EPCOR Announces Quarterly Results



    EDMONTON, Aug. 4 /CNW/ - EPCOR Utilities Inc. (EPCOR) today released its
quarterly results for the period ended June 30, 2009.
    "EPCOR's earnings from operations met expectations in the second quarter,
even as market conditions continued to change, and as we prepared for the
closing of the Capital Power Initial Public Offering in early July," said
EPCOR Utilities Inc. President and CEO, Don Lowry. "Overall, our Genesee
plants continued to perform well and our water portfolio showed gains, in part
driven by the Gold Bar Wastewater Treatment operation which was transferred to
EPCOR on March 31, 2009."
    "EPCOR's second quarter results were impacted by the Capital Power
transaction, primarily by expenses incurred to reorganize our people and
systems into two separate entities. The sale was effective in early July, the
beginning of the third quarter."

    
    Highlights of EPCOR's financial performance:

    -   Cash flow from operating activities for the three months ended
        June 30, 2009 was $104 million compared with $41 million for the
        corresponding period in the previous year.

    -   Cash flow from operating activities for the six months ended June 30,
        2009 was $251 million compared with $139 million for the
        corresponding period in the previous year.

    -   Net income was $50 million on revenues of $740 million for the
        three months ended June 30, 2009 compared with $16 million on
        revenues of $865 million for the corresponding period in the previous
        year.

    -   Net income was $154 million on revenues of $1,630 million for the
        six months ended June 30, 2009 compared with $84 million on revenues
        of $1,664 million for the corresponding period in the previous year.

    -   Other comprehensive loss was $18 million for the three months ended
        June 30, 2009 compared with other comprehensive income of $1 million
        for the corresponding period in the previous year.

    -   Other comprehensive income was $4 million for the six months ended
        June 30, 2009 compared with $24 million for the corresponding period
        in the previous year.

    -   Investment in capital projects for the three months ended June 30,
        2009 was $168 million compared with $186 million for the
        corresponding period in the previous year.

    -   Investment in capital projects for the six months ended June 30, 2009
        was $304 million compared with $294 million for the corresponding
        period in the previous year.
    

    Management's discussion and analysis (MD&A) of the quarterly results are
shown below. The MD&A and the unaudited interim financial statements are
available on EPCOR's website (www.epcor.ca) and will be available on SEDAR
(www.sedar.com).

    EPCOR's wholly-owned subsidiaries build, own and operate electrical
transmission and distribution networks, water and wastewater treatment
facilities and infrastructure in Canada. EPCOR, headquartered in Edmonton,
Alberta, has been named one of Canada's Top 100 employers for nine consecutive
years, and was selected one of Canada's 10 Most Earth-Friendly Employers.
EPCOR's website is www.epcor.ca.

    
    EPCOR Utilities Inc.
    Interim Management's Discussion and Analysis
    June 30, 2009
    -------------------------------------------------------------------------
    

    This management's discussion and analysis (MD&A), dated August 3, 2009,
should be read in conjunction with the unaudited interim consolidated
financial statements of EPCOR Utilities Inc. and its subsidiaries for the
three and six months ended June 30, 2009 and 2008, the audited consolidated
financial statements and MD&A for the year ended December 31, 2008 and the
cautionary statement regarding forward-looking information on page 27. In this
MD&A, any reference to "the Company", "EPCOR", "we", "our" or "us", except
where otherwise noted or the context otherwise indicates, means EPCOR
Utilities Inc., together with its subsidiaries. Financial information in this
MD&A is based on the unaudited interim consolidated financial statements,
which were prepared in accordance with Canadian generally accepted accounting
principles (GAAP), and is presented in Canadian dollars unless otherwise
specified. 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.

    OVERVIEW

    EPCOR is wholly-owned by The City of Edmonton. On May 8, 2009, EPCOR
announced its plan to create Capital Power Corporation (CPC) and sell
substantially all of its power generation assets and related operations to
CPC, as described under Significant Events. The sale was effective early July
2009 and EPCOR's results for the second quarter were impacted by transactions
and events which occurred in preparation for the sale. Administration expenses
were incurred in the second quarter for professional and consulting fees and
other reorganization costs.
    EPCOR's power and water operations continued to deliver good results, and
earnings from operating activities met our expectations for the second
quarter. Consistent with their performance in the first quarter, our Genesee
plants performed well and net availability incentive income was earned under
the terms of the Power Purchase Arrangement (PPA) for Genesee 1 and 2. This
was in contrast to their performance in the corresponding period in 2008 when
there were three planned outages at the Genesee plants and net penalties were
incurred at Genesee 1 and 2. Water revenues from the City of Edmonton customer
base benefited from rate increases on April 1, 2009 and higher sales volumes
due to drier than normal weather conditions in the month of June. Earnings
from our water operations also benefitted from contributions from the Gold Bar
Wastewater Treatment Plant (Gold Bar) operation which was transferred to EPCOR
on March 31, 2009.
    Canadian and U.S. financial markets stabilized somewhat in the second
quarter of 2009. Narrower credit spreads and higher repayments than
anticipated on the notes which EPCOR received in exchange for its Canadian
non-bank sponsored asset-backed commercial paper (ABCP) resulted in a $2
million increase in the fair value of the notes in the quarter. Although
financial markets stabilized in the quarter, we were and are mindful of how
quickly market conditions can change. Accordingly, we continued to rely on our
ability to issue commercial paper and draw on our credit facilities to finance
capital expenditures during the period.
    Progress continued on our capital expenditure program. The second of the
three units at Clover Bar Energy Centre is expected to be commissioned in the
third quarter of 2009 and Power LP completed its repowering project for its
North Island plant on May 1, 2009.
    On June 30, 2009, our joint proposal with Enbridge Inc. for an integrated
gasification combined cycle (IGCC) carbon capture power generation facility at
Genesee was one of three projects selected by the Government of Alberta for
the negotiation of letters of intent under the province's $2 billion program
for large-scale carbon capture and storage (CCS) projects. The Province of
Alberta is working to have letters of intent signed in August 2009.
Construction of the project will be subject to conditions such as regulatory
approvals, economic and engineering assessments, and successful negotiation of
an agreement with the Province of Alberta. EPCOR's progress in finding
technology solutions that can lead to low-emission power from coal was marked
by an agreement reached in May 2009 with Siemens Energy Inc. to provide power
generation technology for EPCOR's Genesee IGCC power generation facility.
EPCOR's interest in the Genesee IGCC CCS project was included in the sale of
generation assets to Capital Power LP effective early July 2009.

    
    SIGNIFICANT EVENTS

    Announcement of initial public offering of Capital Power Corporation
    common shares
    

    On May 8, 2009, EPCOR announced its plans to create CPC, a power
generation company that is permanently headquartered in Edmonton. The final
prospectus for the initial public offering of 21,750,000 common shares of CPC,
at $23.00 per common share was filed with securities regulators in Canada on
June 25, 2009. The initial public offering closed on July 9, 2009.
    Through a series of transactions (the Reorganization), as described more
fully in the CPC prospectus, EPCOR sold substantially all of its power
generation assets net of certain liabilities, and related operations including
its 30.6% interest in EPCOR Power LP (Power LP), to CPC and its subsidiaries
(Capital Power), effective early July 2009. The assets and related operations
were previously included in EPCOR's Generation and Energy Services segments.
EPCOR also entered into various agreements with Capital Power to provide for
certain aspects of the separation of the power generation business from EPCOR,
to provide for the continuity of operations and services and to govern the
ongoing relationships between the two groups of entities.
    The total consideration for the sale consisted of $468 million of cash,
56.6 million exchangeable LP units of Capital Power LP and an $896 million
long-term loan receivable from Capital Power LP. In addition, EPCOR holds one
special limited voting share in CPC providing the right to vote separately as
a class in connection with certain amendments to the articles of CPC,
including an amendment to change or permit the change of the location of the
head office of CPC from The City of Edmonton. The difference between EPCOR's
carrying value of its investment in the power generation business ($2,909
million) and the consideration received results in an estimated loss on
disposal of $107 million which includes estimates of income tax related
charges to recognize unrealizable future income tax assets, direct expenses
incurred in connection with the sale, and underwriters' commissions. The
amount will be finalized when the transaction is recorded in the third quarter
financial statements and may differ materially from the current estimate.
    Immediately following completion of the Reorganization, EPCOR held 56.6
million exchangeable LP units of Capital Power LP (exchangeable for common
shares of CPC on a one-for-one basis) representing approximately 72.2% of
Capital Power LP, while CPC held the remaining 27.8%. Each exchangeable LP
unit is accompanied by a special voting share of CPC which entitles the holder
to a vote at CPC shareholder meetings, subject to the restriction that such
voting shares must at all times represent not more than 49% of the votes
attached to all CPC common shares and special voting shares together. The
special shares also entitle EPCOR to elect a maximum of four out of twelve
directors of CPC. As a result of these restrictive rights, EPCOR has
significant influence, but not control, of CPC and therefore will use the
equity method to account for its investment in Capital Power.
    Effective July 2009, income from Power LP will be included in the income
from EPCOR's investment in Capital Power and EPCOR will no longer consolidate
the financial results of Power LP.
    EPCOR may eventually sell all or a substantial portion of its ownership
interest in Capital Power, subject to market conditions, its requirements for
capital and other circumstances that may arise in the future, and reinvest the
proceeds from the share sales in EPCOR's growing utility infrastructure
businesses, including water and wastewater treatment, and power transmission
and distribution.

    Asset-backed commercial paper exchanged for notes

    On January 21, 2009, the restructuring of ABCP was implemented. Under the
restructuring, the affected ABCP was exchanged for term floating-rate notes
(notes), maturing no earlier than the scheduled termination dates of the
underlying assets. The exchange was recorded at the estimated fair value of
the ABCP on January 21, 2009. The key information on EPCOR's notes is as
follows:

    
    (i)    EPCOR's allocation of notes under the restructuring was as
           follows:

           ------------------------------------------------------------------
           Pool         Series          Rating        Face amount
                                                      ($ millions)
           ------------------------------------------------------------------
           MAV2         Class A-1       A                    $ 47         67%
                        Class A-2       A                       9         13%
                        Class B         Unrated                 2          2%
                        Class C         Unrated                 2          2%
           MAV3         IA Tracking     Unrated                11         16%
           ------------------------------------------------------------------
                                                             $ 71        100%
           ------------------------------------------------------------------
           ------------------------------------------------------------------

    (ii)   For the Master Asset Vehicle 2 (MAV2) pool notes, the underlying
           asset lives are anticipated to average nine years. The remaining
           notes come from Master Asset Vehicle 3 (MAV3) in the form of
           Ineligible Asset Tracking (IA Tracking) notes. These notes are
           expected to amortize over the lives of the underlying assets which
           have a weighted average life of approximately 18 years. In certain
           limited circumstances, the expected repayment dates could be
           longer than the expected asset lives.

    (iii)  ABCP investors, including EPCOR, were paid the accumulated accrued
           interest, net of ABCP restructuring costs, collateral requirements
           and other costs, on their existing ABCP from the date of the
           standstill in August 2007 to the date of the restructuring. For
           the three and six months ended June 30, 2009, EPCOR received
           $2 million and $4 million respectively, of accrued interest on
           ABCP and interest on the new notes.
    

    At June 30, 2009, the Company held $40 million in notes, all of which
were received in exchange for ABCP which was purchased during the third
quarter of 2007 at an original cost of $71 million. As the notes are
classified as held-for-trading financial assets, they are subject to ongoing
fair value adjustments at each reporting date. At June 30, 2009, the fair
value of the notes was estimated at $40 million compared with a fair value of
$38 million and $42 million for the ABCP at March 31, 2009 and December 31,
2008, respectively. The $2 million increase for the second quarter was
primarily due to narrower credit spreads. The $4 million decrease in the first
quarter was primarily due to lower short-term and higher long-term market
interest rates which were taken into account in calculating the fair value of
the notes. In 2008, a $9 million reduction in the fair value of the ABCP was
recognized in the first quarter and there was no change in fair value in the
second quarter.
    The estimate of fair value is subject to significant risks and
uncertainties including the timing and amount of future cash payments, market
liquidity, the quality and tenor of the assets and instruments underlying the
notes, including the possibility of margin calls, and the future market for
the notes. Accordingly, the fair value estimate of the notes may change
materially.

    
    CONSOLIDATED RESULTS OF OPERATIONS

    Net income

    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                  Three       Six
                                                            months    months
    -------------------------------------------------------------------------
    Net income for the periods ended June 30, 2008        $     16  $     84
    Unrealized fair value changes on derivative
     instruments and natural gas inventory held for
     trading, excluding Power LP fair value changes             36        69
    Higher Genesee PPA availability incentive income            19        30
    Maintenance expenses for Genesee scheduled
     turnarounds in 2008                                        11        19
    Higher water rates and sales volumes, net of
     franchise fees                                              5         7
    Gold Bar operating income excluding
     administration expenses                                     5         5
    Lower financing expenses, excluding Power LP
     financing expenses                                          4        11
    Fair value changes on notes exchanged for ABCP               2         7
    Lower foreign exchange expense, excluding Power LP
     foreign exchange expense                                    1         7
    Lower gain on sale of Battle River PSA                       -        (4)
    Gains on sales of portfolio investments in 2008             (3)       (3)
    Lower income from Power LP                                  (8)      (27)
    Lower Alberta electricity margins                           (9)      (14)
    Higher administration expenses, excluding Power LP
     administration                                            (26)      (31)
    Other                                                       (3)       (6)
    -------------------------------------------------------------------------
    Increase in net income                                      34        70
    -------------------------------------------------------------------------
    Net income for the periods ended June 30, 2009        $     50  $    154
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income was $50 million and $154 million for the three and six months
ended June 30, 2009 respectively, compared with $16 million and $84 million
for the corresponding periods in 2008. The increases were primarily due to the
net impact of the following:

    -   In the three and six months ended June 30, 2009, the unrealized fair
        value changes were favourable compared with the corresponding periods
        in the prior year primarily due to the fair value changes relating to
        our power and natural gas derivative contracts that were not
        designated as hedges for accounting purposes, as discussed under
        Energy Services later in this MD&A and due to the fair value changes
        on the Joffre contract-for-differences (CfD), as discussed under
        Generation. These favourable variances were partly offset by
        unfavourable unrealized fair value changes in our forward foreign
        exchange contracts compared with the prior year, as discussed under
        Generation.

    -   Availability incentive income was earned in the three and six months
        ended June 30, 2009 under the terms of the Genesee 1 and 2 PPA
        compared with a net availability penalty in the corresponding periods
        in 2008. The net penalty in 2008 was due to major scheduled
        turnaround work on Genesee 1 in the first and second quarters and on
        Genesee 2 in the second quarter.

    -   Maintenance expenses for Genesee were lower due to the scheduled
        maintenance turnarounds in the first quarter of 2008 for Genesee 1
        and for all three Genesee units in the second quarter of 2008 whereas
        there were no maintenance turnarounds in 2009. The back-to-back
        timing of the maintenance turnarounds in 2008 was required to
        accommodate the Alberta Electric System Operator's upgrade of the new
        high-voltage transmission lines in the Genesee and Keephills area.

    -   Water rates were higher in the three and six months ended June 30,
        2009 compared with the corresponding periods in 2008 primarily due to
        increased rates under the performance-based rate tariff (PBR) as
        approved by The City of Edmonton. Water sales volumes were also
        higher due to drier weather conditions in the second quarter of 2009
        compared with the second quarter of 2008.

    -   The Gold Bar operation was transferred to EPCOR from the City of
        Edmonton on March 31, 2009 and contributed $5 million of operating
        income before administration expenses in the second quarter.

    -   Financing expenses, excluding unrealized fair value adjustments and
        Power LP's financing expenses were lower in the three and six months
        ended June 30, 2009 compared with the corresponding periods in 2008
        primarily due to higher capitalized interest and collection of
        interest and principal related to the ABCP as described under
        Significant Events. The Company capitalizes borrowing costs as part
        of its cost of capital construction projects and in the second
        quarter and first half of 2009, construction work-in-progress for
        Keephills 3 and the Clover Bar Energy Centre was higher compared with
        the corresponding periods in 2008.

    -   In the first quarter of 2009, the fair value of the notes exchanged
        for ABCP decreased $4 million due to lower short-term and higher
        long-term market interest rates, and in the second quarter of 2009,
        the fair value of the notes increased $2 million due to narrower
        credit spreads, which are taken into account in calculating the fair
        value of the notes. In the first quarter of 2008, the fair value of
        EPCOR's ABCP decreased $9 million and there was no change in its fair
        value in the second quarter of 2008.

    -   In the three and six months ended June 30, 2009, foreign exchange
        gains were realized on the settlement of forward foreign exchange
        contracts used to economically hedge the foreign exchange risk
        associated with anticipated purchases of equipment for generation
        capital projects. In the corresponding periods of 2008, foreign
        exchange losses were realized on these contracts.

    -   On January 15, 2009, we sold a 10% interest in the Battle River
        Syndicate Agreement for cash proceeds of $47 million resulting in an
        after-tax gain of $26 million. The sale was pursuant to the purchase
        and sale agreement entered into in June 2006 whereby EPCOR will sell
        its Battle River PPA and related interest in the Battle River Power
        Syndicate Agreement (PSA) over a four-year period ending in January
        2010. An initial interest of 55% was sold in June 2006, followed by
        sales of 10% interests in January of each year thereafter. The after-
        tax gain on sale was $26 million in 2009 and $30 million in 2008. The
        year-over-year decrease was due to lower proceeds reflecting the one
        year shorter term to maturity for the PPA.

    -   Net income from Power LP was lower in the second quarter and first
        half of 2009 compared with the corresponding periods in 2008
        primarily due to the net impact of unrealized changes in the fair
        value of natural gas supply and forward foreign exchange contracts.
        Plant operating margins were slightly higher in the quarter and
        unchanged in the six month period as contributions from the Morris
        facility, which was acquired in October 2008, were substantially
        offset by lower operating margins at the North Carolina plants due to
        reduced generation.

    -   In the first and second quarters of 2009, margins for the
        procurement, marketing and sale of electricity in retail and
        wholesale markets in Alberta (Alberta electricity margins) were lower
        compared with the corresponding periods in 2008 primarily due to the
        impact of lower Alberta spot power prices on our electricity
        portfolio. In addition, power generation was lower in 2009 due to our
        reduced interest in the Battle River PSA.

    -   Administration expenses across all business segments excluding Power
        LP, were higher in the second quarter of 2009 compared with the
        second quarter of 2008 due to increased spending on business
        development activities and our Genesee IGCC and CCS technology
        project, and costs related to the Reorganization.

    Revenues

    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                  Three       Six
                                                            months    months
    -------------------------------------------------------------------------
    Revenues for the periods ended June 30, 2008          $    865  $  1,664
    Unrealized fair value changes on derivative
     instruments and natural gas inventory held for
     trading, excluding Power LP fair value changes             44       134
    Higher Genesee PPA availability incentive revenues          27        42
    Higher Power LP revenues                                    22        29
    Gold Bar revenue in 2009                                    13        13
    Higher water rates and sales volumes                         5         8
    Higher Water Services' commercial and transportation
     services activity                                           4        11
    Lower electricity trading activities in Ontario and
     the north eastern U.S.                                    (18)      (13)
    Lower electricity trading activities in the western U.S.   (18)      (34)
    Lower Alberta electricity revenues                         (55)      (53)
    Lower natural gas trading activities                      (143)     (165)
    Other                                                       (6)       (6)
    -------------------------------------------------------------------------
    Decrease in revenues                                      (125)      (34)
    -------------------------------------------------------------------------
    Revenues for the periods ended June 30, 2009          $    740  $  1,630
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Consolidated revenues were lower for the three and six months ended June
30, 2009 compared with the corresponding periods in 2008 due to the net impact
of the following:

    -   Unrealized fair value gains recognized in the three and six months
        ended June 30, 2009 were due to decreasing forward Alberta power
        prices applied to our Alberta financial sales contracts that were not
        designated as hedges for accounting purposes. In the corresponding
        periods in 2008, unrealized fair value losses on these financial
        sales contracts were due to increasing forward Alberta power prices.

    -   Power LP revenues were higher primarily due to unrealized changes in
        the fair value of forward foreign exchange contracts for U.S. dollars
        used to economically hedge operating cash flow.

    -   Water Services' commercial and transportation services revenues were
        higher in the three and six months ended June 30, 2009 compared with
        the corresponding periods in 2008 primarily due to the water and
        wastewater treatment facilities construction project for Suncor
        Energy Inc., which commenced in the second quarter of 2008, and
        increased construction activity for street lighting, signals and
        light rail transit overhead wires for the City of Edmonton in 2009.

    -   Revenues for our Alberta electricity portfolio were lower in the
        second quarter of 2009 compared with the second quarter of 2008
        primarily due to lower electricity pricing and volumes for our
        Regulated Rate Tariff (RRT) customers, lower Alberta power prices and
        our reduced interest in the Battle River PSA.

    Capital spending and investment

    -------------------------------------------------------------------------
    (Unaudited, $ millions)
    Six months ended June 30                                  2009      2008
    -------------------------------------------------------------------------
    Generation                                            $    228  $    197
    Distribution and Transmission                               36        63
    Energy Services                                              7         2
    Water Services                                              26        26
    Corporate - other                                            7         6
    -------------------------------------------------------------------------
                                                          $    304  $    294
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Capital expenditures for property, plant and equipment were higher for
the six months ended June 30, 2009 compared with the corresponding period in
2008 primarily due to construction activity on Power LP's Southport, Roxboro
and North Island plant enhancements in 2009. These increases were partly
offset by capital expenditures in 2008 for the Downtown Edmonton Supply and
Substation project in Distribution and Transmission which was completed in the
third quarter of 2008 and for the E.L. Smith water treatment plant upgrade in
Water Services which was completed in the second quarter of 2008.
    Despite the current economic conditions, major project construction costs
remain under pressure as project work packages, including material and labour
components, are finalized in the normal course of construction.
    Keephills 3 is a 495-MW supercritical coal-fired generation plant which
is a joint development of EPCOR and TransAlta Corporation at TransAlta's
Keephills site. We continued to manage the schedule and costs of our Keephills
project to achieve commercial operations by the end of the first quarter of
2011.
    The Clover Bar Energy Centre will be composed of three natural gas-fired
peaking power generation units. The first unit was commissioned in the first
quarter of 2008, the second unit is expected to be commissioned in the third
quarter of 2009 and construction of the third unit will continue through to
2010.
    Power LP's capital expenditures, which are included in Generation in the
table above, were $43 million in the six months ended June 30, 2009 compared
with $14 million in the corresponding period in 2008. The capital expenditures
in 2009 included enhancements to the Southport and Roxboro facilities to
reduce their environmental emissions and improve their economic performance.
In addition, during the second quarter of 2009, Power LP completed its upgrade
of the natural gas turbine at the North Island facility resulting in improved
plant efficiency.

    
    SEGMENT RESULTS

    Generation

    -------------------------------------------------------------------------
    Generation results (including
     intersegment transactions)       Three months ended   Six months ended
    (Unaudited, $ millions)                 June 30             June 30
    -------------------------------------------------------------------------
                                          2009      2008      2009      2008

    Revenues                          $    276  $    234  $    515  $    455
    Expenses                               195       118       428       250
    -------------------------------------------------------------------------
    Operating income                  $     81  $    116  $     87  $    205
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                  Three       Six
                                                            months    months
    -------------------------------------------------------------------------
    Operating income for the periods ended June 30, 2008  $    116  $    205
    Higher Genesee PPA availability incentive income            27        42
    Maintenance expenses for Genesee scheduled
     turnarounds in 2008                                        16        26
    Lower realized foreign exchange expense                      3         8
    Unrealized fair value changes on derivative instruments      1        (5)
    Gain on sale of portfolio investments in 2008               (4)       (4)
    Higher administration expenses                             (13)      (18)
    Lower Power LP operating income                            (60)     (160)
    Other                                                       (5)       (7)
    -------------------------------------------------------------------------
    Decrease in operating income                               (35)     (118)
    -------------------------------------------------------------------------
    Operating income for the periods ended June 30, 2009  $     81  $     87
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Generation's operating income for the quarter and six months ended June
30, 2009 decreased $35 million and $118 million, respectively, compared with
the corresponding periods in 2008. Further information on the year-over-year
changes is as follows:

    -   Generation's revenues and operating income increased $27 million and
        $42 million in the second quarter and first half of 2009,
        respectively due to availability incentive income earned under the
        terms of the Genesee 1 and 2 PPA compared with a net availability
        penalty in the corresponding periods in 2008. There were scheduled
        turnarounds for required maintenance at Genesee 1 in the first
        quarter of 2008 and at all three Genesee units in the second quarter
        of 2008 whereas plant availability at Genesee 1 and 2 was above plan
        in both quarters of 2009. The back-to-back timing of the maintenance
        turnarounds in 2008 was required to accommodate the Alberta Electric
        System Operator's upgrade of the new high-voltage transmission lines
        in the Genesee and Keephills area.

    -   Foreign exchange gains were realized in the first and second quarters
        of 2009 on the settlement of forward foreign exchange contracts used
        to economically hedge the foreign exchange risk associated with
        anticipated purchases of equipment for Clover Bar Energy Centre and
        Keephills 3 whereas losses were realized on these contracts in the
        corresponding periods in 2008.

    -   The unrealized changes in the fair value of the forward foreign
        exchange contracts for equipment purchases for Clover Bar Energy
        Centre and Keephills 3 were losses in the first half of 2009 due to a
        weakening U.S. dollar compared with gains in the corresponding period
        in 2008 due to a strengthening U.S. dollar. This unfavourable
        variance was partly offset by a smaller decrease in the fair value of
        the Joffre contract-for-differences (CfD) due to a smaller decrease
        in the forward spark spread in the first half of 2009 compared with
        the first half of 2008. Spark spread is the theoretical difference
        between the price of electricity as the output and its energy cost of
        production.

        These unrealized fair value changes decreased revenues by $3 million
        and expenses by $4 million in the second quarter of 2009 compared
        with the second quarter of 2008. In the six months ended June 30,
        these unrealized fair value changes decreased revenues by $3 million
        and increased expenses by $2 million in 2009 compared with 2008.

    -   Administration expenses increased in the three and six months ended
        June 30, 2009 compared with the corresponding periods in 2008 due to
        costs for the Reorganization and increased spending on business
        development activities and on our Genesee IGCC and CCS technology
        project.

    -   Power LP contributed $58 million of operating income in the second
        quarter and $22 million in the first six months of 2009 compared with
        $118 million and $182 million respectively, in the corresponding
        periods in 2008. The year-over-year decreases include unrealized
        changes in the fair value of natural gas supply and foreign exchange
        contracts of $75 million for the quarter and $175 million for the six
        month period. Plant operating margins were slightly higher in the
        quarter and unchanged in the six month period as contributions from
        the Morris facility which was acquired in October 2008, were offset
        by lower operating margins at the North Carolina plants due to
        reduced generation.

        The decreases in operating income were partly offset by foreign
        exchange losses recognized in 2008. In the fourth quarter of 2008,
        Power LP re-evaluated the functional currency of its U.S.
        subsidiaries and determined it to be U.S. dollars rather than
        Canadian dollars. Accordingly, gains and losses on foreign currency
        translation are recorded in other comprehensive income commencing in
        the fourth quarter of 2008. Power LP reported net foreign exchange
        gains of $3 million in the second quarter of 2008 and foreign
        exchange losses of $11 million in the first half of 2008.

        Power LP's revenues increased $22 million in the second quarter and
        $29 million for the first half of 2009 compared with the
        corresponding periods in the prior year, primarily due to unrealized
        changes in the fair value of forward foreign exchange contracts for
        U.S. dollars used to economically hedge operating cash flows. Year-
        over-year changes in plant revenues were insignificant as the revenue
        from the Morris operation in 2009 was offset by lower revenue from
        the California plants due to lower electricity prices which, under
        the terms of the PPA, were driven by lower natural gas prices.

        Power LP's expenses increased $82 million in the second quarter and
        $189 million in the first half of 2009 compared with the
        corresponding periods in the prior year. The year-over-year increases
        included unrealized changes in the fair value of natural gas supply
        contracts of $100 million for the quarter and $202 million for the
        six month period. These unrealized fair value changes were included
        in fuel expense and were due to decreases in the forward market
        prices for natural gas in the first half of 2009 compared with
        increases in the first half of 2008. Operating expenses for the
        Morris facility also contributed to the increase in Power LP's
        expenses. These increases were partly offset by the foreign exchange
        losses in the first half of 2008 with no corresponding amounts
        included in net income in 2009, and decreased fuel costs at the
        California plants due to lower natural gas prices in the first half
        of 2009 compared with the first half of 2008.

    Distribution and Transmission

    -------------------------------------------------------------------------
    Distribution and Transmission
     results (including intersegment
     transactions)                    Three months ended   Six months ended
    (Unaudited, $ millions)                 June 30             June 30
    -------------------------------------------------------------------------
                                          2009      2008      2009      2008

    Revenues                          $     58  $     59  $    119  $    118
    Expenses                                52        53       101       100
    -------------------------------------------------------------------------
    Operating income                  $      6  $      6  $     18  $     18
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    There were no material changes in Distribution and Transmission revenues,
expenses and operating income, for the three and six months ended June 30,
2009 compared with the corresponding periods in 2008. The increase in
administration expenses for costs related to the Reorganization were offset by
decreased energy purchases due to lower Alberta power prices.

    Energy Services

    -------------------------------------------------------------------------
    Energy Services results (including
     intersegment transactions)       Three months ended   Six months ended
    (Unaudited, $ millions)                 June 30             June 30
    -------------------------------------------------------------------------
                                          2009      2008      2009      2008

    Revenues                          $    381  $    567  $    970  $  1,095
    Expenses                               360       575       878     1,089
    -------------------------------------------------------------------------
    Operating income (loss)           $     21  $     (8) $     92  $      6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                  Three       Six
                                                            months    months
    -------------------------------------------------------------------------
    Operating income (loss) for the periods ended
     June 30, 2008                                        $     (8) $      6
    Unrealized fair value changes in derivative
     instruments and natural gas inventory                      51       106
    Higher natural gas margins                                   3         6
    Higher administration expenses                             (12)      (12)
    Lower Alberta electricity margins                          (13)      (19)
    Other                                                        -         5
    -------------------------------------------------------------------------
    Increase in operating income                                29        86
    -------------------------------------------------------------------------
    Operating income (loss) for the periods ended
     June 30, 2009                                        $     21  $     92
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Energy Services' operating income increased $29 million for the quarter
and $86 million for the six months ended June 30, 2009 compared with the
corresponding periods in 2008 due to the net impact of the following:

    -   The unrealized fair value changes relate primarily to a net short
        position in both periods of both years for derivative electricity
        contracts that were not designated as hedges for accounting purposes.
        In the first and second quarters of 2009, forward Alberta power
        prices decreased which increased the fair value of these contracts
        whereas in the corresponding periods of 2008 forward Alberta power
        prices increased which reduced the fair value of these contracts.
        These unrealized fair value changes increased energy revenues by
        $47 million and decreased energy purchases by $4 million in the
        second quarter of 2009 compared with the second quarter of 2008, and
        increased energy revenues and energy purchases by $137 million and
        $31 million respectively, in the first half of 2009 compared with the
        first half of 2008.

    -   Natural gas margins were higher primarily due to gains realized on
        sales of storage gas in the first half of 2009 compared with losses
        in the first half of 2008 and increased margins from our speculative
        natural gas portfolio. Natural gas revenues and purchases decreased
        $143 million and $146 million respectively, in the second quarter of
        2009 compared with the corresponding period in 2008 primarily due to
        lower physical natural gas trading activities, lower natural gas
        consumption due to fewer wholesale and merchant customers and lower
        natural gas prices. These factors also resulted in decreases in
        natural gas revenues and purchases for the first half of 2009 of
        $165 million and $171 million, respectively.

    -   Administration expenses increased in the three months ended June 30,
        2009 primarily due to costs incurred for the Reorganization.

    -   In the second quarter of 2009, energy revenues and expenses from our
        Alberta electricity portfolio decreased $55 million and $42 million
        respectively, compared with the second quarter of 2008 due to the
        impact of reduced Alberta power prices on the portfolio, our reduced
        interest in the Battle River PSA, and lower pricing and volumes for
        our RRT business. The portfolio was in a net long position as we had
        more physical supply from our generating stations and interests in
        the Battle River and Sundance PPAs (acquired PPAs) than we had
        contracted to sell. The decrease in power generation resulting from
        our reduced interest in the Battle River PSA was partly offset by
        increased generation from Genesee 3. The impact of lower revenues on
        the energy margins for our RRT business was minimal. In the first
        half of 2009, energy revenues and expenses from our Alberta
        electricity portfolio were impacted by the factors described above
        for the second quarter and decreased $53 million and $34 million
        respectively.

    -   Decreased trading activities in the western U.S., north eastern U.S.
        and Ontario in the second quarter and first half of 2009 compared
        with the corresponding periods in 2008 reduced revenues by
        $36 million and $47 million respectively, but had minimal impact on
        energy margins.

    Water Services

    -------------------------------------------------------------------------
    Water Services results (including
     intersegment transactions)       Three months ended   Six months ended
    (Unaudited, $ millions)                 June 30             June 30
    -------------------------------------------------------------------------
                                          2009      2008      2009      2008

    Revenues                          $     92  $     70  $    159  $    128
    Expenses                                76        55       133       102
    -------------------------------------------------------------------------
    Operating income                  $     16  $     15  $     26  $     26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    (Unaudited, $ millions)                                  Three       Six
                                                            months    months
    -------------------------------------------------------------------------
    Operating income for the periods ended June 30, 2008  $     15  $     26
    Increased water rates and sales volumes, net of
     franchise fees                                              5         7
    Gold Bar operating income excluding administration
     expenses in 2009                                            5         5
    Higher administration expenses                              (6)       (9)
    Other                                                       (3)       (3)
    -------------------------------------------------------------------------
    Increase in operating income                                 1         -
    -------------------------------------------------------------------------
    Operating income for the periods ended June 30, 2009  $     16  $     26
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Water Services' operating income increased $1 million in the second
quarter and was unchanged in first half of 2009 compared with the
corresponding periods of the prior year due to the net impact of the
following:

    -   Revenues from water sales, net of franchise fees, were higher in the
        three and six months ended June 30, 2009 compared with the
        corresponding periods in 2008, primarily due to increased rates
        effective April 1, 2008 and April 1, 2009 under Water Services'
        Performance Based Rate structure as approved by the regulator, The
        City of Edmonton, and increased sales volumes due to drier weather
        conditions in the second quarter of 2009.

    -   The Gold Bar operation, which was transferred from the City of
        Edmonton on March 31, 2009, contributed $13 million in revenues and
        $8 million in expenses in the second quarter.

    -   Administration expenses increased in the second quarter of 2009 due
        to costs related to the Reorganization and the Gold Bar operation.
    

    Transportation and other commercial services revenues were $4 million
higher in the second quarter and $11 million higher in the six months ended
June 30, 2009 compared with the corresponding periods in 2008 primarily due to
the water and wastewater treatment facilities construction project for Suncor
Energy Inc. and increased construction activity for street lighting, signals
and light rail transit overhead wires for the City of Edmonton. The
construction project for Suncor commenced in the second quarter of 2008 and
was substantially completed in June 2009. The increase in revenues had minimal
impact on operating income primarily because of increased labour and business
development costs.
    A higher incidence and cost of water distribution main breaks in both
periods in 2009 compared with the corresponding periods in 2008 also
contributed to higher expenses in Water Services.

    
    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
                      June 30, December  Increase
    ($ millions)         2009  31, 2008 (decrease)    Explanation
    -------------------------------------------------------------------------
    Cash and cash       $  81     $ 111     $ (30)    Refer to liquidity and
     equivalents                                      capital resources
                                                      section.
    -------------------------------------------------------------------------
    Accounts receivable   391       509      (118)    Lower receivables from
     (including income                                RRT customers due to
     taxes recoverable)                               lower rates and
                                                      consumption in June
                                                      2009 compared with
                                                      December 2008. Lower
                                                      receivables from
                                                      commercial and
                                                      industrial customers
                                                      due to fewer customers.
                                                      Lower receivables from
                                                      the Alberta Electric
                                                      System Operator and
                                                      customers subject to
                                                      pool price flow-through
                                                      pricing due to lower
                                                      spot prices in June
                                                      2009 compared with
                                                      December 2008.
    -------------------------------------------------------------------------
    Derivative            141       130        11     Increase in fair value
     instruments                                      of power derivative
     assets (current)                                 sell contracts, partly
                                                      offset by decrease in
                                                      fair value of natural
                                                      gas derivative buy
                                                      contracts and Power
                                                      LP's natural gas supply
                                                      contracts.
    -------------------------------------------------------------------------
    Other current assets   97        96         1
    -------------------------------------------------------------------------
    Property, plant and 5,001     4,639       362     Addition of 2009
     equipment                                        capital expenditures
                                                      and Gold Bar assets
                                                      partly offset by
                                                      depreciation and
                                                      amortization expense.
    -------------------------------------------------------------------------
    Power purchase        507       550       (43)    Amortization of PPAs
     arrangements (PPAs)                              and impact of lower
                                                      foreign exchange rate
                                                      on the translation of
                                                      Power LP's U.S. PPAs.
    -------------------------------------------------------------------------
    Contract and          300       296         4
     customer rights and
     other intangible
     assets
    -------------------------------------------------------------------------
    Derivative             74        75        (1)
     instruments assets
     (non-current)
    -------------------------------------------------------------------------
    Future income tax      99       103        (4)
     assets (non-current)
    -------------------------------------------------------------------------
    Goodwill              158       161        (3)
    -------------------------------------------------------------------------
    Other assets          233       235        (2)
    -------------------------------------------------------------------------
    Assets held for sale   26        43       (17)    Sale of 10% interest in
                                                      Battle River PSA.
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                      June 30, December  Increase
    ($ millions)         2009  31, 2008 (decrease)    Explanation
    -------------------------------------------------------------------------
    Short-term debt     $ 468     $ 140     $ 328     Issuance of bankers'
                                                      acceptances and
                                                      commercial paper.
    -------------------------------------------------------------------------
    Accounts payable      455       587      (132)    Lower accrued payables
     and accrued                                      to the Alberta Electric
     liabilities                                      System Operator due to
                                                      lower spot prices in
                                                      June, 2009 compared
                                                      with December, 2008,
                                                      lower current
                                                      liabilities for
                                                      Generation capital
                                                      projects and Power LP
                                                      cash distributions to
                                                      unitholders. Partly
                                                      offset by current
                                                      liabilities for
                                                      Reorganization costs
                                                      and the current portion
                                                      of the transfer fee
                                                      payable to the City of
                                                      Edmonton for the Gold
                                                      Bar asset transfer.
    -------------------------------------------------------------------------
    Derivative            144       131        13     Increased liability
     instruments                                      associated with the
     liabilities                                      fair value of power
     (current)                                        derivative buy
                                                      contracts partly offset
                                                      by fair value changes
                                                      in natural gas
                                                      derivative buy
                                                      contracts.
    -------------------------------------------------------------------------
    Other current
     liabilities           59        58         1
    -------------------------------------------------------------------------
    Long-term debt      2,600     2,728      (128)    Repayment of
     (including current                               $224 million of
     portion)                                         long-term debt that was
                                                      outstanding under the
                                                      syndicated bank credit
                                                      facility, and other
                                                      ongoing debt
                                                      repayments, partly
                                                      offset by the issuance
                                                      of $112 million of
                                                      long-term debt to the
                                                      City of Edmonton for
                                                      the Gold Bar asset
                                                      transfer and
                                                      $38 million of
                                                      long-term debt under
                                                      Power LP's revolving
                                                      credit facilities.
    -------------------------------------------------------------------------
    Derivative             64       110       (46)    Decreased liability
     instruments                                      associated with the
     liabilities                                      fair value of power
     (non-current)                                    derivative sell
                                                      contracts and Power
                                                      LP's forward foreign
                                                      exchange contracts.
    -------------------------------------------------------------------------
    Other non-current     171       125        46     Reflects the
     liabilities                                      non-current portion of
                                                      the transfer fee owing
                                                      to the City of Edmonton
                                                      for the Gold Bar asset
                                                      transfer.
    -------------------------------------------------------------------------
    Future income tax     107       100         7
     liabilities
     (non-current)
    -------------------------------------------------------------------------
    Non-controlling       492       540       (48)    Non-controlling
     interests                                        interests' share of
                                                      Power LP distributions
                                                      and other comprehensive
                                                      loss, partly offset by
                                                      non-controlling
                                                      interests' share of
                                                      Power LP's net income.
    -------------------------------------------------------------------------
    Shareholder's       2,548     2,429       119     Net income, other
     equity                                           comprehensive income
                                                      and the Gold Bar asset
                                                      capital contribution,
                                                      partly offset by common
                                                      share dividends and
                                                      refundable income
                                                      taxes.
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    LIQUIDITY AND CAPITAL RE

SOURCES ------------------------------------------------------------------------- Cash inflows (outflows) ------------------------------------------------------------------------- Three months ended June 30 ---------------- Increase ($ millions) 2009 2008 (decrease) Explanation ------------------------------------------------------------------------- Operating $ 104 $ 41 $ 63 Receipt of Genesee PPA availability incentive income in 2009 compared with payment of availability penalties in 2008, and payments for major maintenance for Genesee turnarounds in 2008. Investing (158) (146) (12) Higher payments for capital expenditures on Keephills 3 and Clover Bar Energy Centre, partly offset by proceeds on the disposal of the Castleton facility in 2009. Financing 13 129 (116) Net financing receipts in 2009 included net proceeds from the issuance of bankers' acceptances and commercial paper partly offset by ongoing long-term debt repayments. Net financing receipts in 2008 included the issuance of $400 million of medium-term note debentures, partly offset by repayment of $200 million of medium- term note debentures and ongoing long-term debt repayments. ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash inflows (outflows) ------------------------------------------------------------------------- Six months ended June 30 ---------------- Increase ($ millions) 2009 2008 (decrease) Explanation ------------------------------------------------------------------------- Operating $ 251 $ 139 $ 112 Payment in 2008 of income taxes related to the 2006 gain on sale of the Battle River PSA, receipt of Genesee PPA availability incentive income in 2009 compared with payment of availability penalties in 2008, and payments for major maintenance for Genesee turnarounds in 2008. Investing (286) (221) (65) Higher payments for capital expenditures and payment of a Gold Bar transfer fee installment in 2009, partly offset by proceeds on the disposal of the Castleton facility in 2009. Financing 2 131 (129) Net financing receipts in 2009 included $328 million in net proceeds from the issuance of bankers' acceptances and commercial paper, and $39 million from the issuance of long-term debt under Power LP's revolving credit facilities, partly offset by repayment of $224 million of long- term debt that was outstanding under the syndicated bank credit facility, and other ongoing debt repayments. Net financing receipts in 2008 included the issuance of $600 million of medium- term note debentures and net proceeds from the issuance of commercial paper, partly offset by repayment of $200 million of medium- term note debentures and $155 million of long-term debt that was outstanding under the syndicated bank credit facility, and ongoing long-term debt repayments. ------------------------------------------------------------------------- ------------------------------------------------------------------------- The Company's cash from operating activities increased $63 million and $112 million in the three and six months ended June 30, 2009 respectively, compared with the corresponding periods in 2008. Over the next few quarters, we anticipate funds from operations to decrease due to the absence of the power generation business which transferred to Capital Power effective early July 2009. The Company plans to finance its working capital requirements with existing credit facilities and the issuance of commercial paper. On July 9, 2009, cash proceeds received on the sale of the power generation business to Capital Power of approximately $468 million increased cash flow from investing activities. Of the proceeds received, approximately $424 million was used to repay bankers' acceptances and $44 million was used to repay commercial paper indebtedness. In addition, EPCOR expects to receive partnership distributions of approximately $18 million per quarter on its 56.6 million exchangeable LP units of Capital Power LP. On July 9, 2009, EPCOR received an $896 million long-term loan receivable from Capital Power LP as part of the consideration on the sale of the power generation business. The principal amounts, repayment schedules and interest rates of the long-term receivable mirror those of certain public debentures of EPCOR that were originally issued in respect of its power generation business. The long-term loan receivable also includes an amount of principal with interest payments that will be sufficient to meet certain debt obligations of EPCOR to the City of Edmonton. At June 30, 2009, the Company had undrawn bank credit facilities of $1,511 million including $222 held by Power LP. In conjunction with the Reorganization on July 9, 2009, the Company cancelled its $600 million syndicated bank credit facility and renegotiated its $800 million syndicated bank credit facility to $500 million. The $500 million syndicated bank credit facility has two tranches of $250 million each. One tranche has approximately 1.5 years remaining while the other has approximately 3.5 years remaining. The changes to the syndicated bank credit facility required increases to borrowing costs to reflect current market conditions. In addition, the Company's five bilateral bank credit facilities totalling $490 million were cancelled and similar facilities were established in CPC. Immediately after the Reorganization, the Company had undrawn committed bank credit facilities of $434 million, of which $136 million was committed for at least two years. These amounts exclude Power LP's credit facilities as it is accounted for on an equity basis effective July 1, 2009 and is no longer consolidated in EPCOR's financial statements. Committed bank lines of credit are also used to provide letters of credit. At June 30, 2009, the Company had letters of credit of $183 million (December 31, 2008 - $253 million) outstanding to meet the credit requirements of energy market participants and conditions of certain service agreements, and to satisfy legislated reclamation requirements. The committed bank lines also indirectly back the Company's commercial paper program which has an authorized capacity of $500 million, of which $44 million was outstanding at June 30, 2009 (December 31, 2008 - $113 million). Immediately after the Reorganization, the Company had $114 million of letters of credit outstanding and its commercial paper program had an effective authorized capacity of $225 million arising from the revised credit facilities, with no amount outstanding. The Company's financing requirements for capital projects are expected to decrease after the transfer of the power generation business to Capital Power in early July 2009. Spending on capital projects and Water Services' commercial construction projects for the remainder of the year is expected to be approximately $280 million and financed with existing credit facilities, the issuance of commercial paper or medium-term notes. The Company has a Canadian shelf prospectus under which it may raise up to $1 billion of debt with maturities of not less than one year. The shelf prospectus expires in November 2009. At June 30, 2009, the available amount remaining under this shelf prospectus was $400 million. Effects of economic downturn and market uncertainty Canadian and U.S. financial markets stabilized somewhat in the second quarter of 2009. The Company secured financing to fund its capital expenditures and working capital requirements at a weighted average interest rate of 0.43% through the issue of commercial paper and bankers' acceptances. The Company plans to continue using commercial paper, existing credit facilities or medium-term notes for its financing requirements for the balance of the year. Should instability in the credit and economic environments worsen, it may adversely affect the interest rates at which we are able to borrow. Notwithstanding the limited signs of improvement in the global economy, if the world-wide economy were to deteriorate in the longer term, particularly as they relate to Canada and the U.S., they may adversely affect the Company's ability to renew credit facilities, arrange long-term financing for its capital expenditure programs and acquisitions, or refinance outstanding indebtedness when it matures. If market conditions worsen, the Company may suffer a credit rating downgrade and be unable to renew its credit facilities or access the public debt markets. Although we continue to believe that these circumstances have a low probability of occurring, we are monitoring EPCOR's capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honour its obligations. Some of these considerations include the preservation of capital through capital expenditure reduction or deferral, operating cost reductions and sale of Capital Power LP units, market conditions permitting and in accordance with the terms and certain limiting conditions of the Reorganization. CONTRACTUAL OBLIGATIONS During the second quarter, the Company financed its capital expenditures and working capital requirements through its credit facilities and commercial paper program. The Company's outstanding short-term debt increased $84 million in the second quarter and $328 million in the first six months of 2009. Power LP's long-term debt under its bank credit facilities increased $29 million in the first quarter and $9 million in the second quarter of 2009. The Company repaid $214 million in the first quarter and $10 million in the second quarter of long-term debt that was outstanding under its syndicated bank credit facility at December 31, 2008. On March 31, 2009, EPCOR issued $112 million of long-term debt to the City of Edmonton and incurred a $75 million transfer fee payable to the City of Edmonton for the Gold Bar asset transfer. The long-term debt bears interest at a weighted average interest rate of approximately 5.25% and matures over the period from 2010 to 2033 as follows: ------------------------------------------------------------------------- (Unaudited, $ millions) ------------------------------------------------------------------------- 2009 $ 6 2010 6 2011 6 2012 5 2013 to 2033 89 ------------------------------------------------------------------------- Total $ 112 ------------------------------------------------------------------------- ------------------------------------------------------------------------- The transfer fee is payable in annual instalments over the period from 2009 to 2015 and is included in the table of contractual obligations in EPCOR's 2008 annual MD&A. The first instalment of $17 million was paid on March 31, 2009. There have been no other material changes to the Company's purchase obligations, including payments for the next five years and thereafter, during the second quarter. However, a significant portion of EPCOR's contractual obligations were transferred to Capital Power or extinguished in conjunction with the sale of the power generation business and Reorganization effective early July 2009. Accordingly, EPCOR's contractual obligations at June 30, 2009 adjusted for the subsequent transactions relating to the sale and Reorganization were as follows: ------------------------------------------------------------------------- Due between Due after Due ----------------------------------more than within 1 and 2 and 3 and 4 and five $ millions 1 year 2 years 3 years 4 years 5 years years Total ------------------------------------------------------------------------- Capital projects (1) $ 67 $ 3 $ - $ - $ - $ - $ 70 Water and wastewater infra- structure projects(2) 24 31 12 10 6 1 84 Long-term debt(3) 230 25 217 14 11 1,261 1,758 Interest on long-term debt 161 127 107 90 81 903 1,469 Short-term debt 468 - - - - - 468 Asset retirement obligations(4) 5 14 - - - - 19 Operating leases 2 2 6 11 11 189 221 ------------------------------------------------------------------------- Total $ 957 $ 202 $ 342 $ 125 $ 109 $ 2,354 $ 4,089 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) EPCOR's obligations for capital projects include obligations for various Distribution and Transmission and Water Services' projects. (2) EPCOR's obligations for water and wastewater infrastructure projects include obligations for the town of Chestermere project and the transfer fee related to the purchase of Gold Bar from the City of Edmonton. (3) Obligations assumed by EPCOR upon transfer of Gold Bar from the City of Edmonton are included. The transfer fee obligation is included in water and wastewater infrastructure projects above. (4) EPCOR's asset retirement obligations reflect the undiscounted cash flow required to settle obligations for the retirement of the Rossdale generating plant. The long-term debt and interest on long-term debt in the above table include amounts for EPCOR's public debentures and obligations to the City of Edmonton that are mirrored by an $896 million long-term receivable from Capital Power LP. For further information on the Company's contractual obligations, refer to the 2008 annual MD&A. CHANGES IN ACCOUNTING STANDARDS Accounting changes for 2009 Rate-regulated operations In December 2007, the Canadian Institute of Chartered Accountants (CICA) amended Handbook Sections 1100 - Generally Accepted Accounting Principles and made consequential amendments to Accounting Guideline 19 - Disclosures by Entities Subject to Rate Regulation. The amendments removed the temporary exemption from the requirement to apply Section 1100 to the recognition and measurement of assets and liabilities arising from rate regulation, effective January 1, 2009. As permitted by Canadian GAAP, the Company is applying the U.S. Financial Accounting Standards Board (FASB) standard, Statement of Financial Accounting Standards No. 71 - Accounting for the Effects of Certain Types of Regulation (SFAS 71), which provides guidance for the recognition and measurement of rate-regulated assets and liabilities. These amendments and adoption of the SFAS 71 guidance effective January 1, 2009 did not have a material impact on our interim consolidated financial statements and is not expected to have a material impact going forward. Intangible assets In February 2008, the CICA issued Handbook Section 3064 - Goodwill and Intangible Assets and consequential amendments to Section 1000 - Financial Statement Concepts. The new section establishes standards effective January 1, 2009 for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions in International Financial Reporting Standards. EPCOR has adopted these amendments commencing January 1, 2009 and applied them on a retrospective basis, resulting in the reclassification of $89 million of net assets from property, plant and equipment to contract and customer rights and other intangible assets in the comparative December 31, 2008 balance sheet. The adoption of these amendments had no other material impact on our interim consolidated financial statements. Credit risk and fair value of financial assets and liabilities On January 20, 2009, the Emerging Issues Committee of the CICA issued EIC-173 Credit Risk and the Fair Value of Financial Assets and Liabilities, which clarifies that an entity's own credit risk and the credit risk of its counterparties should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. Effective January 1, 2009, the Company adopted the recommendations of EIC-173 and applied them retrospectively without restatement of prior periods. Including counterparty credit risk in the estimate of the fair value of Power LP's natural gas and foreign exchange contracts on January 1, 2009 had the following impact on EPCOR's balance sheet on that date: ------------------------------------------------------------------------- Increase (Unaudited, $ millions) (decrease) ------------------------------------------------------------------------- Derivative instruments assets - non-current $ (1) Derivative instruments liabilities - non-current (6) Future income tax liabilities - non-current 1 Non-controlling interests 3 Opening retained earnings 1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Future accounting changes International financial reporting standards In February 2008, the CICA confirmed that Canadian reporting issuers will be required to report under International Financial Reporting Standards effective January 1, 2011, including comparative figures for the prior year. In January 2008, we established a core team to develop a plan which will result in the Company's first interim report for 2011 being in compliance with International Financial Reporting Standards. The diagnostic phase of the project was completed in April 2008. For each international standard, we identified the primary differences from Canadian GAAP and made an initial assessment of the impact of the required changes for the purpose of prioritizing and assigning resources. In making the assessment, the number of businesses impacted, the potential magnitude of the financial statement adjustment, the availability of policy choices, the impacts on systems and the impacts on internal controls were all considered. The information obtained from the diagnostic phase was used to develop a detailed plan for convergence and implementation. The convergence and implementation work has five key sections: Financial Statement Adjustments, Financial Statements, Systems Updates, Policies and Internal Controls, and Training. Financial Statement Adjustments For each international standard, we will determine the quantitative impacts to the financial statements, system requirements, accounting policy decisions, and changes to internal controls and business policies. The initial accounting policy decisions will be brought forward to the Audit Committee for their information as each standard is addressed. However, final accounting policy decisions for all standards in effect at the end of 2009 will be made in the fourth quarter of 2009, as they should not be determined in isolation of other policy decisions. Policy decisions for any new standards or standards that are amended in 2010 will be made in conjunction with our analysis of those standards in 2010. As the project progresses, the timing of completion of certain items may change as changes to standards and other external factors such as discussions with certain stakeholders may result in a change in priorities. However, we believe the project has sufficient resources to meet the overall project timeline. Financial Statements There are also a number of international standards which relate to financial statement presentation. Draft financial statements highlighting the disclosure and presentation requirements were reviewed by and discussed with the EPCOR Audit Committee in the first quarter of 2009. Recommendations on certain presentation issues such as whether to present the income statement by function or nature of expense have been developed and will be brought forward in the third quarter of 2009. The development of the financial statement presentation will evolve throughout the project as the impacts of implementing the various standards are quantified. Systems Updates The diagnostic phase of the project identified two key accounting system requirements. The system must be able to capture 2010 financial information under both the prevailing Canadian GAAP and International Financial Reporting Standards to allow comparative reporting in 2011, the first year of reporting under International Financial Reporting Standards. It must also be able to accommodate possible changes to foreign currency translation methods, depending on how certain foreign entities are classified under International Financial Reporting Standards. EPCOR developed a systems strategy in 2008 and commenced implementation of this strategy in the first quarter of 2009. This strategy involves the implementation of a parallel fixed asset subledger and general ledger, which is planned for completion in the third quarter of 2009. Policies and Internal Controls In the determination of the financial statement adjustments, requirements for changes to Company policies and internal controls will be identified and documented. As there may be factors other than International Financial Reporting Standards impacting policies and internal controls, the formal documentation and approval of revised policies and internal controls will not occur until the third quarter of 2010. The impact of International Financial Reporting Standards on certain agreements, such as debt, shareholder and compensation agreements, has also been included in the plan. Initial assessments of most agreements were performed in the second quarter and the balance will be assessed in the third quarter of 2009. Training The Company recognizes that training at all levels is essential to a successful conversion and integration. Accounting staff have attended two training sessions with more planned to occur throughout the conversion process. The Board of Directors and Audit Committee have attended a training session, and the Audit Committee receives regular updates on the conversion project. Further training for the Board of Directors and Audit Committee will occur throughout the project. Disclosures about financial instruments In June 2009, the CICA amended Handbook Section 3862 Financial Instruments - Disclosures, to adopt the amendments recently made by the International Accounting Standards Board to IFRS 7 Financial Instruments: Disclosures. The amendments require enhanced disclosures about fair value measurements, including the relative reliability of the inputs used in those measurements, and about the liquidity risk of financial instruments. Although the amendments apply to financial statements relating to fiscal years ending after September 30, 2009, comparative information is not required in the first year of application. We will assess the impacts of these amendments on our financial statements and implement the necessary additional disclosures commencing with the annual financial statements for 2009. Consolidated financial statements and non-controlling interests In January 2009, the CICA issued Handbook Section 1601 - Consolidated Financial Statements and Section 1602 - Non-controlling Interests, which replace Section 1600 - Consolidated Financial Statements. Section 1601 establishes the standards for the preparation of consolidated financial statements while Section 1602 establishes the standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. Section 1602 is equivalent to the corresponding provisions of International Accounting Standard 27 - Consolidated and Separate Financial Statements. Sections 1601 and 1602 will apply to EPCOR's interim and annual consolidated financial statements relating to periods commencing on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year provided Section 1582 - Business Combinations is also adopted at the same time. The impact of the new standards and the option to adopt them early will be assessed as part of our International Financial Reporting Standards project. Business combinations In January 2009, the CICA issued Handbook Section 1582 - Business Combinations, which replaces Section 1581 - Business Combinations and provides the Canadian equivalent to International Financial Reporting Standard 3 - Business Combinations. The section will apply on a prospective basis to EPCOR's business combinations for which the acquisition date is on or after January 1, 2011. Earlier adoption is permitted as of the beginning of a fiscal year provided Sections 1601 - Consolidated Financial Statements and 1602 - Non-controlling Interests are also adopted at the same time. The impact of the new standard and the option to adopt it early will be assessed as part of our International Financial Reporting Standards project. CRITICAL ACCOUNTING ESTIMATES In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the consolidated financial statements: electricity revenues, costs and unbilled consumption, fair values, allowance for doubtful accounts, useful lives of assets, income taxes and PPA availability incentives. For further information on the Company's accounting estimates, refer to the 2008 annual MD&A. 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, environment, health and safety risk, political, legislative and regulatory risk, project risk, credit risk, financial liquidity risk, supply risk of acquired PPAs, 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. On June 11, 2009, William Pidruchney filed a Statement of Claim against The City of Edmonton, EPCOR, Power LP General Partner, Power LP and CPC. Mr. Pidruchney alleged, among other things, that The City of Edmonton acted beyond its power and contrary to the Municipal Government Act (Alberta) and did not observe an appropriate public process in connection with the sale of the power generation business to CPC. Based on its review of the available information, EPCOR believes that the claim is without merit and intends to vigorously defend itself. On June 26, 2009, EPCOR filed a Statement of Defence denying all of the allegations contained in the Statement of Claim. On July 3, 2009, Mr. Justice Hawco of the Alberta Court of Queen's Bench denied an application by William Pidruchney for an interim injunction to delay the closing of the Capital Power initial public offering and its acquisition of EPCOR's power generation business. The court was not satisfied that there was any real merit to Mr. Pidruchney's application. On June 30, 2009, an Originating Notice was filed in the Court of the Queen's Bench of Alberta, Judicial District of Edmonton, by the Alberta Federation of Labour, the Canadian Union of Public Employees, Local 30, and the Civic Service Union 52. The Notice names The City of Edmonton, EPCOR Utilities Inc. and CPC as Respondents and alleged, among other things, that certain purported actions taken by The City of Edmonton in connection with the sale of the power generation business to CPC were outside the jurisdiction of the municipality under the Municipal Government Act. Based on its review of the available information, EPCOR believes that this claim is without merit and intends to vigorously defend itself. On March 20, 2009, EPCOR was charged under Alberta's Occupational Health and Safety Act (the Act) and Occupational Safety Code (the Code) in relation to the 2007 fatality of a power lineman employee who came in contact with energized equipment at a job site in south Edmonton. The charge under the Act relates to failure to ensure, as far as it was reasonably practicable to do so, the health and safety of the employee. The three charges under the Code relate to safe work plan provisions, Alberta Electric Utility Code rules and work process safeguards with respect to energized electrical cables. We have received disclosure from the Solicitor General's office regarding the specifics of the allegations, which we are currently reviewing. The next court date is set for August 4, 2009 for the purpose of entering a plea to the charges. Each charge could attract a fine of up to $500,000 upon conviction. As part of 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 material changes to the risk profile or risk management strategies of EPCOR as described in the annual MD&A for 2008 that have affected the financial statements for the second quarter. As a result of the sale of the power generation business and the Reorganization, the risks associated with that business have transferred to Capital Power effective early July 2009. Although EPCOR no longer controls the power generation business, it has significant economic exposure to and influence over Capital Power and therefore the business risks as described in the annual MD&A for 2008 still apply. The key change is the risk associated with the loss of control over this part of the Company's total business. OUTLOOK The sale of the power generation business and associated Reorganization will significantly impact the presentation of EPCOR's subsequent results in its consolidated financial statements. Commencing in early July 2009, EPCOR will no longer recognize operating revenues and expenses for the Generation segment or for the electricity and natural gas trading operations of the Energy Services segment, but will recognize equity income from its approximate 72.2% interest in Capital Power. Also commencing in early July 2009, EPCOR will no longer consolidate the results of Power LP to recognize its 30.6% interest in the partnership's net income. However, EPCOR's equity earnings from Capital Power will include approximately 72.2% of the 30.6% interest in Power LP. In addition, the earnings volatility associated with fair value changes in power and natural gas derivative contracts that are not hedged for accounting purposes will be reflected in the equity earnings from Capital Power rather than in the operating results of the Generation and Energy Services segments. We expect EPCOR's financing expenses to decrease as we used the $468 million of cash proceeds from the sale of the generation business to repay bankers' acceptances and commercial paper debt on July 9, 2009. We also received an $896 million interest-bearing promissory note from Capital Power LP as part of the consideration for the sale, which has the same terms as a corresponding amount of EPCOR's long-term debt. Earnings in the next two quarters will continue to benefit from the March 31, 2009 addition of the Gold Bar operation. Although the second unit of the Clover Bar Energy Centre is still expected to start operating and contributing to net income in the third quarter of 2009 as discussed in the MD&A for the first quarter, its contribution will be reflected in the equity earnings from our 72.2% interest in Capital Power and not in operating revenues and expenses as previously expected. FORWARD-LOOKING INFORMATION Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target", and "expect" or similar words suggest future outcomes. Forward-looking information in this MD&A includes: (i) the Company may eventually sell all or a substantial portion of its ownership interest in Capital Power, subject to market conditions, its requirements for capital and other circumstances that may arise in the future, and reinvest the proceeds from the share sales in the Company's growing utility infrastructure businesses, including water and wastewater treatment, and power transmission and distribution; (ii) Keephills 3 construction will be completed by the end of the first quarter of 2011; (iii) installation of the remaining two units at the Clover Bar Energy Centre is planned for completion in the third quarter of 2009 and in 2010, respectively; (iv) funds from operations are expected to decrease over the next few quarters due to the Reorganization; (v) the Company plans to continue using commercial paper and existing credit facilities for its working capital requirements; (vi) the Company expects to receive partnership distributions of approximately $18 million per quarter on its 56.6 million exchangeable LP units of Capital Power LP; (vii) the company's financing requirements for capital projects are expected to decrease after the Reorganization; (viii) spending on capital projects and Water Services' commercial construction projects for the remainder of the year is expected to be $280 million and is expected to be financed with existing credit facilities, the issuance of commercial paper or medium-term notes; (ix) expectations regarding the impact on the Company of the capital and credit market instability and expected risk mitigation plans; (*) the Company will adopt amendments to accounting standards on financial statement disclosure for financial instruments in the fourth quarter of 2009; (xi) the expected payments to be received related to the acquisition of potable water and wastewater treatment plant assets subsequent to June 30, 2009; (xii) earnings for the remainder of 2009 will benefit from the addition of the Gold Bar operation; and (xiii) equity earnings from Capital Power will benefit from the commissioning of the second unit of the Clover Bar Energy Centre in the third quarter of 2009. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments and other factors it believes are appropriate. The material factors and assumptions underlying this forward-looking information include, but are not limited to: (i) the operation of the Company's facilities; (ii) power plant availability, including those subject to acquired PPAs (iii) the Company's assessment of commodity and power markets; (iv) the Company's assessment of the markets and regulatory environments in which it operates; (v) weather; (vi) availability and cost of labour and management resources; (vii) performance of contractors and suppliers; (viii) availability and cost of financing; (ix) foreign exchange rates; (*) management's analysis of applicable tax legislation; (xi) the currently applicable and proposed tax laws will not change and will be implemented; (xii) proposed environmental regulations will be implemented; (xiii) counterparties will perform their obligations; (xiv) expected interest rates, related credit spreads and mortality rates for new notes exchanged for ABCP; (xv) ability to implement strategic initiatives which will yield the expected benefits: and (xvi) the Company's assessment of capital markets and ability to complete future share offerings. Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from EPCOR's expectations. Such risks and uncertainties include, but are not limited to risks relating to: (i) operation of the Company's facilities (ii) power plant availability and performance; (iii) unanticipated maintenance and other expenditures; (iv) availability and price of energy commodities; (v) electricity load settlement; (vi) regulatory and government decisions including changes to environmental, financial reporting and tax legislation; (vii) weather and economic conditions; (viii) competitive pressures; (ix) construction; (*) availability and cost of financing; (xi) foreign exchange; (xii) availability of labour and management resources; and (xiii) performance of counterparties, partners, contractors and suppliers in fulfilling their obligations to the Company. This MD&A includes the following updates to previously issued forward-looking statements: (i) the second unit of the Clover Bar Energy Centre will be commissioned in the third quarter of 2009 as opposed to the second quarter of 2009 as previously reported due to a component failure during initial commissioning; (ii) expected capital spending will decrease from the previously disclosed $800 million to approximately $591 million due to the Reorganization; and (iii) earnings in the second quarter of 2009, before fair value changes were not consistent with earnings in the first quarter primarily due to costs related to the Reorganization. As a result of the Reorganization, EPCOR no longer controls the generation business that was sold to CPC. Accordingly, after the date of this MD&A, readers should refer to the public disclosures of CPC for any revisions to prior forward looking statements relating to EPCOR's former generation business. 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. QUARTERLY RESULTS ------------------------------------------------------------------------- Quarter ended Revenues Net income ------------------------------------------------------------------------- (Unaudited, $ millions) June 30, 2009 $ 740 $ 50 March 31, 2009 890 104 December 31, 2008 807 15 September 30, 2008 958 76 June 30, 2008 868 16 March 31, 2008 799 68 December 31, 2007 962 59 September 30, 2007 928 67 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Events for 2009, 2008 and 2007 quarters that have significantly impacted net income and the comparability between quarters are: - March 31, 2009 first quarter results included a $26 million gain on the sale of a 10% interest in the Battle River PSA, and unrealized fair value gains resulting from the impact of low Alberta power prices on our derivative electricity contracts that were not designated as hedges for accounting purposes. These gains were partly offset by unrealized fair value losses on Power LP's natural gas supply contracts, and forward foreign exchange contracts used to economically hedge U.S. cash flows. - December 31, 2008 fourth quarter results reflected impairment charges on the goodwill associated with the investment in Power LP and on Power LP's investment in PERH. Power LP also recognized unrealized fair value losses on its forward foreign exchange contracts used to economically hedge U.S. cash flows and on its natural gas supply contracts. - September 30, 2008 third quarter results reflected gains on the sale of portfolio investments and unrealized fair value gains on derivative electricity contracts, Joffre contract for differences and forward foreign exchange contracts. These gains were partly offset by administration costs resulting from Long-Term Incentive Plan (LTIP) adjustments, and lower income from Power LP. - June 30, 2008 second quarter results reflected maintenance costs and Genesee PPA availability penalties resulting from scheduled turnarounds on all three Genesee plants partly offset by the favourable impact of high Alberta power prices on our derivative electricity contract portfolio, and unrealized fair value gains on Power LP's natural gas supply contracts. - March 31, 2008 first quarter results included a $30 million gain on the sale of a 10% interest in the Battle River PSA, the favourable impact of high Alberta power prices on our derivative contract portfolio which was in a net long position and unrealized fair value gains on Power LP's natural gas supply contracts. These gains were partly offset by maintenance costs and Genesee PPA availability penalties resulting from a scheduled turnaround at Genesee 1, and a fair value reduction of ABCP. - December 31, 2007 fourth quarter results included unrealized fair value gains on derivative financial instruments in our Alberta merchant and wholesale portfolio which were not designated as hedges for accounting purposes, and unrealized fair value gains on Power LP's natural gas supply contracts. These gains were partly offset by a reduction in the fair value of ABCP and a future income tax charge for the impact of future tax rate reductions which were substantively enacted in December 2007. - September 30, 2007 third quarter results included higher Alberta electricity margins due to favourable settlements on financial sales as a result of higher contract prices and lower Alberta power prices. In addition, the results included favourable unrealized fair value changes in financial and non-financial derivative instruments, which were not designated as hedges for accounting purposes, in Alberta merchant and wholesale positions due to lower forward power prices combined with a net short position. Additional information Additional information relating to EPCOR, including EPCOR's annual information form, is available on SEDAR at www.sedar.com.

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