Emera Reports Earnings of $144.1 Million for 2008



    HALIFAX, Feb. 13 /CNW/ - (EMA-TSX): Emera Inc.'s consolidated net
earnings were $144.1 million in 2008, compared to $151.3 million in 2007.
Excluding the effect of mark-to-market accounting adjustments in Bear Swamp,
net earnings were $148.9 million in 2008, compared to $141.9 million in 2007.
Earnings per share were $1.29 or $1.33 excluding mark-to-market adjustment for
2008 and $1.36 or $1.28 excluding mark-to-market adjustment for 2007.
Consolidated net earnings for the three months ended December 31, 2008 were
$25.3 million compared to $36.6 million for the fourth quarter of 2007.
Quarterly earnings per share were $0.23 in 2008 compared to $0.33 in 2007.
    "We are pleased with our 2008 results," said Chris Huskilson, President
and Chief Executive Officer of Emera Inc. "Positive trends in our portfolio of
businesses led to a successful year and an increase in our dividend. NSPI's
rate decision, including a fuel adjustment mechanism, was approved in
November, we increased our presence in the Caribbean with our investment in
the Grand Bahama Power Company in September, and Brunswick Pipeline
construction was completed in January 2009."
    Nova Scotia Power Inc. (NSPI), Emera's largest subsidiary, contributed
$105.6 million to 2008 consolidated net earnings, compared to $100.2 million
in 2007. This increase related to the effect of having the April 2007 rate
increase in place for the entire year as well as lower income tax expense.
NSPI contributed $14.4 million to consolidated net earnings in Q4 2008,
compared to $25.2 million in Q4 2007. Earnings were lower quarter-over-quarter
largely due to higher fuel costs.
    Bangor Hydro Electric Company (BHE), Emera's electricity transmission and
distribution utility subsidiary in Maine, contributed $23.1 million for the
year ended December 31, 2008 compared to $27.5 million in 2007. This decrease
was due mainly to the benefits received in 2007 related to the construction of
the NRI transmission line. BHE contributed $6.6 million to consolidated net
earnings in Q4 2008, compared to $6.7 million in Q4 2007.
    Emera's Other operations contributed $15.4 million to consolidated net
earnings in 2008 compared to $23.6 million in 2007. Excluding the effect of
mark-to-market accounting changes on a long-term contract at the Bear Swamp
generating facility, net earnings from Other operations was $20.2 million in
2008 compared to $14.2 million in 2007.
    Consolidated cash provided by operations was $237.2 million for the year
ended December 31, 2008, compared to $351.4 million in 2007. This decrease
relates primarily to the settlement of a receivable from a natural gas
supplier in 2007.

    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, 2008 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 #3280452 (available until midnight, Friday,
February 27, 2009). 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 $5.3 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 600,000 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 and 25% of
Grand Bahama Power Company which serves 19,000 customers on the Caribbean
island of Grand Bahama. In addition to its electric utility investments, Emera
owns the Brunswick Pipeline, a 145 kilometre gas pipeline in New Brunswick;
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; a 7.4% interest in Open Hydro and Emera Energy
Services which manages energy assets on behalf of third parties. Visit Emera
on the web at www.emera.com.


    Management's Discussion & Analysis

    As at February 13, 2009

    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 2008 relative to 2007, and the full
year 2008 relative to 2007 and to 2006; and its financial position at December
31, 2008 relative to 2007. 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 ("MPUC") and the Federal Energy Regulatory
Commission ("FERC"). The accounting policies of Nova Scotia Power Inc. and
Bangor Hydro-Electric Company 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-Electric Company 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 per   Three months ended                    Year ended
     common share)                 December 31                   December 31
    -------------------------------------------------------------------------
                                2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    Revenues                  $337.3    $343.9  $1,331.9  $1,339.5  $1,166.0
    Consolidated net
     earnings                   25.3      36.6     144.1     151.3     125.8
    Earnings per common
     share - basic              0.23      0.33      1.29      1.36      1.14
    Earnings per common
     share - fully diluted      0.22      0.32      1.26      1.32      1.12
    Cash dividends declared
     per share                0.2525    0.2275      0.97      0.90      0.89
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                            Three months ended                    Year ended
                                   December 31                   December 31
    -------------------------------------------------------------------------
    Operating Unit
     Contributions              2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    Nova Scotia Power          $14.4     $25.2    $105.6    $100.2    $104.3
    Bangor Hydro Electric        6.6       6.7      23.1      27.5      16.8
    Other                        4.3       4.7      15.4      23.6       4.7
    -------------------------------------------------------------------------
    Consolidated net
     earnings                  $25.3     $36.6    $144.1    $151.3    $125.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic             $0.23     $0.33     $1.29     $1.36     $1.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic, absent
     the Bear Swamp after-
     tax mark-to-market
     adjustment                $0.26     $0.30     $1.33     $1.28     $1.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                           As at December 31
                                                    2008      2007      2006
    -------------------------------------------------------------------------
    Total assets                                $5,269.4  $4,221.1  $4,049.0
    Total long-term liabilities                  2,843.1   2,354.7   2,149.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    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 wholly-owned 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 $3.5 billion of assets providing service to 482,000
customers in the province of Nova Scotia, and Bangor Hydro-Electric Company
("BHE") is an electricity transmission and distribution company with $783
million of assets serving 117,000 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 mean 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 by 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.

    - Brunswick Pipeline, a 145 kilometer pipeline that delivers natural gas
      from the Canaport(TM) Liquefied Natural Gas import terminal near Saint
      John, New Brunswick, to markets in Canada and the northeastern United
      States. The pipeline was mechanically complete, and received National
      Energy Board approval for shipping gas, in January 2009. This
      accommodates the needs and schedule of the customer, Repsol, and the
      timing of completing the Canaport(TM) LNG terminal, expected in Q2
      2009.

    - 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.

    - Emera Energy Services, a physical energy business which purchases and
      sells natural gas and electricity and provides related energy asset
      management services.

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

    - A 25% indirect interest in Grand Bahama Power Company Limited ("GBPC"),
      a vertically integrated electric utility on Grand Bahama Island, which
      was acquired in September 2008.

    - A 7.35% interest in OpenHydro Group Limited ("OpenHydro"), an Irish
      renewable energy company, which was acquired in February 2008.

    Investment in Grand Bahama Power Company Limited

    In September 2008, Emera indirectly purchased 25% of GBPC for $42.3
million USD ($45.3 million CAD) through its acquisition of 50% of the shares
of ICD Utilities Limited ("ICDU") of the Bahamas. ICDU owns 50% of the shares
of GBPC.
    GBPC has 137 megawatts of installed oil-fired generating capacity. The
Grand Bahama Port Authority Limited regulates the utility and has granted GBPC
a licensed, regulated and exclusive franchise to produce, transmit, and
distribute electricity on the island until 2054. There is a fuel pass through
mechanism and flexible tariff adjustment policies to ensure that costs are
recovered and a reasonable return is earned.
    Emera financed the acquisition with existing credit facilities. GBPC is
expected to add $2.5 million USD to $5.0 million USD to Emera's annual
consolidated net earnings.

    Consolidated Net Earnings History

    (millions of dollars)
                                2008    2007    2006    2005    2004    2003
    Net earnings applicable
     to common shares         $144.1  $151.3  $125.8  $121.2  $129.8  $129.2
    Net earnings applicable
     to common shares,
     absent the Bear Swamp
     after-tax mark-to-
     market adjustment        $148.9  $141.9  $125.8  $121.2  $129.8  $129.2


    Earnings per Share History
    (dollars)

                                2008    2007    2006    2005    2004    2003
    Earnings per share         $1.29   $1.36   $1.14   $1.11   $1.20   $1.20
    Earnings per share,
     absent the Bear Swamp
     after-tax mark-to-market
     adjustment                $1.33   $1.28   $1.14   $1.11   $1.20   $1.20


    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,
Brunswick Pipeline, M&NP, Emera Energy Services, Lucelec, GBPC, OpenHydro 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

    Consolidated Statements
     of Earnings
    millions of dollars
     (except earnings per   Three months ended                    Year ended
     common share)                 December 31                   December 31
    -------------------------------------------------------------------------
                                2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    Electric revenue          $330.6    $322.0  $1,280.8  $1,269.5  $1,132.0
    Other revenue                6.7      21.9      51.1      70.0      34.0
    -------------------------------------------------------------------------
                               337.3     343.9   1,331.9   1,339.5   1,166.0
    Fuel for generation and
     purchased power           154.0     124.0     525.1     494.5     347.7
    Operating, maintenance
     and general                71.0      71.5     266.8     264.8     255.6
    Provincial, state, and
     municipal taxes            12.2      11.4      49.4      47.5      48.0
    Depreciation                39.0      38.1     151.3     149.3     145.2
    Regulatory amortization      9.5       7.8      28.5      31.4      22.8
    -------------------------------------------------------------------------
                                51.6      91.1     310.8     352.0     346.7
    Financing charges           24.8      27.9     123.2     133.2     148.1
    Equity earnings              6.1       3.5      15.2      12.8       4.9
    Other income                   -         -         -         -       8.9
    -------------------------------------------------------------------------
    Earnings before income
     taxes                      32.9      66.7     202.8     231.6     212.4
    Income taxes                 7.0      30.1      58.1      80.3      86.6
    -------------------------------------------------------------------------
    Net earnings                25.9      36.6     144.7     151.3     125.8
    Non-controlling interest     0.6         -       0.6         -         -
    -------------------------------------------------------------------------
    Net earnings applicable
     to common shares          $25.3     $36.6    $144.1    $151.3    $125.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic             $0.23     $0.33     $1.29     $1.36     $1.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - diluted           $0.22     $0.32     $1.26     $1.32     $1.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Review of 2008

    Emera Inc.'s consolidated earnings decreased $11.3 million to $25.3
million in Q4 2008 compared to $36.6 million for the same period in 2007.
Emera's annual consolidated earnings decreased $7.2 million to $144.1 million
in 2008 compared to $151.3 million in 2007, and were $125.8 million in 2006.
Highlights of the changes are summarized in the following table:

                                            Three months ended    Year ended
    millions of dollars                            December 31   December 31
    -------------------------------------------------------------------------
    Consolidated net earnings - 2006                                  $125.8
    Decreased 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                               (4.1)
    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                                                             10.7
    Increased net earnings in Other due
     mainly to Bear Swamp's increased
     energy and capacity sales and a
     favourable price position; and M&NP's
     capitalization of prior years'
     expansion costs in Q1 2007 and
     increased equity earnings due to
     increased tolls and volume                                         18.9
    -------------------------------------------------------------------------
    Consolidated net earnings - 2007                     $36.6         151.3
    Q4 decreased net earnings in NSPI due to
     increased fuel expense partially offset
     by lower income taxes; year-to-date
     increase is due to an electricity price
     increase on April 1, 2007, decreased
     financing charges and accelerated
     income tax deductions, partially offset
     by increased fuel expense                           (10.8)          5.4
    Decreased net earnings in Bangor Hydro
     due mainly to the capitalization of
     costs associated with the NRI
     transmission line in 2007                            (0.1)         (4.4)
    Increased net earnings in Other due
     mainly to allowance for funds used
     during construction ("AFUDC") on
     construction of the Brunswick Pipeline,
     partially offset by increased interest
     on short-term debt used to finance the
     construction of the pipeline. Increased
     year-to-date earnings also reflect Bear
     Swamp's increased year-to-date energy
     and forward reserve sales                             6.7           6.0
    Decreased net earnings in Other related
     to the after-tax mark-to-market
     adjustment on the commodity price
     position in Bear Swamp as discussed in
     Significant Items                                    (7.1)        (14.2)
    -------------------------------------------------------------------------
    Consolidated net earnings - 2008                     $25.3        $144.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Q4 basic earnings per share were $0.23 in 2008 compared to $0.33 in 2007;
    and $1.29 for the full year 2008 compared to $1.36 in 2007 and $1.14 in
    2006.


    SIGNIFICANT ITEMS

    Bear Swamp (2007 - 2008)

    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 to provide the power necessary to produce the energy requirements of
the LIPA contract. One of the contracts between Bear Swamp and Emera's joint
venture partner is marked-to-market through earnings as it does not meet the
stringent accounting requirements of hedge accounting. As at December 31,
2008, the fair value of the net derivative asset was $4.9 million (December
31, 2007 - $10.5 million), which is subject to market volatility of power
prices, and will reverse over the life of the agreement as it is realized. The
agreement expires in 2021.
    The mark-to-market adjustments relating to this position were as follows:

    millions of dollars
    (except earnings per          Three months ended              Year ended
     common share)                       December 31             December 31
    -------------------------------------------------------------------------
                                    2008        2007        2008        2007
    -------------------------------------------------------------------------
    Mark-to-market (loss) gain     $(6.0)       $5.9       $(8.1)      $15.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    After-tax mark-to-market
     (loss) gain                   $(3.6)       $3.5       $(4.8)       $9.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic                 $0.23       $0.33       $1.29       $1.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Earnings per common
     share - basic, absent the
     after-tax mark-to-market
     adjustment                    $0.26       $0.30       $1.33       $1.28
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Income tax recovery (2007 - 2008)

    During 2008, NSPI accelerated the deduction of capitalized expenses
pertaining to the 2007 tax year. As a result, in 2008 NSPI recorded an income
tax recovery of $6.5 million. NSPI will continue to use this methodology in
current and future years.
    During 2007, NSPI filed amended tax returns for 2000 to 2004 related to
the deductibility of previously capitalized overhead expenses. Canada Revenue
Agency ("CRA") audited and approved the amended filings for these years. In
2008, NSPI amended its 2005 and 2006 tax returns on the same basis as was used
for the 2000 to 2004 years. The amendments have since been processed by CRA.
All material amounts relating to these prior year adjustments were recorded in
the 2007 financial statements of NSPI. This resulted in an income tax recovery
of $25.4 million in Q3 2007, of which $14.6 million was recorded as a
reduction of other assets and the remaining $10.8 million was recorded as a
reduction of income tax expense. In addition, in Q4 2007, NSPI recorded refund
interest of $8.6 million, $1.8 million of which was recorded as a reduction of
other assets and the remaining $6.8 million was recorded as a reduction of
financing charges. NSPI used this methodology in filing its 2007 return and
will continue to use this methodology when filing its 2008 and future income
tax returns.

    Settlement of claim (2006)

    In late 2005 a number of NSPI'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, NSPI 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, NSPI
received $8.9 million ($5.5 million after-tax) in settlement of this claim.

    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 85
MW of renewable energy, substantially wind energy, under contracts with
independent power producers. During 2008, NSPI signed power purchase
agreements for 246 MW of new wind energy sources with seven independent power
producers. NSPI also owns approximately 5,000 kilometers of transmission
facilities, and 26,000 kilometers of distribution facilities. The company has
a workforce of approximately 1,800 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.
    NSPI 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 return on equity ("ROE")
range for 2008 was 9.3% - 9.8%, on a maximum allowed common equity component
of 40% of total capitalization. Rates were set for 2009 using a 9.35% ROE,
with a common equity component of 37.5%. The ROE range for 2009 is 9.1% - 9.6%
on a maximum allowed common equity component of 45% of total capitalization.

    Appointment

    On December 1, 2008 NSPI announced plans that George Caines will become
Chair of the Board of Directors of NSPI, effective May 6, 2009. Mr. Caines
will take over from John McLennan, who will replace Derek Oland as Chair of
the Board of Emera Inc.

    2009 Rate Decision

    In May 2008 NSPI filed a rate application with the UARB requesting an
overall rate increase of 11.9% effective January 1, 2009. In September 2008,
NSPI reached a settlement agreement with stakeholders regarding that rate
application. The UARB approved that settlement agreement in November 2008
which includes an average rate increase of 9.4% for most customer segments
effective January 1, 2009. The approved settlement agreement also includes 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 FAM, including review of fuel costs, contracts and transactions.
With the implementation of the FAM, NSPI's ROE range will be reduced to 9.1% -
9.6% with 9.35% used to set rates.

    2007 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.

    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
ROE 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.

    Review of 2008

    NSPI Net Earnings
    millions of dollars
     (except earnings per   Three months ended                    Year ended
     common share)                 December 31                   December 31
    -------------------------------------------------------------------------
                                2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    Electric revenue          $280.7    $283.1  $1,111.1  $1,102.0    $967.9
    -------------------------------------------------------------------------
    Fuel for generation and
     purchased power           139.5     110.3     471.4     433.7     292.8
    Operating, maintenance
     and general                52.3      55.3     203.7     206.0     202.5
    Provincial grants and
     taxes                      10.3      10.1      41.2      40.4      40.3
    Depreciation                33.8      33.1     133.6     131.1     127.8
    Regulatory amortization      6.4       4.5      17.7      17.2       8.6
    Other revenue               (3.5)     (3.7)    (15.5)    (11.7)     (9.6)
    -------------------------------------------------------------------------
                                41.9      73.5     259.0     285.3     305.5
    Financing charges           20.3      24.7     106.8     123.0     130.6
    Other income                   -         -         -         -      (8.9)
    -------------------------------------------------------------------------
    Earnings before income
     taxes                      21.6      48.8     152.2     162.3     183.8
    Income taxes                 7.2      23.6      46.6      62.1      79.5
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings                  $14.4     $25.2    $105.6    $100.2    $104.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated earnings
     per common share          $0.12     $0.23     $0.94     $0.90     $0.94
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    NSPI's contribution to consolidated net earnings decreased $10.8 million
to $14.4 million in Q4 2008, compared to $25.2 million in Q4 2007. Annual
contribution to consolidated net earnings increased $5.4 million to $105.6
million in 2008 compared to $100.2 million in 2007, and was $104.3 million in
2006. Highlights of the earnings changes are summarized in the following
table:

                                            Three months ended    Year ended
    millions of dollars                            December 31   December 31
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2006                                                  $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                                         134.1
    Increased fuel expense                                            (140.9)
    Increased operating expenses mainly due
     to increased storm related costs                                   (3.5)
    Increased regulatory amortization due
     to the start of a new regulatory
     amortization on April 1, 2007                                      (8.6)
    Decreased other income                                              (8.9)
    Decreased financing charges mainly due
     to income tax recovery interest                                     7.6
    Decreased income taxes due to an income
     tax recovery                                                       10.8
    Decreased income taxes due to lower
     taxable income                                                      6.6
    All other                                                           (1.3)
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2007                                     $25.2         100.2
    Decreased electric revenue in Q4 due to
     decreased commercial and industrial
     sales volume; year-to-date increased
     electric revenue due to an electricity
     price increase on April 1, 2007                      (2.4)          9.1
    Increased fuel expense                               (29.2)        (37.7)
    Decreased financing charges due to
     foreign exchange gains on USD
     denominated monetary net assets
     compared to foreign exchange losses in
     2007; and lower interest costs                        4.4          16.2
    Decreased income taxes due to lower
     taxable income, accelerated deductions
     for capital items and a lower statutory
     rate                                                 16.4          15.5
    Other                                                    -           2.3
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2008                                     $14.4        $105.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Electric Revenue

    Q4 Electric Sales Volume            Q4 Electric Sales Revenues
    Gigawatt hours ("GWh")              millions of dollars
    ----------------------------------  -------------------------------------
                 2008    2007    2006                 2008      2007    2006
    ----------------------------------  -------------------------------------
    Residen-                            Residen-
     tial       1,093   1,064   1,016    tial       $129.1    $125.7  $115.5
    Commercial    770     793     742   Commercial    76.9      78.5    72.0
    Industrial    987   1,046     925   Industrial    64.2      67.5    58.5
    Other          84      99     116   Other         10.5      11.4    11.9
    ----------------------------------  -------------------------------------
    Total       2,934   3,002   2,799   Total       $280.7    $283.1  $257.9
    ----------------------------------  -------------------------------------
    ----------------------------------  -------------------------------------


    Year-to-Date ("YTD") Electric
     Sales Volume                       YTD Electric Sales Revenues
    GWh                                 millions of dollars
    ----------------------------------  -------------------------------------
                 2008    2007    2006                 2008      2007    2006
    ----------------------------------  -------------------------------------
    Residen-                            Residen-
     tial       4,179   4,145   3,927    tial       $496.3    $485.6  $439.9
    Commercial  3,115   3,161   3,023   Commercial   305.2     307.6   285.2
    Industrial  4,144   4,191   2,874   Industrial   268.1     266.6   184.8
    Other         334     365     681   Other         41.5      42.2    58.0
    ----------------------------------  -------------------------------------
    Total      11,772  11,862  10,505   Total     $1,111.1  $1,102.0  $967.9
    ----------------------------------  -------------------------------------
    ----------------------------------  -------------------------------------


    Q4 Average Revenue / Megawatt hour
     ("MWh")
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $96     $94     $92
    ----------------------------------
    ----------------------------------


    YTD Average Revenue / MWh
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $94     $93     $92
    ----------------------------------
    ----------------------------------


    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 1% 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 small retail operations, large
office and commercial complexes, and the province's universities and
hospitals. Industrial customers include manufacturing facilities and other
large volume operations. Other electric consists of export sales, sales to
municipal electric utilities and revenues from street lighting.
    Electric revenues decreased by $2.4 million to $280.7 million in Q4 2008
compared to $283.1 million in Q4 2007 due to decreased commercial and
industrial sales volume.
    For the year ended December 31, 2008 electric revenues increased $9.1
million to $1,111.1 million compared to $1,102.0 million in 2007. Revenue
increases are substantially due to a 3.8% rate increase effective April 1,
2007.
    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.
    The increase in average revenue per MWh in 2008 compared to 2007 reflects
the April 1, 2007 rate increase noted above.
    The average revenue per MWh is higher in 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.

    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 85 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 compared to North American
      averages.

    - 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

                 2008      2007      2006      2005      2004
                  75%       79%       71%       78%       82%

    NSPI Thermal Capacity Availability

                 2008      2007      2006      2005      2004
                  88%       91%       90%       90%       92%

    NSPI's thermal capacity utilization was 75% in 2008 compared to 79% in
2007. This was due to NSPI taking advantage of economic import energy as a
result of lower marginal cost for energy in the northeastern United States
during extended periods of warmer weather.
    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 lower cost energy to customers. In
2008, coal plant availability was 88%. The decrease in availability from 2007
reflects extended maintenance periods. 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
    ----------------------------------  -------------------------------------
                 2008    2007    2006                 2008      2007    2006
    ----------------------------------  -------------------------------------
    Coal &                              Coal &
     petcoke    2,177   2,519   2,368    petcoke     9,009     9,561   9,128
    Natural                             Natural
     gas          249     333     128    gas         1,258     1,057     390
    Oil &                               Oil &
     diesel       218      45     174    diesel        339       515     431
    Renewable     257     218     233   Renewable    1,068       911     998
    Purchased                           Purchased
     power        296     189     180    power         889       654     405
    ----------------------------------  -------------------------------------
    Total       3,197   3,304   3,083   Total       12,563    12,698  11,352
    ----------------------------------  -------------------------------------
    ----------------------------------  -------------------------------------
    Purchased power includes 44 GWh of  Purchased power includes 148 GWh of
    renewables in 2008 (2007 - 49 GWh;  renewables in 2008 (2007 - 161 GWh;
    2006 - 33 GWh).                     2006 - 109 GWh).


    Q4 Average Unit Fuel Costs
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $44     $33     $28
    ----------------------------------
    ----------------------------------


    YTD Average Unit Fuel Costs
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $38     $34     $26
    ----------------------------------
    ----------------------------------


    Solid fuel is NSPI's dominant fuel source, supplying approximately 72% of
the company's annual energy. Solid fuels have the lowest per unit fuel cost,
after hydro and NSPI owned 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.
    The average unit fuel costs increased in 2008 compared to 2007 mainly due
to the decreased value of the natural gas supply contract as reflected in the
long-term receivable, and change in generation mix due to lower coal
production due to an increase in coal plant maintenance. Increased coal prices
were partially offset by the economic use of natural gas and favourable hedge
positions as a result of this fuel switch.
    The average unit fuel costs increased in 2007 compared to 2006 mainly due
to the use of higher marginal cost production because of increased 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 Risks and
Enterprise Risk Management section. Fuel 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, 2008, fuel for generation and
purchased power increased $29.2 million to $139.5 million, compared to $110.3
million in Q4 2007. For the year ended December 31, 2008, fuel for generation
and purchased power increased $37.7 million to $471.4 million compared to
$433.7 million in 2007 and $292.8 million in 2006. Highlights of the changes
are summarized in the following table:

                                            Three months ended    Year ended
    millions of dollars                            December 31   December 31
    -------------------------------------------------------------------------
    Fuel for generation and purchased
     power - 2006                                                     $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                                                    103.6
    Commodity price increases                                            6.6
    Decreased net proceeds from the resale
     of natural gas due to the economic
     decision to use natural gas in the
     production process                                                 48.6
    Decreased export sales volume                                      (12.4)
    All other                                                           (5.5)
    -------------------------------------------------------------------------
    Fuel for generation and purchased
     power - 2007                                       $110.3         433.7
    Increased commodity prices in Q4
     primarily due to increased coal and
     natural gas prices; year-to-date the
     increase in coal prices was partially
     offset by the economic use of natural
     gas and favourable hedge positions as a
     result of this fuel switch                           16.9          18.3
    Decreased sales volume                                (7.4)         (9.9)
    Decreased net proceeds from the resale
     of natural gas due to the economic
     decision to use natural gas in the
     production process                                    6.6           8.8
    Increased hydro production                            (3.0)        (11.9)
    Changes in generation mix due to
     increased coal plant maintenance                     16.1          30.7
    Other                                                    -           1.7
    -------------------------------------------------------------------------
    Fuel for generation and purchased
     power - 2008                                       $139.5        $471.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The valuation of the long-term receivable from a natural gas supplier
requires NSPI to utilize a combination of historical and future natural gas
prices. NSPI uses market-based forward indices when determining future prices.
Future prices can change from period to period which will cause a
corresponding change in the value of the long-term receivable.

    Operating, Maintenance and General

    Operating, maintenance and general expenses have remained relatively
unchanged over the three year period.

    Provincial Grants and Taxes

    NSPI pays annual grants to the Province of Nova Scotia in lieu of
municipal taxation other than deed transfer tax.

    Depreciation

    Depreciation expense increased slightly over the three year period due to
plant additions.
    In its November 5, 2008 rate decision, the UARB approved a scheduled
year-three phase-in of the previously approved increased depreciation rates
commencing January 1, 2009.

    Regulatory Amortization

    Regulatory amortization increased $1.9 million to $6.4 million in Q4 2008
compared to $4.5 million in Q4 2007 due to additional amortization of the
pre-2003 income taxes partially offset by the completion of Glace Bay
generating station amortization in 2007.
    For the year ended December 31, 2008 regulatory amortization increased
$0.5 million to $17.7 million compared to $17.2 million in 2007 for the
reasons noted above.
    For the year ended December 31, 2007 regulatory amortization increased
$8.6 million to $17.2 million compared to $8.6 million in 2006 due to the
amortization of pre-2003 income taxes beginning in April 2007 partially offset
by the completion of the Glace Bay generating station amortization in 2007.

    Other Revenue

    Other revenue has increased over the three year period due to settlements
received and a reduction in the accounts receivable securitization program
which resulted in lower fees.

    Financing Charges

    Financing charges decreased $4.4 million to $20.3 million in Q4 2008
compared to $24.7 million in Q4 2007, and decreased $16.2 million to $106.8
million for the year ended December 31, 2008 compared to $123.0 million in
2007 primarily due to foreign exchange gains in 2008 partially offset by
income tax recovery interest in 2007.
    Financing charges decreased $7.6 million, to $123.0 million for the year
ended December 31, 2007 compared to $130.6 million in 2006 primarily due to
the income tax recovery interest as discussed below. As discussed in
Significant Items, in Q4 2007 NSPI recorded income tax refund interest of $8.6
million, $1.8 million of which has been recorded as a reduction of other
assets. The remaining $6.8 million has been recorded as a reduction of
financing charges.
    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.

    Income Taxes

    In accordance with ratemaking regulations established by the UARB, NSPI
uses the taxes-payable method of accounting for income taxes.
    In 2008, NSPI was subject to provincial capital tax (0.2125%), corporate
income tax (35.5%) 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 (42.6% of preferred dividends).
    As discussed in Significant Items, during 2008 NSPI accelerated the
deduction of capitalized expenses pertaining to the 2007 tax year. As a
result, in 2008 NSPI recorded an income tax recovery of $6.5 million. In Q3
2007 NSPI recorded an income tax recovery of $25.4 million, of which $14.6
million was recorded as a reduction of other assets. The remaining $10.8
million was recorded as a reduction of income tax expense.

    Outlook

    Based on the 2009 rate decision and the current economic forecast for Nova
Scotia, NSPI expects to earn within its ROE range in 2009.

    Debt Management

    NSPI has established the following available credit facilities:

    Short-term                                                       Maximum
    millions of dollars                               Maturity        amount
    -------------------------------------------------------------------------
    Operating credit facility                 1 Year Revolving        $500.0
    -------------------------------------------------------------------------


    In July 2008, medium term note series "O", 5.65%, $115 million matured.
    In December 2008, NSPI issued a $150 million medium term note. This note
was issued under a reopening of Series "T", 5.75%, originally issued in
September 2003. This $150 million issue yields 6.238% and will mature in
October 2013. In January 2009, NSPI issued an additional $50 million medium
term note under an additional reopening of Series "T", yielding 5.455%. This
additional issue also matures in October 2013. The proceeds of both issues
were used to pay down short-term borrowings, incurred for general corporate
purposes.
    There were no long-term debt issuances or maturities in 2007 and 2006.
    The weighted average coupon rate on NSPI's outstanding medium-term and
debenture notes at December 31, 2008, was 6.84% (2007 - 6.86%). Approximately
39% of the debt matures over the next ten years; 57% 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 6.12% as of December 31, 2008 (2007 - 5.34%).
    NSPI has the following credit ratings:

                                            DBRS           S&P       Moody's
    -------------------------------------------------------------------------
    Corporate                                N/A           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
    -------------------------------------------------------------------------


    In November 2008, Standard & Poor's ("S&P") Rating Services revised its
rating outlook on Nova Scotia Power to Positive from Stable. At the same time,
S&P confirmed NSPI's other ratings. The outlook revision reflects the recent
regulatory approval of a FAM.
    In August 2008, Moody's Investors Service ("Moody's") confirmed the credit
ratings of Nova Scotia Power and revised the rating outlook from negative to
stable. The revision reflects Moody's view that NSPI has been successful in
improving its relationships with key stakeholders and the UARB. Moody's also
expects that NSPI's exposure to regulatory risk will be reduced and that there
is less likelihood of variability in NSPI's financial results following
implementation of the FAM in January 2009.

    BANGOR HYDRO-ELECTRIC COMPANY

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

    Overview

    BHE'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 and currently has
approximately $100 million of additional transmission development in progress.
BHE has a workforce of approximately 260 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 $55.2
million at December 31, 2008, or 8% of BHE's net asset base.
    Approximately 60% of BHE's electric rate represents distribution service,
20% relates to stranded cost recoveries, and 20% 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 operates under a traditional cost-of-service regulatory structure. In
December 2007, the MPUC approved an increase of approximately 2% in
distribution rates effective January 1, 2008. The allowed ROE used in setting
the new distribution rates is 10.2%, with a common equity component of 50%.
    Until December 31, 2007, BHE's distribution service operated under an
Alternate Rate Plan ("ARP"), which provided for an ROE range of 5% to 17% 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. Beginning January 1, 2008, the earnings band and associated
sharing mechanism, performance standard, and annual distribution rate
reductions are no longer applicable.
    BHE's stranded cost rates provide for an allowed ROE 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 approximate 39% 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 11.14% for low voltage transmission up to 12.64% for high voltage
transmission developed as a result of the regional system plan, which includes
the NRI transmission line.

    Review of 2008

    BHE Net Earnings
    millions of dollars
     (except earnings per   Three months ended                    Year ended
     common share)                 December 31                   December 31
    -------------------------------------------------------------------------
                                2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    T&D revenues               $25.9     $25.9     $97.6    $101.7    $101.8
    Resale of purchased
     power                       5.4       3.7      20.4      14.6      15.2
    Transmission pool
     revenue                     3.2       4.5      16.5      12.7         -
    -------------------------------------------------------------------------
    Total revenue               34.5      34.1     134.5     129.0     117.0
    Fuel for generation and
     purchased power             8.1       8.3      32.2      31.9      31.4
    Operating, maintenance
     and general                 7.8       8.0      28.8      26.3      27.1
    Property taxes               1.3       0.8       5.4       4.8       5.0
    Depreciation                 3.9       3.2      15.3      13.0      12.9
    Regulatory amortization      2.6       3.2      10.1      13.2      12.6
    Other                       (0.7)     (0.8)     (3.8)     (2.1)     (2.2)
    -------------------------------------------------------------------------
    Earnings before
     financing charges and
     income taxes               11.5      11.4      46.5      41.9      30.2
    Financing charges            2.6       1.2      11.1       3.2       6.6
    -------------------------------------------------------------------------
    Earnings before income
     taxes                       8.9      10.2      35.4      38.7      23.6
    Income taxes                 3.6       3.5      13.9      13.0       8.8
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings - USD             $5.3      $6.7     $21.5     $25.7     $14.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings - CAD             $6.6      $6.7     $23.1     $27.5     $16.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated earnings
     per common share - CAD    $0.07     $0.06     $0.21     $0.25     $0.15
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net earnings weighted
     average foreign
     exchange rate -
     CAD /USD                  $1.23     $0.99     $1.07     $1.07     $1.13
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    BHE's contribution to consolidated net earnings decreased $1.4 million to
$5.3 million in Q4 2008 compared to $6.7 million in Q4 2007. Annual
contribution to consolidated net earnings decreased $4.2 million to $21.5
million compared to $25.7 million in 2007, and was $14.8 million in 2006.
Highlights of the earnings changes are summarized in the following table:

                                            Three months ended    Year ended
    millions of dollars                            December 31   December 31
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2006                                                   $14.8
    Increased transmission pool revenue
     associated with the recovery of the NRI
     transmission line from the New England
     Power Pool ("NEPOOL") beginning in June
     2007                                                               12.7
    Increased overheads and AFUDC
     capitalized primarily as a result of
     capital expenditures on the NRI
     transmission line                                                   4.0
    Increased income taxes due to increased
     earnings                                                           (4.2)
    All other                                                           (1.6)
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2007                                      $6.7          25.7
    Year-to-date increase primarily due to
     increased net transmission pool revenue
     and a decrease in miscellaneous
     transmission charges                                 (0.9)          5.0
    Decreased overheads and AFUDC
     capitalized primarily as a result of
     completing the NRI transmission line in
     Q4 2007                                              (1.7)        (10.0)
    Increased interest expense and
     depreciation primarily related to the
     NRI transmission line                                (0.4)         (3.0)
    Other                                                  1.6           3.8
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2008                                      $5.3         $21.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    BHE's decreased contribution to consolidated net earnings in CAD in Q4
2008 compared to Q4 2007 was partially offset by the $1.3 million impact of
the weaker Canadian dollar.  BHE's increased contribution to consolidated net
earnings in CAD in 2007 compared to 2006 was partially offset by the $1.5
million effect of the stronger Canadian dollar.


    Electric Revenue

    Q4 Electric Sales Volume            Q4 Electric Sales Revenues
    GWh                                 millions of dollars
    ----------------------------------  -------------------------------------
                 2008    2007    2006                 2008      2007    2006
    ----------------------------------  -------------------------------------
    Residential   155     157     155   Residential  $12.8     $13.0   $12.9
    Commercial    145     149     141   Commercial     8.7       9.0     8.8
    Industrial     90     102      93   Industrial     3.0       2.7     2.8
    Other           2       3       3   Other          1.4       1.2     1.0
    ----------------------------------  -------------------------------------
    Total         392     411     392   Total        $25.9     $25.9   $25.5
    ----------------------------------  -------------------------------------
    ----------------------------------  -------------------------------------


    YTD Electric Sales Volume           YTD Electric Sales Revenues
    GWh                                 millions of dollars
    ----------------------------------  -------------------------------------
                 2008    2007    2006                 2008      2007    2006
    ----------------------------------  -------------------------------------
    Residential   591     594     589   Residential  $47.6     $49.6   $49.1
    Commercial    604     606     598   Commercial    34.5      36.5    36.1
    Industrial    350     379     372   Industrial    10.0      11.1    11.3
    Other          10      12      12   Other          5.5       4.5     5.3
    ----------------------------------  -------------------------------------
    Total       1,555   1,591   1,571   Total        $97.6    $101.7  $101.8
    ----------------------------------  -------------------------------------
    ----------------------------------  -------------------------------------


    Q4 Average Revenue / MWh
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $66     $63     $65
    ----------------------------------
    ----------------------------------


    YTD Average Revenue / MWh
    ----------------------------------
                 2008    2007    2006
    ----------------------------------
    Dollars per
     MWh          $63     $64     $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 were flat at $25.9 million in Q4 2008 compared to Q4
2007. For the year ended December 31, 2008, electric revenues decreased $4.1
million to $97.6 million compared to $101.7 million for 2007 due to decreased
sales volume and decreased stranded cost rates. For the year ended December
31, 2007, electric revenues were unchanged at $101.7 million compared to
$101.8 million in 2006.
    The changes in average revenue per MWh in 2008 compared to 2007 reflects
the July 1, 2007 reduction in transmission rates and the March 1, 2008
reduction in stranded cost rates, offset by the January 1, 2008 increase in
distribution rates and an increase in transmission rates on July 1, 2008.

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

    BHE 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 as determined through a bid process administered
and approved by the MPUC. The difference between the cost of the power
purchased under these arrangements and the revenue collected from the third
party is recovered through stranded cost rates.

    Transmission Pool Revenue

    Transmission pool revenue includes recovery of the NRI transmission line
from NEPOOL, which began in June 2007, offset by NEPOOL transmission
infrastructure investment charges. BHE recovers the cost of its regionally
funded transmission infrastructure investment through the transmission pool
revenue based on a regional formula that is updated on June 1st of each year.
    Transmission pool revenue decreased by $1.3 million in Q4 2008 to $3.2
million compared to $4.5 million in Q4 2007 due to increased regional charges
from increased transmission infrastructure investment. For the year ended
December 31, 2008, transmission pool revenue increased $3.8 million to $16.5
million compared to $12.7 million for 2007. Much of the year over year
increase is due to 12 months of pool revenue in 2008 from the NRI transmission
line compared to seven months in 2007, partially offset by increased regional
charges.

    Depreciation

    Depreciation expense increased $0.7 million to $3.9 million in Q4 2008
compared to $3.2 million in Q4 2007; and increased $2.3 million to $15.3
million in 2008 compared to $13.0 million in 2007 primarily due to
depreciation on the NRI transmission line which went into service in Q4 2007.

    Financing Charges

    Financing charges increased $1.4 million to $2.6 million in Q4 2008
compared to $1.2 million in Q4 2007 and increased $7.9 million to $11.1
million for the year ended December 31, 2008, compared to $3.2 million in 2007
primarily due to increased debt used to finance the NRI transmission line and
decreased AFUDC capitalized on the NRI transmission line which went into
service in Q4 2007.
    Financing charges decreased $3.4 million to $3.2 million for the year
ended December 31, 2007, compared to $6.6 million in 2006 primarily due to
increased capitalized AFUDC related to the NRI transmission line partially
offset by increased debt used to finance the NRI transmission line.

    Income Taxes

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

    Outlook

    BHE's net earnings for 2009 are expected to be slightly higher than 2008
primarily due to increased transmission investment recoveries.

    Debt Management

    BHE has established the following credit facilities:

    Short-term                                                       Maximum
    millions of dollars                               Maturity        amount
    -------------------------------------------------------------------------
    Unsecured revolving facility              2 year revolving-        $60.0
                                          matures in June 2010
    -------------------------------------------------------------------------

    In September 2007, the company completed a private placement of $50
million in senior unsecured notes at an average interest rate of 5.74% of
which $30 million will mature in September 2014 and $20 million will mature in
September 2017. The primary use of these proceeds was to fund the NRI
transmission line. 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 BHE's long-term debt outstanding at
December 31, 2008 was 6.87% (2007 - 6.82%). Approximately 70% 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 6.95% as of December 31, 2008
(2007 - 5.62%).
    BHE has no public debt, and accordingly has no requirement for public
credit ratings. BHE 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 wholly-owned 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.

    - Brunswick Pipeline, a 145 kilometer pipeline that delivers natural gas
      from the Canaport(TM) Liquefied Natural Gas import terminal near
      Saint John, New Brunswick, to markets in Canada and the northeastern
      United States. The pipeline was mechanically complete, and received
      National Energy Board approval for shipping gas, in January 2009. This
      accommodates the needs and schedule of the customer, Repsol, and the
      timing of completing the Canaport(TM) LNG terminal, expected in Q2
      2009.

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

    - Emera Energy Services, a physical energy business which purchases and
      sells natural gas and electricity 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.

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

    - A 25% indirect interest in GBPC, a vertically integrated utility
      serving 19,000 customers on Grand Bahama Island, which was acquired in
      September 2008.

    - A 7.35% interest in OpenHydro, an Irish renewable tidal energy company,
      which was acquired in February 2008.

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


    Review of 2008

    Bear Swamp, Brunswick Pipeline, and Emera Energy Services are reported on
an earnings before interest and other income taxes basis ("EBIT"), and M&NP,
Lucelec and GBPC are reported on an equity earnings basis.

    Other Net Earnings
    millions of dollars
     (except earnings per   Three months ended                    Year ended
     common share)                 December 31                   December 31
    -------------------------------------------------------------------------
                                2008      2007      2008      2007      2006
    -------------------------------------------------------------------------
    Bear Swamp - operational    $2.4      $3.6     $15.8      $8.9      $1.4
    Bear Swamp - mark-to-
     market                     (6.0)      5.9      (8.1)     15.7         -
    Brunswick Pipeline           7.0         -      15.6         -         -
    M&NP                         4.6       2.6      12.2      10.6       4.9
    Emera Energy Services        1.8       1.9       7.3      12.2      15.1
    Lucelec                      0.3       0.9       1.8       2.2         -
    GBPC                         1.2         -       1.2         -         -
    Corporate costs & other     (2.2)     (4.8)    (12.3)    (14.4)     (9.6)
    -------------------------------------------------------------------------
                                 9.1      10.1      33.5      35.2      11.8
    Interest                     8.6       2.4      20.8       7.4      10.0
    -------------------------------------------------------------------------
                                 0.5       7.7      12.7      27.8       1.8
    Income taxes                (4.4)      3.0      (3.3)      4.2      (2.9)
    -------------------------------------------------------------------------
                                 4.9       4.7      16.0      23.6       4.7
    Non-controlling interest    (0.6)        -      (0.6)        -         -
    -------------------------------------------------------------------------
    Contribution to
     consolidated net
     earnings                   $4.3      $4.7     $15.4     $23.6      $4.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated earnings
     per share                 $0.04     $0.04     $0.14     $0.21     $0.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Contribution to
     consolidated net
     earnings, absent the
     Bear Swamp after-tax
     mark-to-market
     adjustment                 $7.9      $1.2     $20.2     $14.2      $4.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Contribution to
     consolidated earnings
     per share, absent the
     Bear Swamp after-tax
     mark-to-market
     adjustment                $0.07     $0.01     $0.18     $0.13     $0.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    The total contribution of Other to consolidated net earnings decreased
$0.4 million to $4.3 million in Q4 2008 compared to $4.7 million in Q4 2007.
Annual contribution to consolidated net earnings decreased $8.2 million to
$15.4 million in 2008 compared to $23.6 million in 2007, and was $4.7 million
in 2006. Highlights of the earnings changes are summarized in the following
table:

                                            Three months ended    Year ended
    millions of dollars                            December 31   December 31
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2006                                                    $4.7
    Increased Bear Swamp - operational due
     to increased energy and capacity sales                              7.5
    Increased Bear Swamp - mark-to-market
     due to a favourable commodity price
     position                                                           15.7
    Decreased Emera Energy Services as a
     result of changes in supply, market
     performance, and a stronger Canadian
     dollar                                                             (2.9)
    Increased M&NP due to expansion costs
     that were expensed throughout 2006 and
     then capitalized in Q1 2007 and
     increased equity earnings due to
     increased tolls and volume                                          5.7
    Equity earnings from Lucelec which was
     purchased in Q1 2007                                                2.2
    Increased corporate costs and other due
     to increased business development
     activity and depreciation                                          (4.8)
    Increased income taxes related to
     increased earnings                                                 (7.1)
    All other                                                            2.6
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2007                                      $4.7          23.6
    Increased year-to-date Bear Swamp -
     operational due to increased energy and
     forward reserve sales                                (1.2)          6.9
    Decreased Bear Swamp - mark-to-market
     due to an unfavourable commodity price
     position                                            (11.9)        (23.8)
    Increased Brunswick Pipeline due to
     AFUDC on construction of the pipeline                 7.0          15.6
    Decreased Emera Energy Services
     primarily due to reduced activity                    (0.1)         (4.9)
    Increased interest due to increased
     short-term debt used to finance the
     construction of Brunswick Pipeline and
     foreign exchange losses in 2008
     compared to foreign exchange gains in
     2007                                                 (6.2)        (13.4)
    Decreased income taxes due to decreased
     earnings                                              7.4           7.5
    Equity earnings from GBPC which was
     purchased in Q3 2008                                  1.2           1.2
    -------------------------------------------------------------------------
    Other                                                  3.4           2.7
    -------------------------------------------------------------------------
    Contribution to consolidated net
     earnings - 2008                                      $4.3         $15.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Bear Swamp

    Bear Swamp EBIT represents Emera's investment in the Bear Swamp joint
venture.

    Operational

    Bear Swamp EBIT - operational decreased quarter over quarter to $2.4
million in Q4 2008 compared to $3.6 million in Q4 2007; and increased to $15.8
million in 2008 compared to $8.9 million in 2007 and $1.4 million in 2006.
During 2006 a hedging program was implemented to provide more consistent
margins and resulted in a mark-to-market loss in 2006, which reversed in 2007.
    During Q1 2007, Bear Swamp finalized a long-term agreement with the Long
Island Power Authority to provide 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 for the
power supply necessary to produce the energy requirements of the LIPA
agreement.

    Mark-to-market

    As mentioned above, Bear Swamp has contracted with its parents to provide
the power necessary to produce the energy requirements of the LIPA contract.
One of the contracts between Bear Swamp and Emera's joint venture partner is
marked-to-market through earnings as it does not meet the stringent accounting
requirements of hedge accounting. As at December 31, 2008, the fair value of
the net derivative asset was $4.9 million (December 31, 2007 - $10.5 million),
which is subject to market volatility of power prices, and will reverse over
the life of the agreement as it is realized. The agreement expires in 2021.

    Brunswick Pipeline

    Brunswick Pipeline was mechanically complete, and received National Energy
Board approval for shipping gas, in January 2009. This accommodates the needs
of the customer, Repsol, and the timing of completing the Canaport(TM) LNG
terminal, expected in Q2 2009. Capital costs of Brunswick Pipeline are
expected to be $465 million plus additional AFUDC and operating expenses
capitalized as a result of the delay in receiving gas from the Canaport(TM)
LNG terminal. Revenue from the customer will begin when the terminal is
operational, but no later than September 2009.

    M&NP Equity Earnings

    Equity earnings for M&NP were $4.6 million in Q4 2008 compared to $2.6
million in Q4 2007. The increase in earnings was a result of proceeds related
to a settlement agreement between M&NP and EnCana Marketing (USA) Inc.
("EnCana"), a reduction in interest expense related to the US portion of the
pipeline, and a weaker Canadian dollar. In late 2007, M&NP and EnCana entered
into an agreement whereby M&NP would expand its facilities on the US portion
of the pipeline and M&NP would provide firm transport service to EnCana. In
2008, EnCana terminated the agreement and a settlement agreement was reached
in Q4 2008. A portion of the settlement proceeds has been recognized in Q4
2008 with the remaining portion deferred until 2009.
    For the year ended December 31, 2008 M&NP equity earnings were $12.2
million compared to $10.6 million in 2007 due to the reasons noted above.
    For the year ended December 31, 2007 M&NP equity earnings were $10.6
million compared to $4.9 million in 2006 primarily due to expansion costs that
were expensed throughout 2006 and then capitalized in Q1 2007. During Q2 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
northeastern United States. 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 expansion facilities was $21 million
USD.
    During Q3 2008, M&NP repaid its outstanding debt related to the US portion
of the pipeline through equity contributions from the partners, which M&NP
will return to the partners once new financing is in place. The Company's
portion of the equity contribution was $46.5 million USD ($47.0 million CAD).
M&NP is expected to issue long-term debt in 2009, subject to capital market
conditions.

    Income Taxes

    All businesses included in Other follow the future income taxes method of
accounting for income taxes, excluding Brunswick Pipeline which uses the
taxes-payable method as allowed for ratemaking purposes. Taxes are recognized
on pre-tax income, excluding M&NP, Lucelec and GBPC equity earnings that are
recorded net of tax. Variations in income tax expense are largely affected by
earnings and foreign exchange fluctuations, along with changes in the
statutory tax rate.

    Outlook

    Net earnings for 2009, after adjusting for the mark-to-market effect of
the commodity price position in Bear Swamp, will increase over 2008 due to the
Brunswick Pipeline being mechanically complete and ready for gas
transportation in January 2009.

    Debt Management

    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
    Bridge credit facility                       June 20, 2009        $200.0
    -------------------------------------------------------------------------

    During Q4 2008, Emera entered into a $200 million non-revolving bridge
credit facility ("bridge facility"), maturing June 30, 2009. The amount of the
bridge facility is required to be reduced by the proceeds of any debt or
equity issuance by Emera.
    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 its joint venture partner.
    On a consolidated basis, Emera's target percentage of debt to total
capitalization is 50%-55%. The company manages long-term debt terms such that
the average is not less than ten years.
    The credit ratings issued by Dominion Bond Rating Service, Standard &
Poor's, and Moody's Investor Services are unchanged from 2007 and are as
follows:

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

    In November 2008, Standard & Poor's ("S&P") rating agency revised the
corporate and senior unsecured debt rating outlook of Emera to Positive from
Stable.
    In August 2008, Moody's Investors Service confirmed the credit ratings of
Emera and revised the rating outlook from negative to stable. The revision
reflects Moody's view that NSPI has been successful in improving its
relationships with key stakeholders and the UARB. Moody's also expects that
NSPI's exposure to regulatory risk will be reduced and that there is less
likelihood of variability in NSPI's financial results following implementation
of the FAM.

    CONSOLIDATED BALANCE SHEETS

    Significant changes in the consolidated balance sheets between December
31, 2008 and December 31, 2007 include:

                          Increase
    millions of dollars  (Decrease)  Explanation
    -------------------------------------------------------------------------
    Assets
    Cash                    $(14.2)  See consolidated cash flow highlights
                                      section.
    Accounts receivable       65.8   Lower accounts receivable securitized,
                                      increased posted margin to
                                      counterparties, and the effect of the
                                      weaker Canadian dollar.
    Inventory                 31.5   Increased coal volumes and commodity
                                      prices.
    Derivatives in a         141.9   Favourable USD price positions partially
     valid hedging                    offset by unfavourable commodity price
     relationship                     positions. The effective portion of the
     (including long-term             change is recognized in accumulated
     portion)                         other comprehensive income.
    Long-term receivable      48.7   Increased receivable from a natural gas
                                      supplier.
    Goodwill                  19.2   Weaker Canadian dollar.
    Investments subject      193.1   Additional investment in MN&P, indirect
     to significant                   investment in GBPC through the
     influence                        investment in ICDU, and equity
                                      earnings. The non-controlling interest
                                      in ICDU is reflected in non-controlling
                                      interest below.
    Available-for-sale        14.4   Investment in OpenHydro.
     investments
    Property, plant &        547.0   Capital spending in Brunswick Pipeline,
     equipment and                    NSPI and BHE, along with the effect of
     construction work                the weaker Canadian dollar.
     in progress
    -------------------------------------------------------------------------
    Liabilities and
     Shareholders' Equity
    Accounts payable          24.4   Timing of payments.
    Derivatives in a          92.6   Unfavourable commodity price positions
     valid hedging                    partially offset by favourable USD
     relationship                     price positions. The effective portion
     (including long-term             of the change is recognized in
     portion)                         accumulated other comprehensive income.
    Held-for-trading          23.0   Unfavourable commodity price positions.
     derivatives                      The portion related to NSPI's
     (including long-term             regulatory liabilities is recognized in
     portion)                         other assets.
    Future income tax         25.4   Increased timing differences relating to
     liabilities                      depreciable assets.
    Other liabilities         25.9   Increased NSPI regulatory liability
                                      related to held-for-trading contracts,
                                      and the effect of the weaker Canadian
                                      dollar.
    Short-term debt and      622.7   Increased short-term debt to finance
     long-term debt                   Brunswick Pipeline, increased posted
     (including current               margin and the effect of the weaker
     portion)                         Canadian dollar.
    Non-controlling           39.0   Investment in ICDU.
     interest
    Common shares             15.2   Shares issued under purchase plans and
                                      stock options exercised.
    Accumulated other        139.8   Primarily represents the favourable
     comprehensive income             effect of the Canadian dollar on the
                                      company's investment in Bangor Hydro,
                                      and changes in USD and commodity price
                                      hedge positions.
    Retained earnings         31.0   Net earnings in excess of dividends
                                      paid.
    -------------------------------------------------------------------------


    OUTSTANDING SHARE DATA
                                                                Common Share
                                                                     Capital
                                                   Millions of   millions of
    Issued and Outstanding:                             Shares       dollars
    -------------------------------------------------------------------------
    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
    Issued for cash under purchase plans                  0.39           8.0
    Options exercised under senior management
     share option plan                                    0.35           6.4
    Share-based compensation                                 -           0.8
    -------------------------------------------------------------------------
    December 31, 2008                                   112.21      $1,081.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at January 30, 2009 the number of issued and outstanding common shares 
was 112.25 million.


    LIQUIDITY AND CAPITAL RE

SOURCES The company generates cash primarily through its operations in regulated utilities involving the generation, transmission and distribution of electricity. NSPI's and BHE's customer bases are diversified by both sales volume and revenues among residential, commercial, industrial and other. Circumstances that could affect the company's ability to generate cash include fuel commodity price changes, general economic downturns in Nova Scotia and Maine, the loss of one or more large customers, and regulatory decisions affecting customer rates. The UARB approved a FAM that reduces NSPI's exposure to fuel price volatility effective January 1, 2009, providing a mechanism for NSPI to recover these fuel costs beginning in 2010. In addition to internally generated funds, Emera Inc. and NSPI have in aggregate access to $1.1 billion committed syndicated revolving bank lines of credit, of which $375 million is undrawn and available as at December 31, 2008. Emera Inc. has access to $600 million of this facility and NSPI has access to $500 million. NSPI has an active commercial paper program for up to $400 million, of which outstanding amounts are 100% backed by the bank lines referred to above and this results in an equal amount of that credit being considered drawn. Emera's and NSPI's revolving bank lines have a maturity date in June 2009 which can be extended annually for an additional 364 days with the approval of the syndicated banks. At each maturity date Emera and NSPI have the option to convert all amounts drawn on the bank credit line to a one year non-revolving term credit. In October 2008, the company negotiated an additional $200 million in a committed non-revolving bank line of credit as a bridge facility for Brunswick Pipeline. As at December 31, 2008, $66 million is undrawn and available. This non-revolving bank line matures in June 2009. The company intends to finance Brunswick Pipeline with a longer term debt facility in 2009. BHE has a $60 million USD revolving bank line of which $12 million USD was undrawn and available as at December 31, 2008. This facility matures in June 2010. NSPI expects to have access to capital markets to enable it to refinance the $125 million Series C preferred shares and the $125 million long-term note maturing in June, while maintaining sufficient levels of operating liquidity in 2009. In December 2008, NSPI completed a $150 million medium-term note issue, proceeds of which were used to pay down outstanding commercial paper debt. In January 2009, NSPI completed a $50 million medium-term note issue, which was also used to pay down outstanding short-term debt; these proceeds increased the $375 million in available credit referenced previously to $425 million. As at December 31, 2008, Emera and Nova Scotia Power had debt shelf prospectuses in the amounts of $400 million and $250 million respectively. Subsequent to the January 2009 $50 million medium-term note issue, the Nova Scotia Power debt shelf prospectus is now $200 million. As at December 31, 2008 Credit Line Undrawn and millions of dollars Committed Utilized Available ------------------------------------------------------------------------- Nova Scotia Power $500 $171 $329 Emera 600 554 46 Emera bridge facility 200 134 66 Bangor Hydro - in USD 60 48 12 ------------------------------------------------------------------------- NSPI issues commercial paper, 100% backed by a syndicated bank line of credit, to finance short-term cash requirements and has accessed the market as required despite liquidity and pricing pressures arising as a result of the disruption to capital markets. On a few occasions market demand for NSPI's commercial paper was less than required and the company accessed its bank credit line. NSPI has an accounts receivable securitization program as described in the Off-Balance Sheet Arrangements section. NSPI temporarily suspended its accounts receivable securitization program in January 2008 due to a lack of investor interest. The program expires in May 2009 and NSPI's ability to sell its receivables is subject to acceptance by the sponsor bank to buy the receivables. The company does not expect to use this facility in 2009. The company refinanced this $25 million debt through its commercial paper program. North American financial markets experienced significant volatility beginning in 2007 and continuing throughout 2008 due to concerns related to the state of both the global debt market and economy. In the past, the company has been able to access capital markets. Given the current state of North American financial markets, we expect that access to capital markets will continue to be available to the company although possibly at a higher cost. NSPI and BHE are each capable of paying dividends to Emera provided they do not breach their debt to capitalization ratios after giving effect to the dividend payment. 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. Pension Funding Emera has defined pension plans which, similar to most North American pension plans, had negative asset returns during 2008. Consistent with Canadian GAAP and Emera's accounting policy, the company amortizes the net actuarial gain or loss, which exceeds 10% of the greater of the accrued benefit obligation ("ABO") and the market-related value of assets, over active plan members' average remaining service period, which is currently 10 years. Any required amortization of 2008 investment losses in 2009 will be offset by Emera's use of smoothed asset values rather than market values for accounting purposes; and amortization of gains due to a lower ABO measured at December 31, 2008 as a result of a higher discount rate at year end. Emera's selection of the discount rate is in accordance with Canadian GAAP. The net result is that the 2009 pension cost is expected to be lower than 2008 pension cost. The 2008 asset loss will increase Emera's cash contribution to the pension plan. The increased cash requirements in 2009 will be approximately $14 million higher than 2008. This is projected to increase by another $15 million - $20 million in 2010. All pension plan contributions are tax deductible and will be funded with cash from operations. Emera's pension plan is managed with a diversified portfolio of asset classes, investment managers and geographic investments. Emera does not expect to make any changes to the management of its plan as a result of the market performance in 2008. Consolidated Cash Flow Highlights Significant changes in the consolidated cash flow statements between December 31, 2008 and December 31, 2007 include: Three months ended December 31 millions of dollars 2008 2007 Explanation ------------------------------------------------------------------------- Cash and cash $28.5 $8.6 equivalents, beginning of period Provided by (used in): Operating activities (17.1) 207.8 In 2008, increased non-cash working capital partially offset by cash earnings. In 2007, cash earnings and decreased non-cash working capital due to settlement of a receivable from a natural gas supplier in NSPI. Investing activities (146.7) (83.3) In 2008, capital spending, including Brunswick Pipeline, and an additional investment in M&NP. In 2007, capital spending, including NRI project and Brunswick Pipeline projects. Financing activities 147.5 (106.7) In 2008, increased debt levels, partially offset by dividends on common shares. In 2007, reduced debt levels and dividends on common shares. ------------------------------------------------------------------------- Cash and cash $12.2 $26.4 equivalents, end of year ------------------------------------------------------------------------- ------------------------------------------------------------------------- Year ended December 31 millions of dollars 2008 2007 Explanation ------------------------------------------------------------------------- Cash and cash $26.4 $19.5 equivalents, beginning of period Provided by (used in): Operating activities 237.2 351.4 In 2008, cash earnings partially offset by increased non-cash working capital. In 2007, cash earnings partially offset by increased non-cash working capital. Investing activities (671.6) (288.9) In 2008, capital spending in Brunswick Pipeline, NSPI, and BHE, and acquisition of a 7.35% interest in OpenHydro and a 50% interest in ICDU. In 2007, capital spending, including the NRI transmission line and Brunswick Pipeline projects, and acquisition of a 19% interest in Lucelec. Financing activities 420.2 (55.6) In 2008, increased debt levels, partially offset by dividends on common shares and decreased accounts receivable securitized. In 2007, dividends on common shares and decreased accounts receivable securitized, partially offset by increased debt levels. ------------------------------------------------------------------------- Cash and cash $12.2 $26.4 equivalents, end of year ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contractual Obligations The consolidated contractual obligations over the next five years and thereafter include: millions of dollars Payments Due by Period Total 2009 2010 2011 ------------------------------------------------------------------------- Long-term debt $2,304.6 $774.7 $106.3 $6.0 Preferred shares issued by subsidiary 260.0 125.0 - - Operating leases 24.5 10.0 10.0 1.5 Purchase obligations 2,419.1 317.8 243.9 207.5 Other long-term obligations 321.0 2.1 1.5 2.2 ------------------------------------------------------------------------- Total contractual obligations $5,329.2 $1,229.6 $361.7 $217.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- millions of dollars Payments Due by Period 2012 2013 After 2013 ------------------------------------------------------------------------- Long-term debt $106.8 $255.5 $1,055.3 Preferred shares issued by subsidiary - - 135.0 Operating leases 0.4 0.4 2.2 Purchase obligations 154.1 106.3 1,389.5 Other long-term obligations 2.1 41.9 271.2 ------------------------------------------------------------------------- Total contractual obligations $263.4 $404.1 $2,853.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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, outsourced management of the company's computer infrastructure, natural gas, transportation capacity on the Maritimes & Northeast Pipeline, fuel, and construction costs on the 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, including AFUDC, were approximately $590 million for 2008 and included: - $167 million in Nova Scotia Power; - $44 million in Bangor Hydro; and - $375 million in Brunswick Pipeline. Outlook Emera's capital budget for 2009 includes approximately $220 million for NSPI, which is generally directed toward customer growth and system reliability, planned and preventative maintenance, productivity-related investments, air emissions upgrades and a new corporate office. BHE expects to invest approximately $54 million USD, including approximately $32 million USD for major transmission projects. Brunswick Pipeline expects to invest approximately $60 million plus additional AFUDC and operating expenses capitalized. The company expects to finance its capital expenditures with funds from operations and debt. Off-Balance Sheet Arrangements Upon privatization of the former provincially owned Nova Scotia Power Corporation ("NSPC") in 1992, NSPI became responsible for managing a portfolio of defeasance securities, which as at December 31, 2008 totaled $1.1 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 NSPC debt. Approximately 73% 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 at the sole discretion of the Trust on a revolving non-recourse basis. As of December 31, 2008, there were no accounts receivable sold to the Trust (2007 - $25.0 million). The agreement is in place until May 2009 and NSPI's ability to sell its receivables is subject to acceptance by the sponsor bank to buy the receivables. Securitization has provided NSPI with an alternative source of short-term funding. The securitization program was temporarily suspended in January 2008 due to a lack of investor interest. For the year ended December 31, 2007, the average all-in cost of this funding was 4.91%. In the event of termination of this arrangement, NSPI would utilize another credit facility to meet the ongoing operations of the business. 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 coal, 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. The company recognizes 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, for cash flow hedges, the effective portion of the change in 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 change in the fair value of derivatives is recognized in net earnings in the reporting period. The total ineffectiveness recognized by the company was a $0.8 million gain in Q4 2008 and a $0.2 million gain for the year ended December 31, 2008. Where the documentation or effectiveness requirements of hedge accounting are not met, the change in the fair value of the derivatives is recognized in earnings in the reporting period. The company also recognizes the change in 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. Hedging Items Recognized on the Balance Sheet The company has the following categories on the balance sheet related to derivatives in valid hedging relationships: millions of dollars ------------------------------------------------------------------------- December 31 December 31 2008 2007 ------------------------------------------------------------------------- Inventory $(7.1) $7.6 Derivatives in a valid hedging relationship (4.7) (54.0) Long-term debt 0.4 0.6 ------------------------------------------------------------------------- $(11.4) $(45.8) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Hedging Impact Recognized in Earnings 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: Three months ended Year ended millions of dollars December 31 December 31 ------------------------------------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Financing charges decrease $1.5 - $1.5 - Fuel and purchased power decrease (increase) 10.9 $(4.3) 26.5 $(14.7) ------------------------------------------------------------------------- Hedging earnings impact $12.4 $(4.3) $28.0 $(14.7) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Held-for-trading Items Recognized on the Balance Sheet The company has recognized a net held-for-trading derivatives asset of $85.7 million as at December 31, 2008 (2007 - $110.7 million) on the balance sheet. Held-for-trading Derivatives Gains (Losses) Recognized in Earnings The company has recognized the following realized and unrealized gains and losses with respect to held-for-trading derivatives in earnings: Three months ended Year ended millions of dollars December 31 December 31 ------------------------------------------------------------------------- 2008 2007 2008 2007 ------------------------------------------------------------------------- Electric revenue $(2.2) $(1.5) - $(0.6) Other revenue (5.0) 6.2 $3.6 25.8 Fuel and purchased power (0.3) 1.0 (0.4) 0.5 Financing charges (0.1) 0.1 (0.5) 0.1 ------------------------------------------------------------------------- Held-for-trading derivatives (losses) gains $(7.6) $5.8 $2.7 $25.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 $7.0 million (2007 - $5.1 million) during the three months ended December 31, 2008, and $29.4 million (2007 - $25.4 million) during the year ended December 31, 2008, 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, 2008 the amount payable to the related party is $4.1 million (2007 - $4.5 million), is non-interest bearing and is under normal credit terms. Disclosure and Internal Controls Emera's management is responsible for establishing and maintaining disclosure controls and procedures ("DC&P") and internal control over financial reporting ("ICFR"), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or submitted under securities legislation. The President and Chief Executive Officer and the Chief Financial Officer have designed, with the assistance of company employees, DC&P and ICFR to provide reasonable assurance that material information is made known to them; is reported on a timely basis; financial reporting is reliable; and financial statements prepared for external purposes are in accordance with Canadian GAAP. The President and Chief Executive Officer and the Chief Financial Officer have evaluated, with the assistance of company employees, the effectiveness of Emera and its consolidated subsidiaries' DC&P and ICFR and based on that evaluation have concluded DC&P and ICFR were effective at December 31, 2008. There have been no changes in Emera or its consolidated subsidiaries' ICFR during the period beginning on January 1, 2008 and ended on December 31, 2008 that have materially affected, or are reasonably likely to materially affect ICFR. 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, long-term 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 the incurrence of specified expenses is based on the expectation that the regulators will approve the refund to or recovery from ratepayers of the deferred balance. Effective January 1, 2009 the Utility and Review Board has approved the implementation of a FAM. The difference between the costs included in rates and the actual costs of fuel will be deferred and refunded to or collected from customers in the subsequent year. If the regulators' future actions are different from the regulators' previous rulings, 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 5.75% for 2008 (2007 - 5.25%) and BHE's rate was 6.75% for 2008 (2007 - 6.00%). The expected return on plan assets is based on management's best estimate of future returns, considering economic and consensus forecasts. The benefit cost calculations assumed that plan assets would earn a rate of return of 7.5% for 2008 and 2007 for NSPI and 8.0% for 2008 and 2007 for BHE. The reported benefit cost for 2008, based on management's best estimate assumptions, is $34.5 million. While there are numerous assumptions which are used to determine the benefit cost, the discount rate and asset return assumptions have a significant impact on the calculations. The following shows the impact on 2008 benefit cost of a 25 basis point change (0.25%) in the discount rate and asset return assumptions: Increase Decrease millions of dollars 0.25% 0.25% ------------------------------------------------------------------------- Discount rate assumption $(3.5) $3.6 Asset return assumption $(1.7) $1.7 ------------------------------------------------------------------------- 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, 2008, unbilled revenues amount to $89.7 million (2007 - $86.0 million) on a base of annual electric revenues of approximately $1.3 billion (2007 - $1.3 billion). Long-Term 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 market 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, 2008, the asset retirement obligations recorded on the balance sheet were $88.0 million (2007 - $83.8 million). The company estimates the undiscounted amount of cash flow required to settle the obligations is approximately $314.2 million, which will be incurred between 2009 and 2061. The majority of these costs will be incurred between 2020 and 2039. Property, Plant and Equipment Property, plant and equipment represents 66% 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 in depreciation expense 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-two in rates. In its February 5, 2007 decision, the UARB postponed the phase-in of year-three rates until the next rate application. In its November 5, 2008 decision the UARB approved year-three phase-in effective January 1, 2009. 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 2008 or 2007. Changes in Accounting Policies The Canadian Institute of Chartered Accountants ("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 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 externally imposed capital requirements; and, if the company has not complied, the consequences of such non-compliance. The new accounting standard covers disclosure only and had no effect on the financial results of the company. Further information can be found in note 23 to the financial statements. 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 had no effect on the financial results of the company. Further information can be found in note 24 to the financial statements. 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 previously measured inventories at the lower of cost and market. The company uses the weighted average method to determine the cost of inventory. The company has applied the new standard retrospectively without restatement, which resulted in a decrease to inventory and retained earnings of $3.3 million as at January 1, 2008. The change in inventory is due to the following: Fuel inventory Materials inventory Year ended Year ended December 31 December 31 ------------------------------------------------------------------------- millions of dollars 2008 2007 2008 2007 ------------------------------------------------------------------------- Inventory, beginning of period $67.7 $81.2 $32.1 $32.4 Accounting policy change - - (3.3) - Purchases 359.7 313.5 38.7 39.0 Write-down of inventory to net realizable value - - (1.1) (0.7) Inventories expensed (325.7) (327.0) (16.3) (17.3) Inventories capitalized - - (22.5) (23.0) Other - - 1.9 1.6 ------------------------------------------------------------------------- Inventory, end of period $101.7 $67.7 $29.5 $32.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The company has not pledged inventory as security for liabilities. Future Accounting Policy Changes Goodwill and Intangible Assets In February 2008, the CICA issued Section 3064 Goodwill and Intangible Assets ("3064") applicable to Emera's 2009 fiscal year, replacing Section 3062 Goodwill and Other Intangible Assets. The goodwill requirements have not changed. The requirements for intangible assets now clarify that costs may only be deferred when they relate to an item that meets the definition of an asset. An intangible asset must be identifiable; be a resource over which the company has control; probably generate future economic benefits; and have a reliably measurable cost. The company is currently assessing the effect of 3064 on its financial statements but does not expect a material change. 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 expected to be included in future rates, with no resulting effect on net earnings. The company is still assessing the effect on its balance sheet. Financial Instruments In January 2009, the CICA issued Emerging Issue Committee Abstract of Issue Discussed 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities ("EIC-173") applicable to Emera's 2009 fiscal year. EIC-173 recommends that a company take into account its own credit risk and the credit risk of the counterparty in determining the fair value of financial assets and financial liabilities. The company is currently assessing the effect on its financial results. Changeover to International Financial Reporting Standards ("IFRS") In April 2008, the CICA issued an IFRS Omnibus Exposure Draft which proposes that publicly accountable enterprises be required to apply IFRS effective for Emera's interim and annual periods beginning January 1, 2011 with consistent comparative information required for 2010. The company is currently assessing the effect of IFRS on its accounting policies, information systems, internal controls, financial statements, and other business activities. Due to anticipated changes in IFRS during the transition period and up to January 1, 2011, and the uncertainty around the future of rate regulated accounting, the company is not in a position to determine the impact on its financial results at this time. In order to prepare for the transition, Emera has established a formal project and governance structure which includes a steering committee consisting of senior management from finance, information technology, and human resources. Quarterly updates are provided to the Audit Committee. Emera has engaged an external advisor to assist with the changeover to IFRS. The project consists of four phases including the initial assessment, detailed assessment, design, and testing and implementation. Emera has completed the initial assessment phase which included a review of the major differences between Canadian GAAP and IFRS. Although IFRS has a conceptual framework similar to Canadian GAAP there are areas that have a high potential impact to Emera including rate regulated accounting, property, plant and equipment, income taxes, and employee future benefits. In addition, there is significantly more disclosure required under IFRS. Emera will also be affected by the provisions of IFRS 1 First-Time Adoption of IFRS. Emera is now engaged in the detailed assessment phase. Working groups were formed by topical area and are focused on identifying accounting differences between Canadian GAAP and IFRS on a detailed basis. The detailed assessment phase and the design phase, which include designing business process changes and providing training to employees, are expected to be completed in 2009. The testing and implementation phase will take place during late 2009 to January 1, 2011. The roll-out of IFRS and a parallel run of Canadian GAAP and IFRS will take place in 2010. Dividends and Payout Ratios The Board of Directors has approved two increases to the quarterly dividend in 2008. In January 2008, the Board of Directors approved a quarterly dividend increase to $0.2375 per common share, reflecting an increase on an annualized basis to $0.95 per common share. In October 2008, the Board of Directors approved a quarterly dividend increase to $0.2525 per common share, reflecting an increase on an annualized basis to $1.01 per common share. Emera Inc.'s common dividend rate was $0.97 ($0.2375 per quarter in Q1, Q2 and Q3; and $0.2525 in Q4) per common share in 2008 and $0.90 ($0.2225 per quarter in Q1 and Q2; and $0.2275 in Q3 and Q4) for 2007, representing a payout ratio of approximately 76% for 2008 and 66% for 2007. 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 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, interest rates, credit risk, and regulatory risk. In November 2008, the UARB approved the implementation of a FAM effective January 1, 2009. The FAM has been established to mitigate the effects of volatile fuel costs, including related foreign exchange risk, on the electricity rates paid by the customers of Nova Scotia Power. Customers will pay the actual fuel costs including foreign exchange gains and losses related to fuel, adjusted for the incentive mechanism in the FAM. The incentive is 10% of the first $50 million of fuel costs above or below the target, adjusted for load. 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 NSPI's coal and petroleum coke supply comes from international suppliers, which was contracted at or near the market prices prevailing at the time of contract. The company has entered into fixed-price and index price contractual arrangements with several suppliers as part of the fuel procurement portfolio strategy. All index priced contractual arrangements are matched with a corresponding financial instrument to fix the price. 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, 2008 is as follows: - 2009 - 91% - 2010 - 29% - 2011 - 19% - 2012 - 7% 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, 2008 is as follows: - 2009 - 100% - 2010 - 58% Natural Gas NSPI has entered into multi-year contracts to purchase approximately 65,600 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 hedged using financial instruments. As at December 31, 2008, amounts of natural gas volumes that have been economically and/or financially hedged and contracted are approximately as follows: - 2009 - 99% - 2010 - 67% 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. During 2007, NSPI began using a new domestic supplier in two of its coal plants, which provides additional pricing and geographical flexibility. Purchased Power Emera, along with its joint venture partner, has entered into a contract with Bear Swamp to provide the power necessary to produce the energy requirements of the LIPA contract. As at December 31, 2008, amounts of purchased power Emera has hedged are approximately as follows: - 2009 - 97% - 2010 - 100% - 2011 - 60% - 2012 - 10% - 2013 - 10% 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 2009, 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 and swap contracts to limit exposure on fuel purchases 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 $318.0 million are in place at a weighted average rate of $1.08, representing over 70% of 2009 anticipated USD requirements. Forward contracts to buy USD $602.5 million in 2010 through 2012 at a weighted average rate of $1.01 were in place at December 31, 2008 to manage exposure to 34% of anticipated USD requirements in these years. Emera uses foreign exchange forward contracts to hedge the currency risk for capital projects and receivables denominated in foreign currencies. Forward contracts to buy USD $7.8 million are in place at a weighted average rate of $0.99 for capital projects in 2009. Forward contracts to sell USD $39.0 million are in place at a weighted average rate of $1.25 to hedge a portion of receivables in 2010. Emera uses forward contracts to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts to sell USD $46.0 million are in place in 2009 and 2010 at a weighted average rate of $1.25. Option contracts, to eliminate exposure to currency rate fluctuations for 2009, of $0.5 million at a rate of $1.26 were outstanding on December 31, 2008. Interest Rates Emera manages interest rate risk through a combination of fixed and floating borrowing and a hedging program. Floating-rate debt is estimated to represent approximately 24% of total debt in 2009. The company has no interest rate hedging contracts outstanding as of December 31, 2008. 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. A central outcome of the 2009 rate decision will help to reduce that risk. NSPI and formal Intervenors agreed that the UARB should implement a FAM for Nova Scotia Power effective January 1, 2009 to ensure fuel costs are recovered from customers. In November 2008 the UARB issued a decision that approves the implementation of the FAM, effective January 1, 2009 with the first rate adjustment under the FAM occurring on January 1, 2010. The UARB will oversee the FAM, 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 ROE range is reduced by 0.2%, changing its ROE range to 9.1% to 9.6%, with rates set at 9.35%. 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 operates under a traditional cost-of-service regulatory structure. Until December 31, 2007, BHE operated under an Alternate Rate Plan which governed distribution rates. In late 2007 the MPUC approved a modest increase in distribution rates under the 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 purchasing power at above-market prices. This ability eliminates the commodity risk involved with fixed price purchase power contracts. 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 Nova Scotia Power has a contract with its union which will expire in 2012 and Bangor Hydro has a contract with its union which will expire in 2010. 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 2008 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 2008 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 of 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 stabilized greenhouse gas emissions. This has been achieved by energy efficiency and conservation programs, increased use of natural gas, improved efficiency of converting natural gas to electricity and adding and contracting for new renewable energy sources to the generation portfolio. 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. Within this act there is an objective to reduce provincial greenhouse gas emissions to 10 percent below 1990 levels by 2020. In January 2009, the province released their 2009 Energy Strategy and Climate Change Action Plan. These documents provide the elements of the plan to achieve this objective. As described in the plan, greenhouse gas emissions from NSPI will be capped beginning in 2010 through to 2020. The province is developing regulations in line with the plan, which will provide details on the caps. It is anticipated that the 2010 cap will be achieved by continuing success of energy efficiency and conservation programs and the addition of renewable energy to meet the 2010 provincial renewable energy standards. In 2008, NSPI signed power purchase agreements for 246MW of new wind energy sources with seven independent power producers. These power purchase agreements call for those facilities to reach commercial operation between 2009 and 2010. Further it is anticipated that the 2013 - 2015 caps will be achieved by flattening load growth through aggressive energy efficiency and conservation programs and adding renewable energy to meet the provincial 2013 renewable energy standards. NSPI has also piloted co-firing of local biomass, which is a carbon neutral fuel, in the coal fired power plants. Beyond 2015, reduced greenhouse gas emissions will be achieved through a combination of additional renewable energy, co-firing of biomass in existing coal power plants, import of non-emitting energy and energy efficiency and conservation. The federal government has not formalized any greenhouse gas emission reduction regulations. NSPI continues to provide input to the federal government as they proceed with their consultations. In 2008, NSPI carried out extensive testing on mercury abatement technology in the coal power plants. A capital program has been established to add sorbent injection to each of the seven pulverized fuel coal units in 2009. This will allow NSPI to meet the mercury emission cap of 65 kg established by the province for 2010. NSPI has completed its capital program of retrofitting low nitrogen oxide combustion firing systems of six of its seven pulverized fuel coal units. NSPI now meets the nitrogen oxide emission cap of 21,365 tonnes per year established by the province for 2009. NSPI continues to meet its emission cap on sulphur dioxide emissions by the use of compliant fuel. Compared to historical levels, NSPI will have reduced sulphur dioxide by 50% for 2010, nitrogen oxide by 40% for 2009 and mercury emissions by 60% for 2010. Summary of Quarterly Reports For the quarter ended millions of dollars (except earnings per common share) ------------------------------------------------------------------------- Q4 Q3 Q2 Q1 2008 2008 2008 2008 ------------------------------------------------------------------------- Total revenues $337.3 $295.8 $317.6 $381.2 ------------------------------------------------------------------------- Net earnings applicable to common shares 25.3 6.5 42.9 69.4 ------------------------------------------------------------------------- Earnings per common share - basic 0.23 0.05 0.39 0.62 ------------------------------------------------------------------------- Earnings per common share - diluted 0.22 0.05 0.37 0.58 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Q4 Q3 Q2 Q1 2007 2007 2007 2007 ------------------------------------------------------------------------- Total revenues $343.9 $310.3 $325.4 $359.9 ------------------------------------------------------------------------- Net earnings applicable to common shares 36.6 40.9 34.1 39.7 ------------------------------------------------------------------------- Earnings per common share - basic 0.33 0.37 0.30 0.36 ------------------------------------------------------------------------- Earnings per common share - diluted 0.32 0.35 0.30 0.35 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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" or "the Company") 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 13, 2009 "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, 2008 and 2007 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 consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and 2007 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 12, 2009 "Ernst & Young LLP" Chartered Accountants Emera Inc. Consolidated Statements of Earnings Year Ended December 31 millions of dollars (except earnings per common share) 2008 2007 ------------------------------------------------------------------------- Revenue Electric $1,280.8 $1,269.5 Other 51.1 70.0 ------------------------------------------------------------------------- 1,331.9 1,339.5 ------------------------------------------------------------------------- Cost of operations Fuel for generation and purchased power 525.1 494.5 Operating, maintenance and general 266.8 264.8 Provincial, state, and municipal taxes 49.4 47.5 Depreciation 151.3 149.3 Regulatory amortization 28.5 31.4 ------------------------------------------------------------------------- 1,021.1 987.5 ------------------------------------------------------------------------- 310.8 352.0 Equity earnings (note 6) 15.2 12.8 Financing charges (note 7) 123.2 133.2 ------------------------------------------------------------------------- Earnings before income taxes 202.8 231.6 Income taxes (note 8) 58.1 80.3 ------------------------------------------------------------------------- Net earnings 144.7 151.3 Non-controlling interest (note 14) 0.6 - ------------------------------------------------------------------------- Net earnings applicable to common shares $144.1 $151.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per common share - basic (note 10) $1.29 $1.36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per common share - diluted (note 10) $1.26 $1.32 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Emera Inc. Consolidated Balance Sheets As at December 31 millions of dollars 2008 2007 ------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents $12.2 $26.4 Restricted cash 0.8 1.0 Accounts receivable (note 11) 385.1 319.3 Income tax receivable 15.7 13.7 Inventory (note 2) 131.2 99.7 Prepaid expenses 8.3 11.8 Future income tax assets (note 8) 7.1 6.7 Derivatives in a valid hedging relationship 48.4 12.2 Held-for-trading derivatives 73.0 76.2 ------------------------------------------------------------------------- 681.8 567.0 ------------------------------------------------------------------------- Long-term receivable (note 11) 56.4 7.7 ------------------------------------------------------------------------- Derivatives in a valid hedging relationship 116.7 11.0 ------------------------------------------------------------------------- Held-for-trading derivatives 64.8 63.6 ------------------------------------------------------------------------- Other assets (note 12) 420.1 417.3 ------------------------------------------------------------------------- Future income tax assets (note 8) 17.6 16.2 ------------------------------------------------------------------------- Goodwill (note 16) 102.0 82.8 ------------------------------------------------------------------------- Investments subject to significant influence (note 6) 317.6 124.5 ------------------------------------------------------------------------- Available for sale investments 16.2 1.8 ------------------------------------------------------------------------- Property, plant & equipment (note 13) 2,961.9 2,820.0 Construction work in progress 514.3 109.2 ------------------------------------------------------------------------- 3,476.2 2,929.2 ------------------------------------------------------------------------- $5,269.4 $4,221.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Shareholders' Equity Current liabilities Current portion of long-term debt (note 19) $131.4 $121.0 Current portion of preferred shares issued by subsidiary (note 9) 125.0 - Short-term debt (note 18) 157.9 28.4 Accounts payable and accrued charges 307.1 282.7 Income tax payable 7.9 3.2 Dividends payable 3.2 3.2 Future income tax liabilities (note 8) - 2.0 Derivatives in a valid hedging relationship 109.8 44.1 Held-for-trading derivatives 37.8 22.0 ------------------------------------------------------------------------- 880.1 506.6 ------------------------------------------------------------------------- Derivatives in a valid hedging relationship 60.0 33.1 ------------------------------------------------------------------------- Held-for-trading derivatives 14.3 7.1 ------------------------------------------------------------------------- Future income tax liabilities (note 8) 110.3 82.9 ------------------------------------------------------------------------- Asset retirement obligations (note 17) 88.0 83.8 ------------------------------------------------------------------------- Other liabilities (note 12) 236.7 210.8 ------------------------------------------------------------------------- Long-term debt (note 19) 2,159.2 1,676.4 ------------------------------------------------------------------------- Preferred shares issued by subsidiary (note 9) 135.0 260.0 ------------------------------------------------------------------------- Non-controlling interest (note 14) 39.6 0.6 ------------------------------------------------------------------------- Shareholders' equity Common shares (note 20) 1,081.4 1,066.2 Contributed surplus 3.4 3.0 Accumulated other comprehensive income (69.2) (209.0) Retained earnings (note 2) 530.6 499.6 ------------------------------------------------------------------------- 1,546.2 1,359.8 ------------------------------------------------------------------------- $5,269.4 $4,221.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Contingencies (note 25), Commitments (notes 5, 23 and 26), Guarantees (note 27), Subsequent Event (note 28) 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 2008 2007 ------------------------------------------------------------------------- Operating activities Net earnings applicable to common shares $144.1 $151.3 Non-cash items: Depreciation 151.3 149.3 Amortization of other assets 13.7 14.1 Equity earnings (15.2) (12.8) Regulatory amortization 28.5 31.4 Allowance for funds used during construction (21.7) (12.3) Future income taxes 4.3 13.2 Post-retirement benefits 12.5 15.2 Non-controlling interest 0.6 - Reduction in regulatory asset (note 8) - 16.4 Other non-cash operating items (7.1) (0.1) Other cash operating items 6.5 4.6 ------------------------------------------------------------------------- 317.5 358.7 Change in non-cash operating working capital (note 21) (80.3) (7.3) ------------------------------------------------------------------------- Net cash provided by operating activities 237.2 351.4 ------------------------------------------------------------------------- Investing activities Property, plant and equipment (545.8) (251.6) Decrease (increase) in restricted cash 0.2 (1.0) Retirement spending net of salvage (5.7) (5.0) Acquisitions (note 14) (60.7) (25.7) Investments (59.6) (5.6) ------------------------------------------------------------------------- Net cash used in investing activities (671.6) (288.9) ------------------------------------------------------------------------- Financing activities Retirements of long-term debt (120.8) (2.8) Issuance of long-term debt 150.0 117.1 Increase (decrease) in short-term debt 519.5 (22.2) Issuance of common shares 14.4 10.7 Dividends on common shares (107.9) (99.9) Dividends paid by subsidiaries to non- controlling interest (1.9) - Accounts receivable securitization (25.0) (55.0) Other financing activities (8.1) (3.5) ------------------------------------------------------------------------- Net cash provided by (used in) financing activities 420.2 (55.6) ------------------------------------------------------------------------- (Decrease) increase in cash and cash equivalents (14.2) 6.9 Cash and cash equivalents, beginning of year 26.4 19.5 ------------------------------------------------------------------------- Cash and cash equivalents, end of year $12.2 $26.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash and cash equivalents consists of: Cash $5.0 $5.4 Short-term investments 7.2 21.0 ------------------------------------------------------------------------- Cash and cash equivalents, end of year $12.2 $26.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplemental disclosure of cash paid: Interest $131.5 $119.1 Income and capital taxes $62.1 $108.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Emera Inc. Consolidated Statements of Changes in Shareholders' Equity ------------------------------------------------------------------------- For the year ended Accumula- December 31, 2008 ted Other millions of dollars Comprehen- Total Contribu- sive AOCI and Common ted Income Retained Retained Shares Surplus ("AOCI") Earnings Earnings ------------------------------------------------------------------------- Balance, December 31, 2007 $1,066.2 $3.0 $(209.0) $499.6 $290.6 ------------------------------------------------------------------------- Accounting policy change (note 2) - - - (3.3) (3.3) ------------------------------------------------------------------------- Comprehensive Income: Net earnings applicable to common shares - - - 144.1 144.1 Net gain on derivatives in a valid hedging relationship - - 83.1 - 83.1 Reclassification of hedging gains included in income - - (28.9) - (28.9) Reclassification of hedging gains included in inventory - - (14.7) - (14.7) Reclassification of hedging gains included in construction work in progress - - (0.5) - (0.5) Unrealized gain on translation of self- sustaining foreign operations - - 102.1 - 102.1 Other - - (1.3) - (1.3) ------------------------------------------------------------------------- Total comprehensive income - - 139.8 144.1 283.9 ------------------------------------------------------------------------- Dividends declared on common shares - - - (107.9) (107.9) Dividends paid by subsidiaries to non- controlling interest - - - (1.9) (1.9) Common shares issued under purchase plans 8.0 - - - - Senior management stock options exercised 6.4 (0.5) - - - Stock option expense - 0.9 - - - Other share-based compensation 0.8 - - - - ------------------------------------------------------------------------- Balance, December 31, 2008 $1,081.4 $3.4 $(69.2) $530.6 $461.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the year ended Total December 31, 2007 Contribu- AOCI and millions of dollars Common ted Retained Retained Shares Surplus AOCI Earnings Earnings ------------------------------------------------------------------------- Balance, December 31, 2006 $1,055.2 $2.2 $(100.2) $450.9 $350.7 ------------------------------------------------------------------------- Accounting policy change - - (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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to the consolidated financial statements. Emera Inc. Notes to the Consolidated Financial Statements December 31, 2008 and 2007 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Emera Inc., 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 for 2008 is 9.3% to 9.8%, on a maximum allowed common equity component of 40% of the total capitalization. Rates were set for 2009 using 9.35% 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 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 60% of BHE's electric rates represent distribution services, 20% relate to stranded costs recoveries, and 20% 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"). BHE operates under a traditional cost-of-service regulatory structure. In December 2007, the MPUC approved an increase of approximately 2% in distribution rates effective January 1, 2008. The allowed ROE used in setting the new distribution rates is 10.2%, with a common equity component of 50%. Until December 31, 2007, BHE's distribution services operated under an Alternate Rate Plan ("ARP"), which provided for an ROE of 5% to 17% 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. Beginning January 1, 2008, the earnings band and associated sharing mechanism, performance standard, and annual distribution rate reductions were no longer applicable. BHE's stranded cost rates provide for an allowed ROE 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 39% 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 11.14% for low voltage transmission up to 12.64% for high voltage transmission developed as a result of the regional system plan, which includes the NRI transmission line. Bangor Hydro's accounting policies are subject to examination and approval by FERC and the MPUC. Brunswick Pipeline is a pipeline which 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 northeastern United States. The pipeline was mechanically complete, and received National Energy Board approval for shipping gas, in January 2009. 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 an other liability. 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 the absence of rate regulation would have on electric revenue. 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 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. 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 12. 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 12. The UARB agreed to allow NSPI to defer demand side management program expenses for the period January 1, 2008 until December 31, 2009. The UARB approved recovery of this regulatory asset over six years commencing January 1, 2009. In the absence of UARB approved deferral, 2008 expenses incurred would have been expensed in 2008. More details are provided in note 12. 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 other assets and other liabilities and include costs related to restructuring of 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 12. 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 5 years (2007 - 8 years). Unregulated generation assets have an estimated average service life of 38 years (2007 - 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. In its November 5, 2008 decision, the UARB approved the year-three phase-in effective January 1, 2009. 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 2008 2007 ------------------------------------------------------------------------- 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% 7.12% General plant under capital lease 10.95% - Weighted average depreciation rate 3.05% 3.07% ------------------------------------------------------------------------- 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 2008 2007 ------------------------------------------------------------------------- Transmission 50 46 Distribution 36 36 Other 15 15 Weighted average service life 38 36 ------------------------------------------------------------------------- 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, 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, 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 8. 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 nine years as at December 31, 2008 (2007 - 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 11 years as at December 31, 2008 (2007 - 12 years). For Emera Inc., the ARSP of the active employees is 12 years as at December 31, 2008 (2007 - 12 years). 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 an other asset or liability 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 0.32% at December 31, 2008 (2007 - 3.73%). m. Inventory Inventories are measured at the lower of cost and net realizable value. The Company uses the weighted average method to determine the cost of inventory. 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. The Company recognizes the fair value of all its derivatives that are not designated as contracts held for normal purchase or sale on its balance sheet. 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. For fair value hedges, the change in fair value of the hedging derivatives and the hedged item are recorded in net earnings. Any ineffective portion of the change in fair value 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, unless alternative treatment is available as approved by the UARB. 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 the 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 12. 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, Grand Bahama Power Corporation, 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 Canadian Institute of Chartered Accountants ("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 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 externally imposed capital requirements; and, if the Company has not complied, the consequences of such non-compliance. The new accounting standard covers disclosure only and had no effect on the financial results of the Company. Further information can be found in note 22. 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 had no effect on the financial results of the Company. Further information can be found in note 23. 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 previously measured inventories at the lower of cost and market. The Company uses the weighted average method to determine the cost of inventory. The Company has applied the new standard retrospectively without restatement, which resulted in a decrease to inventory and retained earnings of $3.3 million as at January 1, 2008. The change in inventory is due to the following: Fuel inventory Materials inventory Year ended Year ended For the December 31 December 31 ------------------------------------------------------------------------- millions of dollars 2008 2007 2008 2007 ------------------------------------------------------------------------- Inventory, beginning of period $67.7 $81.2 $32.1 $32.4 Accounting policy change - - (3.3) - Purchases 359.7 313.5 38.7 39.0 Write-down of inventory to net realizable value - - (1.1) (0.7) Inventories expensed (325.7) (327.0) (16.3) (17.3) Inventories capitalized - - (22.5) (23.0) Other - - 1.9 1.6 ------------------------------------------------------------------------- Inventory, end of period $101.7 $67.7 $29.5 $32.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company has not pledged inventory as security for liabilities. Future Accounting Policy Changes Changeover to International Financial Reporting Standards ("IFRS"): In April 2008, the CICA issued an IFRS Omnibus Exposure Draft which proposes that publicly accountable enterprises be required to apply IFRS effective for Emera's 2011 fiscal year with consistent comparative information required for 2010. The Company is currently assessing the effect of IFRS on its financial statements and developing its changeover plan. Goodwill and Intangible Assets: In February 2008, the CICA issued Section 3064 Goodwill and Intangible Assets ("3064") applicable to Emera's 2009 fiscal year, replacing Section 3062 Goodwill and Other Intangible Assets. The goodwill requirements have not changed. The requirements for intangible assets now clarify that costs may only be deferred when they relate to an item that meets the definition of an asset. An intangible asset must be identifiable; be a resource over which the Company has control; probably generate future economic benefits; and have a reliably measurable cost. The Company is currently assessing the effect of 3064 on its financial statements but does not expect a material change. 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 expected to be included in future rates, with no resulting effect on net earnings. The Company is currently assessing the effect on its balance sheet. Financial Instruments: In January 2009, the CICA issued Emerging Issue Committee Abstract of Issue Discussed 173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities ("EIC-173") applicable to Emera's 2009 fiscal year. EIC-173 recommends that a company take into account its own credit risk and the credit risk of the counterparty in determining the fair value of financial assets and financial liabilities. The Company is currently assessing the effect on its financial results. 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, 2008 Revenues from external customers $1,126.5 $147.7 $57.7 $1,331.9 Depreciation 133.6 16.3 1.4 151.3 Cost of operations, including depreciation 867.6 97.9 55.6 1,021.1 Equity earnings - - 15.2 15.2 Interest expense 99.1 13.3 19.3 131.7 Income taxes 46.6 14.8 (3.3) 58.1 Net earnings applicable to common shareholders 105.6 23.1 15.4 144.1 Net inter-segment revenues (expenses) 93.5 (0.9) (92.6) - Capital expenditures 158.0 41.3 346.5 545.8 As at December 31, 2008 Total assets 3,490.7 783.0 995.7 5,269.4 Investments subject to significant influence - 2.2 315.4 317.6 Goodwill - 101.1 0.9 102.0 ------------------------------------------------------------------------- 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 828.4 95.6 63.5 987.5 Equity earnings - - 12.8 12.8 Interest expense 95.8 13.7 12.4 121.9 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) 87.3 (2.1) (85.2) - Capital expenditures 119.4 98.6 33.6 251.6 As at December 31, 2007 Total assets 3,182.5 609.9 428.7 4,221.1 Investments subject to significant influence - 1.9 122.6 124.5 Goodwill - 82.5 0.3 82.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Other includes 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, 2008. 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, 2008 December 31, 2009 Acquired companies pension plan December 31, 2008 December 31, 2009 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total cash amount Total cash amount for 2008, 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 $16.9 million (2007 - $18.2 million) for NSPI and Emera. Accrued pension and non-pension benefit asset (liability) 2008 2007 ------------------------------------------------- Defined Non- Defined Non- benefit pension benefit pension pension benefits pension benefits millions of dollars plans plans plans plans ------------------------------------------------------------------------- Assumptions (weighted average) Accrued benefit obligation - December 31: Discount rate 7.50% 7.50% 5.75% 5.75% 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) - 6.00% - 7.00% - ultimate - 4.00% - 4.00% - year ultimate reached - 2010 - 2010 Benefit cost for year ending December 31: Discount rate 5.75% 5.75% 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) - 7.00% - 8.00% - ultimate - 4.00% - 4.00% - year ultimate reached - 2010 - 2010 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accrued benefit obligations Balance, January 1 $780.0 $40.9 $802.7 $39.6 Employer current service cost 10.8 1.6 12.7 1.5 Employee contributions 5.1 - 5.0 - Interest cost 44.4 2.3 41.6 2.0 Actuarial (gains) losses (134.8) (4.7) (46.1) 1.5 Benefits paid (36.0) (4.0) (35.9) (3.7) ------------------------------------------------------------------------- Balance, December 31 669.5 36.1 780.0 40.9 ------------------------------------------------------------------------- Fair value of plan assets Balance, January 1 640.9 - 656.5 - Employer contributions 12.0 4.0 13.8 3.7 Employee contributions 5.1 - 5.0 - Actual return on plan assets (112.8) - 1.5 - Benefits paid (36.0) (4.0) (35.9) (3.7) ------------------------------------------------------------------------- Balance, December 31 509.2 - 640.9 - ------------------------------------------------------------------------- Reconciliation of financial status to accrued benefit asset, December 31 Fair value of plan assets 509.2 - 640.9 - Accrued benefit obligations 669.5 36.1 780.0 40.9 ------------------------------------------------------------------------- Plan deficit (160.3) (36.1) (139.1) (40.9) Unamortized past service (gains) costs (0.4) 1.8 (0.5) 2.1 Unamortized actuarial losses (gains) 204.2 (3.0) 191.5 1.7 Unamortized transitional obligation 0.1 9.0 0.1 11.2 ------------------------------------------------------------------------- Accrued benefit asset (liability) $43.6 $(28.3) $52.0 $(25.9) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The amounts to be recognized in other assets and other liabilities are as follows: 2008 2007 ------------------------------------------------- Defined Non- Defined Non- benefit pension benefit pension pension benefits pension benefits millions of dollars plans plans plans plans ------------------------------------------------------------------------- Prepaid benefit cost $74.8 - $81.6 - Accrued benefit liability (31.2) $(28.3) (29.6) $(25.9) ------------------------------------------------------------------------- Net accrued benefit asset (liability) $43.6 $(28.3) $52.0 $(25.9) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Defined benefit plans asset allocation (% of plan assets) 2008 2007 ------------------------------------------------- Acquired Acquired Employee companies Employee companies pension pension pension pension plan plan plan plan ------------------------------------------------- Equity securities 56% 50% 66% 60% Debt securities 41% 47% 31% 38% Cash 3% 3% 3% 2% ------------------------------------------------------------------------- Total 100% 100% 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2008, the pension funds do not hold any material investments in Emera Inc. or Nova Scotia Power Inc. securities. Plans with accrued benefit obligations in excess of assets As at December 31, 2008, all post-retirement benefit plans have accrued benefit obligations in excess of assets. Benefits cost components millions of dollars 2008 2007 ------------------------------------------------- Defined Non- Defined Non- benefit pension benefit pension pension benefits pension benefits Defined benefit plan plans plans plans plans ------------------------------------------------- Costs arising from events during the year: Current service costs $10.8 $1.6 $12.7 $1.6 Interest on accrued benefits 44.4 2.3 41.6 2.0 Less: actual return on plan assets 112.8 - (1.5) - Actuarial (gains) losses on accrued benefit obligation (134.8) (4.7) (46.1) 1.5 ------------------------------------------------------------------------- Future benefit costs before adjustments 33.2 (0.8) 6.7 5.1 Adjustments to recognize long-term nature of costs: Difference between expected return on assets and actual return (159.6) - (43.1) - Amortization of transitional obligation - 2.2 - 2.2 Difference between amortization of actuarial losses (gains) and actual actuarial losses (gains) on accrued benefit obligations 146.8 4.8 64.8 (1.3) Difference between amortization of past service costs and past service costs for the year - 0.2 - 0.2 ------------------------------------------------------------------------- Total cost recognized $20.4 $6.4 $28.4 $6.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Defined contribution plan Employer cost $0.8 - $0.8 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- The expected return on plan assets is determined based on the market-related value of plan assets of $633.5 million at January 1, 2008 (2007 - $601.7 million), adjusted for interest on certain cash flows during the year. 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 2008: millions of dollars Increase Decrease ------------------------------------------------------------------------- Current service cost and interest cost $0.2 $(0.1) Accrued benefit obligation, December 31 $1.3 $(1.1) ------------------------------------------------------------------------- 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. Employees hired after January 1, 2006 are not eligible for the retiree health care plan. Other retirement benefit plans include an unfunded pension arrangement and a retiree life insurance plan. The measurement date for the assets and obligations of each benefit plan is December 31, 2008. 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, 2007 December 31, 2008 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total cash amount Total cash amount for 2008, 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 $4.8 million (2007 - $8.9 million). Accrued pension and non-pension benefit liability 2008 2007 ------------------------------------------------- Defined Non- Defined Non- benefit pension benefit pension pension benefits pension benefits millions of dollars plans plans plans plans ------------------------------------------------------------------------- Assumptions (weighted average) Accrued benefit obligation - December 31: Discount rate 6.75% 6.75% 6.75% 6.75% Rate of compensation increase 3.75% 3.75% 4.00% - Health care trend - initial (next year) - 7.60% - 9.20% - ultimate - 5.00% - 5.00% - year ultimate reached - 2015 - 2013 Benefit cost for year ending December 31: Discount rate 6.75% 6.75% 6.00% 6.00% 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) - 9.20% - 8.40% - ultimate - 5.00% - 5.00% - year ultimate reached - 2013 - 2011 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accrued benefit obligations Balance, January 1 $65.5 $38.0 $84.0 $37.8 Employer current service cost 1.2 0.9 1.3 0.8 Interest cost 4.7 2.8 4.5 2.1 Actuarial losses (gains) 1.0 4.1 (7.9) 5.9 Benefits paid (3.9) (2.0) (4.1) (2.3) Foreign currency translation adjustment 16.1 9.8 (12.3) (6.3) ------------------------------------------------------------------------- Balance, December 31 84.6 53.6 65.5 38.0 ------------------------------------------------------------------------- Fair value of plan assets Balance, January 1 55.0 1.0 59.9 1.2 Employer contributions 2.6 2.0 6.3 2.3 Actual return on plan assets (16.4) - 2.4 0.1 Benefits paid (3.9) (2.0) (4.1) (2.3) Foreign currency translation adjustment 10.6 0.2 (9.5) (0.3) ------------------------------------------------------------------------- Balance, December 31 47.9 1.2 55.0 1.0 ------------------------------------------------------------------------- Reconciliation of financial status to accrued benefit asset, December 31 Fair value of plan assets 47.9 1.2 55.0 1.0 Accrued benefit obligations 84.6 53.6 65.5 38.0 ------------------------------------------------------------------------- Plan deficit (36.7) (52.4) (10.5) (37.0) Unamortized past service costs (gains) 1.1 (3.7) 1.1 (3.4) Unamortized actuarial losses 36.4 20.5 9.3 13.8 Unamortized transitional obligation - 2.4 - 2.5 ------------------------------------------------------------------------- Accrued benefit asset (liability) $0.8 $(33.2) $(0.1) $(24.1) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Defined benefit plans asset allocation (% of plan assets) 2008 2007 ----------------------------------------------- Employee pension plan Employee pension plan ------------------------------------------------------------------------- Equity securities 56% 64% Debt securities 43% 35% Other 1% 1% ------------------------------------------------------------------------- Total 100% 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2008, 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, 2008, all post-retirement benefit plans have accrued pension obligations in excess of assets. Benefits cost components millions of dollars 2008 2007 ------------------------------------------------- Defined Non- Defined Non- benefit pension benefit pension pension benefits pension benefits Defined benefit plan plans plans plans plans ------------------------------------------------- Costs arising from events during the year: Current service costs $1.2 $0.9 $1.3 $0.8 Interest on accrued benefits 4.7 2.8 4.5 2.1 Less: actual return on plan assets 16.4 - (2.4) (0.1) Actuarial losses (gains) on accrued benefit obligation 1.0 4.1 (7.9) 5.9 ------------------------------------------------------------------------- Future benefit costs before adjustments 23.3 7.8 (4.5) 8.7 Adjustments to recognize long-term nature of costs: Difference between expected return on assets and actual return (21.3) (0.1) (2.1) 0.1 Amortization of transitional obligation - 0.5 - 0.5 Difference between amortization of actuarial losses (gains) and actual actuarial losses (gains) on accrued benefit obligations (0.3) (3.0) 9.0 (4.9) Difference between amortization of past service costs and past service costs for the year 0.2 (0.4) 0.2 (0.4) ------------------------------------------------------------------------- Total cost recognized $1.9 $4.8 $2.6 $4.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Defined contribution plan Employer cost $0.3 - $0.3 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the defined benefit pension plan, the expected return on plan assets is determined on the market-related value of plan assets of $70.2 million at January 1, 2008 (2007 - $50.1 million), adjusted for interest on certain cash flows during the year. 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 2008: Increase Decrease ------------------------------------------------------------------------- Current service cost and interest cost $0.6 $(0.5) Accrued benefit obligation, December 31 $8.2 $(6.5) ------------------------------------------------------------------------- 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 $45.1 million (2007 - $36.3 million) and the total defined benefits expense for 2008 would be $4.6 million (2007 - $4.5 million). 5. OPERATING LEASES The Company has entered into operating lease agreements for office space, telecommunication services, and certain other equipment, which expire in 2009 to 2020. Future minimum annual lease payments under the leases are as follows: millions of dollars --------------------------------------------------------------- 2009 $10.0 2010 10.0 2011 1.5 2012 0.4 2013 0.4 Thereafter 2.2 --------------------------------------------------------------- $24.5 --------------------------------------------------------------- --------------------------------------------------------------- For the year ended December 31, 2008 the Company recognized $10.5 million (2007 - $12.3 million) of operating leases 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: 2008 2007 ------------------------------------------------- Carrying Equity Carrying Equity millions of dollars value earnings value earnings ------------------------------------------------------------------------- Maritimes & Northeast Pipeline $198.5 $12.2 $99.8 $10.6 Grand Bahama Power Company Limited 87.8 1.2 - - St. Lucia Electricity Services Ltd. 29.1 1.8 22.8 2.2 Maine Electric Power Company Inc. 2.0 - 1.4 - Maine Yankee Atomic Power Company 0.2 - 0.5 - ------------------------------------------------------------------------- $317.6 $15.2 $124.5 $12.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Equity investments include a $26.3 million difference between the cost and the underlying net book value of the investees' assets as at the date of acquisition. The excess is attributable to goodwill and is therefore not subject to amortization. 7. FINANCING CHARGES Financing charges consists of the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Interest - long-term debt $104.7 $105.3 - short-term debt 25.4 21.6 Preferred share dividends paid by subsidiary (note 9) 14.1 14.1 Amortization of defeasance cost (note 12) 12.4 12.7 Amortization of debt financing costs 1.6 1.8 Allowance for funds used during construction (21.7) (12.3) Refund interest on income tax recovery (note 8) - (6.8) Foreign exchange gains (13.3) (3.2) ------------------------------------------------------------------------- $123.2 $133.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 8. INCOME TAXES The income tax provision differs from that computed using the statutory rates for the following reasons: millions of dollars 2008 2007 ------------------------------------------------------------------------- Earnings before income taxes $202.8 $231.6 ------------------------------------------------------------------------- Income taxes, at statutory rates 72.0 35.5% 88.2 38.1% Unrecorded future income taxes on regulated earnings (12.0) (5.9) - - Income tax recovery (6.5) (3.3) (10.8) (4.7) Equity earnings not subject to tax (4.9) (2.3) (4.9) (2.1) Change in future income tax asset resulting from rate change - - 0.9 0.4 Other 9.5 4.7 6.9 3.0 ------------------------------------------------------------------------- 58.1 28.7% 80.3 34.7% ------- ------- Income taxes - current 53.8 67.1 ------------------------------------------------------------------------- Income taxes - future $4.3 $13.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The future income tax assets and liabilities comprise the following: Current portion Long-term portion ------------------------------------------------- millions of dollars 2008 2007 2008 2007 ------------------------------------------------------------------------- Future income tax assets: Tax loss carry forwards $1.9 $6.2 $13.2 $11.7 Property, plant and equipment - - 1.4 1.7 Other 5.2 0.5 3.0 2.8 ------------------------------------------------------------------------- $7.1 $6.7 $17.6 $16.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Future income tax liabilities: Property, plant and equipment - - $116.1 $81.7 Other assets - - 7.1 6.8 Other liabilities - - (10.6) (6.1) Tax loss carry forwards - - (5.4) - Other - $2.0 3.1 0.5 ------------------------------------------------------------------------- - $2.0 $110.3 $82.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2008, the Company has tax losses of $59.4 million, which are reflected in future income tax assets or netted against future income liabilities as appropriate, and begin to expire in 2014. Accounting for the impact of rate regulation: At December 31, 2008, the unrecorded future income tax liability of Emera's wholly-owned regulated subsidiaries is approximately $2.2 million (2007 - future income tax asset of $40.7 million), of which a future income tax asset of $2.7 million (2007 - $16.3 million) is related to AOCI. The unrecorded future income tax liability consists of taxable temporary differences of $45.6 million (2007 - deductible temporary differences of $122.4 million) and unused non-capital losses of $30.0 million (2007 - $0.4 million) which begin to expire in 2027. In the absence of regulatory approval of the taxes payable accounting policies, Emera would have had a future income tax expense of $29.3 million in 2008 (2007 - $9.6 million). During 2008, NSPI accelerated the deduction of capitalized expenses pertaining to the 2007 tax year. As a result, in 2008 NSPI recorded an income tax recovery of $6.5 million. During 2007, 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 deductions of certain capitalized expenses. In 2008, NSPI amended its 2005 and 2006 tax returns on the same basis as was used for the years 2000 to 2004 inclusive. The amendments have been processed by CRA. All material amounts relating to these prior year adjustments were recorded in the 2007 financial statements of NSPI. As a result, in Q3 2007 NSPI recorded an income tax recovery of $25.4 million, of which $14.6 million was recorded as a reduction of other assets, specifically the regulatory asset related to its pre-2003 income tax liability. The remaining $10.8 million was 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 other assets. The remaining $6.8 million has been recorded as a reduction of financing charges. NSPI will continue to use this methodology when filing its future tax returns. Absent NSPI's regulator approved taxes payable accounting policy, the recoveries would have no effect on the total current and future income tax expense and net earnings would have been $6.5 million lower (2007 - $10.8 million) for year ended December 31, 2008. 9. 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 Millions of Share Capital Issued and outstanding: Shares millions of dollars ------------------------------------------------------------------------- January 1, 2007 10.4 $260.0 ------------------------------------------------------------------------- December 31, 2007 10.4 260.0 ------------------------------------------------------------------------- December 31, 2008 10.4 $260.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2008 and December 31, 2007 the Company had outstanding 5.0 million 4.9% Series C preferred shares, and 5.4 million 5.9% Series D preferred shares with the following redemption features: 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. These shares are classified as short-term on the balance sheet. 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 $2 and the market price of the Emera Inc. common shares, subject to the right of NSPI to redeem such shares for cash or to cause the holders of such shares to sell on the exchange date all or any part of such shares to substitute purchasers found by NSPI. NSPI will pay all accrued and unpaid dividends to the exchange date. 10. EARNINGS PER SHARE Earnings per share for 2008 are as follows: 2008 ------------------------------------------------- Weighted average Net earnings common (millions shares EPS of dollars) (millions) ($) ------------------------------------------------------------------------- Basic EPS $144.1 111.9 $1.29 Series C preferred shares of NSPI 6.0 5.8 (0.01) Series D preferred shares of NSPI 7.8 6.2 - Restricted share units and deferred share units - 0.7 (0.01) Other share-based compensation - 0.3 (0.01) ------------------------------------------------------------------------- Diluted EPS $157.9 124.9 $1.26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per share for 2007 are as follows: 2007 ------------------------------------------------- Weighted average Net earnings common (millions shares EPS of dollars) (millions) ($) ------------------------------------------------------------------------- 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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. 11. ACCOUNTS RECEIVABLE AND LONG-TERM RECEIVABLE NSPI has 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 other assets. Fees related to securitization are expensed as incurred. At December 31, 2008 no accounts receivables were sold (2007 - $25 million). The agreement is in place until May 2009 and NSPI's ability to sell its receivables is subject to acceptance by the sponsor bank. The securitization program was suspended in January 2008 due to a lack of investor interest. At December 31, 2008, the Company had unbilled revenue included in accounts receivable in the amount of $89.7 million (2007 - $86.0 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 $56.4 million (2007 - $7.7 million) is reflected in long-term receivable. 12. OTHER ASSETS AND LIABILITIES Other assets and liabilities, including the impact of rate-regulated accounting policies, include the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Other assets: Regulatory assets: Unamortized defeasance costs $118.8 $131.1 Pre-2003 income tax liability and related interest 105.3 119.9 Deferral of fuel switching derivatives 36.3 5.6 Costs to restructure purchased power contracts 20.1 17.9 Seabrook nuclear project 14.3 13.2 Deferral of income and capital taxes not included in Q1 2005 rates 13.8 15.5 Hydro-Quebec obligation 5.9 4.0 Maine Yankee decommissioning costs 5.8 6.9 Deferred restructuring costs 4.7 4.8 Stranded cost revenue requirement levelizers 4.3 3.0 Held-for-trading natural gas contracts 1.7 1.5 Other 7.0 6.6 ------------------------------------------------------------------------- 338.0 330.0 ------------------------------------------------------------------------- Non-regulatory assets: Accrued pension asset - Nova Scotia Power (note 4) 74.8 81.6 Accrued pension asset - Bangor Hydro (note 4) 0.8 - Retained interest in accounts receivable securitized (note 11) - 2.5 Other 6.5 3.2 ------------------------------------------------------------------------- 82.1 87.3 ------------------------------------------------------------------------- $420.1 $417.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Other liabilities: Regulatory liabilities: Held-for-trading natural gas contracts $67.5 $75.3 Deferral of fuel switching derivatives 49.6 29.9 Other 3.1 0.2 ------------------------------------------------------------------------- 120.2 105.4 ------------------------------------------------------------------------- Non-regulatory liabilities: Accrued pension and non-pension benefit liability - Nova Scotia Power (note 4) 59.5 55.5 Accrued non-pension benefit liability - Bangor Hydro (note 4) 33.2 24.2 Hydro-Quebec obligation 5.9 4.0 Maine Yankee decommissioning liability 5.8 6.9 Unearned revenue 2.2 2.8 Other 9.9 12.0 ------------------------------------------------------------------------- 116.5 105.4 ------------------------------------------------------------------------- $236.7 $210.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Based on the terms and conditions of NSPI's defined-benefit pension plans and non-pension benefit plans, the Company is required under the accounting standards to disclose the accrued benefit assets and accrued benefit liabilities separately rather than the net amount as previously disclosed. As a result, other assets and liabilities as at December 31, 2007 have been increased by $55.5 million respectively. The change had no impact on the measurement of cash flows, shareholders' equity, net earnings applicable to common shares, and basic and diluted earnings per share. Further information can be found in note 4. 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, 2008 totaled $1.1 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 $12.3 million higher in 2008 (2007 - $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 addition, 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 $14.6 million higher in 2008 (2007 - $12.6 million). 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 relative 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 2008 would be $30.7 million ($19.8 million after-tax) lower (2007 - $5.6 million or $3.5 million after-tax). Costs to 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 restructure certain of the contracts. The MPUC has allowed Bangor Hydro to defer these costs and recover them in stranded cost rates. The contract restructuring costs are being recovered over a 20-year period ending in June 2018. The annual amortization is approximately $1.8 million. 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 2008 (2007 - $1.8 million or $1.1 million after-tax). 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 2008 and 2007 would each be $1.8 million ($1.1 million after-tax) higher. 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 2008 would be $1.7 million (2007 - $1.2 million) higher. 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 other liability, 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, 2008 earnings would be $0.3 million ($0.2 million after-tax) higher (2007 - $0.4 million or $0.2 million after-tax). 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 $5.0 million in 2008 (2007 - $4.4 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. 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 $3.3 million ($1.9 million after-tax) higher in 2008 (2007 - $4.4 million or $2.6 million after-tax). Deferred Restructuring Costs In conjunction with Bangor Hydro's Alternative Rate Plan, BHE was provided with accounting orders from the MPUC to defer and amortize over ten years certain employee transition costs. Eligible for deferral were 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 2008 earnings would be $1.1 million ($0.6 million after-tax) higher (2007 - $1.2 million or $0.7 million after-tax). Stranded Cost Revenue Requirement Levelizer Bangor Hydro's stranded cost rates are reset every three years and are designed to recover BHE's cumulative stranded cost revenue requirements over the three-year period. The most recently approved stranded cost rates are in effect from March 2008 to February 2011. While the stranded cost revenue requirements differ throughout the period due to changes in stranded cost revenues and expenses, 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. 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 regulator approval, earnings for 2008 would be $0.9 million ($0.5 million after-tax) higher (2007 - $6.3 million or $3.7 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. Absent this accounting policy, NSPI's 2008 net earnings would be $0.2 million ($0.1 million after-tax) lower (2007 - $0.1 million or $0.1 million after-tax). Other The UARB approved NSPI's deferral of $2.0 million of vegetation management spending in 2008 to be recovered in rates in a future period. The UARB also agreed to allow NSPI to defer up to $12.8 million of demand side management expenditures for the period January 1, 2008 through December 31, 2009 to be recovered in rates over six years commencing January 1, 2009. In the absence of the UARB's approval, these costs would not have been deferred and net earnings for 2008 would be $2.3 million lower. 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 $4.9 million ($2.9 million after-tax) higher in 2008 (2007 - $3.5 million or $2.0 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. Absent this accounting policy, NSPI's 2008 net earnings would be $7.8 million ($5.0 million after-tax) lower (2007 - $98.0 million or $60.6 million after-tax). 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 2008 would be $19.7 million ($12.7 million after-tax) higher (2007 - $29.9 million or $18.5 million after-tax). 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 $2.7 million ($1.6 million after-tax) lower in 2008 (2007 - $1.3 million or $0.7 million after-tax). 13. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is comprised of the following: 2008 ------------------------------------------------- Accumulated Net millions of dollars Cost Depreciation Book Value ------------------------------------------------------------------------- Generation Thermal $1,809.0 $752.1 $1,056.9 Gas Turbines 38.5 29.3 9.2 Combustion Turbines 73.8 12.6 61.2 Hydroelectric 450.7 142.3 308.4 Wind Turbines 2.1 0.6 1.5 Transmission 906.4 351.2 555.2 Distribution 1,433.7 699.4 734.3 Other 417.1 184.9 232.2 Other, under capital lease 3.7 0.7 3.0 ------------------------------------------------------------------------- $5,135.0 $2,173.1 $2,961.9 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2007 ------------------------------------------------- Accumulated Net millions of dollars Cost Depreciation Book 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accounting for the impact of rate regulation: During 2007, NSPI completed the amortization of the Glace Bay generating station by expensing $5.2 million related to the plant. In the absence of the UARB approved accounting policy, the generating station would have been written off in the year when NSPI determined that the unamortized cost of the generating station would not be recoverable and net earnings for 2007 would be $5.2 million higher. 14. ACQUISITIONS ICD Utilities Limited ("ICDU") In September 2008, Emera purchased 50% of the shares of ICDU of the Bahamas for $42.3 million USD ($45.3 million CAD). ICDU owns 50% of Grand Bahama Power Company Limited ("GBPC") which is a vertically integrated utility serving 19,000 customers on Grand Bahama Island. GBPC has 137 megawatts of installed oil-fired generating capacity. The Grand Bahama Port Authority Limited regulates the utility and has granted GBPC a licensed, regulated and exclusive franchise to produce, transmit, and distribute electricity on the island until 2054. There is a fuel pass through mechanism and flexible tariff adjustment policies to ensure that costs are recovered and a reasonable return is earned. The acquisition has been accounted for under the purchase method of accounting as Emera has determined it has control of ICDU, and accordingly, the results of operations since the date of acquisition have been included in the consolidated statements of earnings. ICDU is included in the segment "Other" in note 3 Segment Information. The following summarizes the transaction: Net assets acquired millions of dollars ------------------------------------------------------------------------- Long-term investment $78.8 Non-controlling interest (33.5) ------------------------------------------------------------------------- Cash paid $45.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The purchase price allocation has not yet been finalized as the Company has not completed the valuation of the long-term investment in GBPC. OpenHydro Group Limited ("OpenHydro") In February 2008 Emera acquired a 7.35% interest in OpenHydro, an Irish renewable tidal energy company for (euro)10.2 million ($15.4 million CAD). OpenHydro designs and manufactures marine turbines for harnessing energy from tidal currents in the world's oceans. The acquisition has been accounted for as an available-for-sale investment as Emera has determined it does not have significant influence over the investment, and accordingly, the investment was initially recorded at cost. Any dividends received or receivable since acquisition will be recognized as dividend income. OpenHydro is included in the segment "Other" in note 3 Segment Information. 15. 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 2008 2007 ------------------------------------------------------------------------- Current assets $8.3 $7.8 Non-current assets 71.5 61.6 ------------------------------------------------------------------------- $79.8 $69.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current liabilities $13.2 $7.9 Non-current liabilities 95.7 67.7 ------------------------------------------------------------------------- $108.9 $75.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Revenues $34.3 $55.4 Expenses (31.7) (42.2) ------------------------------------------------------------------------- Net earnings $2.6 $13.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash provided by operations $18.4 $8.8 Cash used in investing activities (1.5) (2.0) Cash used in financing activities (19.1) (4.7) ------------------------------------------------------------------------- (Decrease) increase in cash $(2.2) $2.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 16. GOODWILL The change in goodwill is due to the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Balance, beginning of year $82.8 $97.1 Change in foreign exchange rate 19.2 (14.3) ------------------------------------------------------------------------- Balance, end of year $102.0 $82.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 17. 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 2008 2007 ------------------------------------------------------------------------- Balance, beginning of year $83.8 $78.1 Accretion included in depreciation expense 2.2 2.0 Accretion deferred to regulatory asset 2.3 2.0 Liabilities settled (0.3) (0.2) Other - 1.9 ------------------------------------------------------------------------- Balance, end of year $88.0 $83.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The key assumptions used to determine the asset retirement obligations are as follows: ------------------------------------------------------------------------- Estimated undiscounted future obligation Expected Credit-adjusted (millions settlement Asset risk-free rate of dollars) date ------------------------------------------------------------------------- Thermal 5.3% $242.3 12-31 years Hydro 5.3% 60.8 23-53 years Combustion Turbines 5.3% 5.1 1-15 years Transmission & Distribution 5.8% 5.5 1-17 years Other 7.4% - 8.6% 0.5 3-8 years ------------------------------------------------------------------------- $314.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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. Additionally, some of the Company's transmission and distribution assets may have conditional asset retirement obligations, the fair value of which can not be reasonably estimated as sufficient information does not exist to estimate the obligation. A liability will be recognized in the period in which sufficient information becomes available. 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 2008 would be $2.3 million lower (2007 - $2.0 million). 18. SHORT-TERM DEBT For the year ended December 31, 2008, short-term debt consists of: - Short-term discount notes of $129.9 million issued against lines of credit, which bear interest at prevailing market rates, which on December 31, 2008, averaged 2.36%. - LIBOR loans of $24.9 million issued against lines of credit, which bear interest at prevailing market rates, which on December 31, 2008, averaged 1.50%. - Advances of $3.1 million, which when drawn upon against operating lines of credit, bear interest at the prime rate, which on December 31, 2008, was 3.50% in Canada and 3.25% in the US. For the year ended December 31, 2007, short-term debt consists of: - Short-term discount notes of $22.9 million. Short-term discount notes bear interest at prevailing market rates, which on December 31, 2007, averaged 4.69%. - Advances of $5.5 million, which when drawn upon against operating lines of credit, bear interest at the prime rate, which on December 31, 2007, was 6.00% in Canada and 7.25% in the US. This short-term debt is unsecured. 19. 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 of Outstanding millions of dollars 2008 2007 Maturity 2008 2007 ------------------------------------------------------------------------- Emera Bankers acceptances, LIBOR loans and advances 2.23 5.31 1 year renewal $535.6 $107.4 Capital lease obligations 5.09 5.15 Various 1.8 1.5 NSPI Medium term notes 6.63 6.64 2009 - 2097 1,285.0 1,250.0 Debentures 9.75 9.75 2019 95.0 95.0 Short-term discount notes 2.13 4.69 1 year renewal 53.0 94.0 Capital lease obligations 6.30 - - 0.4 - Bangor Hydro (issued and payable in USD) LIBOR loans & demand loans 2.14 5.62 1 year renewal 54.7 30.7 General & refunding mortgage bonds - secured by property, plant and equipment 9.74 9.74 2020 - 2022 61.2 49.4 Municipal review committee - 5.00 - - 0.9 Senior unsecured note 5.63 5.63 2009 - 2017 141.4 118.6 Bear Swamp (issued and payable in USD) Senior non-revolving credit facility secured by the assets of Bear Swamp 4.81 5.63 2012 76.5 61.7 ------------------------------------------------------------------------- 2,304.6 1,809.2 Amount due within one year (131.4) (121.0) Unamortized debt financing costs (14.0) (11.8) ------------------------------------------------------------------------- $2,159.2 $1,676.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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, 2008 long-term debt and obligations under a capital lease are due as follows: millions of dollars ------------------------------------------------------------------------- Year of Maturity ------------------------------------------------------------------------- One year renewable $643.3 2009 131.4 2010 106.3 2011 6.0 2012 106.8 2013 255.5 Greater than 5 years 1,055.3 ------------------------------------------------------------------------- $2,304.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 20. COMMON SHARES Authorized: Unlimited number of non-par value common shares. Millions of Issued and outstanding: shares ------------------------------------------------------------------------- January 1, 2007 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 Issued for cash under purchase plans 0.39 Options exercised under senior management share option plan 0.35 ------------------------------------------------------------------------- December 31, 2008 112.21 ------------------------------------------------------------------------- ------------------------------------------------------------------------- As at December 31, 2008, there were 4.5 million (2007 - 4.8 million) common shares reserved for issuance under the senior management common share option plan, and 0.8 million (2007 - 1.0 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 total number of shares to be optioned to any optionee shall not exceed five 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 termination for other than just cause, 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. 2008 2007 ------------------------------------------------- Weighted Weighted Shares average Shares average under exercise under exercise option price option price ------------------------------------------------------------------------- Outstanding, beginning of year 2,343,450 $18.98 1,892,425 $18.54 Granted 289,500 $21.51 542,600 $20.43 Exercised (351,625) $18.27 (91,575) $18.18 Expired (83,600) $20.14 - - ------------------------------------------------------------------------- Outstanding, end of year 2,197,725 $19.39 2,343,450 $18.98 Exercisable, end of year 1,176,300 $18.43 1,058,150 $17.86 ------------------------------------------------------------------------- The weighted average contractual life of options outstanding at December 31, 2008 is 6.9 years (2007 - 7.3 years). The range of exercise prices for the options outstanding at December 31, 2008 is $13.70 to $22.59 (2007 - $13.70 to $20.52). 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: 2008 2007 ------------------------------------------------- Expected dividend yield 5.00% 5.04% Expected volatility 13.96% 14.00% Risk-free interest rate 4.18% 4.24% 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 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. Payments are usually made in cash. At the sole discretion of the Management Resources and Compensation Committee ("MRCC"), payments may be made in the form of actual shares. Any participant who is a United States taxpayer shall receive payment on the first business day following the six month anniversary of their termination. In addition, special DSU awards may be made from time to time by the 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 based on the average of Emera's stock closing price for the fifty trading days prior to a given calculation date and multiplied by a ratio factor of 1.11. 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, disability or death. ------------------------------------------------- Employee Employee Director DSUs RSUs DSUs Outstanding Outstanding Outstanding ------------------------------------------------------------------------- January 1, 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 Granted 70,680 137,816 27,838 Retirement, termination, disability & death (32,559) (16,432) (16,286) Payout - (105,255) - ------------------------------------------------------------------------- December 31, 2008 280,249 283,347 87,202 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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, 2008, $4.7 million (2007 - $4.0 million) of compensation expense related to options granted, units issued, and shares purchased by employees was recognized in operating, maintenance and general expense. 21. SUPPLEMENTAL CASH FLOW INFORMATION The change in non-cash operating working capital consists of the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Decrease (increase) in accounts receivable $37.6 $(43.5) (Increase) decrease in inventory (34.1) 15.2 Decrease (increase) in prepaid expenses 14.7 (10.5) (Increase) decrease in long-term receivables (48.6) 61.2 Change in posted margin included in accounts receivable or accounts payable and accrued charges (70.5) (0.9) Increase in other accounts payable and accrued charges 18.6 15.6 Increase (decrease) in income tax payable 2.0 (44.4) ------------------------------------------------------------------------- $(80.3) $(7.3) ------------------------------------------------------------------------- ------------------------------------------------------------------------- 22. CAPITAL MANAGEMENT The Company includes shareholders' equity (excluding AOCI), short-term and long-term debt, preferred shares issued by subsidiary, non-controlling interest related to BHE, securitized receivables, and cash and cash equivalents in the definition of capital as follows: millions of dollars 2008 2007 ------------------------------------------------------------------------- Shareholders' equity, excluding AOCI $1,615.4 $1,568.8 Debt 2,448.5 1,825.8 Preferred shares issued by subsidiary 260.0 260.0 Non-controlling interest related to BHE 0.5 0.6 Securitized accounts receivable - 25.0 Cash and cash equivalents (12.2) (26.4) ------------------------------------------------------------------------- $4,312.2 $3,653.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company's objectives when managing capital are to ensure sufficient liquidity and ongoing access to capital in order to allow the Company to acquire, build and maintain its regulated electric utilities, low risk unregulated generation and energy infrastructure businesses. The Company has a strategy of managing its capital structure through its various wholly-owned subsidiaries, while ensuring it is in compliance with its debt covenants. This strategy is managed by the Company through the issuance from time to time of shares, bonds, medium-term notes, preferred shares, or other indebtedness, and sales of receivables through the Company's securitization program. The securitization program was suspended in January 2008 due to increased pricing and limitations of supply in the market and expires in May 2009. NSPI is subject to regulation by the Utility and Review Board with an allowed maximum common equity component for 2008 of 40%. The UARB has approved this component to increase to 45% in 2009. BHE is subject to regulation by the Maine Public Utilities Commission with an allowed maximum common equity component of 50% for rate-making purposes. The Federal Energy Regulatory Commission does not specify an allowed common equity component for BHE. The Company is in compliance with these requirements. Emera Inc.'s syndicated bank credit agreement provides that the Company's debt can not exceed 70% of the Company's capitalization. NSPI's trust indentures, applicable to the senior unsecured debenture and senior unsecured medium-term notes, provide that NSPI's funded debt cannot exceed 75% of total capitalization as defined in the credit agreements. NSPI's syndicated bank credit facility limits its debt to capitalization ratio to no greater than 0.65:1. BHE has short-term and long-term financing agreements that limit the amount of debt to less than 55% of capitalization, limit priority debt to 15% of net worth, limit earnings before interest, taxes, depreciation and amortization to interest to 2:1, and requires net worth of at least $150 million. The Company is in compliance with all of its financial debt covenants. 23. FINANCIAL INSTRUMENTS The Company manages its exposure to foreign exchange, interest rate, and commodity risks in accordance with established risk management policies and procedures. Derivative financial instruments, consisting mainly of foreign exchange forward contracts, interest caps and collars, and oil and gas options and swaps, are used to hedge cash flows. Derivative financial instruments, consisting of foreign exchange forward contracts, are also used to hedge fair values. 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: 2008 2007 ------------------------------------------------------------------------- Carrying Fair Carrying Fair millions of dollars Amount Value Amount Value ------------------------------------------------------------------------- Cash and cash equivalents $12.2 $12.2 $26.4 $26.4 Restricted cash 0.8 0.8 1.0 1.0 Accounts receivable 385.1 385.1 319.3 319.3 Long-term receivable 56.4 56.4 7.7 7.7 Derivatives held in a valid hedging relationship (current and long-term portion) 165.1 165.1 23.2 23.2 Held-for-trading derivatives (current and long-term portion) 137.8 137.8 139.8 139.8 ------------------------------------------------------------------------- Total financial assets $757.4 $757.4 $517.4 $517.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accounts payable and accrued charges $307.1 $307.1 $282.7 $282.7 Short-term debt 157.9 158.0 28.4 28.5 Long-term debt (including current portion) 2,290.6 2,330.8 1,797.4 2,030.4 Preferred shares issued by a subsidiary 260.0 258.9 260.0 275.7 Derivatives held in a valid hedging relationship (current and long-term portion) 169.8 169.8 77.2 77.2 Held-for-trading derivatives (current and long-term portion) 52.1 52.1 29.1 29.1 ------------------------------------------------------------------------- Total financial liabilities $3,237.5 $3,276.7 $2,474.8 $2,723.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 $5.1 million (2007 - $6.9 million). The allowance for doubtful accounts was $4.8 million as at January 1, 2008 (2007 - $2.6 million) and $4.5 million as at December 31, 2008 (2007 - $4.8 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 a subsidiary are recognized using the effective interest method and are disclosed in note 7. 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 include the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Financing charges decrease $1.5 - Fuel and purchased power decrease (increase) 26.5 $(14.7) ------------------------------------------------------------------------- Total gains (losses) $28.0 $(14.7) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company recognized total ineffectiveness in net earnings related to cash flow hedges as follows: millions of dollars 2008 2007 ------------------------------------------------------------------------- Fuel and purchased power increase $(0.5) $(0.2) ------------------------------------------------------------------------- Total losses $(0.5) $(0.2) ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company recognized total ineffectiveness in net earnings related to fair value hedges as follows: millions of dollars 2008 2007 ------------------------------------------------------------------------- Financing charges decrease $0.7 - ------------------------------------------------------------------------- Total gains $0.7 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company expects to reclassify $61.4 million of losses currently included in AOCI to net earnings over the next 12 months related to hedged items realized in net earnings. 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 may enter into interest rate hedging contracts to limit exposure to fluctuations in floating and fixed interest rates on its short-term and long-term debt. The Company has no interest rate hedging contracts outstanding as of December 31, 2008. 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, 2008, the Company had hedged approximately 99% of all natural gas purchases and sales associated with its forecasted natural gas burn and resale for 2009, and 67% 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, 2008, the Company has hedged approximately 100% of 2009 requirements and 58% for 2010. The Company enters into solid fuel swap contracts to limit exposure to fluctuations in world prices of solid fuel. As at December 31, 2008, the Company had hedged approximately 91% of all solid fuel purchases for 2009, 29% for 2010, 19% for 2011 and 7% for 2012. The Company enters into power swaps to limit exposure to fluctuations in power prices. At December 31, 2008, the Company has hedged 97% of 2009 requirements, 100% of 2010 requirements, 60% of 2011 requirements and approximately 10% of the requirements for 2012 and 2013. 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 2009, 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 and swap contracts to limit exposure on fuel purchases 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 $318.0 million are in place at a weighted average rate of $1.08, representing over 70% of 2009 anticipated USD requirements. Forward contracts to buy USD $602.5 million in 2010 through 2012 at a weighted average rate of $1.01 were outstanding at December 31, 2008 to manage exposure to 34% of anticipated USD requirements in these years. As of December 31, 2008 there were no fuel related swaps outstanding. Emera uses foreign exchange forward contracts to hedge the currency risk for capital projects and receivables denominated in foreign currencies. Forward contracts to buy USD $7.8 million are in place at a weighted average rate of $0.99 for capital projects in 2009. Forward contracts to sell USD $39.0 million are in place at a weighted average rate of $1.25 to hedge a portion of receivables in 2010. Emera uses forward contracts to hedge the currency risk associated with revenue streams denominated in foreign currencies. Forward contracts to sell USD $46.0 million are in place in 2009 and 2010 at a weighted average rate of $1.25. Option contracts, to eliminate exposure to currency rate fluctuations for 2009, of $0.5 million at a rate of $1.26 were outstanding on December 31, 2008. 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. The Company has a derivative, a power swap, where no observable market exists, therefore modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices as applicable, to interpolate certain prices. Total gains and losses included in net earnings with respect to held-for-trading derivatives includes the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Electric revenue - $(0.6) Other revenue $3.6 25.8 Fuel and purchased power (0.4) 0.5 Financing charges (0.5) 0.1 ------------------------------------------------------------------------- Total gains $2.7 $25.8 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Changes in the fair value of the derivative asset, where no observable market exists, includes the following: millions of dollars 2008 2007 ------------------------------------------------------------------------- Balance, beginning of year $10.5 - (Loss) gain recognized in other revenue (8.1) $15.7 Foreign exchange included in AOCI 2.5 (5.2) ------------------------------------------------------------------------- Balance, end of year $4.9 $10.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Energy marketing assets and liabilities On December 31, 2008, 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, 2008, 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 the power necessary to produce the energy requirements 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. Market risks associated with derivatives, which includes the Company's hedges and HFT derivatives, are related to movement in commodity prices and foreign exchange rates. Market risk associated with short-term debt is related to movement in interest rates. Market risk associated with the long-term receivable is related to movements in commodity prices and foreign exchange rates. As at December 31, 2008 the Company determined that market risk exposure associated with its financial instruments would affect the Company's financial results as follows: After-tax After-tax net earnings AOCI increase increase millions of dollars (decrease) (decrease) ------------------------------------------------------------------------- $1 per one million British Thermal Unit increase in the price of natural gas $2.3 $8.7 $5 per barrel increase in the price of heavy fuel oil 0.8 10.0 $15 per metric tonne increase in the price of coal - 38.6 $0.01 decrease in the strength of the Canadian relative to the US dollar (0.3) 8.1 100 basis point increase in the central bank interest rates 0.2 - $1 per megawatt hour increase in the price of power 0.6 - ------------------------------------------------------------------------- The above table illustrates the effect on the Company's financial results due to a certain fixed price change on the entire portfolio of financial instruments as at the end of the quarter. The results disclosed in the above table cannot be extrapolated linearly to determine the effect on the Company's financial results due to varying price changes. 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. As at December 31, 2008, the maximum exposure the Company has to credit risk is $606.8 million, which includes accounts receivable, long-term receivable, and the assets related to derivatives in a valid hedging relationship, and held-for-trading derivatives, excluding NSPI's natural gas contracts. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, foreign exchange and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The Company also obtains cash deposits from electric customers. The total cash deposits and letters of credit on hand as at December 31, 2008 was $47.6 million, which mitigates the Company's maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the cash deposit to the counterparty where the credit limit is no longer exceeded or where the customer is no longer considered a high risk account. The Company generally considers the credit quality of financial assets that are neither past due nor impaired to be good. The Company monitors collection performance to ensure payments are received on a timely basis. The Company does not have any financial assets that would be considered to be impaired. As at December 31, 2008, the Company had $31.3 million in financial assets considered to be past due, which have been outstanding for an average of 69 days. The fair value of these financial assets is $28.5 million, the difference of which is included in the allowance for doubtful accounts. These assets primarily relate to accounts receivable from electric revenue. Concentration risk The Company's concentrations of risk as at December 31, 2008 is as follows: 2008 millions % of total of dollars exposure ------------------------------------------------------------------------- Accounts receivable Regulated utilities Residential $115.6 16% Commercial 62.0 8% Industrial 31.2 4% Other 15.1 2% Posted margin with other counterparties 25.1 3% ------------------------------------------------------------------------- 249.0 33% ------------------------------------------------------------------------- Trading group Credit rating of A- or above 44.1 6% Credit rating of BBB- to BBB+ 21.5 3% Not rated 46.1 6% Fully collateralized 12.3 2% ------------------------------------------------------------------------- 124.0 17% ------------------------------------------------------------------------- Other accounts receivable 12.1 2% ------------------------------------------------------------------------- 385.1 52% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Long-term receivable 56.4 7% ------------------------------------------------------------------------- ------------------------------------------------------------------------- Derivatives (in a valid hedging relationship and held-for-trading; current and long-term portions) Credit rating of A- or above 216.4 29% Credit rating of BBB- to BBB+ 15.5 2% Not rated 71.0 10% ------------------------------------------------------------------------- 302.9 41% ------------------------------------------------------------------------- ------------------------------------------------------------------------- $744.4 100% ------------------------------------------------------------------------- ------------------------------------------------------------------------- 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 2009 2010 2011 2012 2012 ------------------------------------------------------------------------- Accounts payable and accrued charges $307.1 - - - - Short-term debt 157.9 - - - - Long-term debt 774.7 $106.3 $6.0 $106.8 $1,310.8 Preferred shares issued by subsidiary 125.0 - - - 135.0 Derivatives held in a valid hedging relationship 110.2 36.0 18.8 4.6 0.2 Held-for-trading derivatives 40.4 11.4 0.3 - - ------------------------------------------------------------------------- Total financial liabilities $1,515.3 $153.7 $25.1 $111.4 $1,446.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company has available the following credit facilities as at December 31, 2008 for the management of liquidity risk: millions of dollars Available Used Unused ------------------------------------------------------------------------- Bank operating and commercial paper $1,373.5 $917.9 $455.6 ------------------------------------------------------------------------- ------------------------------------------------------------------------- AVAILABLE-FOR-SALE INVESTMENTS Available-for-sale investments includes the Company's investment in OpenHydro Group Limited ("OpenHydro"). The investment is recognized at its cost of $15.4 million. The fair value of OpenHydro has not been recognized or disclosed because its shares are not actively traded in an open market. The Company does not intend to dispose of the investment in the near term. The market for any disposition of OpenHydro shares would be with an existing shareholder or a new private investor. 24. RELATED PARTY TRANSACTIONS In the ordinary course of business, Emera purchased natural gas transportation capacity totaling $29.4 million (2007 - $25.4 million) during the year ended December 31, 2008, 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, 2008 the amount payable to the related party is $4.1 million (2007 - $4.5 million), is non-interest bearing and is under normal credit terms. 25. CONTINGENCIES A number of individuals who live in proximity to NSPI'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 proposed to amend the statement of claim to reference emissions from the operation of the plant commencing in the early 1970's, though the amendment has not at this time been consented to nor granted by the court. The Company has filed a defence to the claim. 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. 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. 26. COMMITMENTS In addition to commitments outlined elsewhere in these notes, Emera had the following significant commitments at December 31, 2008: - 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 952 GWh of electricity from independent power producers over varying contract lengths ranging from five to 25 years. - NSPI is required to purchase approximately 61,600 mmbtu of natural gas per day for the next two years (subject to offshore gas production), and an additional 4,000 mmbtu per day for three years. - NSPI has a commitment to purchase approximately 61,600 mmbtu per day of transportation capacity on the Maritimes and Northeast Pipeline, a related party, for the next two years. The approximate cost of the commitment $18 million per year. - NSPI has a commitment to purchase an additional 4,000 mmbtu per day of transportation capacity on the Maritimes and Northeast Pipeline, a related party, for three years. The commitment includes renewal rights at the supplier's option for two additional five year terms, at an approximate cost of $1 million per year. - NSPI is responsible for managing a portfolio of approximately $1.1 billion of defeasance securities held in trust. The defeasance securities must provide the principal and interest payment streams of the related defeased debt. Approximately 73%, or $774 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 unloading and 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 2009 to 2012, to purchase and transport 3.5 million metric tons ("mts") of import coal, 335,800 mts of petroleum coke, 720,000 mts of domestic coal and 2.4 million mts of marine freight. - Bangor Hydro has various contracts committing it to purchase annually, net of resale revenues, approximately $7 million to $11 million of electricity for the period from 2009 to 2019 from independent power producers. These commitments are reduced to less than $2 million each year from 2018 to 2026. 27. GUARANTEES Emera had the following guarantees at December 31, 2008: - The Company has letters of credit issued totaling $133.1 million. Emera's outstanding letters of credit are to secure payment to various vendors that expire in 2009 and/or are renewed annually. Nova Scotia Power's letters of credit extend to 2009 and/or are renewed annually and secure payments to various vendors, including counterparties, and to secure obligations under an unfunded pension plan. Bangor Hydro's letters of credit extend to 2009 and/or are renewed annually to secure payments to a vendor and for obligations under an unfunded pension plan. 28. SUBSEQUENT EVENT In January 2009, Nova Scotia Power issued $50 million in medium term notes, at a yield of 5.455%. The notes are due in full in October 2013. Proceeds were used to pay down short-term debt. 29. COMPARATIVE INFORMATION Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted for 2008. OPERATING STATISTICS FIVE-YEAR SUMMARY Year Ended December 31 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Electric energy sales (GWh) Residential 4,769.6 4,738.5 4,516.0 4,602.7 4,632.4 Commercial 3,721.1 3,768.5 3,621.1 3,614.1 3,567.4 Industrial 4,491.5 4,568.4 3,246.7 4,600.3 4,556.1 Other 1,115.2 1,320.4 1,550.8 902.7 819.1 ------------------------------------------------------------------------- Total electric energy sales 14,097.4 14,395.8 12,934.6 13,719.8 13,575.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Sources of energy (GWh) Thermal - coal 9,008.9 9,561.4 9,128.1 9,116.3 9,490.2 - oil 340.7 516.6 431.9 1,581.3 1,699.3 - natural gas 1,257.9 1,057.1 390.3 194.3 97.0 Hydro 1,102.3 936.8 1,034.7 1,092.6 983.5 Wind 2.4 2.4 2.4 1.8 2.4 Purchases 3,493.2 3,534.7 3,144.7 2,961.6 2,339.9 ------------------------------------------------------------------------- Total generation and purchases 15,205.4 15,609.0 14,132.1 14,947.9 14,612.3 Losses and internal use 1,076.3 1,213.2 1,197.5 1,228.1 1,037.3 ------------------------------------------------------------------------- Total electric energy sold 14,129.1 14,395.8 12,934.6 13,719.8 13,575.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Electric customers Residential 535,494 530,955 526,014 520,671 515,726 Commercial 54,461 51,083 50,780 50,321 49,353 Industrial 2,541 2,543 2,526 2,515 2,455 Other 9,064 9,574 9,378 9,094 8,684 ------------------------------------------------------------------------- Total electric customers 601,560 594,155 588,698 582,601 576,218 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capacity Generating nameplate capacity (MW) Coal fired 1,243 1,243 1,243 1,243 1,243 Dual fired 365 350 350 350 350 Gas turbines 304 319 323 323 319 Hydroelectric 1,005 1,005 1,005 1,005 395 Wind turbines 1 1 1 1 1 Independent power producers 120 120 120 74 66 ------------------------------------------------------------------------- 3,038 3,038 3,042 2,996 2,374 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total number of employees 2,215 2,194 2,149 2,075 2,249 ------------------------------------------------------------------------- ------------------------------------------------------------------------- km of transmission lines 6,400 6,200 6,100 6,100 6,100 ------------------------------------------------------------------------- ------------------------------------------------------------------------- km of distribution lines 32,600 32,000 32,000 32,000 32,000 ------------------------------------------------------------------------- ------------------------------------------------------------------------- FIVE YEAR SUMMARY Year Ended December 31 (millions of dollars) 2008 2007 2006 2005 2004 ------------------------------------------------------------------------- Statements of Earnings Information Revenue $1,331.9 $1,339.5 $1,166.0 $1,168.0 $1,134.2 ------------------------------------------------------------------------- Cost of operations Fuel for generation and power purchased 525.1 494.5 347.7 432.0 350.0 Operating, maintenance and general 266.8 264.8 255.6 248.2 245.2 Provincial, state and municipal taxes 49.4 47.5 48.0 48.4 46.3 Provincial tax deferral - - - (4.5) - Depreciation 151.3 149.3 145.2 136.1 131.2 Regulatory amortization 28.5 31.4 22.8 19.4 26.1 ------------------------------------------------------------------------- 1,021.1 987.5 819.3 879.6 798.8 ------------------------------------------------------------------------- 310.8 352.0 346.7 288.4 335.4 Equity earnings 15.2 12.8 4.9 6.5 6.2 Other income - - 8.9 8.0 - Financing charges 123.2 133.2 148.1 140.3 152.1 ------------------------------------------------------------------------- Earnings before income taxes 202.8 231.6 212.4 162.6 189.5 Income taxes 58.1 80.3 86.6 52.7 61.9 Income taxes deferral - - - (12.2) - ------------------------------------------------------------------------- Net earnings from continuing operations 144.7 151.3 125.8 122.1 127.6 (Loss) earnings from discontinued operations - - - (0.9) 2.2 ------------------------------------------------------------------------- Net earnings 144.7 151.3 125.8 121.2 129.8 Non-controlling interest 0.6 - - - - ------------------------------------------------------------------------- Net earnings applicable to common shares 144.1 151.3 125.8 121.2 129.8 Common dividends 107.9 99.9 98.3 97.4 95.5 Dividends paid by subsidiaries to non-controlling interest 1.9 - - - - ------------------------------------------------------------------------- Earnings retained for use in Company $34.3 $51.4 $27.5 $23.8 $34.3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cost of fuel for generation - coal $282.1 $276.0 $266.2 $260.9 $209.1 - oil 17.7 49.7 34.3 100.2 91.1 - natural gas 92.5 52.0 (41.6) (35.4) (30.6) Power purchased 132.8 116.8 88.8 106.3 80.4 ------------------------------------------------------------------------- Total cost of fuel for generation and power purchased $525.1 $494.5 $347.7 $432.0 $350.0 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Balance Sheets Information Current assets $681.8 $567.0 $491.3 $391.5 $332.1 Other assets 793.0 600.4 577.3 678.8 742.0 Investments subject to significant influence 317.6 124.5 98.5 99.1 96.8 Property, plant and equipment 3,476.2 2,929.2 2,881.9 2,829.2 2,778.3 ------------------------------------------------------------------------- Total assets $5,268.6 $4,221.1 $4,049.0 $3,998.6 $3,949.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current liabilities $880.1 $506.6 $491.0 $506.4 $493.6 Other liabilities 508.5 417.7 231.8 233.4 231.5 Long-term debt 2,159.2 1,676.4 1,657.4 1,631.8 1,626.5 Preferred shares issued by subsidiary 135.0 260.0 260.0 260.0 260.0 Non-controlling interest 39.6 0.6 0.7 0.8 0.8 Common shares 1,081.4 1,066.2 1,055.2 1,039.2 1,017.3 Contributed surplus 3.4 3.0 2.2 1.8 1.9 Accumulated other comprehensive income (69.2) (209.0) (100.2) (98.2) (82.0) Retained earnings 530.6 499.6 450.9 423.4 399.6 ------------------------------------------------------------------------- Total equity and liabilities $5,268.6 $4,221.1 $4,049.0 $3,998.6 $3,949.2 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Statements of Cash Flow Information Cash provided by operating activities $237.2 $351.4 $332.5 $151.0 $291.2 Cash used in investing activities $671.6 $288.9 $196.9 $117.2 $214.5 Cash provide by (used in) financing activities $419.7 $(55.6) $(143.4) $(55.0) $(44.0) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Financial ratios ($ per common share) Earnings per common share $1.29 $1.36 $1.14 $1.11 $1.20 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Other assets and liabilities restated to December 31, 2007 only

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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