Emera Reports Record Earnings of $151.3 Million for 2007



    HALIFAX, Feb. 15 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net
earnings increased to $151.3 million in 2007, compared to $125.8 million in
2006. Annual earnings per share were $1.28 before considering the effect of
mark-to-market accounting gains in Bear Swamp which increased earnings per
share to $1.36 compared to $1.14 in 2006. Consolidated net earnings for the
three months ended December 31, 2007 were $36.6 million compared to
$33.5 million for the fourth quarter of 2006. Quarterly earnings per share
were $0.33 in 2007 compared to $0.30 in 2006.
    "We are pleased with our 2007 results," said Chris Huskilson, President
and Chief Executive Officer of Emera Inc. "We made significant progress
throughout our business to stabilize our core utilities and invest in future
growth. Nova Scotia Power performed consistent with expectations, Bangor Hydro
had a very strong year and Emera Energy reported solid earnings as well. Our
investments in Brunswick Pipeline, the Northeast Reliability Interconnect
transmission line as well as other transmission development in New England and
Bear Swamp together will make a significant contribution to earnings in the
coming years."
    Nova Scotia Power (NSPI), Emera's largest subsidiary, contributed
$100.2 million to 2007 consolidated net earnings, compared to $104.3 million
in 2006, and $91.2 million in 2005. This slight decrease was due primarily to
a reduction in electric margin, higher spending on storm response and
increased regulatory amortization. NSPI contributed $25.2 million to
consolidated net earnings in Q4 2007, compared to $29.9 million in Q4 2006.
Earnings were lower quarter-over-quarter largely because 2006 earnings
included approximately $9 million in insurance proceeds from settlement of a
claim related to a 2005 fuel supply interruption and 2007 storm costs were
higher due to a post tropical storm in November.
    Bangor Hydro Electric (BHE), Emera's electricity transmission and
distribution utility subsidiary in Maine, contributed $6.7 million to
consolidated net earnings in Q4 2007, compared to $5.3 million in Q4 2006; and
$27.5 million for the year ended December 31, 2007 compared to $16.8 million
in 2006. Earnings increased due to higher revenue and capitalized costs
associated with the NRI transmission line project. This was partially offset
by higher income taxes and the effects of a stronger Canadian dollar.
    Emera's other operations contributed $23.6 million to consolidated net
earnings compared to $4.7 million in 2006. This increase was largely related
to the Bear Swamp generating facility which had higher energy and capacity
sales as well as a $9.4 million after tax mark-to-market gain on a long term
contract. The Maritimes and Northeast Pipeline and Lucelec also had higher
earnings for the year.
    Consolidated cash provided by operations was $351.4 million for the year
ended December 31, 2007, compared to $332.5 million in 2006. Q4 2007 cash
provided by operating activities increased to $198.0 million compared to $93.4
million in Q4 2006 due to settlement of a receivable from a natural gas
supplier and receipt of cash from the tax settlement recorded in the third
quarter in NSPI.

    Forward Looking Information

    This news release contains forward looking information. Actual future
results may differ materially. Additional financial and operational
information is filed electronically with various securities commissions in
Canada through the System for Electronic Document Analysis and Retrieval
(SEDAR).

    Teleconference Call

    Emera is holding a teleconference today at 4:00 pm Atlantic (3:00 pm
Toronto/Montreal/New York; 2:00 pm Winnipeg; noon Vancouver) to discuss the
Q4, 2007 financial results. Analysts and other interested parties wanting to
participate in the call should dial 1-888-575-8232 (in Toronto 416-406-6419)
at least 10 minutes prior to the start of the call. No pass code is required.
The teleconference will be recorded. If you are unable to join the
teleconference live, you can dial for playback toll-free at 1-800-408-3053 (in
Toronto 416-695-5800), access code 3249386# (available until midnight, Friday,
February 29, 2008). The teleconference will also be web cast live at
www.emera.com and available for playback for one year.

    About Emera

    Emera Inc. (EMA-TSX) is an energy and services company with $4.0 billion
in assets. Electricity is Emera's core business. The company has two
wholly-owned regulated electric utility subsidiaries, Nova Scotia Power Inc.
and Bangor Hydro-Electric Company, which together serve 590,000 customers.
Emera also owns 19% of St. Lucia Electricity Services Limited, which serves
more than 50,000 customers on the Caribbean island of St. Lucia. In addition
to its electric utility investments, Emera has a joint venture interest in
Bear Swamp, a 600 megawatt pumped storage hydro-electric facility in northern
Massachusetts; a 12.9% interest in the Maritimes & Northeast Pipeline; and
Emera Energy Services which manages energy assets on behalf of third parties
and provides related services. Visit Emera on the web at www.emera.com.


    
    Management's Discussion & Analysis
    As at February 15, 2008

    Management's Discussion and Analysis ("MD&A") provides a review of the
results of operations of Emera Inc. and its primary subsidiaries and
investments during the fourth quarter of 2007 relative to 2006, and the full
year 2007 relative to 2006 and to 2005; and its financial position at December
31, 2007 relative to 2006. Certain factors that may affect 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. To enhance shareholders' understanding, certain
multi-year historical financial and statistical information is presented.
    This discussion and analysis should be read in conjunction with the Emera
Inc. annual audited consolidated financial statements and supporting notes.
Emera follows Canadian Generally Accepted Accounting Principles ("GAAP").
Emera's wholly-owned subsidiary, Nova Scotia Power Inc.'s accounting policies
are subject to examination and approval by the Nova Scotia Utility and Review
Board ("UARB"). Emera's wholly-owned subsidiary, Bangor Hydro-Electric
Company's accounting policies are subject to examination and approval by the
Maine Public Utilities Commission and the Federal Energy Regulatory
Commission. The rate-regulated accounting policies of Nova Scotia Power and
Bangor Hydro may differ from GAAP for non rate-regulated companies.
    Throughout this discussion, "Emera Inc." and "Emera" refer to Emera Inc.
and all of its consolidated subsidiaries and affiliates.
    All amounts are in Canadian dollars ("CAD") except for the Bangor Hydro
section of the MD&A, which is reported in US dollars ("USD") unless otherwise
stated.
    Additional information related to Emera, including the company's Annual
Information Form, can be found on SEDAR at www.sedar.com.


    CONSOLIDATED FINANCIAL HIGHLIGHTS

    millions of dollars
     (except earnings    Three months ended                       Year ended
     per common share)          December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    Revenues              $343.9     $307.0   $1,339.5   $1,166.0   $1,168.0
    Net earnings from
     continuing operations  36.6       33.5      151.3      125.8      122.1
    Consolidated net
     earnings               36.6       33.5      151.3      125.8      121.2
    Earnings per common
     share - basic
      Continued operations  0.33       0.30       1.36       1.14       1.12
      Total                 0.33       0.30       1.36       1.14       1.11
    Earnings per common
     share - fully diluted
      Continued operations  0.32       0.30       1.32       1.12       1.10
      Total                 0.32       0.30       1.32       1.12       1.09
    Cash dividends
     declared per share   0.2275     0.2225       0.90       0.89       0.89
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                           As at December 31
                                                  2007       2006       2005
    -------------------------------------------------------------------------
    Total assets                              $4,172.7   $4,049.0   $3,998.6
    Total long-term liabilities                2,227.1    2,149.9    2,126.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    INTRODUCTION AND STRATEGIC OVERVIEW

    Emera is a Canadian energy holding company headquartered in Halifax, Nova
Scotia. The company invests in electricity generation, transmission and
distribution as well as gas transmission and energy marketing.
    Most of Emera's revenues are earned by its two regulated electric
utilities which it owns and operates in Northeastern North America. Nova
Scotia Power Inc. ("NSPI") is an electricity generation, transmission and
distribution company with $3.1 billion of assets providing service to
478,000 customers in the province of Nova Scotia, and Bangor Hydro-Electric
Company ("BHE") is an electricity transmission and distribution company with
$610 million of assets serving 116,000 customers in eastern Maine. Both
businesses operate as monopolies in their service territories, and together
comprise approximately 90% of Emera's consolidated revenues. The success of
Emera's electric utilities is integral to the creation of shareholder value,
providing substantial earnings and cash flow to fund dividends and
reinvestment. The essential nature of the services provided, the monopoly
positions, and the regulated market structures means that NSPI and BHE can
generally be expected to produce stable earnings streams within regulated
ranges. Nova Scotia and Maine are mature electricity markets, with annual
demand growth of approximately 1%. Accordingly, Emera looks beyond its
existing regulated electricity business to supplement organic growth.
    Emera's goal is to deliver annual consolidated earnings growth of 4% - 6%,
and build and diversify its earnings base. To accomplish this, Emera will
continue to seek growth from its existing businesses and will leverage its
core strength in the electricity business as it pursues both acquisitions and
greenfield development opportunities in regulated electricity transmission and
distribution and low risk generation. Emera's growth strategy also includes
serving the United States' market through transmission development and
capitalizing on opportunities in related energy infrastructure businesses
appropriate to its risk profile, where its development, commercial and
operational skills are needed.

    Emera is growing its business through the following investments:

    - Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
      hydro-electric facility in northern Massachusetts.

    - Emera Energy Services, a wholly owned subsidiary, which purchases and
      sells natural gas and electricity on behalf of third parties and
      provides related energy asset management services.

    - Brunswick Pipeline, a 145 kilometer greenfield pipeline project
      currently under development that will deliver natural gas from the
      Canaport(TM) Liquefied Natural Gas import terminal, currently under
      construction, near Saint John, New Brunswick, to markets in Canada and
      the US northeast. The project is expected to be in service as targeted
      by the end of 2008.

    - A 12.9% interest in the $2 billion, 1,400 kilometer Maritimes &
      Northeast Pipeline ("M&NP") that transports Nova Scotia's offshore
      natural gas to markets in Maritime Canada and the northeastern United
      States.

    - A 19% interest in St. Lucia Electricity Services ("Lucelec"), a
      vertically integrated electric utility on the Caribbean Island of
      St. Lucia, which was acquired in January 2007.

    Dividend Increases

    Emera increased its annual dividend twice in the last year to $0.95 per
share annually from $0.89 per share. In January 2008, the Board of Directors
approved a quarterly dividend of $0.2375 per common share, reflecting a
$0.04 annual increase. In July 2007, The Board of Directors approved a
quarterly dividend of $0.2275 per common share, reflecting a $0.02 annual
increase.


    Consolidated Net Earnings History
    (millions of dollars)

                 2007       2006       2005       2004       2003       2002
               $151.3     $125.8     $121.2     $129.8     $129.2      $83.6


    Earnings per Share History
    (dollars)

                 2007       2006       2005       2004       2003       2002
                $1.36      $1.14      $1.11      $1.20      $1.20      $0.85


    Structure of MD&A

    This Management's Discussion and Analysis begins with an overview of
consolidated results; then presents information on the company's two primary
subsidiaries, NSPI and BHE. All other operations, including Bear Swamp, Emera
Energy Services, the Maritimes & Northeast Pipeline, Lucelec, the Brunswick
Pipeline project, and corporate activities are grouped and discussed as
"Other". Significant changes in the consolidated balance sheets, outstanding
share data, liquidity and capital resources, financial and commodity
instruments, transactions with related parties, disclosure and internal
controls, critical accounting estimates, changes in accounting policies,
dividend policy and payout ratios, business risks and enterprise risk
management, and selected quarterly trend information are presented on a
consolidated basis.


    EMERA CONSOLIDATED

    Summary Consolidated Income Statement

    millions of dollars
     (except earnings    Three months ended                       Year ended
     per common share)          December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    Electric revenue      $322.0     $301.6   $1,269.5   $1,132.0   $1,125.9
    Other revenue           21.9        5.4       70.0       34.0       42.1
    -------------------------------------------------------------------------
                           343.9      307.0    1,339.5    1,166.0    1,168.0
    Fuel for generation
     and purchased power   124.0      102.3      494.5      347.7      432.0
    Operating,
     maintenance and
     general                71.5       65.0      264.8      255.6      248.2
    Provincial, state,
     and municipal taxes    11.4       11.7       47.5       48.0       48.4
    Provincial tax
     deferral                  -          -          -          -       (4.5)
    Depreciation            38.1       36.9      149.3      145.2      136.1
    Regulatory
     amortization            7.8        6.2       31.4       22.8       19.4
    Other                   (6.7)      (3.3)     (25.1)     (10.7)     (10.9)
    -------------------------------------------------------------------------
                            97.8       88.2      377.1      357.4      299.3
    Interest                24.4       34.2      118.7      127.1      117.4
    Preferred share
     dividends paid by
     subsidiary              3.5        3.5       14.1       14.1       14.1
    Amortization of
     defeasance costs        3.2        3.2       12.7       12.7       13.2
    Other income               -       (8.9)         -       (8.9)      (8.0)
    -------------------------------------------------------------------------
                            66.7       56.2      231.6      212.4      162.6
    Income taxes            30.1       22.7       80.3       86.6       52.7
    Income taxes deferral      -          -          -          -      (12.2)
    -------------------------------------------------------------------------
    Net earnings from
     continuing operations  36.6       33.5      151.3      125.8      122.1
    Loss from discontinued
     operations, net of tax    -          -          -          -       (0.9)
    -------------------------------------------------------------------------
    Net earnings applicable
     to common shares      $36.6      $33.5     $151.3     $125.8     $121.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic
      Continuing
       operations          $0.33      $0.30      $1.36      $1.14      $1.12
      Discontinued
       operations              -          -          -          -      (0.01)
    -------------------------------------------------------------------------
                           $0.33      $0.30      $1.36      $1.14      $1.11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - diluted
      Continuing
       operations          $0.32      $0.30      $1.32      $1.12      $1.10
      Discontinued
       operations              -          -          -          -      (0.01)
    -------------------------------------------------------------------------
                           $0.32      $0.30      $1.32      $1.12      $1.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Operating Unit Contributions

                         Three months ended                       Year ended
    millions of dollars         December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    Nova Scotia Power      $25.2      $29.9     $100.2     $104.3      $91.2
    Bangor Hydro-Electric    6.7        5.3       27.5       16.8       14.9
    Other, including
     corporate costs         4.7       (1.7)      23.6        4.7       15.1
    -------------------------------------------------------------------------
    Consolidated net
     earnings              $36.6      $33.5     $151.3     $125.8     $121.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Review of 2007

    Emera Inc.'s consolidated earnings increased $3.1 million to $36.6 million
in Q4 2007 compared to $33.5 million for the same period in 2006. Emera's
annual consolidated earnings increased $25.5 million to $151.3 million in 2007
compared to $125.8 million in 2006, and were $121.2 million in 2005.
Highlights of the changes are summarized in the following table:


                                                     Three months       Year
                                                            ended      ended
                                                         December   December
    millions of dollars                                        31         31
    -------------------------------------------------------------------------
    Consolidated net earnings - 2005                                  $121.2
    Increased net earnings in NSPI primarily due to
     increased electric margin partially offset by
     increased income taxes due to higher taxable
     income, and higher operating, maintenance and
     general expense, depreciation, and regulatory
     amortization                                                       13.1
    Increased net earnings in BHE primarily as a
     result of increased overheads capitalized as
     a result of capital expenditures on the
     Northeast Reliability Interconnect ("NRI")
     transmission project partially offset by
     decreased revenue due to warmer weather and
     the effect of the stronger Canadian dollar                          1.9
    Decreased earnings before interest and taxes
     ("EBIT") in Other primarily due to decreased
     EBIT in Emera Energy Services and Bear Swamp                      (10.2)
    Foreign exchange gains in Other recognized in
     2005 reflecting an adjustment to refine prior
     years' foreign exchange                                            (5.2)
    All other                                                            5.0
    -------------------------------------------------------------------------
    Consolidated net earnings - 2006                        $33.5     $125.8
    Decreased year-to-date net earnings in NSPI due
     to increased fuel expense, a new regulatory
     amortization and decreased other income partially
     offset by increased revenue and an income
     tax refund and related interest recovery                (4.7)      (4.1)
    Increased net earnings in Bangor Hydro due to
     increased revenue and capitalized costs
     associated with the NRI transmission project
     partially offset by increased income taxes and
     the effect of the stronger Canadian dollar               1.4       10.7
    Increased net earnings in Other due mainly to
     Bear Swamp's increased energy and capacity sales
     and mark-to-market positions and M&NP's
     capitalization of prior years' expansion costs
     in Q1 2007 and increased equity earnings due to
     increased tolls and volume                               6.4       18.9
    -------------------------------------------------------------------------
    Consolidated net earnings - 2007                        $36.6     $151.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Q4 basic earnings per share were $0.33 in 2007 compared to $0.30 in 2006;
    and $1.36 for the full year 2007 compared to $1.14 in 2006 and $1.11 in
    2005.


    SIGNIFICANT ITEMS

    2007

    Income tax recovery

    NSPI filed amended tax returns for 2000 to 2004 and is in the process of
filing amended returns for 2005 and 2006 related to the deductibility of
previously capitalized expenses. Canada Revenue Agency ("CRA") approved the
amended filings for the years 2000 to 2004 and will be processing adjustments
for 2005 and 2006 after they have been filed by NSPI. This has resulted in an
income tax recovery of $25.4 million, of which $14.6 million has been recorded
as a reduction of deferred charges and the remaining $10.8 million has been
recorded as a reduction of current income tax expense. In addition, NSPI
recorded refund interest of $8.6 million, $1.8 million of which has been
recorded as a reduction of deferred charges and the remaining $6.8 million has
been recorded as a reduction of interest expense. NSPI will continue to use
this methodology when filing future returns.

    Bear Swamp

    As part of its long-term energy and capacity supply agreement with the
Long Island Power Authority ("LIPA"), Bear Swamp has contracted with its
parents, Emera and Brookfield Power Corporation ("Brookfield"), to provide the
power necessary to produce the requirements of the LIPA contract. A contract
with Brookfield is marked-to-market through earnings as it does not meet the
stringent accounting requirements of hedge accounting. As at December 31,
2007, the fair value of the net derivative asset was $14.8 million (2006 -
$nil), is subject to market volatility of power prices, and will reverse over
the life of the derivative which expires in 2021.
    The mark-to-market adjustment to Q4 2007 earnings was a gain of
$5.9 million ($3.5 million after-tax) and to Q4 2006 was nil. For the year
ended December 31, 2007, the mark-to-market adjustment to earnings was a gain
of $15.7 million ($9.4 million after-tax) and for 2006 was nil.

    2006

    Settlement of claim

    In late 2005 a number of Nova Scotia Power's petroleum coke suppliers were
unable to supply fuel due to hurricanes in the Gulf of Mexico which seriously
affected their operations. As a result, Nova Scotia Power incurred additional
costs for replacement fuel and other expenses, which were included in Q4 2005
fuel expense. NSPI filed a claim with its insurers to recover applicable
costs. In Q4 2006, Nova Scotia Power received $8.9 million ($5.5 million
after-tax) in settlement of this claim.

    2005

    Natural gas supply contract

    In Q4 2005, Nova Scotia Power reached an agreement with its supplier on
pricing for natural gas under an existing long-term natural gas purchase
agreement. The contract was subject to a price re-determination as of
November 1, 2004. Throughout most of 2005, while the new pricing was under
discussion, NSPI recorded its gas purchases at its best estimate of the new
contract price. The pricing ultimately agreed to was more favourable than
NSPI's estimate. This resulted in a $23.8 million ($14.7 million after-tax)
adjustment to fuel expense for 2005, all of which was recorded in Q4 2005. In
addition, in a separate agreement, NSPI was provided with a net payment of
$8.0 million ($5.0 million after-tax) by its gas supplier, which was recorded
as other income in Q4 2005.

    Deferral of Q1 Income and Capital Taxes

    The UARB agreed to allow Nova Scotia Power to defer taxes not reflected in
rates for the period January 1, 2005 until April 1, 2005, the date when new
rates became effective. In 2005, NSPI deferred $16.7 million, consisting of
$4.5 million of provincial and federal grants and $12.2 million in income
taxes reflecting increases in these taxes since rates had last been set in
2002.


    NOVA SCOTIA POWER INC.

    Overview

    NSPI is the primary electricity supplier in Nova Scotia, providing over
95% of electricity generation, transmission and distribution in the province.
The company owns 2,293 megawatts ("MW") of generating capacity. Approximately
53% is coal-fired; natural gas and/or oil together comprise another 29% of
capacity; and hydro and wind production provide 18%. In addition, NSPI has
87 MW of renewable energy, substantially wind energy, under contract with
independent power producers. During 2007, NSPI announced it is negotiating
contracts with independent power producers for an additional 240 MW of new,
renewable energy. NSPI also owns approximately 5,000 kilometers of
transmission facilities, and 25,000 kilometers of distribution facilities. The
company has a workforce of approximately 1,700 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 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.
    Nova Scotia Power is regulated under a cost of service model, with rates
set to recover prudently incurred costs of providing electricity service to
customers, and provide an appropriate return to investors. NSPI's allowed
return on equity range is 9.3% to 9.8%, on a maximum allowed common equity
component of 40% of total capitalization. Rates were last set at a 9.55%
return on equity, with a common equity component of 37.5%.

    Cash Flow Highlights

    During Q4 2007 NSPI had two significant cash receipts. NSPI received $87.6
million USD for the November 2004 to October 2007 price adjustment rebate on
an existing long-term natural gas purchase agreement. The final three-year
settlement will be received in November 2010 for the November 2007 to October
2010 price adjustment rebate. In addition, NSPI received $34.0 million in cash
related to the income tax recovery discussed in Significant Items.

    Fuel Adjustment Mechanism

    In December 2007 the UARB issued a decision that provides conditional
approval and establishes achievable conditions for the implementation of a
Fuel Adjustment Mechanism ("FAM"), effective January 1, 2009 with the first
rate adjustment under the FAM occurring on January 1, 2010. The UARB will
oversee the fuel adjustment mechanism, including review of fuel costs,
contracts and transactions. The decision supports NSPI's position that a FAM
is the best way to ensure customer rates reflect the actual price of the fuel
used to make electricity. With the proposed implementation of the FAM
beginning in 2009, NSPI's allowed return on equity will be reduced by 0.2%,
changing its allowed earnings band to 9.1% to 9.6%.

    2007 Rate Decision

    In February 2007 the UARB approved an average increase in electricity
rates of 3.8% effective April 1, 2007. The rate increase was part of a first
ever rate settlement agreement between NSPI and key stakeholders. NSPI's
return on equity range was unchanged at 9.3% to 9.8%.

    2006 Rate Decision

    The UARB granted NSPI an average rate increase of approximately 8.7%
effective March 10, 2006. The UARB noted improvements NSPI had made in fuel
procurement, but determined that a previous finding related to 2002 and 2003
fuel procurement carried over into 2006, resulting in a $15.7 million
disallowance for 2006. The UARB noted that this would be the final
disallowance related to this issue.

    2005 Rate Decision

    On March 31, 2005, the UARB granted NSPI an average rate increase of
approximately 5.3%, effective April 1, 2005. In the 2005 decision, the UARB
expressed dissatisfaction with certain past fuel procurement practices,
resulting in a disallowance of $18 million of NSPI's forecasted 2005 fuel
costs.

    Review of 2007

    NSPI Net Earnings

    millions of dollars
     (except earnings    Three months ended                       Year ended
     per common share)          December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    Electric revenue      $283.1     $257.9   $1,102.0     $967.9     $955.0
    -------------------------------------------------------------------------
    Fuel for generation
     and purchased power   110.3       87.7      433.7      292.8      373.8
    Operating,
     maintenance and
     general                55.3       51.5      206.0      202.5      188.8
    Provincial grants
     and taxes              10.1       10.1       40.4       40.3       40.4
    Provincial grants
     and taxes deferral        -          -          -          -       (4.5)
    Depreciation            33.1       32.1      131.1      127.8      119.5
    Regulatory amortization  4.5        3.9       17.2        8.6        6.2
    Other                   (4.2)      (2.9)     (13.1)     (11.2)     (10.1)
    -------------------------------------------------------------------------
                            74.0       75.5      286.7      307.1      240.9
    Interest                18.5       27.4       97.6      105.4       97.9
    Preferred share
     dividends               3.5        3.5       14.1       14.1       14.1
    Amortization of
     defeasance costs        3.2        3.2       12.7       12.7       13.2
    Other income               -       (8.9)         -       (8.9)      (8.0)
    -------------------------------------------------------------------------
                            48.8       50.3      162.3      183.8      123.7
    Income taxes            23.6       20.4       62.1       79.5       44.7
    Income taxes deferral      -          -          -          -      (12.2)
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings              $25.2      $29.9     $100.2     $104.3      $91.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated
     earnings per
     common share          $0.23      $0.27      $0.90      $0.94      $0.83
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    NSPI's contribution to consolidated net earnings decreased $4.7 million to
$25.2 million in Q4 2007, compared to $29.9 million in Q4 2006. Annual
contribution to consolidated net earnings decreased $4.1 million to
$100.2 million in 2007 compared to $104.3 million in 2006, and was
$91.2 million in 2005. Highlights of the earnings changes are summarized in
the following table:

                                                     Three months       Year
                                                            ended      ended
                                                         December   December
    millions of dollars                                        31         31
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2005                   $91.2
    Increased electric revenue due to electricity
     price increases and increased export sales                         87.1
    Decreased electric revenue due to reduced
     industrial sales volume and warmer weather                        (74.2)
    Decreased fuel expense due to reduced load and
     increased natural gas sales margin partially
     offset by higher commodity prices and
     increased export sales                                             81.0
    Increased operating expenses mainly due to
     pension costs                                                     (13.7)
    Increased depreciation and regulatory amortization                 (10.7)
    Increased interest expense due to higher long-term
     debt balances and foreign exchange losses
     on USD contracts                                                   (7.5)
    Insurance proceeds received for a supply
     interruption claim                                                  8.9
    Net payment from a gas supplier in 2005                             (8.0)
    Increased taxes primarily due to higher
     taxable income                                                    (34.8)
    Deferral of Q1 2005 taxes                                          (16.7)
    All other                                                            1.7
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2006        $29.9     $104.3
    Increased electric revenue due to electricity price
     increases on March 10, 2006 and April 1, 2007,
     higher industrial sales volume, and colder weather
     partially offset by lower export sales volume           25.2      134.1
    Increased fuel expense                                  (22.6)    (140.9)
    Increased operating expenses mainly due to increased
     storm related costs                                     (3.8)      (3.5)
    Increased regulatory amortization due to the start
     of a new regulatory amortization on April 1, 2007       (0.6)      (8.6)
    Decreased other income                                   (8.9)      (8.9)
    Decreased interest mainly due to income tax
     recovery interest                                        8.9        7.8
    Decreased income taxes due to an income tax recovery        -       10.8
    (Increased) decreased income taxes due to
    (higher) lower taxable income                            (3.2)       6.6
    All other                                                 0.3       (1.5)
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2007        $25.2     $100.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Electric Revenue

    Q4 Electric Sales Volume             Q4 Electric Sales Revenues
    Gigawatt hours ("GWh")               millions of dollars
    -----------------------------------  ------------------------------------
                  2007    2006    2005                  2007    2006    2005
    -----------------------------------  ------------------------------------
    Residential  1,064   1,016     999   Residential  $125.7  $115.5  $104.2
    Commercial     793     742     728   Commercial     78.5    72.0    65.3
    Industrial   1,046     925   1,020   Industrial     67.5    58.5    58.6
    Other           99     116     144   Other          11.4    11.9    14.9
    -----------------------------------  ------------------------------------
    Total        3,002   2,799   2,891   Total        $283.1  $257.9  $243.0
    -----------------------------------  ------------------------------------
    -----------------------------------  ------------------------------------


    Year-to-Date ("YTD") Electric Sales  YTD Electric Sales Revenues
     Volume
    GWh                                  millions of dollars
    -----------------------------------  ------------------------------------
                  2007    2006    2005                  2007    2006    2005
    -----------------------------------  ------------------------------------
    Residential  4,145   3,927   4,000   Residential  $485.6  $439.9  $411.4
    Commercial   3,161   3,023   3,004   Commercial    307.6   285.2   263.6
    Industrial   4,191   2,874   4,197   Industrial    266.6   184.8   235.1
    Other          365     681     436   Other          42.2    58.0    44.9
    -----------------------------------  ------------------------------------
    Total       11,862  10,505  11,637   Total      $1,102.0  $967.9  $955.0
    -----------------------------------  ------------------------------------
    -----------------------------------  ------------------------------------


    Q4 Average Revenue /
     Megawatt hour ("MWh")
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars
     per MWh       $94     $92     $84
    -----------------------------------
    -----------------------------------


    YTD Average Revenue / MWh
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars
     per MWh       $93     $92     $82
    -----------------------------------
    -----------------------------------

    Electric sales volume is primarily driven by general economic conditions,
population and weather. Electricity pricing in Nova Scotia is regulated and
therefore only changes when new regulatory decisions are implemented. The
exceptions are annually adjusted rates, subscribed to by certain larger
industrial customers, and export sales which in recent years comprised less
than 2% of NSPI sales volume and are priced at market. Residential and
commercial electricity sales are seasonal, 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 revenues from street lighting.
    Electric revenues increased by $25.2 million to $283.1 million in Q4 2007
compared to $257.9 million in Q4 2006. Revenue increases are substantially due
to increased sales volume due to a large industrial customer returning to
operations in late 2006, colder weather and a 3.8% rate increase effective
April 1, 2007, partially offset by lower export sales.
    For the year ended December 31, 2007 electric revenues increased by $134.1
million to $1,102.0 million compared to $967.9 million in 2006. Revenue
increases are substantially due to the 8.7% rate increase effective March 10,
2006 and a 3.8% rate increase effective April 1, 2007, increased sales volume
due to a large industrial customer returning to operations in late 2006, and
colder weather, partially offset by lower export sales.
    For the year ended December 31, 2006 electric revenues increased
$12.9 million to $967.9 million compared to $955.0 million in 2005. The impact
of the March 10, 2006 rate increase noted above and increased export sales was
partially offset by the temporary shut-down of the large industrial customer
for much of 2006, and warmer weather.
    The average revenue per MWh is higher in Q4 2007 compared to Q4 2006 and
for the year ended December 31, 2007 compared to 2006 reflecting the two rate
increases noted above, offset by a change in sales mix, specifically the
increase in lower priced industrial sales due to the return to operations of a
large industrial customer.
    The increase in average revenue per MWh in Q4 2006 compared to Q4 2005 and
for the year ended December 31, 2006 compared to 2005 reflects the March 10,
2006 rate increase noted above, and a change in sales mix, specifically a
reduction in industrial sales.

    Fuel for Generation and Purchased Power

    Capacity

    To ensure reliability of service, NSPI maintains a generating capacity
greater than firm peak demand. The total company-owned generation capacity is
2,293 MW, which is supplemented by 87 MW contracted with independent power
producers. NSPI meets the planning criteria for reserve capacity established
by the Maritime Control Area, and the Northeast Power Coordinating Council.
    Management of capacity and 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, which
allows for annual maintenance programs to be carried out without compromising
reserve capacity requirements. NSPI's daily load is generally highest in the
early evening; its seasonal load is highest through the winter months.
Maximizing capacity utilization can have a positive effect on earnings, and
helps defer significant investment in additional generation capacity.
Maximizing capacity utilization primarily depends on:

    - Ensuring generating plants are consistently available to service demand
      - NSPI conducts ongoing planned maintenance programs, and has sustained
      high availability over the past several years. NSPI maintains low
      forced and unplanned outage rates.
    - 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. NSPI also controls
      over 400 MW of interruptible electric load; over 250 MW is supplied
      under real time or time of day rates.
    - Export sales - Increasing export sales when margins are satisfactory
      allows energy from excess capacity to be sold when not required in the
      province. NSPI operates a 24-hour marketing desk to optimize commercial
      opportunities such as export sales.

    NSPI Thermal Capacity Utilization

                            2007       2006       2005       2004       2003
                             79%        71%        78%        82%        78%

    NSPI's generating capacity utilization was 79% in 2007 compared to 71% in
2006. The Net System Requirement was increased in 2007 due to NSPI's largest
customer returning to operations in late 2006, and colder weather increasing
the home heating load.

    NSPI Generating Capacity Availability

                            2007       2006       2005       2004       2003
                             91%        90%        90%        92%        91%

    NSPI facilities continue to rank among the best in Canada on capacity
related performance indicators. The high availability and capability of low
cost thermal generating stations provide low cost energy to customers. In
2007, coal plant availability was 93% with all but one unit achieving over
90%. Sustained high availability and low forced outage rates on low cost
facilities are good indicators of sound maintenance and investment practices.


    Fuel Expense

    Q4 Production Volume                 YTD Production Volume
    GWh                                  GWh
    -----------------------------------  ------------------------------------
                  2007    2006    2005                  2007    2006    2005
    -----------------------------------  ------------------------------------
    Coal &                               Coal &
     petcoke     2,519   2,368   2,280    petcoke      9,561   9,128   9,116
    Natural gas    333     128      32   Natural gas   1,057     390     194
    Oil & diesel    45     174     442   Oil & diesel    515     431   1,581
    Renewable      218     233     308   Renewable       911     998   1,063
    Purchased                            Purchased
     power         189     180     126    power          654     405     529
    -----------------------------------  ------------------------------------
    Total        3,304   3,083   3,188   Total        12,698  11,352  12,483
    -----------------------------------  ------------------------------------
    -----------------------------------  ------------------------------------
    Purchased power includes 49 GWh of   Purchased power includes 161 GWh of
    renewables in 2007 (2006 - 33 GWh;   renewables in 2007 (2006 - 109 GWh;
    2005 - 29 GWh).                      2005 - 83 GWh).


    Q4 Average Unit Fuel Costs
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars
     per MWh       $33     $28     $25
    -----------------------------------
    -----------------------------------


    YTD Average Unit Fuel Costs
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars
     per MWh       $34     $26     $30
    -----------------------------------
    -----------------------------------

    Solid fuel is NSPI's dominant fuel source, supplying approximately 75% of
the company's annual generation. The solid fuels have the lowest per unit fuel
cost, after hydro and wind production, which have no fuel cost component. Oil,
natural gas, and purchased power are next, depending on the relative pricing
of each. 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. Accordingly, in 2007, the
increase in industrial load resulted in an increase in natural gas fired
production and purchased power.
    In Q4 2007, NSPI began using domestic coal in its Lingan plant. NSPI
consumed approximately 80,000 tonnes of coal from this domestic supplier in
Q4.
    The Q4 and full year average unit fuel costs increased in 2007 compared to
2006 mainly due to the use of higher marginal cost production because of
increased load.
    The Q4 average unit fuel costs are higher in 2006 compared to 2005 due to
a favourable adjustment in Q4 2005 to reflect finalization of pricing terms of
the natural gas supply contract. The year-to-date average unit fuel costs
decreased in 2006 compared to 2005 mainly due to the contribution from higher
natural gas margins, and NSPI's reduced use of higher priced fuels because of
reduced load.
    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 portfolio
strategy, combining 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 Risk and
Enterprise Risk Management section. Contracts may be exposed to broader global
conditions which may include impacts on delivery reliability and price,
despite contracted terms.
    For the three months ended December 31, 2007, fuel for generation and
purchased power increased $22.6 million to $110.3 million, compared to
$87.7 million in Q4 2006. For the year ended December 31, 2007, fuel for
generation and purchased power increased $140.9 million to $433.7 million
compared to $292.8 million in 2006 and $373.8 million in 2005. Highlights of
the changes are summarized in the following table:

                                                     Three months       Year
                                                            ended      ended
                                                         December   December
    millions of dollars                                        31         31
    -------------------------------------------------------------------------
    Fuel for generation and purchased power - 2005                    $373.8
    Decreased load due to the temporary shutdown
     of a large industrial customer and warmer weather                 (79.6)
    Increased net proceeds from the resale of natural gas              (23.2)
    Commodity price increases                                           18.8
    Decreased hydro production                                           2.2
    All other                                                            0.8
    -------------------------------------------------------------------------
    Fuel for generation and purchased power - 2006          $87.7     $292.8
    Increased sales volume due to the return to
     operation of a large industrial customer that
     had been shut-down for most of 2006, colder weather,
     and generation mix                                      17.2      103.6
    Commodity price (decreases) increases                   (10.3)       6.6
    Decreased net proceeds from the resale of natural
     gas due to the economic decision to use natural
     gas in the production process                           14.5       48.6
    Reversal of Q2 2007 fuel deferral to avoid the need
     to recover in future rates                               3.0          -
    Decreased export sales volume                            (0.8)     (12.4)
    All other                                                (1.0)      (5.5)
    -------------------------------------------------------------------------
    Fuel for generation and purchased power - 2007         $110.3     $433.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Operating, Maintenance and General Expenses

    NSPI's operating, maintenance and general expenses increased $3.8 million
to $55.3 million in Q4 2007 compared to $51.5 million in Q4 2006, primarily
due to costs related to post-tropical storm Noel, which had hurricane force
gusts. For the year ended December 31, 2007, NSPI's operating, maintenance and
general expenses increased $3.5 million to $206.0 million compared to
$202.5 million in 2006 primarily for the same reason.
    For the year ended December 31, 2006, NSPI's operating, maintenance and
general expenses increased $13.7 million to $202.5 million compared to
$188.8 million in 2005 primarily due to higher pension costs.

    Provincial Grants and Taxes

    NSPI pays annual grants to the Province of Nova Scotia in lieu of
municipal taxation other than deed transfer tax.
    In Q1 2005, the UARB agreed to allow NSPI to defer taxes not included in
rates for the period from January 1, 2005 until April 1, 2005, the date when
new rates became effective. In its February 5, 2007 decision, the UARB
approved amortization of the deferred amount over an eight year period,
beginning April 1, 2007.

    Depreciation

    NSPI's depreciation expense increased $1.0 million in Q4 2007, to
$33.1 million compared to $32.1 million in Q4 2006, due to plant additions.
For the year ended December 31, 2007 depreciation expense increased
$3.3 million, to $131.1 million compared to $127.8 million in 2006, for the
same reason.
    For the year ended December 31, 2006 depreciation expense increased
$8.3 million, to $127.8 million compared to $119.5 million in 2005 primarily
due to the scheduled phase-in of increased depreciation rates as approved by
the UARB.
    In its February 5, 2007 decision, the UARB postponed the scheduled
year-three phase-in of previously approved increased depreciation rates until
the next general rate application.

    Regulatory Amortization

    The Glace Bay generating station has been returned to an industrial
greenfield site, and was amortized at a minimum annual rate of $6.2 million.
In 2007 NSPI completed the amortization and expensed $5.2 million. In 2006
NSPI amortized $8.6 million (2005 - $6.2 million).
    The UARB has approved recovery, over eight years, of a $147.1 million
regulatory asset related to pre-2003 income taxes that have been paid, but not
yet recovered from customers; and a $16.7 million regulatory asset related to
Q1 2005 taxes not previously included in rates. Amortization of these
regulatory assets began on April 1, 2007 and increased regulatory amortization
by $4.0 million in Q4 2007 and $12.0 million for the year ended December 31,
2007.
    As discussed in Significant Items, the regulatory asset related to
pre-2003 income taxes was reduced by the $14.6 million of an income tax
recovery, and was reduced by $1.8 million of tax refund interest.

    Interest

    Interest expense decreased $8.9 million, to $18.5 million in Q4 2007
compared to $27.4 million in Q4 2006, and decreased $7.8 million, to
$97.6 million for the year ended December 31, 2007 compared to $105.4 million
in 2006 primarily due to the income tax recovery interest as discussed below.
    As discussed in Significant Items, NSPI recorded income tax refund
interest of $8.6 million, $1.8 million of which has been recorded as a
reduction of deferred charges. The remaining $6.8 million has been recorded as
a reduction of interest expense.
    For the year ended December 31, 2006, interest expense increased
$7.5 million to $105.4 million compared to $97.9 million in 2005 due to the
issuance in November 2005 of a $150 million 5.67% medium-term note which
partially refinanced short-term debt, and foreign exchange losses.
    The company manages exposure to interest rate risk through a combination
of fixed and floating borrowing, and hedging. Interest rate caps are the
principal instrument used to hedge interest rate risk.

    Other Income

    In Q4 2006, Nova Scotia Power received an $8.9 million insurance
settlement on a petcoke supply interruption claim.
    In Q4 2005, Nova Scotia Power received a net payment of $8.0 million from
a natural gas supplier as part of the renegotiation of contractual matters.

    Income Taxes

    In accordance with ratemaking regulations established by the UARB, NSPI
uses the taxes-payable method of accounting for income taxes.
    In 2007, NSPI was subject to provincial capital tax (0.238%), corporate
income tax (38.12%) and Part VI.1 tax relating to preferred dividends (40%).
NSPI also receives a reduction in its corporate income tax otherwise payable
related to the Part VI.1 tax deduction (45.7% of preferred dividends).
    As discussed in Significant Items, NSPI has recorded an income tax
recovery of $25.4 million, of which $14.6 million has been recorded as a
reduction of deferred charges. The remaining $10.8 million has been recorded
as a reduction of current income tax expense.
    In Q1 2005, the UARB agreed to allow NSPI to defer taxes not included in
rates for the period from January 1, 2005 until April 1, 2005, the date when
new rates became effective. In its February 5, 2007 decision, the UARB
approved amortization of the deferred amount over an eight year period,
beginning April 1, 2007.

    Outlook

    Electricity sales volume is expected to be slightly higher in 2008 than in
2007 due to general growth in the residential and commercial sectors. Electric
sales revenue will increase due to a full year of the approved 3.8%
electricity price that was effective April 1, 2007.
    Fuel costs are expected to increase primarily due to the expected increase
in sales volume noted above, and higher commodity prices. One of NSPI's fuel
suppliers has provided notice that it is suspending 2008 shipments pending a
review of the contract. NSPI is working to address the effect of any potential
supply disruption and at this time is unable to estimate the potential effect
on 2008 results.

    Debt Management

    There were no long-term debt issuances in 2007 and 2006.
    In Q4 2005, NSPI issued a $150 million medium-term note at a coupon rate
of 5.67% maturing November 14, 2035. Proceeds were used to pay down short-term
debt.
    Earlier in 2005, NSPI issued a $100 million medium-term note at a coupon
rate of 4.22% maturing May 17, 2010. The proceeds were used to refinance
$100 million 8.38% medium-term notes that matured on that date.
    The weighted average coupon rate on NSPI's outstanding medium-term and
debenture notes at December 31, 2007, was 6.86% (2006 - 6.86%). Approximately
38% of the debt matures over the next ten years; 58% matures between 2018 and
2037; and $50 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 5.34% as of December 31, 2007 (2006 - 5.10%).
    NSPI has established the following available credit facilities:

    Short-term

                                                                     Maximum
    millions of dollars                                  Maturity     amount
    -------------------------------------------------------------------------
    Commercial paper, with 100% backup line
     of credit                                   1 Year Revolving     $400.0
    Operating credit facility                    3 Year Revolving     $100.0
    -------------------------------------------------------------------------

    In June 2006, Standard & Poor's ("S&P") rating agency lowered the
corporate and senior unsecured debt credit ratings of Nova Scotia Power to
BBB/Stable Outlook from BBB+/Negative Outlook. The ratings on NSPI's preferred
shares were lowered to P-3 (high) from P-2 (low). NSPI's commercial paper
program rating remained unchanged at A2. S&P cited concerns related to the
recovery of fuel-related expenses under the current regulatory framework in
Nova Scotia; and an evolving fuel procurement strategy.
    In October 2005, Moody's rating agency revised NSPI's rating outlook to
negative from stable citing Nova Scotia Power fuel cost recovery concerns and
regulatory uncertainty.
    The ratings issued by Dominion Bond Rating Service ("DBRS"), Standard &
Poors ("S&P"), and Moody's are unchanged from 2006.
    NSPI has the following available credit ratings:

                                                 DBRS         S&P    Moody's
    -------------------------------------------------------------------------
    Corporate                                  A (low)        BBB       Baa1
    Senior unsecured debt                      A (low)        BBB       Baa1
    Preferred stock                        Pfd-2 (low)  P-3 (high)       N/A
    Commercial paper                         R-1 (low)   A-2 (Cdn)       P-2
    -------------------------------------------------------------------------

    Outlook

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

    BANGOR HYDRO-ELECTRIC COMPANY

    All amounts in the Bangor Hydro section are reported in US dollars unless
otherwise stated.

    Overview

    Bangor Hydro's core business is the transmission and distribution ("T&D")
of electricity. BHE is the second largest electric utility in Maine.
Electricity generation is deregulated in Maine, and several suppliers compete
to provide customers with the commodity that is delivered through the BHE T&D
network. BHE owns and operates approximately 1,100 kilometers of transmission
facilities, and 7,000 kilometers of distribution facilities. BHE has recently
invested approximately $141 million in the Northeast Reliability Interconnect
("NRI"), an international electricity transmission line connecting New
Brunswick to Maine which went in service in Q4 2007. BHE has a workforce of
approximately 240 people.
    In addition to T&D assets, BHE has net "regulatory" assets (stranded
costs), which arose through the restructuring of the electricity industry in
the state in the late 1990s; and as a result of rate and accounting orders
issued by its regulator. BHE's net regulatory assets primarily include the
costs associated with the restructuring of an above-market power purchase
contract; and the unamortized portion on its loss on the sale of its
investment in the Seabrook nuclear facility. Unlike T&D operational assets,
which are generally sustained with new investment, the regulatory asset pool
diminishes over time, as elements are amortized through charges to earnings,
and recovered through rates. These regulatory assets total approximately
$47.6 million at December 31, 2007, or 7% of BHE's net asset base.
    Approximately 55% of BHE's electric rate represents distribution service,
30% relates to stranded cost recoveries, and 15% to transmission service. The
rates for each element are established in distinct regulatory proceedings.
BHE's distribution operations and stranded costs are regulated by the Maine
Public Utilities Commission ("MPUC"). The transmission operations are
regulated by the Federal Energy Regulatory Commission ("FERC").
    BHE's distribution service operated under an Alternate Rate Plan ("ARP")
through December 31, 2007, which provided for an earnings band of 5% to 17%
return on equity on distribution operations, with rates set at the midpoint of
11%. There was a 50/50 sharing mechanism between the company and customers
outside of the earnings band. The ARP also included performance standards and
provided for average annual reductions in distribution rates of approximately
2.5% for five years, to 2007.
    In December 2007, the MPUC replaced rates set forth in the ARP, approving
an increase of approximately 2% in distribution rates effective January 1,
2008, providing for a traditional cost-of-service regulatory structure. The
earnings band and associated sharing mechanism, performance standard, and
annual distribution rate reductions are no longer applicable starting January
1, 2008. The allowed ROE used in setting the new distribution rates is 10.2%,
with a 50% common equity ratio.
    BHE's stranded cost rates provide for an allowed return on equity of 10%
on the related asset base for the three-year period ending February 29, 2008.
In December 2007 the MPUC issued an order approving an approximately 25%
reduction in stranded cost rates for the three-year period beginning March 1,
2008. The allowed ROE used in setting the new stranded cost rates is 8.5%.
    Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The allowed ROE for transmission operations
ranges from 10.9% for low voltage transmission up to 12.4% for high voltage
transmission developed as a result of the regional system plan, which includes
the NRI project.

    Leadership

    Effective October 5, 2007 Robert J.S. Hanf was appointed President and
Chief Operating Officer for Bangor Hydro. Prior to his position with
Bangor Hydro, Mr. Hanf was General Counsel for Emera Inc., and its affiliates,
where he and his internal legal team provided legal and regulatory services to
Emera. Before joining Emera in 2002, he was Partner in the law firm McCarthy
Tétrault LLP, Calgary, Alberta, specializing in energy law.

    Review of 2007

    BHE Net Earnings

    millions of dollars
     (except earnings    Three months ended                       Year ended
     per common share)          December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    T&D revenues           $25.9      $25.5     $101.7     $101.8     $105.5
    Resale of purchased
     power                   3.7        3.7       14.6       15.2       13.6
    Other revenue            4.5          -       12.7          -          -
    -------------------------------------------------------------------------
    Total revenue           34.1       29.2      129.0      117.0      119.1
    Fuel for generation
     and purchased power     8.3        8.2       31.9       31.4       33.6
    Operating, maintenance
     and general             8.0        7.0       26.3       27.1       31.2
    Property taxes           0.8        1.0        4.8        5.0        4.9
    Depreciation             3.2        3.2       13.0       12.9       12.4
    Regulatory
     amortization            3.2        2.0       13.2       12.6       10.8
    Other                   (3.2)      (2.1)     (11.8)      (5.9)      (3.9)
    -------------------------------------------------------------------------
    Earnings before
     interest and income
     taxes                  13.8        9.9       51.6       33.9       30.1
    Interest                 3.6        2.7       12.9       10.3       10.0
    -------------------------------------------------------------------------
    Earnings before
     income taxes           10.2        7.2       38.7       23.6       20.1
    Income taxes             3.5        2.6       13.0        8.8        7.8
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings - USD         $6.7       $4.6      $25.7      $14.8      $12.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings - CAD         $6.7       $5.3      $27.5      $16.8      $14.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated
     earnings per common
     share - CAD           $0.06      $0.04      $0.25      $0.15      $0.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net earnings weighted
     average foreign
     exchange rate -
     CAD /USD              $0.99      $1.15      $1.07      $1.13      $1.21
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Bangor Hydro's contribution to consolidated net earnings was $6.7 million
in Q4 2007 compared to $4.6 million in Q4 2006. Annual contribution to
consolidated net earnings increased $10.9 million to $25.7 million compared to
$14.8 million in 2006, and was $12.3 million in 2005. Highlights of the
earnings changes are summarized in the following table:

                                                     Three months       Year
                                                            ended      ended
                                                         December   December
    millions of dollars                                        31         31
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2005                   $12.3
    Increased overheads capitalized primarily as a
     result of capital expenditures on the Northeast
     Reliability Interconnect transmission project                       5.2
    Decreased energy sales largely due to warmer
     weather year over year                                             (1.8)
    All other                                                           (0.9)
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2006         $4.6      $14.8
    Other revenue associated with the recovery of the
     NRI project beginning in June 2007                       4.5       12.7
    (Decreased)/Increased overheads and AFUDC
     capitalized primarily as a result of capital
     expenditures on the NRI transmission project            (0.8)       4.0
    Increased income taxes due to increased earnings         (0.9)      (4.2)
    All other                                                (0.7)      (1.6)
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2007         $6.7      $25.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Bangor Hydro's increased contribution to consolidated net earnings in CAD
was partially offset by the $1.0 million impact of the stronger Canadian
dollar in the quarter; the $1.5 million effect of the stronger Canadian dollar
for the year ended December 31, 2007 compared to 2006; and the $1.1 million
effect of the stronger Canadian dollar in 2006 compared to 2005.


    Electric Revenue

    Q4 Electric Sales Volume             Q4 Electric Sales Revenues
    GWh                                  millions of dollars
    -----------------------------------  ------------------------------------
                  2007    2006    2005                  2007    2006    2005
    -----------------------------------  ------------------------------------
    Residential    157     155     157   Residential   $13.0   $12.9   $13.0
    Commercial     149     141     147   Commercial      9.0     8.8     9.0
    Industrial     102      93     100   Industrial      2.7     2.8     2.8
    Other            3       3       3   Other           1.2     1.0     1.1
    -----------------------------------  ------------------------------------
    Total          411     392     407   Total         $25.9   $25.5   $25.9
    -----------------------------------  ------------------------------------
    -----------------------------------  ------------------------------------


    YTD Electric Sales Volume            YTD Electric Sales Revenues
    GWh                                  millions of dollars
    -----------------------------------  ------------------------------------
                  2007    2006    2005                  2007    2006    2005
    -----------------------------------  ------------------------------------
    Residential    594     589     603   Residential   $49.6   $49.1   $51.1
    Commercial     606     598     610   Commercial     36.5    36.1    37.0
    Industrial     379     372     404   Industrial     11.1    11.3    12.4
    Other           12      12      12   Other           4.5     5.3     5.0
    -----------------------------------  ------------------------------------
    Total        1,591   1,571   1,629   Total        $101.7  $101.8  $105.5
    -----------------------------------  ------------------------------------
    -----------------------------------  ------------------------------------


    Q4 Average Revenue / MWh
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars per
     MWh           $63     $65     $64
    -----------------------------------
    -----------------------------------


    YTD Average Revenue / MWh
    -----------------------------------
                  2007    2006    2005
    -----------------------------------
    Dollars per
     MWh           $64     $65     $65
    -----------------------------------
    -----------------------------------

    Electric sales volume is primarily driven by general economic conditions,
population and weather. Electric sales pricing in Maine is regulated, and
therefore changes in accordance with regulatory decisions.
    Electric revenues increased by $0.4 million in Q4 2007 to $25.9 million
compared to $25.5 million in Q4 2006. For the year ended December 31, 2007,
electric revenues decreased $0.1 million to $101.7 million compared to
$101.8 million for 2006. For the year ended December 31, 2006, electric
revenues decreased $3.7 million to $101.8 million compared to $105.5 million
in 2005 primarily due to the stranded cost rate reduction effective March 1,
2005 and decreased sales volume due to warmer weather.

    Other Revenue

    Other revenue was $4.5 million in Q4 2007 and $12.7 million in 2007, which
resulted from the recovery of NRI project costs, starting in June 2007, from
the New England Power Pool.

    Resale of Purchased Power, and Fuel for Generation and Purchased Power

    The company has several above-market purchase power contracts pre-dating
the Maine market restructuring. Power purchased under these arrangements is
resold to a third party at market rates.

    Operating, Maintenance and General Expenses

    Operating, maintenance and general expenses increased $1.0 million to $8.0
million in Q4 2007 compared to $7.0 million in 2006 and decreased $0.8 million
to $26.3 million for the year ended December 31, 2007 compared to $27.1
million in 2006 primarily due to overheads capitalized as a result of capital
expenditures on the NRI transmission project.
    Operating, maintenance and general expenses decreased $4.1 million to
$27.1 million in 2006 from $31.2 million in 2005 primarily due to the reason
noted above.

    Depreciation

    Depreciation expense was $3.2 million in Q4 2007 and Q4 2006; increased
$0.1 million in 2007 relative to 2006; and increased $0.5 million in 2006
relative to 2005, due principally to plant additions. Depreciation associated
with the NRI transmission project, which began in Q4 2007 when the project
went into service, had a minimal effect on Q4 2007 results.

    Other

    Other income was $3.2 million in Q4 2007 compared to $2.1 million in
Q4 2006 and $11.8 million in 2007, compared to $5.9 million for 2006 and
$3.9 million for 2005 primarily due to increased allowance for funds used
during construction related to the NRI project.

    Interest

    Interest expense was $0.9 million higher in Q4 2007 at $3.6 million,
compared to $2.7 million in Q4 2006 and increased $2.6 million to
$12.9 million for the year ended December 31, 2007, compared to $10.3 million
in 2006 primarily due to increased debt used to finance the NRI project.

    Income Taxes

    Bangor Hydro uses the future income tax method of accounting for income
taxes.
    Bangor Hydro is subject to corporate income tax at the statutory rate of
40.8% (combined federal and state).

    Outlook

    Bangor Hydro's net earnings for 2008 are expected to be slightly lower
than 2007 primarily due to the benefits realized in 2007 of the NRI
transmission project.

    Debt Management

    In September 2007, the company completed a private placement of
$50 million in senior unsecured notes at an average interest rate of 6.0%. The
primary use of these proceeds was to fund the NRI construction project.
Proceeds were used to pay down a $40 million interim bank credit line used as
bridge financing, and short-term debt.
    The weighted-average coupon rate on Bangor Hydro's long-term debt
outstanding at December 31, 2007 was 6.82% (2006 - 7.22%). Approximately 71%
of the debt matures over the next 10 years; the remaining issues mature in
2020 and 2022. The quoted market weighted average interest rate for the same
or similar issues of the same remaining maturities was 5.62% as of
December 31, 2007 (2006 - 5.86%).
    Bangor Hydro has established the following credit facilities:

    Short-term

                                                                     Maximum
    millions of dollars                                  Maturity     amount
    -------------------------------------------------------------------------
                                                 3 year revolving-
    Unsecured revolving facility             matures in June 2008      $60.0
    -------------------------------------------------------------------------
    Operating line of credit                                           $10.0
    -------------------------------------------------------------------------

    Bangor Hydro has no public debt, and accordingly has no requirement for
public credit ratings. Bangor Hydro believes that its credit facility provides
adequate access to capital to support current operations and a base level of
capital expenditures. For additional capital needs, BHE expects to have
sufficient access to competitively priced funds in the unsecured debt market.


    OTHER, INCLUDING CORPORATE COSTS

    All activities of Emera other than its two regulated electric utilities
are incorporated into Other, including:

    - Bear Swamp, a 50/50 joint venture in a 600 megawatt pumped storage
      hydro-electric facility in northern Massachusetts. Bear Swamp typically
      pumps water into its reservoir using lower priced off-peak power, and
      uses that hydro capacity to generate electricity during higher priced
      on-peak periods.

    - Emera Energy Services, a wholly owned subsidiary, which purchases and
      sells natural gas and electricity on behalf of third parties and
      provides related energy asset management services. Emera Energy
      Services operates with minimal day-to-day commodity risk exposure.
      Volatility in natural gas markets usually results in increased
      opportunities for Emera Energy Services.

    - Brunswick Pipeline, a 145 kilometer greenfield pipeline project under
      development that will deliver natural gas from the planned Canaport(TM)
      Liquefied Natural Gas import terminal near Saint John, New Brunswick,
      to markets in Canada and the US northeast. The project is expected to
      be in service as targeted by the end of 2008.

    - A 12.9% interest in the $2 billion, 1,400 kilometer Maritimes &
      Northeast Pipeline that transports Nova Scotia's offshore natural gas
      to markets in Maritime Canada and the northeastern United States.

    - A 19% interest in St. Lucia Electricity Services, a vertically
      integrated electric utility on the Caribbean Island of St. Lucia, which
      was acquired in January 2007. Additional details are provided below.

    - Certain corporate-wide functions such as executive management,
      strategic planning, treasury services, tax planning, business
      development, and corporate governance; and financing for the
      corporation's business outside of its regulated electric utilities.

    Investment in Brunswick Pipeline

    Brunswick Pipeline, a $400 million greenfield pipeline project under
development that will deliver natural gas from the Canaport(TM) Liquefied
Natural Gas ("LNG") import terminal, currently under construction, near Saint
John, New Brunswick to markets in Canada and the US northeast. The
145 kilometer Brunswick Pipeline will travel through southwest New Brunswick
and connect with the Maritimes and Northeast Pipeline at the Canada/US border
near Baileyville, Maine. Emera has been an investor in M&NP since its
inception in 1999.
    Canaport(TM) LNG is a partnership of Repsol YPF, S.A. ("Repsol") and
Irving Oil Limited. Emera has negotiated a 25 year send or pay toll agreement
with Repsol to transport natural gas through the Brunswick Pipeline. Emera has
also negotiated agreements with its M&NP partner, Spectra Energy Corp.
("Spectra"), an affiliate of which is assisting Emera in the Brunswick
Pipeline permitting and construction process and will be operating the
pipeline on Emera's behalf.
    Emera expects to finance the investment with internally generated cash
flow and debt. The investment is forecast to provide a return on project
equity of 11% - 14%.
    The project received National Energy Board ("NEB") approval in Q2 2007 and
there are no outstanding appeals. Clearing began in Q4 2007 and the pipeline
is expected to be in service as targeted by the end of 2008.
    Emera's net cash requirements related to Brunswick Pipeline are expected
to be $355 million for 2008.

    Investment in St. Lucia Electricity Services

    St. Lucia Electricity Services Limited is a vertically integrated electric
utility serving more than 50,000 customers on the Caribbean island of St.
Lucia. Emera acquired a 19% equity interest in Lucelec for $25.7 million in
January 2007.
    Lucelec has an exclusive license to generate, transmit and distribute
electricity on the island to 2045. The utility has 77 MW of generating
capacity, primarily oil fired, and 800 kilometers of electricity transmission
and distribution assets. Lucelec is a cost of service utility, with a minimum
rate of return of 10% on a 50% equity base. Emera financed the acquisition
with existing credit facilities. Lucelec is expected to add approximately
$1 million - $2 million to Emera's annual consolidated net earnings.
    Emera's strategy recognizes that the Caribbean market has attractive
growth prospects and opportunities for the company to deploy its operational
expertise. This modest investment in Lucelec provides Emera with a low risk
vehicle to assess whether there is broader business potential for the company
in the region, and at the same time, provides immediately accretive and
attractive returns. Emera is seeking opportunities to invest further in the
region over the next several years.

    Review of 2007

    Other Net Earnings

    millions of dollars
     (except earnings    Three months ended                       Year ended
     per common share)          December 31                      December 31
    -------------------------------------------------------------------------
                            2007       2006       2007       2006       2005
    -------------------------------------------------------------------------
    Bear Swamp EBIT -
     operational            $3.6      $(0.8)      $8.9       $1.4       $4.2
    Bear Swamp EBIT -
     mark-to-market          5.9          -       15.7          -          -
    Emera Energy Services
     EBIT                    1.9        4.6       12.2       15.1       18.3
    M&NP equity earnings     2.6        1.2       10.6        4.9        6.5
    Lucelec equity
     earnings                0.9          -        2.2          -          -
    Corporate Costs &
     Other                  (4.8)      (3.6)     (14.4)      (9.6)      (7.0)
    -------------------------------------------------------------------------
                            10.1        1.4       35.2       11.8       22.0
    Interest                 2.4        3.6        7.4       10.0        7.4
    -------------------------------------------------------------------------
                             7.7       (2.2)      27.8        1.8       14.6
    Income taxes             3.0       (0.5)       4.2       (2.9)      (1.4)
    -------------------------------------------------------------------------
    Net earnings from
     continuing operations   4.7       (1.7)      23.6        4.7       16.0
    Loss from discontinued
     operations, net of tax    -          -          -          -       (0.9)
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings               $4.7      $(1.7)     $23.6       $4.7      $15.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated earnings
     per share             $0.04     $(0.01)     $0.21      $0.05      $0.14
    Less: earnings per
     share impact of
     Bear Swamp EBIT -
     other, after-tax       0.03          -       0.08          -          -
    -------------------------------------------------------------------------
                           $0.01     $(0.01)     $0.13      $0.05      $0.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The contribution of Other to consolidated net earnings increased
$6.4 million to $4.7 million in Q4 2007 compared to $(1.7) million in Q4 2006.
Annual contribution to consolidated net earnings increased $18.9 million to
$23.6 million in 2007 compared to $4.7 million in 2006, and was $15.1 million
in 2005.
    Highlights of the earnings changes are summarized in the following table:

                                                     Three months       Year
                                                            ended      ended
                                                         December   December
    millions of dollars                                        31         31
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2005                   $15.1
    Decreased EBIT in Emera Energy Services as a result
     of decreased natural gas marketing opportunities                   (3.2)
    Reduced Bear Swamp EBIT due to decreased electric
     margin and mark-to-market losses related to 2007
     hedged positions                                                   (2.8)
    Loss in Emera Fuels in 2005, net of tax                              0.9
    Capitalization in Q4 2005 of previously expensed
     business development costs to the Bear Swamp
     cost of net assets purchased                                       (2.5)
    Foreign exchange gains recognized in 2005 reflecting
     an adjustment to refine prior years' foreign exchange              (5.2)
    All other                                                            2.4
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2006        $(1.7)      $4.7

    Increased Bear Swamp EBIT - operational due to
     increased energy and capacity sales                      4.4        7.5
    Increased Bear Swamp EBIT - other due to changes in
     mark-to-market of a contract with Brookfield             5.9       15.7
    Decreased Emera Energy Services EBIT as a result of
     changes in supply, market performance, and a
     stronger Canadian dollar                                (2.7)      (2.9)
    Increased M&NP equity earnings due to expansion costs
     that were expensed throughout 2006 and capitalized
     in Q1 2007 and increased equity earnings due to
     increased tolls and volume                               1.4        5.7
    Equity earnings from Lucelec                              0.9        2.2
    Increased corporate costs and other due to increased
     business development activity and depreciation          (1.2)      (4.8)
    Increased income taxes related to increased earnings     (3.5)      (7.1)
    All other                                                 1.2        2.6
    -------------------------------------------------------------------------
    Contribution to consolidated net earnings - 2007         $4.7      $23.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Emera Energy Services

    Emera Energy Services EBIT decreased quarter over quarter to $1.9 million
in Q4 2007 from $4.6 million in Q4 2006 reflecting diminished price arbitrage
opportunities in natural gas and power markets. For the year ended
December 31, 2007 EBIT decreased to $12.2 million from $15.1 million in 2006
as a result of changes in supply, market performance, and a stronger Canadian
dollar. For the year ended December 31, 2006 EBIT was $15.1 million compared
to $18.3 million in 2005 as a result of moderating margins in natural gas
markets.

    Bear Swamp

    Bear Swamp EBIT represents Emera's investment in the Bear Swamp joint
venture, which was acquired in Q2 2005.

    Operational

    Bear Swamp EBIT - operational increased quarter over quarter to
$3.6 million in Q4 2007 compared to $(0.8) million in Q4 2006; and to
$8.9 million in 2007 compared to $1.4 million in 2006 and $4.2 million in
2005. In 2005 Bear Swamp's margins were strong, because peak prices rose as a
result of the impact of an active hurricane season. During 2006, margins were
weaker than 2005 due to milder weather patterns. A hedging program was
implemented in 2006 to provide more consistent margins and resulted in a
mark-to-market loss, which reversed in 2007.
    During Q1 2007, Bear Swamp finalized a long-term agreement with the
Long Island Power Authority providing LIPA with 345 MW of capacity to May 31,
2010 (approximately 55% of Bear Swamp's total capacity); and 100 MW
thereafter, to April 30, 2021. In addition, Bear Swamp will provide LIPA with
12,200 MWh of super-peak and peak energy weekly, (approximately 35% of the
plant's available energy) at a fixed price, with an annual increase, over the
15 year term of the agreement. Bear Swamp has contracted with its parent
companies, Emera and Brookfield for the power supply necessary to produce the
requirements of the LIPA agreement.

    Mark-to-market

    As mentioned above, Bear Swamp has contracted with its parents, Emera and
Brookfield, to provide the power necessary to produce the requirements of the
LIPA contract. A certain contract with Brookfield is marked-to-market through
earnings as it does not meet the stringent accounting requirements of hedge
accounting. As at December 31, 2007, the fair value of the derivative asset
was $14.8 million (2006 - nil), is subject to market volatility of power
prices, and will reverse over the life of the derivative, which expires in
2021. The effect on 2007 net earnings was an increase of $9.4 million
after-tax. Absent this mark-to-market adjustment, Emera's earnings per share
would have been $1.28.

    M&NP Equity Earnings

    Equity earnings for M&NP were $2.6 million in Q4 2007 compared to
$1.2 million in Q4 2006, and were $10.6 million in 2007 compared to
$4.9 million for 2006 primarily due to expansion costs that were expensed
throughout 2006 and capitalized in Q1 2007, and increased equity earnings due
to increased tolls and volume.
    For the year ended December 31, 2006 M&NP equity earnings were
$4.9 million compared to $6.5 million in 2005 primarily due to expansion costs
expensed pending regulatory approval.
    On May 16, 2006 M&NP filed an application with the FERC to expand its
US pipeline system to carry volumes from the proposed Brunswick Pipeline to
markets in the US northeast. Construction of the $307 million USD proposed
expansion facilities began in June 2007, in conjunction with the building of
Brunswick Pipeline. M&NP was expensing development costs associated with the
expansion until FERC approval was obtained in Q1 2007 when these costs were
capitalized as part of the US pipeline expansion. Emera's portion of the
required capital contribution for the proposed expansion facilities is
$26 million USD.

    Corporate Costs & Other

    Expenses related to Corporate Costs & Other increased quarter over quarter
to $4.8 million in Q4 2007 from $3.6 million in Q4 2006; and increased year
over year to $14.4 million in 2007 from $9.6 million in 2006 primarily due to
increased business development costs and depreciation.
    For the year ended December 31, 2006 expenses related to Corporate Costs &
Other increased to $9.6 million from $7.0 million in 2005 largely as a result
of the capitalization in Q4 2005 of previously expensed business development
costs to the Bear Swamp cost of net assets purchased, partially offset by
dividend income received in 2006.

    Interest

    Interest decreased quarter over quarter to $2.4 million in Q4 2007 from
$3.6 million in Q4 2006; and decreased year over year to $7.4 million in 2007
from $10.0 million in 2006 primarily due to foreign exchange gains on USD
denominated payables, offset by increased borrowing by Bear Swamp.
    For the year ended December 31, 2006 interest increased to $10.0 million
from $7.4 million in 2005 largely as a result of foreign exchange gains
recognized in 2005 reflecting an adjustment to prior years' foreign exchange.

    Income Taxes

    All businesses included in Other follow the future income taxes method of
accounting for income taxes, excluding Brunswick Pipeline which uses
taxes-payable method as allowed for ratemaking purposes. Taxes are recognized
on pre-tax income, excluding M&NP and Lucelec equity earnings that are
recorded net of tax. Variations in income tax expense are largely affected by
withholding taxes paid on cross-border dividends and interest, and completion
of prior year's tax returns.

    Outlook

    Net earnings for 2008 will be consistent with 2007 after adjusting for the
mark-to-market effect of the Bear Swamp contract with Brookfield.

    Debt Management

    During Q2 2007, Bear Swamp completed a $125 million USD financing using a
senior secured non-revolving credit facility. The five-year credit facility
bears interest at a LIBOR-based facility rate, is secured by the assets of
Bear Swamp, and is due in May 2012. Proceeds of the financing were distributed
equally to Emera and Brookfield Power.
    Emera has established the following credit facilities outside its
regulated electric utilities:

    Short-term

                                                                     Maximum
    millions of dollars                                  Maturity     amount
    -------------------------------------------------------------------------
    Operating and acquisition credit facility    1 Year Revolving     $600.0
    -------------------------------------------------------------------------

    The ratings issued by Dominion Bond Rating Service, Standard & Poor's, and
Moody's Investor Services are unchanged.
    In October 2005, Moody's rating agency revised Emera and NSPI's rating
outlooks to negative from stable citing Nova Scotia Power fuel cost recovery
concerns and regulatory uncertainty. In December 2007 Moody's stated that
NSPI's ability to achieve a negotiated settlement in respect of its 2007 rate
case and the progress toward implementation of a FAM are positive
developments. In the event that during 2008 NSPI is able to demonstrate
progress toward the satisfaction of the UARB's FAM conditions, then all else
being equal, Moody's expects that the negative outlook of Emera and NSPI could
be stabilized.
    Emera has the following available credit ratings:

                                                 DBRS         S&P    Moody's
    -------------------------------------------------------------------------
    Long-term corporate                     BBB (high)        BBB       Baa2
    -------------------------------------------------------------------------

    On a consolidated basis, Emera's target percentage of debt to total
capitalization is 50%-55%, of which 10%-25% would be exposed to short-term
rates. The company manages long-term debt terms such that the average is not
less than ten years.


    CONSOLIDATED BALANCE SHEETS

    Significant changes in the consolidated balance sheets between
December 31, 2007 and December 31, 2006 include:

                          Increase
    millions of dollars  (Decrease)  Explanation
    -------------------------------------------------------------------------
    Assets

    Accounts receivable       20.6   Lower accounts receivable securitized,
                                     and higher sales due to a rate increase
                                     partially offset by settlement of a
                                     receivable from a natural gas supplier
                                     in NSPI.
    Inventory                (13.9)  Reduced inventory levels.
    Derivatives in a valid    22.9   Implementation of new accounting
     hedging relationship            standards related to financial
     (including long-term            instruments and hedges. Balance
     portion)                        primarily represents the fair value of
                                     NSPI's hedges.
    Held-for-trading         115.1   Implementation of new accounting
     derivatives (including          standards related to financial
     long-term portion)              instruments and hedges. Balance
                                     represents the fair value of certain of
                                     NSPI's natural gas contracts, trading
                                     instruments in Emera Energy Services,
                                     and instruments held by NSPI that are
                                     not considered valid hedges.
    Deferred charges        (101.0)  Implementation of new accounting
                                     standards, reclassification of deferred
                                     financing costs, now netted against
                                     long-term debt. An income tax recovery
                                     in NSPI which reduced a regulatory
                                     asset, ongoing and new amortizations,
                                     decreased accounts receivable
                                     securitized in NSPI, and a stronger
                                     Canadian dollar also contributed to the
                                     decrease.
    Goodwill                 (14.3)  Stronger Canadian dollar.
    Investments subject to
     significant influence    26.0   Q1 2007 investment in Lucelec
    Property, plant and       47.3   Mainly due to the NRI transmission
     equipment and                   project in BHE.
     construction
     work-in-progress
    -------------------------------------------------------------------------
    Liabilities and
     Shareholders' Equity

    Short-term debt          (28.6)  Issuance of long-term debt in Bear Swamp
                                     used to reduce short-term debt,
                                     partially offset by increased issuance
                                     of short-term debt in NSPI.
    Income tax payable       (36.1)  Increased installment payments.
    Derivatives in a valid    76.9   Implementation of new accounting
     hedging relationship            standards related to financial
     (including long-term            instruments and hedges. Balance
     portion)                        primarily represents the fair value of
                                     NSPI's hedges.
    Deferred credits          92.8   Implementation of new accounting
                                     standards. Change primarily represents
                                     the new regulatory liability recognized
                                     in NSPI as a result of fair valuing
                                     certain natural gas contracts partially
                                     offset by the effect of a stronger
                                     Canadian dollar in Bangor Hydro.
    Long-term debt            60.4   Increased borrowing in Bangor Hydro
     (including current              and Bear Swamp partially offset by the
     portion)                        netting of deferred financing costs
                                     against long-term debt as a result of
                                     implementing new accounting standards,
                                     and a stronger Canadian dollar.
    Common shares             11.0   Shares issued under purchase plans and
                                     share options exercised.
    Accumulated other       (108.8)  Implementation of new accounting
     comprehensive income            standards related to financial
                                     instruments, hedges, and comprehensive
                                     income. Balance represents the effective
                                     portion of the change in fair value of
                                     NSPI's hedges and the cumulative foreign
                                     exchange translation loss on foreign
                                     self-sustaining operations. Change
                                     primarily represents the effect of the
                                     strengthening Canadian dollar relative
                                     to NSPI's existing foreign exchange
                                     hedges and on the company's investment
                                     in Bangor Hydro.
    Retained earnings         48.7   Net earnings in excess of dividends
                                     paid.
    -------------------------------------------------------------------------


    OUTSTANDING SHARE DATA                                            Common
                                                                       Share
                                                                     Capital
                                                                    millions
                                                      Millions of         of
    Issued and Outstanding:                                Shares    dollars
    -------------------------------------------------------------------------
    January 1, 2006                                        110.10   $1,039.2
    Issued for cash under purchase plans                     0.45        8.6
    Options exercised under senior management
     share option plan                                       0.38        6.7
    Share-based compensation                                    -        0.7
    -------------------------------------------------------------------------
    December 31, 2006                                      110.93   $1,055.2
    Issued for cash under purchase plans                     0.45        9.0
    Options exercised under senior management
     share option plan                                       0.09        1.7
    Share-based compensation                                    -        0.3
    -------------------------------------------------------------------------
    December 31, 2007                                      111.47   $1,066.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at February 1, 2008 the number of issued and outstanding common shares
was 111.56 million.

    Liquidity and Capital Resources

    The company generates cash primarily through its operations in regulated
utilities involving the generation, transmission and distribution of
electricity. Circumstances that could affect the company's ability to generate
cash include fuel commodity price changes, general economic downturns in
Nova Scotia and Maine, and regulatory decisions affecting customer rates. In
addition to internally generated funds, the company has access to debt capital
markets, including $769 million in committed syndicated bank lines of credit,
an active $400 million commercial paper program, which is 100% backed up by a
committed syndicated bank line of credit, and $80 million in credit under its
accounts receivable securitization 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.
    In Q1 2008, Emera and Nova Scotia Power completed final filings of debt
shelf prospectuses in the amount of $400 million for each company that will
provide the companies with access to long-term debt. The company also has
access to equity capital markets for both common and preferred shares.
    North American financial markets experienced significant volatility in the
last half of 2007 due to ongoing U.S. sub-prime mortgage concerns. This has
pressured global debt markets and in turn affected the Canadian asset-backed
commercial paper market. Emera and its subsidiaries have no investments in
asset-backed commercial paper. Nova Scotia Power issues commercial paper, 100%
backed by a syndicated bank line of credit, to finance short-term cash
requirements and has been able to continue to access the market as required.
NSPI temporarily suspended its accounts receivable securitization program in
January 2008 as a result of a lack of investor interest. The company
refinanced the debt with its current commercial paper program and has
sufficient unutilized capacity to continue to meet requirements. The company
did not incur any significant incremental costs during the market disruption.
The pressure on global debt markets may affect the credit worthiness of
certain counterparties of Emera and its subsidiaries. Emera continues to
perform regular credit risk assessments on its counterparties and deposits are
required on any high risk accounts. Further information on Emera's credit risk
can be found in the Business Risks and Enterprise Risk Management section.

    Consolidated Cash Flow Highlights

    Significant changes in the consolidated cash flow statements between
December 31, 2007 and December 31, 2006 include:

    Three months ended
     December 31
    millions of dollars          2007    2006   Explanation
    -------------------------------------------------------------------------
    Cash and cash equivalents,   $8.6   $14.2
     beginning of period
    Provided by (used in):
    Operating activities        198.0    93.4   In 2007, cash earnings and
                                                decreased non-cash working
                                                capital due to settlement of
                                                a receivable from a natural
                                                gas supplier in NSPI.
                                                In 2006, cash earnings and
                                                decreased non-cash working
                                                capital.
    Investing activities        (83.3)  (85.4)  In 2007, capital spending,
                                                including NRI project and
                                                Brunswick Pipeline projects.
                                                In 2006, capital spending,
                                                including NRI project.
    Financing activities        (96.9)   (2.7)  In 2007, reduced debt levels
                                                and dividends on common
                                                shares.
                                                In 2006, reduced debt levels
                                                and dividends on common
                                                shares offset by increased
                                                accounts receivable
                                                securitized and receipt of a
                                                long-term receivable.
    -------------------------------------------------------------------------
    Cash and cash equivalents,  $26.4   $19.5
     end of year
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Year ended December 31
    millions of dollars          2007    2006   Explanation
    -------------------------------------------------------------------------
    Cash and cash equivalents,  $19.5   $27.3
     beginning of period
    Provided by (used in):
    Operating activities        351.4   332.5   In 2007, cash earnings
                                                partially offset by increased
                                                non-cash working capital.
                                                In 2006, cash earnings and
                                                decreased non-cash working
                                                capital.
    Investing activities       (288.9) (196.9)  In 2007, capital spending,
                                                including NRI and Brunswick
                                                Pipeline projects, and
                                                acquisition of 19% interest
                                                in Lucelec.
                                                In 2006, capital spending,
                                                including NRI project.
    Financing activities        (55.6) (143.4)  In 2007, dividends on common
                                                shares and decreased accounts
                                                receivable securitized,
                                                partially offset by increased
                                                debt levels.
                                                In 2006, dividends on common
                                                shares and reduction in debt
                                                levels, partially offset by
                                                common shares issued and
                                                receipt of long-term
                                                receivable.
    -------------------------------------------------------------------------
    Cash and cash equivalents,  $26.4   $19.5
     end of year
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Contractual Obligations

    The consolidated contractual obligations over the next five years and
thereafter include:

    millions of dollars                               Payments Due by Period
    -------------------------------------------------------------------------
                                                                       After
                      Total    2008    2009    2010   2011    2012      2012
    -------------------------------------------------------------------------
    Long-term
     debt          $1,733.0  $276.9  $130.0  $104.8   $4.6   $85.9  $1,130.8
    Preferred
     shares issued
     by subsidiary    260.0       -   125.0       -      -       -     135.0
    Operating
     leases            34.7    10.4    10.0     9.9    1.6     0.6       2.2
    Purchase
     obligations    1,128.1   370.7   173.8   125.3   78.8    62.3     317.2
    Other
     long-term
     obligations      336.2    20.4     2.1     0.7    1.0     0.9     311.1
    -------------------------------------------------------------------------
    Total
     contractual
     obligations   $3,492.0  $678.4  $440.9  $240.7  $86.0  $149.7  $1,896.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Operating lease obligations: Emera's operating lease obligations consist
of operating lease agreements for office space, telecommunications services,
and photocopiers.

    Purchase obligations: Emera has purchasing commitments for electricity
from independent power producers, transportation of coal, outsource management
of the company's computer infrastructure, natural gas, transportation capacity
on the Maritimes & Northeast Pipeline, and fuel as well as for pipe and
related equipment and the pipe lay contractor for Brunswick Pipeline.

    Other long-term obligations: The company has asset retirement and other
long-term obligations.

    The company expects to be able to meet its obligations with cash flows
generated from operations.

    Capital Resources

    Capital expenditures were approximately $255 million for 2007 and
included:

    - $120 million in Nova Scotia Power;
    - $100 million in Bangor Hydro; and
    - $30 million in Brunswick Pipeline.

    Outlook

    Emera's capital budget for 2008 includes approximately $167 million for
NSPI, which is generally directed to customer growth and system reliability,
planned and preventative maintenance, productivity-related investments, and
air emissions upgrades. BHE expects to invest approximately $38 million USD,
including approximately $20 million USD for major transmission projects, and
$2 million USD for other transmission projects. Brunswick Pipeline expects to
invest approximately $355 million.
    In addition, Emera has committed $22 million USD for 2008 and 2009 to M&NP
for the $307 million USD proposed expansion facilities in the US to carry
volumes from the Brunswick Pipeline to markets in the US northeast.
    The company expects to finance its capital expenditures with funds from
operations and debt.

    Off-Balance Sheet Arrangements

    Upon privatization in 1992, NSPI became responsible for managing a
portfolio of defeasance securities, which as at December 31, 2007 totaled
$1.0 billion, held in trust for Nova Scotia Power Finance Corporation
("NSPFC"), an affiliate of the Province of Nova Scotia. NSPI is responsible to
ensure that the defeasance securities provide the principal and interest
streams to match the related defeased debt. Approximately 70% 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 has a market value higher than the related debt, reducing
the future risk of this portion of the portfolio.
    NSPI has an agreement with an independent trust administered by a Canadian
chartered bank whereby it can sell accounts receivable to the trust on a
revolving non-recourse basis. As of December 31, 2007, the company had sold
$25.0 million (2006 - $80.0 million) of net accounts receivable. 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. Securitization provides NSPI with an
alternative source of short-term funding. For the year ended December 31,
2007, the average all-in cost of this funding was 4.91% (2006 - 4.30%). In the
event of termination of this arrangement, NSPI would utilize another credit
facility to meet the ongoing operations of the business. NSPI has suspended
the program due to current market conditions and has adequate alternative
credit facilities.

    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 financial instruments consisting mainly of
foreign exchange forward contracts, interest rate options and swaps, and oil
and gas options and swaps. In addition, the company has contracts for the
physical purchase and sale of natural gas, and physical and financial
contracts held-for-trading ("HFT"). Collectively these contracts are referred
to as derivatives.
    As a result of implementing new accounting standards related to financial
instruments and hedges in Q1 2007, the company is now recognizing the fair
value of all its derivatives on its balance sheet, except for non-financial
derivatives that qualify and are designated as contracts held for normal
purchase or sale.
    Derivatives 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, the effective portion
of the fair value of derivatives is deferred to other comprehensive income and
recognized in earnings in the same period the related hedged item is realized.
Any ineffective portion of the fair value of derivatives is recognized in net
earnings in the reporting period. The total ineffectiveness recognized by the
company was a $0.2 million loss in Q4 2007 and for the year ended December 31,
2007.
    Where the documentation or effectiveness requirements of hedge accounting
are not met, the fair value of the derivatives is recognized in earnings in
the reporting period. The company also recognizes the fair value of its HFT
derivatives in earnings of the reporting period. The company has not
designated any financial instruments to be included in the HFT category.
    Nova Scotia Power has contracts for the purchase and sale of natural gas
at its Tufts Cove generating station ("TUC") that are considered HFT
derivatives and accordingly are recognized on the balance sheet at fair value.
This reflects NSPI's history of buying and reselling any natural gas not used
in the production of electricity at TUC. Changes in fair value of HFT
derivatives are normally recognized in net earnings. In accordance with NSPI's
accounting policy for financial instruments and hedges relating to TUC fuel,
NSPI has deferred any changes in fair value to a regulatory asset or
liability.
    The company has the following categories on the balance sheet related to
derivatives in valid hedging relationships:

    Hedging Items Recognized on the Balance Sheet
    millions of dollars
    -------------------------------------------------------------------------
                                                         December   December
                                                               31         31
                                                             2007       2006
    -------------------------------------------------------------------------
    Inventory                                                $7.6       $5.2
    Derivatives in a valid hedging relationship             (54.0)         -
    Long-term debt                                            0.6          -
    Deferred charges                                            -        0.9
    -------------------------------------------------------------------------
                                                           $(45.8)      $6.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the three months and year ended December 31, the impacts of
derivatives in valid hedging relationships recognized in earnings were
recorded in the following categories:

    Hedging Impact Recognized in Earnings

                                    Three months ended            Year ended
    millions of dollars                  December 31           December 31
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Fuel and purchased power
     (increase) decrease              $(4.4)     $14.4     $(14.7)     $47.1
    Hedging earnings impact           $(4.4)     $14.4     $(14.7)     $47.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Held-for-trading Items Recognized on the Balance Sheet

    The company has recognized a net held-for-trading derivatives asset of
$110.7 million (2006 - $1.2 million) on the balance sheet.
    The company has recognized the following realized and unrealized gains and
losses with respect to held-for-trading derivatives in earnings:

    Held-for-trading Derivatives Gains (Losses)
    Recognized in Earnings

                                    Three months ended          Year ended
    millions of dollars                  December 31           December 31
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    Electric revenue                   $0.8      $(1.5)      $0.8      $(3.2)
    Other revenue                      10.2        4.0       31.0       17.8
    Fuel and purchased power            0.7        2.2       (0.8)         -
    Interest                            0.1          -        0.1          -
    -------------------------------------------------------------------------
    Held-for-trading derivatives
     gains                            $11.8       $4.7      $31.1      $14.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    In determining the fair value of derivative financial instruments, the
company has relied on quoted market prices as at the reporting date.

    Transactions With Related Parties

    In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $5.1 million (2006 - $6.2 million) during the
three months ended December 31, 2007, and $25.4 million (2006 - $29.3 million)
during the year ended December 31, 2007, from the Maritimes & Northeast
Pipeline, an investment under significant influence of the company. The amount
is recognized in fuel for generation and purchased power or netted against
energy marketing margin in other revenue, and is measured at the exchange
amount. At December 31, 2007 the amount payable to the related party is
$4.5 million (2006 - $3.4 million), is non-interest bearing and is under
normal credit terms.

    Disclosure and Internal Controls

    Emera's management is responsible for the design of disclosure controls
and procedures, as defined under Multilateral Instrument 52-109, for the year
ended December 31, 2007 in order to provide reasonable assurance that material
information is made known to them. Management is also responsible for the
design of internal controls over financial reporting in order to provide
reasonable assurance regarding the reliability of financial statements
prepared for external purposes in accordance with GAAP.
    The President and Chief Executive Officer and the Chief Financial Officer,
with the assistance of company employees, have evaluated the effectiveness of
the design and operation of disclosure controls and procedures. Based on that
evaluation, the President and Chief Executive Officer and the Chief Financial
Officer have concluded that the company's disclosure controls and procedures
are adequate and effective in ensuring material information relating to Emera
and its consolidated subsidiaries is made known to them and is complete and
reliable.
    The President and Chief Executive Officer and the Chief Financial Officer,
with the assistance of company employees, have evaluated the effectiveness of
the design of internal controls over financial reporting. Based on that
evaluation, the President and Chief Executive Officer and the Chief Financial
Officer have concluded that the design of these internal controls was
effective.
    There have been no changes in Emera's internal controls over financial
reporting during the quarter ended December 31, 2007, that have materially
affected, or are reasonably likely to materially affect, internal controls
over financial reporting.

    Critical Accounting Estimates

    The preparation of consolidated 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
post-retirement employee benefits, unbilled revenue, natural gas price
adjustment receivable, asset retirement obligations, useful lives for
depreciable assets, and goodwill impairment assessments. Actual results may
differ from these estimates.

    Rate Regulation

    NSPI, BHE, and Brunswick Pipeline accounting policies are subject to
examination and approval by their respective regulators. As a result, their
rate-regulated accounting policies may differ from accounting policies for
non-rate-regulated companies. These differences occur when the regulators
render their decisions on rate applications or other matters and generally
involve the timing of revenue and expense recognition.
    The accounting for these items is based on the expectation of the future
actions of the regulators. For example, NSPI does not record future income
taxes. 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 regulations and the realization of specified expenses is based on
the expectation that the regulators will approve the refund to or recovery
from ratepayers of the deferred balance.
    If the regulators' future actions are different from the companies'
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 provision 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 discount rate used to determine benefit costs is based on 'A' grade
long-term Canadian corporate bonds for NSPI's pension plan and US corporate
bonds for BHE's pension plan. The discount rate is determined with reference
to bonds which have the same duration as the accrued benefit obligation as at
January 1 of the fiscal year rounded to the nearest 25 basis points. For
benefit cost purposes, NSPI's rate was 5.25% for 2007 (2006 - 5.25%) and BHE's
rate was 6.00% for 2007 (2006 - 5.75%).
    The expected return on plan assets is based on management's best estimate
of future returns, considering economic and consensus forecasts. The 2007 and
2006 benefit cost calculations assumed that plan assets would earn a rate of
return of 7.5% for NSPI and 8.0% for BHE.

    Unbilled Revenue

    Electric revenues are billed on a systematic basis over a one or two-month
period for NSPI and a one-month period for BHE. At the end of each month the
company must make an estimate of energy delivered to customers since the date
their meter was last read 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, 2007, unbilled revenues amount to $86.0 million
(2006 - $82.3 million) on a base of annual electric revenues of approximately
$1.3 billion (2006 - $1.1 billion).

    Natural Gas Price Adjustment Receivable

    NSPI's existing long-term natural gas purchase agreement includes a price
adjustment clause covering three years of natural gas purchases. The clause
states that NSPI will pay for all gas purchases at the agreed contract price,
but will be entitled to a price rebate on a portion of the volumes. The first
settlement took place in November 2007 for purchases to the end of October
2007. The next settlement will be in November 2010. Management has made a best
estimate of the price rebate based on the contract specifications using actual
and forward marketing pricing and recorded it in long-term receivable.

    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, restoration and remedial work based on present-day methods and
technologies.
    As part of the 2003 NSPI depreciation settlement, the UARB included the
amount of future expenditures associated with the removal of generation
facilities. NSPI 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, 2007, the asset retirement obligations recorded on the
balance sheet were $83.8 million (2006 - $78.1 million). The company estimates
the undiscounted amount of cash flow required to settle the obligations is
approximately $314.4 million, which will be incurred between 2008 and 2061.
The majority of these costs will be incurred between 2020 and 2039.

    Property, Plant and Equipment

    Property, plant and equipment represents 69% 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
largely based on formal depreciation studies, which are conducted from time to
time.
    In 2002 NSPI commissioned a depreciation study by an external consultant.
The study was filed with the UARB in 2003. A settlement agreement on the
matter was reached with all intervenors, which recommended a four-year
phase-in of new depreciation rates, which, based on assets in service in the
study, would reach an overall increase of $20 million by 2007. The UARB
approved the settlement. NSPI began phasing the new rates in 2004. In its rate
decision for 2005, the UARB deferred the scheduled phase-in for 2005. In the
rate decision for 2006, the UARB included the phase-in of year 2 in rates. In
its February 5, 2007 decision, the UARB postponed the phase-in of year 3 rates
until the next rate application.

    Goodwill Impairment Assessments

    Goodwill represents the excess of the acquisition purchase price for
Bangor Hydro over the fair values assigned to individual assets acquired and
liabilities assumed. Emera is required to perform an impairment assessment
annually, or in the interim if an event occurs that indicates that the fair
value of Bangor Hydro may be below its carrying value. Emera performs its
annual impairment test as at March 31.
    Impairment assessments are based on fair market value assessments. Fair
market value is determined by use of net present value financial models that
incorporate management's assumptions about future profitability. There was no
impairment provision required in 2007 or 2006.

    Changes in Accounting Policies

    The Canadian Institute of Chartered Accountants ("CICA") has introduced
new classification and measurement requirements for financial instruments,
including increased use of fair value measurement. These new accounting
standards are incorporated in CICA Handbook Sections 1530 Comprehensive
Income, 3855 Financial Instruments - Recognition and Measurement, and
3865 Hedges, and are effective as of January 1, 2007 for Emera Inc.
    In accordance with the new accounting standards, the accounting policy
changes were applied retroactively without restatement of prior periods. The
following provides more information on each standard.

    Comprehensive Income

    As a result of the recently issued standard, a new item, accumulated other
comprehensive income ("AOCI"), is recognized in the shareholders' equity
section of the consolidated balance sheets. AOCI includes the unrealized
foreign exchange translation adjustments on the company's self-sustaining
foreign operations, the effective portion of changes in fair value of
derivatives meeting the requirements for cash flow hedges, and unrealized
gains and losses on financial assets classified as available-for-sale.

    Financial Instruments - Recognition and Measurement

    According to the new standard, financial assets are now classified as
loans and receivables, held-for-trading, available for sale, or held to
maturity. Financial liabilities are classified as either held-for-trading, or
other than held-for-trading. The financial assets and liabilities are subject
to different methods of measurement and classification in the financial
statements, as set out in the accompanying table:

    -------------------------------------------------------------------------
    Financial Instrument              Measured at       Change in fair value
                                                        recorded in
    -------------------------------------------------------------------------
    - Loans and receivables           Amortized cost    N/A
    - Held to maturity financial
      assets
    - Other than held-for-trading
      financial liabilities
    -------------------------------------------------------------------------
    - Held-for-trading financial      Fair value        Net earnings unless
      assets and liabilities                            deferral permitted
                                                        under regulatory
                                                        accounting
    -------------------------------------------------------------------------
    - Available for sale financial    Fair value        Other comprehensive
      assets                                            income
    -------------------------------------------------------------------------

    In accordance with the new standard, transaction costs associated with the
issuance of long-term debt are included in long-term debt and amortized using
the effective interest method.

    Hedges

    The new standard outlines the criteria for applying hedge accounting to
cash flow hedges, fair value hedges, and hedging foreign currency fluctuations
on self-sustaining foreign operations.
    Cash flow hedges are recognized on the balance sheet at fair value with
the effective portion of the hedging relationship recognized in other
comprehensive income. Any ineffective portion of the cash flow hedge is
recognized in net earnings. Amounts recognized in AOCI are reclassified to net
income in the same periods in which the hedged item is recognized in net
earnings.
    Fair value hedges and the related hedged items are recognized on the
balance sheet at fair value with any changes in fair value recognized in net
income. To the extent the fair value hedge is effective, the changes in fair
value of the hedge and the hedged item will offset each other.
    Hedges of self-sustaining foreign operations are recognized at fair value
with any changes in fair value recognized in other comprehensive income.

    Accounting for the impact of rate-regulation:

    In accordance with the new accounting standards as outlined above,
Nova Scotia Power determined that its contracts for the purchase or sale of
natural gas for its Tufts Cove generating station ("TUC") should be considered
derivative financial instruments and accordingly recognized at fair value as a
held-for-trading ("HFT") asset or liability as applicable. This reflects
NSPI's history of buying and reselling any natural gas not used in the
production of electricity at TUC.
    Changes in the fair value of HFT assets and liabilities are recognized in
net earnings. In accordance with Nova Scotia Power's accounting policy
covering physical and financial contracts relating to fuel at TUC, NSPI has
deferred any changes in fair value to a regulatory asset or liability as
appropriate, which are reflected in deferred assets or credits. Upon
implementation of these accounting standards at January 1, 2007, the fair
value of these contracts was $171.9 million. Absent this accounting policy,
which has been approved by the UARB, retained earnings would have increased by
$171.9 million ($106.4 million after-tax) at January 1, 2007. As of
December 31, 2007, the fair value of the net HFT liability was $73.8 million.
Absent this accounting policy, the decrease of $98.1 million ($60.7 million
after-tax) would have decreased NSPI's earnings.

    Details of the amounts recognized upon implementation of the new
accounting standards, and the effect on the consolidated balance sheet as at
January 1, 2007 are summarized below:

                                               Balance     Effect    Balance
                                                Before         of      After
    Consolidated                              Implemen-  Implemen-  Implemen-
     Balance Sheet                              tation     tation     tation
    Selected Information                        Adjust-    Adjust-    Adjust-
    millions of dollars                           ment       ment       ment
    -------------------------------------------------------------------------
    Current assets
      Energy marketing assets                    $37.3     $(37.3)         -
      Derivatives in valid hedging relationship      -       13.9      $13.9
      Held-for-trading derivatives                   -       76.0       76.0
    Energy marketing assets                        2.0       (2.0)         -
    Derivatives in a valid hedging relationship      -       17.9       17.9
    Held-for-trading derivatives                     -      136.4      136.4
    Deferred charges                             468.2      (11.3)     456.9
    Investments                                   98.5      (98.5)         -
    Investments subject to significant
     influence                                       -       98.5       98.5
    -------------------------------------------------------------------------
                                                           $193.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Current liabilities
      Current portion of long-term debt           $3.4      $(0.2)      $3.2
      Energy marketing liabilities                36.7      (36.7)         -
      Derivatives in a valid hedging
       relationship                                  -       26.6       26.6
      Held-for-trading derivatives                   -       39.7       39.7
    Energy marketing liabilities                   1.4       (1.4)         -
    Derivatives in a valid hedging relationship      -       10.6       10.6
    Held-for-trading derivatives                     -        2.6        2.6
    Deferred credits                              66.1      173.1      239.2
    Long-term debt                             1,657.4      (12.7)   1,644.7
    Shareholders' equity
      Foreign exchange translation adjustment   (100.2)     100.2          -
      Accumulated other comprehensive income         -     (105.5)    (105.5)
      Retained earnings                          450.9       (2.7)     448.2
    -------------------------------------------------------------------------
                                                           $193.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The effect on the January 1, 2007 balances can be further explained as
follows:

    Energy marketing assets and liabilities: The balances have been
reclassified to held-for-trading derivatives.
    Derivatives in a valid hedging relationship: This new account represents
the fair value of Nova Scotia Power's hedges. These derivatives are all
designated as hedging future expected cash flows.
    Held-for-trading derivatives: This new account includes the fair value of
certain of Nova Scotia Power's natural gas contracts, amounts previously
recognized as energy marketing assets and liabilities, and the fair value of
any derivatives that are not considered valid hedges.
    Deferred charges: The adjustment represents the reclassification of
deferred financing costs which are now netted against the related debt,
partially offset by the regulatory asset resulting from the fair value
recognition of certain of Nova Scotia Power's natural gas contracts.
    Investments: The adjustment represents the reclassification of equity
accounted investments to investments subject to significant influence.
    Investments subject to significant influence: This new account represents
the reclassification of equity accounted investments from the investments
account as noted above.
    Deferred credits: The adjustment represents the regulatory liability
resulting from the fair value recognition of certain of Nova Scotia Power's
natural gas contracts.
    Long-term debt (including current portion): The adjustment represents the
netting of deferred financing costs against the related debt.
    Foreign exchange translation adjustment: The adjustment represents the
reclassification of foreign exchange losses on self-sustaining foreign
operations to accumulated other comprehensive income.
    Accumulated other comprehensive income: The adjustment represents the
effective portion of the change in fair value of Nova Scotia Power's hedges,
and the cumulative foreign exchange loss on self-sustaining foreign
operations.
    Retained earnings: The adjustment represents the fair value of
Bear Swamp's interim LIPA contract.

    As a result of implementing the accounting policy changes, earnings have
increased by $0.2 million ($0.1 million after-tax) in Q4 2007 and $2.9 million
($1.7 million after-tax) year-to-date 2007, which represents the change in
fair value of Bear Swamp's interim LIPA contract and the ineffective portion
of the company's hedges. There has been no effect on the consolidated
statement of changes of cash flow.
    The fair value of derivatives held in a valid hedging relationship and
held-for-trading derivatives are estimated by obtaining prevailing market
rates from investment dealers.

    Future Accounting Policy Changes

    The CICA has issued new accounting standards 1535 Capital Disclosures,
3031 Inventories, 3862 Financial Instruments - Disclosures, and 3863 Financial
Instruments - Presentation, which are applicable to Emera's 2008 fiscal year.
The CICA has also issued new accounting standards relating to rate-regulated
operations which are applicable to Emera's 2009 fiscal year. The following
provides more information on each new accounting standard.
    Capital Disclosures: This new standard requires disclosure of the
company's objectives, policies, and processes for managing capital;
quantitative data about what the company regards as capital; whether the
company has complied with any capital requirements; and, if the company has
not complied, the consequences of such non-compliance. The new accounting
standard covers disclosure only and will have no effect on the financial
results of the company.
    Inventories: The new standard provides more guidance on the measurement
and disclosure requirements for inventories than the previous standard,
3030 Inventories. Specifically, the new standard requires that inventories be
measured at the lower of cost and net realizable value, and provides more
guidance on the determination of cost and its subsequent recognition as an
expense, including any write-down to net realizable value. The company is
assessing the effect of the new standard on its financial results but does not
anticipate any material effect on its results.
    Financial Instruments - Disclosures and Financial Instruments -
Presentation: These new standards replace accounting standard 3861 Financial
Instruments - Disclosure and Presentation. Presentation requirements have not
changed. Enhanced disclosure is required to assist users of the financial
statements in evaluating the significance of financial instruments on the
company's financial position and performance, including qualitative and
quantitative information about the company's exposure to risks arising from
financial instruments. The new accounting standards cover disclosure only and
will have no effect on the financial results of the company.
    Rate-Regulated Operations: These new standards include removing the
temporary exemption in Section 1100 Generally Accepted Accounting Principles
pertaining to the application of the section to the recognition and
measurement of assets and liabilities arising from rate regulation; and
amending Section 3465 Income Taxes to require the recognition of future income
tax assets and liabilities for the amount of future income taxes expected to
be included in future rates and recovered from or paid to future customers. As
a result of the new standard, Emera will recognize future income tax assets
and liabilities of its wholly-owned regulated subsidiaries. In accordance with
the company's regulated accounting policies covering income taxes, Emera will
defer any future income taxes to a regulatory asset or liability where the
future income taxes are included in future rates, with no resulting effect on
net earnings.

    Dividends and Payout Ratios

    In January 2008, the Board of Directors approved a quarterly dividend of
$0.2375 per common share, reflecting an increase on an annualized basis to
$0.95 per common share.
    Emera Inc.'s common dividend rate was $0.90 ($0.2225 per quarter in Q1 and
Q2; and $0.2275 in Q3 and Q4) per common share in 2007 and $0.89 ($0.2225 per
quarter) for 2006, representing a payout ratio of approximately 66% for 2007
(2006 - 78%). In July 2007, the Board of Directors approved a quarterly
dividend of $0.2275 per common share, reflecting an increase on an annualized
basis to $0.91.

    Business Risks and Enterprise Risk Management

    Risk Management

    Significant risk management activities for Emera are overseen by the
Enterprise Risk Management Committee to ensure that risks are appropriately
assessed, monitored and controlled within predetermined risk tolerances
established through Board of Directors approved policies.
    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, interest rates, and regulatory risk.

    Commodity Prices

    Substantially all of the company's annual fuel requirement is subject to
fluctuation in commodity market prices, prior to any commodity risk management
activities. The company utilizes a portfolio strategy for fuel procurement
with a combination of long, medium, and short-term supply agreements. It also
provides for supply and supplier diversification. The strategy is designed to
reduce the effects from market volatility through agreements with staggered
expiration dates, volume options, and varied pricing mechanisms.

    Coal/Petroleum Coke

    A substantial portion of the company's coal and petroleum coke supply
comes from international suppliers, which was contracted for at or near the
market prices prevailing at the time of contract. The company has entered into
fixed-price contractual arrangements with several suppliers as part of the
fuel procurement portfolio strategy. Physical contracts are used to hedge coal
price risk due to the lack of liquidity in the financial markets for coal. The
approximate percentage of coal and petcoke requirements contracted at
December 31, 2007 is as follows:

    - 2008 - 80%
    - 2009 - 60%
    - 2010 - 10%

    The contracted amounts would have been 100% for 2008, 70% for 2009 and 20%
for 2010, but for the exclusion of amounts related to the notice received from
a fuel supplier, referred to in NSPI's outlook section.

    Heavy Fuel Oil

    NSPI manages exposure to changes in the market price of heavy fuel oil
through the use of swaps, options, and forward contracts. The approximate
percentage of heavy fuel oil requirements hedged and contracted as at
December 31, 2007 is as follows:

    - 2008 - No deliveries planned, therefore, no hedge requirement
    - 2009 - 70%

    Natural Gas

    NSPI has entered into multi-year contracts to purchase approximately
61,600 mmbtu of natural gas per day. Volumes exposed to market prices are
managed using financial instruments where the fuel is required for NSPI's
generation; and the balance is sold against 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 using financial instruments. As at
December 31, 2007, amounts of natural gas volumes that have been economically
and/or financially hedged and contracted are approximately as follows:

    Natural gas:

    - 2008 - 100%
    - 2009 - 75%
    - 2010 - 55%

    Fuel Mix

    The ability to switch fuel at NSPI's Tufts Cove generating station
provides a dynamic and effective option in managing commodity price and supply
risk.

    Purchased Power

    Emera, along with its partner Brookfield, has entered into a contract with
Bear Swamp to provide the power necessary to produce the requirements of the
LIPA contract. Emera has hedged a portion of this requirement. For 2008, 100%
of the requirement is hedged and 40% of the requirement is hedged for 2009.

    Foreign Exchange

    The risk due to fluctuation of the Canadian dollar against the US dollar
for the cost of fuel is measured and managed. In 2008, NSPI expects
approximately 80% of its anticipated net fuel costs to be denominated in USD;
USD from sales of surplus natural gas will provide a natural hedge against a
portion of USD fuel costs.
    Emera 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 US dollars, reducing exposure to
currency rate fluctuations. Forward contracts to buy USD $380 million are in
place at a weighted average rate of $1.0852, representing over 90% of 2008
anticipated USD requirements. Forward contracts to buy USD $427.3 million for
years 2009 to 2011 at a weighted average rate of $1.0656 were outstanding at
December 31, 2007. These contracts cover 25% to 50% of anticipated
USD requirements in these years.
    Option contracts, to eliminate exposure to currency rate fluctuations for
2008, of $5.5 million at a rate of $1.0605 were outstanding on December 31,
2007.

    Interest Rates

    Emera 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 19% of total debt in 2008. Interest
rate caps are used to limit exposure to movements of interest rates on
floating debt. For 2008, interest on approximately 40% of floating debt is
capped at a weighted-average rate of 4.80%.

    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 on the Board of Directors' approved credit policies. The company
frequently uses collateral agreements within its negotiated master agreements
to further mitigate credit exposure.

    Regulatory Risk

    Nova Scotia Power

    NSPI faces risk with respect to the timeliness and certainty of full
recovery of costs, particularly fuel costs in light of their magnitude and
volatility. A central provision of the 2007 general rate application was an
agreement in principle that the UARB should establish a FAM for Nova Scotia
Power to ensure fuel costs are recovered from customers. In December 2007 the
UARB issued a decision that establishes achievable conditions for the
implementation of the FAM, effective January 1, 2009 with the first rate
adjustment under FAM occurring on January 1, 2010. The UARB will oversee the
fuel adjustment mechanism, including review of fuel costs, contracts and
transactions. The decision supports NSPI's position that a FAM is the best way
to ensure customer rates reflect the actual price of the fuel used to make
electricity. With the proposed implementation of the FAM in 2009, NSPI's
allowed return on equity reduces by 0.2%, changing its allowed earnings band
to 9.1% to 9.6%, with rates set at 9.35%.
    During 2006 the Province of Nova Scotia proposed, and later passed,
regulations under the Electricity Act that set out future requirements for
energy from renewable sources. The regulations require NSPI to meet targets
for an additional 5% of energy from renewable sources in 2010, and a further
5% in 2013. In 2007 NSPI announced that it expects to award approximately
240 MW of renewable energy capacity, to provide the renewable energy required
during the first target period.

    Bangor Hydro

    Bangor Hydro's business consists of three primary components which are
each governed by their own regulatory structure. The components include
distribution, transmission, and stranded costs.
    BHE's distribution business operates under the regulation of the Maine
Public Utilities Commission. BHE operated under an Alternate Rate Plan which
governed distribution rates for the past seven years and which expired at the
end of December 2007. In late 2007 the MPUC approved a modest increase in
distribution rates under a traditional cost-of-service regulatory structure.
In the event that costs rise faster than revenues, BHE would have the ability
to return to the MPUC at any time to request a further increase in rates.
    The transmission business of BHE is primarily regulated by the FERC. The
rates charged are determined by formula and are adjusted on an annual basis.
Bangor Hydro is a participating transmission owner within the Regional
Transmission Organization for New England, and its operations are therefore
linked with the transmission operations of all of New England. BHE's return on
equity on its transmission assets, and the extent to which BHE will receive
added incentives on the ROE for its transmission assets is determined by FERC
along with the regional transmission owners.
    BHE also has the ability to recover stranded costs of both regulatory
assets and the ongoing costs of both regulatory assets and purchasing power at
above-market prices. This ability eliminates the commodity risk involved with
fixed price contracts. As mentioned previously, BHE has filed a request for a
decrease in stranded cost rates effective Q1 2008.
    Metering, billing and settlement services for power suppliers are provided
directly by BHE within its service territory, and BHE is permitted to recover
all prudently incurred costs for these services.

    Labour

    In August, 2007 Nova Scotia Power reached an agreement with approximately
900 unionized employees replacing the contract which expired on July 31, 2007.
The new agreement is for fifty-six months and will expire on March 31, 2012.
    Bangor Hydro's contract with its unionized employees expired at the end of
2005 and a new agreement has been reached, which will expire in June 2010.

    Environmental Protection

    Corporate Environmental Governance

    Emera is committed to operating in a manner that is respectful and
protective of the environment, and in full compliance with legal requirements
and company policy. Emera and its wholly-owned subsidiaries have implemented
this policy through development and application of environmental management
systems ("EMS").
    Implementation of EMS has provided a systematic focus on environmental
issues such that risks are identified and managed proactively. All areas of
Emera undertook initiatives in 2007 to reduce potential environmental risks
and associated costs. Activities included, but were not limited to, reducing
air emissions, protecting water resources, and continued management of
PCB contaminated electrical equipment.
    Conformance with legislative and company requirements is verified through
a comprehensive environmental audit program. There were no significant
environmental or regulatory compliance issues identified during the 2007
audits. Plans are in place to promptly address any audit finding and
continually improve the environmental management of the operations.
    Oversight of environmental matters is carried out by the Board of
Directors of all Emera operating companies or committees of the Board or
Directors with specific environmental responsibilities. In addition, an
Environmental Council, made up of senior Emera employees with working
accountability for environment, continues to guide the implementation of
programs that address key environmental issues.
    In addition to programs for employees, the EMS procedures of all
wholly-owned subsidiaries include planning, implementing and monitoring of
contractors' performance.
    In 2007, NSPI was audited by the Canadian Electricity Association ("CEA")
to verify the quality of its environmental reporting and management systems.
The auditor from the CEA concluded that NSPI had "robust programs,
environmental leadership and a strong, mature EMS."

    Climate Change and Air Emissions

    NSPI has been identified as a climate disclosure leader by the
Conference Board of Canada's Climate Disclosure Project for having shown
distinction in climate change reporting.
    In April 2007 the federal government unveiled a regulatory framework for
air emissions that proposes reductions in greenhouse gases ("GHG") and air
emissions from industry. The framework proposes an 18% reduction of
GHG intensity (i.e., mass of GHG per kWh) by 2010, with an additional
2% improvement of intensity each year thereafter. It also proposes the
establishment of nationwide emission caps for sulphur dioxide, nitrogen
oxides, volatile organics and particulate matter that would see further
reductions of these compounds.
    In January 2007, the Nova Scotia Government announced the Renewable Energy
Standards Regulations requiring NSPI to increase the supply of renewable
energy by 5% by 2010 and 10% by 2013. In April 2007, the province enacted an
Act Respecting Environmental Goals and Sustainable Prosperity which, among
other measures, established an objective of reducing provincial greenhouse gas
emissions to 10 percent below 1990 levels by 2020.
    The Company continues to work with the federal and provincial governments
on these matters. It is expected that compliance costs will be material, but
the company is not able to forecast, pending legislative action.

    NSPI's approach to reducing emissions and greenhouse gases includes:

    - The planned addition, via contract, of approximately 300MW of renewable
      energy by 2010, primarily wind;

    - Strategic investments in clean, gas fired generation such as the
      addition of an approximate $55 million heat recovery boiler to the
      Tufts Cove generating station;

    - Assessing new technologies such as stream tidal power together with the
      company's partner OpenHydro Group Limited and undertaking research with
      Dalhousie University and the Canadian Clean Power Coalition on carbon
      sequestration;

    - Plans for transmission investments to strengthen the provincial bulk
      power delivery system and interprovincial connection to enable the
      importation of non-greenhouse gas emitting electricity; and

    - Fuel switching to reduce sulfur dioxide by 50 percent in 2010;
      approximately $30 million of technology additions have been and are
      being made to reduce nitrogen oxide emissions by 40 percent by 2009;
      and assessing the appropriate means to reduce mercury emissions


    Summary of Quarterly Reports

    For the quarter ended
    millions of dollars (except earnings per common share)
    -------------------------------------------------------------------------
                  Q4      Q3      Q2      Q1      Q4      Q3      Q2      Q1
                2007    2007    2007    2007    2006    2006    2006    2006
    -------------------------------------------------------------------------
    Total
     revenues $343.9  $310.3  $325.4  $359.9  $307.0  $272.4  $275.9  $310.7
    -------------------------------------------------------------------------
    Net
     earnings
     appli-
     cable to
     common
     shares     36.6    40.9    34.1    39.7    33.5    19.5    29.2    43.6
    -------------------------------------------------------------------------
    Earnings
     per
     common
     share -
     basic      0.33    0.37    0.30    0.36    0.30    0.18    0.26    0.40
    -------------------------------------------------------------------------
    Earnings
     per
     common
     share -
     diluted    0.32    0.35    0.30    0.35    0.30    0.18    0.26    0.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Quarterly total revenues and 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 year.


                           MANAGEMENT REPORT

    Management's Responsibility for Financial Reporting

    The accompanying consolidated financial statements of Emera Inc. ("Emera")
and the information in this annual report are the responsibility of management
and have been approved by the Board of Directors ("Board").
    The consolidated 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. ("NSPI"), one of
Emera's wholly-owned electric utilities and principal subsidiary, is regulated
by the Nova Scotia Utility and Review Board, which also examines and approves
NSPI's accounting policies and practices. Emera's other wholly-owned electric
utility and subsidiary, Bangor Hydro-Electric Company ("Bangor Hydro"), is
regulated by the Federal Energy Regulatory Commission and the Maine Public
Utilities Commission, which also examine and approve Bangor Hydro's accounting
policies and practices. In preparation of these consolidated 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 consolidated 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
consolidated 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 consolidated financial statements.
    Emera 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 Emera'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 consolidated 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 Emera. The Audit 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 consolidated financial statements and the
external auditors' report. The Audit Committee reports its findings to the
Board for consideration when approving the consolidated financial statements
for issuance to the shareholders. The Audit Committee also considers, for
review by the Board and approval by the shareholders, the appointment of the
external auditors.
    The consolidated financial statements have been audited by Ernst & Young
LLP, the external auditors, in accordance with Canadian generally accepted
auditing standards. Ernst & Young LLP has full and free access to the Audit
Committee.

    February 14, 2008

    "Christopher Huskilson"                        "Nancy Tower, FCA"
    President and Chief Executive Officer          Chief Financial Officer


                               AUDITORS' REPORT

    To the Shareholders of Emera Inc.

    We have audited the consolidated balance sheets of Emera Inc. as at
December 31, 2007 and 2006 and the consolidated statements of earnings, cash
flows, and changes in shareholders' equity for the years then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
    We conducted our audits in accordance with 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, 2007 and
2006 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
    February 14, 2008

    "Ernst & Young LLP"
    Chartered Accountants


    Emera Inc.
    Consolidated Statements of Earnings
    Year Ended December 31

    millions of dollars (except earnings
    per common share)                                        2007       2006
    -------------------------------------------------------------------------
    Revenue
      Electric                                           $1,269.5   $1,132.0
      Other                                                  70.0       34.0
    -------------------------------------------------------------------------
                                                          1,339.5    1,166.0
    -------------------------------------------------------------------------
    Cost of operations
      Fuel for generation and purchased power               494.5      347.7
      Operating, maintenance and general                    264.8      255.6
      Provincial, state, and municipal taxes                 47.5       48.0
      Depreciation                                          149.3      145.2
      Regulatory amortization                                31.4       22.8
      Allowance for funds used during construction          (12.3)      (5.8)
    -------------------------------------------------------------------------
                                                            975.2      813.5
    -------------------------------------------------------------------------
    Earnings from operations                                364.3      352.5
    Equity earnings (note 6)                                 12.8        4.9
    -------------------------------------------------------------------------
                                                            377.1      357.4
    Interest (note 7)                                       118.7      127.1
    Preferred share dividends paid
     by subsidiaries (note 10)                               14.1       14.1
    Amortization of defeasance costs                         12.7       12.7
    Other income (note 8)                                       -       (8.9)
    -------------------------------------------------------------------------
    Earnings before income taxes                            231.6      212.4
    Income taxes (note 9)                                    80.3       86.6
    -------------------------------------------------------------------------
    Net earnings applicable to common shares               $151.3     $125.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common share - basic (note 11)             $1.36      $1.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common share - diluted (note 11)           $1.32      $1.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    Emera Inc.
    Consolidated Balance Sheets
    As at December 31
    millions of dollars                                      2007       2006
    -------------------------------------------------------------------------
    Assets
    Current assets
      Cash and cash equivalents                             $26.4      $19.5
      Restricted cash                                         1.0          -
      Accounts receivable (note 12)                         274.2      253.6
      Income tax receivable                                  13.7        5.3
      Inventory                                              99.7      113.6
      Prepaid expenses                                       56.9       53.9
      Future income tax assets (note 9)                       6.7       18.9
      Derivatives in a valid hedging relationship (note 2)   11.9          -
      Held-for-trading derivatives (note 2)                  79.5       26.5
    -------------------------------------------------------------------------
                                                            570.0      491.3
    -------------------------------------------------------------------------
    Long-term receivable (note 12)                            7.7          -
    -------------------------------------------------------------------------
    Derivatives in a valid hedging relationship (note 2)     11.0          -
    -------------------------------------------------------------------------
    Held-for-trading derivatives (note 2)                    64.1        2.0
    -------------------------------------------------------------------------
    Deferred charges (notes 2 and 13)                       367.2      468.2
    -------------------------------------------------------------------------
    Future income tax assets (note 9)                        16.2       10.0
    -------------------------------------------------------------------------
    Goodwill (note 17)                                       82.8       97.1
    -------------------------------------------------------------------------
    Investments subject to significant
     influence (notes 2 and 6)                              124.5       98.5
    -------------------------------------------------------------------------
    Property, plant & equipment (note 14)                 2,820.0    2,756.4
    -------------------------------------------------------------------------
    Construction work in progress                           109.2      125.5
    -------------------------------------------------------------------------
                                                          2,929.2    2,881.9
    -------------------------------------------------------------------------
                                                         $4,172.7   $4,049.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities and Shareholders' Equity
    Current liabilities
      Current portion of long-term
       debt (notes 2 and 20)                               $121.0       $3.4
    Short-term debt (note 19)                               104.6      133.2
    Accounts payable and accrued charges                    282.7      286.0
    Income tax payable                                        3.2       39.3
    Dividends payable                                         3.2        3.2
    Future income tax liabilities (note 9)                    2.0          -
    Derivatives in a valid hedging relationship (note 2)     43.8          -
    Held-for-trading derivatives (note 2)                    25.3       25.9
    -------------------------------------------------------------------------
                                                            585.8      491.0
    -------------------------------------------------------------------------
    Derivatives in a valid hedging relationship (note 2)     33.1          -
    -------------------------------------------------------------------------
    Held-for-trading derivatives (note 2)                     7.6        1.4
    -------------------------------------------------------------------------
    Future income tax liabilities (note 9)                   82.9       86.2
    -------------------------------------------------------------------------
    Asset retirement obligations (note 18)                   83.8       78.1
    -------------------------------------------------------------------------
    Deferred credits (notes 2 and 13)                       158.9       66.1
    -------------------------------------------------------------------------
    Long-term debt (notes 2 and 20)                       1,600.2    1,657.4
    -------------------------------------------------------------------------
    Preferred shares issued by subsidiary (note 10)         260.0      260.0
    -------------------------------------------------------------------------
    Non-controlling interest                                  0.6        0.7
    -------------------------------------------------------------------------
    Shareholders' equity
      Common shares (note 21)                             1,066.2    1,055.2
      Contributed surplus                                     3.0        2.2
      Accumulated other comprehensive income (note 2)      (209.0)    (100.2)
      Retained earnings (note 2)                            499.6      450.9
    -------------------------------------------------------------------------
                                                          1,359.8    1,408.1
    -------------------------------------------------------------------------
                                                         $4,172.7   $4,049.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contingencies (note 24), Commitments (notes 5, 22 and 25), Guarantees
    (note 26)

    See accompanying notes to the consolidated financial statements.

    Approved on behalf of the Board of Directors

    "Derek Oland"                      "Christopher Huskilson"
    Chairman                           President and Chief Executive Officer


    Emera Inc.
    Consolidated Statements of Cash Flows
    Year Ended December 31

    millions of dollars                                      2007       2006
    -------------------------------------------------------------------------
    Operating activities
    Net earnings applicable to common shares               $151.3     $125.8
    Non-cash items:
      Depreciation                                          149.3      145.2
      Amortization of deferred charges                       14.1       13.9
      Equity earnings                                       (12.8)      (4.9)
      Regulatory amortization                                31.4       22.8
      Allowance for funds used during construction          (12.3)      (5.8)
      Future income taxes                                    13.2        5.1
      Post-retirement benefits                               15.2        9.1
      Reduction in regulatory asset (note 9)                 16.4          -
      Other non-cash operating items                         (5.9)      (1.4)
      Other cash operating items                              4.6        3.4
    -------------------------------------------------------------------------
                                                            364.5      313.2
    Change in non-cash operating working capital            (13.1)      19.3
    -------------------------------------------------------------------------
    Net cash provided by operating activities (note 10)     351.4      332.5
    -------------------------------------------------------------------------
    Investing activities
      Property, plant and equipment                        (251.6)    (193.7)
      Increase in restricted cash                            (1.0)         -
      Retirement spending net of salvage                     (5.0)      (3.2)
      Acquisition (note 15)                                 (25.7)         -
      Other investing activities                             (5.6)         -
    -------------------------------------------------------------------------
    Net cash used in investing activities                  (288.9)    (196.9)
    -------------------------------------------------------------------------
    Financing activities
      Retirements of long-term debt                          (2.8)    (112.6)
      Issuance of long-term debt                            117.1          -
      (Decrease) increase in short-term debt                (22.2)      30.5
      Issuance of common shares                              10.7       15.3
      Dividends on common shares                            (99.9)     (98.3)
      Long-term financing of asset sale                         -       20.0
      Accounts receivable securitization                    (55.0)         -
      Other financing activities                             (3.5)       1.7
    -------------------------------------------------------------------------
    Net cash used in financing activities (note 10)         (55.6)    (143.4)
    -------------------------------------------------------------------------
    Increase (decrease) in cash and cash equivalents          6.9       (7.8)
    Cash and cash equivalents, beginning of year             19.5       27.3
    -------------------------------------------------------------------------
    Cash and cash equivalents, end of year                  $26.4      $19.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash and cash equivalents consists of:
    Cash                                                     $5.4      $10.9
    Short-term investments                                   21.0        8.6
    -------------------------------------------------------------------------
    Cash and cash equivalents, end of year                  $26.4      $19.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Supplemental disclosure of cash paid:
    Interest                                               $119.1     $122.0
    Income and capital taxes                               $108.2      $46.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements



    Emera Inc.
    Consolidated Statements of Changes in Shareholders' Equity
    -------------------------------------------------------------------------
    For the year
    ended
    December 31,
    2007                                      Accumula-
    millions of                              ted Other
    dollars                                  Comprehen-                Total
                                   Contribu-      sive              AOCI and
                          Common        ted     Income   Retained   Retained
                          Shares    Surplus    ("AOCI")  Earnings   Earnings
    -------------------------------------------------------------------------
    Balance, December
     31, 2006           $1,055.2       $2.2    $(100.2)    $450.9     $350.7
    -------------------------------------------------------------------------
    Implementation
     adjustment (note 2)       -          -       (5.3)      (2.7)      (8.0)
    -------------------------------------------------------------------------
    Comprehensive
     Income:
    Net earnings
     applicable to
     common shares             -          -          -      151.3      151.3
    Net loss on
     derivatives in
     a valid hedging
     relationship              -          -      (58.2)         -      (58.2)
    Reclassification
     of hedging losses
     included in income        -          -       14.6          -       14.6
    Reclassification
     of hedging losses
     included in
     inventory                 -          -        2.4          -        2.4
    Unrealized loss on
     translation of
     self-sustaining
     foreign
     operations                -          -      (62.1)         -      (62.1)
    Other                                         (0.2)         -       (0.2)
    -------------------------------------------------------------------------
    Total
     comprehensive
     income                    -          -     (103.5)     151.3       47.8
    -------------------------------------------------------------------------
    Dividends declared
     on common shares          -          -          -      (99.9)     (99.9)
    Common shares
     issued under
     purchase plans          9.0          -          -          -          -
    Senior management
     stock options
     exercised               1.7          -          -          -          -
    Stock option
     expense                   -        0.8          -          -          -
    Other share-based
     compensation            0.3          -          -          -          -
    -------------------------------------------------------------------------
    Balance,
     December 31, 2007  $1,066.2       $3.0    $(209.0)    $499.6     $290.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------


    For the year
    ended
    December 31,
    2006
    millions of
    dollars                                                            Total
                                   Contribu-                        AOCI and
                          Common        ted              Retained   Retained
                          Shares    Surplus       AOCI   Earnings   Earnings
    -------------------------------------------------------------------------
    Balance,
    December 31, 2005   $1,039.2       $1.8     $(98.2)    $423.4     $325.2
    -------------------------------------------------------------------------
    Comprehensive
     Income:
    Net earnings
     applicable to
     common shares             -          -          -      125.8      125.8
    Unrealized loss
     on translation of
     self-sustaining
     foreign
     operations                -          -       (2.0)         -       (2.0)
    -------------------------------------------------------------------------
    Total
     comprehensive
     income                    -          -       (2.0)     125.8      123.8
    -------------------------------------------------------------------------
    Dividends declared
     on common shares          -          -          -      (98.3)     (98.3)
    Common shares
     issued under
     purchase plans          8.6          -          -          -          -
    Senior management
     stock options
     exercised               6.7       (0.5)         -          -          -
    Stock option
     expense                   -        0.9          -          -          -
    Other share-based
     compensation            0.7          -          -          -          -
    -------------------------------------------------------------------------
    Balance,
    December 31, 2006   $1,055.2       $2.2    $(100.2)    $450.9     $350.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    Emera Inc.
    Notes to the Consolidated Financial Statements

    December 31, 2007 and 2006

    1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    Emera Inc. ("Emera" or the "Company"), incorporated in the Province of
Nova Scotia, through its principal subsidiaries, Nova Scotia Power Inc. ("Nova
Scotia Power" or "NSPI") and Bangor Hydro-Electric Company ("Bangor Hydro" or
"BHE"), is engaged in the production and sale of electric energy.
    Nova Scotia Power is the primary electricity supplier in Nova Scotia
providing over 95% of electricity generation, transmission and distribution in
the province. NSPI is a public utility as defined under the Public Utilities
Act of Nova Scotia ("Act") and is subject to regulation under the Act by the
Utility and Review Board ("UARB"). The Act gives the UARB authority over
NSPI's operations and expenditures. Electricity rates for NSPI's customers are
subject to UARB approval. NSPI is not subject to an annual rate review
process, but rather participates in hearings from time to time at NSPI's or
the regulator's request.
    NSPI is regulated under a cost of service model, with rates set to cover
prudently incurred costs of providing electricity service to customers, and
provide an opportunity to earn an appropriate return to investors. NSPI's
return on equity ("ROE") range is 9.3% to 9.8%, on a maximum allowed common
equity component of 40% of the total capitalization. Rates were last set using
9.55% ROE with a common equity component of 37.5%.
    NSPI's accounting policies are subject to examination and approval by the
UARB.
    Bangor Hydro's core business is the transmission and distribution ("T&D")
of electricity. Electricity is deregulated in Maine, and several suppliers
compete to provide customers with the commodity that is delivered through the
BHE T&D network. In addition to the T&D network, BHE has substantial net
regulatory assets (stranded costs), which arose through the electricity
industry restructuring, and as a result of rate and accounting orders issued
by its regulators. Approximately 55% of BHE's electric rates represent
distribution services, 30% relate to stranded costs recoveries, and 15% to
transmission service. The rates for each element are established in distinct
regulatory proceedings. The transmission operations are regulated by the
Federal Energy Regulatory Commission ("FERC"), and the distribution operations
and stranded costs are regulated by the Maine Public Utilities Commission
("MPUC").
    For distribution services, BHE operated under an Alternate Rate Plan
("ARP") through December 31, 2007, which provided for an earnings band of 5%
to 17% return on equity on distribution operations, with rates set at the
midpoint of 11%. There was a 50/50 sharing mechanism between BHE and customers
outside of the earnings band. The ARP also included performance standards and
provided for average annual reductions in distribution rates of approximately
2.5% for five years, to 2007.
    In December 2007, the MPUC replaced rates set forth in the ARP, approving
an increase of approximately 2% in distribution rates effective January 1,
2008, providing for a traditional cost-of-service model. The earnings band and
associated sharing mechanism, performance standard, and annual distribution
rate reductions are no longer applicable starting January 1, 2008. The allowed
ROE used in setting the new distribution rates is 10.2%, with a 50% common
equity ratio.
    BHE's stranded cost rates provide for an allowed return on equity of 10%
on the related asset base for the three-year period ending February 29, 2008.
In December 2007 the MPUC issued an order approving an approximately 25%
reduction in stranded cost rates for the three-year period beginning March 1,
2008. The allowed ROE used in setting the new stranded cost rates is 8.5%.
    Transmission rates are set by the FERC annually on July 1, based on the
prior year's revenue requirement. The allowed ROE for transmission operations
ranges from 10.9% for low voltage transmission up to 12.4% for high voltage
transmission developed as a result of the regional system plan, which includes
the NRI project.
    Bangor Hydro's accounting policies are subject to examination and approval
by FERC and the MPUC.
    Brunswick Pipeline is a greenfield pipeline project under development that
will deliver natural gas from the Canaport(TM) Liquefied Natural Gas ("LNG")
import terminal, currently under construction, near Saint John, New Brunswick
to markets in Canada and the US northeast. The 145 kilometer Brunswick
Pipeline will travel through southwest New Brunswick and connect with the
Maritimes and Northeast Pipeline ("M&NP") at the Canada/US border near
Baileyville, Maine.
    Canaport(TM) LNG is a partnership of Repsol YPF, S.A. ("Repsol") and
Irving Oil Limited. Emera has negotiated a 25 year send or pay toll agreement
with Repsol to transport natural gas through the Brunswick Pipeline. Toll
rates were set using a return on project equity of 11% - 14% and have been
approved by the National Energy Board which regulates Brunswick Pipeline.
    Emera follows Canadian generally accepted accounting principles ("GAAP").
The accounting policies approved by the regulators of NSPI, Bangor Hydro, and
Brunswick Pipeline may differ from GAAP for non rate-regulated companies in
that the timing of recognition of certain revenues and expenses in these
operations may differ from that otherwise expected under GAAP. Where the
differences between GAAP and GAAP for rate-regulated companies are considered
significant, disclosure of the policy has been made in these notes to the
consolidated financial statements.

    a.  Consolidation

    The consolidated financial statements include the accounts of Emera Inc.
and its subsidiaries. Intercompany transactions and accounts have been
eliminated.

    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 policy is as follows:

    - 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.
    - Energy Marketing: Derivatives that are not entered into for hedging
      purposes are recognized at fair market value at year-end.
    - 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.

    Electric revenues generated by NSPI and Bangor Hydro are recognized at
rates set by their respective regulators. The Company is unable to determine
the effect on electric revenue in the absence of rate regulation.


    d. Allowance for Funds Used during Construction

    Accounting for the impact of rate regulation:

    In accordance with accounting policies determined by their respective
regulators, NSPI, Bangor Hydro, and Brunswick Pipeline provide for the cost of
financing construction work in progress by including an allowance for funds
used during construction ("AFUDC") as an addition to the cost of property
constructed, using a weighted average cost-of-capital. AFUDC is included in
property, plant and equipment and construction work in progress for financial
reporting purposes and is charged to operations through depreciation over the
service life of the related assets and recovered through future revenues.
Since AFUDC includes not only an interest component, but also an equity
component, it exceeds the amount that could be capitalized in the absence of
the regulated accounting policies.

    e. Regulatory Amortization

    Accounting for the impact of rate regulation:

    In accordance with the regulations of the UARB, significant assets of Nova
Scotia Power, 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. Prior to 2007 the unamortized
portion of the generation station was included in property, plant and
equipment, however, amortization was completed in Q4 2007. In the absence of
the UARB's approved accounting policies, the generation station would have
been written off in the year when NSPI determined that the unamortized cost of
the generating station would not be recoverable. More details are provided in
note 14.

    NSPI has a regulatory asset related to pre-2003 income taxes that have
been paid, but not yet recovered from customers. This circumstance arose when
NSPI claimed capital cost allowance ("CCA") deductions in its income tax
returns that were ultimately disallowed by a decision of the Supreme Court of
Canada. NSPI applied to the regulator to include recovery of these costs in
customer rates. The UARB approved recovery of this regulatory asset over eight
years, commencing April 1, 2007. In the absence of UARB approved recovery, the
liability would have been expensed when incurred. More details are provided in
note 13.

    The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period January 1, 2005 until April 1, 2005, the date when new rates became
effective. The UARB approved recovery of this regulatory asset over eight
years, commencing April 1, 2007. In the absence of UARB approved deferral, the
taxes would have been expensed in 2005. More details are provided in note 13.

    In accordance with rate and accounting orders issued by the MPUC, Bangor
Hydro has recorded regulatory assets and liabilities on its balance sheet.
These regulatory assets and liabilities are being amortized over varying lives
expiring through to 2018 through charges to earnings. These regulatory assets
and liabilities are included in deferred assets and deferred liabilities and
include costs related to restructuring a purchased power contracts, the
Seabrook nuclear project, decommissioning costs for Maine Yankee, obligations
to Hydro-Quebec, and the stranded cost revenue requirement levelizer, and are
described in more detail in note 13.


    f. Property, Plant and Equipment

    Property, plant and equipment are recorded at original cost, net of
contributions in aid of construction. When property, plant and equipment are
replaced or retired, any remaining net book value is charged to net earnings.

    Depreciation is determined by the straight-line method, based on the
estimated remaining service lives of the depreciable assets in each category.
The estimated average service life for the Company's unregulated general
assets is 8 years (2006 - 6 years). Unregulated generation assets have an
estimated average service life of 51 years (2006 - 51 years).

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

    Accounting for the impact of rate regulation:

    During 2003, following completion of a depreciation study, and a
negotiated agreement with stakeholders, NSPI's regulator approved new
depreciation rates which were to be phased in over four years beginning in
2004. In the decision on NSPI's 2005 rate application, the UARB delayed the
phase-in of year two rates for one year. In the decision on NSPI's 2006 rate
application, the UARB approved restarting of the phase-in including year-two
in 2006 rates. In its February 5, 2007 decision, the UARB postponed the
scheduled year-three phase-in of increased depreciation rates until the next
rate application. Absent consideration of growth in plant-in-service, the
phase-in of new depreciation rates will increase depreciation expense by a
cumulative increase of $20 million over the phase-in period. In the absence of
the UARB's approval of depreciation rates, NSPI would be required to set rates
based on management's best estimates of useful lives. The average rates for
the major categories of plant in service are summarized as follows:

    Function                                                 2007       2006
    -------------------------------------------------------------------------
    Generation
      Thermal                                                2.44%      2.44%
      Gas turbines                                           2.32%      2.32%
      Combustion turbines                                    3.33%      3.33%
      Hydroelectric                                          1.39%      1.39%
      Wind turbines                                          5.00%      5.00%
    Transmission                                             2.65%      2.65%
    Distribution                                             4.04%      4.04%
    General plant                                            7.12%      6.55%
    General plant under capital lease                           -      11.97%
    Weighted average depreciation rate                       3.07%      3.06%
    -------------------------------------------------------------------------

    Bangor Hydro's depreciation is determined by the straight-line method,
based on the estimated service lives of the depreciable assets in each
category. In 2004 BHE implemented the results of a depreciation study that was
completed in 2004 and approved by its regulators. The estimated average
service lives in years for the major categories of plant in service are
summarized as follows:

    Function                                                 2007       2006
    -------------------------------------------------------------------------
    Transmission                                               46         45
    Distribution                                               36         35
    Other                                                      15         17
    Weighted average service life                              36         33
    -------------------------------------------------------------------------


    In accordance with regulator approved accounting policies, when
depreciable property, plant and equipment of NSPI and Bangor Hydro 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 operation in the future through adjustments to depreciation
expense. In the absence of regulator approved accounting policies, gains and
losses on the disposition of property, plant and equipment are charged to net
earnings as incurred.

    g. Capitalization Policy

    Capital assets of the Company include labour, materials, and other
non-labour costs directly attributable to the capital activity. In addition,
in order to ensure the full cost approach, overhead costs that contribute to
the capital program are allocated to capital projects. These costs include
corporate costs such as finance, information technology, executive and other
support functions, and employee benefits, insurance, inventory costs, and
fleet operating and maintenance costs. The Company calculates an application
rate and only eligible operating expenditures are used in the calculation. The
Company applies overhead costs based on direct labour costs. The application
rate varies depending on the type of capital expenditure. In addition, BHE
applies inventory overhead based on inventory issued to the project, and
applies general and administrative overhead based upon non-labour charges.

    h. Leases

    Leases that substantially transfer all the benefits and risks of ownership
of property, plant and equipment to the Company, or otherwise meet the
criteria for capitalizing a lease under GAAP, are accounted for as capital
leases. An asset is recognized at the time a capital lease is entered into
together with its related long-term obligation. Property, plant and equipment
recognized under capital leases are depreciated on the same basis as described
in note 1(f). Payments on operating leases are expensed as incurred.

    i. Income Taxes and Investment Tax Credits

    Emera follows the future income tax method of accounting for 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.

    Accounting for the impact of rate regulation:

    In accordance with ratemaking regulations established by the UARB, NSPI
uses the taxes-payable method of accounting for income taxes. Bangor Hydro
uses the future income tax method where allowed for ratemaking purposes.
Brunswick Pipeline uses the taxes-payable method as allowed for ratemaking
purposes. NSPI, Bangor Hydro, and Brunswick Pipeline would be required to
recognize all future income tax assets and liabilities in the absence of their
regulator approved accounting policies. More details are provided in note 9.

    j. 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 investment gains and losses, relative to the assumed
rate of return, 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 years of future
service to the full eligibility date for active employees.
    For any given year, when the 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 average remaining service period ("ARSP") is amortized on a
straight-line basis. For NSPI, the ARSP of the active employees is 10 years as
at December 31, 2007 (2006 - 10 years). For Bangor Hydro this excess is
amortized on a straight-line basis over the expected ARSP, in accordance with
ratemaking purposes, which is 12 years as at December 31, 2007 (2006 - 12
years). For Emera Inc., the ARSP of the active employees is 12 years as at
December 31, 2007 (2006 - N/A).
    On January 1, 2000 Emera 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 benefit cost and pension funding is recorded as a
deferred asset or credit on the balance sheet.

    k. Share-Based Compensation

    The Company has several share-based compensation plans, which are a common
share option plan for senior management, an employee common share purchase
plan, a deferred share unit plan, and a restricted share unit plan. The
Company accounts for its plans in accordance with the fair value based method
of accounting for share-based compensation.

    l. Cash and Cash Equivalents

    Short-term investments, which consist of money market instruments with
maturities of three months or less, are considered to be cash equivalents and
are recorded at cost, which approximates current market value. The short-term
investments have an effective interest rate of 3.73% at December 31, 2007
(2006 - 5.23%).

    m. Inventory

    Inventories of materials and supplies are valued at the lower of average
cost and market. Fuel inventory is valued at the lower of the weighted average
cost method, and net realizable value.

    n. Debt Financing Costs

    Financing costs pertaining to debt issues are amortized over the life of
the related debt using the effective interest method.

    o. Derivative Financial & Commodity Instruments

    The Company uses various financial instruments to hedge its exposure to
foreign exchange, interest rate, and commodity price risks. In addition, the
Company has contracts for the physical purchase and sale of natural gas, and
physical and financial contracts that are held-for-trading ("HFT").
Collectively, these contracts are referred to as derivatives.
    As a result of implementing new accounting standards related to financial
instruments and hedges in Q1 2007, the Company is now recognizing on its
balance sheet the fair value of all its derivatives that are not designated as
contracts held for normal purchase or sale. See note 2 for further details.
    Hedging relationships that meet stringent documentation requirements, and
can be proven to be effective both at the inception and over the term of the
relationship qualify for hedge accounting. Specifically, in a cash flow hedge,
the effective portion of the change in the fair value of hedging derivatives
is recorded in other comprehensive income and reclassified to earnings in the
same period the related hedged item is realized. Any ineffective portion of
the change in fair value of hedging derivatives is recognized in net earnings
in the reporting period.
    Where documentation and effectiveness requirements are not met, the change
in fair value of the derivative is recognized in earnings in the reporting
period. The Company also recognizes the change in fair value of its HFT
derivatives in earnings of the reporting period.
    If a cash flow hedge is terminated, the effective portion of the change in
fair value of the hedging derivative up until the date of termination remains
in accumulated other comprehensive income and is recognized in earnings in the
same period the related hedged risk is realized. The change in fair value of
the derivative, if retained, would then be recognized in earnings from the
termination date on.
    Amounts received or paid related to derivatives used to hedge foreign
exchange and commodity price risks are recognized in the cost of fuel
purchases. Amounts received or paid related to derivatives used to hedge
interest rate risks are recognized over the term of the hedged item in
interest expense. Amounts received or paid related to HFT derivatives are
reflected in other revenue.
    Cash flows related to derivatives are reflected in operating activities on
the statement of cash flows.

    Accounting for the impact of rate regulation:

    In accordance with Handbook Section 3865 Hedges, NSPI determined that it
can not meet the probability requirement of the standard for its derivatives
in place to hedge natural gas and heavy fuel oil for its Tufts Cove generating
station ("TUC"). This is due to the generating station's ability to fuel
switch and NSPI's economic dispatch based on the cost of these two fuels. The
UARB has allowed NSPI to apply hedge accounting to these derivatives as long
as the other requirements of handbook are met. Absent UARB approval, NSPI
would be required to recognize the fair value of these derivatives in
earnings.
    Nova Scotia Power has contracts for the purchase and sale of natural gas
at TUC that are considered HFT derivatives and accordingly are recognized on
the balance sheet at fair value. This reflects NSPI's history of buying and
reselling any natural gas not used in the production of electricity at TUC.
Changes in fair value of HFT derivatives are normally recognized in net
earnings. In accordance with NSPI's accounting policy for financial
instruments and hedges relating to TUC fuel, NSPI has deferred any changes in
fair value to a regulatory asset or liability.
    Further details on the regulatory assets and liabilities recognized as a
result of the above can be found in note 13.

    p. Goodwill

    Goodwill represents the excess of the purchase price of an acquired
business over the net amount of the fair values assigned to its assets and
liabilities and is not subject to amortization. The Company evaluates the
carrying value of goodwill for potential impairment through an annual review
and analysis of fair market value. Goodwill is also evaluated for potential
impairment between annual tests if an event or circumstances occur that more
likely than not reduces the fair value of a business below its carrying value.
Fair market value is determined by use of net present value financial models,
which incorporate management's assumptions of future profitability.

    q. Long-Term Investments

    The Company accounts for certain investments, over which it shares
control, using the proportionate consolidation method, whereby the Company
recognizes its pro-rata share of the jointly controlled assets and the
liabilities jointly incurred in the Company's balance sheet, recognizes its
pro-rata share of any revenue and expenses in the Company's statement of
earnings, and recognizes its pro-rata share of cash flows on the Company's
statement of cash flows. Emera accounts for its investment in Bear Swamp using
proportionate consolidation.
    The Company accounts for certain investments, over which it maintains
significant influence, but not control, using the equity method, whereby the
amount of the investment is adjusted annually for the Company's pro-rata share
of the income or loss of investment and reduced by the amount of any dividends
received. Emera accounts for its investments in Maritimes & Northeast
Pipeline, St. Lucia Electricity Services, Maine Yankee Atomic Power Company,
and Maine Electric Power Company Inc. using the equity method.

    r. Foreign Currency Translation

    Monetary assets and liabilities denominated in foreign currencies are
converted to Canadian dollars at rates of exchange prevailing at the balance
sheet date. The resulting differences between the translation at the original
transaction date and the balance sheet date are charged to earnings.
    Assets and liabilities of self-sustaining foreign operations are
translated using the exchange rates in effect at the balance sheet date and
the results of operations at the average rates for the period. The resulting
exchange gains and losses on the assets and liabilities are deferred and
included in other comprehensive income.

    s. Research and Development Costs

    All research and development costs are expensed in the year incurred
unless they qualify for deferral as a part of capital assets.

    2. CHANGE IN ACCOUNTING POLICIES

    The CICA has issued new accounting standards 1530 Comprehensive Income,
3855 Financial Instruments - Recognition and Measurement, and 3865 Hedges,
which were applicable to the Company effective January 1, 2007. In accordance
with the new accounting standards, the accounting policy changes were applied
retroactively without restatement of prior periods. The following provides
more information on each standard.

    Comprehensive Income

    As a result of the recently issued standard, a new item, accumulated other
comprehensive income, is recognized in the shareholders' equity section of the
consolidated balance sheets. AOCI includes the unrealized foreign exchange
translation adjustments on the Company's self-sustaining foreign operations,
the effective portion of changes in fair value of derivatives meeting the
requirements for cash flow hedges, and unrealized gains and losses on
financial assets classified as available-for-sale.

    Financial Instruments - Recognition and Measurement

    According to the new standard, financial assets are now classified as
loans and receivables, held-for-trading, available for sale, or held to
maturity. Financial liabilities are classified as either held-for-trading, or
other than held-for-trading. The financial assets and liabilities are subject
to different methods of measurement and classification in the financial
statements as follows:

    -------------------------------------------------------------------------
    Financial Instrument             Measured at       Change in fair value
                                                       recorded in
    -------------------------------------------------------------------------
      Loans and receivables          Amortized cost    N/A
      Held to maturity financial
      assets
      Other than held-for-trading
      financial liabilities
    -------------------------------------------------------------------------
      Held-for-trading financial     Fair value        Net earnings unless
      assets and liabilities                           deferral permitted
                                                       under regulatory
                                                       accounting
    -------------------------------------------------------------------------
      Available for sale financial                     Other comprehensive
      assets Fair value                                income
    -------------------------------------------------------------------------

    In accordance with the new standard, transaction costs associated with the
issuance of long-term debt are included in long-term debt and amortized using
the effective interest method.

    The Company has chosen January 1, 2003 as the transition date for embedded
derivatives and as a result, embedded derivatives in contracts written prior
to the transition date are not reflected as separate assets and liabilities on
the balance sheet. An embedded derivative is a component of a contract with
characteristics similar to a derivative.

    Hedges

    The new standard outlines the criteria for applying hedge accounting to
cash flow hedges, fair value hedges, and hedging foreign currency fluctuations
on self-sustaining foreign operations.
    Cash flow hedges are recognized on the balance sheet at fair value with
the effective portion of the hedging relationship recognized in other
comprehensive income. Any ineffective portion of the cash flow hedge is
recognized in net earnings. Amounts recognized in AOCI are reclassified to net
income in the same periods in which the hedged item is recognized in net
earnings.
    Fair value hedges and the related hedged items are recognized on the
balance sheet at fair value with any changes in fair value recognized in net
income. To the extent the fair value hedge is effective, the changes in fair
value of the hedge and the hedged item will offset each other.
    Hedges of self-sustaining foreign operations are recognized at fair value
with any changes in fair value recognized in other comprehensive income.
    Details of the amounts recognized upon implementation of the new
accounting standards, and the effect on the consolidated balance sheet as at
January 1, 2007 are summarized below:

    Consolidated Balance Sheet                 Balance  Effect of    Balance
    Selected Information                        Before   Implemen-     After
    millions of dollars                       Implemen-    tation   Implemen-
                                                tation     Adjust-    tation
                                                Adjust-      ment     Adjust-
                                                  ment                  ment
    -------------------------------------------------------------------------
    Current assets
      Energy marketing assets                    $37.3     $(37.3)         -
      Derivatives held in valid hedging
       relationship                                  -       13.9      $13.9
      Held-for-trading derivatives                   -       76.0       76.0
    Energy marketing assets                        2.0       (2.0)         -
    Derivatives in a valid hedging relationship      -       17.9       17.9
    Held-for-trading derivatives                     -      136.4      136.4
    Deferred charges                             468.2      (11.3)     456.9
    Investments                                   98.5      (98.5)         -
    Investments subject to significant
     influence                                       -       98.5       98.5
    -------------------------------------------------------------------------
                                                           $193.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Current liabilities
      Current portion of long-term debt           $3.4      $(0.2)      $3.2
      Energy marketing liabilities                36.7      (36.7)         -
      Derivatives held in a valid hedging
       relationship                                  -       26.6       26.6
      Held-for-trading derivatives                   -       39.7       39.7
    Energy marketing liabilities                   1.4       (1.4)         -
    Derivatives in a valid hedging
     relationship                                    -       10.6       10.6
    Held-for-trading derivatives                     -        2.6        2.6
    Deferred credits                              66.1      173.1      239.2
    Long-term debt                             1,657.4      (12.7)   1,644.7
    Shareholders' equity
      Foreign exchange translation adjustment   (100.2)     100.2          -
    Accumulated other comprehensive income           -     (105.5)    (105.5)
    Retained earnings                            450.9       (2.7)     448.2
    -------------------------------------------------------------------------
                                                           $193.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The effect on the January 1, 2007 balances can be further explained as
follows:

    Energy marketing assets and liabilities: The balances have been
reclassified to held-for-trading derivatives.

    Derivatives in a valid hedging relationship: This new account represents
the fair value of the Company's hedges. These derivatives are all designated
as hedging future expected cash flows.

    Held-for-trading derivatives: The new account includes the fair value of
certain of Nova Scotia Power's natural gas contracts, amounts previously
recognized as energy marketing assets and liabilities, and the fair value of
any derivatives that are not valid hedges.

    Deferred charges: The adjustment represents the reclassification of
deferred financing costs which are now netted against the related debt,
partially offset by the regulatory asset resulting from the fair value
recognition of certain of Nova Scotia Power's natural gas contracts.

    Investments: The adjustment represents the reclassification of equity
accounted investments to investments subject to significant influence.

    Investments subject to significant influence: This new account represents
the reclassification of equity accounted investments from the investments
account as noted above.

    Deferred credits: The adjustment represents the regulatory liability
resulting from the fair value recognition of certain of Nova Scotia Power's
natural gas contracts.

    Long-term debt (including current portion): The adjustment represents the
netting of deferred financing costs against the related debt.

    Foreign exchange translation adjustment: The adjustment represents the
reclassification of foreign exchange losses on self-sustaining foreign
operations to accumulated other comprehensive income.

    Accumulated other comprehensive income: The adjustment represents the
effective portion of the change in fair value of Nova Scotia Power's hedges,
and the cumulative foreign exchange loss on self-sustaining foreign
operations.

    Retained earnings: The adjustment represents the fair value of Bear
Swamp's interim contract with the Long Island Power Authority ("LIPA").

    As a result of implementing the accounting policy changes, earnings have
increased by $2.9 million ($1.7 million after-tax) in 2007, which represents
the change in fair value of Bear Swamp's interim LIPA contract and the
$0.2 million ineffective portion of the Company's hedges.

    Future Accounting Policy Changes

    The CICA has issued new accounting standards 1535 Capital Disclosures,
3031 Inventories, 3862 Financial Instruments - Disclosures, and 3863 Financial
Instruments - Presentation, which are applicable to Emera's 2008 fiscal year.
The CICA has also issued new accounting standards relating to rate-regulated
operations which are applicable to Emera's 2009 fiscal year. The following
provides more information on each new accounting standard.

    Capital Disclosures: This new standard requires disclosure of the
Company's objectives, policies, and processes for managing capital;
quantitative data about what the Company regards as capital; whether the
Company has complied with any capital requirements; and, if the Company has
not complied, the consequences of such non-compliance. The new accounting
standard covers disclosure only and will have no effect on the financial
results of the Company.

    Inventories: The new standard provides more guidance on the measurement
and disclosure requirements for inventories than the previous standard,
3030 Inventories. Specifically, the new standard requires that inventories be
measured at the lower of cost and net realizable value, and provides more
guidance on the determination of cost and its subsequent recognition as an
expense, including any write-down to net realizable value. The Company is
assessing the effect of the new standard and does not anticipate a material
effect on its results.

    Financial Instruments - Disclosures, and Financial Instruments -
Presentation: These new standards replace accounting standard 3861 Financial
Instruments - Disclosure and Presentation. Presentation requirements have not
changed. Enhanced disclosure is required to assist users of the financial
statements in evaluating the significance of financial instruments on the
Company's financial position and performance, including qualitative and
quantitative information about the Company's exposure to risks arising from
financial instruments. The new accounting standards cover disclosure only and
will have no effect on the financial results of the Company.

    Rate-Regulated Operations: These new standards included removing the
temporary exemption in Section 1100 Generally Accepted Accounting Principles
pertaining to the application of the section to the recognition and
measurement of assets and liabilities arising from rate regulation; and
amending Section 3465 Income Taxes to require the recognition of future income
tax assets and liabilities for the amount of future income taxes expected to
be included in future rates and recovered from or paid to future customers. As
a result of the new standard, Emera will recognize future income tax assets
and liabilities of its wholly-owned regulated subsidiaries. In accordance with
the Company's regulated accounting policies covering income taxes, Emera will
defer any future income taxes to a regulatory asset or liability where the
future income taxes are included in future rates, with no resulting effect on
net earnings.

    3. SEGMENT INFORMATION

    The Company has two reportable segments: Nova Scotia Power and Bangor
Hydro. The Company evaluates performance based on contribution to consolidated
net earnings applicable to common shareholders. The accounting policies of the
reported segments are the same as those described in the summary of
significant accounting policies.

    Reported segments are determined based on Emera's operating activities.
NSPI is engaged in the production and sale of electric energy in Nova Scotia;
and Bangor Hydro is engaged in the transmission and distribution of electric
energy in central Maine. Other revenue is largely generated from energy
marketing margin and electric revenue from the Company's investment in Bear
Swamp.

    -------------------------------------------------------------------------
                                       Nova
                                     Scotia     Bangor
    millions of dollars               Power      Hydro     Other(*)    Total
    -------------------------------------------------------------------------
    Year ended December 31,
     2007:
    Revenues from external
     customers                     $1,113.5     $140.4     $85.6    $1,339.5
    Depreciation                      131.1       13.9       4.3       149.3
    Cost of operations,
     including depreciation           827.0       85.2      63.0       975.2
    Equity earnings                       -          -      12.8        12.8
    Interest expense                   97.6       13.7       7.4       118.7
    Income taxes                       62.1       14.0       4.2        80.3
    Net earnings applicable to
     common shareholders              100.2       27.5      23.6       151.3
    Net inter-segment revenues
     (expenses)                        89.3       (2.1)    (87.2)          -
    Capital expenditures              119.4       98.6      33.6       251.6
    As at December 31, 2007
    Total assets                    3,134.1      609.9     428.7     4,172.7
    Investments subject to
     significant influence                -        1.9     122.6       124.5
    Goodwill                              -       82.5       0.3        82.8
    -------------------------------------------------------------------------

    Year ended December 31, 2006:
    Revenues from external
     customers                       $977.4     $135.0     $53.6    $1,166.0
    Depreciation                      127.8       14.7       2.7       145.2
    Cost of operations, including
     depreciation                     670.4       96.6      46.5       813.5
    Equity earnings                       -          -       4.9         4.9
    Interest expense                  105.4       11.7      10.0       127.1
    Other income                        8.9          -         -         8.9
    Income taxes                       79.5       10.0      (2.9)       86.6
    Net earnings applicable to
     common shareholders              104.3       16.8       4.7       125.8
    Net inter-segment revenues
     (expenses)                       158.6       (3.8)   (154.8)          -
    Capital expenditures               99.0       81.5      13.2       193.7
    As at December 31, 2006
    Total assets                    3,061.5      644.6     342.9     4,049.0
    Investments subject to
     significant influence                -        2.7      95.8        98.5
    Goodwill                              -       97.1         -        97.1
    -------------------------------------------------------------------------
    (*)Other consists of corporate activities and adjustments to reconcile to
consolidated balances.

    4. EMPLOYEE FUTURE BENEFITS

    NOVA SCOTIA POWER PLANS

    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. Certain of Emera's corporate
employees participate in these plans and Emera Inc. is charged accordingly.
    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 the 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 unfunded long service award was closed to
new entrants effective August 1, 2007.
    The measurement date for the assets and obligations of each benefit plan
is December 31, 2007.

    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 as follows:

                                           Most recent         Next required
                                   actuarial valuation   actuarial valuation
    -------------------------------------------------------------------------
    Employee pension plan            December 31, 2007     December 31, 2008
    Acquired companies
     pension plan                    December 31, 2007     December 31, 2008
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total cash amount

    Total cash amount for 2007, made up of 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
$18.2 million (2006 - $22.8 million) for NSPI and Emera.



    Accrued pension and non-pension benefit asset (liability)

                                                  2007                  2006
                            -------------------------------------------------
                                    Defined-       Non-   Defined-       Non-
                                    benefit    pension    benefit    pension
                                    pension    benefit    pension    benefit
    millions of dollars               plans      plans      plans      plans
    -------------------------------------------------------------------------
    Assumptions (weighted average)
    Accrued benefit obligation
     - December 31:
    Discount rate                      5.75%      5.75%      5.25%      5.25%
    Rate of compensation
     increase                     3% to 5.5% 3% to 5.5% 3% to 5.5% 3% to 5.5%
    Health care trend
     - initial (next year)                -       7.00%         -       8.00%
     - ultimate                           -       4.00%         -       4.00%
     - year ultimate reached              -       2010          -       2010
    Benefit cost for year
     ending December 31:
    Discount rate                      5.25%      5.25%      5.25%      5.25%
    Expected long-term return
     on plan assets                    7.50%         -       7.50%         -
    Rate of compensation
     increase                     3% to 5.5% 3% to 5.5% 3% to 5.5% 3% to 5.5%
    Health care trend
     - initial (current year)             -       8.00%         -       9.00%
     - ultimate                           -       4.00%         -       4.00%
     - year ultimate reached              -       2010          -       2010
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Accrued benefit obligations
    Balance, January 1               $802.7      $39.6     $777.5      $34.8
    Employer current service
     cost                              12.7        1.5       12.6        1.3
    Employee contributions              5.0          -        4.7          -
    Interest cost                      41.6        2.0       40.4        1.8
    Past service amendments               -          -          -        2.4
    Actuarial (gains) losses          (46.1)       1.5       (1.5)       1.9
    Benefits paid                     (35.9)      (3.7)     (31.0)      (2.6)
    -------------------------------------------------------------------------
    Balance, December 31              780.0       40.9      802.7       39.6
    -------------------------------------------------------------------------
    Fair value of plan assets
    Balance, January 1                656.5          -      581.2          -
    Employer contributions             13.8        3.7       19.6        2.6
    Employee contributions              5.0          -        4.7          -
    Actual investment income            1.5          -       82.0          -
    Benefits paid                     (35.9)      (3.7)     (31.0)      (2.6)
    -------------------------------------------------------------------------
    Balance, December 31              640.9          -      656.5          -
    -------------------------------------------------------------------------
    Reconciliation of financial
     status to accrued benefit
     asset, December 31
    Fair value of plan assets         640.9          -      656.5          -
    Accrued benefit obligations       780.0       40.9      802.7       39.6
    -------------------------------------------------------------------------
    Plan deficit                     (139.1)     (40.9)    (146.2)     (39.6)
    Unamortized past service
     (gains) costs                     (0.5)       2.1       (0.5)       2.3
    Unamortized actuarial losses      191.4        1.8      213.2        0.6
    Unamortized transitional
     obligation                         0.1       11.2        0.1       13.4
    -------------------------------------------------------------------------
    Accrued benefit asset
     (liability)                      $51.9     $(25.8)     $66.6     $(23.3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The expected return on plan assets is determined based on the market-
    related value of plan assets of $601.7 million at January 1, 2007 (2006 -
    $578.1 million), adjusted for interest on certain cash flows during the
    year.



    Defined benefit plans asset
    allocation (% of plan assets)                 2007                 2006
                                  -------------------------------------------
                                              Acquired             Acquired
                                   Employee  companies   Employee companies
                                    pension    pension    pension   pension
                                       plan       plan       plan      plan
                                  -------------------------------------------
    Equity securities                    66%        60%        69%       62%
    Debt securities                      31%        38%        29%       37%
    Cash                                  3%         2%         2%        1%
    -------------------------------------------------------------------------
    Total                               100%       100%       100%      100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, the pension funds do not hold any material
investments in Emera Inc. or Nova Scotia Power Inc. securities. Any such
investment would primarily be held indirectly through pooled investment funds.

    Plans with accrued benefit obligations in excess of assets

    As at December 31, 2007, all post-retirement benefit plans have accrued
benefit obligations in excess of assets.


    Benefits cost components
    millions of dollars
                                                  2007                  2006
                            -------------------------------------------------
                                    Defined-       Non-   Defined-       Non-
                                    benefit    pension    benefit    pension
                                    pension    benefit    pension    benefit
    Defined benefits plan             plans      plans      plans      plans
                            -------------------------------------------------
    Costs arising from
     events during the year:
    Current service costs             $12.7       $1.6      $12.6       $1.3
    Interest on accrued
     benefits                          41.6        2.0       40.4        1.8
    Less: actual return
     on plan assets                    (1.5)         -      (82.0)         -
    Actuarial (gains) losses
     on accrued benefit
     obligation                       (46.1)       1.5       (1.5)       1.9
    Past service costs                    -          -          -        2.3
    -------------------------------------------------------------------------
    Future benefit costs
     before adjustments                 6.7        5.1      (30.5)       7.3
    Adjustments to recognize
     long-term nature of costs:
    Difference between expected
     return on assets and
     actual return                    (43.1)         -       38.9          -
    Amortization of transitional
     obligation                           -        2.2          -        2.3
    Difference between
     amortization of actuarial
     losses (gains) and actual
     actuarial losses (gains)
     on accrued benefit
     obligations                       64.8       (1.3)      21.4       (2.0)
    Difference between
     amortization of past
     service costs and past
     service costs for the year           -        0.2          -       (2.4)
    -------------------------------------------------------------------------
    Total cost recognized             $28.4       $6.2      $29.8       $5.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Defined contribution plan
    Employer cost                      $0.8          -       $0.7          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    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 had the following impact in 2007:

    millions of dollars                                  Increase   Decrease
    -------------------------------------------------------------------------
    Current service cost and interest cost                   $0.2      $(0.2)
    Accrued benefit obligation, December 31                  $2.0      $(1.6)
    -------------------------------------------------------------------------

    BANGOR HYDRO PLANS

    BHE maintains a non-contributory defined-benefit and a contributory
defined-contribution pension plan, which cover substantially all of its
employees, and a health care plan for its retirees. The defined benefit
pension is based on the years of service and average salary at the time the
employee terminates employment and provides no post-employment indexing. The
defined benefit pension plan was closed to new entrants effective February
2006.
    Other retirement benefit plans include an unfunded pension arrangement and
a contributory health care plan.
    The measurement date for the assets and obligations of each benefit plan
is December 31, 2007.

    Valuation date for defined-benefit plans

    BHE 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, 2006     December 31, 2007
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Total cash amount

    Total cash amount for 2007, made up of BHE contributions to its funded
defined-benefit pension plan, 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
$8.9 million (2006 - $10.7 million).


    Accrued pension and non-pension
    benefit liability
                                                  2007                  2006
                            -------------------------------------------------
                                    Defined-       Non-   Defined-       Non-
                                    benefit    pension    benefit    pension
                                    pension    benefit    pension    benefit
    millions of dollars               plans      plans      plans      plans
    -------------------------------------------------------------------------
    Assumptions
    (weighted average)
    Accrued benefit obligation
     - December 31:
    Discount rate                      6.75%      6.75%      6.00%      6.00%
    Rate of compensation increase      4.00%         -       4.00%         -
    Health care trend
     - initial (next year)                -       9.20%         -       8.40%
     - ultimate                           -       5.00%         -       5.00%
     - year ultimate reached              -       2013          -       2011
    Benefit cost for year ending
     December 31:
    Discount rate                      6.00%      6.00%      5.75%      5.75%
    Expected long-term return
     on plan assets                    8.00%      5.00%      8.00%      5.00%
    Rate of compensation increase      4.00%      4.00%      4.00%      4.00%
    Health care trend
     - initial (current year)             -       8.40%         -       9.20%
     - ultimate                           -       5.00%         -       5.00%
     - year ultimate reached              -       2011          -       2011
    -------------------------------------------------------------------------
    Accrued benefit obligations
    Balance, January 1                $84.0      $37.8      $85.8      $35.6
    Employer current service cost       1.3        0.8        1.5        0.7
    Interest cost                       4.5        2.1        4.7        1.8
    Past service amendments               -          -       (0.3)         -
    Actuarial (gains) losses           (7.9)       5.9       (3.2)       1.9
    Benefits paid                      (4.1)      (2.3)      (4.3)      (2.3)
    Foreign currency translation
     adjustment                       (12.3)      (6.3)      (0.2)       0.1
    -------------------------------------------------------------------------
    Balance, December 31               65.5       38.0       84.0       37.8
    -------------------------------------------------------------------------
    Fair value of plan assets
    Balance, January 1                 59.9        1.2       50.6        1.0
    Employer contributions              6.3        2.3        8.2        2.3
    Actual investment income            2.4        0.1        5.2          -
    Benefits paid                      (4.1)      (2.3)      (4.3)      (2.3)
    Foreign currency translation
     adjustment                        (9.5)      (0.3)       0.2        0.2
    -------------------------------------------------------------------------
    Balance, December 31               55.0        1.0       59.9        1.2
    -------------------------------------------------------------------------
    Reconciliation of financial
     status to accrued benefit
     asset, December 31
    Fair value of plan assets          55.0        1.0       59.9        1.2
    Accrued benefit obligations        65.5       38.0       84.0       37.8
    -------------------------------------------------------------------------
    Plan deficit                      (10.5)     (37.0)     (24.1)     (36.6)
    Unamortized past service
     costs (gains)                      1.1       (3.4)       1.5       (4.4)
    Unamortized actuarial losses        9.3       13.8       18.4       10.8
    Unamortized transitional
     obligation                           -        2.5          -        3.5
    -------------------------------------------------------------------------
    Accrued benefit liability         $(0.1)    $(24.1)     $(4.2)    $(26.7)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the defined benefit pension plan, the expected return on plan assets
    is determined based on the market-related value of plan assets of
    $50.1 million at January 1, 2007 (2006 - $51.9 million), adjusted for
    interest on certain cash flows during the year.



    Defined benefit plans
    asset allocation
    (% of plan assets)                           2007                   2006
                                ---------------------------------------------
                                Employee pension plan  Employee pension plan
    -------------------------------------------------------------------------
    Equity securities                              64%                    59%
    Debt securities                                35%                    40%
    Other                                           1%                     1%
    -------------------------------------------------------------------------
    Total                                         100%                   100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

     As at December 31, 2007, the pension fund does not directly hold any
investments in Emera or Bangor Hydro securities. However, as a significant
portion of assets for the benefit plans are held in mutual funds, there may be
indirect investments in these securities.

    Plans with accrued benefit obligation in excess of assets

    As at December 31, 2007, all post-retirement benefit plans have accrued
pension obligations in excess of assets.


    Benefits cost components
    millions of dollars                           2007                  2006
                            -------------------------------------------------
                                    Defined-       Non-   Defined-       Non-
                                    benefit    pension    benefit    pension
                                    pension    benefit    pension    benefit
    Defined benefit plan              plans      plans      plans      plans
                            -------------------------------------------------
    Costs arising from
     events during the year:
    Current service costs              $1.3       $0.8       $1.5       $0.7
    Interest on accrued
     benefits                           4.5        2.1        4.7        1.8
    Less: actual return
     on plan assets                    (2.4)      (0.1)      (5.2)         -
    Actuarial (gains) losses
     on accrued benefit
     obligation                        (7.9)       5.9       (3.2)       1.9
    Past service gains                    -          -       (0.3)         -
    -------------------------------------------------------------------------
    Future benefit costs
     before adjustments                (4.5)       8.7       (2.5)       4.4
    Adjustments to recognize
     long-term nature of costs:
    Difference between expected
     return on assets and actual
     return                            (2.1)       0.1        1.0          -
    Amortization of transitional
     obligation                           -        0.5          -        0.6
    Difference between
     amortization of actuarial
     losses (gains) and actual
     actuarial losses (gains)
     on accrued benefit
     obligations                        9.0       (4.9)       4.5       (1.1)
    Difference between
     amortization of past service
     costs and past service costs
     for the year                       0.2       (0.4)       0.6       (0.5)
    -------------------------------------------------------------------------
    Total cost recognized              $2.6       $4.0       $3.6       $3.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Defined contribution plan
    Employer cost                      $0.3          -       $0.2          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Sensitivity analysis for non-pension 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 had the following impact in 2007:

                                                         Increase   Decrease
    ------------------------------------------------------------------------
    Current service cost and interest cost                   $0.6      $(0.4)
    Accrued benefit obligation, December 31                  $7.1      $(5.6)
    ------------------------------------------------------------------------
    Accounting for the impact of rate regulation:

    When Bangor Hydro was purchased by Emera, BHE received regulatory approval
to continue amortizing certain existing balances over a period of 10 years.
Under GAAP, as a result of the purchase, these unamortized balances would have
been recognized immediately in the year BHE was purchased. In the absence of
the regulatory policy, BHE's total accrued benefit liability would be $36.3
million (2006 - $47.1 million) and the total defined benefits expense for 2007
would be $4.5 million (2006 - $4.8 million).

    5. OPERATING LEASES

    The Company has entered into operating lease agreements for office space,
telecommunication services, and certain other equipment, which expire in 2008
to 2020. Future minimum annual lease payments under the leases are as follows:


        millions of dollars
        ---------------------------------------------------------------
        2008                                                      $10.4
        2009                                                       10.0
        2010                                                        9.9
        2011                                                        1.6
        2012                                                        0.6
        Thereafter                                                  2.2
        ---------------------------------------------------------------
                                                                  $34.7
        ---------------------------------------------------------------
        ---------------------------------------------------------------

    For the year ended December 31, 2007 the Company recognized $12.3 million
(2006 - $7.1 million) in operating, maintenance and general expense.

    6. INVESTMENTS SUBJECT TO SIGNIFICANT INFLUENCE AND EQUITY EARNINGS

    Investments subject to significant influence are comprised of the
following:


                                                  2007                  2006
                                  -------------------------------------------
                                   Carrying     Equity   Carrying     Equity
    millions of dollars               value   earnings      value   earnings
    -------------------------------------------------------------------------
    Maritimes & Northeast
     Pipeline                         $99.8      $10.6      $95.8       $4.9
    St. Lucia Electricity
     Services Ltd.                     22.8        2.2          -          -
    Maine Yankee Atomic
     Power Company                      0.5          -        1.4          -
    Maine Electric Power
     Company Inc.                       1.4          -        1.3          -
    -------------------------------------------------------------------------
                                     $124.5      $12.8      $98.5       $4.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    7. INTEREST

    Interest expense consists of the following:

    millions of dollars                                      2007       2006
    -------------------------------------------------------------------------
    Interest on long-term debt                             $105.3     $104.4
    Interest on short-term debt                              21.6       16.5
    Amortization of debt financing                            1.8        1.8
    Refund interest on income tax recovery (note 9)          (6.8)         -
    Foreign exchange (gains) losses                          (3.2)       4.4
    -------------------------------------------------------------------------
                                                           $118.7     $127.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    8. OTHER INCOME

    During 2006, Nova Scotia Power received an $8.9 million insurance
settlement on a petcoke supply interruption claim related to 2005.

    9. INCOME TAXES

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

    millions of dollars                           2007                  2006
    -------------------------------------------------------------------------
    Earnings before income taxes     $231.6                $212.4
    -------------------------------------------------------------------------
    Income taxes, at
     statutory rates                   88.2       38.1%      80.9       38.1%
    Change in future income tax
     asset resulting from
     rate change                        0.9        0.4          -          -
    Income tax recovery               (10.8)      (4.7)         -          -
    Equity earnings not
     subject to tax                    (4.9)      (2.1)      (1.9)      (0.9)
    Unrecorded future income
     taxes on regulated earnings          -          -        4.2        2.0
    Other                               6.9        3.0        3.4        1.6
    -------------------------------------------------------------------------
                                       80.3       34.7%      86.6       40.8%
    Income taxes - current             67.1                  81.5
    -------------------------------------------------------------------------
    Income taxes - future             $13.2                  $5.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The future income tax assets and liabilities comprise the following:


                                       Current portion     Long-term portion
                                       --------------------------------------
    millions of dollars                2007       2006       2007       2006
    -------------------------------------------------------------------------
    Future income tax assets:
    Tax loss carry forwards            $6.2      $15.1      $11.7       $6.5
    Property, plant and equipment         -          -        1.7        1.6
    Other                               0.5        3.8        2.8        1.9
    -------------------------------------------------------------------------
                                       $6.7      $18.9      $16.2      $10.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Future income tax liabilities:
    Property, plant and equipment         -          -      $81.7      $85.9
    Deferred charges                      -          -        6.8       12.1
    Deferred credits                      -          -       (6.1)      (7.9)
    Tax loss carry forwards               -          -          -       (4.1)
    Other                              $2.0          -        0.5        0.2
    -------------------------------------------------------------------------
                                       $2.0          -      $82.9      $86.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, the Company has tax losses of $51.8 million,
which are reflected in future income tax assets or netted against future
income liabilities as appropriate, and expire as follows:

    millions of dollars
    -------------------------------------------------------------------------
    2009                                                                $2.4
    2010                                                                 9.6
    After 2012                                                          39.8
    -------------------------------------------------------------------------
                                                                       $51.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accounting for the impact of rate regulation:

    At December 31, 2007, the unrecorded future income tax asset of Emera's
wholly-owned regulated subsidiaries is approximately $40.7 million (2006 -
$34.0 million), of which $16.3 million (2006 - nil) is related to AOCI. The
unrecorded future income tax asset consists of deductible temporary
differences of $122.8 million (2006 - $97.1 million). In the absence of
regulatory approval of the taxes payable accounting policies, Emera would have
had a future income tax expense of $9.6 million in 2007 (2006 - $12.8 million
recovery).
    NSPI prepared and filed with Canada Revenue Agency ("CRA") amended tax
returns for the years 2000 to 2004 inclusive. CRA reviewed and approved the
amended filings, which has resulted in accelerated deductibility of certain
capitalized expenses. NSPI intends to amend tax returns for 2005 and 2006
using the same methodology and will continue to use this methodology when
filing its future tax returns. As a result, NSPI has recorded an income tax
recovery of $25.4 million, of which $14.6 million has been recorded as a
reduction of deferred charges. The remaining $10.8 million has been recorded
as a reduction of current income tax expense. In addition, NSPI received
refund interest of $8.6 million for the years 2000 to 2004, $1.8 million of
which has been recorded as a reduction of deferred charges. The remaining
$6.8 million has been recorded as a reduction of interest expense. Refund
interest has not been estimated for 2005 and 2006 as it is not reasonably
determinable.
    Absent NSPI's regulator approved taxes payable accounting policy, the
recovery would have no effect on the net current and future income tax expense
and net earnings for 2007 would be $10.8 million lower.

    10. PREFERRED SHARES ISSUED BY SUBSIDIARY

    Preferred shares issued by subsidiary consist of the preferred shares of
Nova Scotia Power Inc. and are classified as a financial liability on the
balance sheet.

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


                                                             Preferred Share
                                           Millions of               Capital
    Issued and outstanding:                     Shares   millions of dollars
    -------------------------------------------------------------------------
    January 1, 2006                               10.4                $260.0
    December 31, 2006                             10.4                 260.0
    December 31, 2007                             10.4                $260.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 and after April 1, 2009, Series C First Preferred Shares are redeemable
by NSPI, in whole at any time or in part from time to time at $25 per share
plus accrued and unpaid dividends. NSPI also has the option, commencing April
1, 2009, to exchange the Series C First Preferred Shares into Emera Inc.
common shares, determined by dividing $25 by the greater of $2 and the market
price of the Emera Inc. common share.
    Commencing on and after July 1, 2009 with prior notice and prior to any
dividend payment date, each Series C First Preferred Share will be
exchangeable at the option of the holder into fully paid and freely tradable
Emera Inc. common shares determined by dividing $25 by the greater of $2 and
the market price of the Emera Inc. common shares, subject to the right of NSPI
to redeem such shares for cash or to cause the holders of such shares to sell
on the exchange date all or any part of such shares. NSPI will pay all accrued
and unpaid dividends to the exchange date.

    Series D First Preferred Shares:

    Each Series D First Preferred Share is entitled to a $1.475 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 fifteenth day of January, April, July and October of each year.
    On and after October 15, 2015, Series D First Preferred Shares are
redeemable by NSPI, in whole at any time or in part from time to time at
$25 per share plus accrued and unpaid dividends. NSPI also has the option,
commencing October 15, 2015, to exchange the Series D First Preferred Shares
into Emera Inc. common shares determined by dividing $25 by the greater of
$2 and the market price of the Emera Inc. common shares.

    Commencing on and after January 15, 2016, with prior notice and prior to
any dividend payment date, each Series D First Preferred Share will be
exchangeable at the option of the holder into fully paid and freely tradable
Emera Inc. common shares determined by dividing $25 by the greater of $2 and
the market price of the Emera Inc. common shares, subject to the right of NSPI
to redeem such shares for cash or to cause the holders of such shares to sell
on the exchange date all or any part of such shares to substitute purchasers
found by NSPI. NSPI will pay all accrued and unpaid dividends to the exchange
date.
    Based on the terms and conditions of the preferred shares issued by NSPI,
the Company changed, as at December 31, 2007, its description of these shares
on the balance sheet from "non-controlling interest" to "preferred shares
issued by subsidiary". The related preferred share dividends were reclassified
as a charge to earnings before income taxes and reclassified as a use of funds
in operating activities with an offsetting reduction of funds used in
financing activities. This change had no impact on the measurement of
shareholders' equity, net earnings applicable to common shares, and basic and
diluted earnings per common share.

    11. EARNINGS PER SHARE

    Earnings per share for 2007 are as follows:

                                                                        2007
                                     ----------------------------------------
                                                         Weighted
                                                          average
                                                           common
                                          Net earnings     shares        EPS
                                           ($ millions) (millions)        ($)
    -------------------------------------------------------------------------
    Basic EPS                                   $151.3      111.2      $1.36
    Series C preferred shares of NSPI              5.8        6.0      (0.02)
    Series D preferred shares of NSPI              7.5        6.5      (0.01)
    Restricted share units and deferred
     share units                                     -        0.6      (0.01)
    Other share-based compensation                   -        0.3          -
    -------------------------------------------------------------------------
    Diluted EPS                                 $164.6      124.6      $1.32
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Earnings per share for 2006 are as follows:


                                                                        2006
                                    ----------------------------------------
                                                         Weighted
                                                          average
                                                           common
                                          Net earnings     shares        EPS
                                           ($ millions) (millions)        ($)
    -------------------------------------------------------------------------
    Basic EPS                                   $125.8      110.5      $1.14
    Series C preferred shares of NSPI              5.8        6.2      (0.01)
    Series D preferred shares of NSPI              7.5        6.7          -
    Restricted share units and deferred
     share units                                     -        0.5      (0.01)
    Other share-based compensation                   -        0.3          -
    -------------------------------------------------------------------------
    Diluted EPS                                 $139.1      124.2      $1.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Senior management share options were excluded from the above calculation
    because they did not dilute earnings per share where the exercise price
    exceeded the average price for the period.

    12. ACCOUNTS RECEIVABLE AND LONG-TERM RECEIVABLE

    In May 2004 NSPI renewed a revolving non-recourse securitization agreement
with an independent trust administered by a major Canadian bank. Under the
securitization agreement NSPI sells an undivided co-ownership interest in
certain current and future accounts receivable generated in the normal course
of business. The amount of the accounts receivables sold is removed from the
balance sheet with each revolving securitization. NSPI also retains an
undivided co-ownership of approximately 10% in the receivables sold to the
trust. The retained interest is recognized at amortized cost in deferred
charges. Fees related to securitization are expensed as incurred. At December
31, 2007 net accounts receivables sold amounted to $25 million
(2006 - $80 million).
    At December 31, 2007, the Company had unbilled revenue included in
accounts receivable in the amount of $86.0 million (2006 - $82.3 million). The
unbilled revenue is an estimate of the amount of revenue related to energy
delivered to customers since the date their meter was last read. Actual
results may differ from this estimate.
    NSPI's existing long-term natural gas purchase agreement includes a price
adjustment clause covering three years of natural gas purchases. The clause
states that NSPI will pay for all gas purchases at the agreed contract price,
but will be entitled to a price rebate on a portion of the volumes, settled in
November 2007 and November 2010. In November 2007 NSPI received the first
settlement of the pricing rebate. Management's best estimate of the price
rebate, based on the contract specifications using actual and forward market
pricing, of $7.7 million is reflected in long-term receivable. In 2006,
accounts receivable included $68.9 million related to the pricing rebate.

        13.  DEFERRED CHARGES AND CREDITS

        Deferred charges and credits, including the impact of rate-regulated
accounting policies, include the following:


    millions of dollars                                      2007       2006
    -------------------------------------------------------------------------
    Deferred charges:
    Regulatory assets:
    Unamortized defeasance costs                           $131.1     $143.8
    Pre-2003 income tax liability and related interest      119.9      147.1
    Costs to terminate/restructure purchased
     power contracts                                         17.9       23.2
    Deferral of income and capital taxes not
     included in Q1 2005 rates                               15.5       16.7
    Seabrook nuclear project                                 13.2       17.6
    Deferral of fuel switching derivatives                    9.0          -
    Maine Yankee decommissioning costs                        6.9       14.0
    Deferred restructuring costs                              4.8        7.4
    Hydro-Quebec obligation                                   4.0        4.5
    Stranded cost revenue requirement levelizers              3.0       10.1
    Held-for-trading natural gas contracts                    1.5          -
    Other                                                     6.6        8.0
    -------------------------------------------------------------------------
                                                            333.4      392.4
    -------------------------------------------------------------------------
    Non-regulatory assets:
    Accrued pension and non-pension benefit
     asset (note 4)                                          26.1       43.3
    Retained interest in accounts receivable
     securitized (note 12)                                    2.5        8.1
    Unamortized debt financing costs                            -       13.0
    Other                                                     5.2       11.4
    -------------------------------------------------------------------------
                                                             33.8       75.8
    -------------------------------------------------------------------------
                                                           $367.2     $468.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deferred credits:
    Regulatory liabilities:
    Held-for-trading natural gas contracts                  $75.3          -
    Deferral of fuel switching derivatives                   33.2          -
    Other                                                     0.2       $2.2
    -------------------------------------------------------------------------
                                                            108.7        2.2
    -------------------------------------------------------------------------
    Non-regulatory liabilities:
    Accrued pension and non-pension benefit
     liability (note 4)                                      24.2       30.9
    Maine Yankee decommissioning liability                    6.9       14.0
    Hydro-Quebec obligation                                   4.0        4.5
    Unearned revenue                                          2.8        3.1
    Other                                                    12.3       11.4
                                                             50.2       63.9
    -------------------------------------------------------------------------
                                                           $158.9      $66.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Regulatory assets consist of:

    Unamortized Defeasance Costs

    Upon privatization in 1992, NSPI became responsible for managing a
portfolio of defeasance securities held in trust, which as at December 31,
2007 totaled $1.0 billion. 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 as permitted by the UARB. In the
absence of UARB approval, the losses would have been expensed as incurred and
net earnings would be $12.7 million higher in 2007 (2006 - $12.7 million).

    Pre-2003 Income Tax Liability and Related Interest

    NSPI has a regulatory asset related to pre-2003 income taxes that have
been paid, but not yet recovered from customers. This circumstance arose when
NSPI claimed capital cost allowance ("CCA") deductions in its income tax
returns that were ultimately disallowed by a decision of the Supreme Court of
Canada. NSPI applied to the regulator to include recovery of these costs in
customer rates. In its February 5, 2007 decision, the UARB approved recovery
of this regulatory asset over eight years, commencing April 1, 2007. In 2007
NSPI has recorded an income tax recovery of $14.6 million relating to
accelerated deductibility of certain capitalized expenses and associated
interest of $1.8 million relating to its pre-2003 income tax liability, which
reduced this regulatory asset. In the absence of UARB approved recovery, the
liability would have been expensed when incurred and the interest reflected in
earnings when receivable, therefore net earnings would be $12.6 million higher
in 2007 (2006 - nil).

    Costs to Terminate/Restructure Purchased Power Contracts

    Bangor Hydro has power purchase contracts, which it was required to
negotiate when oil prices were high, with several independent power producers
known as small power production facilities. The cost of power from these
facilities is more than Bangor Hydro would incur from other sources if it were
not obligated under these contracts. Bangor Hydro attempted to alleviate the
adverse impact of these high-cost contracts and in doing so incurred costs to
terminate or restructure certain of the contracts. The MPUC has allowed Bangor
Hydro to defer these costs and recover them in stranded cost rates. The
contract termination was recovered over an 11-year period, which ended in
February 2006, while the contract restructuring is being recovered over a     
 20-year period ending in June 2018. The annual amortization is approximately
$1.8 million, beginning in 2007. In the absence of the MPUC's approval, these
costs would have been expensed as incurred and earnings would have been
$1.8 million ($1.1 million after-tax) higher in 2007 (2006 - $4.6 million or
$2.7 million after-tax).

    Deferral of Income and Capital Taxes Not Included in Q1 2005 Rates

    The UARB agreed to allow NSPI to defer taxes not reflected in rates for
the period January 1, 2005 until April 1, 2005, the date when new rates became
effective. In 2005, NSPI deferred $16.7 million consisting of $4.5 million of
provincial and federal grants and $12.2 million in income taxes reflecting
increases in these taxes since rates were last set in 2002. In its February 5,
2007 decision, the UARB approved recovery of this regulatory asset over eight
years, commencing April 1, 2007. In the absence of the UARB's approval, these
taxes would not have been deferred and net earnings for 2007 would be
$1.2 million (2006 - nil) higher.

    Seabrook Nuclear Project

    Bangor Hydro was a participant in the Seabrook nuclear project in
Seabrook, New Hampshire. On December 31, 1984, Bangor Hydro had almost
$87 million invested in Seabrook, but because the uncertainties arising out of
the Seabrook Project were having an adverse impact on Bangor Hydro's financial
condition, an agreement for the sale of Seabrook was reached in mid-1985 and
was consummated in November 1986. In 1985, the MPUC issued an order
disallowing recovery of certain Seabrook costs, but provided for the recovery
through customer rates of 70% of Bangor Hydro's year-end 1984 investment in
Seabrook Unit 1 over 30 years ending in October 2015. In the absence of MPUC
approval, the loss on sale would have been recognized when incurred and
earnings for 2007 would be $1.8 million ($1.1 million after-tax) higher
(2006 - $1.9 million or $1.1 million after-tax).

    Deferral of Fuel Switching Derivatives

    In accordance with Handbook Section 3865 Hedges, NSPI determined that it
could not meet the probability requirement of the standard for its derivatives
in place to hedge natural gas and heavy fuel oil for its Tufts Cove generating
station. This is due to the generating station's ability to fuel switch and
NSPI's economic dispatch based on the cost of these two fuels. The UARB has
allowed NSPI to apply hedge accounting to these derivatives as long as the
other requirements of the handbook are met. This accounting policy permits
NSPI to defer the fair value of hedges that are no longer required because of
fuel switching. Absent UARB approval, NSPI would be required to recognize the
changes in fair value of these derivatives in earnings and net earnings for
2007 would be $9.0 million ($5.6 million after-tax) lower (2006 - nil).


    Maine Yankee Decommissioning Costs

    Bangor Hydro owns 7% of the common stock of Maine Yankee, which in 1997
permanently shutdown its nuclear generating plant. Pursuant to a contract with
Maine Yankee, BHE is required to pay its pro-rata share of Maine Yankee's
decommissioning costs. BHE's share of the estimated decommissioning costs were
approximately $4.4 million in 2007 (2006 - $4.7 million). Maine Yankee expense
recovery is included in BHE's stranded cost revenues, and along with all
stranded cost revenues, purchased power, and Hydro-Quebec costs, are fully
recoverable starting March 1, 2005. For any variance between the actual amount
of these items and the amounts used in setting rates, a regulatory deferral is
recorded with a credit or charge to regulatory amortizations. Any over or
under-recovery will be reviewed at future rate proceedings with the MPUC. In
the absence of regulator approval, the Maine Yankee decommissioning costs
would have been expensed when incurred and earnings would have been
$4.4 million ($2.6 million after-tax) higher in 2007 (2006 - $4.7 million or
$2.8 million after-tax).

    Deferred Restructuring Costs

    In conjunction with Bangor Hydro's Alternative Rate Plan, BHE has been
provided with accounting orders from the MPUC to defer and amortize over ten
years certain employee transition costs. Eligible for deferral are the 2002
and 2003 employee transition costs related to reductions in the cost of
operations and employee transition costs associated with Bangor Hydro's
automated meter reading project and the outsourcing of information technology
support in 2004 and 2005. In the absence of regulator approval, these costs
would have been expensed as incurred and 2007 earnings would be $1.2 million
($0.7 million after-tax) higher (2006 - $1.3 million or $0.8 million
after-tax).

    Hydro-Quebec Obligation

    The obligation associated with Hydro-Quebec represents the estimated
present value of Bangor Hydro's estimated future payments for net costs
associated with ownership and operation of the Hydro-Quebec intertie between
the New England utilities and Hydro-Quebec. The obligation has been recognized
as a long-term deferred credit, and the MPUC has permitted recovery of this
obligation. The regulatory asset and obligation are being reduced as expenses
are incurred with the reduction of the regulatory asset amortized to purchase
power expense. In the absence of regulator approval, 2007 earnings would be
$0.4 million ($0.2 million after-tax) higher (2006 - $0.5 million or
$0.3 million after-tax).

    Stranded Cost Revenue Requirement Levelizer

    Bangor Hydro's current stranded cost rates are designed to recover their
cumulative stranded cost revenue requirements over a three-year period from
March 2005 to February 2008. While the stranded cost revenue requirements
differ throughout the period due to changes in purchased power expenses and
varying amortization periods for regulatory assets and liabilities, the annual
stranded cost revenues are the same during the period. To levelize the impact
of the varying revenue requirements, cost or revenue deferrals are recognized.
For the period March 2005 to February 2006 BHE deferred $15.0 million of costs
and will amortize the deferral almost evenly over the periods March 2006 to
February 2007, and March 2007 to February 2008. This levelizer is recognized
only as result of regulatory accounting and the stranded cost ratemaking
process. Absent regulatory accounting, the levelizer mechanism would not
exist, and the methodology for determining BHE's rates associated with
stranded costs is not known. In the absence of regulatory approval, earnings
for 2007 would be $6.3 million ($3.7 million after-tax) higher (2006 -
$3.9 million or $2.3 million after-tax).

    Held-for-trading Natural Gas Contracts

    In accordance with implementing 3855 Financial Instruments - Recognition
and Measurement, Nova Scotia Power has contracts for the purchase and sale of
natural gas at its Tufts Cove generating station that are considered HFT
derivatives and accordingly are recognized on the balance sheet at fair value.
This reflects NSPI's history of buying and reselling any natural gas not used
in the production of electricity at TUC. Changes in fair value of HFT
derivatives are normally recognized in net earnings. In accordance with NSPI's
regulated accounting policy for financial instruments and hedges relating to
TUC fuel, NSPI has deferred any changes in fair value to a regulatory asset or
liability. The fair value of the natural gas contracts which resulted in a
regulatory asset at inception of the new accounting standard was $1.4 million.
As at December 31, 2007, the fair value of these contracts was a regulatory
asset of $1.5 million. Absent this accounting policy, NSPI's 2007 net earnings
would be $0.1 million ($0.1 million after-tax) lower (2006 - nil).

    Other

    Bangor Hydro has other regulatory assets, which are being amortized to net
earnings over varying lives. These deferred costs would have been expensed as
incurred in the absence of approval from one of its regulators, and earnings
would have been $3.5 million ($2.0 million after-tax) higher in 2007 (2006 -
$2.7 million or $1.6 million after-tax).

    Regulatory liabilities include:

    Held-for-trading Natural Gas Contracts

    As discussed above, in accordance with NSPI's accounting policy for
financial instruments and hedges relating to TUC fuel, NSPI has deferred any
changes in fair value of its natural gas contracts to a regulatory asset or
liability. The fair value of the natural gas contracts which resulted in a
regulatory liability at inception of the new accounting standard was
$173.3 million. As at December 31, 2007, the fair value of these contracts was
a regulatory liability of $75.3 million. Absent this accounting policy, NSPI's
2007 net earnings would be $98.0 million ($60.6 million after-tax) lower (2006
- nil).

    Deferral of Fuel Switching Derivatives

    As discussed above, NSPI has an accounting policy that permits NSPI to
defer the fair value of any hedges that are no longer required because of fuel
switching. Absent UARB approval, NSPI would be required to recognize the
changes in fair value of these derivatives in earnings and net earnings for
2007 would be $33.2 million ($20.5 million after-tax) higher (2006 - nil).

    Other

    Bangor Hydro has other regulatory liabilities, which are being amortized
to net earnings over varying lives. These deferred gains would have been
expensed as incurred in the absence of approval from one of its regulators,
and earnings would have been $1.3 million ($0.7 million after-tax) lower in
2007 (2006 - $1.2 million or $0.7 million after-tax).

    14. PROPERTY, PLANT AND EQUIPMENT

    Property, plant and equipment
     is comprised of the following:
                                                                        2007
                                      ---------------------------------------

                                                                         Net
                                                      Accumulated       Book
    millions of dollars                      Cost    Depreciation      Value
    -------------------------------------------------------------------------
    Generation
      Thermal                            $1,768.9          $712.7   $1,056.2
      Gas Turbines                           32.5            22.4       10.1
      Combustion Turbines                    76.3            14.9       61.4
      Hydroelectric                         431.3           135.0      296.3
      Wind Turbines                           2.1             0.5        1.6
    Transmission                            809.1           326.0      483.1
    Distribution                          1,325.5           639.2      686.3
    Other                                   384.7           161.8      222.9
    Other, under capital lease                2.5             0.4        2.1
    -------------------------------------------------------------------------
                                         $4,832.9        $2,012.9   $2,820.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                                        2006
                                      ---------------------------------------

                                                                         Net
                                                      Accumulated       Book
    millions of dollars                      Cost    Depreciation      Value
    -------------------------------------------------------------------------
    Generation
      Thermal                            $1,744.0          $676.7   $1,067.3
      Gas Turbines                           32.1            21.8       10.3
      Combustion Turbines                    76.7            13.2       63.5
      Hydroelectric                         434.6           129.5      305.1
      Wind Turbines                           2.1             0.4        1.7
    Transmission                            683.5           315.6      367.9
    Distribution                          1,324.1           611.7      712.4
    Other                                   382.0           157.1      224.9
    Other, under capital lease                3.8             0.5        3.3
    -------------------------------------------------------------------------
                                         $4,682.9        $1,926.5   $2,756.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accounting for the impact of rate regulation:

    At December 31, 2007, the Glace Bay generating station had a net book
value of nil (2006 - $5.1 million). During the year NSPI completed the
amortization by expensing $5.2 million (2006 - $8.6 million) related to the
plant, and capitalized $0.1 million in AFUDC (2006 - $0.8 million) to the
plant value. In the absence of the UARB's approved accounting policies, the
generation station would have been written off in the year when NSPI
determined that the unamortized cost of the generating station would not be
recoverable.

    15. ACQUISITION

    On January 16, 2007 Emera acquired a 19% interest in St. Lucia Electricity
Services Limited ("Lucelec") for a purchase price of $25.7 million. Lucelec is
a vertically integrated electric utility with an exclusive license to
generate, transmit and distribute electricity on the island of St. Lucia to
2045. The utility has 77 MW of generating capacity and 800 kilometers of
electricity transmission and distribution assets. Lucelec is a cost of service
utility, with a minimum rate of return of 10% on a 50% equity basis.
    The acquisition has been accounted for as an equity investment, and
accordingly, the investment was initially recorded at cost. Emera's pro-rata
share of the results since acquisition have been included in the investment
and consolidated statements of earnings. Any dividends received or receivable
reduces the investment. Lucelec is included in the segment "Other" in
note 3 Segment Information.

    16. INTEREST IN JOINT VENTURES

    The following amounts represent the Company's proportionate interest in
its joint ventures' financial position, operating results, and cash flows
included in the consolidated financial statements:

    millions of dollars                           2007                  2006
    -------------------------------------------------------------------------
    Current assets                                $7.8                  $8.1
    Non-current assets                            61.6                  58.7
    -------------------------------------------------------------------------
                                                 $69.4                 $66.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Current liabilities                           $7.9                  $6.1
    Non-current liabilities                       67.7                   1.2
    -------------------------------------------------------------------------
                                                 $75.6                  $7.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Revenues                                     $55.4                 $31.6
    Expenses                                     (42.2)                (28.4)
    -------------------------------------------------------------------------
    Net earnings                                 $13.2                  $3.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash provided by (used in) operations         $8.8                 $(1.2)
    Cash used in investing activities             (2.0)                 (0.7)
    Cash (used in) provided by financing
     activities                                   (4.7)                  0.1
    -------------------------------------------------------------------------
    Increase (decrease) in cash                   $2.1                 $(1.8)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    17. GOODWILL

    The change in goodwill is due to the following:

    millions of dollars                           2007                  2006
    -------------------------------------------------------------------------
    Balance, beginning of year                   $97.1                 $97.1
    Change in foreign exchange rate              (14.3)                    -
    -------------------------------------------------------------------------
    Balance, end of year                         $82.8                 $97.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    18. ASSET RETIREMENT OBLIGATIONS

    Asset retirement obligations are recognized when incurred and represent
the fair value, using the Company's credit-adjusted risk-free rate, of the
Company's estimated future cash flows necessary to discharge legal obligations
related to reclamation of land at the Company's thermal, hydro and combustion
turbine sites, and disposal of polychlorinated biphenyls ("PCBs") in its
transmission and distribution equipment. Estimated future cash flows are based
on the Company's completed depreciation studies, prior experience, estimated
useful lives, and governmental regulatory requirements. Actual results may
differ from these estimates.

    The change in asset retirement obligations is due to the following:

    millions of dollars                           2007                  2006
    -------------------------------------------------------------------------
    Balance, beginning of year                   $78.1                 $74.1
    Accretion included in depreciation expense     2.0                   2.0
    Accretion deferred to regulatory asset         2.0                   2.1
    Liabilities settled                           (0.2)                 (0.1)
    Other                                          1.9                     -
    -------------------------------------------------------------------------
    Balance, end of year                         $83.8                 $78.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    The key assumptions used to determine the asset retirement obligations are
as follows:
    -------------------------------------------------------------------------
                                                  Estimated
                                                undiscounted        Expected
                    Credit-adjusted        future obligation      settlement
    Asset            risk-free rate     (millions of dollars)           date
    -------------------------------------------------------------------------
    Thermal                     5.3%                  $242.3   13 - 32 years
    Hydro                       5.3%                    60.8   24 - 54 years
    Combustion Turbines         5.3%                     5.1    1 - 16 years
    Transmission &
     Distribution               5.8%                     5.8    1 - 18 years
    Other                7.4% - 8.6%                     0.4     3 - 8 years
    -------------------------------------------------------------------------
                                                      $314.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Some of the Company's hydro, transmission and distribution assets may have
additional 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.

    Accounting for the impact of rate regulation:

    Any difference between the amount approved by the regulator of Nova Scotia
Power as depreciation expense and the amount that would have been calculated
under the accounting standard for asset retirement obligations is recognized
as a regulatory asset in property, plant and equipment. In the absence of this
deferral, net earnings for 2007 would be $2.0 million lower (2006 - $2.1
million).

    19. SHORT-TERM DEBT

    For the year ended December 31, 2007, short-term debt consists of:
    - Commercial Paper of $22.9 million. Commercial Paper bears interest at
      prevailing market rates, which on December 31, 2007, averaged 4.69%.
    - LIBOR loans of $75.7 million issued against lines of credit. LIBOR
      loans bear interest at prevailing market rates, which on December 31,
      2007, averaged 5.62%.
    - Advances of $6.0 million against operating lines of credit, which when
      drawn upon, bear interest at the prime rate, which on December 31,
      2007, was 6.00% in Canada and 7.25% in the US.

    For the year ended December 31, 2006, short-term debt consists of:
    - LIBOR loans of $122.1 million issued against lines of credit. LIBOR
      loans bear interest at prevailing market rates, which on December 31,
      2006, averaged 5.94%.
    - Advances of $11.1 million against the operating line of credit, which
      when drawn upon, bears interest at the prime rate, which on
      December 31, 2006, was 6.00%.

    This short-term debt is unsecured.

    20. LONG-TERM DEBT

    Long-term debt includes the issues detailed below. Medium term notes and
debentures are issued under trust indentures at fixed interest rates, and are
unsecured unless noted below. Also included are certain bankers acceptances
and commercial paper where the Company has the intention and the unencumbered
ability to refinance the obligations for a period greater than one year.


                        Effective Average                          Amount
                         Interest Rate %            Years       Outstanding
    millions of dollars     2007    2006      of Maturity     2007      2006
    -------------------------------------------------------------------------
    Emera
    Bankers Acceptances
     and Advances           5.11    5.23   1 year renewal    $61.9    $111.0
    Capital lease
     obligations            5.15       -          Various      1.5         -
    NSPI
    Medium Term Notes       6.64    6.64      2008 - 2097  1,250.0   1,250.0
    Debentures              9.75    9.75             2019     95.0      95.0

    Commercial paper        4.69    4.29   1 year renewal     94.0      57.0
    Capital lease
     obligations               -    4.44                -        -       3.8
    Bangor Hydro
     (issued and payable
     in USD)
    General & Refunding
     Mortgage Bonds -
     secured by property,
     plant and equipment    9.74    9.74      2020 - 2022     49.4     58.3
    Municipal Review
     Committee              5.00    5.00             2008      0.9      4.1
    Senior unsecured
     note                   5.84    6.09      2012 - 2017     69.2     23.3
    Senior unsecured
     notes                  5.31    5.31      2008 - 2018     49.4     58.3
    Bear Swamp (issued
     and payable in USD)
    Senior non-revolving
     credit facility
     secured by the
     assets of Bear
     Swamp                  5.63       -             2012     61.7        -
    -------------------------------------------------------------------------
                                                           1,733.0  1,660.8
    Amount due within
     one year                                               (121.0)    (3.4)
    Unamortized debt
     financing costs
     (note 2)                                                (11.8)       -
    -------------------------------------------------------------------------
                                                          $1,600.2  $1,657.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    An NSPI medium term note ("MTN") of $40.0 million bearing interest at
8.50%, maturing in 2026, is extendable until 2056 at the option of the
holders.

    As at December 31, 2007 long-term debt and obligations under a capital
lease are due as follows:

    millions of dollars
    -------------------------------------------------------------------------
    Year of Maturity
    -------------------------------------------------------------------------
    One year renewable                                                $155.9
    2008                                                               121.0
    2009                                                               130.0
    2010                                                               104.8
    2011                                                                 4.6
    2012                                                                85.9
    Greater than 5 years                                             1,130.8
    -------------------------------------------------------------------------
                                                                    $1,733.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    21.  COMMON SHARES

    Authorized:  Unlimited number of non-par value common shares.

                                                                 Millions of
    Issued and outstanding:                                           Shares
    -------------------------------------------------------------------------
    January 1, 2006                                                   110.10
    Issued for cash under purchase plans                                0.45
    Options exercised under senior management share option plan         0.38
    -------------------------------------------------------------------------
    December 31, 2006                                                 110.93
    Issued for cash under purchase plans                                0.45
    Options exercised under senior management share option plan         0.09
    -------------------------------------------------------------------------
    December 31, 2007                                                 111.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, there were 4.8 million (2006 - 4.9 million)
common shares reserved for issuance under the senior management common share
option plan, and 1.0 million (2006 - 1.2 million) common shares reserved for
issuance under the employee common share purchase plan.

    DIVIDEND REINVESTMENT AND EMPLOYEE COMMON SHARE PURCHASE PLANS

    The Company has a Common Shareholder Dividend Reinvestment Plan, which
provides an opportunity for shareholders to reinvest dividends and to make
cash contributions for the purpose of purchasing common shares. The Company
also has an Employee Common Share Purchase Plan to which the Company and
employees make cash contributions for the purpose of purchasing common shares
and which allows reinvestment of dividends.

    SHARE-BASED COMPENSATION PLAN

    Common Share Option Plan

    The Company has a common share option plan that grants options to senior
management of the Company for a maximum term of ten years. The option price
for these shares is the closing market price of the shares on the day before
the option is granted.
    All options granted to date are exercisable on a graduated basis with up
to 25 percent of options exercisable on the first anniversary date and in
further 25 percent increments on each of the second, third and fourth
anniversaries of the grant. If an option is not exercised within ten years, it
expires and the optionee loses all rights thereunder. The holder of the option
has no rights as a shareholder until the option is exercised and shares have
been issued. The maximum number of such shares optioned to anyone cannot
exceed one percent of the issued and outstanding common shares on the date the
option is granted.
    If, before the expiry of an option in accordance with its terms, the
optionee ceases to be an eligible person due to retirement or a change of
responsibility at the Company's request, such option may, subject to the terms
thereof and any other terms of the plan, be exercised at anytime within the
24 months following the date the optionee retires, but in any case prior to
the expiry of the option in accordance with its terms.
    If, before the expiry of an option in accordance with its terms, the
optionee ceases to be an eligible person due to employment termination for
just cause, resignation or death, such option may, subject to the terms
thereof and any other terms of the plan, be exercised at anytime within the
six months following the date the optionee is terminated, resigns, or dies, as
applicable, but in any case prior to the expiry of the option in accordance
with its terms.

                                                  2007                  2006
                                     ----------------------------------------
                                              Weighted              Weighted
                                     Shares    average     Shares    average
                                      under   exercise      under   exercise
                                     option      price     Option      price
    -------------------------------------------------------------------------
    Outstanding, beginning
     of year                      1,892,425     $18.54  1,696,475     $17.81
    Granted                         542,600     $20.43    578,700     $19.88
    Exercised                       (91,575)    $18.18   (382,750)    $19.20
    -------------------------------------------------------------------------
    Outstanding, end of year      2,343,450     $18.98  1,892,425     $18.54
    Exercisable, end of year      1,058,150     $17.86    743,225     $17.45
    -------------------------------------------------------------------------


    The weighted average contractual life of options outstanding at December
31, 2007 is 7.3 years (2006 - 7.4 years). The range of exercise prices for the
options outstanding at December 31, 2007 is $13.70 to $20.52 (2006 - $13.70 to
$19.88).

    The fair value of each option is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for the grants:

                                                             2007       2006
    Expected dividend yield                                  5.04%      5.12%
    Expected volatility                                     14.00%     14.04%
    Risk-free interest rate                                  4.24%      4.27%
    Expected life                                         7 years    7 years

    Deferred Share Unit Plan and Restricted Share Unit Plan

    The Company has deferred share unit ("DSU") and restricted share unit
("RSU") plans.
    Under the Directors' DSU 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 a common share at the time of
redemption, pursuant to the plan.
    Under the executive and senior management DSU plan, each participant may
elect to defer all or a percentage of their annual incentive award in the form
of DSUs with the proviso that for participants who 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 a value equal to the market price of a Company 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 Committee ("MRCC") 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.
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 the Company's common share market price and corporate
performance.
    RSUs vest at the end of the three-year cycle and will be calculated and
approved by the MRCC 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.

                                       -------------------------------------
                                              Employee   Employee   Director
                                                  DSUs       RSUs       DSUs
                                                   Out-       Out-       Out-
                                              standing   standing   standing
    -------------------------------------------------------------------------
    Balance at January 1, 2006                 130,286    361,249     39,436
    Granted                                     22,511     95,268     23,347
    Retirement, termination, disability
     & death                                      (311)   (21,739)         -
    Payout                                           -   (139,693)         -
    -------------------------------------------------------------------------
    December 31, 2006                          152,486    295,085     62,783
    Granted                                     96,371     90,548     23,886
    Retirement, termination, disability
     & death                                    (6,729)    (3,360)   (11,019)
    Payout                                           -   (115,055)         -
    -------------------------------------------------------------------------
    December 31, 2007                          242,128    267,218     75,650
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Company is using the fair value based method to measure the
compensation expense related to its share-based compensation and employee
purchase plan 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, 2007, $4.0 million (2006 - $2.7 million) of
compensation expense related to options granted, units issued, and shares
purchased by employees was recognized in operating, maintenance and general
expense.

    22. 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 financial instruments consisting mainly of foreign
exchange forward contracts, interest caps and collars, and oil and gas options
and swaps.
    Derivative financial instruments involve credit and market risks. Credit
risks arise 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:
                                                  2007                  2006
    -------------------------------------------------------------------------
                                   Carrying       Fair   Carrying       Fair
    millions of dollars              Amount      Value     Amount      Value
    -------------------------------------------------------------------------
    Cash and cash equivalents         $26.4      $26.4      $19.5      $19.5
    Restricted cash                     1.0        1.0          -          -
    Accounts receivable               274.2      274.2      253.6      253.6
    Long-term receivable                7.7        7.7          -          -
    Derivatives held in a valid
     hedging relationship (current
     and long-term portion)            22.9       22.9          -       31.8
    Held-for-trading derivatives
     (current and long-term
     portion)                         143.6      143.6       28.5       28.5
    -------------------------------------------------------------------------
    Total financial assets           $475.8     $475.8     $301.6     $333.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accounts payable and accrued
     charges                         $282.7     $282.7     $286.0     $286.0
    Short-term debt                   104.6      109.0      133.2      129.2
    Long-term debt                  1,721.2    1,949.9    1,660.8    1,925.5
    Preferred shares issued by a
     subsidiary                       260.0      275.7      260.0      292.7
    Derivatives held in a valid
     hedging relationship
     (current and long-term
     portion)                          76.9       76.9          -       37.2
    Held-for-trading derivatives
     (current and long-term
     portion)                          32.9       32.9       27.3       27.3
    -------------------------------------------------------------------------
    Total financial liabilities    $2,478.3   $2,727.1   $2,367.3   $2,697.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    ACCOUNTS RECEIVABLE, LONG-TERM RECEIVABLE AND ACCOUNTS PAYABLE AND
    ACCRUED CHARGES

    The Company's accounts receivable, long-term receivable and accounts
payable and accrued charges are recognized at amortized cost. The carrying
value of accounts receivable, long-term receivable and accounts payable and
accrued charges is a reasonable approximation of fair value. Losses included
in earnings and recorded in operating, maintenance and general expenses are
$6.9 million (2006 - $3.1 million).
    The allowance for doubtful accounts was $2.6 million as at January 1, 2007
(2006 - $4.4 million) and $4.8 million as at December 31, 2007 (2006 - $2.6
million). Changes in the allowance were due to changes in mix and volume of
accounts receivable and changes in the provision related to specific
customers.

    PREFERRED SHARES ISSUED BY A SUBSIDIARY, LONG-TERM DEBT AND SHORT-TERM
    DEBT

    The Company's preferred shares issued by a subsidiary, long-term debt and
short-term debt are measured at amortized cost. Preferred share dividends paid
by subsidiary are recognized using the effective interest method and are
disclosed on the income statement. Interest expense and debt financing
expenses related to the Company's long-term debt and short-term debt are
recognized using the effective interest method and are included in note 7.
    The fair value of preferred shares issued by a subsidiary is based on
market rates.
    The fair value of the Company'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 the Company, for debt of the same remaining
maturities.

    DERIVATIVES IN VALID HEDGING RELATIONSHIPS

    The fair value of derivative financial instruments is estimated by
obtaining prevailing market rates from investment dealers.
    Gains and losses included in net earnings with respect to derivatives in
valid hedging relationships includes the following:
                                                                  Year ended
    millions of dollars                                          December 31
    -------------------------------------------------------------------------
                                                             2007       2006
    -------------------------------------------------------------------------
    Fuel and purchased power (increase) decrease           $(14.7)     $47.1
    -------------------------------------------------------------------------
    Total (losses) gains                                   $(14.7)     $47.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Interest Rates

    The Company makes use of various financial instruments to hedge against
interest rate risk. Additionally, the Company uses diversification as a risk
management 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 concentration risk.
    The Company enters into interest rate hedging contracts to limit exposure
to fluctuations in floating and fixed interest rates on its short-term and
long-term debt.
    Interest rate cap contracts limiting floating rate interest on
$185.0 million short-term debt over 2008 to a fixed interest rate of 4.80%
were outstanding at December 31, 2007.

    Commodity Prices

    A substantial amount of NSPI's fuel supply comes from international
suppliers and is subject to commodity price risk. As part of its fuel
management strategy, NSPI manages exposure to commodity price risk utilizing
financial instruments providing fixed or maximum prices.
    The Company enters into natural gas swap contracts to limit exposure to
fluctuations in natural gas prices. As at December 31, 2007, the Company had
hedged approximately 100% of all natural gas purchases and sales associated
with its forecasted natural gas burn and resale for 2008, 75% for 2009, and
55% for 2010.
    The Company enters into oil swap contracts to limit exposure to
fluctuations in world prices of heavy fuel oil. As at December 31, 2007, the
Company has hedged approximately 70% of 2009 requirements.
    The Company enters into power swaps to limit exposure to fluctuations in
power prices. At December 31, 2007, the Company has hedged 100% of 2008
requirements and approximately 40% of 2009 requirements.

    Foreign Exchange

    A substantial amount of NSPI's fuel supply comes from international
suppliers and is subject to foreign exchange risk. As part of its fuel
management strategy, NSPI manages exposure to foreign exchange through forward
and option contracts.
    Emera 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 US dollars, reducing exposure to
currency rate fluctuations. Forward contracts to buy USD $380 million are in
place at a weighted average rate of $1.0852 representing over 90% of 2008
anticipated USD requirements. Forward contracts to buy USD $427.3 million over
2009 to 2011 at a weighted average rate of $1.0656 were outstanding at
December 31, 2007 to manage exposure in a range of 25% to 50% of anticipated
USD requirements in these years.
    Option contracts, to eliminate exposure to currency rate fluctuations, of
$5.5 million at a rate of $1.0605 were outstanding on December 31, 2007.
    The Company expects to reclassify $23.5 million of losses currently
included in AOCI to net earnings over the next 12 months.

    HELD-FOR-TRADING DERIVATIVES

    Derivatives included in held-for-trading assets and liabilities are
required to be included in this classification in accordance with Canadian
GAAP. The Company has not designated any financial instruments to be included
in the held-for-trading category.
    The fair value of derivatives is estimated by obtaining prevailing market
rates from investment dealers.
    Gains and losses included in net earnings with respect to held-for-trading
derivatives includes the following:

                                                                  Year ended
    millions of dollars                                          December 31
    -------------------------------------------------------------------------
                                                             2007       2006
    -------------------------------------------------------------------------
    Electric revenue                                         $0.8      $(3.2)
    Other revenue                                            31.0       17.8
    Fuel and purchased power                                 (0.8)         -
    Interest                                                  0.1          -
    -------------------------------------------------------------------------
    Total gains                                             $31.1      $14.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Energy marketing assets and liabilities

    On December 31, 2007, the Company held derivative financial and commodity
instruments within its trading group.

    Natural gas contracts

    Nova Scotia Power has contracts for the purchase and sale of natural gas
at its Tufts Cove generating station that are considered HFT derivatives and
accordingly are recognized on the balance sheet at fair value. This reflects
NSPI's history of buying and reselling any natural gas not used in the
production of electricity at TUC.

    Derivatives not in valid hedging relationships

    On December 31, 2007, the Company held natural gas, power and oil
derivatives, which were not in valid hedging relationships. This includes a
certain swap in place to economically hedge a portion of the long-term power
supply agreement with the Long Island Power Authority, which is
marked-to-market through earnings as it does not meet the stringent accounting
requirements of hedge accounting.

    RISK MANAGEMENT

    Market Risk

    The Company uses value-at-risk limits to manage its exposure to energy
commodities from commercial activities on behalf of third parties such as the
purchase and sale of natural gas and electricity, and related energy
management services. These commercial activities are monitored on a daily
basis by the Company's risk management group such that the value-at-risk is
not material.

    Credit risk

    The Company is exposed to credit risk with respect to amounts receivable
from customers. Credit assessments are conducted on all new customers and
deposits are requested on any high risk accounts. The Company also maintains
provisions for potential credit losses, which are assessed on a regular basis.
With respect to customers other than electric customers, counterparty
creditworthiness is assessed through reports of credit rating agencies or
other available financial information.

    Liquidity risk

    Liquidity risk encompasses the risk that the Company cannot meet its
financial obligations.
    Emera's main sources of liquidity are its cash flows from operations,
short-term and long-term debt, and the securitization of accounts receivable.
Funds are primarily used to finance capital transactions. Some of these
instruments are subject to market risks that the Company typically hedges with
interest rate swaps, caps, floors, futures and options.
    Emera manages its liquidity by holding adequate volumes of liquid assets
and maintaining credit facilities in addition to the cash flow generated by
its operating businesses. The liquid assets consist of cash and cash
equivalents.
    The Company's financial instrument liabilities mature as follows:

                                                              (greater than)
                             2008      2009       2010       2011       2011
    -------------------------------------------------------------------------
    Accounts payable and
     accrued charges      $282.7          -          -          -          -
    Short-term debt        104.6          -          -          -          -
    Long-term debt         276.9     $130.0     $104.8       $4.6   $1,216.7
    Preferred shares
     issued by
     subsidiary                -      125.0          -          -      135.0
    Derivatives held in
     a valid hedging
     relationship           43.8       20.2       12.9          -          -
    Held-for-trading
    derivatives             25.3        3.2        0.3        0.3        3.8
    -------------------------------------------------------------------------
    Total financial
     liabilities          $733.3     $278.4     $118.0       $4.9   $1,355.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    23. RELATED PARTY TRANSACTIONS

    In the ordinary course of business, Emera purchased natural gas
transportation capacity totaling $25.4 million (2006 - $29.3 million) during
the year ended December 31, 2007, from the Maritimes & Northeast Pipeline, an
investment under significant influence of the Company. The amount is
recognized in fuel for generation and purchased power or netted against energy
marketing margin in other revenue, and is measured at the exchange amount. At
December 31, 2007 the amount payable to the related party is $4.5 million
(2006 - $3.4 million), is non-interest bearing and is under normal credit
terms.

    24. CONTINGENCIES

    A number of individuals who live in proximity to the Company's Trenton
generating station have filed a statement of claim against Nova Scotia Power
in respect of emissions from the operation of the plant for the period 2001
forward. The plaintiffs have proposed to amend the statement of claim to
reference emissions from the operation of the plant commencing in the early
1970's. The Company is currently considering its response to this proposed
amendment. The plaintiffs claim unspecified damages as a result of
interference with enjoyment of, or damage to, their property and adverse
health effects they allege were caused by such emissions. The outcome, and
therefore an estimate of any contingent loss, of this litigation are not
determinable.
    Bangor Hydro Electric has a potential liability to Great Lake Hydro
America LLC for headwater benefits on the Penobscot River in connection with
hydro assets sold to PPL Generation, LLC in 1999. The matter is currently
before the Federal Energy Regulatory Commission for determination. The
outcome, and therefore an estimate of any contingent loss, of this litigation
are not determinable.
    One of NSPI's fuel suppliers has provided notice that it is suspending
2008 shipments pending a review of the contract. NSPI is working to address
the effects of any potential supply disruption and at this time is unable to
estimate the potential effect on 2008 results. The outcome, and therefore an
estimate of the potential affect, are not determinable.
    In addition, the Company may, from time to time, be involved in legal
proceedings, claims and litigations that arise in the ordinary course of
business which the Company believes would not reasonably be expected to have a
material adverse effect on the financial condition of the Company.

    25. COMMITMENTS

    In addition to commitments outlined elsewhere in these notes, Emera had
the following significant commitments at December 31, 2007:

    - The Company has a commitment to purchase pipe and related equipment for
      the construction of Brunswick Pipeline in 2008 for approximately
      $64 million.
    - The Company has a commitment to contribute their portion of the
      Maritimes & Northeast Pipeline's, a related party, Phase IV capital
      expansion costs of approximately $21 million in 2008 and 2009.
    - The Company has a commitment to purchase approximately 43,000 mmbtu per
      day of transportation capacity on the US portion of the Maritimes &
      Northeast Pipeline, a related party, for the next five years, at an
      approximate average cost of $10 million per year.
    - NSPI has an annual requirement to purchase approximately 360 GWh of
      electricity from independent power producers over varying contract
      lengths ranging from six to eighteen years.
    - NSPI is required to purchase approximately 61,600 mmbtu of natural gas
      per day for the next three years (subject to offshore gas production),
      and an additional 4,000 mmbtu per day, at the option of the supplier,
      for four years.
    - NSPI has a commitment to purchase approximately 61,000 mmbtu per day of
      transportation capacity on the Maritimes and Northeast Pipeline, a
      related party, for the next three years, and an additional 4,000 mmbtu
      per day, at the option of the supplier for four years. The commitment
      includes renewal rights at NSPI's option for two additional five year
      terms, at an approximate cost of $16 million per year.
    - NSPI is responsible for managing a portfolio of approximately
      $1.0 billion of defeasance securities held in trust. The defeasance
      securities must provide the principal and interest payment streams of
      the related defeased debt. Approximately 70%, or $702 million, of the
      defeasance portfolio consists of investments in the related debt,
      eliminating all risk associated with this portion of the portfolio.
    - NSPI has a commitment to a third party for the transportation of coal
      for ten years beginning in late 2002 at an approximate cost of
      $16 million per year.
    - NSPI has commitments to third parties for 2008 to 2011, to purchase
      3.1 million metric tons ("mts") of import coal, 724,000 mts of
      petroleum coke, 960,000 mts of domestic coal and 4.1 million mts of
      marine freight. One of these parties has provided notice "note 24".
    - Bangor Hydro has various contracts committing it to purchase annually,
      net of resale revenues, approximately $7 million to $9 million of
      electricity for the period from 2008 to 2018 from independent power
      producers. These commitments are reduced to less than $2 million each
      year from 2018 to 2026.

    26. GUARANTEES

    Emera had the following guarantees at December 31, 2007:

    - The Company has letters of credit issued totaling $21.8 million.
      Emera's outstanding letter of credit is to secure payment to a vendor
      that expires in 2008 and is renewed annually. Nova Scotia Power's
      letters of credit extend to 2008 and/or are renewed annually and secure
      payments to various vendors and obligations under an unfunded pension
      plan. Bangor Hydro's letters of credit extend to 2008 and/or are
      renewed annually to secure payments to a vendor and for obligations
      under an unfunded pension plan.

    27. COMPARATIVE INFORMATION

    Certain of the comparative figures have been reclassified to conform to
the financial statement presentation adopted for 2007.

    OPERATING STATISTICS
    FIVE-YEAR SUMMARY
    -------------------------------------------------------------------------
    Year Ended
     December 31            2007       2006       2005       2004       2003
    -------------------------------------------------------------------------
    Electric energy sales (GWh)
      Residential        4,738.5    4,516.0    4,602.7    4,632.4    4,391.1
      Commercial         3,768.5    3,621.1    3,614.1    3,567.4    3,586.1
      Industrial         4,568.4    3,246.7    4,600.3    4,556.1    4,449.8
      Other              1,320.4    1,550.8      902.7      819.1    1,375.4
    -------------------------------------------------------------------------
    Total electric
     energy sales       14,395.8   12,934.6   13,719.8   13,575.0   13,802.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Sources of energy (GWh)
    Thermal - coal       9,561.4    9,128.1    9,116.3    9,490.2    9,218.7
            - oil          516.6      431.9    1,581.3    1,699.3    1,537.2
            - natural
                  gas    1,057.1      390.3      194.3       97.0      119.5
    Hydro                  936.8    1,034.7    1,092.6      983.5    1,176.8
    Wind                     2.4        2.4        1.8        2.4        2.6
    Purchases            3,534.7    3,144.7    2,961.6    2,339.9    2,724.5
    -------------------------------------------------------------------------
    Total generation
     and purchases      15,609.0   14,132.1   14,947.9   14,612.3   14,779.3
    Losses and
     internal use        1,213.2    1,197.5    1,228.1    1,037.3      976.9
    -------------------------------------------------------------------------
    Total electric
     energy sold        14,395.8   12,934.6   13,719.8   13,575.0   13,802.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Electric customers
      Residential        530,955    526,014    520,671    515,726    509,824
      Commercial          51,083     50,780     50,321     49,353     48,846
      Industrial           2,543      2,526      2,515      2,455      2,393
      Other                9,574      9,378      9,094      8,684      8,341
    -------------------------------------------------------------------------
    Total electric
     customers           594,155    588,698    582,601    576,218    569,404
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Capacity
    Generating nameplate
     capacity (MW)
      Coal fired           1,243      1,243      1,243      1,243      1,243
      Dual fired             350        350        350        350        350
      Gas turbines           319        323        323        319        274
      Hydroelectric        1,005      1,005      1,005        395        395
      Wind turbines            1          1          1          1          1
    Independent power
     producers               120        120         74         66         67
    -------------------------------------------------------------------------
                           3,038      3,042      2,996      2,374      2,330
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total number of
     employees             2,194      2,149      2,075      2,249      2,359
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    km of transmission
     lines                 6,200      6,100      6,100      6,100      6,100
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    km of distribution
     lines                32,000     32,000     32,000     32,000     32,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    FIVE YEAR SUMMARY

    Year Ended December 31
    (millions of dollars)   2007       2006       2005       2004       2003
    -------------------------------------------------------------------------
    Statements of
     Earnings
     Information
    Revenue             $1,339.5   $1,166.0   $1,168.0   $1,134.2   $1,146.8
    -------------------------------------------------------------------------
    Cost of operations
      Fuel for
       generation and
       power purchased     494.5      347.7      432.0      350.0      363.3
      Operating,
       maintenance and
       general             264.8      255.6      248.2      245.2      258.6
      Provincial, state
       and municipal
       taxes                47.5       48.0       48.4       46.3       40.9
      Provincial tax
       deferral                -          -       (4.5)         -          -
      Depreciation         149.3      145.2      136.1      131.2      126.9
      Regulatory
       amortization         31.4       22.8       19.4       26.1       18.2
      Allowance for funds
       used during
       construction        (12.3)      (5.8)      (4.4)      (4.0)      (5.1)
    -------------------------------------------------------------------------
                           975.2      813.5      875.2      794.8      802.8
    -------------------------------------------------------------------------
    Earnings from
     operations            364.3      352.5      292.8      339.4      344.0
    Equity earnings         12.8        4.9        6.5        6.2        8.6
    -------------------------------------------------------------------------
                           377.1      357.4      299.3      345.6      352.6
    Interest               118.7      127.1      117.4      126.8      133.6
    Preferred share
     dividends paid by
     subsidiaries           14.1       14.1       14.1       14.2       14.2
    Amortization of
     defeasance costs       12.7       12.7       13.2       15.1       16.7
    Other income               -       (8.9)      (8.0)         -          -
    -------------------------------------------------------------------------
                           231.6      212.4      162.6      189.5      188.1
    Income taxes            80.3       86.6       52.7       61.9       59.9
    Income taxes
     deferral                  -          -      (12.2)         -          -
    -------------------------------------------------------------------------
    Net earnings from
     continuing operations 151.3      125.8      122.1      127.6      128.2
    (Loss) earnings from
     discontinued
     operations                -          -       (0.9)       2.2        1.0
    -------------------------------------------------------------------------
    Net earnings
     applicable to common
     shares                151.3      125.8      121.2      129.8      129.2
    Common dividends        99.9       98.3       97.4       95.5       92.8
    -------------------------------------------------------------------------
    Earnings retained
     for use in Company    $51.4      $27.5      $23.8      $34.3      $36.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cost of fuel for
     generation - coal    $276.0     $266.2     $260.9     $209.1     $211.9
                - oil       49.7       34.3      100.2       91.1       90.4
                - natural
                      gas   52.0      (41.6)     (35.4)     (30.6)     (58.4)
    Power purchased        116.8       88.8      106.3       80.4      119.4
    -------------------------------------------------------------------------
    Total cost of fuel
     for generation and
     power purchased      $494.5     $347.7     $432.0     $350.0     $363.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Balance Sheets
     Information
    Current assets        $570.0     $491.3     $391.5     $332.1     $305.5
    Other assets           549.0      577.3      678.8      742.0      705.6
    Investments subject
     to significant
     influence             124.5       98.5       99.1       96.8      102.8
    Property, plant
     and equipment       2,929.2    2,881.9    2,829.2    2,778.3    2,777.0
    -------------------------------------------------------------------------
    Total assets        $4,172.7   $4,049.0   $3,998.6   $3,949.2   $3,890.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Current liabilities   $585.8     $491.0     $506.4     $493.6     $520.2
    Other liabilities      366.3      231.8      233.4      231.5      207.8
    Long-term debt       1,600.2    1,657.4    1,631.8    1,626.5    1,589.5
    Preferred shares
     issued by
     subsidiary            260.0      260.0      260.0      260.0      260.0
    Non-controlling
     interest                0.6        0.7        0.8        0.8        0.8
    Common shares        1,066.2    1,055.2    1,039.2    1,017.3    1,007.2
    Contributed surplus      3.0        2.2        1.8        1.9        1.2
    Accumulated other
     comprehensive
     income               (209.0)    (100.2)     (98.2)     (82.0)     (61.1)
    Retained earnings      499.6      450.9      423.4      399.6      365.3
    -------------------------------------------------------------------------
    Total equity and
     liabilities        $4,172.7   $4,049.0   $3,998.6   $3,949.2   $3,890.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Statements of Cash
     Flow Information
    Cash provided by
     operating
     activities           $351.4     $332.5     $151.0     $291.2     $238.7
    Cash used in
     investing
     activities           $288.9     $196.9     $117.2     $214.5      $85.2
    Cash used in
     financing
     activities            $55.6     $143.4      $55.0      $44.0     $171.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Financial ratios
     ($ per common share)
    Earnings per
     common share          $1.36      $1.14      $1.11      $1.20      $1.20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    






For further information:

For further information: Nancy Tower, FCA, Chief Financial Officer,
(902) 428-6991; Jennifer Nicholson, CA, Director, Investor Relations &
Strategic Development, (902) 428-6347

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Emera Inc.

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