
                                               benefit     pension     benefit      pension
                                               pension     benefits    pension      benefits
                                               plans       plans       plans        plans
     --------------------------------------- ------------ ----------- ------------ ------------
<S>                                        <C>          <C>         <C>          <C>
     Costs arising from events in period
        Current service costs                      $10.0        $1.2         $8.6         $1.2
        Interest on accrued benefits                36.8         1.9         35.2          2.2
        Less: actual return on plan assets        (37.6)           -       (67.9)            -
        Actuarial losses (gains) on
        accrued benefit obligations                  1.3       (1.4)         48.3        (4.5)
        Past service costs (gains)                 (7.3)           -          6.1            -
     --------------------------------------- ------------ ----------- ------------ ------------
     Future benefit costs before                    $3.2        $1.7        $30.3       $(1.1)
     adjustments
     Adjustments to recognize long-term
     nature of costs
        Difference between expected return
          on assets and actual return              (1.1)           -         30.0            -
        Amortization of transitional                   -         2.2            -          2.2
        obligation
        Difference between amortization of
          actuarial losses (gains) and
          actual actuarial losses (gains)
          on accrued benefit obligations             6.5         1.1       (45.7)          4.6
        Difference between amortization of
          past service costs and past
          service costs for the year                 7.6           -        (5.8)            -
     --------------------------------------- ------------ ----------- ------------ ------------
     Total benefit expense                         $16.2        $5.0         $8.8         $5.7
     --------------------------------------- ------------ ----------- ------------ ------------

     Defined-contribution plan
     Employer expense                               $0.8          $-         $0.7           $-
     --------------------------------------- ------------ ----------- ------------ ------------
</TABLE>


<PAGE>


     Sensitivity analysis for non-pension benefits plans

     The health care cost trend significantly influences the amounts presented
     for health care plans. An increase or decrease of one percentage-point of
     the assumed health care cost trend would have the following impact in 2004:

         millions of dollars                             Increase    Decrease
         -----------------------------------------------------------------------
         Current service cost and interest cost                 $0.2     $(0.1)
         Accrued benefit obligation, December 31                $1.7     $(1.4)
         -----------------------------------------------------------------------


6.   INTEREST

     Interest expense consists of the following:

          millions of dollars                                2004         2003
          ------------------------------------------ ------------- ------------
          Interest on long-term debt                        $89.1        $93.5
          Interest on short-term debt                         9.3         13.9
          Amortization of debt financing                      1.3          1.1
          Foreign exchange losses (gains)                     0.5        (4.1)
          Defeasance earnings                               (0.1)        (0.1)
          ------------------------------------------ ------------- ------------
                                                           $100.1       $104.3
          ------------------------------------------ ------------- ------------


7.   INCOME TAXES

     The income tax provision differs from that computed using the statutory
     rates for the following reasons:

<TABLE>
<CAPTION>
     millions of dollars                                      2004               2003
     -------------------------------------------------- --------- -------- -------- ---------
                                                           $         %        $        %
     -------------------------------------------------- --------- -------- -------- ---------
<S>                                                   <C>       <C>      <C>      <C>
     Earnings before income taxes                         $179.8            $183.0
     Income taxes, at statutory rates                      $68.5    38.1%    $73.4     40.1%
     Unrecorded future income taxes                       (13.5)    (7.5)   (18.3)    (10.0)
     Manufacturing & processing profits deduction              -        -    (2.4)     (1.3)
     Large corporations tax                                  4.2      2.3      5.1       2.8
     -------------------------------------------------- --------- -------- -------- ---------
     Income taxes                                          $59.2    32.9%    $57.8     31.6%
     -------------------------------------------------- --------- -------- -------- ---------
</TABLE>

     At December 31, 2004 the unrecorded future income tax assets of NSPI are
     approximately $39 million (2003 - $47 million), consisting of deductible
     temporary differences of $103 million (2003 - $121 million).

     Preferred Share Dividends

     Preferred share dividends consist of preferred dividends less a recovery of
     income tax expense of $0.8 million (2003 - $1.0 million). The income tax
     recovery of $6.4 million in 2004 (2003 - $6.6 million) is reflected as a
     reduction of preferred share dividends with an offsetting increase in
     income tax expense.

<TABLE>
<CAPTION>
     millions of dollars                                                2004            2003
     ------------------------------------------------------------- ---------- ---------------
<S>                                                              <C>        <C>
     Preferred share dividend                                          $14.1           $14.1
     Part VI.1 tax on preferred share dividends                          5.6             5.6
     Part I tax recovery related to the Part VI.1 tax deduction        (6.4)           (6.6)
     ------------------------------------------------------------- ---------- ---------------
                                                                       $13.3           $13.1
     ------------------------------------------------------------- ---------- ---------------
</TABLE>


<PAGE>


8.  ACCOUNTS RECEIVABLE SECURITIZATION

    In May 2004, NSPI renewed a revolving securitization agreement with an
    independent trust administered by a major Canadian bank. Under the
    securitization agreement the Company sells an undivided co-ownership
    interest in certain current and future accounts receivables generated in the
    normal course of business. The amount of the accounts receivables sold is
    removed from the balance sheet with each revolving securitization. The
    Company also retains an undivided co-ownership of approximately 10% in the
    receivables sold to the trust. This retained interest is accounted for at
    carrying value in deferred charges. Fees related to securitization are
    expensed as incurred.

    At December 31, 2004, net accounts receivables sold amounted to $80 million
    (2003 - $50 million). This agreement is in place until 2009 with the
    intention that it will be renewed at that time.


9.   RELATED PARTY TRANSACTIONS

     Due from associated companies represents the total carrying amounts of
     trade receivables, which are owed to NSPI by companies wholly-owned by
     NSPI's parent company, Emera Inc. The terms of repayments are the same as
     those for non-affiliate trade receivables. During the year NSPI had sales
     of $174.9 million (2003 - $126.8 million) to and purchases of $10.1 million
     (2003 - $14.5 million) from companies under common control of Emera Inc.

     During the year, in the ordinary course of business, the Company purchased
     transportation capacity totaling $16.4 million (2003 - $17.0 million) from
     the Maritimes and Northeast Pipeline, an investment under significant
     influence of Emera Inc. The amount is recognized as an expense in fuel for
     generation and purchased power and is measured at the fair market value. At
     December 31, 2004 the amount payable to this related party is $1.4 million
     (2003 - $1.3 million).


10.  DEFERRED CHARGES AND CREDITS

     Deferred charges and credits comprise the following:

<TABLE>
<CAPTION>
        millions of dollars                                                  2004             2003
        --------------------------------------------------------- ---------------- ----------------
<S>                                                             <C>              <C>
        Deferred charges
        Regulatory assets
        Pre-2003 income tax liability and related interest                 $150.0           $148.7
        Deferred restructuring costs                                          2.0              5.5
        --------------------------------------------------------- ---------------- ----------------
                                                                           $152.0           $154.2
        --------------------------------------------------------- ---------------- ----------------
        Non-regulatory assets
        Unamortized debt financing and defeasance costs                    181.9             198.3
        Accrued pension and non-pension benefit asset (note 5)              48.2              36.1
        Deferred hedging premiums                                            0.1               4.8
        Retained interest in accounts receivable securitized                 7.5               5.0
        Other                                                                0.3               0.6
        --------------------------------------------------------- --------------- -----------------
                                                                          $238.0            $244.8
        --------------------------------------------------------- --------------- -----------------
                                                                          $390.0            $399.0
        --------------------------------------------------------- --------------- -----------------

        Deferred credits
        Non-regulatory liabilities
        Unearned revenue                                                    $4.5              $5.2
        Other                                                                1.3               4.1
        --------------------------------------------------------- --------------- -----------------
                                                                            $5.8              $9.3
        --------------------------------------------------------- --------------- -----------------
</TABLE>


<PAGE>


     On June 11, 2004 the Supreme Court of Canada dismissed Nova Scotia Power's
     appeal to allow income tax deductions the Company had claimed between 1998
     and 2002. The deductions represented approximately $129 million in income
     tax otherwise payable ($150 million including interest).

     NSPI had previously filed income tax returns that increased the tax
     depreciation (capital cost allowance) available to be deducted against
     NSPI's future taxable income. The Canada Revenue Agency ("CRA") disallowed
     the deductions claimed and NSPI successfully pursued the issue through the
     Tax Court of Canada. When the Federal Court overturned the Tax Court's
     decision, NSPI appealed this decision to the Supreme Court of Canada.

     NSPI deposited the amount owing with CRA in 2001 and 2003 in order to avoid
     incurring non-deductible interest charges in the event the appeal was
     unsuccessful. The UARB provided an accounting order allowing NSPI to defer
     this amount on the balance sheet while the matter was before the Supreme
     Court and recognized that depending upon the outcome, NSPI could apply to
     amortize this deferral.

     As a result of the Supreme Court's decision, NSPI amended its 2005 Rate
     Application to provide for amortization of the tax deposit over a
     seven-year period starting in 2005. The hearing before the UARB to consider
     the 2005 Rate Application took place over a three-week period which began
     on November 15, 2004. Subsequent to the hearing, NSPI filed a negotiated
     Settlement Agreement with the UARB on December 15, 2004. The Settlement
     Agreement proposes to resolve the issues highlighted in its rate filings of
     May 28, 2004 and June 23, 2004, including the proposed treatment of the tax
     deposit previously deferred. The Settlement proposes to extend the
     amortization period to approximately seventeen years. The hearing on the
     Settlement Agreement was held on January 13 and 14, 2005. A decision on
     this matter is currently pending. NSPI will continue to defer this amount
     until the UARB decides on the matter. Amounts ultimately not approved for
     recovery through rates, if any, will be charged to operations at that time.

     In the meantime, beginning on January 1, 2005, the UARB has agreed to allow
     NSPI to defer new taxes not presently in rates until rates allowed by the
     UARB in the 2005 Rate Application become effective. The amount of the
     deferral will be determined after year end, and the period over which the
     deferral will be amortized will be determined at that time.


11.  PROPERTY, PLANT AND EQUIPMENT

     Property, plant and equipment is comprised of the following:

<TABLE>
<CAPTION>
         millions of dollars                                     2004
         ------------------------- ---------- ----------------- ----------------- ---------------
                                     Average                         Accumulated             Net
                                        Rate              Cost      Depreciation      Book Value
         ------------------------- ---------- ----------------- ----------------- ---------------
<S>                              <C>        <C>               <C>               <C>
         Generation
             Thermal                   2.38%          $1,651.8            $604.0        $1,047.8
             Gas turbines              2.18%              30.8              21.0             9.8
             Combustion turbines       5.00%              76.0               3.0            73.0
             Hydroelectric             1.26%             364.9             118.6           246.3
             Wind turbines             5.00%               2.0               0.2             1.8
         Transmission                  2.68%             572.5             269.3           303.2
         Distribution                  3.96%             984.0             458.6           525.4
         General plant                 6.21%             270.2              92.0           178.2
         ------------------------- ---------- ----------------- ----------------- ---------------
                                       3.07%          $3,952.2          $1,566.7        $2,385.5
         ------------------------- ---------- ----------------- ----------------- ---------------
</TABLE>


<PAGE>


<TABLE>
<CAPTION>
         millions of dollars                                             2003
         ------------------------- ---------- ----------------- ----------------- ---------------
                                     Average              Cost       Accumulated             Net
                                        Rate                        Depreciation      Book Value
         ------------------------- ---------- ----------------- ----------------- ---------------
<S>                              <C>        <C>               <C>               <C>
         Generation
             Thermal                   2.33%          $1,616.1            $588.0        $1,028.1
             Gas turbines              2.04%              30.8              20.3            10.5
             Combustion turbines       5.00%              41.9               0.9            41.0
             Hydroelectric             1.18%             358.2             114.1           244.1
         Wind turbines                 5.00%               1.2               0.1             1.1
         Transmission                  2.71%             567.7             256.7           311.0
         Distribution                  3.82%             961.3             428.2           533.1
         General plant                 5.28%             272.1              61.7           210.4
         ------------------------- ---------- ----------------- ----------------- ---------------
                                       2.89%          $3,849.3          $1,470.0        $2,379.3
         ------------------------- ---------- ----------------- ----------------- ---------------
</TABLE>


     At December 31, 2004, the Glace Bay generating station had a net book value
     of $17.8 million (2003 - $22.5 million). During the year NSPI amortized
     $6.2 million (2003 - $6.2 million) related to the plant, and capitalized
     $1.5 million in allowance for funds used during construction (2003 - $1.7
     million) to the plant value.


12.  ASSET RETIREMENT OBLIGATIONS

     The change in asset retirement obligations is as follows:


<TABLE>
<CAPTION>
     millions of dollars                                                       2004           2003
     ----------------------------------------------------------------- ------------- --------------
<S>                                                                  <C>           <C>
     Opening asset retirement obligations                                     $64.4          $61.3
         Accretion in depreciation expense                                      0.8            1.2
        Accretion in regulated asset                                            2.6            1.9
     ----------------------------------------------------------------- ------------- --------------
     Ending asset retirement obligations                                      $67.8          $64.4
     ----------------------------------------------------------------- ------------- --------------
</TABLE>

     The key assumptions used to determine the asset retirement obligations are
     as follows:

<TABLE>
<CAPTION>
                                        Credit-adjusted              Estimated            Expected
              Asset                      risk-free rate    undiscounted future     settlement date
                                                                    obligation             (years)
                                                         (millions of dollars)
     ------------------------- ------------------------- ---------------------- -------------------
<S>                          <C>                       <C>                    <C>
     Steam                                         5.3%                 $242.3             16 - 35
     Hydro                                         5.3%                   60.8             27 - 57
     Combustion turbines                           5.3%                    5.1               3 -19
     ------------------------- ------------------------- ---------------------- -------------------
                                                                        $308.2
     ------------------------- ------------------------- ---------------------- -------------------
</TABLE>


<PAGE>


13.  LONG-TERM DEBT

     Long-term debt is comprised of debentures and medium term notes payable.
     All long-term debt instruments are issued under trust indentures at fixed
     interest rates, and are unsecured. Also included is certain commercial
     paper where the Company has the intention and the unencumbered ability to
     refinance the obligation for a period greater than one year.

<TABLE>
<CAPTION>
                                           Effective average    Years of
                                           interest rate (%)    maturity
        millions of dollars                  2004     2003                    2004       2003
        ---------------------------------- --------- -------- ------------- ---------- ---------
<S>                                      <C>       <C>      <C>           <C>        <C>
        Medium term notes                   7.114     7.135    2005 - 2097   $1,100.0  $1,240.0
        Debentures                          9.750     9.750           2019       95.0      95.0
                                                                  One Year
        Commercial paper                    2.557     2.765      Renewable      262.0      81.0
        ---------------------------------- --------- -------- ------------- ---------- ---------
                                                                             $1,457.0  $1,416.0
        Less: amount due within one year                                        100.0     140.0
        ---------------------------------- --------- -------- ------------- ---------- ---------
                                                                             $1,357.0  $1,276.0
        ---------------------------------- --------- -------- ------------- ---------- ---------
</TABLE>

    A debenture of $40.0 million bearing interest at 5.20%, maturing in 2029, is
    redeemable at the option of the holder in 2006. If not redeemed the interest
    rate on the debenture increases to 6.28% until maturity. Another debenture
    of $40.0 million, maturing in 2026, is extendable until 2056 at the option
    of the holder.

    Repayments of long-term debt are due as follows:

        millions of dollars
        ------------------------------- -------------------------------
        One year renewable                                      $262.0
        2005                                                     100.0
        2006                                                         -
        2007                                                         -
        2008                                                     115.0
        2009                                                     125.0
        Greater than 5 years                                     855.0
        ------------------------------- -------------------------------
                                                              $1,457.0
        ------------------------------- -------------------------------


14.  SHORT-TERM DEBT

     Short-term debt consists of advances from the operating line of credit of
     $4.7 million (2003 - $7.1 million). The operating line of credit bears
     interest at the prime rate, which on December 31, 2004, was 4.25% (2003 -
     4.50%). Short-term debt is unsecured.


15.  PREFERRED SHARES

     Authorized:

     Unlimited number of First Preferred Shares, issuable in series. Unlimited
     number of Second Preferred Shares, issuable in series.

<TABLE>
<CAPTION>
     Issued and outstanding:
                                                                          Preferred
                                                           Millions of        Share
      millions of dollars                                       Shares      Capital
      -------------------------------------------------- -------------- ------------
<S>                                                    <C>            <C>
      January 1, 2003                                             10.4       $260.0
      -------------------------------------------------- -------------- ------------
      December 31, 2003                                           10.4       $260.0
      -------------------------------------------------- -------------- ------------
      December 31, 2004                                           10.4       $260.0
      -------------------------------------------------- -------------- ------------
</TABLE>


<PAGE>


     Series C First Preferred Shares

     Each Series C First Preferred Share is entitled to a $1.225 per share per
     annum fixed cumulative preferential dividend, as and when declared by the
     Board of Directors, accruing from the date of issue and payable quarterly
     on the first day of January, April, July and October of each year. On or
     after April 1, 2009, NSPI may redeem for cash the Series C First Preferred
     Shares, in whole at any time or in part from time to time at $25 per share
     plus accrued and unpaid dividends. The Series C First Preferred Shares will
     be exchangeable into Emera Inc. common shares on April 1, 2009.

     Series D First Preferred Shares

     Each Series D First Preferred Share is entitled to a fixed cumulative
     preferential cash dividend of $1.475 per share per annum, as and when
     declared by the Board of Directors. These dividends will accrue from the
     date of issue and will be payable quarterly on the fifteenth day of
     January, April, July, and October of each year. On or after October 15,
     2015, NSPI may redeem for cash the Series D First Preferred Shares, in
     whole at any time, at $25 per share plus accrued and unpaid dividends. The
     Series D First Preferred Shares will be exchangeable into Emera Inc. common
     shares on October 15, 2015.


16.  COMMON SHARES

     Authorized:

     Unlimited number of non-par value Common Shares.

<TABLE>
<CAPTION>
     Issued and outstanding:

                                                                   Millions of   Common share
      millions of dollars                                               shares        capital
      ----------------------------------------------------------- ------------- --------------
<S>                                                             <C>           <C>
      January 1, 2003                                                     96.8         $830.6
      ----------------------------------------------------------- ------------- --------------
      December 31, 2003                                                   96.8         $830.6
      ----------------------------------------------------------- ------------- --------------
      December 31, 2004                                                   96.8         $830.6
      ----------------------------------------------------------- ------------- --------------
</TABLE>


17.  SHARE-BASED COMPENSATION

     Employee Common Share Purchase Plan

     Employees may participate in an Employee Common Share Purchase Plan whereby
     the Company and employees can make cash contributions for the purpose of
     purchasing common shares of the parent company, Emera Inc. ("Emera"). The
     plan also allows for the reinvestment of dividends.

     Deferred Share Units Plan and Restricted Share Units Plan

     The Company has deferred share units ("DSUs") and restricted share units
     ("RSUs") plans.

     Under the DSUs plan Directors of the Company who are resident in Canada may
     elect to receive all or any portion of their compensation in DSUs in lieu
     of cash compensation. Directors' fees are paid on a quarterly basis and at
     the time of each payment of fees, the applicable amount is converted to
     DSUs. A DSU has a value equal to one Emera common share. When a dividend is
     paid on Emera's common shares, the Director's DSU account is credited with
     additional DSUs. DSUs cannot be redeemed for cash until the Director
     retires, resigns, or otherwise leaves the Board. The cash redemption value
     of a DSU equals the market value of an Emera common share at the time of
     redemption, pursuant to the plan.

     Under the DSUs plan for executive and senior management, each participant
     may elect to defer all or a percentage of the annual incentive award in the
     form of DSUs with the proviso that for participants who


<PAGE>


     are subject to executive share ownership guidelines, a minimum of 50% of
     the value of their actual annual incentive award (25% in the first year of
     the program) will be payable in DSUs until the applicable guidelines are
     met.

     When incentive awards are determined, the amount elected is converted to
     DSUs, which have value equal to the market price of an Emera common share.
     When a dividend is paid on Emera's common shares, each participant's DSU
     account is allocated additional DSUs equal in value to the dividends paid
     on an equivalent number of Emera common shares. Following termination of
     employment or retirement, and by December 15 of the calendar year after
     termination or retirement, the value of the DSUs credited to the
     participant's account is calculated by multiplying the number of DSUs in
     the participant's account by the then market value of an Emera common
     share.

     In addition, special DSU awards may be made from time to time by the
     Management Resources and Compensation ("MRC") Committee to selected
     executives and senior management to recognize singular achievements or to
     achieve certain corporate objectives.

     RSUs are granted annually for three-year overlapping performance cycles.
     The first cycle runs from January 1, 2003 through December 31, 2005. RSUs
     are granted at fair value on the grant date and dividend equivalents are
     awarded and are used to purchase additional RSUs. The RSU value varies
     according to Emera's common share market price.

     RSUs vest at the end of the three-year cycle and will be calculated and
     approved by the MRC Committee early in the following year. The value of the
     payout considers actual service over the performance cycle and will be
     pro-rated in the case of retirement, involuntary termination, disability or
     death.

<TABLE>
<CAPTION>
                                                    Employee            Employee           Director
                                            DSUs Outstanding    RSUs Outstanding   DSUs Outstanding
     ------------------------------------- ------------------ ------------------- ------------------
<S>                                      <C>                <C>                 <C>
     Balance at January 1, 2003                            -                   -                  -
     Granted                                               -              97,660             13,226
     ------------------------------------- ------------------ ------------------- ------------------
     Balance at December 31, 2003                          -              97,660             13,226
     Granted                                         137,032             143,652             18,796
     ------------------------------------- ------------------ ------------------- ------------------
     Balance at December 31, 2004                    137,032             241,312             32,022
     ------------------------------------- ------------------ ------------------- ------------------
</TABLE>

     The Company is using the fair value based method to measure the
     compensation expense related to its share-based compensation and recognizes
     the expense over the vesting period on a straight-line basis. The DSU and
     RSU liabilities are marked to market at the end of each period based on the
     common share price at the end of the period. For the year ended December
     31, 2004 $2.3 million (2003 - $0.2 million) of net compensation expense was
     recognized in operating, maintenance and general expense.

18.  OPERATING LEASES

     The Company has entered into operating lease agreements for office space
     and telecommunication services, which expire in March 2011 and March 2010
     respectively. Future minimum annual lease payments under the leases are as
     follows:

      millions of dollars
      ------------------------------------------------------- ---------------
        2005                                                            $5.2
        2006                                                             5.2
        2007                                                             5.2
        2008                                                             5.2
        2009                                                             5.2
        Greater than 5 years                                             5.1
      ------------------------------------------------------- ---------------
                                                                       $31.1
      ------------------------------------------------------- ---------------


<PAGE>


For the year ended December 31, 2004 the Company recognized $5.2 million (2003 -
$5.2 million) in operating, maintenance and general expense.


19.  FINANCIAL INSTRUMENTS


     The Company manages its exposure to foreign exchange, interest rate, and
     commodity risks in accordance with established risk management policies and
     procedures using derivative instruments consisting mainly of foreign
     exchange forward contracts, interest options and swaps, and oil and gas
     options and swaps.

     Derivative financial instruments involve credit and market risks. Credit
     risk arises from the possibility that a counterparty will default on its
     contractual obligations and is limited to those contracts where the Company
     would incur a loss in replacing the instrument.

     Financial instruments include the following:

<TABLE>
<CAPTION>
      millions of dollars                                        2004                         2003
      ------------------------------------ ------------- -------------- ------------- --------------
                                               Carrying           Fair       Carrying           Fair
                                                 Amount          Value        Amount           Value
      ------------------------------------ ------------- -------------- ------------- --------------
<S>                                   <C>             <C>            <C>           <C>
        Financial liabilities
          Long-term debt                       $1,457.0       $1,666.1      $1,416.0       $1,597.5
          Short-term debt                           4.7            4.7           7.1            7.1

        Derivative financial
        instruments receivable
        (payable)
           Interest rate swaps                    (1.1)          (2.8)         (1.4)          (7.6)
           Interest rate caps and collars           0.1          (0.9)             -          (0.3)
           Natural gas swaps                          -          (1.1)             -            0.3
           Natural gas caps and collars               -              -           3.6          (0.4)
           Oil swaps                                  -            0.1             -           13.1
           Foreign exchange contracts                 -         (27.4)           0.5         (11.0)
      ------------------------------------ ------------- -------------- ------------- --------------
</TABLE>

     Long-term Debt and Short-term Debt

     The fair value of NSPI's long-term and short-term debt is estimated based
     on the quoted market prices for the same or similar issues, or on the
     current rates offered to NSPI, for debt of the same remaining maturities.

     Derivative Financial Instruments

     The fair value of derivative financial instruments is estimated by
     obtaining prevailing market rates from investment dealers.

     Interest rates

     The Company enters into interest rate hedging contracts to convert the
     interest characteristics of a portion of its outstanding short-term debt
     from a floating to a fixed rate basis. Interest rate swap contracts
     converting floating interest on $50.0 million over 2005 (2003 - $120
     million over 2004 to 2005) to a weighted average fixed interest rate of
     6.81% (2003 - 6.48%) were outstanding at December 31, 2004.


<PAGE>


     Interest rate caps are used to limit exposure to movements of interest
     rates on floating debt. An interest rate cap contract covering $100.0
     million over 2005 (2004 - nil) at a fixed rate of 3.45% was outstanding at
     December 31, 2004.

     Interest rate collars are used to partially hedge reinvestment risk on
     long-term fixed-rate debt. Interest rate collar contracts covering $25.0
     million (2003 - $50 million) at average fixed interest rates in a range
     from 4.89% to 5.30% (2003 - 4.81% to 5.23%) were outstanding at December
     31, 2004.

     Commodity prices

     The Company has entered into natural gas swap contracts in 2004 to limit
     exposure to fluctuations in natural gas prices. As at December 31, 2004,
     the Company had hedged approximately 70% of all natural gas purchases and
     sales for 2005.

     The Company enters into oil swap contracts to limit exposure to
     fluctuations in world prices of heavy fuel oil. As at December 31, 2004,
     the Company had entered into oil swap contracts that fixed the price of
     approximately 50% of 2005 requirements.

     Foreign exchange

     The Company enters into foreign exchange forward, option, and swap
     contracts to limit exposure to currency rate fluctuations. Currency
     forwards are used to fix the Canadian dollar cost to acquire U.S. dollars,
     reducing exposure to currency rate fluctuations. Forward contracts to buy
     U.S. $239.9 million over 2005 to 2009 (2003 - U.S. $84 million over 2004
     and 2005) at a weighted average rate of CAD $1.3137 (2003 - CAD $1.4234)
     were outstanding at December 31, 2004. At December 31, 2003, there were
     also option contracts to buy U.S. $50 million over 2004 at rates in a range
     from CAD $1.3180 to $1.5600 in 2004.

     Risk Management


     Commodity price and foreign exchange risk

     A substantial amount of NSPI's fuel supply comes from international
     suppliers, and is subject to commodity price and foreign exchange risk. The
     Company manages exposure to commodity price risk utilizing a combination of
     physical fixed-price fuel contracts and financial instruments providing
     fixed or maximum prices. Foreign exchange risk is managed through forward
     and option contracts. The risk inherent in the Canadian dollar cost of fuel
     is measured and managed on a portfolio basis. The ability to switch fuel
     provides a dynamic, operational and effective option in managing commodity
     price and supply risk.


     Interest rate risk

     The Company makes use of various financial instruments to hedge against
     interest rate risk, as discussed above. Additionally, the Company uses
     diversification as a strategy. It maintains a portfolio of debt instruments
     which includes short-term instruments and long-term instruments with
     staggered maturities. The Company also deals with several counterparties so
     as to mitigate interest rate concentration risk.

     Credit risk

     The Company is exposed to credit risk with respect to amounts receivable
     from customers. Credit assessments are conducted with respect to, and
     deposits are requested from, many new customers. The Company also maintains
     provisions for potential credit losses, which are assessed on a regular
     basis. With the exception of in-province electricity customers,
     counterparty


<PAGE>


     creditworthiness is assessed through reports of credit rating agencies or
     other available financial information.


20.  COMMITMENTS

     NSPI had the following significant commitments at December 31, 2004:

     o    An annual requirement to purchase approximately 290 GWh of electricity
          from independent power producers over varying contract lengths ranging
          from nine to twenty years.
     o    A requirement to purchase approximately 61.6 million cubic feet of
          natural gas per day for the next six years (subject to offshore gas
          production), and an additional 4 million cubic feet per day, at the
          option of the supplier, for four years.
     o    Commitments to purchase approximately 65,000 mmbtu per day of
          transportation capacity on the Maritimes and Northeast Pipeline for
          the next six years, with renewal rights at the Company's option for an
          indefinite period of time, at an approximate cost of $16 million per
          year.
     o    Responsibility for managing a portfolio of approximately $1.1 billion
          of defeasance securities held in trust. The defeasance securities must
          provide the principal and interest streams of the related defeased
          debt. Approximately 69%, or $735 million, of the defeasance portfolio
          consists of investments in the related debt, eliminating all risk
          associated with this portion of the portfolio.
     o    Commitment to a third party for the transportation of coal to the
          Lingan and Point Aconi generation stations for ten years beginning in
          late 2002 at an approximate cost of $15 million per year.
     o    Commitment to a third party beginning in early 2004 for seven years to
          outsource the management of the Company's computer infrastructure at
          an annual cost ranging from $3.8 to $5.6 million.


21.  GUARANTEES

     The Company had the following guarantees at December 31, 2004:

     o    As of December 31, 2004 there were letters of credit issued against
          the Company's operating facility totaling $12.7 million (2003 - $6.2
          million). The Company's letters of credit extend to 2005 or are
          renewed annually and secure payments to various vendors.


22.  NET CASH PROVIDED BY OPERATING ACTIVITIES

     Net cash provided by operating activities, using the indirect method, is as
     follows:

<TABLE>
<CAPTION>
                                                                    2004            2003
   ---------------------------------------------------- ----------------- ---------------
<S>                                                   <C>               <C>
   Operating activities
       Net earnings applicable to common shares                   $107.3          $112.1
       Non-cash items                                              170.8           153.9
       Other operating                                            (41.3)          (41.6)
   ---------------------------------------------------- ----------------- ---------------
   Operating cash flow                                             236.8           224.4
   Pre-2003 income tax assessment                                      -         (133.0)
   Change in non-cash operating working capital                    (7.9)            86.2
   ---------------------------------------------------- ----------------- ---------------
   Net cash provided by operating activities                      $228.9          $177.6
   ---------------------------------------------------- ----------------- ---------------
</TABLE>



<PAGE>


23.  COMPARATIVE INFORMATION

     Certain of the comparative figures have been reclassified to conform to the
     financial statement presentation adopted for 2004.


<TABLE>
<CAPTION>
OPERATING STATISTICS
Five-Year Summary

                                            2004       2003       2002       2001      2000
--------------------------------------------------------------------------------------------
<S>                                  <C>         <C>        <C>        <C>       <C>
Electric energy sales (GWh)
Residential                              4,038.7    3,818.9    3,835.0    3,756.7   3,632.1
Commercial                               2,964.6    3,000.9    2,818.3    2,724.9   2,661.9
Industrial                               4,196.5    4,091.3    3,786.2    3,831.6   3,917.2
Other                                      473.4      586.0      766.2      574.6     445.0
--------------------------------------------------------------------------------------------
Total electric energy sales             11,673.2   11,497.1   11,205.7   10,887.8  10,656.2
--------------------------------------------------------------------------------------------

Sources of energy (GWh)
Thermal - coal                           9,490.2    9,218.7    8,862.2    8,854.8   8,863.7
              - oil                      1,698.2    1,535.8      287.7      690.7   1,347.8
              - natural gas                 97.0      119.5    1,578.7    1,129.1      43.8
Hydro                                      886.2    1,077.0    1,024.3      692.2     881.2
Wind                                         2.4        2.6        0.3          -         -
Purchases                                  390.9      375.2      277.6      279.4     295.2
--------------------------------------------------------------------------------------------
Total generation and purchases          12,564.9   12,328.8   12,030.8   11,646.2  11,431.7
Losses and internal use                    891.7      831.7      825.1      758.4     775.5
--------------------------------------------------------------------------------------------
Total electric energy sold              11,673.2   11,497.1   11,205.7   10,887.8  10,656.2
--------------------------------------------------------------------------------------------

Customers
Residential                              419,832    415,254    411,571    403,767   400,653
Commercial                                33,107     32,873     32,743     32,159    32,186
Industrial                                 2,419      2,347      2,280      2,246     2,194
Other                                      8,682      8,339      7,917      7,332     7,073
--------------------------------------------------------------------------------------------
Total customers                          464,040    458,813    454,511    445,504   442,106
--------------------------------------------------------------------------------------------

Generating nameplate capacity (MW)
Coal fired                                 1,243      1,243      1,243      1,243     1,243
Dual fired                                   350        350        350        350       250
Heavy fuel oil-fired                           -          -          -          -       100
Gas turbines                                 304        254        204        204       204
Hydroelectric                                395        395        395        395       395
Wind turbines                                  1          1          1          -         -
Independent power producers                   25         25         25         25        25
--------------------------------------------------------------------------------------------
Total capacity                             2,318      2,268      2,218      2,217     2,217
--------------------------------------------------------------------------------------------

Total number of employees                  1,638      1,750      1,833      1,970     1,948
--------------------------------------------------------------------------------------------

Thousands of kms of transmission
lines (69 kV and over)                         5          5          5          5         5
--------------------------------------------------------------------------------------------

Thousands of kms of distribution
lines (25 kV and under)                       25         25         25         25        25
--------------------------------------------------------------------------------------------
</TABLE>


<PAGE>


<TABLE>
<CAPTION>
FINANCIAL INFORMATION
Five-Year Summary

For the year ended December 31
 (millions of dollars)                          2004      2003      2002      2001      2000
---------------------------------------------------------------------------------------------
<S>                                  <C>         <C>        <C>        <C>       <C>
Statements of Earnings Information
Revenue                                       $934.1    $904.6    $876.5    $838.6    $818.9
---------------------------------------------------------------------------------------------
Cost of operations
Fuel for generation and purchased power        303.1     277.8     335.6     301.0     273.9
Operating, maintenance and general             177.5     186.0     176.4     156.8     156.7
Provincial grants and taxes                     39.5      33.4      22.0      20.2      17.7
Depreciation                                   116.0     101.7     103.9      99.6      97.1
---------------------------------------------------------------------------------------------
                                               636.1     598.9     637.9     577.6     545.4
---------------------------------------------------------------------------------------------
Earnings from operations                       298.0     305.7     238.6     261.0     273.5
Regulatory amortization                        (6.2)     (6.2)     (1.0)     (3.0)    (19.0)
Allowance    for   funds    used    during       3.2       4.5       3.4       5.1       4.8
construction
---------------------------------------------------------------------------------------------
Earnings before the following                  295.0     304.0     241.0     263.1     259.3
Interest                                       100.1     104.3     109.6     112.3     111.5
Amortization of defeasance costs                15.1      16.7      19.4      19.8      19.8
---------------------------------------------------------------------------------------------
Earnings before income taxes                   179.8     183.0     112.0     131.0     128.0
Income taxes                                    59.2      57.8      15.7      13.9      14.4
---------------------------------------------------------------------------------------------
Net earnings before preferred dividends        120.6     125.2      96.3     117.1     113.6
Preferred dividends                             13.3      13.1      10.2      12.0       9.9
---------------------------------------------------------------------------------------------
Net earnings applicable to common shares       107.3     112.1      86.1     105.1     103.7
Common dividends                               153.1      70.0      84.4     161.2      93.2
---------------------------------------------------------------------------------------------
Earnings retained for use in Company         $(45.8)     $42.1      $1.7   ($56.1)     $10.5
---------------------------------------------------------------------------------------------

Cost of fuel for generation - coal            $209.1    $211.8    $229.6    $202.9    $186.3
                                      -         91.2      91.4      20.6      40.7      60.5
oil                                           (30.6)    (58.4)      62.5      35.8       5.9
                                                33.4      33.0      22.9      21.6      21.2
- natural gas
Purchased power
---------------------------------------------------------------------------------------------
Total cost                                    $303.1    $277.8    $335.6    $301.0    $273.9
---------------------------------------------------------------------------------------------

Balance Sheets Information
Current assets                                $154.5    $189.6    $242.5    $250.9    $186.2
Deferred charges                               390.0     399.0     256.3     272.2     285.0
Property, plant and equipment                2,443.4   2,416.2   2,384.5   2,381.8   2,367.5
---------------------------------------------------------------------------------------------
Total assets                                $2,987.9  $3,004.8  $2,883.3  $2,904.9  $2,838.7
---------------------------------------------------------------------------------------------

Current liabilities                           $244.3    $296.3    $390.6    $457.8    $455.3
Deferred credits                                 5.8       9.3      33.1      25.2      26.3
Asset retirement obligations*                   67.8      64.4         -         -         -
Long-term debt                               1,357.0   1,276.0   1,146.0   1,185.0   1,155.0
Preferred shares                               260.0     260.0     260.0     260.0     249.1
Common shares                                  830.6     830.6     827.5     752.5     672.5
Retained earnings                              222.4     268.2     226.1     224.4     280.5
---------------------------------------------------------------------------------------------
Total equity and liabilities                $2,987.9  $3,004.8  $2,883.3  $2,904.9  $2,838.7
---------------------------------------------------------------------------------------------

Statements of Cash Flow Information
Cash provided by operating activities         $228.9    $177.6    $218.3    $145.4    $219.9
Cash used in investing activities             $144.4     $94.9    $104.6    $111.8    $121.4
---------------------------------------------------------------------------------------------
</TABLE>

*Asset retirement obligations restated to December 31, 2003 only.


</TEXT>
</DOCUMENT>
