EPCOR announces 2007 financial results



    EDMONTON, March 20 /CNW/ - EPCOR Utilities Inc. today filed its annual
and fourth quarter results for 2007.
    "EPCOR's performance in 2007 demonstrated the ability of our people
across North America to deliver on the company's strategy of growth in the
power and water industries," said EPCOR President and CEO Don Lowry. "As a
result of their efforts, EPCOR's net income was $277 million in 2007 and the
dividend increased for the seventh consecutive year. From top to bottom our
people made significant contributions through strong operational performance
in our power and water businesses, and the company's major capital projects
remained on schedule. We were also pleased to have entered into agreements to
construct and finance new water or wastewater infrastructure in the
communities of Wetaskiwin, Chestermere and Taber, and to see our wastewater
partnership with the community of Sooke, B.C. recognized with a national
award. EPCOR enters 2008 with a strong business, having more than doubled its
revenues, dividend and employee count over the past ten years, and earned
recognition as a Top 100 employer in Canada for the eighth consecutive year."

    
    Highlights of EPCOR's financial performance:

    -   Net income from continuing operations was $277 million for the year
        ended December 31, 2007 compared with $632 million for the previous
        year.
    -   Net income was $277 million on total revenues of $3.7 billion for the
        year ended December 31, 2007 compared with net income of $642 million
        on revenues of $2.9 billion for the previous year.
    -   There was no net income from discontinued operations for the year
        ended December 31, 2007 compared with $10 million for the previous
        year.
    -   Cash flow from operating activities for the year ended December 31,
        2007 was $541 million compared with $589 million for the previous
        year.
    -   Investment in capital projects and business acquisitions for the year
        ended December 31, 2007 was $531 million compared with $632 million
        for the previous year.
    -   Net income from continuing operations for the three months ended
        December 31, 2007 was $59 million compared with $17 million for the
        same period in the previous year.
    -   Net income was $59 million on revenues of $969 million for the three
        months ended December 31, 2007 compared with $17 million on revenues
        of $728 million for the same period in the previous year.
    -   Investment in capital projects and business acquisitions for the
        three months ended December 31, 2007 was $168 million compared with
        $475 million for the same period in the previous year.
    -   The common dividend payment increased to $128 million for the year
        ended December 31, 2007 from $125 million in the previous year.
    

    Management's discussion and analysis (MD&A) of the annual and fourth
quarter results for 2007 are shown below. The MD&A and the consolidated
financial statements are available on EPCOR's web-site (www.epcor.ca), and
will be available at SEDAR (www.sedar.com).
    EPCOR Utilities Inc. builds, owns and operates power plants, electrical
transmission and distribution networks, water and wastewater treatment
facilities and infrastructure in Canada and the United States. EPCOR has been
named one of Canada's Top 100 employers for eight consecutive years, and is
headquartered in Edmonton, Alberta. EPCOR's website is www.epcor.ca.

    Management's discussion and analysis

    This management's discussion and analysis (MD&A) dated March 20, 2008
should be read in conjunction with the audited consolidated financial
statements of EPCOR Utilities Inc., hereinafter "the Company", "EPCOR", "we",
"our" or "us", for the years ended December 31, 2007 and 2006. In accordance
with its terms of reference, the Audit Committee of the Company's Board of
Directors reviews the contents of the MD&A and recommends its approval by the
Board of Directors. The Board of Directors has approved this MD&A upon the
recommendation of the Audit Committee.

    FORWARD-LOOKING STATEMENTS

    Certain information in this MD&A is forward-looking and related to
anticipated financial performance, events and strategies. When used in this
context, words such as "will", "anticipate", "believe", "plan", "intend",
"target" and "expect" or similar words suggest future outcomes. By their
nature, such statements are subject to significant risks and uncertainties,
which could cause EPCOR's actual results and experience to be materially
different than the anticipated results. Such risks and uncertainties include,
but are not limited to, operating performance, commodity prices and volumes,
load settlement, regulatory and government decisions including changes to
environmental and tax legislation, weather and economic conditions,
competitive pressures, construction risks, availability and cost of financing,
foreign exchange risks, availability of labour and management resources and
the performance of partners, contractors and suppliers.
    Readers are cautioned not to place undue reliance on forward-looking
statements as actual results could differ materially from the plans,
expectations, estimates or intentions expressed in the forward-looking
statements. Except as required by law, EPCOR disclaims any intention and
assumes no obligation to update any forward-looking statement even if new
information becomes available, as a result of future events or for any other
reason.

    STRATEGY

    EPCOR builds, owns and operates power plants, electrical transmission and
distribution networks, water and wastewater treatment facilities, and
infrastructure in Alberta, British Columbia and Ontario. We also provide
energy and water services to residential and commercial customers. Through its
investment in EPCOR Power L.P. (Power LP), EPCOR also has electricity
generation operations in California, Colorado, New Jersey, New York State,
North Carolina, Washington State and Indiana. Our strategy is delivered
through an integrated structure with a portfolio of regulated and competitive
businesses. We continue to look for opportunities for growth consistent with
our balanced portfolio of businesses. By maintaining a strong base in
regulated wires and water businesses and growing our commercial electricity
and water operations, we intend to increase shareholder value as a leading
North American supplier of energy and water services.

    KEY PERFORMANCE INDICATORS

    Our performance in meeting the goals of our strategy is measured through
both financial and non-financial measures that are approved by the Board of
Directors. The measurement categories include net income, operational
excellence, safety, environment and reputation and are generally common to all
of our business units operating within each business segment, and our shared
service units.
    Within each category, there are specific measures established for each
business unit and shared service unit that are important to the results of the
respective unit and in alignment with the Company's strategy. For example, in
Generation, plant availability is the key measure of operational excellence.
In the customer service area of Energy Services, the key operational measures
relate to call answer and handle times and reputation. Environment and safety
performance are measured based on outcomes (for example, the number of
incidents and accidents) and proactive activities (for example, applicable
training) that are designed to minimize the potential for negative events such
as lost time accidents or environmental incidents. Business unit measures
under the reputation category are focused on customer related measures
relevant to the particular business unit, such as customer satisfaction survey
results.
    For 2007, EPCOR's results were ahead of target for both its non-financial
and financial performance measures.

    SIGNIFICANT EVENTS

    Keephills 3

    On February 26, 2007, EPCOR and TransAlta Corporation (Transalta)
announced their decision to build Keephills 3, a 495 megawatt (MW)
supercritical coal-fired generation plant at TransAlta's Keephills site.
Construction is expected to be completed by 2011. Our 50% committed share of
the total capital cost is estimated to be $820 million. In addition, EPCOR and
TransAlta have indemnified each other for up to $115 million during
construction in the event that either party makes payments to the turbine
supplier on behalf of the other party.

    Sale of power purchase arrangement

    On January 1, 2007, we sold a 10% interest in the Battle River Power
Syndicate Agreement (Battle River PSA) for cash proceeds of $59 million
resulting in a pre-tax gain of $34 million. The associated income taxes were
$4 million of expense and $7 million of refundable taxes which were charged to
retained earnings. This sale was pursuant to the purchase and sale agreement
entered into in June 2006 whereby EPCOR will sell its Battle River Power
Purchase Arrangement (Battle River PPA) and related interest in the Battle
River PSA to ENMAX Corporation (ENMAX) over a 4-year period ending in January
2010.
    An initial 55% interest was sold for cash proceeds of $343 million on
June 5, 2006. The Company also sold a 17.8% interest in the Sundance Power
Syndicate Agreement to other syndicate members for $57 million. These
transactions resulted in a pre-tax gain of $378 million and $51 million of
associated income tax expense.

    Energy Services reorganization

    On January 1, 2007, we reorganized our two subsidiaries within the Energy
Services segment that operate our regulated retail business. As part of the
transactions, one of the subsidiaries, which was previously exempt from income
taxes, became subject to income taxes under the Income Tax Act. Upon becoming
taxable the subsidiary recognized future income tax assets of $10 million and
a corresponding reduction in income tax expense.

    Issue of preferred shares

    In May 2007, EPCOR Power Equity Ltd. (EPEL), a subsidiary of Power LP (a
subsidiary of EPCOR), issued 5 million 4.85% cumulative, redeemable First
Preference Shares, Series 1 at a price of $25.00 per share with dividends
payable on a quarterly basis at the annual rate of $1.2125 per share. Net
proceeds of $121 million were used to repay a portion of amounts outstanding
under Power LP's bridge acquisition credit facilities which were incurred for
Power LP's acquisition of EPCOR USA Ventures LLC (Ventures), formerly Primary
Energy Ventures LLC, in November 2006. On or after June 30, 2012, the shares
are redeemable by EPEL at $26.00 per share, declining by $0.25 per share each
year to $25.00 per share after June 30, 2016. The shares are not retractable
by the holders.
    The net proceeds from the issue are included in non-controlling interests
in the consolidated balance sheet.

    Limited partnership units offering by Power LP

    In May 2007, Power LP issued 4,015,297 limited partnership units at
$26.15 per unit for net proceeds of $102 million which were also used to repay
amounts outstanding under Power LP's bridge acquisition credit facilities.
    EPCOR, through wholly-owned subsidiaries purchased 1,228,681 limited
partnership units to maintain its 30.6% interest in Power LP. The net proceeds
from the units issued to the public are included in non-controlling interests
in the consolidated balance sheet.

    Redemption of preferred shares

    On October 1, 2007, EPCOR Preferred Equity Inc., a subsidiary of the
Company, completed the redemption of 8 million Cumulative Redeemable Perpetual
First Preferred Shares, Series I at par for $200 million, funded from cash
balances and debt.
    The carrying value of the preferred shares prior to their redemption was
$197 million, reflecting $200 million less issue costs of $3 million which
were incurred when the preferred shares were issued in 2002. The $3 million
difference was charged to non-controlling interests in the consolidated
statements of income.

    Asset-backed commercial paper

    At December 31, 2007, the Company held $60 million ($71 million original
cost) in Canadian non-bank sponsored asset-backed commercial paper (ABCP), all
of which was purchased during the third quarter of 2007. The Company's ABCP is
part of the $35 billion broader ABCP market that has been disrupted by the
significant lack of liquidity that emerged in August 2007 and as a result, all
of the Company's ABCP matured with no payment of principal, accrued interest
or roll over. At the time, all of the conduits in which the Company's ABCP
investments were held were rated R-1 (high) by DBRS Limited (DBRS), which is
their highest rating for commercial paper. DBRS placed these conduits "Under
Review with Developing Implications" following an announcement on August 16,
2007 that a consortium representing banks, asset providers and major
investors, represented by the Pan-Canadian Investors Committee (Investors
Committee), had agreed in principle to a long-term proposal and interim
arrangements regarding the ABCP (the Montreal Accord). Under this proposed
restructuring, the affected ABCP would be converted into term floating-rate
notes maturing no earlier than the scheduled termination dates of the
underlying assets. During the restructuring period, no payments of principal
or accrued interest are being made on the ABCP (standstill arrangements). The
standstill arrangements under the Montreal Accord were extended to December
14, 2007 on October 15, 2007 and to January 31, 2008 on December 31, 2007 and
to February 22, 2008 on February 4, 2008.
    On December 23, 2007, the Chairman of the Investors Committee announced
the framework of the proposed restructuring of ABCP in which the Company has
investments. The proposed restructuring is expected to be completed by April
30, 2008 and its key elements as they relate to EPCOR are:

    
     (i)   exchange of ABCP for floating-rate notes (FRN);
     (ii)  separation of ABCP conduit assets that are subject to U.S. sub-
           prime mortgage exposure;
     (iii) pooling of certain ABCP conduit assets that are largely comprised
           of synthetic assets (assets other than conventional securitization
           assets such as leases and credit card receivables);
     (iv)  setting the maturity of the FRNs to match the maturities inherent
           in the underlying pooled assets which is expected to be 7 years;
     (v)   establishment of margin call facilities available to provide an
           aggregate of $14 billion of liquidity to support to the
           restructured assets;
     (vi)  modification of the margin call triggers in the ABCP conduits to
           make them more transparent and more trigger-risk remote.
    

    On March 17, 2008 the Investors Committee applied for and received court
approval for the restructuring plan to be carried out under the Companies'
Creditors Arrangement Act. DBRS consequently downgraded 20 of the affected
ABCP conduits to a "D" credit rating but re-affirmed its prior comments that
the majority of the assets held by the affected conduits remain strong. We
believe this action by DBRS is not reflective of the underlying credit quality
of our ABCP investments. Accordingly, in assessing the valuation of our ABCP,
we have considered the fundamental underlying credit ratings of our ABCP
investments.
    Under the proposed restructuring, EPCOR expects that $61 million of its
original ABCP investment cost (in two conduits) will be exchanged for FRNs
associated with the pooled synthetic asset conduit. These FRNs will be
comprised of senior and subordinated notes, the relative breakdown of which
will be determined by an assessment by JPMorgan Chase & Co., the financial
adviser to the Investors Committee. The senior notes are expected to receive
the second highest investment-grade credit rating from an independent
recognized credit rating agency. The subordinated notes may not be assigned a
credit rating, however EPCOR expects that the subordinated notes could be
investment grade.
    Under the proposed restructuring, EPCOR expects that the remaining
$10 million of its original ABCP investment cost (in one conduit) will be
subject to a separate FRN, since the conduit is considered ineligible for
pooling owing to its U.S. sub-prime mortgage exposure. These FRNs may not be
assigned a credit rating. In February 2008, DBRS downgraded the original
conduit to R-4, a speculative ratings class, but as noted by DBRS,
approximately 80% of the underlying assets of this conduit are high investment
grade.
    Due to the expected longer term repayment and ongoing uncertainties, the
ABCP investment is classified as non-current within other assets.
    ABCP is a financial instrument and has been classified as held for
trading and therefore is recorded at fair value. EPCOR has recognized a
decrease in fair value of $11 million during the year, representing the
difference between the original investment cost of $71 million and the
estimated fair value of $60 million at December 31, 2007. There are no
observable market prices for ABCP as at the balance sheet date. Accordingly,
EPCOR has estimated the fair value using a probability-weighted discounted
cash flow approach based on the assumed credit ratings and potential ratings
actions on the applicable ABCP conduits under the proposed restructuring,
observable interest rates and credit spreads for estimating future interest
payments and applicable discount rates, the cost of margin call facilities
(1.60% of the FRN investments), the cost of the proposed restructuring (0.001%
of the FRN investments), estimated recovery periods based on the estimated
lives of the underlying assets of the proposed restructuring conduits (7 years
for pooled asset FRNs and 9 years for ineligible asset FRNs) and ranges of
recoverability based on publicly available default statistics for credit-rated
entities.
    The estimate of fair value of ABCP is subject to significant risks and
uncertainties including the timing and amount of future cash payments, the
success of the proposed restructuring under the Montreal Accord, market
liquidity, the quality and tenor of the underlying assets and instruments in
the applicable conduits and the future market for the FRNs. Accordingly, the
estimate of fair value of ABCP may change materially as events unfold and more
information becomes available. The sensitivity of the estimated fair value to
changes in key valuation assumptions, holding all other assumptions constant,
is as follows:

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

                                                         Impact on estimated
                                                                  fair value
    Assumption                                  Change           ($ millions)
    -------------------------------------------------------------------------
    Amortization term                       +/- 1 year                 -/+ 1
    Interest rate on FRN or cost of
     margin call facilities                  +/- 1.00%                 +/- 4
    Credit ratings downgrade
     (increase in loss probability
     and losses realized)            3-notch downgrade            - 3 to - 5
    -------------------------------------------------------------------------
    

    If the restructuring is successful, it is possible that a secondary
market for the FRNs will develop. If that occurs, there would be observable
market prices for these investments that would be factored into our
valuations. Such prices could be subject to market volatility and therefore
could result in substantially different outcomes than our current valuation
approach.
    The estimate of fair value at December 31, 2007 of $60 million is lower
than our estimate at September 30, 2007 of $67 million primarily due to
changes in assumptions as a result of new information about the proposed
restructuring, including the estimated FRN amortization period and margin
facility costs, a ratings downgrade on one of the current conduits, and
changes in interest rates, including credit spreads.
    The Company continues to be in compliance with the financial covenants of
its credit facilities and publicly-issued debt and has sufficient credit
facilities and cash flows from operations to satisfy its financial obligations
as they come due. Based on current information, the Company does not expect
there will be a material adverse impact on its business as a result of this
current ABCP liquidity issue.

    Substantive enactment of tax rate reductions

    Effective December 14, 2007, the Government of Canada passed Bill C-28
whereby the federal corporate income tax rate is scheduled to be reduced in
increments over the period from January 1, 2008 to December 31, 2012, for a
total reduction of 3.5 percentage points. These rate reductions were in
addition to those included in the Government of Canada's Bill C-52 which was
enacted on June 22, 2007. The effect of Bill C-52 was to reduce the general
corporate income tax rate from 19% to 18.5% commencing January 1, 2011.
    As a result, we reduced the amount of future income tax balances by
$1 million in the second quarter and $12 million in the fourth quarter, with
corresponding increases in future income tax expense. The charge in the fourth
quarter was composed of an $18 million charge for reductions in net future
income tax assets partly offset by a $6 million future income tax recovery
relating to future income tax balances for Power LP.

    
    CONSOLIDATED FINANCIAL INFORMATION
    -------------------------------------------------------------------------
    ($ millions)                                  2007       2006       2005
    -------------------------------------------------------------------------
    Revenues                                    $3,663     $2,931     $2,640
    Net income from continuing operations          277        632        159
    Net income from discontinued operations          -         10         28
    Net income                                     277        642        187
    Total assets                                 6,539      6,383      5,664
    Long-term debt                               2,139      2,179      2,083
    Common share dividends                         128        125        123
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Analysis of net income

    -------------------------------------------------------------------------
    Net income from continuing operations
     for the year ended December 31, 2005                             $  159
    Net income from discontinued operations                               28
    -------------------------------------------------------------------------
    Net income for the year ended
     December 31, 2005                                                $  187
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income from continuing operations
     for the year ended December 31, 2005                             $  159
    Gain on sale of Battle River PSA and
     related transactions                                                327
    Impact of recording a net future income
     tax asset associated with the restructuring
     of EPCOR Generation Inc. on January 3, 2006                         117
    2005 PILOT settlement adjustment                                      38
    Higher income from combined operations of
     Genesee 3, Calpine, Kingsbridge I and
     Joffre                                                               25
    Higher realized gains on forward foreign
     exchange contracts                                                   17
    Lower financing expenses and preferred
     share dividends excluding Power LP financing                         11
    Regulatory decisions for 2005 distribution
     and transmission tariffs and 2005 RRT non-
     energy charges received in 2006                                       7
    Higher water rates                                                     7
    Cumulative translation account adjustment
     for the sale of Frederickson to Power LP
     in 2006                                                              (6)
    2005 gain on sale of Alberta competitive
     electricity contracts and favourable
     settlement of litigation                                            (13)
    Lower Ontario electricity margins                                    (21)
    2006 impact of income tax rate reductions
     on future income tax assets and liabilities                         (39)
    Other                                                                  3
    -------------------------------------------------------------------------
    Increase in net income from continuing
     operations                                                          473
    -------------------------------------------------------------------------
    Net income from continuing operations for
     the year ended December 31, 2006                                    632
    Net income from discontinued operations                               10
    -------------------------------------------------------------------------
    Net income for the year ended December 31,
     2006                                                             $  642
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income from continuing operations for
     the year ended December 31, 2006                                 $  632
    Impact of 2006 and 2007 income tax rate
     reductions on future income tax assets
     and liabilities, excluding Power LP                                  20
    Higher water rates                                                    16
    Lower financing expenses and preferred
     share dividends excluding Power LP financing                         15
    Impact of recording a net future income tax
     asset associated with the Energy Services
     reorganization on January 1, 2007                                    10
    Fair value changes in unhedged electricity
     positions and foreign exchange contracts                              8
    Higher income from Power LP                                            8
    Cumulative translation account adjustment
     for the sale of Frederickson to Power LP
     in 2006                                                               6
    Lower maintenance costs on Genesee 1 and 2                             5
    Regulatory decisions for 2005 distribution
     and transmission tariffs and 2005 RRT
     non-energy charges received in 2006                                  (7)
    Impact of forward foreign exchange contract
     settlements                                                         (18)
    Impact of recording a net future income tax
     asset associated with the restructuring
     of EPCOR Generation Inc. on January 3, 2006                        (117)
    Gain on sale of Battle River PSA and related
     transactions                                                       (297)
    Other                                                                 (4)
    -------------------------------------------------------------------------
    Decrease in net income from continuing
     operations                                                         (355)
    -------------------------------------------------------------------------
    Net income from continuing operations for
     the year ended December 31, 2007                                    277
    Net income from discontinued operations                                -
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2007                   $  277
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income from continuing operations for the year ended December 31, 2007
was $277 million compared with $632 million for 2006. Net income from
continuing operations decreased by $355 million for the year ended December
31, 2007 compared with the previous year primarily due to the sale of an
interest in the Battle River PSA and related transactions in June 2006, partly
offset by the sale of a further interest in January, 2007 as described under
Significant Events. The reorganization of the Generation subsidiaries in
January 2006, as described below, also contributed to the decrease. Excluding
these transactions, net income from continuing operations increased by
$59 million due to the net impact of the following:

    -   In June and December 2007, the Government of Canada substantively
        enacted tax legislation which reduced general corporate income tax
        rates as described under Significant Events. On April 10, 2006 and
        June 6, 2006, the Government of Alberta and the Government of Canada,
        respectively, reduced corporate income tax rates. The impact of these
        rate reductions on our future income tax assets and liabilities
        resulted in a $32 million charge to net income. This charge was
        composed of $39 million for reductions in net future income tax
        assets partly offset by a $7 million future income tax recovery
        relating to future income tax balances for Power LP. The impact of
        the 2007 and 2006 income tax rate reductions relating to Power LP is
        included as an offset to the higher income from Power LP in the table
        above.

    -   Water revenue was higher in 2007 compared with 2006 primarily due to
        increased rates as approved by The City of Edmonton.

    -   Financing expenses, excluding financing for Power LP, decreased
        primarily due to interest earned on higher cash balances in the first
        half of 2007, repayment in the third quarter of 2006 of the loan
        issued under a 3-year credit facility, and scheduled repayments of
        obligations to The City of Edmonton and non-recourse debt. The
        Company capitalizes an allowance for funds used during construction
        (AFUDC) to provide for the cost of capital invested in rate-regulated
        construction activities. AFUDC was higher in 2007 than in 2006 for
        the E.L. Smith water treatment plant (EL Smith) upgrade project.
        Capitalized interest on commercial construction activities was higher
        in 2007 for the Keephills 3 and Clover Bar Energy Centre generation
        projects. Preferred share dividends decreased due to the redemption
        of subsidiary Series A preferred shares on June 30, 2006 and EPEI
        preferred shares on September 30, 2007. In addition, in June 2007 the
        Government of Canada substantively enacted an effective income tax
        rate reduction relating to preferred share dividends paid since 2002
        resulting in a decrease in non-controlling interests. These decreases
        were partly offset by the reduction in fair value of third-party ABCP
        that was recognized in 2007.

    -   Favourable fair value changes in the Alberta merchant and wholesale
        electricity positions were recognized in 2007 due to an increase in
        financial contracts for the forward sales of power (financial sales)
        which hedged anticipated energy revenues and were not designated as
        hedges for accounting purposes, combined with decreasing forward
        Alberta power prices in the second half of the year. In 2006, the
        fair value changes were unfavourable due to increased Alberta power
        forward prices. The increase in 2007 in the volume of financial sales
        contracts that were not designated as hedges for accounting purposes
        was due to the decrease in generation resulting from our reduced
        interest in the Battle River PSA and a planned outage at the
        Genesee 3 facility. These variances were partly offset by fair value
        losses on forward contracts for the purchase of U.S. dollars due to a
        weakening U.S. dollar in 2007, and lower fair value gains on the
        Joffre Cogeneration Project (Joffre) contract-for-differences (CfD)
        due to less significant changes in Alberta natural gas and power
        forward prices in 2007.

    -   Net income from Power LP was higher in 2007 compared with the prior
        year primarily due to foreign exchange gains on the translation of
        Power LP's $US-denominated monetary assets and liabilities due to a
        strengthening Canadian dollar relative to the U.S. dollar in 2007.

        The foreign exchange gains were partly offset by a decline in the
        fair value of the natural gas supply contracts for Power LP's Ontario
        generation plants. These fair value adjustments were required by the
        new accounting standard for financial instruments. The contracts did
        not qualify for the designation under the accounting standard as
        expected purchase and use contracts and therefore were measured at
        fair value. There was no comparable adjustment in 2006 as the new
        accounting standard was effective January 1, 2007.

        In 2007, Power LP had higher interest expense on debt used to finance
        the 2006 acquisition of Ventures and on capital lease obligations
        assumed as part of the acquisition. Power LP recognized an impairment
        charge in the third quarter of 2007 in respect of certain Ventures
        management contracts, and experienced lower generation and pricing at
        its Curtis Palmer plant in 2007 compared with 2006.

        The impact of income tax rate reductions on future income tax
        balances for Power LP was a $6 million recovery in 2007 and a
        $7 million recovery in 2006.

    -   On August 1, 2006 the Company sold its interest in the Frederickson
        power plant (Frederickson) to Power LP. The recognition of previously
        deferred foreign exchange losses on the investment in Frederickson
        was partly offset by the recognition of a foreign exchange gain on
        repayment of the U.S. dollar debt designated as a hedge of the net
        investment in the foreign operations. The result was a net foreign
        exchange loss of $6 million in 2006. There was no comparable event or
        transaction in 2007.

    -   Maintenance costs for Genesee 1 and Genesee 2 were lower in 2007 due
        to changes in plant outage profiles. The scheduled plant outage at
        Genesee 2 lasted 24 days in 2006 whereas the Genesee 1 scheduled
        plant outage in 2007 lasted only 7 days.

    -   In the second quarter of 2006, the Alberta Utilities Commission (AUC,
        formerly Alberta Energy and Utilities Board) issued its decisions
        relating to our general tariff applications for electricity
        transmission, distribution and Regulated Rate Tariff (RRT) services
        in respect of the period from January 1, 2005 through December 31,
        2006. The effect of these decisions relating to the period from
        January 1, 2005 to June 30, 2006 was recognized in the second quarter
        of 2006, of which $7 million related to 2005 service. There was no
        comparable rate decision in 2007.

    -   In 2007, net losses were realized on forward foreign exchange
        contracts used to hedge the purchase of generation assets with
        foreign currencies, whereas net gains were realized in 2006.

    -   The January 3, 2006 reorganization of the Generation subsidiaries
        resulted in the recognition of a future income tax asset associated
        with additional deductions available for income tax purposes, partly
        offset by the write-off of future income tax balances associated with
        the Alberta government's Payment in Lieu of Tax (PILOT) Regulation,
        thereby increasing income in 2006 by $117 million.


    Net income and net income from discontinued operations
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2006                   $  642
    Decrease in net income from continuing operations -
     see previous table                                                 (355)
    Decrease in income from operation of the Clover Bar
     generation plant                                                    (10)
    -------------------------------------------------------------------------
    Decrease in net income                                              (365)
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2007                   $  277
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    -   In 2006, the estimate of costs to decommission the Clover Bar
        generation facility was reduced resulting in $10 million of income
        from discontinued operations.


    Revenues
    -------------------------------------------------------------------------
    Revenues for the year ended December 31, 2005                   $  2,640
    Higher Power LP revenues                                             246
    Unrealized fair value changes in derivative
     financial instruments                                                57
    Higher natural gas trading                                            56
    Regulatory decisions for 2005 distribution
     and transmission tariffs and 2005 RRT non-energy
     charges received in 2006                                              9
    Lower energy revenues                                                (41)
    2005 gain on sale of Alberta competitive
     electricity contracts and settlement of litigation                  (21)
    Commercial and other sales                                           (15)
    -------------------------------------------------------------------------
    Increase in revenues                                                 291
    -------------------------------------------------------------------------
    Revenues for the year ended December 31, 2006                      2,931
    Higher natural gas trading activities                                381
    Higher Power LP revenues                                             229
    Higher energy trading activities in the western
     U.S. region                                                          67
    Unrealized fair value changes on derivative
     instruments                                                          17
    Higher water revenues                                                 17
    Higher other energy revenues                                           9
    Regulatory decisions for 2005 distribution and
     transmission tariffs and 2005 RRT non-energy
     charges received in 2006                                              9
    Commercial and other sales                                            21
    -------------------------------------------------------------------------
    Increase in revenues                                                 732
    -------------------------------------------------------------------------
    Revenues for the year ended December 31, 2007                   $  3,663
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Revenues increased $732 million in 2007 compared with 2006 due to the
following:

    -   Power LP revenues were higher in 2007 primarily due to the
        acquisition of Ventures on November 1, 2006 and Frederickson on
        August 1, 2006 as well as favourable changes in the fair value of
        foreign exchange contracts used to hedge operating cash flows. The
        sale of Frederickson to Power LP had no impact on consolidated
        revenues and the offsetting decrease in revenues is included in the
        other energy revenues in the table above. These increases were partly
        offset by the non-recurrence of a settlement received from the
        Ontario Electricity Financial Corporation (OEFC) in the first quarter
        of 2006 and lower generation and pricing at the Curtis Palmer
        facility in 2007.

    -   Energy trading activities in the western U.S. region include new
        trading activities in the California market.

    -   The unrealized fair value changes on the Joffre CfD were
        insignificant in 2007 whereas they were unfavourable in 2006 due to
        significant changes in natural gas and power forward prices in
        Alberta. Unrealized fair value gains resulting from an increase in
        the volume of Alberta financial sales contracts that were not
        designated as hedges for accounting purposes, combined with a
        decrease in forward Alberta power prices in the second half of the
        year also resulted in higher revenues. The financial sales contracts
        were used to hedge anticipated energy revenues. The unrealized fair
        value gains on these contracts were offset by lower unrealized fair
        value gains on Ontario financial sales contracts resulting from
        significantly decreased trading activity in the Ontario market.

    -   Water revenues were higher in 2007 compared with 2006 primarily due
        to increased rates as approved by the regulator, The City of
        Edmonton.

    -   Other energy revenues include favourable settlements of financial
        sales contracts resulting from higher contract prices and increased
        volume. Revenues from RRT customers increased due to higher pricing.
        These increases were partly offset by a decrease in generation
        related to our reduced interest in the Battle River PSA, expiry of
        the short-term tolling arrangement with Calpine Power Income Fund
        (Calpine) and the sale of Frederickson to Power LP.

    -   Commercial and other sales were higher primarily due to an increase
        in streetlight and traffic signal construction activities for The
        City of Edmonton, new water and wastewater treatment facilities and
        infrastructure construction projects for third parties, and
        construction work for Distribution and Transmission's Downtown
        Edmonton Supply and Substation (DESS) project. Our Transportation
        department in the Water Services segment was contracted for some of
        the work on the DESS project and the intercompany profit was not
        eliminated from consolidated revenues as the transfer price for the
        constructed facilities is recognized for rate-making purposes as a
        valid cost of construction by the AUC, Distribution and
        Transmission's regulator.


    Capital spending and investment

    -------------------------------------------------------------------------
    ($ millions)                                  2007       2006       2005
    -------------------------------------------------------------------------

    Generation                                   $ 240       $ 63      $ 124
    Distribution and Transmission                  105         61         61
    Energy Services                                 12         11          8
    Water Services                                 122        104         51
    Corporate - other                               20         19          6
    -------------------------------------------------------------------------
                                                   499        258        250
    Investment in Primary Energy
     Ventures LLC                                    -        371          -
    Investment in Power LP                          32          -        534
    Other investment                                 -          3          -
    -------------------------------------------------------------------------
                                                $  531     $  632     $  784
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Capital expenditures for property, plant and equipment increased in 2007
primarily due to increased investments in Generation and, Distribution and
Transmission.
    EPCOR and TransAlta commenced construction of Keephills 3, a 495 MW
generation plant as described under Significant Events. EPCOR's capital
expenditures on Keephills 3 were $142 million in 2007 and $10 million in 2006.
    In December 2006, the AUC approved our proposal to construct three
natural-gas-fired peaking power generation units for an aggregate gross
generating capacity of 243 MWs at our Clover Bar Energy Centre site in
northeast Edmonton. The first 43 MWs were commissioned in February 2008 with
subsequent capacity to come on line by late 2010. Capital expenditures on the
Clover Bar Energy Centre were $61 million in 2007 and $2 million in 2006.
    In the first quarter of 2007, Distribution and Transmission commenced
construction of the DESS project which consists of a new high-voltage
transmission line that will supply electricity to downtown Edmonton. Capital
expenditures on this project were $40 million in 2007 and $5 million in 2006.
Water Services' construction on the EL Smith upgrade continued in 2007 with
capital expenditures of $61 million in 2007 and $60 million in 2006. Both
projects are scheduled for completion in 2008.
    In May 2007, EPCOR purchased $32 million of Power LP limited partnership
units to maintain its 30.6% ownership interest in Power LP, as described under
Significant Events. On November 1, 2006, Power LP acquired 100% of Ventures
for $366 million (US$326 million) plus acquisition costs of $5 million for a
total purchase price of $371 million.

    SEGMENT RESULTS

    Generation

    Generation operates more than 3,400 MW of generating capacity produced
from 34 generating stations in Alberta, British Columbia, Ontario, Colorado,
New York State, Washington State, California, New Jersey, North Carolina and
Indiana.
    The facilities owned by EPCOR include two generating units in Alberta
that are subject to Power Purchase Arrangements (PPAs) and have a generating
capacity of 820 MW. We also own 673 MW of coal-fired, gas-fired,
hydro-electric, wind-powered and landfill gas-fired commercial generating
capacity through six additional plants in Alberta, 40 MW of commercial
generating capacity from two hydro-electric plants in British Columbia and
approximately 40 MW of commercial generating capacity from a wind-powered
project in Ontario.
    Generation, as the manager, has the contractual right and obligation to
operate Power LP's portfolio of 12 power generation plants in Canada and the
U.S. with electric capacity of 869 MW, and a further 8 combined heat and power
facilities in the U.S. with electric capacity of approximately 418 MW and a
thermal energy capacity of approximately 3 million pounds per hour (lbs/hr).
These power plants generate electricity from natural gas, waste heat, wood
waste, water flow, coal and tire-derived fuel. Power LP also has a 15.4%
equity interest in Primary Energy Recycling Holdings (PERH). The PERH power
plants have an electric capacity of approximately 283 MW and a thermal
capacity of approximately 2 million lbs/hr.
    The Genesee 1 and Genesee 2 power generation units, which were previously
rate-regulated through annual tariff applications, became subject to PPAs
effective January 1, 2001 and continue to be rate-regulated by the guidelines
of the Electric Utilities Act (Alberta). The electricity generated from these
units is provided to the Alberta Balancing Pool as the PPA holder. In exchange
for the rights to the electricity, we receive formula-based fixed capacity and
variable payments which are intended to provide us with a reasonable
opportunity to recover unit operating costs, a formula-based provision for
income taxes and a rate of return on investment. The return on equity
component is set at 4.5% over the rate of long-term Canada bonds. In addition,
we receive incentives and pay penalties when the output available from the
generation unit exceeds or falls below target availability levels set out in
the PPAs. The target availability levels were originally set with the
expectation that the incentives and penalties would net to zero over the life
of the PPAs. EPCOR's Clover Bar and Rossdale plants also became subject to
PPAs in 2001 but those PPAs are no longer in effect.
    Although the units operating under PPAs are rate-regulated, they do not
meet the criteria for rate-regulated accounting under generally accepted
accounting principles. Accordingly, the generation units are accounted for as
unregulated facilities in accordance with the commercial terms and conditions
inherent in the PPAs. Key to the earnings performance of generation units
operating under PPAs is managing the costs of the units and ensuring that they
are able to meet or exceed the target availability levels.
    The Clover Bar PPA was terminated effective September 30, 2005 at which
time decommissioning of the plant commenced. All operating results relating to
the Clover Bar facility subsequent to the PPA termination were reported under
discontinued operations and excluded from the Generation segment results. The
plant was decommissioned in 2007.
    The Rossdale PPA expired on December 31, 2003 and the plant was operated
as a commercial generation unit throughout 2004. An ancillary services
contract with the Alberta Electric System Operator (AESO) for continued
operation of the Rossdale plant was finalized in 2005. The agreement defers
decommissioning of the Rossdale generation plant until 2009 to provide ongoing
transmission system reliability for the city of Edmonton and back-up
generating capacity for the province of Alberta.
    Electricity generated from commercial generation plants is sold either
under long-term contracts to creditworthy third parties or into the wholesale
market where the plant is located. Our general objective is to contract the
majority of our non-base-loaded commercial plants' capacity. Key to the
earnings of these plants is ensuring that the plants are dispatched (directed
to supply electricity to the power grid) as economically as possible, as well
as ensuring that operating costs, including fuel, are appropriately controlled
and that the plants are well maintained.


    
    Generation operating income

    -------------------------------------------------------------------------
    Year ended December 31                                   2007       2006
    -------------------------------------------------------------------------
    Generation results
    (including intersegment transactions, $ millions)
    Revenues                                              $ 1,016      $ 777
    Expenses  Energy purchases and fuel                       312        102
              Operations, maintenance, administration
               and foreign exchange                           148        176
              Franchise fees and taxes other than
               income taxes                                    17         18
              Depreciation, amortization and asset
               retirement accretion                           172        151
    -------------------------------------------------------------------------
                                                              649        447
    -------------------------------------------------------------------------
    Operating income before corporate charges                 367        330
    Corporate charges                                          45         26
    -------------------------------------------------------------------------
    Operating income                                       $  322     $  304
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Operating income for the year ended December 31,
     2006                                                             $  304
    Higher Power LP operating income                                      59
    Write-down of project capital costs in 2006                            8
    Lower maintenance costs on Genesee 1 and 2                             7
    Cumulative translation account adjustment for
     the sale of Frederickson to Power LP in 2006                          6
    Lower PPA capacity payments                                           (5)
    Realized foreign exchange loss                                       (18)
    Unrealized fair value changes in derivative
     financial instruments                                               (43)
    Other                                                                  4
    -------------------------------------------------------------------------
    Increase in operating income                                          18
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2007             $  322
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the year ended December 31, 2007, Generation's operating income
increased by $18 million from the prior year primarily due to the following:

    -   Power LP contributed $141 million of operating income in 2007
        compared with $82 million in 2006 due to the impact of the Ventures
        and Frederickson acquisitions commencing on their respective purchase
        dates of November 1, 2006 and August 1, 2006. Revenues and expenses
        from Power LP increased $229 million and $170 million, respectively,
        from 2006 to 2007. The sale of Frederickson to Power LP had no impact
        on consolidated results and the offsetting decrease in operating
        margin is included in the unfavourable other variance in the table
        above.
    

    Power LP's revenues were also impacted by favourable changes in the fair
value of forward foreign exchange contracts, partly offset by the non-
recurrence of the settlement payment received from the OEFC and recognized in
the first quarter of 2006, and lower revenues from the Curtis Palmer plant in
2007.
    Power LP's expenses also increased due to unfavourable fair value changes
in its natural gas supply contracts. An impairment charge in respect of
certain Ventures management contracts was recognized in the current year with
no corresponding amount in the prior year. These increases were partly offset
by unrealized foreign exchange gains in 2007 on the translation of higher U.S.
dollar debt balances for the Frederickson and Ventures acquisitions, which
were due to a strengthening Canadian dollar relative to the U.S. dollar.

    
    -   Capital costs related to a project at the Frederickson generating
        plant were written down in 2006 as the project was cancelled. Capital
        costs related to the Kingsbridge II project were also written down in
        2006 as the project is being re-examined.

    -   Maintenance costs were lower in 2007 as the plant outage for
        Genesee 2 lasted 24 days in 2006 whereas the Genesee 1 outage in 2007
        had a reduced scope and lasted only 7 days.

    -   In accordance with the PPAs for Genesee 1 and Genesee 2, we receive
        capacity payments from the Alberta government's Balancing Pool.
        Income taxes, based on statutory rates, and the PPA rate base are two
        of the factors in the formula for determining capacity payments and
        reductions in both of these variables resulted in lower payments in
        2007 compared with 2006.

    -   The Company realized losses on foreign exchange contracts entered
        into in anticipation of asset purchases related to the Clover Bar
        Energy Centre and Keephills 3 projects, due to a strengthening
        Canadian dollar. In comparison, the Company realized gains on EURO
        forward foreign exchange contracts related to the Kingsbridge I and
        II projects in 2006.

    -   The generation from the Joffre plant is subject to a CfD which is a
        financial agreement whereby the difference between the cost of
        electricity at spot prices and variable operating costs for the
        contracted volume, is remitted by one counterparty to the other. In
        2007, the unrealized fair value changes on the CfD were
        insignificant. However, in 2006, they decreased revenues and expenses
        by $18 million and $45 million respectively, due to significant
        changes in Alberta natural gas and power forward prices.

    Unrealized fair value changes on foreign exchange contracts entered into
in anticipation of asset purchases related to the Clover Bar Energy Centre and
Keephills 3 generation projects decreased operating income and increased
expenses year over year by $16 million due to a strengthening Canadian dollar.
These foreign exchange contracts are expected to substantially hedge the
economic changes caused by foreign currency movements on these asset
purchases. However, they have not been recognized as hedges for accounting
purposes.

    -------------------------------------------------------------------------
                                                             2007       2006
    Electricity generation (000s of megawatt-hours)
    Generation units owned by EPCOR
      Coal generation units                                 8,147      8,136
      Natural gas generation units                            305        451
      Hydro and wind generation units                         316        250
    -------------------------------------------------------------------------
                                                            8,768      8,837
    -------------------------------------------------------------------------
    Generation units owned by Power LP
      Natural gas or waste heat units                       3,495      1,934
      Wood waste or waste heat units                        1,387        817
      Hydro generation units                                  574        648
    -------------------------------------------------------------------------
                                                            5,456      3,399
    -------------------------------------------------------------------------
      Total                                                14,224     12,236
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                             2007       2006
    Generation plant availability (%)
    Generation units owned by EPCOR
      Coal generation units                                    97         96
      Natural gas generation units                             96         94
      Hydro and wind generation units                          88         93
    Generation units owned by Power LP
      Natural gas or waste heat generation units               93         96
      Coal/tire-derived fuel, wood-waste or waste-heat
       generation units                                        95         95
      Hydro generation units                                   89         91
    -------------------------------------------------------------------------
      Total                                                    95         95
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Generation maintains a fleet of high quality power plants with good
geographic, fuel source and counterparty diversification. We have a strong
track-record of maximizing efficiency, productivity and reliability of our
facilities. The overall availability of our facilities was 95% in both 2007
and 2006. The lower availability of EPCOR's hydro and wind generation units
was due to an increase in planned outages in 2007. The lower availability of
Power LP's hydro units was due to an increase in outages at the Curtis Palmer
and Mamquam plants in 2007.
    Generation will continue to operate and safely maintain EPCOR's
generation assets. In 2008, all three Genesee units will be required to shut
down to accommodate AESO's upgrade of the high-voltage transmission lines in
the Genesee Keephills area. Based on negotiations with AESO, EPCOR expects to
be compensated for certain direct and indirect costs of the outage.
    The Company continues to pursue commercially and environmentally viable
acquisition and development opportunities for generation plants to help grow
the business in both Canada and the U.S. The Company has commenced
construction of three new gas-fired generating units at the Clover Bar Energy
Centre site and commercial operations at one of the units began in February
2008. The other two units are scheduled for completion by the end of 2010. In
2007, the Company and TransAlta started the development and construction of
Keephills 3, a 495 MW supercritical coal-fired generation plant at TransAlta's
Keephills site with completion targeted for 2011. These generation plants will
assist in providing capacity to Alberta's electric system and provide
additional growth for EPCOR. The Company continues to review the design and
schedule of the Kingsbridge II wind farm.

    Distribution and Transmission

    Distribution and Transmission earns income principally by transmitting
high-voltage electricity from generation plants to points of distribution and,
from there, distributing low-voltage electricity to retailers' end-use
customers. Our distribution and transmission assets are located in and around
The City of Edmonton and are regulated by the AUC. We earn provincially
regulated distribution and transmission tariffs intended to allow us to
recover our prudent costs and earn a fair rate of return on our distribution
and transmission infrastructure. Effective January 1, 2007 the AUC approved
the merger of distribution assets with transmission assets into a new legal
entity, EPCOR Distribution and Transmission Inc. (EDTI) to improve
efficiencies and create cost savings that will flow back to the consumer.
Distribution and Transmission is also responsible for meter reading for all
electricity suppliers within The City of Edmonton service area and acting as
the load settlement agent for The City of Edmonton.

    
    Distribution and Transmission operating income

    -------------------------------------------------------------------------
    Year ended December 31                                   2007       2006
    -------------------------------------------------------------------------
    Distribution and Transmission results
    (including intersegment transactions, $ millions)
    Revenues     Distribution                              $  201     $  206
                 Transmission                                  36         40
                 Commercial and other                          10         12
    -------------------------------------------------------------------------
                                                              247        258
    -------------------------------------------------------------------------
    Expenses     Energy purchases and fuel                     72         79
                 Operations, maintenance, administration
                  and foreign exchange                         56         59
                 Franchise fees and taxes other than
                  income taxes                                 39         38
                 Depreciation, amortization and asset
                  retirement accretion                         27         26
    -------------------------------------------------------------------------
                                                              194        202
    -------------------------------------------------------------------------
    Operating income before corporate charges                  53         56
    Corporate charges                                          14         13
    -------------------------------------------------------------------------
    Operating income                                       $   39     $   43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2006             $   43
    2005/2006 regulatory decisions for distribution and
     transmission tariffs                                                 (6)
    Operations, maintenance and administration and other                   2
    -------------------------------------------------------------------------
    Decrease in operating income                                          (4)
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2007             $   39
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the year ended December 31, 2007, Distribution and Transmission
operating income decreased $4 million from the prior year. The 2005/2006 rate
decision was received in June 2006 and resulted in the recognition of
$8 million of revenue and $2 million of administration expenses relating to
2005. Energy purchases were lower due to increased Balancing Pool rebates from
the AESO and reduced transmission charges.

    -------------------------------------------------------------------------
                                                             2007       2006
    Distribution reliability and volumes
    Reliability (system average interruption duration
     index in hours)                                         1.14       0.73
    Electricity distribution (000s of megawatt-hours)       7,076      7,096
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The strategic focus of Distribution and Transmission continues to be
operational excellence. Reliability rates for our Edmonton distribution system
continue to be among the best in Canada. Our primary measure of distribution
system reliability is System Average Interruption Duration Index (SAIDI) which
we attempt to minimize. This measure captures the annual average number of
hours of interruption experienced by our customers, including scheduled and
unscheduled interruption to our primary distribution circuits. In 2007, we
experienced a SAIDI of 1.14 hours compared with 0.73 hours in 2006. This
increase was primarily due to unusually bad weather in 2007 including three
major storms and a significant increase in the number of failed underground
cables on EDTI's system. Commencing in 2008, EDTI is undertaking an aggressive
program to rejuvenate or replace a number of aging underground cables which
are experiencing failures. Electricity distribution volumes decreased modestly
from 2006 to 2007 due to the loss of three large industrial customers, partly
offset by higher consumption resulting from population growth in the Edmonton
region.
    Distribution and Transmission's earnings and cash flow are driven from
its rate base, which requires continuous maintenance and upgrading to
accommodate growth in The City of Edmonton. Distribution and Transmission will
complete the DESS project and will be adding a new substation at the Clover
Bar Energy Centre site in 2008. Once complete, these investments will be added
to Distribution and Transmission's rate base and provide additional earnings
and cash flows. Distribution and Transmission is reviewing transmission
expansion opportunities in the Heartland area northeast of Edmonton. An
increase in electricity demand is forecasted for the region due to rapid
industrial growth. We are reviewing route selection and construction
opportunities for one or more transmission lines to service the area.

    Energy Services

    Energy Services earns income from the supply of electricity and to a
lesser extent natural gas, to end-use customers in Alberta. Electricity
revenues are earned at regulated rates from RRT customers and at rates set by
competitive retail contracts to commercial and industrial customers, both
designed to cover the costs of supplying electricity (including the costs of
the commodity, credit risk, and volume risks) and provide an appropriate
margin. Natural gas revenues are earned under competitive retail contracts. In
addition, Energy Services has wholesale contracts with Alberta Energy Savings
Limited Partnership (AESLP) to supply their retail customers with both natural
gas and electricity.
    Energy Services also manages our overall electricity and natural gas
portfolio in all markets in which we operate. To balance supply and demand,
electricity and natural gas are purchased and sold under physical and
financial transactions with the objective of matching volumes and terms or
taking positions within limits established under prudent risk management
policies. Electricity supply is also provided through EPCOR's interests in the
Sundance and Battle River PPAs and EPCOR's merchant plants, Genesee 3 and
Joffre. The electricity from all these sources is used to help balance and
optimize the Company's electricity portfolio and satisfy customer electricity
requirements. As part of its mandate, Energy Services also participates in the
ancillary services (electricity reserves) market with its merchant plants.

    
    Energy Services operating income

    -------------------------------------------------------------------------
    Year ended December 31                                   2007       2006
    -------------------------------------------------------------------------
    Energy Services results
    (including intersegment transactions, $ millions)
    Revenues     Energy revenues                         $  2,382   $  1,926
                 Commercial and other                          35         37
    -------------------------------------------------------------------------
                                                            2,417      1,963
    -------------------------------------------------------------------------
    Expenses     Energy purchases                           2,149      1,745
                 Operations, maintenance, administration
                  and foreign exchange                         80         79
                 Depreciation, amortization and asset
                  retirement accretion                         30         28
    -------------------------------------------------------------------------
                                                            2,259      1,852
    -------------------------------------------------------------------------
    Operating income before corporate charges                 158        111
    Corporate charges                                          26         22
    -------------------------------------------------------------------------
    Operating income                                     $    132   $     89
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2006           $     89
    Unrealized fair value increases in derivative
     financial instruments                                                63
    Lower Ontario electricity margins                                     (3)
    Lower Alberta electricity margins                                     (3)
    Higher operations, administration, foreign exchange and
     corporate charges for non-regulated operations                      (10)
    Other                                                                 (4)
    -------------------------------------------------------------------------
    Increase in operating income                                          43
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2007           $    132
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    For the year ended December 31, 2007, Energy Services' operating income
increased by $43 million from the prior year due to the net impact of the
following:

    -   The unrealized fair value changes in our financial electricity
        contracts were favourable compared with the prior year due to an
        increase in financial sales contracts in our Alberta portfolio that
        were not designated as hedges for accounting purposes and were
        entered into during the first half of the year. The volume of these
        instruments that were not designated as hedges for accounting
        purposes was higher in 2007 due to decreased generation resulting
        from our reduced interest in the Battle River PSA. The favourable
        change in fair value was due to a net short position for the
        financial electricity contracts held in 2007, combined with decreased
        forward Alberta power prices in the second half of the year. In 2006
        the financial electricity contracts were in a net short position
        while forward Alberta power prices increased resulting in unrealized
        fair value losses.

        Energy revenues and purchases relating to unrealized fair value
        changes in our derivative instruments were lower in 2007 than in 2006
        by $1 million and $64 million, respectively. Energy Services
        significantly reduced its trading activity in the Ontario power
        market which reduced both revenues and expenses. However, the
        decrease in energy revenue was partly offset by increases in
        financial sales contracts in the Alberta market that were not
        designated as hedges for accounting purposes.

    -   Ontario electricity margins were lower due to the expiry in 2007 of a
        number of our contracts with wholesale customers and contracts for
        the supporting power supply.

    -   Alberta electricity margins were lower in 2007 compared with 2006 due
        to our reduced interest in the Battle River PSA. We also did not have
        the benefit of the short-term tolling arrangement with Calpine for
        the operation of their Calgary Energy Centre which was in place for
        most of 2006.

        The Genesee 3 facility is operated by the Generation segment under a
        tolling arrangement with Energy Services, whereby Energy Services
        pays a fixed capacity fee plus a variable cost fee in exchange for
        the right to control the dispatch of generation from the facility.
        Margins from Genesee 3 were lower in 2007 due to reduced generation
        resulting from an outage in October 2007 and other de-rates earlier
        in the year.

        Income from our Joffre facility depends on the plant's spark spread
        which represents the difference between Alberta power prices and the
        rate for variable costs, primarily the cost of natural gas, required
        to produce electricity. If the price of power is higher than the cost
        of natural gas to produce electricity, the spark spread is favourable
        and vice versa. Income from our Joffre facility was lower in 2007
        compared with 2006 due to a lower spark spread.

        Energy margins from our RRT customer base were lower in 2007 compared
        with 2006 primarily due to changes in the Energy Price Setting Plan
        (EPSP) for energy charges effective July 1, 2006.

        These decreases in Alberta electricity margins were partly offset by
        a higher volume of financial sales contracts which settled at higher
        contract prices compared with the prior year, combined with a lower
        Alberta power price.

    -   Alberta electricity revenues and purchases increased primarily due to
        the higher volume of financial contracts which settled at higher
        prices. Pricing for RRT energy revenues and purchases were higher
        under the new Regulated Rate Option (RRO) and EPSP, effective July 1,
        2006, but did not result in a higher margin. These increases in
        Alberta electricity revenues and purchases were partly offset by
        lower rates for non-energy charge revenues, our reduced interest in
        the Battle River PSA, lower generation from Genesee 3, the absence of
        the Calpine short-term tolling arrangement and lower prices for
        purchases from the Alberta Power Pool.

    -   Higher natural gas trading activities also contributed to higher
        energy sales and purchases, but had minimal impact on energy margins.

    -   During 2007, merchant trading activities were entered into for the
        first time in the Pennsylvania, New Jersey, Maryland and California
        electricity markets which contributed to higher energy sales and
        purchases. The impact of this new activity on energy margins was
        insignificant.

    -   Operating expenses for the non-regulated portion of Energy Services
        were higher in 2007 compared with 2006 primarily due to higher
        employee short-term incentive compensation and foreign exchange
        losses on U.S. transactions.

    Energy Services' retail customer sales volumes, which exclude electricity
and natural gas trading activities, were as follows:

    -------------------------------------------------------------------------
                                                             2007       2006
    Retail sales
    Electricity (000s of megawatt-hours)
      RRT                                                   5,711      5,710
      Default                                                 868        872
      Competitive                                           3,267      3,583
    -------------------------------------------------------------------------
                                                            9,846     10,165
    -------------------------------------------------------------------------
    Natural gas (000s of gigajoules)                        1,880      2,044
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                             2007       2006
    Energy supply (MWh)
    Battle River PPA generation                             1,301      2,253
    Sundance PPA generation                                 2,514      2,828
    Genesee 3 generation                                    1,796      1,887
    Joffre generation                                         270        256
    -------------------------------------------------------------------------
                                                            5,881      7,224
    Calpine short-term tolling arrangement                      -        715
    -------------------------------------------------------------------------
                                                            5,881      7,939
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Overall customer sales volumes declined in 2007 from 2006 primarily due
to the expiry of some commercial and industrial customer contracts in Ontario
and Alberta. Power sales volumes for RRT and default customers remained
consistent from 2006 to 2007. Natural gas sales volumes declined due to a
reduction in industrial gas contracts.
    In 2006, we began repositioning our power portfolio by selling interests
in our Battle River and Sundance PPAs. The sales of additional interests in
the Battle River PSA in the period from 2007 to 2010 will continue to reduce
our power supply volumes, which will be replaced over time with new production
from the Clover Bar Energy Centre and Keephills 3 facilities as they come on
line.
    Energy Services will continue to play a key role in EPCOR's growth as it
continues to pursue opportunities, and manage EPCOR's electricity and natural
gas portfolios. As new generation assets are added to EPCOR's fleet, Energy
Services will contract with Generation for the capacity of the new assets and
optimize the value of those investments by selling the electricity to the
market or end-use customers. Energy Services is also working to add value to
existing operations by identifying trading and marketing opportunities in each
region we operate.

    Water Services

    Water Services earns income primarily from the treatment, distribution
and sale of water while ensuring public health standards are exceeded. The
majority of Water Services' income is earned through a performance-based rate
(PBR) tariff charged to its Edmonton customers. The PBR tariff is intended to
allow Water Services to recover its costs and earn a fair rate of return while
providing an incentive to manage costs below the inflationary adjustment built
into the PBR rate. The key to maintaining earnings on water sales is to
provide sufficient quantities of high quality water while controlling costs.
    Water Services manages EPCOR's Transportation Services business which
provides competitive contract-based commercial services related to
installation, maintenance and repair of street lighting, traffic signal, light
rail transit and trolley facilities. In addition, Water Services provides
competitive contract-based water and wastewater services to commercial,
industrial and municipal customers. The key to earning satisfactory margins on
these contracts is to satisfy the terms of the contract while controlling or
reducing operating costs.

    
    Water Services operating income

    -------------------------------------------------------------------------
                                                             2007       2006
    -------------------------------------------------------------------------
    Water Services results
    (including intersegment transactions, $ millions)
    Revenues     Water revenues                            $  136     $  119
                 Commercial and other                         128         85
    -------------------------------------------------------------------------
                                                              264        204
    -------------------------------------------------------------------------
    Expenses     Operations, maintenance, administration
                  and foreign exchange                        163        125
                 Franchise fees and taxes other than
                  income taxes                                 10          8
                 Depreciation, amortization and asset
                  retirement accretion                         18         17
    -------------------------------------------------------------------------
                                                              191        150
    -------------------------------------------------------------------------
    Operating income before corporate charges                  73         54
    Corporate charges                                          14         10
    -------------------------------------------------------------------------
    Operating income                                       $   59     $   44
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2006             $   44
    Increased water rates                                                 16
    Higher commercial services activity                                    6
    Higher operations and maintenance                                     (3)
    Higher depreciation, administration and other                         (4)
    -------------------------------------------------------------------------
    Increase in operating income                                          15
    -------------------------------------------------------------------------
    Operating income for the year ended December 31, 2007             $   59
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    For the year ended December 31, 2007, Water Services' operating income
increased by $15 million from the prior year due to the net impact of the
following:

    -   Water revenues were higher in 2007 compared with 2006 primarily due
        to increased rates as approved by the regulator, The City of
        Edmonton, which were implemented in the second quarter of 2007.

    -   Transportation and other commercial services revenues and expenses
        increased in 2007 over 2006 by $41 million and $35 million
        respectively, primarily due to an increase in streetlight and traffic
        signal construction activities for The City of Edmonton and
        contracting income from Distribution and Transmission's DESS project.
        Also, new commercial services construction projects are in progress
        for the City of Wetaskiwin and the Town of Taber in Alberta, and for
        the 2010 Vancouver Olympics Committee.

    -   Operations and maintenance costs increased in 2007 over 2006 due to a
        higher incidence of distribution main breaks and unplanned
        maintenance at the Rossdale and EL Smith plants. Water treatment
        costs were also higher due to more spring run-offs and unfavourable
        water conditions due to wet weather in 2007.

    -------------------------------------------------------------------------
                                                             2007       2006
    Water volumes for The City of Edmonton and
     surrounding region
    Water sales (megalitres)                              124,696    125,106
    -------------------------------------------------------------------------
    

    Water Services owns 4 and operates 16 water treatment and distribution
facilities. As well, it operates 19 wastewater and collection facilities in
Alberta and British Columbia. Our core market is stable as we are the sole
supplier of water within The City of Edmonton. In 2007, we saw a slight
decrease in water volumes, primarily due to cooler and wetter weather on
average compared with 2006, and the impact of water conservation efforts in
the Edmonton region. Operationally, the facilities we own or manage performed
well in both 2006 and 2007.
    The completion of the EL Smith upgrade in 2008 will provide water
capacity necessary to meet the anticipated growth in the city of Edmonton.
Asset components are being added to the rate base as they are placed into
service. The water rates for 2007 and 2008 reflect the costs of the upgrade
project resulting in additional cash flow and earnings.
    Business development efforts in the Alberta commercial marketplace are
expected to contribute to additional growth in cash flow and earnings in 2008
and beyond. In late 2007, Water Services entered into agreements to design,
build, operate and finance water and wastewater facilities for the City of
Wetaskiwin and the Town of Chestermere. The Company is also close to
completing commercial agreements with other municipal and industrial partners
for the construction and operation of treatment facilities in 2008.

    
    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
    Significant changes in consolidated assets:
    December 31, 2007 and 2006
    -------------------------------------------------------------------------
                                     Increase
    ($ millions)      2007    2006  (decrease)  Explanation
    -------------------------------------------------------------------------
    Cash and cash   $   79  $  260     $ (181)  Refer to cash flows summary
     equivalents                                 below.
    -------------------------------------------------------------------------
    Accounts           591     647        (56)  Reflects lower energy pricing
     receivable                                  on wholesale power
     (including                                  settlements and lower
     income taxes                                receivables for Genesee 3,
     recoverable)                                due to lower Alberta power
                                                 prices, partly offset by
                                                 higher commercial services
                                                 receivables.
    -------------------------------------------------------------------------
    Derivative         104      26         78   Implementation of new
     instruments                                 financial instruments
     assets (current)                            accounting standards for
                                                 physical power and natural
                                                 gas purchase and sales
                                                 contracts and derivatives
                                                 used in cash flow hedges of
                                                 electricity.
    -------------------------------------------------------------------------
    Other current       74      70          4   Reflects changes in
     assets                                      inventories, prepaid
                                                 expenses and current portion
                                                 of future income tax assets.
    -------------------------------------------------------------------------
    Property, plant  4,216   3,908        308   Reflects 2007 capital
     and equipment                               expenditures in excess of
                                                 depreciation and
                                                 amortization expense.
    -------------------------------------------------------------------------
    Power purchase     679     757        (78)  Sale of 10% interest in
     arrangements                                Battle River PSA and
                                                 amortization of remaining
                                                 PPAs in 2007.
    -------------------------------------------------------------------------
    Contract and       179     207        (28)  Amortization of customer and
     customer rights                             contract rights.
     and other
     intangible
     assets
    -------------------------------------------------------------------------
    Derivative         116      20         96   Implementation of new
     instruments                                 financial instruments
     assets                                      accounting standards for
     (non-current)                               physical power and natural
                                                 gas purchase and sales
                                                 contracts and derivatives
                                                 used in cash flow hedges of
                                                 electricity, combined with
                                                 an increase in the fair
                                                 value of foreign exchange
                                                 derivatives.
    -------------------------------------------------------------------------
    Future income      103     127        (24)  Reflects enactment of future
     tax assets                                  tax rate reductions partly
     (non-current)                               offset by increase in
                                                 deductions available for tax
                                                 purposes resulting from
                                                 implementation of new
                                                 financial instruments
                                                 accounting standards.
    -------------------------------------------------------------------------
    Goodwill           185     183          2
    -------------------------------------------------------------------------
    Other assets       236     178         58   Purchase and subsequent
                                                 reduction in fair value of
                                                 ABCP.
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Significant changes in consolidated liabilities and shareholder's equity:
    December 31, 2007 and 2006
    -------------------------------------------------------------------------
                                     Increase
    ($ millions)      2007    2006  (decrease)  Explanation
    -------------------------------------------------------------------------
    Short-term debt $  138  $  216 $      (78)  Reflects the repayment of
                                                 Power LP's borrowing under
                                                 its bridge acquisition
                                                 credit facility, partly
                                                 offset by new commercial
                                                 paper borrowings.
    -------------------------------------------------------------------------
    Derivative         136      24        112   Implementation of new
     instruments                                 financial instruments
     liabilities                                 accounting standards for
     (current)                                   physical power and natural
                                                 gas purchase and sales
                                                 contracts and derivatives
                                                 used in cash flow hedges of
                                                 power.
    -------------------------------------------------------------------------
    Accounts payable   615     608          7   Reflects increased capital
     and accrued                                 accruals, partly offset by
     liabilities                                 lower Alberta power prices
                                                 on wholesale electricity
                                                 settlements.
    -------------------------------------------------------------------------
    Other current       98     124        (26)  Reflects a reduction in
     liabilities                                 future and current income
                                                 tax liabilities due to
                                                 payments and rate reductions
                                                 substantively enacted in
                                                 2007, partly offset by an
                                                 increase in future income
                                                 taxes payable for the gain
                                                 on sale of the interest in
                                                 the Battle River PSA.
    -------------------------------------------------------------------------
    Long-term debt   2,139   2,179        (40)  Ongoing scheduled debt
     (including                                  repayments on The City of
     current                                     Edmonton debentures and non-
     portion)                                    recourse financing,
                                                 reclassification of debt
                                                 issue costs from other
                                                 assets effective January 1,
                                                 2007 and a net decrease in
                                                 Power LP's debt with the
                                                 replacement of acquisition
                                                 financing and lease
                                                 obligations with two senior
                                                 unsecured notes issues.
                                                 Partly offset by a credit
                                                 facility draw-down in 2007.
    -------------------------------------------------------------------------
    Derivative          78      27         51   Implementation of new
     instruments                                 financial instruments
     liabilities                                 accounting standards for
     (non-current)                               physical power and natural
                                                 gas purchase and sales
                                                 contracts, and derivatives
                                                 used in cash flow hedges of
                                                 power.
    -------------------------------------------------------------------------
    Other non-current  125     127         (2)  Reflects changes in asset
     liabilities                                 retirement obligations and
                                                 employee future benefits.
    -------------------------------------------------------------------------
    Future income tax  126      84         42   Reflects the enactment of the
     liabilities                                 SIFT legislation, partly
     (non-current)                               offset by the impact of tax
                                                 rate reductions that were
                                                 substantively enacted in
                                                 2007.
    -------------------------------------------------------------------------
    Non-controlling    740     751        (11)  Reflects redemption and issue
     interests                                   of preferred shares by
                                                 subsidiary companies. Also
                                                 reflects non-controlling
                                                 interests' share of Power LP
                                                 distributions less unit
                                                 offering and Power LP
                                                 income. Partly offset by
                                                 opening adjustment upon
                                                 implementation of financial
                                                 instruments accounting
                                                 standards attributable to
                                                 non-controlling interests.
    -------------------------------------------------------------------------
    Shareholder's    2,367   2,243        124   Net income and adjustments to
     equity                                      retained earnings upon
                                                 implementation of financial
                                                 instruments accounting
                                                 standards, partly offset by
                                                 common share dividends and
                                                 refundable income taxes.
                                                 Also reflects adjustment to
                                                 accumulated other
                                                 comprehensive income upon
                                                 implementation of financial
                                                 instruments accounting
                                                 standards and other
                                                 comprehensive income for
                                                 2007.
    -------------------------------------------------------------------------



    CONSOLIDATED STATEMENTS OF CASH FLOWS
    -------------------------------------------------------------------------
    Cash inflows (outflows) and cash position:
    -------------------------------------------------------------------------
                                               ($ millions)
                               ----------------------------------------------
                                          Years ended December 31
                                2007    2006  Change    2006    2005  Change
                               ----------------------------------------------
    Operating                  $ 541   $ 589   $ (48)  $ 589   $ 479   $ 110

    Investing                   (469)   (303)   (166)   (303)   (757)    454

    Financing                   (253)   (116)   (137)   (116)    (88)    (28)

    Opening cash and cash
     equivalents                 260      90     170      90     456    (366)
                               ----------------------------------------------
    Closing cash and cash
     equivalents               $  79   $ 260   $(181)  $ 260   $  90   $ 170
                               ----------------------------------------------

    Operating changes:

    The 2006 to 2007 decrease in cash inflows reflects changes in non-cash
    working capital due to the timing of receipts and payments, reduced cash
    flow from the Calpine short-term tolling arrangements and the Battle
    River PPA, and net realized losses on forward foreign exchange and
    interest rate contract settlements.

    Investing changes:

    The 2006 to 2007 increase in investing activities reflects higher capital
    expenditures in 2007, primarily for the Keephills 3 and Clover Bar Energy
    Centre generation projects, the EL Smith upgrade and the DESS project.
    Investing activities in 2007 also included the purchase of ABCP and the
    sale of a smaller interest in the Battle River PSA. Investing activities
    in 2006 included Power LP's purchase of Ventures, but no purchases of
    ABCP as it was classified as a cash equivalent in 2006.

    Financing changes:

    The 2006 to 2007 increase in financing outflows reflects higher short-
    term debt repayments, lower long-term and short-term debt issues and
    higher subsidiary company preferred share redemptions in 2007. These
    increases were partly offset by a subsidiary company preferred share
    issue and lower long- term debt repayments in 2007.
    -------------------------------------------------------------------------



    LIQUIDITY AND CAPITAL RE

SOURCES ------------------------------------------------------------------------- ($ millions) Years ended December 31 2007 2006 2005 ------------------------------------------------------------------------- Cash flow from operations(1) $ 517 $ 547 $ 493 Long-term borrowings during the year 395 406 200 Cash and cash equivalents, at end of year 79 260 90 Short-term debt, at end of year (138) (216) (29) Ratios(1) Debt to equity(2) 42:58 44:56 44:56 Interest coverage (excluding gain on sale of PPA and related transactions) on long-term debt: Income before financing and taxes(3) 3.2 X 3.0 X 3.4 X Income from continuing operations before financing and taxes(4) 3.2 X 2.9 X 3.1 X Income before financing, taxes, depreciation and amortization(5) 4.7 X 4.4 X 5.1 X Income from continuing operations before financing, taxes, depreciation and amortization(6) 4.7 X 4.3 X 4.3 X Cash flow to interest bearing debt(%)(7) 22.7 22.8 23.3 Credit ratings(8) Standard & Poor's Long-term debt BBB+ BBB+ BBB+ Preferred shares of subsidiary companies P-2 (Low) P-2 (Low) P-2 (Low) Dominion Bond Rating Service's Short-term debt R-1 (low) R-1 (low) R-1 (low) Long-term debt A (low) A (low) A (low) Preferred shares Pfd-2 (low)/ of subsidiary companies Pfd-3 (high) Pfd-2 (low) Pfd-2 (low) ------------------------------------------------------------------------- (1) Cash flow from operations and ratios in this table are non- GAAP financial measures that do not have any standardized meaning prescribed by GAAP and are unlikely to be comparable to similar statistics published by other companies. They are presented since they are commonly referred to by debt holders and other interested parties in evaluating the Company's financial position and in assessing its credit worthiness. See "Non-GAAP Measures" for a reconciliation of cash flow from operations. The ratios are explained in the following notes. (2) Debt to equity is expressed as a ratio of debt as a percentage of total capital to equity as a percentage of total capital. Debt is the sum of short-term debt and long-term debt (including the current portion). Equity is the sum of non-controlling interests and shareholder's equity. Total capital is the sum of debt and equity. (3) Revenue and foreign exchange gains less energy purchases, fuel, operations, maintenance and administration, franchise fee, property taxes and other taxes and depreciation, amortization and asset retirement accretion, for continuing and discontinued operations, divided by interest on long-term debt and capital lease obligation for continuing and discontinued operations. (4) Revenue and foreign exchange gains less energy purchases, fuel, operations, maintenance and administration, franchise fee, property taxes and other taxes and depreciation, amortization and asset retirement accretion, for continuing operations, divided by interest on long- term debt and capital lease obligation for continuing operations. (5) Revenue and foreign exchange gains less energy purchases, fuel, operations, maintenance and administration and franchise fee, property taxes and other taxes, for continuing and discontinued operations, divided by interest on long- term debt and capital lease obligation for continuing and discontinued operations. (6) Revenue and foreign exchange gains less energy purchases, fuel, operations, maintenance and administration and franchise fee, property taxes and other taxes, for continuing operations divided by interest on long-term debt and capital lease obligation for continuing operations. (7) Cash flow to interest bearing debt (expressed as a percentage) is cash flow from operations divided by short-term debt plus long-term debt (including the current portion). (8) Rating agencies have disclosed that all current ratings are stable. ------------------------------------------------------------------------- Generally, our external capital is raised at the corporate level and invested in the operating business units. However, some of the businesses that we own jointly with parties unrelated to EPCOR, such as Power LP and Joffre, have their own external financing. By centralizing our finance function we are able to access capital markets appropriate for our growth strategy and to minimize financing costs. Our external financing has consisted of borrowings under committed credit facilities, debentures payable to The City of Edmonton, public debentures, and preferred and common shares. Power LP's external financing has been raised through the issuance of partnership units and preferred shares, borrowings under lines of credit and long-term notes payable. Financing In May 2007, EPEL issued 5 million 4.85% cumulative, redeemable preferred shares for net proceeds of $121 million and Power LP issued limited partnership units for net proceeds of $102 million, as described under Significant Events. These financings were used to repay amounts outstanding under Power LP's bridge acquisition credit facilities which were incurred for Power LP's acquisition of Ventures. EPCOR, through wholly-owned subsidiaries purchased 1,228,681 limited partnership units to maintain its 30.6% interest in Power LP. On August 15, 2007, a subsidiary of Power LP completed a private placement of senior unsecured notes for aggregate proceeds of $240 million (US$225 million), less issue costs of $1 million (US$1 million). The notes were issued in two tranches consisting of 10 and 12 year maturities. The $160 million (US$150 million) in 10-year notes have a coupon rate of 5.87% and the $80 million (US$75 million) in 12-year notes have a coupon rate of 5.97%. The combined carrying value of these notes declined to $223 million at December 31, 2007 due to a decrease in the U.S. dollar exchange rate. On August 24, 2007, Power LP paid off its capital lease obligations for the Naval Station, North Island and Naval Training Centers for $72 million (US$68 million). The proceeds from the private placement were used to repay the capital lease obligations and amounts initially borrowed as part of the Frederickson and Ventures acquisitions. As of March 20, 2008 there were three common shares of the Company outstanding, all of which are owned by The City of Edmonton. EPCOR's dividend policy for these common shares has remained unchanged since 2000. Under the policy, the annual dividend is set at the greater of the previous year's dividend adjusted for the forecast change in the consumer price index, and 60% of the current year's earnings available to the common shareholder. This policy is subject to amendment in the event of a significant change in EPCOR's business or financial condition. Dividends for the year are generally established in the fall of the previous year based on forecast earnings. In accordance with the policy, the annual dividends for 2007 were $128 million (2006 - $125 million). Power LP paid $91 million (2006 - $85 million) of distributions to the non-controlling unit holders. EPCOR paid preferred share dividends, including those of EPEL, and related income taxes of $12 million (2006 - $17 million). The decrease from 2006 was due to the redemption of 6 million preferred shares at their stated redemption price of $150 million on June 30, 2006 and the redemption of 8 million preferred shares at par for $200 million effective September 30, 2007. Operating activities Cash flow from operating activities, which includes changes in non-cash working capital, decreased to $541 million in 2007 from $589 million in 2006. The decrease was primarily due to changes in non-cash working capital due to the timing of receipts and payments, reduced cash flow from the short-term tolling arrangements and the Battle River PPA, and net realized losses on forward foreign exchange and interest rate contracts. Cash flow from operating activities is anticipated to decline in 2008 from 2007 due to lower earnings. Cash requirements for working capital are expected to be substantially higher in 2008 than in 2007 due to the timing of payments related to accounts payable, and income taxes payable related primarily to the sale of an interest in the Battle River PSA. 2008 cash requirements EPCOR's 2008 projected cash requirements include $800 million to $900 million for capital expenditures, $388 million for long-term debt repayments, $130 million for common dividends, and Power LP cash distributions as and when declared by the Board of Directors of its general partner. The major project expenditures in 2008 will be on the Keephills 3, Clover Bar Energy Centre and DESS projects. The total cost of constructing the generation units at Clover Bar Energy Centre is expected to be approximately $283 million. The current estimate is higher than the original project estimate of $245 million due to unanticipated scope and cost increases which the Company is actively attempting to mitigate. The project remains viable and is expected to be within the range of the project economics we originally contemplated. On January 25, 2007, we announced that based on the status of required local and provincial approvals, we would re-examine the project design and schedule of the Kingsbridge II project and terminate arrangements with certain suppliers. At that time we estimated that our project cash commitment, which was under review, would be approximately $300 million. The Company continues to work through the regulatory process with respect to this project. If total cash requirements remain as planned, the sources of capital will be from cash on hand, operating cash flows, the scheduled sale of a further 10% interest in the Battle River PSA, existing credit facilities, new public debt borrowings, and public equity markets (Power LP). The Company does not expect that the funds invested in ABCP will impede the Company's ability to fulfill its capital requirements for 2008. However, the collapse of the ABCP market is illustrative of the broader tightening of credit markets and has resulted in reduced debt market liquidity and widening credit spreads. This could cause an increase in rates or a reduced market for new borrowings by the Company. At December 31, 2007 the Company's bank lines of credit were as follows: ------------------------------------------------------------------------- ($ millions) December 31, 2007 2006 2007 2006 ------------------------------------------------------------------------- EPCOR Power LP ------------------------------------------------------------------------- Bank lines of credit - committed $ 1,200 $ 1,200 $ 300 $ 468 Bank lines of credit - uncommitted 45 25 20 20 ------------------------------------------------------------------------- 1,245 1,225 320 488 Outstanding loans (293) - - (420) Letters of credit outstanding (357) (236) - (12) ------------------------------------------------------------------------- Bank lines of credit available $ 595 $ 989 $ 320 $ 56 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Committed bank lines are used principally for the purpose of providing capital and letters of credit. Letters of credit are issued to meet conditions of certain debt and service agreements, and to satisfy legislated reclamation requirements. The committed bank lines also back the Company's commercial paper program which has an authorized capacity of $500 million, of which $138 million was outstanding at December 31, 2007 (2006 - $nil). On January 31, 2008, the Company completed a $200 million public offering of unsecured medium-term note debentures with a coupon rate of 5.8% and maturity date of January 31, 2018. Net proceeds from the offering will be used to repay EPCOR's commercial paper indebtedness and for general corporate purposes. Credit ratings In February 2008, Standard & Poor's reaffirmed EPCOR's credit rating for long-term debt at BBB+. DBRS Limited's rating also remained unchanged at A (low). The significant increase in debt and interest expense to fund capital expenditures planned for 2008 will weaken certain credit rating ratios but are not expected to result in ratings action. A ratings downgrade for EPCOR would result in higher interest costs on new borrowings and reduce the availability of sources of investment capital. CONTRACTUAL OBLIGATIONS ------------------------------------------------------------------------- $ millions Payments due by period ------------------------------------------------------------------------- 2012 and there- 2008 2009 2010 2011 after Total Acquired PPA obligations(1) $ 149 $ 116 $ 89 $ 88 $1,041 $1,483 Capital projects(2) 513 338 119 37 27 1,034 Energy purchase/ transportation contracts(3)(4) 66 73 72 70 305 586 Asset retirement obligations 16 16 13 9 318 372 Long-term debt 388 26 221 215 1,305 2,155 Interest on long-term debt 178 160 137 117 1,008 1,600 Short-term debt 138 - - - - 138 Operating leases 3 3 3 3 216 228 Operating and maintenance contracts(5) 28 27 28 29 201 313 Other purchase obligations 5 2 1 1 11 20 ------------------------------------------------------------------------- Total contractual obligations $1,484 $ 761 $ 683 $ 569 $4,432 $7,929 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) EPCOR's obligation to make payments on a monthly basis for fixed and variable costs under the terms of its acquired PPAs will vary depending on generation volume and scheduled plant outages. (2) EPCOR's obligations for capital projects include Keephills 3, Clover Bar Energy Centre, EL Smith upgrade, DESS, and water treatment plants for the City of Wetaskiwin and the towns of Chestermere and Taber. EPCOR's obligation to construct the Kingsbridge II wind-power generation facility is not included as the project design and schedule are being re-examined. (3) The natural gas purchase contracts have fixed and variable components. The variable components are based on estimates subject to variability in plant production. These contracts have expiry dates ranging from 2010 to 2016 with built-in escalators. (4) The natural gas transportation contracts are based on estimates subject to changes in regulated rates for transportation and have expiry dates ranging from 2011 to 2017. (5) Operating and maintenance contracts are based on fixed fees escalated annually by inflation and have expiry terms ranging from 2008 to 2018. In the normal course of business, EPCOR provides financial support and performance assurances, including guarantees, letters of credit and surety bonds, to third parties in respect of its subsidiaries. The liabilities associated with these underlying subsidiary obligations are included in the consolidated balance sheet. In connection with the sale of Alberta mass-market competitive contracts to AESLP, effective February 1, 2005, EPCOR made arrangements to provide AESLP's prudential obligations with AESO and Alberta's wire service providers and gas distributors. On December 31, 2007, prudential obligations posted under this arrangement, in the form of letters of credit and guarantees, were $27 million (2006 - $36 million). EPCOR is legally required to remove its power generation facilities and Genesee coal mine at the end of their useful lives and restore the plants and mine sites to their original condition. The Company estimates that the undiscounted amount of cash flow required to settle its asset retirement obligations is approximately $372 million, calculated using inflation rates ranging from 2% to 3%. The expected timing for settlement of the obligations is between 2008 and 2090. The majority of the payments to settle the obligations are expected to occur between 2027 and 2064 for the power generation plants, and between 2008 and 2012 for sections of the Genesee coal mine. As part of a 2003 disposition, EPCOR agreed to indemnify certain liabilities of UE Waterheater Operating Trust (the Trust) until 2010 primarily consisting of potential tax liabilities that could arise relating to operations of the water heater rental business prior to the sale by EPCOR to the Trust. Any known liabilities associated with this indemnification are reflected on the balance sheet at December 31, 2007 and it is uncertain what, if any, additional amounts may be incurred in the future. The June 2006 sale of the initial 55% interest in the Battle River PSA was completed through a series of transactions. Before the sale, we owned approximately 70% of the PSA. To facilitate the eventual sale of a 100% interest to ENMAX Corporation, we acquired the remaining 30% interest in the PSA from non-EPCOR syndicate members for cash and an ownership interest in the Company's Sundance Power Syndicate Agreement (Sundance Swap). As part of the agreement for the Sundance Swap, we committed to providing interest-free notes of approximately $19 million to the counterparties to fund any income tax liabilities that they incur for the dispositions of their interests in the Battle River PSA. At December 31, 2007, the Company had advanced approximately $13 million. In December 2007, the Company announced that it had entered into a 20-year lease for space in a new office tower for its headquarters in downtown Edmonton. The lease will commence January 1, 2012 or earlier and the existing lease for Edmonton offices will expire at the end of 2011. There were no other material guarantee obligations outstanding in respect of third parties and no significant liquidity risks with respect to the Company's financial instruments at December 31, 2007. OUTLOOK In 2007, we focused on operational excellence, execution of development projects and integration of Ventures. Our strategy remains to grow our water and power business with a good diversity of asset types and geographic regions. In 2008, we will focus on maintaining the Company's income growth with increased capital expenditures and business development. The EL Smith upgrade and the DESS project are expected to be completed in 2008. Construction is expected to continue throughout 2008 on Keephills 3 and Clover Bar Energy Centre. Our business development activity will concentrate on water and power prospects. Public interest in water is increasing and water pricing is starting to reflect its growing scarcity. As demand continues to increase, we anticipate increased requirements for better water management practices including watershed management and conservation. In North America, there are significant water infrastructure upgrade requirements which we believe will provide us with growth opportunities. Although there has not been a major shift to water markets opening to private development, there has been some progress in public-private partnerships. We are a solution provider who can maximize the efficient, effective and environmentally responsible use of this resource. Environmental policy development and discussion are becoming more intense across North America and around the world. Recently, Canadian federal and provincial governments have taken strong environmental and fiscal positions. In addition, the public is not appropriately informed about the present state of technology and the valuable continuing role to be played by coal. Environmental policy remains uncertain and regional initiatives may be out of step with federal policy development. New stringent emission standards will evolve and could have a material impact on EPCOR's operations. EPCOR is supportive of initiatives to decrease emissions, but this needs to be done in a thoughtful and prudent manner. This situation requires us to continue to be vigilant in discussing policy initiatives with legislators to ensure they are fair and do not result in impractical or damaging policies. We plan to be actively engaged in raising our public profile as an environmentally responsible water and power provider. Our strategy of improving our existing power and water operations continues which means extracting the maximum efficiency and effectiveness from our existing operations. Our earnings are expected to be lower in 2008 and factors that will impact 2008 include: - No items similar to the tax benefit of the Energy Services reorganization in 2007. - Two major outages are planned at the Genesee site in 2008 for scheduled equipment repairs and maintenance whereas one outage occurred in 2007. - Increased business development activity emphasizing water and environmentally responsible power. - Higher operating costs primarily due to higher labour rates. In addition, fair value changes can cause significant positive or negative income volatility. RISK MANAGEMENT Approach to risk management ---------------------------------- Board of Directors Risk tolerance and governance ---------------------------------- ---------------------------------- Risk Oversight Council Policy development and oversight ---------------------------------- ---------------------------------- Operating Units Risk mitigation ---------------------------------- Our approach to risk management is to identify, monitor and manage the key controllable risks facing the Company. Risk management includes the controls and procedures implemented to reduce controllable risks to acceptable levels and the identification of the appropriate management actions in the case of events occurring outside of management's control. Acceptable levels of risk for EPCOR are established by the Board of Directors, representing the shareholder, and are embodied in the decisions and corporate policies associated with risk. Risk management is generally carried out at three levels. Firstly, general oversight, policy review and recommendation, and reviews of risk compliance are provided by the Risk Oversight Council, a senior executive group including the Vice President, Risk Management. Secondly, the Vice President, Risk Management is generally responsible for monitoring compliance with risk management policies. His responsibilities include oversight of the enterprise risk management program and leadership of our commodity risk management (or middle office) function. Thirdly, the operational business units and shared service units are responsible for carrying out the risk management and mitigation activities associated with the risks in their respective operations. These risk management activities are integral aspects of the business units' and shared service units' operations. We believe that risk management is a key component of the Company's culture and we have put into place cost-effective risk management practices. At the same time, we view risk management as an ongoing process and continually review our risks and look for ways to enhance our risk management processes. Electricity price and volume risk We buy and sell electricity in the wholesale markets of Alberta, Ontario, and the U.S. Such exchanges are settled at the spot market prices of the respective markets. We currently use purchase and sale arrangements including CfDs and firm price physical contracts for periods of varying duration to manage our exposure to spot price variability within specified risk limits. Due to limited market liquidity and the varying shape of electricity consumption during peak usage hours compared with off-peak usage hours, it is not possible to hedge all positions every hour. We balance our electricity position within the limits of our policies and generally trade in electricity to reduce the Company's exposure to changes in electricity prices or to match physical and financial obligations. A limited portion of our trading is directed at optimizing our electricity position. When aggregate customer electricity consumption (load shape) changes unexpectedly, EPCOR is exposed to electricity price risk. Load shape refers to the different pattern of consumption for peak hours and off-peak hours. Consumption is higher during peak hours when people and organizations are active, than during off-peak hours. We purchase blocks of electricity in advance of consumption to minimize exposure to extreme price fluctuations, especially during higher priced peak hour periods. In order to do this, we rely on historical aggregate consumption data provided by load settlement agents and local distribution companies to anticipate what aggregate customer consumption will be during peak hours. When consumption varies from historical consumption patterns and from the volume of electricity purchased for any given peak hour period, we are exposed to the prevailing market prices because we must either buy electricity if we have less than we need (short) or sell electricity if we have more than we need (long). Exposures can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns. Electricity sales associated with EPCOR's Genesee units 1 and 2 are governed by the terms of the associated PPAs. These sales are accounted for as long-term fixed margin contracts, which limit the impact of swings in wholesale spot electricity prices, unless plant availability drops significantly below the PPA target availability for an extended period. Our other plants, such as Brown Lake, Miller Creek, and Kingsbridge I operate under long-term commercial contracts with credit worthy counterparties. Our 40% interest in Joffre is governed by a long-term commercial contract. However, its operations are subject to market price variability as there are provisions in the contract that require the facility to run to provide steam to the host facility, irrespective of market prices. Although our 50% interest in Genesee 3 is not covered by a long-term commercial contract, it is a base-loaded coal-fired generating unit with a relatively low variable cost and it will generally run when it is available. It is subject to spot price exposure when those prices are below its price for corresponding variable costs or the unit suffers an unplanned outage. Since its commissioning, the occasions when Alberta electricity prices have been below Genesee 3's variable cost have been very limited and the plant has operated above our expectations. Electricity price and volume risks for Power LP, including Ventures' plants acquired in November 2006, are lower than they would be in a merchant environment since each of the facilities operates under long-term power sales contracts with investment-grade power and steam buyers. In order to stabilize future cash flows, we will seek to re-contract existing generation plants under new or extended contracts and acquire new plants that meet our investment criteria. Although commercial contracts provide better electricity price and volume protection than if the plant operations were completely subject to spot market risk, the contract provisions must be met and the Company can incur charges in the event of unplanned outages or variations from the contract performance benchmarks. Natural gas price and volume risk Price risk associated with natural gas purchased for our natural gas-fired generation plants operating under commercial contracts is mitigated by the provisions of the contracts which generally require the contract power buyer to pay the generator a market indexed price or buy the gas outright on behalf of the plant. Natural gas price risk associated with Joffre is partly flowed through to its electricity sale prices as they depend on the natural gas price. For Power LP's natural gas-fired plants, the natural gas price risks have been minimized by executing fixed price long-term contracts for a significant portion of the supply of natural gas or through the use of tolling agreements. However, certain Power LP plants are at risk for the fuel supply after the term of the fixed price contract if it expires before the termination of the PPA. For example, for its Tunis Plant, Power LP will be exposed to commodity price risk on its natural gas purchases commencing with the expiry of its natural gas contract in 2010 until the expiry of the PPA in 2014, unless Power LP is able to secure another fixed-price natural gas supply contract for that period. We will attempt to bridge these gaps by securing new natural gas contracts. For our retail and wholesale natural gas contracts, we balance our exposure by purchasing natural gas back-to-back with our sales contracts to the fullest extent possible. That is, we normally purchase only enough physical natural gas delivery in advance to satisfy the natural gas load represented by expected volumes from signed contracts. Natural gas exposures are managed to the specific limits established by our risk management policies. The initial term of a block of retail natural gas contracts that we acquired in 2000 expired in late 2004. The customers under these contracts had an option to renew at the original contracted price and approximately 56% did so with terms expiring by the end of 2009. Due to the relatively low embedded contract price, EPCOR will experience losses on servicing these contracts which are estimated to be up to $5 million for 2008 and 2009, depending on future natural gas prices. As we are no longer active in the retail natural gas market, we will continue to seek opportunities to exit from these contracts. Commodity risk measures and limits Our tolerance for energy commodity price and volume risk is based on our assessment of the trade-off between risk and return for the underlying commodity. The risk tolerance of our consolidated energy commodity portfolio is established by total exposure limits as set out in policy and approved by the Board of Directors. We use Value-at-Risk (VaR) as the basic component to measure the risk in our energy commodity portfolio. VaR is the maximum expected loss over a given period of time at a given level of confidence. Our VaR is calculated at a 95% statistical confidence level over a holding period of 20 business days. In other words, over the 20-day period commencing with the point in time that the VaR is measured, there is a 1 in 20 likelihood that the fair value of our commodity portfolio could change by an amount in excess of the VaR amount. The VaR calculation incorporates positions, forward prices, price volatilities and correlations as major input variables. As VaR is not a perfect measure of risk, we apply a factor to the calculated VaR amount to attempt to capture unaccounted for exposures. The resulting measure is referred to as the total exposure of the portfolio. EPCOR's one year energy commodities total exposure, when considering the portfolio on a net basis, as at December 31, 2007 was $8 million (2006 - $20 million). To supplement the total exposure estimates, we use stress-testing and scenario analysis on the electricity and natural gas portfolio by applying plausible but unlikely adverse market conditions and movements. This testing is used to determine the resulting financial effects on the portfolio in relation to the Company's total exposure limits. We have also adopted a series of operational limits for our energy trading operations, including position limits, transaction limits and stop loss limits. Key risk measures in relation to the applicable limits are reported daily to Risk Oversight Council and quarterly to the Board of Directors. Operational risk The ability of EPCOR's power plants to generate the expected amount of electricity that will be sold under contract or to the applicable market has a significant impact on the revenues of the Company. If a power plant delivers less than the required quantities of electricity in a given month, revenue may be insufficient to cover contractual or financial obligations. Our plant operations are susceptible to outages due to equipment failure, which could make plants unavailable to provide service. This is also true for the generation units associated with the acquired PPAs. Such risks are partly mitigated by our, and the acquired PPA plant owners', operating and maintenance practices that are intended to minimize the likelihood of prolonged unplanned down time. We have a very strong record of availability, as measured against our peers by the Canadian Electricity Association. In addition, the penalty provisions within the PPAs provide appropriate incentives to owners to keep the plants well maintained and operational. The terms of the PPAs also provide force majeure protection for high-impact low probability events including major equipment failures. Our maintenance practices are augmented by the maintenance of an inventory of strategic spare parts, which can reduce down time considerably in the event of failure. Finally, we have secured appropriate business interruption insurance to reduce the impact of prolonged outages caused by insured events at our generation plants and at the plants supporting our acquired PPAs. Operational risk in Distribution and Transmission, and Water Services is also managed through sound maintenance and safety practices. In addition, Water Services performs continuous and rigorous quality control testing of water purification to ensure adequate water treatment consistent with government and industry standards. The ability of the water treatment plants to maintain adequate treatment and testing of water on a continuous basis is essential to ensure that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines, lost revenue or potential lawsuits. Fuel expense for the Genesee plants is predominantly comprised of coal supply. Coal is supplied under long-term agreements with the Genesee Coal Mine joint venture, of which we hold a 50% interest. The price of coal is based on a cost-of-service model with annual updates to inflation, interest rate and capital budget parameters and is, therefore, not subject to coal market price volatility. EPCOR and the Genesee Coal Mine joint venture maintain coal inventories which are available as fuel supply in the event that the coal mine equipment and operations suffer significant disruption. Power LP's coal-fired power plants (Roxboro and Southport) purchase coal and tire-derived fuel from local suppliers in the southeast U.S. The coal and coal-based fuel is transported to the power plants by rail service. Any disruption in rail service due to unforeseen circumstances could impair the operations of the coal-fired power plants if alternative transportation cannot be arranged in a timely manner. The level of waste heat fuel at Power LP's Ontario plants, provided by TransCanada Corporation's adjacent compressor stations, is dependent upon the amount of natural gas throughput on the pipeline and the output of the compressor stations. In addition, the availability of waste heat gases is dependent upon the compressor stations remaining in use and their ability to supply the waste heat gases. Performance of our hydroelectric facilities is dependent upon the availability of water. Variances in water flows are caused by uncontrollable weather related factors affecting precipitation and can result in volatility of hydroelectric plant revenues. In addition, the hydroelectric facilities are exposed to potential dam failure, which could affect water flows and have an impact on revenues from the associated plants. We manage the wood waste fuel risk at Power LP's biomass and wood waste plants through contracts with a number of wood waste suppliers, and a new two year wood supply agreement was negotiated in August 2007. We use several key computer application systems to support our various operations such as electricity and water distribution network control systems, electricity and water plant control systems and electricity settlement and billing systems. We take measures to reduce the risk of malicious corruption or failure of these systems and the hardware and network infrastructure on which they operate, as well as electronic theft of data. We maintain a Compliance and Ethics Policy which includes an Accounting and Auditing Complaint Procedures Policy which provides for confidential disclosure of any wrong-doing relating to accounting, reporting and auditing matters. Environment, health and safety risk Environment There are a variety of significant environmental risks associated with each of our power and water operations such as air emissions, water use, wastewater discharges, waste, land use and landfill. We manage these risks by incorporating the environment in our strategy, policies, processes and procedures. EPCOR's strategy includes a commitment to environmental performance on existing and new facilities, renewable energy and investment in the development of coal gasification with carbon capture and storage. In addition, EPCOR's environmental policy commits the Company and all of its employees to environmental compliance and stewardship. Each plant and facility has an environmental management system which meets the ISO 14001 standard. These systems encompass the identification of the scope, objectives, training and stewardship of our environmental responsibility. Each plant and facility is also subject to environmental audits to ensure compliance with all regulations. Our operations, technical support and environment departments work on technology solutions to emerging environmental issues such as mercury emission mitigation. We are active in the development of the CO2 offset market by designing protocols, developing projects that will qualify for offsets and trading offsets. EPCOR complies, in all material respects, with federal, provincial, state and local environmental legislation and guidelines with respect to its electricity operations. EPCOR's generation business is a significant emitter of carbon dioxide (a greenhouse gas), nitrogen oxides and sulphur dioxide. Compliance with future environmental legislation may require significant capital and operating expenditures and failure to comply could result in fines and penalties or the regulator could force the curtailment of operations. Canada On April 26, 2007, the Canadian Environment Minister proposed a new regulatory framework to reduce greenhouse gas emissions and air pollution in Canada and then released further information on the proposed regulatory framework on March 10, 2008. If adopted, the proposed framework would require a 20% absolute reduction in greenhouse gases from 2006 levels by 2020 and a 50% reduction in air pollution by 2015. Carbon dioxide, nitrogen oxide and sulphur dioxide emissions are all targeted for reduction under the proposed legislation. Some of the other key provisions of the proposed framework are: - The cleaner fuel standard for coal-fired generation would be supercritical pulverized coal technology (such as Genesee 3 and Keephills 3) and the cleaner fuel standard for natural gas-fired generation would be natural gas combined cycle technology; - The framework would apply to each generating facility with generating capacity greater than 10 MW (which would include most of EPCOR's generating units); - Corporations (such as EPCOR), that own existing generating facilities would be required to reduce the intensity of the emissions of their entire fleets by 18%, starting in 2010 and increasing by 2% per year thereafter; - New generating facilities placed into production after 2004 and before 2012 (such as Keephills 3), (i) would be allowed a 3-year commissioning period during which no intensity targets would apply, (ii) must comply with the cleaner fuel standard from and after commissioning, and (iii) must reduce their emissions by 2% per year after expiry of the commissioning period; - Greenhouse gas emitters (such as EPCOR), would be able to obtain credits for compliance by making contributions toward a fund to support the development of emission-reducing technology. EPCOR estimates that its costs of compliance with this framework could be range from $8 million to $12 million for 2010, escalating proportionately with the increasing emission reduction targets after 2010. This estimate is based on EPCOR's current fleet of generation assets and the costs of contributions to the technology fund as outlined in the proposed framework. Readers are cautioned that there are a number of uncertainties associated with this estimate including, but not limited to: whether the regulations that are enacted in the future reflect the proposed framework as described by the government on March 10, 2008; the extent to which future costs will be recoverable from customers; the future composition of EPCOR's fleet of generation assets; the future production of electricity from EPCOR's generation assets; the extent and timing of the development of a carbon offset market; whether economically feasible emission-reducing technology emerges; the market price for carbon offset credits and other measures that the Company might undertake to reduce its emissions. We participate in the Clean Air Strategic Alliance which has recommended to the Alberta government a framework on nitrogen oxide, sulphur dioxide, mercury and particulate emissions, for both natural gas-fired and coal-fired generation plants. EPCOR will participate in tests and install equipment over the next 3 years to meet Alberta requirements to reduce mercury emissions by 70% by 2011. Consistent with our strategy to anticipate and comply with environmental legislation, EPCOR is participating in a $33 million research project to undertake a front-end engineering design study of a clean coal project. The Government of Canada announced in October 2007 that it will partner with us, the Alberta Energy Research Institute (AERI) and the Clean Coal Power Coalition in this project. The Government of Canada is investing $11 million in the project through ecoENERGY Technology, and each of EPCOR and AERI will contribute the same amount. EPCOR will also contribute use of the Genesee site for the study. The work is scheduled for completion in 2009, and if subsequent investment and construction decisions go as planned, a 500 MW generating station using the new technology could be in operation in Alberta as early as 2015. Effective July 1, 2007, EPCOR is subject to the Alberta Government's new Specified Gas Emitters Regulation. The regulation is applicable to all facilities in Alberta that produce over 100,000 tonnes of carbon dioxide equivalent (CO2E or greenhouse gas) per year. Accordingly, EPCOR's Genesee generating units 1, 2 and 3 and the generating units subject to PPAs in which EPCOR holds interests (i.e. Sundance 5 and 6 and Battle River) are subject to the regulation. The regulation imposes a CO2E intensity reduction of 12% from the average CO2E emissions intensity for the 2003 to 2005 period. Under the regulation entities that cannot meet the reduction target may either contribute cash to an Alberta technology fund at $15 per tonne of excess emissions intensity or invest in Alberta based projects that reduce or offset emissions on their behalf. While compliance is required effective July 1, 2007, the first reporting deadline, which includes the submission of offsets, is March 31, 2008. The costs associated with compliance with the regulation for Genesee 1 and 2 generating units are recoverable from the PPA holder under the terms of the PPA. These costs amounted to $4 million in 2007 and are estimated to be approximately $11 million per year in the future. EPCOR's Genesee 3 unit is considered a new unit under the regulation and will receive a three-year grace period, after which its compliance obligation will be phased in over 5 years, starting at a 2% intensity reduction and increasing to 12% by the end of the 5 years. The estimated cost of EPCOR's share of the compliance cost after the grace and phase-in periods is approximately $3 million per year. EPCOR's share of the compliance costs for Sundance 5 & 6 is estimated to be approximately $5 million per year. The cost of compliance for our interest in the Battle River PPA is estimated to be approximately $2 million for each of 2008 and 2009. These cost estimates assume that no offsets will be used to comply with the regulation. We will likely use offsets which may reduce this estimated cost of compliance but their availability and cost are not yet determinable. In 2007, EPCOR recorded $3 million for the cost associated with this regulation. In September, 2007 there was an incident at our Miller Creek plant where a series of mechanical and operator errors caused a low water condition to occur in the creek on which the plant is located. B.C. Environment is investigating EPCOR's conduct at Miller Creek. Although the incident should not result in a material financial loss, we are taking the incident very seriously and taking steps to ensure that we prevent an episode like this from recurring. Our water operations comply in all material respects with federal, provincial, and local environmental legislation and guidelines. These operations are controlled through stringent water treatment standards and controls covering the quality of treated water and the number, frequency and form of water quality testing, as well as mandatory improvements to the water treatment process. We are actively involved in a watershed management program, which involves the protection and management of our Edmonton water source from impurities such as soil particles, excess nutrients, fertilizers, microbiological contaminants and organic materials. Activities undertaken include river water quality monitoring, forming stakeholder partnerships to work on watershed issues, and acting as a resource and leader on quality issues of the North Saskatchewan River Basin. United States We continually assess the potential impact on Power LP assets of future legislation and regulatory requirements for certain air emissions under the United States' Clean Air Act (US CAA). The US CAA Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) will affect the Roxboro and Southport facilities in North Carolina beginning in 2009. The North Carolina plants were pulled into the CAIR program, but did not receive nitrogen oxide and sulphur dioxide allocations. The costs associated with purchasing the required offset allocations are projected at approximately $1.5 million per year. Engineering and operating solutions are being pursued which will combine operating methods such as alteration of the fuel mix, and emissions controls to reduce the annual cost. The North Carolina plants are classified as low emitters of mercury as they emit less than 9 pounds per year at each plant. The plants will be required to install mercury emission monitoring equipment in order to comply with CAMR. The cost of the monitoring equipment is estimated at less than $0.2 million. The Kenilworth facility in New Jersey and the Castleton facility in New York are potentially affected by the Regional Greenhouse Gas Initiative applicable in seven New England states. The regulations are implemented on a state-by-state basis and we are monitoring the states' proposals and evaluating their impact on Power LP operations. California has recently enacted stringent limits on greenhouse gases and is currently developing regulations to implement the program. We are monitoring the state's progress and the features of the program to assess the financial and operational implications on Power LP's California plants. Compliance with future environmental legislation may require material capital and operating expenditures and failure to comply could result in fines and penalties or the regulator could force the curtailment of operations. There are significant uncertainties associated with the current legislative proposals including implementation details, their impact on current licenses and permits, and how compliance costs might be recovered through prices or shared among emitters, customers and stakeholders. Accordingly, it is not possible to provide meaningful estimates of the costs of complying with the proposed legislation or the net financial impact on EPCOR. Health and safety We manage our health and safety risks through company-wide health and safety management processes. We also monitor our health and safety performance against recognized industry and internal performance measures. Our operations are subject to the risks of a widespread influenza outbreak or other pandemic illness. We have developed plans to respond to a potential pandemic influenza to help maintain a sufficient healthy workforce and enable the Company to deliver reliable power and water to customers in such an event. Government and regulatory risk EPCOR is subject to risks associated with changes in federal, provincial, state, local or common law, regulations and permitting requirements in Canada and the United States. It is not possible to predict changes in laws or regulations that could impact the Company's operations, income tax status or ability to renew permits as required. Under the Settlement System Code of the Electric Utilities Act (Alberta), a retailer must rely on load settlement agents to provide customer consumption data to be used in computing its customers' bills. Under the Alberta Regulated Default Supply Regulation, regulated rate providers may not collect from customers an amount undercharged due to a billing error if the error occurred more than 12 months before the date of the revised billing. Effective January 1, 2008 the Alberta Energy and Utilities Board (AEUB) was separated into two boards, the AUC and the Energy Resources Conservation Board, with new regulations. The intent was to bring more resources to both electricity and oil sands issues. The new regulations provide the AUC with authority to impose harsher penalties for noncompliance. Under these new rules, potential fines for serious infractions, such as exercising market power, could be as high as $3 million per day. EPCOR believes that its governance and monitoring policies reduce the risk of EPCOR incurring such fines. In 2006, the AUC (formerly AEUB) set final rates for the 2005 and 2006 Distribution and Transmission tariffs and RRT non-energy charges. In 2007 EPCOR filed its 2007 - 2009 tariff application for its RRT non-energy charges. EPCOR filed its Distribution and Transmission 2007 - 2009 tariff application at the end of January 2008. These application processes have risks customarily associated with rate-regulated tariff filings. The AUC sets rates intended to permit the regulated Distribution and Transmission business to recover estimated costs of providing service and a fair rate of return on investment in distribution and transmission. In its current RRT non-energy tariff application, the Company has applied for a return margin (a percentage of revenue), rather than a traditional return on rate base. Our ability to recover the actual costs of providing service and to earn a fair return is dependent upon achieving the forecasts established in the rate-setting process. On June 8, 2005, the Government of Alberta announced a new 5-year RRO for residential, farm and small commercial Alberta electricity consumers. The new RRO replaced the Regulated Rate Tariff which expired on June 30, 2006 and regulates our charges to these customers for energy. The RRO became the default option for consumers in the aforementioned customer segments who have not entered into contracts with an electricity retailer. Commencing on July 1, 2006, the new RRO uses a combination of long-term and monthly forward hedges, with an increasing percentage of monthly forward hedges over the 5-year transition period. At the end of the transition period in 2010, the new RRO is intended to be similar to the design of the current Alberta natural gas default rate, which is based on monthly forward prices. As this electricity pricing model results in increasing volatility in prices to our customers over the transition period, it may impact our volume of electricity sales, as well as electricity margins. To date the financial impact to EPCOR has been insignificant. EPCOR's water treatment and distribution services to customers within The City of Edmonton are rate-regulated by The City of Edmonton Council pursuant to a performance based rates bylaw. Rates approved under this bylaw are intended to allow the Company to recover its operating costs and earn a return on equity, as well as provide an incentive to manage cost increases below inflation. If the performance targets outlined in the bylaw are achieved, water rates are increased by the change in the rate of inflation less an efficiency factor. The City of Edmonton Council approved a renewal of the PBR bylaw on July 4, 2006 for the 5-year period commencing April 1, 2007. Our ability to fully recover operating and capital costs and to earn a fair return is dependent upon achieving the performance targets prescribed in the Bylaw, maintaining cost increases below inflation and managing operational risks. Rates for water sales to regional water commissions that supply water to communities surrounding Edmonton are regulated by the AUC on a complaints-only basis, whereby such communities may apply to the AUC to resolve disputes related to rates, tolls or charges determined by the Company. EPCOR sets the rates it charges to these regional water commissions to recover related operating and capital costs plus a reasonable rate of return. Actual operating and capital costs associated with the provision of water to the commissions and a fair return on rate-base, are recovered in accordance with a full cost-of-service method which has been approved by the AUC. Income Tax Risk On September 21, 2007, the U.S. and Canada signed the fifth protocol to the U.S. - Canada Income Tax Treaty (Treaty), which contains extensive changes to the current Treaty. The Treaty included the addition of a treaty denial provision applicable to payments obtained from or through certain hybrid entities. A hybrid entity in this context means one with different tax treatments under different tax jurisdictions, which is the case for Power LP. The Treaty has not yet been ratified and the treaty denial provision will not be effective earlier than 2010. EPCOR continues to evaluate the potential impact, if any, that the treaty denial provisions will have but management expects to be able to address the denial provisions without realizing any materially adverse tax consequences. Canadian tax legislation, (SIFT Legislation) related to specified investment flow-through entities (SIFTs) included in Bill C-52 was enacted in 2007 and will result in changes to how certain publicly traded trusts and partnerships, including Power LP, are taxed. It is expected that under this legislation Power LP will become taxable commencing in 2011 as long as it does not exceed the Canadian Department of Finance's normal growth guidelines by issuing greater than $1.7 billion of new equity before 2011. All other things being equal, the SIFT Legislation will likely result in a reduction of cash available for distribution by Power LP commencing after 2010. Project risk Our construction and development of generation, electric transmission and distribution, and water treatment facilities and acquisition activities are subject to various engineering, construction, stakeholder, government and environmental risks, many of which are beyond our control. Furthermore, rapid cost escalation has occurred in a number of regions in which we operate. These risks can translate into performance issues, delays and cost overruns. We attempt to mitigate these risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into favourable long-term contracts for output and services to be provided where and when available. Supply risk of Alberta PPAs EPCOR holds interests in acquired PPAs, which entitle the Company to its proportionate interest in the electricity produced from specific generating units up to their committed capacity. In most cases when plant capability falls below committed capacity, we are entitled to receive our relative portion of the availability payments from the plant owners based on the 30-day rolling average power pool prices and target availability. The occurrence of an event which disrupts the ability of the power plants to produce or sell power or thermal energy for an extended period under the PPAs, preventing the PPA owners from fulfilling their obligations under the PPAs, could have a material negative impact on our ability to generate revenue. In such circumstances, we may be required to replace unavailable generation output with electricity at prevailing market rates, while being relieved of the obligation to pay the unit capacity fee. Depending on market liquidity, the prices could be significantly higher than the prices inherent in the PPA, thus increasing the cost of our energy purchases. Credit risk Credit risk is the possible financial loss associated with the ability of counterparties to satisfy their contractual obligations to EPCOR, including payment and performance. We manage credit risk and limit exposures through our credit policies and procedures. These include an established credit review process, specific terms and limits, credit diversification, daily monitoring of wholesale exposures against credit limits, appropriate allowance provisioning and use of credit mitigation strategies, including collateral arrangements. Wholesale credit risk Exposure to credit risk for wholesale and trading counterparties is measured by calculating the costs (or proceeds) of replacing the commodity position (physical and derivative contracts), adjusting for settlement amounts due to or due from the counterparty and netting amounts if permitted by legally enforceable set-off rights. Due to price volatilities of electricity and natural gas, the market value of individual credit exposures could exceed the credit limits granted to those counterparties. If the counterparty fails to perform its obligations EPCOR could incur a material loss. This could include, but is not limited to, the cost of replacing the obligation, a loss on amounts owed from the counterparty or a loss incurred on liability settlements. EPCOR's exposure to wholesale and trading counterparties is summarized below. Exposures represent 60 days of potential accounts receivable plus the fair value of the contracts. ------------------------------------------------------------------------- December 31 ($ millions) 2007 2006 Wholesale (includes industrial end-use customers, trading and position management counterparties) Investment grade(1) $ 117 $ 116 Below-investment grade(1) 19 14 ------------------------------------------------------------------------- Total $ 136 $ 130 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Credit ratings are based on EPCOR's internal analyses which take into account the ratings of external credit rating agencies. The year-over-year increase in the credit exposure of both investment grade and below-investment grade counterparties is primarily due to additional transactions with current counterparties. RRT and default supply credit risk Exposure to credit risk for residential and commercial customers under default power supply rates are generally limited to amounts due from the customers for electricity consumed but not yet paid for. As the electricity procurement for these customers has evolved to shorter terms, our exposure to losses for the purchase of electricity that is not consumed has been mitigated. This portfolio is reasonably well diversified with no significant credit concentrations. Historically, credit losses in these customer segments have not been significant and depend in large measure on the strength of the economy and the ability of the customers to effectively manage their affairs through economic cycles and competitive pressures. Should economic or market conditions decline in the regions in which we provide service, we may experience additional credit losses in these segments. Although regulations allow for recovery of a percentage of unforecasted credit losses through a deferral account, EPCOR monitors credit risk for this portfolio at the gross exposure level. EPCOR's exposure to RRT and default customer credit risk, which is primarily the risk of non-payment for electricity consumed by these end-use customers, is summarized below. Exposures represent a 60-day potential accounts receivable value for this portfolio. ------------------------------------------------------------------------- December 31 ($ millions) 2007 2006 Unrated RRT and default supply customers(1) $ 144 $ 151(2) ------------------------------------------------------------------------- (1) Under the Alberta Electric and Utilities Act, EPCOR provides electricity supply in its service area to residential, irrigation and small commercial customers and those commercial and industrial customers in its service areas who have not chosen a competitive offer and consume electricity under default supply arrangements. (2) December 31, 2006 value includes $141 million of accounts receivable and $10 million of fair value exposure. In the RRT and default supply category, the year-over-year increase in exposure related to the 60-day potential accounts receivable from $141 million to $144 million was driven by higher electricity prices. Power LP credit risk The values above do not include EPCOR's exposure to credit risk derived from activities within Power LP. Power LP has exposure to credit risk associated with counterparty default under its power and steam sales contracts, energy supply agreements and foreign currency hedges. In the event of default by a counterparty, existing PPAs and steam purchase agreements may not be replaceable on similar terms as many of these agreements have favourable pricing relative to their current markets. Power LP's counterparty risk is managed by making appropriate credit assessments of counterparties, dealing with creditworthy counterparties, diversifying the risk using several counterparties and where appropriate and contractually allowed, requiring the counterparty to provide appropriate security. Availability of people Our ability to continuously operate and grow the business is dependent upon retaining and developing sufficient labour and management resources. As with most organizations, we are facing the demographic shift where a large number of employees is expected to commence retirement over the next few years. In addition, the market for labour and management, particularly in Alberta and British Columbia, is extremely competitive. Although a legislated forced arbitration for Alberta building trades in the third quarter eliminated the risk of a legal strike, general labour challenges remain as a risk to the timing and cost of our projects in the province. We believe that we employ good human resource practices and have been named a top 100 employer in Canada for 8 consecutive years. We continue to monitor developments and review our human resource strategies to ensure we have an adequate supply of labour and management. Weather risk Weather can have a significant impact on our operations. Temperature levels, seasonality and precipitation, within EPCOR's markets and adjacent geographies, can affect the level of demand for electricity and natural gas, thus resulting in electricity and natural gas price and volume volatility. In addition, the level of precipitation affects the availability of our hydro generating units and impacts the cooling pond reservoir level at the Battle River generation plant, which in turn can impact the performance of our interest in the Battle River PPA. Melting snow, freeze/thaw cycles and seasonal precipitation events in the North Saskatchewan River watershed affect the quality of water entering our water treatment plants and the resulting costs of purification. Weather variability and seasonality also impact the demand and supply of water. Extreme weather can impact the physical operation of our facilities. Two of Power LP's facilities are situated in North Carolina, a region susceptible to hurricanes. Weather related financial instruments are available in the financial markets but we have not pursued them due to their limited coverage and relatively high cost. Financial exposures associated with extreme weather are managed through our insurance programs. Foreign exchange risk Fluctuations in the exchange rate between either the U.S. dollar or the Euro, and the Canadian dollar affect some of our revenues, capital costs, operating costs and cash flows, and could have an adverse impact our financial performance and condition. The foreign exchange risk of anticipated U.S. dollar denominated cash flows from Power LP's U.S. plants is managed through the use of forward foreign exchange contracts for periods of up to 7 years. At December 31, 2007, US$281 million (2006 - US$331 million) or approximately 83% (2006 - 70%) of these future cash flows were economically hedged for 2008 to 2013 (2006 - 2007 to 2013) at a weighted average exchange rate of 1.13 (2006 - 1.14). In situations where EPCOR contracts to purchase large value parts for Generation and, Distribution and Transmission operations from suppliers outside of Canada, we generally fix the purchase price in Canadian dollars by contracting in Canadian dollars or using forward foreign exchange contracts. Conflicts of interest Certain conflicts of interest could arise as a result of EPCOR's relationship with The City of Edmonton, which is EPCOR's sole common shareholder and regulator for EPCOR's water utility rates in Edmonton. In addition, certain conflicts of interest could arise as a result of EPCOR's relationship with Power LP. The Company is, through wholly-owned subsidiaries, Power LP's principal unitholder, 100% owner of the general partner, EPCOR Power Services Ltd. (GP), and through wholly-owned subsidiaries of the Company in both Canada and the U.S., manager of the assets and operations of Power LP. Other conflicts of interest could arise as a result of Power LP's relationship with Primary Energy Recycling Corporation (PERC). Ventures, a wholly-owned subsidiary of Power LP, also has a 15.4% equity ownership of and provides management and administrative services to PERC, PERH and PERH's subsidiaries under a management agreement. PERC, through PERH and its subsidiaries, engages in activities similar to those of Power LP and Ventures. PERC owns the remaining 84.6% equity in PERH. Certain senior officers of EPCOR are officers and directors of GP and Power LP's subsidiaries. The board of directors of the GP currently has eight members, four of whom are EPCOR elect directors and four of whom are independent directors within the meaning of applicable Canadian securities laws. The chairman of the board of directors of the GP is an executive officer of EPCOR and has a casting vote or second vote in the case of a tie vote at any meeting of the GP board of directors. General economic conditions, business environment and other risks The Company is exposed to potential recovery and fair value measurement uncertainty in respect of its investment in third party ABCP. See Asset-Backed Commercial Paper under Significant Events. The credit and liquidity issues that impacted the global economy in 2007 have resulted in credit markets being less readily accessible. In addition, Power LP's unit price is exposed to market volatility. These conditions pose a risk to the Company's plans for new project financing. Transmission risk relates to blackouts or constraints on the system which result in curtailment of output at generation facilities or restrictions on the development of interconnections with new generation facilities. This risk is mitigated by the terms of our PPAs and long-term power contracts. We also manage our relationships with regulators and governments to ensure that appropriate transmission capability and technology is developed in a timely manner. Fluctuations in interest rates, product supply and demand, market competition, risks associated with technology, EPCOR's ability to generate sufficient cash flow from operations to meet its current and future economic and business conditions, EPCOR's ability to access external sources of debt and equity capital, general economic and business conditions, EPCOR's ability to make capital investments and the amounts of capital investments, risks associated with existing and potential future lawsuits and other regulations, assessments and audits (including income tax) against EPCOR and its subsidiaries, political and economic conditions in the geographic regions in which EPCOR and its subsidiaries operate, difficulty in obtaining necessary regulatory approvals, a significant decline in EPCOR's reputation and such other risks and uncertainties described from time to time in EPCOR's reports and filings with the Canadian Securities authorities could materially adversely impact EPCOR's business, prospects, financial condition, results of operations or cash flows. Our ability to mitigate these risks is dependent upon management's ability to anticipate such risks and, where possible, to develop appropriate mitigation plans. The following table outlines our estimated sensitivity to specific risk factors as at December 31, 2007. Each sensitivity factor provides a range of outcomes assuming all other factors are held constant and current risk management strategies, including hedges, are in place. Under normal circumstances, such sensitivity factors will not be held constant but rather, will change at the same time as other factors are changing. In addition, these sensitivities are presented at December 31, 2007 and the degree of sensitivity to each factor will change as the Company's mix of assets and operations subject to these factors changes or the degree of commodity hedge coverage changes. ------------------------------------------------------------------------- Factor Annual Annual ($ millions) Change Cash Flow Net Income ------------------------------------------------------------------------- Wholesale price of electricity - Alberta(1) + $5/MWh + 4 - 9 Wholesale price of natural gas(1) + $1/Gj nominal + 13 US exchange rate - strengthening + $0.01 CDN dollar (CDN to US dollar) nominal + 2 Short-term interest rates +1.0% - 2 - 2 Increase in water consumption - Alberta +3.0% +4 +4 Canadian federal and provincial income tax rates -1.0% + 1 + 3 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Sensitivities to wholesale prices of electricity and natural gas include the impact of fair value changes in derivative financial instruments that are not hedges for accounting purposes. CONTROLS AND PROCEDURES For purposes of certain Canadian securities regulations, EPCOR is a "Venture Issuer". As such, effective November 23, 2007, it was exempted from the requirements of MI 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings as long as it files Basic Annual Certificates and Basic Interim Certificates for periods ending on or after December 31, 2007. Accordingly, the Chief Executive Officer and Chief Financial Officer have reviewed the annual information form, annual financial statements and annual MD&A, for the year ended December 31, 2007. Based on their knowledge and exercise of reasonable diligence they have concluded that these materials fairly present in all material respects the financial condition, results of operations and cash flows of the Company for the periods presented and they do not contain any misrepresentations. In addition, as of December 31, 2007, management conducted an evaluation of the design and effectiveness of the Company's disclosure controls and procedures. The evaluation took into consideration the Company's Disclosure Policy, the sub-certification process that has been implemented, and the functioning of its Disclosure Committee. In addition, the evaluation covered the Company's processes, systems and capabilities relating to public disclosures, and the identification and communication of material information. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's disclosure controls and procedures are appropriately designed and effective. Also as of December 31, 2007, management conducted an evaluation of the design of internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that the Company's internal controls over financial reporting are appropriately designed. These evaluations were conducted in accordance with the standards of the Committee of Sponsoring Organizations (COSO), a recognized control model, and the requirements of Multilateral Instrument 52-109 of the Canadian Securities Administrators. There were no changes in the Company's internal controls over financial reporting that have occurred during the year ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting. NEW ACCOUNTING STANDARDS IN 2007 Financial instruments, hedges and comprehensive income Commencing January 1, 2007, we adopted new accounting standards as issued by the Canadian Institute of Chartered Accountants (CICA) for Comprehensive Income, Equity, Financial Instruments and Hedges. In accordance with the new standards, our comparative financial statements have not been restated as a result of implementing the new accounting standards except to reclassify unrealized foreign currency translation gains and losses on net investments in self-sustaining foreign operations from the cumulative translation adjustment account to accumulated other comprehensive income, both within shareholder's equity. A statement called Consolidated Statement of Comprehensive Income has been added to our consolidated financial statements. This statement includes net income and the components of other comprehensive income such as (a) unrealized gains or losses arising from the translation of net investments in self-sustaining foreign operations, (b) the changes in fair value of the effective hedge portion of derivative instruments used in cash flow hedges of electricity sales and purchases of anticipated foreign currency cash flows and (c) changes in the fair value of available-for-sale financial instruments. As the foreign exchange gains and losses are realized or the hedged item of the cash flow hedge affects income, these items of other comprehensive income are reclassified to the income statement. Other comprehensive income is intended to capture the changes in the fair value of the financial instruments, derivatives or translated balances which would not otherwise be recorded in the financial statements. Each component of the statement of comprehensive income is recorded net of income taxes. Accumulated other comprehensive income is a new component of shareholder's equity. Financial instruments The new standards require that financial assets be classified as "available for sale", "held for trading", "held to maturity", or "loans and receivables". Financial liabilities are classified as either "held for trading" or "other liabilities". Initially, all financial assets and financial liabilities must be recorded on the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability. We classify our cash, cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading, and measure them at fair value. Accounts receivable are classified as loans and receivables and accounts payable and accrued liabilities are classified as other liabilities. Accounts receivable and accounts payable and accrued liabilities are measured at amortized cost and their fair values are not materially different from their carrying values due to their short-term nature. The classification, carrying values and fair values of other financial instruments held at December 31, 2007 are as follows: ------------------------------------------------------------------------- Carrying value ------------------------------------------------- Loans and Other Total Held for Available receiv- financial fair ($millions) trading for sale ables liabilities Total value ------------------------------------------------------------------------- Other assets $ 60 $ 63 $ 98 $ - $ 221 $ 224 Long-term debt (including current portion) - - - 2,139 2,139 2,226 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Long-term debt includes The City of Edmonton debentures which are offset by the payments made by the Company into the sinking fund. Although the accumulated contributions to the sinking fund are classified as available for sale, they are included as an offset to long-term debt under financial liabilities in the table above, consistent with how they are presented on the balance sheet. The accumulated contributions to the sinking fund and our interest in the PERH preferred shares (included in other assets) are measured at cost as they are not quoted in an active market. Transaction costs on financial assets and liabilities classified as other than held for trading are capitalized and amortized over the expected life of the instrument utilizing the effective interest method. Prior to January 1, 2007, transaction costs related to long-term debt were deferred and amortized on a straight-line basis over the term of the debt. Accordingly, we reclassified $15 million of debt issue costs from other assets to long-term debt effective January 1, 2007 and are amortizing them over the term of the debt using an effective interest rate. Risk management and hedging activities We are exposed to changes in energy commodity prices, foreign currency exchange rates and interest rates. We use various risk management techniques, including derivative instruments such as forward contracts, fixed-for-floating swaps, and option contracts, to reduce this exposure. The derivative instruments assets and liabilities used for risk management purposes consist of the following: ------------------------------------------------------------------------- Foreign Interest Energy exchange rate ---------------- Cash flow Non- Non- Non- ($millions) hedges hedges hedges hedges Total ------------------------------------------------------------------------- Total derivative instruments net assets (liabilities) as at December 31, 2007 $ (93) $ 75 $ 24 $ - $ 6 ------------------------------------------------------------------------- Total derivative instruments net assets (liabilities) as at December 31, 2006 - (11) 5 1 (5) ------------------------------------------------------------------------- ------------------------------------------------------------------------- We use various open-market derivative instruments with arm's-length parties, including CfDs, to manage our exposure to risks associated with electricity and natural gas prices, foreign exchange rates and interest rates. These derivative instruments are recorded at fair value on the balance sheet unless they are designated as hedges which are effective, or if we elect the fair value exemption for non-financial derivatives that are entered into and continue to be held for the purpose of receipt or delivery of a non-financial item in accordance with our expected purchase, sale or usage requirements. At December 31, 2007, the fair value of our aggregate energy commodity derivatives used for risk management purposes, including derivatives that were not designated as hedges for accounting purposes, was in a net derivative liability position. This was due to a net long position for the short-term portion of the financial electricity portfolio combined with decreases in the forward Alberta electricity prices for 2008, relative to the contract prices. In addition, a net short position for the long-term portion of the financial electricity portfolio combined with increases in the forward Alberta electricity prices for the period from 2009 to 2016 resulted in a net derivative liability for these contracts. This derivative liability position was partly offset by the net derivative asset for unrealized gains on our natural gas supply contracts due to increases in forward natural gas prices relative to the contract prices. Unrealized and realized gains and losses on energy derivatives that are not designated as hedges for accounting purposes are recorded in energy revenues, energy purchases or cost of fuel as appropriate. For energy derivatives that are designated as hedges, unrealized gains and losses are recorded in other comprehensive income and reclassified to net income as energy revenues or energy purchases when realized. For the year ended December 31, 2007, the fair value of our forward foreign currency contracts increased, resulting in unrealized gains primarily due to the impact of a strengthening Canadian dollar in the current year on forward foreign exchange sales contracts used to hedge $US-denominated revenues. This was partly offset by higher unrealized losses on forward foreign exchange purchase contracts used to hedge anticipated $US-denominated purchases in 2007. The weighted average fixed exchange rate for contracts outstanding at December 31, 2007 was US$0.90 (December 31, 2006 - US$0.88) for every Canadian dollar. Unrealized and realized gains and losses on foreign exchange derivatives that are not designated as hedges for accounting purposes are recorded in energy revenues or foreign exchange gains and losses. Unrealized and realized gains and losses on interest rate derivatives that are not designated as hedges for accounting purposes are recorded in financing expenses. Unrealized gains and losses on foreign exchange or interest rate derivatives that are designated as hedges are recorded in other comprehensive income and reclassified to net income as energy revenues, foreign exchange gains and losses, or financing expenses when realized. Energy derivatives designated as accounting hedges At December 31, 2007, the net fair value of energy financial derivative instruments designated and qualifying for hedge accounting was a liability of $93 million and is included in derivative instruments assets and derivative instruments liabilities on the consolidated balance sheet. Prior to January 1, 2007, the fair value of financial derivative instruments that qualified for hedge accounting was not recorded in the balance sheet and was disclosed as an off-balance sheet item. The January 1, 2007 net fair value of these financial derivative instruments that were designated and qualified for hedge accounting was a liability of $60 million. Unrealized gains and losses for fair value changes on these financial derivatives that qualify for hedge accounting are recorded in other comprehensive income. Energy derivatives not designated as accounting hedges Unrealized changes in fair value on financial and non-financial derivatives that either do not qualify or we elect not to apply for hedge accounting treatment, and non-financial derivatives that do not qualify for the expected purchase, sale or usage requirements of the contract, are recognized in net income. The corresponding unrealized changes in the fair value of the associated hedged exposures are not recognized in income. Derivative instruments that are recorded at fair value can produce volatility in net income as a result of fluctuating forward commodity prices, exchange rates and interest rates which are not offset by the unrealized fair value changes of the exposure being hedged. As a result, the recording of gains or losses for changes in fair values of derivative instruments for accounting purposes does not necessarily represent the underlying economics of the hedging transaction. For example, we have more physical supply of power in Alberta from our generating stations and power purchased under PPAs than we have contracted to physically sell. We utilize financial sells to reduce our exposure to changes in the price of power in Alberta. Economically, we benefit from higher Alberta pool prices due to our net long position, as our expected physical supply is in excess of our physical and financial sells. However, financial sells that are not hedged for accounting purposes are recorded at fair value at each balance sheet date and the offsetting anticipated future physical supply (or hedged item) is not. Accordingly, an increase in forward Alberta power prices can result in fair value losses for accounting purposes whereas on an economic basis these losses are offset by unrecognized economic gains on the physical supply. This economic gain will be recognized in later periods when power is produced and sold. The opposite is true for forward price decreases in Alberta power prices. As a result of adopting the new accounting standards, all non-financial derivative instruments are required to be measured at fair value unless they are designated as contracts used for the purpose of receipt or delivery of a non-financial item in accordance with our expected purchase, sale or usage requirements. We hold certain physical power and natural gas purchase and sales contracts that are used to meet power generation and retail customer requirements. Certain of the natural gas purchase contracts were not designated as contracts used in accordance with our expected purchase requirements, as defined in the accounting standard, since the natural gas can at times be re-sold in the market and not entirely used to produce electricity or to sell to end-use consumers. These contracts were therefore recorded at fair value in the balance sheet. As at January 1, 2007, the fair valuation of fuel supply contracts in Power LP resulted in an increase in derivative instruments assets of $96 million, an increase in non-controlling interests of $66 million, an increase in future income tax liabilities of $10 million, and an increase in opening retained earnings, net of income taxes, of $20 million. The fair valuation of other physical power and natural gas purchase and sales contracts resulted in opening transition adjustments that increased derivative instruments assets by $45 million and derivative instruments liabilities by $45 million. In addition, opening 2007 retained earnings decreased $8 million net of income taxes to recognize the fair value of the ineffective hedge portion of previously deferred losses. Other Comprehensive Income As of January 1, 2007, the changes in the fair value of the effective hedge portion of the financial derivative contracts used to manage our energy portfolio and designated as accounting hedges, are recorded in other comprehensive income. The ineffective portion of the contracts is recorded in net income. Prior to January 1, 2007, such financial contracts were recorded in the income statement as they settled. The transition adjustment to opening accumulated other comprehensive income included unrealized losses, net of income taxes, of $42 million related to cash-flow hedging relationships and $1 million of unrealized gains, net of non-controlling interests and income taxes, related to previously discontinued cash flow hedges no longer deferred in derivative instruments assets and liabilities in the consolidated balance sheet. For the year ended December 31, 2007, a cumulative loss, net of income taxes, of $70 million was recorded in other comprehensive income for the effective portion of cash flow hedges, and an unrealized loss, net of income taxes, of $46 million was re-classified to energy purchases and revenues as appropriate. There was no ineffective portion of cash flow hedges for which unrealized losses were required to be recognized in income. Of the $64 million in net losses recorded in accumulated other comprehensive income, net losses of $45 million (net of taxes of $20 million) related to derivative instruments designated as cash flow hedges at December 31, 2007 are expected to settle and be reclassified to net income over the next twelve months. Unrealized gains on financial instruments designated as available for sale are related to certain venture capital investments which are focused on strategic elements of the energy and water value chain. Some of the shares held are not typically traded on an exchange and therefore are difficult to value. During the year ended December 31, 2007, an unrealized fair value gain on a venture capital investment was recognized in other comprehensive income as a result of market value appreciation after the initial public offerings of the investment in June 2007. We have considered the effect of illiquidity and the restrictions on the shares held in determining their fair value. FUTURE ACCOUNTING CHANGES International financial reporting standards In 2005, the CICA announced plans to converge Canadian GAAP with International Financial Reporting Standards (IFRS) over a transition period from 2006 to 2011. The CICA has indicated that Canadian reporting issuers will need to begin reporting under IFRS by the first quarter of 2011 with comparative figures. We have developed a high level plan for the implementation of IFRS and are assessing the impact of the differences in accounting standards to EPCOR's financial statements. Based on our analysis thus far, we anticipate that the more significant differences for EPCOR will be in the areas of property, plant and equipment, regulatory accounting, joint arrangements, financial instruments, hedges, income taxes, impairments, business combinations, goodwill, asset retirement obligations, foreign exchange and financial statement disclosures. It is not practically possible to quantify the impact of these differences at this stage. We also expect to make changes to certain processes and systems before 2010, in time to enable us to record transactions under IFRS for comparative purposes in our financial reporting in 2011. Capital disclosures and financial instruments - presentation and disclosures On December 1, 2006, the CICA issued the new CICA Handbook Sections 1535, 3862 and 3863 for Capital Disclosures and Financial Instruments - Disclosures and Presentation. Effective January 1, 2008, the Company will adopt these new accounting standards. As required by the new standards, the Company will disclose quantitative and qualitative information that is intended to provide users of the financial statements with additional insight into the Company's risks associated with financial instruments and how these risks are managed. These risks include credit, liquidity and market risks. The disclosures will also include information on how the Company manages its capital. Inventories Effective January 1, 2008 the new CICA Handbook Section 3031 Inventories will replace Section 3030. The new section requires inventories to be measured at the lower of cost and net realizable value, which is consistent with EPCOR's current policy for measuring inventories held for resale. EPCOR currently measures inventories held for consumption at the lower of cost and replacement value. We do not expect the adoption of the new standard to result in a material transition adjustment to the financial statements. Rate-regulated operations In December 2007 the CICA amended Handbook Sections 1100 - Generally Accepted Accounting Principles and 3465 - Income Taxes, and made consequential amendments to Accounting Guideline 19 - Disclosures by Entities Subject to Rate Regulation. The amendments removed the temporary exemption from the requirement to apply Section 1100 to the recognition and measurement of assets and liabilities arising from rate regulation. They also require rate-regulated enterprises to recognize future income taxes separate from the regulatory asset or liability for the future recovery from or refund to customers for those income taxes. The guidance is now consistent with corresponding guidance under U.S. generally accepted accounting principles. We will assess our accounting for rate-regulated operations in relation to these amendments but do not expect them to be material to EPCOR. These amendments are effective January 1, 2009. Goodwill and intangible assets In February 2008, the CICA issued Handbook Section 3064 - Goodwill and Intangible Assets and consequential amendments to Section 1000 - Financial Statement Concepts. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions in IFRS. The provisions relating to goodwill are unchanged from those of the replaced Section 3062 - Goodwill and Other Intangible Assets. EPCOR will review its capitalization policies and practices for internally developed software for compliance with the new standard which will determine the impact of the amendments to EPCOR by the end of 2008. These amendments are effective January 1, 2009. SIGNIFICANT ACCOUNTING POLICIES Revenue recognition under PPAs Our Genesee power generation units 1 and 2 operate under a PPA. Under the terms of the Genesee PPA, the target levels of generation availability set out in the PPA recognize that the generation units will experience planned and forced outages over the terms of the PPA. The Company records the electricity revenue from the generation units under PPAs at the price embedded in the PPAs, including expected incentives and penalties for operating above or below specified availability targets set out in the PPA. Under this approach, incentives for the current period are deferred since they are not expected to be sustained over the full term of the PPA. As penalties are incurred, any balance of deferred incentive will be drawn down. If cumulative penalties exceed cumulative incentives, the excess will be charged to income and no deferred charge will be created. Deferred incentive amounts are included in other non-current liabilities in the balance sheet. The degree to which incentives are recognized or deferred will change due to revisions to the long-term outlook of plant performance, which is based on historical performance, planned maintenance, reliability and generation availability, and due to revisions in the estimated long-term price embedded in the PPA. Revenues from the Company's power generation plants located outside of Alberta are recognized upon delivery of output or upon availability of delivery as prescribed by contractual arrangements. These contractual arrangements are also commonly referred to as PPAs. Revenues under the Curtis Palmer PPA are recognized at the lower of (1) the cumulative billable contract price per megawatt hour (MWh) and (2) an amount determined by the MWhs made available during the period, multiplied by the average price per MWh over the term of the contract. Any excess of the contract price over the average price is recorded as deferred revenue. Financial commodity contracts EPCOR uses CfDs for risk management purposes. Our accounting policies for financial instruments, including CfDs and non-financial derivatives are discussed under New Accounting Standards in 2007. Consolidation of Power LP While EPCOR owns only 30.6% of the outstanding units of Power LP, it controls Power LP under generally accepted accounting principles. Accordingly, the acquisition of EPCOR's interest in Power LP was accounted as a business combination with full consolidation of the financial position and results of Power LP in the financial statements of EPCOR from the date of acquisition. CRITICAL ACCOUNTING ESTIMATES In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements. Electricity revenues, costs and unbilled consumption Due to the imprecision in customer consumption data received from load settlement agents, the lag between billing dates and meter reading dates and the lag between billing dates and financial reporting dates, we must use estimates for determining the amount of energy consumed but not yet billed. These estimates affect accrued revenues and accrued energy costs of the Energy Services segment. There are a number of variables in the computation of these estimates, and the underlying energy settlement processes within EPCOR and the Alberta and Ontario electric systems are complex. Owing to the factors above and the statutory delays in final load settlement determinations and information, adjustments to previous estimates could be material. Estimates for unbilled consumption average about $90 million at the end of each month and these estimates vary from $75 million to $115 million. Adjustments of estimated revenues to actual billings were less than $6 million per month. Fair values We are required to estimate the fair value of certain assets or obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures. Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, we use appropriate price modeling to estimate fair value. For determining purchase price allocations for business combinations the Company is required to estimate the fair value of acquired assets and obligations. Goodwill arising on business combinations is tested for impairment annually or more frequently if events and circumstances indicate that a possible impairment may exist. To test for impairment, the fair value of the reporting unit to which the goodwill relates is compared to the carrying value, including goodwill, of the reporting unit. If the carrying value of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any. The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from its use and eventual disposition. An impairment loss, if any, would be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset. Estimates of fair value for purchase price allocations, and goodwill and other asset impairments as described above, are mainly based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will be based on, among other things, the lives of the assets, contract prices, estimated future prices, revenues and expenses, including inflation, and required capital expenditures. The fair values of asset retirement obligations are estimated using the total undiscounted amount of the estimated future cash flows required to settle the obligations and applying the appropriate credit-adjusted risk-free discount rate. In this process assumptions are made regarding the useful lives of the assets and the legal restoration obligations. The range for the estimates of fair value for the purposes of determining an asset retirement obligation varies by asset. Allowance for doubtful accounts We continually review our aged accounts receivable and assess the underlying credit quality of the customers or counterparties. The allowance for doubtful accounts reflects an estimate of the accounts receivable that are ultimately expected to be uncollectible. It is based on a number of factors including the aging of receivables, historical write-offs within customer groups, assessments of the collectibility of amounts from individual customers and general economic conditions. EPCOR's allowance account averaged $6 million (2006 - $6 million) and reported bad debts, net of recoveries were $1 million in 2007 (2006 - $3 million). The estimate of the allowance affects accounts receivable and all segments' operations, maintenance and administration expenses. Useful lives of assets Depreciation and amortization allocate the cost of assets over their estimated useful lives on a systematic and rational basis. Depreciation and amortization also include amounts for future decommissioning costs and asset retirement obligation accretion expenses. Estimating the appropriate useful lives of assets requires significant judgement and is generally based on estimates of common life characteristics of common assets. Income taxes and amounts in lieu of income taxes EPCOR follows the asset and liability method of accounting for income taxes and amounts in lieu of income taxes. Income taxes and amounts in lieu of income taxes are determined based on estimates of our current income taxes and estimates of future income taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values. Future income tax assets are assessed to determine the likelihood that they will be recovered from future taxable income. To the extent recovery is not considered likely, a valuation allowance is recorded and charged against income in the period that the allowance is created or revised. Estimates of the provision for income taxes and amounts in lieu of income taxes, future income tax assets and liabilities and any related valuation allowance might vary from actual amounts incurred. Fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time. Similarly, income taxes and amounts in lieu of income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities. Accordingly, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers. PPA availability incentives Electricity revenue from the Genesee 1 and 2 units operating under PPAs includes an estimate of availability incentives as described above under Significant Accounting Policies. Availability incentive payments received are deferred in non-current liabilities and recognized in energy sales when they are expected to be sustained over the full term of the PPA. Accordingly the amount deferred can vary from no amount to the full amount of availability incentive payments received. At December 31, 2007, $nil (2006 - $2 million) was deferred in the balance sheet and $27 million (2006 - $26 million) was recognized in energy sales during the year. NON-GAAP FINANCIAL MEASURES We use cash flow from operations to measure the Company's ability to generate funds from current operations. Cash flow from operations is a non-GAAP financial measure, does not have any standardized meaning prescribed by GAAP and is unlikely to be comparable to similar measures published by other entities. However, it is presented since it is commonly referred to by debt holders and other interested parties in evaluating the Company's financial position and in assessing its credit worthiness. A reconciliation of cash flow from operations to cash flow from operating activities is as follows: ------------------------------------------------------------------------- Year ended December 31 2007 2006 2005 ------------------------------------------------------------------------- Cash flow from operations $ 517 $ 547 $ 493 Change in non-cash operating working capital 24 42 (14) ------------------------------------------------------------------------- Cash flow from operating activities $ 541 $ 589 $ 479 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RELATED PARTY TRANSACTIONS EPCOR enters into various transactions with its sole shareholder, The City of Edmonton. These transactions are in the normal course of operations and are recorded at the exchange value generally based on normal commercial rates or as agreed to by the parties. We recorded financing expenses of $54 million in 2007 ($58 million - 2006) on EPCOR's debt obligation to The City of Edmonton. This debt obligation relates to debt capital raised by The City of Edmonton prior to 1996 when EPCOR commenced raising capital directly. The decrease in interest expense in 2007 corresponds to the decrease in the net obligation. The outstanding balance of the net obligation to The City of Edmonton was $243 million at December 31, 2007 (2006 - $309 million). Sales from EPCOR to The City of Edmonton included electricity and water, and the provision of maintenance, repair, construction and customer care services totaling $77 million in 2007 (2006 - $69 million). We paid franchise fees and property taxes to The City of Edmonton of $49 million (2006 - $46 million). The City of Edmonton provided miscellaneous services to EPCOR totaling $7 million (2006 - $8 million). Included in the Company's revenues is $3 million (2006 - $1 million) for the provision of management services by Power LP to PERC under a long-term management agreement. At December 31, 2007, accounts receivable included $1 million (2006 - $nil) due from PERC. FOURTH QUARTER REVIEW AND QUARTERLY RESULTS ------------------------------------------------------------------------- Net income Net income from (loss) from continuing discontinued Net Quarters ended Revenues operations operations income ------------------------------------------------------------------------- (Unaudited, in $ millions) ------------------------------------------------------------------------- December 31, 2007 $ 969 $ 59 $ - $ 59 September 30, 2007 930 67 - 67 June 30, 2007 865 53 - 53 March 31, 2007 899 98 - 98 December 31, 2006 728 16 1 17 September 30, 2006 702 47 9 56 June 30, 2006 689 383 - 383 March 31, 2006 812 186 - 186 ------------------------------------------------------------------------- ------------------------------------------------------------------------- For the quarter ended December 31, 2007, consolidated net income from continuing operations increased by $43 million from the same quarter in the prior year primarily due to unrealized fair value gains on derivative financial instruments in our Alberta wholesale and merchant portfolio due to a short position on financial contracts and a decrease in Alberta forward power prices. In addition, income from Power LP operations was higher primarily due to unrealized fair value gains on its natural gas contracts in 2007 and foreign exchange losses on the translation of its U.S. dollar debt in 2006. These increases were partly offset by the impact of future tax rate reductions which were substantively enacted in December 2007, unfavourable fair value changes on the Joffre CfD, the absence of the Calpine short-term tolling arrangements which were in place in 2006, and lower income from the Joffre plant. In addition, losses were realized on forward foreign exchange contracts in the fourth quarter of 2007 whereas gains were realized in the corresponding period in 2006. Segment results for the fourth quarter included higher operating income in Energy Services with an operating profit of $56 million compared with an operating loss of $7 million for the corresponding period in 2006. Energy Services' fourth quarter results included favourable unrealized fair value changes on merchant and wholesale positions in Alberta, partly offset by reduced income from Joffre and the absence of the Calpine short-term tolling arrangements. Generation's operating income increased to $97 million in the fourth quarter of 2007 from $52 million in the same period in 2006 primarily due to higher income from Power LP and lower maintenance costs at the Genesee units. These increases were partly offset by an unrealized fair value decrease in the Joffre CfD and losses realized on forward foreign exchange contracts in the fourth quarter of 2007 compared with gains realized in the fourth quarter of 2006. Distribution and Transmission's operating income increased to $8 million in the fourth quarter of 2007 from $6 million of the same period in 2006, primarily due to an increase in distribution volumes. Water Services' operating income increased to $13 million in the fourth quarter of 2007 compared with $8 million in the fourth quarter of 2006, primarily due to higher rates for water sales. Events for 2007 and 2006 quarters that have significantly impacted net income from continuing operations and net income and cash flows and the comparability between quarters are: - September 30, 2007 third quarter results include higher Alberta electricity margins due to favourable settlements on financial sales as a result of higher contract prices and lower Alberta power prices, and higher income from the acquired PPAs. In addition the results included favourable unrealized fair value changes in financial and non-financial derivative instruments in Alberta merchant and wholesale positions due to lower forward power prices combined with a net short position. This was partly offset by an unfavourable fair value change in the Joffre CfD due to a lower spark spread in the quarter. - June 30, 2007 second quarter results include unrealized fair value decreases in derivative financial instruments which were not designated as hedges for accounting purposes, resulting from increasing forward market prices. In addition, income from Power LP included unrealized fair value decreases for the natural gas supply contracts resulting from decreasing forward natural gas prices and contract price changes for the Tunis plant. - March 31, 2007 first quarter results include a gain from the sale of a 10% interest in the Battle River PSA, a reduction of future income tax expense resulting from a reorganization of two subsidiaries within the Energy Services segment, and higher income from Power LP due to the fair value changes in the natural gas supply contracts for its Ontario generation plants which were required under the implementation of the new accounting standard for financial instruments effective January 1, 2007. These gains were partly offset by unrealized fair value decreases in derivative financial instruments resulting from a combination of increasing volumes of financial sales contracts not qualifying for hedge accounting and increasing Alberta forward power prices. - December 31, 2006 fourth quarter results include unrealized fair value decreases in derivative financial instruments which were not designated as hedges for accounting purposes, resulting from increased forward power prices. In addition, income from Power LP included unrealized foreign exchange losses on the translation of US dollar debt. These events were partly offset by increased generation from a short-term tolling arrangement with Calpine, higher generation incentive income and realized gains on forward foreign exchange contracts. - September 30, 2006 third quarter results include a net income increase from discontinued operations for the reduction of the Clover Bar asset retirement obligation offset by reduced Alberta electricity margins from the Battle River and Sundance PPAs resulting from the sale of partial interests in these agreements in the second quarter of 2006. - June 30, 2006 second quarter results include the sale of a 55% interest in the Battle River PPA and related transactions. The regulatory decisions for the 2005/2006 distribution and transmission tariffs and the RRT non-energy charge were received in the second quarter of 2006 resulting in an increase in net income. Future income tax assets and liabilities were adjusted to reflect the corporate income tax rate reductions that were enacted by the governments of Alberta and Canada in the quarter, which reduced net income. - March 31, 2006 first quarter results include the tax impact of the Generation reorganization whereby a Generation subsidiary became subject to federal and provincial income taxes rather than the PILOT Regulation. As a result, additional deductions are available for income tax purposes and the net tax effect was recognized as non- current future income tax assets in the balance sheet with a corresponding increase in net income. In addition, unrealized fair value changes in derivative financial instruments increased net income. ADDITIONAL INFORMATION Additional information relating to EPCOR including the Company's 2007 Annual Information Form is available on SEDAR at www.sedar.com.

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EPCOR Utilities Inc.

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