EPCOR announces quarterly results



    EDMONTON, Nov. 2 /CNW/ - EPCOR Utilities Inc. ("EPCOR") today released
its quarterly results for the period ended September 30, 2007.
    "Our third quarter results reflect the Company's solid investments in
water and power assets," said EPCOR President and CEO, Don Lowry. "I am
excited by the future prospects for this organization as we construct
technologically leading edge facilities like Keephills 3 and upgrades to the
E.L. Smith Water Treatment Centre. I am also pleased with the recent
announcement that the Government of Canada is partnering with EPCOR, the
Alberta Energy Research Institute and the Clean Coal Power Coalition to fund a
front-end engineering design study of coal gasification at our Genesee site.
This study supports our commitment to be a leader in applying leading
technologies to meet customer demands while minimizing our environmental
impact."

    
    Highlights of EPCOR's financial performance:

    -   Cash flows from operating activities for the three months ended
        September 30, 2007 were $150 million compared with $111 million for
        the same period in the previous year.

    -   Cash flows from operating activities for the nine months ended
        September 30, 2007 were $351 million compared with $443 million for
        the same period in the previous year.

    -   Net income was $67 million on revenues of $930 million for the three
        months ended September 30, 2007 compared with $56 million on revenues
        of $702 million for the same period in the previous year.

    -   Net income was $218 million on revenues of $2,694 million for the
        nine months ended September 30, 2007 compared with $625 million on
        revenues of $2,203 million for the same period in the previous year.

    -   Comprehensive income was $43 million for the three months and
        $191 million for the nine months ended September 30, 2007. This is a
        new measure under generally accepted accounting principles adopted on
        January 1, 2007.

    -   Investment in capital projects for the three months ended
        September 30, 2007 was $146 million compared with $59 million for the
        same period in the previous year.

    -   Investment in capital projects for the nine months ended
        September 30, 2007 was $331 million compared with $145 million for
        the same period in the previous year.
    

    Management's discussion and analysis ("MD&A") of the quarterly results
are shown below. The MD&A and the interim 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 web site is www.epcor.ca.



    EPCOR Utilities Inc.
    Interim Management's Discussion and Analysis
    September 30, 2007
    -------------------------------------------------------------------------

    This management's discussion and analysis ("MD&A"), dated November 2,
2007, should be read in conjunction with the unaudited interim consolidated
financial statements of EPCOR Utilities Inc. (hereinafter the "Company",
"EPCOR", "we", "our" or "us") for the nine months ended September 30, 2007 and
2006 and in conjunction with the audited consolidated financial statements and
MD&A for the year ended December 31, 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", "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, weather and economic
conditions, competitive pressures, construction risks, obtaining financing 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.

    SIGNIFICANT EVENTS

    Redemption of preferred shares

    Effective September 30, 2007, EPCOR Preferred Equity Inc., a subsidiary
of the Company, redeemed 8 million Cumulative Redeemable Perpetual First
Preferred Shares, Series I ("Preferred Shares") at par for $200 million. The
Preferred Shares were issued on September 27, 2002. The redemption was
completed on October 1, 2007 and funded from cash balances and debt.
    The carrying value of the Preferred Shares prior to their redemption by
the Company 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 between the redemption price and the carrying value
has been charged to non-controlling interests in the consolidated statements
of income.

    Asset Backed Commercial Paper

    At September 30, 2007, the Company held $67 million in Canadian third
party asset backed commercial paper ("ABCP"), all of which was purchased
during the third quarter. The Company's ABCP has been directly impacted by the
current liquidity issues affecting that segment of the commercial paper market
and as a result, all of the Company's ABCP matured with no payment of
principal, accrued interest or roll over. All of the trusts in which the
Company's ABCP investments are held are rated R-1 (high) by DBRS Limited
("DBRS"), which is their highest rating for commercial paper. DBRS has placed
these trusts "Under Review with Developing Implications" following an
announcement on August 16, 2007 that a consortium representing banks, asset
providers and major investors had agreed in principle to a long-term proposal
and interim arrangements regarding the ABCP ("the Montreal Accord"). Under
this proposal, 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"). On
October 15, 2007, the standstill arrangements of the Montreal Accord were
extended to December 14, 2007.
    Due to the uncertainties associated with the timing of repayment, the
ABCP investment is classified as non-current under 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
reduction in fair value of $4 million during the third quarter, representing
the difference between the original purchase price of $71 million and the
estimated fair value of $67 million at September 30, 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
downgrades of the applicable ABCP issuing trusts, observable interest rates
and credit spreads for estimating future interest payments and applicable
discount rates, estimated recovery periods based on the estimated lives of the
underlying assets of the issuing trusts, and ranges of recoverability based on
publicly available default statistics for 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 and the quality and tenor of the underlying assets and instruments
in the applicable trusts. Accordingly, the estimate of fair value of ABCP may
change materially as events unfold and more information becomes available.
    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. At September 30, 2007, the Company's subsidiary, EPCOR Power
L.P., did not have any investments in ABCP. 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.

    
    CONSOLIDATED RESULTS OF OPERATIONS

    Net income from continuing operations

    -------------------------------------------------------------------------
                                                            Three       Nine
    (Unaudited, $ millions)                                months     months
    -------------------------------------------------------------------------
    Net income from continuing operations for
     the periods ended September 30, 2006                  $   47     $  616
    Higher Alberta electricity margin                          11          2
    Unrealized fair value changes in financial
     and non-financial derivative instruments,
     excluding Power LP                                        10        (32)
    Cumulative translation account adjustment in 2006
     for the sale of Frederickson to Power LP                   6          6
    Higher water sales                                          5         10
    Higher availability incentive income                        5          3
    Lower (higher) financing expenses and preferred
     share dividends, excluding Power LP financing             (3)        21
    Lower income from Power LP                                 (9)       (11)
    Impact of income tax rate reductions on
     future income tax assets and liabilities,
     excluding Power LP                                         -         22
    Impact of recording a net future income tax
     asset associated with the Energy Services
     reorganization on January 1, 2007                          -         10
    Regulatory decisions for 2005 distribution and
     transmission tariffs and 2005 RRT non-energy
     charges received in 2006                                   -         (7)
    Impact of recording a net future income tax
     asset associated with the restructuring of
     EPCOR Generation Inc. on January 3, 2006                   -       (117)
    Gains on sales of interests in Battle River PSA             -       (297)
    Other                                                      (5)        (8)
    -------------------------------------------------------------------------
    Increase (decrease) in net income                          20       (398)
    -------------------------------------------------------------------------
    Net income from continuing operations for
     the periods ended September 30, 2007                  $   67     $  218
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income from continuing operations was $67 million and $218 million for
the three and nine months ended September 30, 2007 respectively, compared with
$47 million and $616 million for the corresponding periods in 2006.

    -   Alberta electricity margins were higher due to favourable settlements
        on financial sales as a result of higher contract prices and lower
        power prices in the month of September 2007 compared with the prior
        year. Income from the acquired Power Purchase Arrangements ("PPAs")
        also increased due to higher penalty payments received resulting from
        higher rolling average pool prices during unplanned plant outages.
        These variances were partly offset by the impact of our reduced
        interest in the Battle River Power Syndicate Agreement ("Battle River
        PSA") and lower generation from Genesee 3 compared with the prior
        year. Alberta electricity margins from our retail Regulated Rate
        Tariff ("RRT") customers were lower in 2007 due to changes in the
        Energy Price Setting Plan ("EPSP") effective July 1, 2006, and higher
        energy settlements associated with customer billings.

    -   The unrealized fair value changes in financial and non-financial
        derivative instruments for the quarter include favourable changes in
        Alberta merchant and wholesale positions due to lower forward power
        prices compared with the same quarter of the prior year combined with
        a net short position. This was partly offset by an unfavourable fair
        value change in the Joffre contract-for-differences ("CfD") due to a
        lower spark spread in the current quarter compared with the spark
        spread in the prior year's third quarter. (See Segment Results -
        Generation).

        For the nine month period, the year over year variances of the fair
        value changes in the Alberta merchant and wholesale positions,
        forward foreign currency contracts, and Joffre CfD were unfavourable.
        The unfavourable change in the Alberta merchant and wholesale
        position was due to an increase in financial sales contracts which
        were not designated as hedges for accounting purposes combined with
        higher forward Alberta power prices than in the prior year.
        Anticipated generation decreased due to our reduced interest in the
        Battle River PSA and a planned outage on the Genesee 3 facility which
        caused the increase in the volume of financial sales contracts not
        qualifying as hedges for accounting purposes. The decrease in fair
        value of forward foreign currency contracts was due to a
        strengthening Canadian dollar in the current year. The decrease in
        the fair value of the Joffre CfD was due to a lower spark spread in
        2007 compared with 2006.

    -   On August 1, 2006, the Company sold certain subsidiaries associated
        with its interest in Frederickson Power L.P. ("Frederickson") to
        EPCOR Power L.P. ("Power LP", a subsidiary of EPCOR). No gain or loss
        was recognized on the intercompany sale. However, previously deferred
        foreign exchange losses on the Company's net investment in the
        Frederickson operations and a foreign exchange gain on repayment of
        the US dollar debt designated as a hedge of the net investment in the
        foreign operations were recognized, resulting in a net foreign
        exchange loss of $6 million, in the third quarter of 2006.

    -   Water sales were higher in 2007 compared with 2006 primarily due to
        rate increases which were implemented in April 2007.

    -   Availability incentive revenues earned under the terms of the Genesee
        1 and 2 PPAs increased in the third quarter due to revisions for
        higher forward Alberta power prices and significantly fewer outage
        days in 2007 compared with 2006.

    -   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
        $87 million outstanding under a three-year credit facility, which had
        been drawn to hedge the Company's investment in Frederickson, and
        scheduled repayments of obligations to the City of Edmonton. 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
        2006 for the E.L. Smith water treatment plant construction project.
        Preferred share dividends decreased due to the redemption of
        $150 million of subsidiary preferred shares on June 30, 2006. 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. This change resulted in an $8 million
        decrease in non-controlling interests in the second quarter of 2007.
        These decreases were partly offset by a $4 million reduction in fair
        value of ABCP in the current quarter as described under Significant
        Events.

    -   Net income from Power LP was lower in 2007 compared with the prior
        year primarily due to the fair value changes in the natural gas
        supply contracts for its Ontario generation plants. These fair value
        adjustments were required by the new accounting standard for
        financial instruments that was implemented on January 1, 2007. The
        contracts did not qualify for the designation under the accounting
        standard as contracts used for the purpose of receipt of natural gas
        in accordance with our expected purchase or usage requirements and
        therefore were measured at fair value. There was no comparable
        adjustment in 2006 as the new accounting standard is effective
        January 1, 2007. The opening fair value adjustment at January 1, 2007
        was recorded in retained earnings. See Changes in Accounting
        Standards - Accounting Changes for 2007.

        Net income also decreased due to realized losses on forward interest
        rate contracts, higher financing costs related to the 2006 PEV
        acquisition by Power LP, an impairment charge in the third quarter of
        2007 in respect of certain PEV management contracts, and lower
        pricing and volume at the Curtis Palmer plant.

        Partly offsetting these reductions were higher foreign exchange gains
        on the translation of Power LP's US denominated debt in 2007 due to
        an increase in debt balances for the Frederickson and Primary Energy
        Ventures LLC ("PEV") acquisitions in 2006 and a strengthening
        Canadian dollar in 2007. Fair value gains on the foreign exchange
        contracts were also higher in 2007.

    -   In the second quarter of 2006, the enactment of income tax rate
        reductions resulted in an increase in income tax expense of
        $23 million. These tax changes consisted of a provincial rate
        reduction effective April 1, 2006 and a federal income tax rate
        reduction that is scheduled to occur in increments over the period
        from January 1, 2008 to December 31, 2010. The tax rate reduction
        announced in June 2007 resulted in an increase in income tax expense
        of $1 million.

    -   On January 1, 2007, the Company reorganized two subsidiaries within
        the Energy Services segment that operate the regulated retail
        business. As part of the transactions, one of the subsidiaries, which
        was previously exempt from income taxes became subject to tax 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.

    -   In the second quarter of 2006, the Alberta Energy and Utilities Board
        ("AEUB") issued its decisions relating to the Company's general
        tariff applications for its electricity transmission, distribution
        and RRT services for the period from January 1, 2005 through
        December 31, 2006. Prior to receiving the Decisions, the Company had
        billed customers and recorded revenues based on AEUB-approved interim
        rates for 2005 and 2006. The 2005 effect of these decisions was a
        $7 million contribution to net income, which was recognized in the
        second quarter of 2006.

    -   The January 3, 2006 reorganization of the Generation subsidiaries
        resulted in 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 Regulation, thereby
        increasing income in 2006 by $117 million.

    -   On January 1, 2007, we sold a 10% interest in the 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 PPA and related interest in the Battle River PSA to ENMAX
        Corporation over a four-year period ending in January 2010.

        The initial sale in June 2006 of a 55% interest was for $343 million.
        The Company also sold a 17.8% interest in the Sundance Power
        Syndicate Agreement ("Sundance PSA") to non-EPCOR syndicate members
        for $58 million. These transactions resulted in a pre-tax gain of
        $378 million and $51 million of associated income tax expense.


    Net income and net income from discontinued operations

    -------------------------------------------------------------------------
                                                            Three       Nine
    (Unaudited, $ millions)                                months     months
    -------------------------------------------------------------------------
    Net income for the periods ended September 30, 2006    $   56     $  625
    Increase (decrease) in net income from
     continuing operations - see previous table                20       (398)
    Decrease in income from operation of the
     Clover Bar generation plant                               (9)        (9)
    -------------------------------------------------------------------------
    Increase (decrease) in net income                          11       (407)
    -------------------------------------------------------------------------
    Net income for the periods ended September 30, 2007    $   67     $  218
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income for the three and nine months ended September 30, 2007 was
$67 million and $218 million, respectively. Net income for the three and nine
months ended September 30, 2006 was $56 million and $625 million,
respectively. Net income from discontinued operations was $9 million in 2006
which included a reduction of the Clover Bar asset retirement obligation net
of associated income taxes. There was no net income from discontinued
operations for the three and nine months ended September 30, 2007.


    Revenues

    -------------------------------------------------------------------------
                                                            Three       Nine
    (Unaudited, $ millions)                                months     months
    -------------------------------------------------------------------------
    Revenues for the periods ended September 30, 2006      $  702     $2,203
    Higher energy sales                                       126        359
    Higher Power LP revenues                                   78        214
    Unrealized fair value changes in derivative
     financial and non-financial instruments                   11        (91)
    Higher commercial and other sales                          13          9
    -------------------------------------------------------------------------
    Increase in revenues                                      228        491
    -------------------------------------------------------------------------
    Revenues for the periods ended September 30, 2007      $  930     $2,694
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Consolidated revenues for the three and nine months ended September 30,
2007 were higher than for the corresponding periods in 2006 primarily due to:

    -   Energy sales increased due to higher natural gas trading activities,
        new power trading activities in the Pacific Northwest power market,
        favourable settlements of financial sales due to higher contract
        prices and increased volume, higher revenues from RRT customers due
        to higher pricing, and higher availability incentive income due to
        higher forward Alberta power prices and significantly fewer outage
        days for 2007. These favourable variances were partly offset by a
        decrease in generation related to our reduced interests in the Battle
        River PSA in June 2006 and January 2007, expiry of the short term
        tolling arrangement with Calpine Power Income Fund for operation of
        their Calgary Energy Centre for the period from February 16, 2006 to
        June 30, 2006 and the month of September 2006.

    -   Revenues from Power LP were $153 million for the three months and
        $461 million for the nine months ended September 30, 2007 compared
        with $75 million and $247 million for the corresponding periods in
        2006. The increases were primarily due to the acquisition of PEV on
        November 1, 2006 and Frederickson on August 1, 2006 as well as
        favourable changes in the fair value of foreign exchange contracts.
        The sale of Frederickson to Power LP had no impact on consolidated
        revenues. These favourable variances were partly offset by the
        non-recurrence of a settlement received from the Ontario Electricity
        Financial Corporation in the first quarter of 2006 and lower
        generation and pricing at the Curtis Palmer facility.

    -   Unrealized fair value changes on derivative financial instruments
        increased energy revenues for the quarter compared with the prior
        year primarily due to decreasing forward Alberta power prices on
        financial sales that were not designated as hedges for accounting
        purposes. This was partly offset by unfavourable changes in the fair
        value of the Joffre CfD resulting from a lower spark spread in the
        third quarter compared with the prior year. For the nine months ended
        September 30, 2007, unrealized fair value changes on derivative
        financial instruments decreased energy revenues due to higher forward
        Alberta power prices combined with an increase in financial sales
        contracts, and unfavourable fair value changes on the Joffre CfD due
        to a lower spark spread, compared with the prior year.


    Capital spending and investment

    -------------------------------------------------------------------------
    (Unaudited, $ millions)
    Nine months ended September 30                           2007       2006
    -------------------------------------------------------------------------
    Generation                                             $  155     $   38
    Distribution and Transmission                              72         37
    Energy Services                                             8          5
    Water Services                                             82         57
    Corporate - other                                          14          8
    -------------------------------------------------------------------------
                                                           $  331     $  145
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Capital expenditures for property, plant and equipment were higher for the
nine months ended September 30, 2007 compared with the same period in 2006 due
to construction activity on several projects including the Keephills 3 and
Clover Bar generation projects, both of which commenced in the first quarter
of 2007, new transmission infrastructure, the Downtown Edmonton Supply and
Substation ("DESS"), and the E.L. Smith water treatment plant.
    On February 26, 2007, EPCOR and TransAlta Corporation ("TransAlta")
announced their decision to build Keephills 3, a 450 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.
    In December 2006, the AEUB approved our proposal to construct three
natural gas-fired peaking power generation units for an aggregate gross
generating capacity of 245 MWs at our Clover Bar site in northeast Edmonton.
The first 45 MWs are expected to be commissioned in the first quarter of 2008
with subsequent capacity coming on line in late 2008 and 2009.
    In the first quarter of 2007, Distribution and Transmission commenced
construction of the DESS project which consists of a new high voltage
transmission line, which will supply electricity to downtown Edmonton. Water
Services' construction on the EL Smith water treatment plant expansion
continued in 2007. Both projects are scheduled for completion in 2008.

    SEGMENT RESULTS

    Generation

    -------------------------------------------------------------------------
    Generation results (including
     intersegment transactions)      Three months ended    Nine months ended
    (Unaudited, $ millions)             September 30          September 30
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006

    Revenues                         $  268     $  192     $  777     $  580
    Expenses                            223        129        552        328
    -------------------------------------------------------------------------
    Operating income                 $   45     $   63     $  225     $  252
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                 Three       Nine
                                                           months     months
    -------------------------------------------------------------------------
    Operating income for the periods
     ended September 30, 2006                              $   63     $  252
    Increased estimates of PPA availability
     incentive revenue                                          8          4
    Cumulative translation account adjustment for
     the sale of Frederickson to Power LP in 2006               6          6
    Write-down of venture capital investment                    3          3
    Lower operating income from Frederickson operations         -         (3)
    Higher maintenance on Genesee 1 generating unit            (4)        (4)
    Higher realized losses on foreign exchange derivatives     (5)        (8)
    Unrealized fair value changes in
     derivative instruments                                    (8)       (24)
    Lower operating income from Power LP                      (18)        (3)
    Other                                                       -          2
    -------------------------------------------------------------------------
    Decrease in operating income                              (18)       (27)
    -------------------------------------------------------------------------
    Operating income for the periods ended
     September 30, 2007                                    $   45     $  225
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Generation's operating income for the quarter and nine months ended
September 30, 2007 decreased $18 million and $27 million respectively, from
the same periods in 2006. The key changes are as follows:

    -   Availability incentive revenue earned under the terms of the
        Genesee 1 and 2 PPAs increased due to revised estimates for higher
        forward Alberta power prices and significantly fewer outage days
        compared to the prior year.

    -   The sale of Frederickson to Power LP resulted in higher Power LP
        operating income and lower operating income for the balance of the
        Generation segment for the period from the date of sale on August 1,
        2006. Other than the loss recorded in the prior year on the
        cumulative foreign currency translation, this sale had no overall
        impact on the Generation segment results.

    -   A venture capital investment was written down in the prior year to
        reflect its loss in value.

    -   A Genesee 1 maintenance outage occurred in the third quarter of 2007.

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

    -   The generation from the Joffre plant is subject to a CfD whereby the
        difference between spot electricity prices and variable operating
        costs, multiplied by the contracted volume is remitted by one
        counterparty to the other. The CfD effectively incorporates an
        Alberta spark spread which represents the difference between Alberta
        power prices and 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. If the
        price of power is less than the cost of natural gas to produce
        electricity, the spark spread is unfavourable. Unrealized fair value
        changes on the CfD decreased revenues by $10 million and expenses by
        $3 million in the third quarter and decreased revenues by $8 million
        and increased expenses by $4 million for the nine months ended
        September 30, 2007, due to a lower spark spread compared to the prior
        year.

        In addition, unrealized fair value changes on foreign exchange
        contracts entered into in anticipation of asset purchases related to
        the Clover Bar and Keephills 3 generation projects decreased
        operating income and increased expenses in the quarter and nine
        months ended September 30, 2007 due to a strengthening Canadian
        dollar.

    -   Power LP contributed a $3 million operating loss in the current
        quarter and $15 million of operating income in the third quarter of
        2006. For the nine month period ended September 30, Power LP's
        operating income was $90 million in 2007 and $93 million in 2006.
        Power LP's revenues and expenses were higher by $78 million and
        $96 million, respectively for the quarter and $214 and $217 million,
        respectively for the nine month period ended September 30, 2007
        compared with the corresponding prior year periods primarily due to
        the acquisition of PEV and Frederickson in the prior year. Revenues
        for both periods in 2007 also increased compared to the corresponding
        periods in the prior year due to favourable changes in the fair value
        of foreign exchange contracts, partly offset by lower revenues from
        the Curtis Palmer plant. For the nine month period, these increases
        in revenues were also partly offset by the non-recurrence of the
        settlement received from the Ontario Electricity Financial
        Corporation in the first quarter of 2006.

        Fair value changes in the natural gas supply contracts were the main
        contributors to the increase in expenses in Power LP, especially in
        the current quarter. Realized losses on foreign exchange contracts
        related to the PEV acquisition and an impairment charge in respect of
        certain PEV management contracts were recognized in the current
        quarter with no corresponding amounts in the prior year. These
        increases were partly offset by unrealized foreign exchange gains in
        2007 on the translation of higher US dollar debt balances for the
        Frederickson and PEV acquisitions due to a strengthening Canadian
        dollar.

        Fair value changes for accounting purposes in the natural gas supply
        contracts and foreign exchange contracts are not representative of
        changes in the economic value of these contracts when considered in
        conjunction with the economically hedged item, such as future natural
        gas requirements, future power sales and future equipment purchases.


    Distribution and Transmission

    -------------------------------------------------------------------------
    Distribution and Transmission
     results (including
     intersegment transactions)      Three months ended    Nine months ended
    (Unaudited, $ millions)             September 30          September 30
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006

    Revenues                         $   63     $   66     $  181     $  192
    Expenses                             52         57        150        156
    -------------------------------------------------------------------------
    Operating income                 $   11     $    9     $   31     $   36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Distribution and Transmission's operating income increased in the three
months ended September 30, 2007 compared with the same period in 2006 due to
an increase in distribution revenue resulting from higher demand and prices in
2007. Total revenues were lower due to balancing pool rebates received from
the Alberta Electricity System Operator for system access charges which were
passed on to customers. Operating income decreased in the nine month period
compared with the prior year due to the 2005/2006 rate decision received in
June 2006 which resulted in the recognition of $6 million of operating income
relating to 2005 service.

    Energy Services

    -------------------------------------------------------------------------
    Energy Services results
     (including intersegment
     transactions)                   Three months ended    Nine months ended
    (Unaudited, $ millions)             September 30          September 30
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006

    Revenues                         $  599     $  458     $1,759     $1,478
    Expenses                            548        436      1,683      1,382
    -------------------------------------------------------------------------
    Operating income                 $   51     $   22     $   76     $   96
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                            Three       Nine
    (Unaudited, $ millions)                                months     months
    -------------------------------------------------------------------------
    Operating income for the periods ended
     September 30, 2006                                    $   22     $   96
    Unrealized fair value changes in derivative
     instruments                                               23        (21)
    Higher Alberta electricity margin                          16          2
    Lower Ontario margin                                       (4)        (1)
    Other                                                      (6)         -
    -------------------------------------------------------------------------
    Increase/(Decrease) in operating income                    29        (20)
    -------------------------------------------------------------------------
    Operating income for the periods
     ended September 30, 2007                             $    51     $   76
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Energy Services' operating income increased $29 million for the quarter
and decreased $20 million for the nine months ended September 30, 2007
compared with the corresponding periods in 2006 due to the net impact of the
following:

    -   The unrealized fair value changes in our financial electricity
        contracts were favourable in the current quarter due to a decrease in
        forward Alberta power prices on a net short position while forward
        Alberta power prices were increasing in the same period in 2006. For
        the nine month period, the unrealized fair value changes were
        unfavourable compared with the prior year due to higher forward
        Alberta power prices combined with an increase in financial sales
        contracts that were not designated as hedges for accounting purposes.
        The volume of these instruments that were recorded at fair value was
        higher in 2007 due to decreased generation as a result of our reduced
        interests in the Battle River PSA.

        These financial sales contracts hedge anticipated energy revenues on
        an economic basis. Unrealized fair value changes in derivative
        instruments recorded for accounting purposes are not representative
        of the changes in economic value when considering them in conjunction
        with the economically hedged item such as future power supply.

        Unrealized fair value changes in our derivative instruments increased
        energy revenues by $22 million and decreased energy expenses by
        $1 million for the quarter. Increases in energy revenues and expenses
        resulting from the impact of decreasing forward Alberta power prices
        were partly offset by decreased trading activity in the Ontario power
        market for the three months ended September 30. For the nine months
        ended September 30, unrealized fair value changes in our derivative
        instruments decreased energy revenues and expenses by $83 million and
        $62 million respectively, and were due to decreased trading activity
        in the Ontario power market, and higher forward Alberta power prices
        combined with an increase in financial sales contracts that were not
        designated as hedges for accounting purposes.

    -   Alberta electricity margins increased for the three months and nine
        months ended September 30, 2007 primarily due to favourable
        settlements on financial sales contracts resulting from portfolio
        length that was sold forward in the third quarter of 2007 at higher
        contract prices compared with the prior year. In 2006, portfolio
        length was sold at spot Alberta power prices. Penalty payments
        received on our acquired PPAs were higher in 2007 due to higher
        rolling average power prices when the underlying plants incurred
        unplanned outages.

        These increases were partly offset by our reduced interest in the
        Battle River PSA. In addition, Alberta electricity margins on energy
        sales to RRT customers were lower in 2007 due to changes in the EPSP
        effective July 1, 2006. We also experienced unfavourable energy
        settlements associated with customer billings due to the imprecision
        in customer consumption data received from load settlement agents and
        the time lags inherent in the resettlement process. We use estimates
        for determining the amount of energy consumed but not yet billed. The
        variance is within an acceptable range and could reverse with the
        receipt of future resettlement information.

    -   Energy Services' energy revenues and expenses, excluding unrealized
        fair value changes, increased by $119 million and $109 million
        respectively, for the quarter and by $366 million and $362 million
        respectively, for the nine months ended September 30 compared with
        the prior year periods. These increases were due to more natural gas
        trading activities and more power trading activities in the Pacific
        Northwest market in 2007. Energy revenues from settlements of
        financial sales were higher in 2007 due to increased volume and
        higher contract prices. Revenues from our RRT customers were higher
        due to EPSP pricing. Energy expenses were higher due to increased
        volume of financial purchases resulting from the new EPSP and higher
        contract prices. These increases were partly offset by our reduced
        interest in the Battle River PSA and expiry of the short term tolling
        arrangement with Calpine Power Income Fund for operation of their
        Calgary Energy Centre for the period from February 16, 2006 to
        June 30, 2006 and the month of September 2006.

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

    Water Services

    -------------------------------------------------------------------------
    Water Services results
     (including intersegment
     transactions)                   Three months ended    Nine months ended
    (Unaudited, $ millions)             September 30          September 30
    -------------------------------------------------------------------------
                                       2007       2006       2007       2006

    Revenues                         $   70     $   56     $  174     $  155
    Expenses                             47         42        128        119
    -------------------------------------------------------------------------
    Operating income                 $   23     $   14     $   46     $   36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Water sales were higher in the three and nine months ended September 30,
2007 due to increased rates as approved by the City of Edmonton. Water
transportation services margins were higher in the third quarter due to an
increase in streetlight construction activities for the City of Edmonton and
contracting income from Distribution and Transmission's DESS project in 2007.
Partly offsetting this, water treatment costs were higher due to more spring
run-off and unfavourable water conditions due to wet weather in 2007.

    
    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
    Significant changes in consolidated assets are outlined below:
    -------------------------------------------------------------------------
                                              Increase
                   September     December   (decrease)
                    30, 2007     31, 2006   $ millions  Explanation
    -------------------------------------------------------------------------
    Cash and cash  $     102    $     260    $    (158) Refer to liquidity
     equivalents                                        and capital resources
                                                        section.

    -------------------------------------------------------------------------
    Accounts             578          647          (69) Lower Alberta
     receivable                                         wholesale electricity
     (including                                         settlements due to
     income taxes                                       lower power prices
     recoverable)                                       compared with
                                                        December 31, 2006,
                                                        and lower Genesee PPA
                                                        and Genesee 3 pool
                                                        revenues.

    -------------------------------------------------------------------------
    Derivative           118           26           92  Implementation of new
     instruments                                        financial instruments
     asset (current)                                    accounting standards
                                                        for physical power
                                                        and natural gas
                                                        purchase and sales
                                                        contracts and
                                                        derivatives used in
                                                        cash flow hedges of
                                                        power.

    -------------------------------------------------------------------------
    Other current assets   81           70          11  Higher inventory for
                                                        planned maintenance
                                                        activity.

    -------------------------------------------------------------------------
    Property,          4,107        3,908          199  Reflects 2007
     plant and                                          capital expenditures
     equipment                                          partly offset by
                                                        depreciation and
                                                        amortization expense.

    -------------------------------------------------------------------------
    Power purchase       693          757          (64) Sale of 10% interest
     arrangements                                       in Battle River PSA
     ("PPAs")                                           and amortization of
                                                        remaining PPAs in
                                                        2007.

    -------------------------------------------------------------------------
    Contract and         182          207          (25) Amortization of
     customer                                           customer and
     rights and                                         contract rights.
     other
     intangible
     assets

    -------------------------------------------------------------------------
    Derivative           101           20           81  Implementation of
     instruments                                        new financial
     asset                                              instruments
     (non-current)                                      accounting standards
                                                        for physical power
                                                        and natural gas
                                                        purchase and sales
                                                        contracts and
                                                        derivatives used in
                                                        cash flow hedges of
                                                        power, combined with
                                                        an increase in the
                                                        fair value of foreign
                                                        exchange derivatives.

    -------------------------------------------------------------------------
    Future income        149          127           22  Increase in
     tax asset                                          temporary
     (non-current)                                      differences between
                                                        accounting and tax
                                                        bases of assets and
                                                        liabilities
                                                        resulting from
                                                        implementation of
                                                        new financial
                                                        instruments
                                                        accounting standards.

    -------------------------------------------------------------------------
    Goodwill             185          183            2

    -------------------------------------------------------------------------
    Other assets         234          178           56  Purchase of ABCP
                                                        offset by a
                                                        reduction in
                                                        estimated fair value.

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



    -------------------------------------------------------------------------
    Significant changes in consolidated liabilities and shareholder's equity
    are outlined below:
    -------------------------------------------------------------------------
                                              Increase
                   September     December   (decrease)
                    30, 2007     31, 2006   $ millions  Explanation
    -------------------------------------------------------------------------
    Short-term     $       -    $     216    $    (216) Reflects the
     debt                                               repayment of Power
                                                        LP's borrowing under
                                                        its bridge
                                                        acquisition credit
                                                        facility.

    -------------------------------------------------------------------------
    Derivative           159           24          135  Reflects
     instruments                                        implementation of new
     liability                                          financial instruments
     (current)                                          accounting standards
                                                        for physical power
                                                        and natural gas
                                                        purchase and sales
                                                        contracts and
                                                        derivatives used in
                                                        cash flow hedges of
                                                        power.

    -------------------------------------------------------------------------
    Accounts             736          608          128  Redemption of
     payable and                                        subsidiary's
     accrued                                            preferred shares on
     liabilities                                        September 30 2007,
                                                        which were settled
                                                        in October, partly
                                                        offset by lower
                                                        Alberta wholesale
                                                        electricity
                                                        settlements due to
                                                        lower power prices
                                                        compared with
                                                        December 31, 2006.

    -------------------------------------------------------------------------
    Other current        128          124            4
     liabilities

    -------------------------------------------------------------------------
    Long-term          2,077        2,179         (102) Ongoing scheduled
     debt                                               debt repayments to
     (including                                         the City of Edmonton
     current                                            and net reduction in
     portion)                                           Power LP's debt with
                                                        the replacement of
                                                        acquisition financing
                                                        and lease obligations
                                                        with a senior
                                                        unsecured notes
                                                        issue.

    -------------------------------------------------------------------------
    Derivative           134           27          107  Reflects
     instruments                                        implementation of new
     liability                                          financial instruments
     (non-current)                                      accounting standards
                                                        for physical power
                                                        and natural gas
                                                        purchase and sales
                                                        contracts and
                                                        derivatives used in
                                                        cash flow hedges of
                                                        power.

    -------------------------------------------------------------------------
    Future income         91           84            7
     tax liability
     (non-current)

    -------------------------------------------------------------------------
    Other
     non-current
     liabilities         120          127           (7)

    -------------------------------------------------------------------------
    Non-controlling      783          751           32  Reflects opening
     interests                                          adjustment upon
                                                        implementation of
                                                        financial instruments
                                                        accounting standards
                                                        attributable to
                                                        non-controlling
                                                        interests,
                                                        non-controlling
                                                        interests' share of
                                                        Power LP unit
                                                        offering, Power LP
                                                        income less
                                                        distributions,
                                                        substantive enactment
                                                        of the change in tax
                                                        rate applicable to
                                                        preferred dividends
                                                        and redemption of
                                                        preferred shares by
                                                        subsidiary company
                                                        in September 2007.

    -------------------------------------------------------------------------
    Shareholder's      2,302        2,243           59  Net income and
     equity                                             adjustments to
                                                        retained earnings
                                                        upon implementation
                                                        of financial
                                                        instruments
                                                        accounting standards,
                                                        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.

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



    LIQUIDITY AND CAPITAL RE

SOURCES Cash inflows (outflows) are summarized below: ------------------------------------------------------------------------- Three months ended ---------------------- Increase September September (decrease) 30, 2007 30, 2006 $ millions Explanation ------------------------------------------------------------------------- Operating $ 150 $ 111 $ 39 Reflects change in non-cash operating working capital, primarily fewer payments for Alberta wholesale electricity due to the timing of the electricity settlements. Investing (204) (37) (167) Reflects higher capital expenditures, primarily the Keephills 3 and Clover Bar generation projects, the E.L. Smith water treatment plant expansion, and the DESS project. Also reflects the purchase of ABCP. Financing 10 (80) 90 Net financing inflows in 2007 reflect proceeds from a private placement of senior unsecured notes by Power LP, used to repay capital lease obligations and amounts borrowed for the Frederickson and PEV acquisitions, whereas 2006 financing net outlays reflect repayment of US long term financing partly offset by equity issued by Power LP to non-controlling interests. ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Nine months ended ---------------------- Increase September September (decrease) 30, 2007 30, 2006 $ millions Explanation ------------------------------------------------------------------------- Operating $ 351 $ 443 $ (92) Reflects change in non-cash operating working capital, primarily due to increased payments of liabilities including higher employee short-term incentive payments in 2007 and higher working capital requirements for the PEV operations. Also reflects change in other non-current items, primarily loans advanced to Battle River Syndicate members in 2007 and lower PPA availability incentive payments received in 2007 compared with 2006. Investing (319) 152 (471) Reflects sale of a smaller interest in Battle River PSA and higher capital expenditures in 2007, primarily the Keephills 3 and Clover Bar generation projects, the E.L. Smith water treatment plant expansion and the DESS project. Also reflects the purchase of ABCP. Financing (190) (406) 216 Net financing outlays in 2007 included the repayment of Power LP's borrowing under its bridge acquisition credit facility, partly offset by the issuance of preferred shares by a Power LP subsidiary in the second quarter and the placement of senior unsecured notes in the third quarter, whereas 2006 financing outlays were marked by the redemption of preferred shares by a subsidiary. ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company has issued letters of credit for $380 million (December 31, 2006 - $248 million) to meet the credit requirements of energy market participants, to meet conditions of certain debt and service agreements, and to satisfy legislated reclamation requirements. CONTRACTUAL OBLIGATIONS 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%. On August 24, 2007, a subsidiary of the Company paid off its capital lease obligations for the Naval Station, North Island and Naval Training Centers for $72 million (US$68 million). The $1 million difference between the purchase price and the carrying amount of the lease obligation has been recorded as an increase in the cost of the acquired property, plant and equipment. The proceeds from the private placement were used to repay the capital lease obligations as well as to repay amounts initially borrowed as part of the Frederickson and PEV acquisitions. During the quarter, the Company drew $29 million on its $400 million five-year extendible syndicated bank revolving credit facility. The amounts outstanding under this facility mature within one year of the balance sheet date and bear interest at 5.01%. During the quarter, the Company drew $35 million on its $400 million unsecured two-year credit facilities. The amounts outstanding under these facilities mature within one year of the balance sheet date and bear interest at a weighted average interest rate of 4.81%. During the quarter, the Company drew $11 million on its $300 million unsecured three-year Power LP revolving extendible credit facilities. The amounts outstanding under these facilities mature within one year of the balance sheet date and bear interest at 4.77%. There have been no other material changes to the Company's purchase obligations during the third quarter, including payments for the next five years and thereafter. For further information on these obligations, refer to the 2006 annual MD&A. CHANGES IN ACCOUNTING STANDARDS Accounting changes for 2007 As described in EPCOR's most recent annual MD&A, the Company has adopted accounting policies in accordance with the following new accounting standards. Financial instruments, hedges and comprehensive income On January 1, 2007, we adopted the Canadian Institute of Chartered Accountants' new accounting standards "Financial Instruments - Recognition and Measurement", "Financial Instruments - Disclosure and Presentation, "Hedges", and "Comprehensive Income". As required by the new accounting standards, our comparative interim financial statements have not been restated, except to reclassify the 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. 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 unrealized foreign exchange gains and losses arising from the translation of self-sustaining foreign operations, the effective portion of the changes in the fair value of derivative instruments used in cash flow hedges of electricity sales and purchases and of anticipated foreign currency cash flows, and changes in the fair value of assets available for sale. 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 this new statement is recorded net of income taxes. Accumulated other comprehensive income is a new component of shareholder's equity. Financial instruments In accordance with the new accounting standard, we classify our cash and 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 financial 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 September 30, 2007 are summarized as follows: ------------------------------------------------------------------------- Carrying value -------------------------------------------------- Loans Other Held Avail- and financial Total for able receiv- liabil- fair trading for sale ables ities Total value ------------------------------------------------------------------------- Other assets $ 67 $ 19 $ 91 $ - $ 177 $ 180 Long-term debt (including current portion) - - - 2,077 2,077 2,261 ------------------------------------------------------------------------- ------------------------------------------------------------------------- In accordance with the standard, we have reclassified $15 million of debt issue costs from other assets to long-term debt effective January 1, 2007 and amortized them using the effective interest method. Previously, debt issue costs were amortized on a straight-line basis over the life of the associated debt. Also, in accordance with the new accounting standard, we expense any transaction costs related to financial instruments classified as held for trading. 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 -------------------- Non- Non- Non- Hedges hedges hedges hedges Total ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total derivative instruments net asset (liability) as at September 30, 2007 $ (108) $ 7 $ 27 $ - $ (74) ------------------------------------------------------------------------- Total derivative instruments net asset (liability) as at December 31, 2006 - (11) 5 1 (5) ------------------------------------------------------------------------- ------------------------------------------------------------------------- At September 30, 2007, the net fair value of financial derivative instruments specifically designated and qualifying for hedge accounting was a liability of $108 million and is included in derivative instruments asset and derivative instruments liability in 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. 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, but are 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 asset of $96 million, an increase in non-controlling interests of $66 million, an increase in future income tax liability 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 asset by $45 million and derivative instruments liability by $45 million. In addition, opening 2007 retained earnings decreased $8 million net of income taxes to recognize the fair value of the ineffective portion of previously deferred losses. At September 30, 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 due to increases in the forward Alberta electricity prices relative to the contract prices, which was partly offset by the unrealized gain on our natural gas supply contracts due to increases in forward natural gas prices relative to the contract prices. For the nine months ended September 30, 2007, the fair value of our forward foreign currency contracts increased, resulting in unrealized gains. This was due to the impact of a strengthening Canadian dollar in the current year on foreign currency sales contracts used to hedge US denominated revenues. This was partly offset by higher unrealized losses on foreign currency purchase contracts used to hedge anticipated US dollar denominated purchases in 2007. The weighted average fixed exchange rate for contracts outstanding at September 30, 2007 was $US 0.90 (December 31, 2006, $US 0.88) for every Canadian dollar. Other Comprehensive Income As of January 1, 2007, the changes in the fair value of the effective 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. Historically, 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 asset and liability in the consolidated balance sheet. For the nine months ended September 30, 2007, a cumulative loss, net of income taxes, of $59 million was recorded in other comprehensive income for the effective portion of cash flow hedges, and an unrealized loss, net of income taxes, of $25 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 $74 million in net losses recorded in accumulated other comprehensive income, net losses of $39 million (net of taxes of $17 million) related to derivative instruments designated as cash flow hedges at September 30, 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. The shares held are not typically traded on an exchange and therefore can be difficult to value. During the nine months ended September 30, 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. We have considered the effect of illiquidity and the restrictions on the shares held in determining its fair value. Future accounting changes Effective January 1, 2008, the new CICA Handbook Section 3031 "Inventories" will replace existing Section 3030 "Inventories" to be consistent with the International Accounting Standard for inventories. 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, which could be the best available measure for net realizable value. We are assessing the impact, if any, of the new standard. 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 disclosures on the Company's management of capital and on the risks associated with financial instruments. The Company is currently reviewing the impact of these new standards on its financial statements. CRITICAL ACCOUNTING ESTIMATES Implementation of the new accounting standard on financial instruments in 2007 has required us to record more of these instruments at fair value than in the past, which involves a greater use of estimates. The most significant item requiring fair valuation under the new standard was Power LP's natural gas supply contracts for its Ontario plants. These valuations reflect management's best estimates considering various factors including closing exchange or over-the-counter quotations, estimates of futures prices and foreign exchange rates, time value, credit risk, estimated recovery periods and volatility. In illiquid or inactive markets, we use appropriate price modeling to estimate fair value. It is possible that the assumptions used in establishing fair value amounts will differ from actual prices and the impact of such variations could be material. Risk management This section should be read in conjunction with the Risk Management section of the most recent annual MD&A. EPCOR faces a number of risks including electricity price and volume risk, natural gas price and volume risk, operational risk, government and regulatory risk, supply risk of acquired PPAs, credit risk, environmental risk, project risk, availability of people risk, weather risk, foreign exchange risk, conflicts of interest risk, and general economic conditions and business environment risks. The Company employs active programs to manage these risks. Environmental risk 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 both EPCOR and AERI will contribute equal amounts. 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"). The Regulation is applicable to all facilities in Alberta that produce over 100,000 tonnes of carbon dioxide equivalent ("CO(2)E" or greenhouse gas) per year. Accordingly, EPCOR's Genesee 1, 2 and 3 generating stations, and the Sundance 5 and 6 units which are subject to PPAs acquired by EPCOR, are subject to the Regulation. The Regulation imposes a CO(2)E intensity reduction of 12% from the average CO(2)E emissions intensity for the 2003 to 2005 period. The Alberta Government will recognize three mechanisms for compliance with this regulation: (1) operational or plant changes to reduce emission intensity, (2) submission of greenhouse gas emission reduction offsets which are sourced from within Alberta, and (3) investment in a new Alberta technology fund at $15 per tonne of required CO(2)E reduction. 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 should be recoverable from the PPA holder under the terms of the PPA. These costs have been estimated at approximately $11 million per year. EPCOR's Genesee 3 unit is considered a new unit under the Regulation and will receive a "three-year grace period", after which time 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 reducing interest in the Battle River PPA is $1 million, $2 million and $2 million for the years 2007, 2008 and 2009, respectively. In 2007, EPCOR has recorded $2 million for the cost associated with this regulation. On April 26, 2007, the Canadian Environment Minister announced a new regulatory framework to reduce greenhouse gas emissions and air pollution in Canada. The Canadian government has set targets of a 20% absolute reduction in greenhouse gases from 2006 levels by 2020 and a 50% reduction in air pollution by 2015. The Company is an emitter of carbon dioxide (a greenhouse gas), nitrogen oxide and sulphur dioxide which are all targeted for reduction under the proposed new legislation. The operational and financial impact to the Company of the new regulatory framework cannot be determined until further details are announced, including the definition of the clean air fuel standard and how such costs will be allocated among producers and consumers and whether the provincial and federal regulatory regimes will be harmonized. The Company complies, in all material respects, with current federal, provincial, state and local environmental legislation and guidelines. Availability of people 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. Government and regulatory risk In the second quarter of 2007, tax legislation included in Bill C-52, the Budget Implementation Act, 2007 (the "Bill), was substantively enacted and will result in changes to the manner in which certain publicly traded trust and partnerships, such as Power LP, are taxed. Substantive enactment of the Bill resulted in the recognition of future income tax amounts based on estimated net taxable temporary differences that will reverse after 2010, but it was not material at a consolidated level. On October 30, 2007, the Minister of Finance (Canada) announced proposed tax measures including corporate income tax rate reductions. If these measures become law, EPCOR will record a net charge to income tax expense reflecting a reduction in EPCOR's recorded future income tax assets and liabilities resulting from the reduced income tax rates. This reduction is estimated to be in the range of $5 million to $10 million. In addition, if the measures become law, income tax payments will be lower than they otherwise would be in future years. Asset backed commercial paper 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. As part of its ongoing risk management practices, the Company reviews current and proposed transactions to consider their impact on the risk profile of the Company. There have been no other material changes to the risk profile or risk management strategies of EPCOR as described in the annual MD&A for 2006. Internal Controls over Financial Reporting There were no changes in the Company's internal controls over financial reporting during the interim period ended September 30, 2007 that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting. Outlook Excluding the gain on sale of the interest in the Battle River PSA and the impact of fair value changes, earnings are expected to be slightly lower for the final quarter than the average for the first three quarters, in part due to normal seasonal variances and plant maintenance activities. The implementation of the new accounting standard on financial instruments is expected to increase the volatility of our earnings, which may not be representative of the performance of the underlying business and has no impact on our cash flows. QUARTERLY RESULTS ------------------------------------------------------------------------- Net Net income income from (loss) from continuing discontinued Quarter ended Revenues operations operations Net income ------------------------------------------------------------------------- (Unaudited, $millions) ------------------------------------------------------------------------- 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 December 31, 2005 866 46 (9) 37 Events for 2007, 2006 and 2005 quarters that have significantly impacted net income from continuing operations, net income and the comparability between quarters are: - 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 $30 million gain from the sale of a 10% interest in the Battle River PSA, an $11 million 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 electricity 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 increasing forward market 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 Power Income Fund, higher generation incentive income and realized gains on foreign exchange forward contracts. - September 30, 2006 third quarter results include a net income increase from discontinued operations of $10 million 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 PSA and related transactions which contributed $327 million to net income. 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 a $10 million 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. These tax adjustments reduced net income by $16 million. - 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 of $117 million. In addition, unrealized fair value changes in derivative financial instruments increased net income by $14 million. - December 31, 2005 fourth quarter results include the impact of reduced Alberta electricity margins as margins on new and renewed electricity contracts decreased. Additional information Additional information relating to EPCOR is available on SEDAR at www.sedar.com.

For further information:

For further information: Media inquiries: Tim le Riche, (780) 969-8238;
Shareholder and analyst inquiries: Randy Mah, (780) 412-4297 or toll free
(866) 896-4636

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EPCOR Utilities Inc.

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