EPCOR Power L.P. reports first quarter results



    EDMONTON, April 27 /CNW/ - (TSX: EP.UN) - EPCOR Power Services Ltd., the
general partner of EPCOR Power L.P. (the Partnership), today released the
Partnership's quarterly results for the period ended March 31, 2009.
    "The Partnership's first quarter operating cash flows were slightly below
our expectations as a result of lower water flows at our BC facilities and
lower waste heat availability at the Ontario facilities.", said Brian Vaasjo,
President of the General Partner of EPCOR Power L.P. "Cash provided by
operating activities from continuing operations was $33.7 million and
excluding working capital changes was $32.4 million in the first quarter of
2009. The Partnership reported a net loss of $33.3 million in the first
quarter of 2009, which was driven by the accounting recognition of $50.3
million in unrealized losses on the change in fair value of natural gas supply
and foreign exchange contracts. Due to various non-cash items that are
reported on the income statement which have no current economic impact, the
net loss is not a meaningful measure of the Partnership's operating
performance."
    "In the first quarter, our focus was on making progress on our two larger
growth initiatives. These initiatives include enhancements to our two North
Carolina facilities that will reduce environmental emissions and improve the
economic performance. The other initiative is the repowering of our North
Island facility that will improve plant efficiency. Both projects are on
schedule for completion later this year and are expected to be accretive."
    Highlights of EPCOR Power L.P.'s operational and financial performance
included:

    
    -------------------------------------------------------------------------
              Operational and Financial Highlights              Three months
                           (unaudited)                        ended March 31
    -------------------------------------------------------------------------
    (millions of dollars except per unit
     and operational amounts)                                 2009      2008
    -------------------------------------------------------------------------
    Power generated (GWh)                                    1,299     1,253
    -------------------------------------------------------------------------
    Weighted average plant availability                        94%       97%
    -------------------------------------------------------------------------
    Revenue                                                  127.6     118.1
    -------------------------------------------------------------------------
    Net income (loss) from continuing operations             (32.6)     53.3
    -------------------------------------------------------------------------
      Per unit                                            $  (0.60)  $  0.99
    -------------------------------------------------------------------------
    Net income (loss)                                        (33.3)     53.4
    -------------------------------------------------------------------------
      Per unit                                            $  (0.62)  $  0.84
    -------------------------------------------------------------------------
    Comprehensive income (loss)                              (16.6)     52.5
    -------------------------------------------------------------------------
    Cash provided by operating activities of
     continuing operations                                    33.7      41.6
    -------------------------------------------------------------------------
      Per unit(1)                                          $  0.63   $  0.77
    -------------------------------------------------------------------------
    Cash distributions                                        34.0      34.0
    -------------------------------------------------------------------------
      Per unit                                             $  0.63   $  0.63
    -------------------------------------------------------------------------
    Capital expenditures                                      17.0       3.4
    -------------------------------------------------------------------------
    Weighted average units outstanding (millions)             53.9      53.9
    -------------------------------------------------------------------------

    (1) Cash provided by operating activities of continuing operations per
        unit is a non-GAAP financial measure that is defined in the interim
        MD&A.

    The March 31, 2009 interim report is shown below. The interim management
discussion and analysis and interim consolidated financial statements are
available on the EPCOR Power L.P. website (www.epcorpowerlp.ca) and will be
available on SEDAR (www.sedar.com).



    EPCOR Power L.P.
    Management's Discussion and Analysis
    For the Three Months Ended March 31, 2009
    -------------------------------------------------------------------------
    

    This management's discussion and analysis (MD&A) is dated April 27, 2009
and should be read in conjunction with the unaudited interim consolidated
financial statements of EPCOR Power L.P. (collectively with its subsidiaries,
the Partnership, unless otherwise specifically stated) for the three months
ended March 31, 2009 and the audited consolidated financial statements and
MD&A of the Partnership for the year ended December 31, 2008. Additional
information relating to the Partnership, including the 2008 Annual Information
Form and continuous disclosure documents are available on SEDAR at
www.sedar.com. This discussion contains certain forward-looking information
and readers are advised to read this discussion in conjunction with the
cautionary statement regarding forward-looking information and statements on
page 23 of this report.
    EPCOR Power Services Ltd., the general partner of the Partnership (herein
the General Partner), a wholly-owned subsidiary of EPCOR Utilities Inc.
(collectively with its subsidiaries, EPCOR, unless otherwise specifically
stated), is responsible for management of the Partnership. The Board of
Directors (the Board) of the General Partner declares the cash distributions
to the Partnership's unitholders. The General Partner has engaged EPCOR
Regional Power Services L.P. and EPCOR USA Inc., both wholly-owned
subsidiaries of EPCOR Utilities Inc. (collectively herein, the Manager), to
perform management and administrative services for the Partnership and to
operate and maintain the power plants pursuant to management and operations
agreements. The Audit Committee of the Board is to review and approve the
interim MD&A of the Partnership in accordance with the Audit Committee's terms
of reference. The Audit Committee has reviewed and approved the contents of
this interim MD&A.



    
    CONSOLIDATED RESULTS OF OPERATIONS

    -------------------------------------------------------------------------
    (millions of dollars)(unaudited)
    -------------------------------------------------------------------------
    Cash provided by operating activities of continuing
     operations for the three months ended March 31, 2008               41.6
    -------------------------------------------------------------------------
    Lower operating margin at the North Carolina plants                 (3.0)
    Lower contract prices on foreign exchange contracts                 (2.4)
    Higher interest expenses                                            (1.8)
    Lower operating margin at the Ontario plants                        (1.7)
    Lower operating margin at Williams Lake                             (1.5)
    Contribution of Morris acquired October 31, 2008,
     excluding interest paid                                             2.4
    Other                                                                0.1
    -------------------------------------------------------------------------
    Cash provided by operating activities of continuing
     operations for the three months ended March 31, 2009               33.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Partnership reported cash provided by operating activities of
continuing operations of $33.7 million or $0.63 per unit for the quarter ended
March 31, 2009 compared to $41.6 million or $0.77 per unit for the same period
in 2008. Cash provided by operating activities of continuing operations per
unit is defined below under Non-GAAP Measures. The $7.9 million decrease in
cash provided by operating activities of continuing operations for the first
quarter of 2009 compared to the first quarter of 2008 was primarily due to the
following:

    
    -   Operating margin was $3.0 million lower at the North Carolina plants
        due to lower generation and higher maintenance costs for planned
        repairs undertaken during plant outages for the enhancement projects
        (see "Liquidity and Capital Resources - Capital Expenditures");
    -   The foreign exchange contracts that settled in the first quarter of
        2009 had lower contract prices compared to the same period in 2008,
        which resulted in a decrease in operating margin of $2.4 million.
        Approximately 40% of the reduction in operating margin expected in
        2009 as a result of lower contract prices was incurred in the first
        quarter;
    -   Higher interest expenses of $1.8 million were incurred due to the
        impact of a stronger US dollar relative to the Canadian dollar on US
        dollar interest expenses and interest on draws under the
        Partnership's revolving credit facilities to finance the acquisition
        of the Morris facility;
    -   Operating margin was $1.7 million lower at the Ontario plants due to
        higher waste heat optimization costs and lower waste heat
        availability; and
    -   Operating margin was $1.5 million lower at Williams Lake due to
        higher pricing under terms of the power purchase agreement (PPA) in
        2008 to offset the lower
        revenue in the second quarter of 2008 caused by a planned outage to
        complete a major overhaul.As a result, operating margin at Williams
        Lake is expected to be higher in the second quarter of 2009 compared
        the same period in 2008.

    Decreases were partially offset by $2.4 million of operating margin from
the Morris facility which was acquired on October 31, 2008.

    -------------------------------------------------------------------------
    (millions of dollars)(unaudited)
    -------------------------------------------------------------------------
    Cash provided by operating activities for the three
     months ended March 31, 2008                                        42.9
    -------------------------------------------------------------------------
    Decreases in cash provided by operating activities
     of continuing operations - see previous table                      (7.9)
    Decrease in cash provided by operating activities of Castleton      (2.6)
    -------------------------------------------------------------------------
    Cash provided by operating activities for the three months
     ended March 31, 2009                                               32.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Partnership reported cash provided by operating activities of $32.4
million for the three months ended March 31, 2009 compared to $42.9 million
for the same period in 2008. The decrease in cash provided by operating
activities of Castleton in the three months ended March 31, 2009 was due to
lower cash provided by operating activities after the expiry of its PPA in
June 2008.

    
    -------------------------------------------------------------------------
    (millions of dollars)(unaudited)
    -------------------------------------------------------------------------
    Net income from continuing operations for the three
     months ended March 31, 2008                                        53.3
    -------------------------------------------------------------------------
    Fair value changes on natural gas supply and foreign
     exchange contracts                                               (102.6)
    Lower operating margin at the North Carolina plants                 (3.0)
    Lower contract prices on foreign exchange contracts                 (2.4)
    Higher interest expenses                                            (1.8)
    Lower operating margin at the Ontario plants                        (1.7)
    Higher depreciation and amortization mainly due to the
     Morris acquisition in 2008                                         (1.7)
    Lower operating margin at Williams Lake                             (1.5)
    Decrease in income tax expense                                      13.3
    Foreign exchange losses                                             12.7
    Contribution of Morris acquired October 31, 2008,
     excluding interest paid                                             2.4
    Other                                                                0.4
    -------------------------------------------------------------------------
    Net loss from continuing operations for the three months ended
     March 31, 2009                                                    (32.6)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Net loss from continuing operations was $32.6 million or $0.60 per unit
for the three months ended March 31, 2009 compared to net income of $53.3
million or $0.99 per unit for the same period in 2008. In addition to the
items described above for the change in cash provided by operating activities,
the decrease in net income of $85.9 million was the result of the following:

    
    -   A net loss of $50.3 million was recorded in the first quarter of 2009
        on the change in the fair value of the natural gas supply and foreign
        exchange contracts compared to a net gain of $52.3 million in the
        first quarter of 2008 (see "Gains (Losses) on Derivative
        Instruments"). The majority of the changes in fair value are the
        result of decreases in the future market prices for natural gas in
        the first quarter of 2009 compared to increases in the first quarter
        of 2008.

    The items that reduced net income were partially offset by the following:

    -   An income tax recovery of $11.0 million was recorded in the first
        quarter of 2009 compared to income tax expense of $2.3 million in
        2008. The change was mainly due to future income taxes on changes in
        temporary differences primarily related to changes in the fair value
        of natural gas and foreign exchange contracts; and

    -   In the fourth quarter of 2008, the Partnership re-evaluated the
        functional currency of its US subsidiaries and determined it to be US
        dollars. Accordingly, gains and losses on foreign currency
        translation are accumulated as a component of partners' equity
        commencing in the fourth quarter of 2008. The Partnership reported
        net foreign exchange losses of $0.5 million for the three months
        ended March 31, 2009 compared to $13.2 million for the same period in
        2008.

    -------------------------------------------------------------------------
    (millions of dollars)(unaudited)
    -------------------------------------------------------------------------
    Net income for the three months ended March 31, 2008                53.4
    -------------------------------------------------------------------------
    Decreases in the net loss from continuing operations
     - see previous table                                              (85.9)
    Decrease in net income from Castleton                               (0.8)
    -------------------------------------------------------------------------
    Net loss for the three months ended March 31, 2009                 (33.3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    NON-GAAP MEASURES

    The Partnership uses operating margin as a performance measure and cash
provided by operating activities of continuing operations per unit as a cash
flow measure. These terms are not defined financial measures according to
Canadian generally accepted accounting principles (GAAP) and do not have
standardized meanings prescribed by GAAP. Therefore, these measures may not be
comparable to similar measures presented by other enterprises.
    The Partnership uses operating margin to measure the financial
performance of plants and groups of plants. A reconciliation from operating
margin to net income from continuing operations before tax and preferred share
dividends is as follows:

    
                                                                Three months
                                                              ended March 31
    (millions of dollars)(unaudited)                          2009      2008
    -------------------------------------------------------------------------
    Operating margin                                          (0.8)    106.8
    Deduct:
      Depreciation and amortization                           23.8      22.1
      Management and administration                            4.3       3.5
      Foreign exchange losses                                  0.5      13.2
      Equity losses in PERH                                    1.7       1.7
      Financial charges and other, net                        10.9       9.1
    -------------------------------------------------------------------------
    Net (loss) income from continuing operations
     before tax and preferred share dividends                (42.0)     57.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Cash provided by operating activities of continuing operations per unit
is cash provided by operating activities of continuing operations (a GAAP
defined measure) divided by the weighted average number of units outstanding
in the period. The composition of these measures is consistent with December
31, 2008 reporting.

    CHANGES IN ACCOUNTING POLICIES

    Commencing January 1, 2009, the Partnership adopted new accounting
guidelines and standards as issued by the Canadian Institute of Chartered
Accountants (CICA) for credit risk and the fair value of financial assets and
financial liabilities as well as goodwill and intangible assets.

    
    Credit risk and the fair value of financial assets and financial
    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 Financial
Liabilities, which clarifies that an entity's own credit risk and the credit
risk of the counterparty should be taken into account in determining the fair
value of financial assets and liabilities, including derivative instruments.
Effective January 1, 2009, the Partnership adopted the recommendations of
EIC-173 and applied the recommendations retrospectively without restatement of
prior periods. On January 1, 2009, the Partnership made the following
adjustments to the balance sheet to adopt the recommendations of EIC-173:

    
                                      Increase
    Balance sheet item               (decrease)                 Explanation
                                    ------------ ---------------------------
    Derivative instruments assets         (1.5)  Impact to fair value of
                                                 foreign exchange and natural
    Derivative instruments                       gas contracts from
     liabilities                          (6.3)  incorporating credit risk of
                                                 counterparties of the
                                                 Partnership.
    Future income taxes liabilities
     - non-current                         0.9   Tax impact from adoption of
                                                 new standard.

                                                 After tax impact to opening
                                                 deficit resulting from
    Opening deficit                       (3.9)  adoption of new standard.
                                    ------------ ---------------------------
    

    Goodwill and intangible assets

    In February 2008, the CICA issued Handbook Section 3064 - Goodwill and
Intangible Assets and consequential amendments to Section 1000 - Financial
Statement Concepts. The new section establishes standards for the recognition,
measurement and disclosure of goodwill and intangible assets. The provisions
relating to the definition and initial recognition of intangible assets,
including internally generated intangible assets, are equivalent to the
corresponding provisions in International Financial Reporting Standards
(IFRS). The Partnership adopted these amendments January 1, 2009 which did not
result in a material transition adjustment to the financial statements. The
new accounting standard has been applied prospectively and the comparative
financial statements have not been restated.

    
    OPERATING MARGIN(1) AND PLANT OUTPUT

    (millions of dollars except GWh)                  Three months ended
    (unaudited)                                             March 31
    -------------------------------------------------------------------------
                                            GWh      2009      GWh      2008
                                         ------------------------------------
    Ontario plants                          387   $  19.8      349   $  21.5
    Williams Lake                           136       6.9      137       8.4
    Mamquam and Queen Charlotte              29       1.5       29       1.3
    Northwest US plants                     214       8.9      195       8.7
    California plants                       229       1.5      243       3.0
    Curtis Palmer                            90       8.7      108       9.5
    Northeast US natural gas plants(3)      166       3.9       38       0.8
    North Carolina plants                    48      (2.3)     154       0.7
    PERC management fees                      -       0.6        -       0.6
                                         ------------------------------------
                                          1,299      49.5    1,253      54.5
    Fair value changes
      Foreign exchange contracts              -     (16.2)       -     (15.3)
      Natural gas supply contracts            -     (34.1)       -      67.6
                                         ------------------------------------
                                          1,299   $  (0.8)   1,253   $ 106.8
    -------------------------------------------------------------------------


    Weighted average plant                            Three months ended
    availability(2)                                         March 31
    -------------------------------------------------------------------------
                                                     2009               2008
                                         ------------------------------------
      Ontario plants                                  97%                99%
      Williams Lake                                  100%               100%
      Mamquam and Queen Charlotte                     81%                79%
      Northwest US plants                            100%               100%
      California plants                               86%                89%
      Curtis Palmer                                  100%               100%
      Northeast US natural gas plants(3)              98%                92%
      North Carolina plants                           75%                99%
    -------------------------------------------------------------------------
      Weighted average total                          94%                97%
    -------------------------------------------------------------------------

    (1) Operating margin is not a defined financial measure according to
        Canadian GAAP, and does not have a standardized meaning prescribed by
        GAAP. See "Non-GAAP Measures".

    (2) Plant availability represents the percentage of time in the period
        that the plant is available to generate power, whether actually
        running or not, and is reduced by planned and unplanned outages.

    (3) Includes the results of Morris from the date of acquisition of
        October 31, 2008. Restated to reflect the operations of Castleton as
        discontinued operations.
    

    Operating margin excluding fair value changes in foreign exchange and
natural gas supply contracts for the three months ended March 31, 2009
decreased by $5.0 million compared to the same period in 2008. The decrease in
operating margin was primarily due to lower margins at the North Carolina
facilities as a result of higher planned maintenance costs, lower margins at
the California facilities due to inspection work at Naval Station and lower
margins at the Ontario facilities primarily due to higher waste heat
optimization costs.
    Unrealized fair value changes in derivative instruments recorded for
accounting purposes are not representative of their economic value when
considering them in conjunction with the economically hedged item such as
future natural gas purchases or future power sales.

    Ontario Plants

    The Ontario plants reported operating margin of $19.8 million for the
three months ended March 31, 2009 compared to $21.5 million for the same
period in 2008. The decrease was primarily due to lower revenues from waste
heat. Waste heat optimization costs increased for the three months ended March
31, 2009 compared to the same period in 2008, while revenues from waste heat
declined 3%. Lower throughput on TransCanada Corporation's (TransCanada)
Canadian Mainline, the natural gas transmission line to Northern Ontario, was
the cause of the decline.

    Williams Lake

    Operating margin from Williams Lake was $6.9 million for the three months
ended March 31, 2009, compared to $8.4 million for the same period in 2008.
The decrease in operating margin was due to higher pricing under terms of the
PPA in 2008 to offset the lower revenue in the second quarter of 2008 caused
by a planned outage to complete a major overhaul. As a result, operating
margin at Williams Lake is expected to be higher in the second quarter of 2009
compared the same period in 2008.

    Mamquam and Queen Charlotte

    Operating margin at Mamquam and Queen Charlotte was $1.5 million for the
three months ended March 31, 2009, consistent with $1.3 million for the same
period in 2008.

    Northwest US Plants

    Operating margin from Frederickson was $3.3 million for the three months
ended March 31, 2009 consistent with $3.3 million for the same period in 2008.
    Operating margin from Manchief was $5.3 million for the three months
ended March 31, 2009, consistent with $5.1 million for the same period in
2008.
    Operating margin from Greeley was $0.3 million for the three months ended
March 31, 2009 consistent with $0.3 million for the same period in 2008.

    California Plants

    Operating margin from the Naval facilities was $1.6 million for the three
months ended March 31, 2009 compared to $2.5 million for the same period in
2008. The decrease was due to lower dispatch of Naval Station due to planned
outages for inspections and maintenance partially offset by lower maintenance
costs at North Island in 2009 and the impact of lower contract prices on
foreign exchange contracts that settled in the first quarter of 2009 compared
to the same period in 2008.
    Oxnard reported operating margin losses of $0.1 million for the three
months ended March 31, 2009 compared to operating margin of $0.5 million for
the same period in 2008. The decrease was due to turbine maintenance expenses
in 2009 related to damage to the natural gas turbine identified in 2008. The
total cost of the repair is expected to be in the range of $3 million to $4
million and may be covered by insurance and/or warranty from the company who
recently performed maintenance on the turbine.

    Curtis Palmer

    Operating margin from Curtis Palmer was $8.7 million for the three months
ended March 31, 2009 compared to $9.5 million for the same period in 2008. The
decrease was due to a decline in water flows to normal levels in 2009 which
resulted in lower generation partially offset by a step-up in pricing under
the PPA of 18% in December 2008.

    Northeast US Natural Gas Plants

    Operating margin from Morris, which was acquired on October 31, 2008, was
$2.4 million for the three months ended March 31, 2009, slightly below
expectations due to a short forced outage.
    Operating margin from Kenilworth was $1.5 million for the three months
ended March 31, 2009 compared to $0.8 million for the same period in 2008. The
increase was due to lower natural gas prices.

    North Carolina Plants

    The North Carolina plants reported operating margin losses of $2.3
million for the three months ended March 31, 2009 compared to operating margin
of $0.7 million for the same period in 2008. The decrease was the result of
higher maintenance costs for planned repairs undertaken during plant outages
for the enhancement projects (see "Liquidity and Capital Resources - Capital
Expenditures") and lower dispatch.

    Fair value changes

    Unrealized losses on foreign exchange contracts were $16.2 million for
the three months ended March 31, 2009 compared to $15.3 million reported for
the same period in 2008. The change in fair value was primarily due to changes
in the forward prices for Canadian dollars relative to US dollars which
increased $0.054 for the three months ended March 31, 2009 compared to $0.048
for the same period in 2008.
    The Partnership recorded fair value losses on the natural gas supply
contracts of $34.1 million for the three months ended March 31, 2009 compared
to fair value gains of $67.6 million for the same period in 2008. The changes
in the fair value of the natural gas contracts were primarily due to changes
in natural gas forward prices which decreased $0.32 per gigajoule (GJ) for the
three months ended March 31, 2009 compared to an increase of $1.10 per GJ for
the same period in 2008.

    
    REVENUES                                                    Three months
                                                              ended March 31
    (millions of dollars)(unaudited)                          2009      2008
    -------------------------------------------------------------------------

    Ontario
      - Power                                                 42.6      39.9
      - Enhancements                                           0.1       2.7
      - Gas diversions                                         1.0       0.6
                                                            -------   -------
                                                              43.7      43.2

    Williams Lake                                             10.5      10.6
      - Firm energy                                            0.5       0.3
                                                            -------   -------
      - Excess energy                                         11.0      10.9

    Mamquam and Queen Charlotte                                2.5       2.5
    Northwest US plants                                       15.7      14.9
    California plants                                         21.8      29.8
    Curtis Palmer                                             10.2      10.7
    Northeast US natural gas plants(1)                        27.5       7.7
    North Carolina plants                                     10.5      12.9
    PERC management expenses                                   0.9       0.8
    Fair value changes on foreign exchange contracts         (16.2)    (15.3)
    -------------------------------------------------------------------------
                                                             127.6     118.1
    -------------------------------------------------------------------------
    (1) Includes the results of Morris from the date of acquisition of
        October 31, 2008. Restated to reflect the operations of Castleton as
        discontinued operations.
    

    Revenues were $127.6 million for the three months ended March 31, 2009
compared to $118.1 million for the same period in 2008. The increase was
primarily due to the acquisition of Morris on October 31, 2008, which
contributed $17.0 million to revenues in the three months ended March 31,
2009. Overall, the plants in the US realized lower US dollar revenue for the
three months ended March 31, 2009 compared to the same period in 2008
primarily due to lower US dollar electricity prices at the California plants
as a result of lower natural gas prices, and lower generation at the North
Carolina plants. The lower US dollar revenues were partially offset by the
impact of a stronger US dollar relative to the Canadian dollar. A portion of
the impact of the stronger US dollar was offset by losses realized on foreign
exchange contracts used to hedge exposure to changes in the exchange rate
compared to realized gains for the same period in 2008. The realized gains or
losses were reflected in the revenues of the US plants.

    Ontario Plants

    The Ontario plants reported revenues of $43.7 million for the three
months ended March 31, 2009 compared to $43.2 million for the same period in
the prior year. The increase was due to built-in annual price escalators
partially offset by decreased enhancement activity due to lower natural gas
prices.

    Williams Lake

    Revenues from Williams Lake were $11.0 million for the three months ended
March 31, 2009, consistent with $10.9 million for the same period in 2008. The
impact of recoveries of higher fuel costs under the terms of the PPA (See
"Cost of Fuel") was partially offset by lower pricing under the terms of the
PPA in the first quarter of 2009.

    Mamquam and Queen Charlotte

    Revenues from Mamquam and Queen Charlotte were $2.5 million for the three
months ended March 31, 2009, consistent with the same period in 2008.

    Northwest US Plants

    Revenues from the Northwest US plants were $15.7 million for the three
months ended March 31, 2009 compared to $14.9 million for the same period in
2008. The increase was due to the impact of a stronger US dollar relative to
the Canadian dollar.

    California Plants

    Revenues from the California plants were $21.8 million for the three
months ended March 31, 2009 compared to $29.8 million for the same period in
2008. The decrease was due to the impact of lower US dollar electricity prices
driven by lower natural gas prices and planned outages for inspections at
Naval Station, partially offset by a stronger US dollar relative to the
Canadian dollar.

    Curtis Palmer

    Revenues from Curtis Palmer were $10.2 million for the three months ended
March 31, 2009 compared to $10.7 million for the same period in 2008. The
impact of lower generation in the first quarter of 2009 compared to the same
period in the prior year was partially offset by a step-up in pricing under
the Curtis Palmer PPA of 18% and a stronger US dollar relative to the Canadian
dollar.

    Northeast US Natural Gas Plants

    Revenues from the Northeast US natural gas plants were $27.5 million for
the three months ended March 31, 2009 compared with $7.7 million for the same
period in 2008. The increase was primarily due to the acquisition of Morris on
October 31, 2008, which contributed $17.0 million to revenues in the three
months ended March 31, 2009, and a stronger US dollar relative to the Canadian
dollar.

    North Carolina Plants

    Revenues from the North Carolina plants were $10.5 million for the three
months ended March 31, 2009 compared to $12.9 million for the same period in
2008. The decrease was the result of lower generation due to lower dispatch
resulting from increased competition from natural gas-fired plants in the
region due to lower natural gas prices, partially offset by a stronger US
dollar relative to the Canadian dollar.

    
    COST OF FUEL                                                Three months
                                                              ended March 31
    (millions of dollars)(unaudited)                          2009      2008
    -------------------------------------------------------------------------

    Ontario plants
      Natural gas                                             17.8      16.7
      Waste heat                                               1.5       0.6
      Wood waste                                               0.8       0.6
                                                            -------   -------
                                                              20.1      17.9

    Williams Lake - wood waste                                 2.1       0.6

    Northwest US plants - natural gas                          3.1       3.1

    California plants - natural gas                           14.6      21.5

    Northeast US natural gas plants - natural gas(1)          20.7       6.2

    North Carolina plants - coal, tire-derived
     fuel & wood waste                                         6.5       8.7

    Fair value changes on natural gas contracts               34.1     (67.6)
                                                            -------   -------
                                                             101.2      (9.6)
    -------------------------------------------------------------------------
    (1) Includes the results of Morris from the date of acquisition of
        October 31, 2008. Restated to reflect the operations of Castleton as
        discontinued operations.
    

    Fuel costs, which are the Partnership's most significant cost of
operations, include commodity costs, transportation costs and fair value
changes on natural gas supply contracts.
    For the three months ended March 31, 2009, fuel costs, excluding fair
value changes on natural gas contacts, were $67.1 million compared to $58.0
million for the same period in 2008.
    Fuel costs at the Ontario plants for the three months ended March 31,
2009 were $20.1 million compared to $17.9 million for the same period in 2008.
The increase was due to higher waste heat costs and contractual price
increases.
    Williams Lake incurred fuel costs of $2.1 million for the three months
ended March 31, 2009, compared to $0.6 million for the same period in 2008.
The increase was due primarily to the use of higher priced wood waste due to
reduced production from the plant's major suppliers. As discussed in the
Partnership's December 31, 2008 MD&A, one of the two major suppliers of wood
waste to the Partnership's Williams Lake facility shut down its mills in
January 2009 and the second major supplier has significantly reduced its
production. The Partnership has identified other sources of supply, but these
sources are more expensive. Approximately 82% of the fuel cost is expected to
be recovered under the terms of Williams Lake's PPA. However, considering the
economics of the power produced at high fuel prices relative to the value of
the electricity produced during a low electricity demand period in the region,
the Partnership and the PPA counterparty agreed to a temporary outage from
April 23, 2009 until the end of May 2009, after which the plant will complete
its annual maintenance outage. Under the terms of the Williams Lake PPA, the
Partnership will continue to receive firm energy payments while the plant is
offline. The Partnership does not expect a decline in the operating margin
from firm energy as a result of the temporary outage. The Partnership expects
that Williams Lake will be dispatched to optimize available wood waste
supplies until its major suppliers return to normal operation or are replaced
with new sources of economically viable supply. Based on the historic split
between firm and excess energy production, operating margin provided by
Williams Lake is expected to be approximately $2 million lower in 2009 versus
2008, primarily due to the impact of higher wood waste costs on excess energy
margins.
    In April 2009, several of the shut down mills restarted and production
levels have been increasing. As of the date of this MD&A, these two suppliers
were providing approximately 60% of their normal wood waste volumes, however
with no assurance that they will continue to provide wood waste at this level.
    The Northwest US plants incurred fuel costs of $3.1 million for the three
months ended March 31, 2009, consistent with $3.1 million for the same period
in 2008.
    Fuel costs at the California facilities were $14.6 million for the three
months ended March 31, 2009 compared to $21.5 million for the same period in
2008. The decrease was due to lower US dollar natural gas prices and planned
outages for inspections at Naval Station partially offset by a stronger US
dollar relative to the Canadian dollar.
    The Northeast US natural gas plants incurred fuel costs of $20.7 million
for the three months ended March 31, 2009, compared to $6.2 million for the
same period in 2008. The increase was primarily due to the acquisition of
Morris on October 31, 2008, which had fuel costs of $12.5 million in the three
months ended March 31, 2009, and a stronger US dollar relative to the Canadian
dollar.
    The North Carolina plants incurred fuel costs of $6.5 million for the
three months ended March 31, 2009, compared to $8.7 million for the same
period in 2008. The decrease was the result of lower generation partially
offset by a stronger US dollar relative to the Canadian dollar.
    The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric plants do
not have fuel costs.

    
    OPERATING AND MAINTENANCE EXPENSE                           Three months
                                                              ended March 31
    (millions of dollars)(unaudited)                          2009      2008
    -------------------------------------------------------------------------

    Ontario plants                                             3.8       3.8
    Williams Lake                                              2.0       1.9
    Mamquam and Queen Charlotte                                1.0       1.2
    Northwest US plants                                        3.7       3.1
    California plants                                          5.7       5.3
    Curtis Palmer                                              1.5       1.2
    Northeast US natural gas plants(1)                         2.9       0.7
    North Carolina plants                                      6.3       3.5
    PERC management expenses                                   0.3       0.2
    -------------------------------------------------------------------------
                                                              27.2      20.9
    -------------------------------------------------------------------------
    (1) Includes the results of Morris from the date of acquisition of
        October 31, 2008. Restated to reflect the operations of Castleton as
        discontinued operations.
    

    Operating and maintenance expenses include payments to the Manager and
third parties for the operation and routine maintenance of the plants. Fees
paid to the Manager are based on fixed charges adjusted annually for inflation
for the Canadian plants, Curtis Palmer and Manchief, and a flow through of
costs for the remaining US plants. Operating and maintenance expenses were
$27.2 million for the three months ended March 31, 2009, compared to $20.9
million for the same period in 2008. The increase was primarily due to the
acquisition of Morris in 2008, which had maintenance costs of $2.1 million in
the three months ended March 31, 2009 and higher maintenance costs at the
North Carolina plants for planned repairs undertaken during plant outages for
the enhancement projects.

    DEPRECIATION AND AMORTIZATION

    Depreciation and amortization expense for the three months ended March
31, 2009 was $23.8 million compared to $22.1 million for the same period in
2008. The increase was primarily due to the acquisition of Morris on October
31, 2008.

    MANAGEMENT AND ADMINISTRATION

    Management and administration costs, which include fees payable to EPCOR
and general and administrative costs, were $4.3 million for the three months
ended March 31, 2009 compared to $3.5 million for the same period in 2008. The
increase was due to a stronger US dollar relative to the Canadian dollar and
an arbitration award of $0.5 million received in the first quarter of 2008
partially offset by lower enhancement fees paid to EPCOR as a result of lower
enhancement profits.

    FOREIGN EXCHANGE LOSSES

    The Partnership reported net foreign exchange losses of $0.5 million for
the three months ended March 31, 2009 compared to $13.2 million for the same
period in 2008. In the fourth quarter of 2008 the Partnership re-evaluated the
functional currency of its US subsidiaries and determined it to be US dollars.
Accordingly, gains and losses on translating the Partnership's US operations
into Canadian dollars are accumulated as a component of partners' equity
commencing in the fourth quarter of 2008. The foreign exchange losses recorded
in the three months ended March 31, 2008 were primarily the result of a
weakening of the Canadian dollar of $0.035 relative to the US dollar on the
translation of US dollar-denominated debt.

    EQUITY LOSSES IN PERH

    Equity losses in Primary Energy Recycling Holdings LLC (PERH) were from
the Partnership's 17.0% common ownership interest in PERH, which is accounted
for on the equity basis. For the three months ended March 31, 2009, the
Partnership received dividends of $0.4 million ($0.5 million for the same
period in 2008) on its 14.2% preferred ownership interest and dividends of
$0.8 million ($0.8 million for the same period in 2008) from its common
interest in PERH.

    
    FINANCIAL CHARGES AND OTHER, NET                            Three months
                                                              ended March 31
    (millions of dollars)(unaudited)                          2009      2008
    -------------------------------------------------------------------------

    Interest on long-term debt                                11.1       9.3
    Interest on short-term debt                                0.2       0.1
    Dividend income from Class B preferred share
     interests in PERH                                        (0.4)     (0.5)
    Other                                                        -       0.2
    -------------------------------------------------------------------------
                                                              10.9       9.1
    -------------------------------------------------------------------------
    

    Financial charges and other expenses were $10.9 million for the three
months ended March 31, 2009 compared to $9.1 million for same period in 2008.
The increase was primarily due to the impact of a stronger US dollar relative
to the Canadian dollar on US dollar interest expenses and interest on draws
under the Partnership's revolving credit facilities to finance the acquisition
of Morris.

    INCOME TAX (RECOVERY) EXPENSE

    Income tax recovery was $11.0 million for the three months ended March
31, 2009 compared to income tax expense of $2.3 million for the same period in
2008. The change was mainly due to future income taxes on changes in temporary
differences primarily related to changes in the fair value of natural gas and
foreign exchange contracts.
    Withholding taxes on payments between US and Canadian subsidiaries,
excluding dividends, are expected to be eliminated by 2010 from the current 4%
on payments made in 2009.

    PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY

    A subsidiary of the Partnership issued preferred shares, which pay
dividends at a rate of 4.85% per annum. For the three months ended March 31,
2009, dividends of $1.5 million paid to shareholders and net income tax
expenses of $0.1 million were recorded. Part VI.1 tax is paid at a rate of 40%
of the dividends and a deduction from Part I tax is available for payment of
Part VI.1 tax. The subsidiary expects to realize the benefit of the deduction
in 2011.

    
    GAINS (LOSSES) ON DERIVATIVE INSTRUMENTS

                                                            Amounts recorded
    Three months ended March 31            Income      in income statement(1)
                                         statement   ------------------------
    (millions of dollars)(unaudited)      category            2009      2008
    -------------------------------------------------------------------------
    Foreign exchange contracts            Revenues           (16.2)    (15.3)
    Natural gas contracts             Cost of fuel           (34.1)     67.6
    -------------------------------------------------------------------------
                                                             (50.3)     52.3
    -------------------------------------------------------------------------
    (1) Excludes realized gains or losses, which are included in plant
        revenue and cost of fuel for operating cash flow.
    

    Discussion of changes in fair value amounts is included in the respective
income statement categories.

    LIQUIDITY AND CAPITAL RE

SOURCES Cash distributions Cash distributions of $0.63 per unit were declared for the first quarter of 2009, consistent with the same period in 2008. When cash provided by operating activities plus the dividend from PERH exceeds cash distributions and maintenance capital expenditures, the Partnership utilizes the difference to stabilize future quarterly cash distributions, to finance future capital expenditures and to make debt repayments. When cash provided by operating activities plus dividends from PERH are less than cash distributions and maintenance capital expenditures, the Partnership utilizes available cash balances and short-term financing to cover the shortfall. The ability of the Partnership to sustain existing distributions is subject to the Partnership finding cash accretive investments to replace expected future declines in cash flow as contracts expire and when the Partnership becomes taxable in Canada under Specified Investment Flow Through legislation. Three months ended March 31 (millions of dollars)(unaudited) 2009 2008 ------------------------------------------------------------------------- Cash distributions 34.0 34.0 Cash provided by operating activities of continuing operations 33.7 41.6 Net (loss) income from continuing operations (32.6) 53.3 Dividends from PERH 0.8 0.8 Additions to property, plant and equipment 17.0 3.4 (Shortfall) excess of cash provided by operating activities of continuing operations over cash distributions (0.3) 7.6 (Shortfall) excess of net (loss) income from continuing operations over cash distributions (66.6) 19.3 ------------------------------------------------------------------------- Cash distributions exceeded cash provided by operating activities of continuing operations by $0.3 million for the three months ended March 31, 2009. The shortfall between cash distributions and cash provided by operating activities has been funded with cash on hand. The Partnership also incurred capital expenditures of $17.0 million during the three months ended March 31, 2009, which the Partnership financed with draws under its revolving credit facilities.Cash provided by operating activities of continuing operations before changes in working capital requirements was below the Partnership's expectations due to lower water volumes at Mamquam and Queen Charlotte and lower waste heat availability. Net income is not necessarily comparable to cash distributions as net income includes items such as changes in the fair value of derivative instruments. Aside from these items, management expects that distributions will exceed net income. Accordingly, a portion of the distributions represent a return of capital. To date, and subject to ensuring adequate liquidity, the Partnership has chosen to make distributions that include a return of capital. The Partnership believes that major investments of capital to maintain or increase productive capacity are often most effectively made by obtaining new capital in the external markets at the time of the required investment and not necessarily using retained cash. To the extent there is a shortfall between the Partnership's cash provided by operating activities and cash distributions and capital expenditures, the Partnership has available to it three revolving credit facilities, each of $100.0 million. The revolving credit facilities expire in June 2010, September 2010 and October 2011. Alternatively, in the case of major investments of capital, the Partnership may obtain new capital from external markets at the time of the required investment, utilizing its $1 billion shelf prospectus which expires in August 2010. The first quarter 2009 cash distribution of $0.63 per unit will be paid on April 30, 2009 to unitholders of record on March 31, 2009. Capital expenditures Capital expenditures for the three months ended March 31, 2009 totalled $17.0 million compared with $3.4 million for the same period in 2008. Capital spending in 2009 included spending for the enhancement of the Southport and Roxboro coal plants and the upgrade of the LM5000 natural gas turbine at North Island with an LM6000 unit. Three months ended March 31 (millions of dollars)(unaudited) 2009 2008 ------------------------------------------------------------------------- Maintenance capital expenditures 4.1 2.9 North Carolina enhancement project 6.9 0.5 North Island turbine replacement project 6.0 - ------------------------------------------------------------------------- 17.0 3.4 ------------------------------------------------------------------------- In line with previous expectations, the Partnership plans to invest an additional $78 million (US$62 million) in the remaining nine months of 2009 for the enhancement of Southport and Roxboro to reduce environmental emissions and improve their economic performance. The expected total project costs are US$80 million and the projects are expected to contribute approximately $0.10 per unit of additional cash provided by operating activities after giving effect to interest costs and distributions on new units based on a hypothetical capital structure. In line with previous expectations, the Partnership plans to invest an additional $13 million (US$10 million) in the second quarter of 2009 for the upgrade of the natural gas turbine at North Island to improve plant efficiency. The expected total project cost is US$19 million and the project is expected to contribute approximately $0.03 to $0.04 per unit of additional cash provided by operating activities after giving effect to interest costs and distributions on new units based on a hypothetical capital structure. The plant is expected to be fully operational in early May 2009, in time for the start of the summer capacity season. Financing The following table summarizes the long-term debt of the Partnership. March 31 December 31 (millions of dollars)(unaudited) 2009 2008 ------------------------------------------------------------------------ Senior unsecured notes, due 2036 210.0 210.0 Senior unsecured notes (US$415.0) due 2014 to 2019 523.4 505.5 Secured term loan, due 2010 2.0 2.6 Revolving credit facilities 118.2 86.7 ------------------------------------------------------------------------ 853.6 804.8 ------------------------------------------------------------------------ The Partnership's debt to total capitalization ratio as at March 31, 2009 increased to 55% from 51% at December 31, 2008 primarily due to drawings on its revolving credit facilities, the impact of a strengthening US dollar on US dollar-denominated borrowings and declines in fair value of foreign exchange and natural gas contracts. The debt to total capitalization ratio is calculated as follows: Debt to total capitalization ratio = Debt (short-term debt + long-term debt) --------------------------------------- Debt + preferred shares + partners' equity Under the terms of its debt agreements, the Partnership must maintain a debt to capitalization ratio of not more than 65% at the end of each fiscal quarter. During the three months ended March 31, 2009, the Partnership drew $28.9 million on its revolving credit facilities to fund the North Carolina and North Island capital projects.. In addition, under the revolving credit facilities, in the event the Partnership is assigned a rating of less than BBB+ by Standard and Poors (S&P) and BBB(high) by DBRS Limited (DBRS), the Partnership also would be required to maintain a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization as defined in the credit facilities) to interest expense of not less than 2.5 to 1, measured quarterly. In April 2009, S&P lowered its outlook for the Partnership from stable to negative as are result of increasing debt levels. At the same time, S&P confirmed its BBB+ credit rating and SR-2 stability rating for the Partnership. DBRS continues to assign the Partnership a credit rating of BBB(high) and a stability rating of STA-2 (high). The BBB+ debt rating by S&P is the fourth highest rating out of 10 rating categories. The plus sign shows the relative standing within the major rating categories. DBRS' BBB(high) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The "BBB" rating is DBRS' fourth highest of 10 categories. The high classification shows the relative standing within the major rating categories. Having an investment grade credit rating impacts the Partnership's ability to re-finance existing debt as it matures and to access cost competitive capital for future growth. The stability ratings of SR-2 by S&P is the second highest rating of seven categories and indicates that the Partnership has a high level of distributable cash generation stability relative to other rated Canadian income funds. The STA-2 (high) stability rating by DBRS is the second highest of seven categories in their rating system for income fund stability. DBRS further subcategorizes each rating by the designation of "high", "middle" and "low" to indicate where an entity falls within the rating category. Financial market liquidity The exposure of the Partnership to the ongoing volatility in the Canadian and US financial markets is substantially unchanged from December 31, 2008. For further information on our outlook, refer to the Partnership's December 31, 2008 MD&A. In line with expectations, the Partnership has increased the amount drawn on its revolving credit facilities to finance the enhancement capital spending at North Island and the North Carolina plants. The Partnership has a sufficient liquidity position with revolving credit facilities of $300 million and a demand credit facility of $20 million with Canadian tier 1 banks. Principal repayments on the Partnership's long-term debt facilities are as follows: Year Principal repayment (millions of dollars) --------------------------------------------- 2009 (9 months) 0.7 2010 119.5 2014 239.7 2017 189.2 2019 94.6 2036 210.0 --------------------------------------------- The Partnership expects to borrow an additional US$72 million on the credit facilities to fund the completion of the North Island and North Carolina capital projects in 2009. Uncertainty in global financial markets and, in particular, the Canadian and US financial markets may adversely affect the Partnership's ability to arrange permanent long-term financing for the Morris acquisition, for significant capital expenditures, such as enhancement expenditures at the North Island and North Carolina facilities and potentially to refinance indebtedness under the credit facilities outstanding at their maturity dates. This could, in turn, also affect the Partnership's credit ratings. FOREIGN EXCHANGE RISK MANAGEMENT The Partnership manages the foreign exchange risk of its anticipated US dollar-denominated cash flows from its US plants through the use of forward foreign exchange contracts for periods up to seven years. As at March 31, 2009, $550.5 million (US$488.3 million) or approximately 94% of expected future cash flows were economically hedged for 2009 to 2015 at a weighted average exchange rate of $1.13 to US $1.00. TRANSACTIONS WITH RELATED PARTIES Three months ended March 31 (millions of dollars)(unaudited) 2009 2008 ------------------------------------------------------------------------- Transactions with EPCOR ----------------------- Cost of fuel - Greeley natural gas contract 0.6 - Operating and maintenance expense 13.0 11.1 Management and administration Base fee 0.3 0.3 Incentive fee 0.6 0.6 Enhancement fee - 0.2 General and administrative costs 2.0 1.3 ------------------------------------------------------------------------- 2.9 2.4 ------------------------------------------------------------------------- Transactions of discontinued operations Cost of fuel - Castleton natural gas demand charge 0.7 0.5 Operating and maintenance expense - Castleton 0.9 0.7 ------------------------------------------------------------------------- 1.6 1.2 ------------------------------------------------------------------------- Transactions with PERH ---------------------- Revenue Base management fees 0.9 0.8 ------------------------------------------------------------------------- In operating the Partnership's 21 power plants, the Partnership and EPCOR engage in a number of related party transactions which are in the normal course of business. These transactions are based on contracts and many of the fees are escalated by inflation. The table above summarizes the amounts included in the calculation of net income for the three months ended March 31, 2009 and 2008. General and administrative costs were $2.0 million for the three months ended March 31, 2009, an increase of $0.7 million from the same period in 2008 due to increased public company support costs and the impact of a stronger US dollar on US general and administrative costs. The Partnership makes quarterly cash distributions to EPCOR in the amount proportionate to its ownership interest. At March 31, 2009, EPCOR owned 30.6% of the Partnership's units (March 31, 2008 - 30.6%). CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES There were no material changes to the Partnership's purchase obligations, commitments or contingencies during the first quarter, including payments for the next five years and thereafter. For further information on these obligations, refer to the Partnership's December 31, 2008 MD&A. CRITICAL ACCOUNTING ESTIMATES Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Partnership's consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. The Partnership's critical accounting estimates include tax provision calculations as a result of the Partnership becoming taxable in 2011, depreciation and amortization expense, asset retirement obligations and fair value estimates. For further information on the Partnership's critical accounting estimates, refer to the Partnership's December 31, 2008 MD&A. INTERNAL CONTROL OVER FINANCIAL REPORTING There were no changes made to the Partnership's internal controls over financial reporting during the interim period ended March 31, 2009 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. BUSINESS RISKS The Partnership's business and operational risks remain substantially unchanged since December 31, 2008 as provided in the Partnership's December 31, 2008 MD&A. For further information on business risks, refer to the Partnership's December 31, 2008 MD&A. FUTURE ACCOUNTING STANDARDS International financial reporting standards In February 2008, the CICA confirmed that Canadian reporting issuers will be required to report under IFRS effective January 1, 2011, including comparative figures for the prior year. The Partnership's plan for conversion to and implementation of these international standards has not changed substantially since December 31, 2008. For further information on our plan for conversion and implementation, refer to the Partnership's December 31, 2008 MD&A. 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 Auditing Standard 27 - Consolidated and Separate Financial Statements. Sections 1601 and 1602 will apply to the Partnership'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 IFRS 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 IFRS 3 - Business Combinations. The section will apply on a prospective basis to the Partnership's future 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 the Partnership's IFRS project. OUTLOOK The Partnership's longer term outlook, including expectations regarding the impact on the Partnership from the economic downturn remains substantially unchanged since December 31, 2008 as provided in the Partnership's December 31, 2008 MD&A. For further information on our outlook, refer to the Partnership's December 31, 2008 MD&A. The Partnership continues to expect that annual 2009 cash provided by operating activities before working capital changes plus PERH dividends will be in line with 2008. The temporary outage at Williams Lake (see "Cost of Fuel") was anticipated in determining expectations for 2009. While results for the first quarter of 2009 were slightly behind expectations due to lower water volumes at Mamquam and Queen Charlotte and lower waste heat availability, the Partnership expects water volumes and waste heat availability will be in line with previous expectations for the remainder of 2009. SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA (unaudited) (millions of dollars except 2009 2008 per unit amounts) First Fourth Third Second First ------------------------------------------------------------------------- Revenues 127.6 103.8 133.5 143.9 118.1 Operating margin(1) (0.8) (32.1) (118.4) 155.1 106.8 Net (loss) income from continuing operations (32.6) (73.3) (152.2) 105.1 53.3 Net (loss) income (33.3) (73.1) (153.0) 104.9 53.4 Cash provided by operating activities of continuing operations 33.7 56.5 20.0 39.4 41.6 Capital expenditures 17.0 21.5 5.1 10.0 3.4 Cash distributions 34.0 33.9 34.0 33.9 34.0 Per unit statistics Net (loss) income from continuing operations $ (0.60) $ (1.36) $ (2.82) $ 1.95 $ 0.99 Cash provided by operating activities of continuing operations(1) $ 0.63 $ 1.05 $ 0.37 $ 0.73 $ 0.77 Cash distributions $ 0.63 $ 0.63 $ 0.63 $ 0.63 $ 0.63 ------------------------------------------------------------------------- (unaudited) (millions of dollars except 2007 per unit amounts) Fourth Third Second ------------------------------------------------------- Revenues 114.1 144.9 154.3 Operating margin(1) 81.5 18.7 14.3 Net (loss) income from continuing operations 45.3 (15.9) (67.9) Net (loss) income 45.3 (15.9) (68.0) Cash provided by operating activities of continuing operations 35.7 22.8 7.5 Capital expenditures 4.1 2.6 4.2 Cash distributions 34.0 33.9 34.0 Per unit statistics Net (loss) income from continuing operations $ 0.84 $ (0.29) $ (1.33) Cash provided by operating activities of continuing operations(1) $ 0.66 $ 0.42 $ 0.15 Cash distributions $ 0.63 $ 0.63 $ 0.63 ------------------------------------------------------- (1) The selected quarterly consolidated financial data has been prepared in accordance with GAAP except for operating margin and cash provided by operating activities of continuing operations per unit. See Non- GAAP Measures. Factors impacting quarterly financial results The Partnership's Selected Quarterly Financial Data, which has been prepared in accordance with GAAP, except as noted, is set out above. Quarterly revenues, net income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in US dollar exchange rates relative to the Canadian dollar, attainment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly net income is also affected by unrealized foreign exchange gains and losses primarily on the Partnership's US dollar-denominated long-term debt prior to the fourth quarter of 2008 and fair value changes in foreign exchange contracts and natural gas supply contracts. The Partnership's cash flow tends to be relatively stable over the year with seasonal fluctuations at the individual facilities. The Naval facilities earn approximately 75% of their capacity revenue during the summer peak demand months and all the California plants can earn performance bonuses during these months. Under the power sales contracts for the Ontario plants, the Partnership receives higher per megawatt hour prices in the winter months (October to March) and lower prices in the summer months (April to September). The lower summer prices reduce the threshold for economic curtailments thereby increasing the profitability of enhancements, natural gas prices being equal. Contributions from Williams Lake are usually lower in the fourth quarter once the annual firm energy requirements are fulfilled and the plant is only producing lower-priced excess energy. Revenues from the hydroelectric facilities are generally higher in the spring months due to seasonally higher water flows. Significant items which impacted the last eight quarters' net income were as follows: In the fourth quarter of 2008, the Partnership acquired Morris. In the fourth quarter of 2008, the Partnership recorded a $24.1 million asset impairment charge on its investment in the common shares of PERH. In the third quarter of 2007, the Partnership recorded a $13.0 million asset impairment charge in respect of certain management contracts. In the second quarter of 2007, a future income tax expense of $75.5 million was recognized due to a change in tax law which will result in the Partnership's Canadian operations becoming taxable in 2011. In the second quarter of 2007, the Partnership reached a settlement with one of its natural gas suppliers and recorded additional fuel costs of $2.8 million for consumption in the first two quarters of 2007. At the same time, the Partnership reversed previously recorded charges of $3.1 million related to periods ending before December 31, 2006. Settlement with the second natural gas supplier was reached in the first quarter of 2008 on terms anticipated in the second quarter of 2007. In the third quarter of 2008 the Partnership recorded a $3.4 million reduction in natural gas costs based on our updated estimate of the cost for natural gas supplied under contract. Unrealized foreign exchange gains on US dollar-denominated debt were recorded in the second, third and fourth quarters of 2007 and the second quarter of 2008. Losses were recorded in the first and third quarters of 2008. The gains and losses are due to fluctuations in the US dollar relative to the Canadian dollar. The Partnership recorded gains on the change in the fair value of the natural gas supply contracts in the fourth quarter of 2007 and the first and second quarters of 2008 and losses in the second and third quarters of 2007, the third and fourth quarters of 2008 and the first quarter of 2009. Unrealized fair value changes on foreign exchange contracts resulted in gains in the second and third quarters of 2007 and the second quarter of 2008. Losses were recorded in the fourth quarter of 2007, in the first, third and fourth quarters of 2008 and in the first quarter of 2009. The first quarter of 2008 had unseasonably high water flows at Curtis Palmer, while the fourth quarter of 2007 had unseasonably low water flows. FORWARD-LOOKING Information Certain information in this MD&A is forward-looking and related to anticipated financial performance, events and strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target" and "expect" or similar words suggest future outcomes. By their nature, such statements are subject to significant risks, assumptions and uncertainties, which could cause the Partnership's actual results and experience to be materially different than the anticipated results. In particular, forward-looking information and statements include ((i) planned capital upgrades at Southport and Roxboro of US$80 million which are expected to result in a contribution of $0.10 per unit, (ii) planned upgrades at North Island of US$19 million which are expected to result in a contribution of $0.03 to $0.04 per unit, (iii) expectations regarding renewal of the Partnership's credit facilities, (iv) expectations regarding the Partnership's cash provided by operating activities, including relative to cash distributions (after accounting for dividends received from PERH), capital expenditures generally and working capital in 2009, and (v) expectations regarding the financing of the Partnership's capital expenditures. These statements are based on certain assumptions and analyses made by the Partnership 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 used to develop these forward-looking statements include: (i) the Partnership's operations, financial position and available credit facilities, (ii) the Partnership's assessment of commodity, currency and power markets, (iii) the markets and regulatory environment in which the Partnership's facilities operate, (iv) the state of capital markets, (v) management's analysis of applicable tax legislation, (vi) the assumption that the currently applicable and proposed tax laws will not change and will be implemented, (vii) the assumption that counterparties to fuel supply and power purchase agreements will continue to perform their obligations under the agreements taking account of the matters described herein, (viii) the level of plant availability and dispatch, (ix) the performance of contractors and suppliers, (*) the renewal and terms of PPAs, (xi) the ability of the Partnership to successfully integrate and realize the benefits of its acquisitions, (xii) the ability of the Partnership to implement its strategic initiatives and whether such initiatives will yield the expected benefits, and (xiii) expected water flows. Whether actual results, performance or achievements will conform to the Partnership's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from the Partnership's expectations. Such risks and uncertainties include, but are not limited to risks relating to (i) the operation of the Partnership's facilities, (ii) plant availability and performance, (iii) the availability and price of energy commodities including natural gas and wood waste, (iv) the performance of counterparties in meeting their obligations under PPAs, (v) competitive factors in the power industry, (vi) economic conditions, including in the markets served by the Partnership's facilities, (vii) ongoing compliance by the Partnership with its current debt covenants, (viii) developments within the North American capital markets, (ix) the availability and cost of permanent long term financing in respect of acquisitions and investments, (*) unanticipated maintenance and other expenditures, (xi) the Partnership's ability to successfully realize the benefits of acquisitions and investments, (xii) changes in regulatory and government decisions including changes to emission regulations, (xiii) waste heat availability and water flows, (xiv) changes in existing and proposed tax and other legislation in Canada and the US and including changes in the Canada-US tax treaty, (xv) the tax attributes of and implications of any acquisitions, and (xvi) the availability and cost of equipment. 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. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. Except as required by law, the Partnership disclaims any intention and assumes no obligation to update any forward-looking statement. QUARTERLY UNIT TRADING INFORMATION The Partnership units trade on the Toronto Stock Exchange under the symbol EP.UN. For the three months ended Mar. 31 Dec. 31 Sep. 30 Jun. 30 Mar. 31 (unaudited) 2009 2008 2008 2008 2008 ------------------------------------------------------------------------- Unit price High $18.98 $20.65 $23.50 $24.70 $23.78 Low $12.90 $15.50 $19.83 $21.52 $19.65 Close $13.80 $17.72 $20.32 $22.41 $21.90 Volume traded (millions) 3.3 5.1 3.6 4.5 4.8 ------------------------------------------------------------------------- As at April 27, 2009, the Partnership had 53.9 million units outstanding. The weighted average number of units outstanding for the three months ended March 31, 2009 was 53.9 million. ADDITIONAL INFORMATION Additional information relating to EPCOR Power L.P. including the Partnership's Annual Information Form and continuous disclosure documents are available on SEDAR at www.sedar.com. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF INCOME AND LOSS Three months ended March 31 (unaudited) 2009 2008 ----------------------------------------------------- --------- --------- (In millions of dollars except units and per unit amounts) Revenues $ 127.6 $ 118.1 Cost of fuel 101.2 (9.6) Operating and maintenance expense 27.2 20.9 --------- --------- (0.8) 106.8 Other costs Depreciation and amortization 23.8 22.1 Management and administration 4.3 3.5 Foreign exchange losses 0.5 13.2 Equity losses in PERH 1.7 1.7 Financial charges and other, net (Note 4) 10.9 9.1 --------- --------- 41.2 49.6 --------- --------- Net (loss) income from continuing operations before income tax and preferred share dividends (42.0) 57.2 Income tax (recovery) expense (11.0) 2.3 --------- --------- Net (loss) income from continuing operations before preferred share dividends (31.0) 54.9 Preferred share dividends of a subsidiary company 1.6 1.6 --------- --------- Net (loss) income from continuing operations (32.6) 53.3 (Loss) income from discontinued operations, net of income tax (Note 3) (0.7) 0.1 --------- --------- Net (loss) income $ (33.3) $ 53.4 --------- --------- --------- --------- Net (loss) income per unit from continuing operations $ (0.60) $ 0.99 Net loss per unit from discontinued operations (0.01) 0.00 Net (loss) income per unit $ (0.62) $ 0.99 --------- --------- --------- --------- Weighted average units outstanding (millions) 53.9 53.9 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF CASH FLOW Three months ended March 31 (unaudited) 2009 2008 ----------------------------------------------------- --------- --------- (In millions of dollars) Operating activities Net (loss) income from continuing operations $ (32.6) $ 53.3 Items not affecting cash: Depreciation and amortization 23.8 22.1 Future income taxes (11.9) 1.0 Fair value changes on derivative instruments 50.3 (52.3) Unrealized foreign exchange losses (0.1) 13.2 Other 2.4 1.5 --------- --------- 31.9 38.8 Change in non-cash operating working capital 1.8 2.8 --------- --------- Cash provided by operating activities of continuing operations 33.7 41.6 Cash (used in) provided by operating activities of discontinued operations (1.3) 1.3 --------- --------- Cash provided by operating activities 32.4 42.9 --------- --------- Investing activities Additions to property, plant and equipment (17.0) (3.4) Change in non-cash working capital (3.8) (0.5) Dividends from PERH 0.8 0.8 --------- --------- Cash used in investing activities of continuing operations (20.0) (3.1) Cash used in investing activities of discontinued operations (0.1) - --------- --------- Cash used in investing activities (20.1) (3.1) --------- --------- Financing activities Distributions paid (33.9) (33.9) Proceeds from long-term debt issued 28.9 - Long-term debt repaid (0.6) (0.5) --------- --------- Cash used in financing activities (5.6) (34.4) --------- --------- Foreign exchange gain on cash held in a foreign currency - 0.5 Increase in cash and cash equivalents 6.7 5.9 Cash and cash equivalents, beginning of period 3.0 20.1 --------- --------- Cash and cash equivalents, end of period $ 9.7 $ 26.0 --------- --------- --------- --------- Supplementary cash flow information Income taxes paid net of income taxes recovered $ 0.3 $ 3.0 Interest paid net of interest received $ 15.3 $ 12.5 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED BALANCE SHEETS March 31, December (unaudited) 2009 31, 2008 ----------------------------------------------------- --------- --------- (In millions of dollars) ASSETS Current assets Cash and cash equivalents $ 9.7 $ 3.0 Accounts receivable 49.8 60.6 Inventories 22.2 23.2 Prepaids and other 3.3 5.0 Derivative instruments assets (Note 5) 6.2 22.8 Future income taxes 2.3 2.3 Current assets of discontinued operations (Note 3) 2.0 2.3 --------- --------- 95.5 119.2 Property, plant and equipment 1,128.4 1,106.0 Power purchase arrangements 412.0 408.6 Long-term investments 17.4 19.2 Goodwill 57.1 55.1 Derivative instruments assets (Note 5) 11.0 27.1 Future income taxes 22.0 16.8 Other assets 47.2 45.2 Long-term assets of discontinued operations (Note 3) 12.3 12.0 --------- --------- $1,802.9 $1,809.2 --------- --------- --------- --------- LIABILITIES AND PARTNERS' EQUITY Current liabilities Accounts payable $ 55.0 $ 70.3 Distributions payable 34.0 33.9 Long-term debt due within one year 1.3 1.3 Derivative instruments liabilities (Note 5) 21.1 13.0 Current liabilities of discontinued operations (Note 3) 0.7 1.2 --------- --------- 112.1 119.7 Asset retirement obligations 29.4 28.6 Long-term debt 847.3 798.5 Derivative instruments liabilities (Note 5) 43.6 38.5 Contract liabilities 4.2 4.7 Future income taxes 54.2 60.7 Long-term liabilities of discontinued operations (Note 3) 4.5 4.2 Preferred shares issued by a subsidiary company 122.0 122.0 Partners' equity 585.6 632.3 --------- --------- $1,802.9 $1,809.2 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Three months ended March 31 (unaudited) 2009 2008 ----------------------------------------------------- --------- --------- (In millions of dollars) Partnership capital Balance, beginning of period $1,197.1 $1,197.1 Issue of partnership units - - --------- --------- Balance, end of period $1,197.1 $1,197.1 --------- --------- --------- --------- Deficit Balance, beginning of period: As previously reported $ (500.1) $ (296.5) Adjustment for changes in accounting policies (Note 2) 3.9 - --------- --------- As restated (496.2) (296.5) Net (loss) income (33.3) 53.4 Cash distributions (34.0) (34.0) --------- --------- Balance, end of period $ (563.5) $ (277.1) --------- --------- Accumulated other comprehensive (loss) income Balance, beginning of period $ (64.7) $ 5.1 Other comprehensive income (loss) 16.7 (0.9) --------- --------- Balance, end of period $ (48.0) $ 4.2 --------- --------- Total of deficit and accumulated other comprehensive --------- --------- (loss) income $ (611.5) $ (272.9) --------- --------- --------- --------- Partners' equity $ 585.6 $ 924.2 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND LOSS Three months ended March 31 (unaudited) 2009 2008 ----------------------------------------------------- --------- --------- (In millions of dollars) Net (loss) income $ (33.3) $ 53.4 Other comprehensive loss, net of income taxes Gains on translating net assets of self-sustaining foreign operations(1) 17.1 - Amortization of deferred gains on derivatives de-designated as cash flow hedges to income(1) (0.4) (0.9) --------- --------- Other comprehensive income (loss) 16.7 (0.9) Comprehensive (loss) income $ (16.6) $ 52.5 --------- --------- --------- --------- (1) Net of income tax of nil. See accompanying notes to the consolidated financial statements. Note 1. Significant accounting policies The consolidated financial statements of EPCOR Power L.P. (the Partnership) have been prepared by the management of the General Partner in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in the Partnership's annual financial statements for the year ended December 31, 2008, except for the changes described in Note 2. These consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These consolidated financial statements for the three months ended March 31, 2009 do not include all disclosures required in the annual financial statements and should be read in conjunction with the annual financial statements included in the Partnership's 2008 Annual Report. Quarterly revenues, net income and cash provided by operating activities are affected by seasonal contract pricing, seasonal weather conditions, fluctuations in United States (US) dollar exchange rates, fulfillment of firm energy requirements, natural gas prices, waste heat availability and planned and unplanned plant outages, as well as items outside of the normal course of operations. Quarterly net income is also affected by unrealized foreign exchange gains and losses and fair value changes in derivative instruments. Revenues, net income and cash provided by operating activities from the Partnership's Ontario plants are generally higher in the winter months (October to March) and lower in the summer months (April to September) due to seasonal pricing under the power purchase arrangements (PPAs). Revenues and net income from the Partnership's hydroelectric plants are generally higher in the spring months due to seasonally higher water flows. The California plants normally generate the majority of their operating margin during the summer months when the plants can earn performance bonuses. Additionally, the plants located on Naval bases earn approximately 75% of their capacity revenue during these months. Since a determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions which have been made with careful judgment. In the opinion of management of the Partnership's General Partner, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Partnership's accounting policies. Note 2. Changes in accounting policies Credit risk and the fair value of financial assets and financial liabilities On January 20, 2009 the Emerging Issues Committee of the Canadian Institute of Chartered Accountants (CICA) issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities, which clarifies that an entity's own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. Effective January 1, 2009, the Partnership adopted the recommendations of EIC-173 and applied the recommendations retrospectively without restatement of prior periods. On January 1, 2009, the Partnership made the following adjustments to the balance sheet to adopt the recommendations of EIC-173: Balance sheet item (millions Increase of dollars) (decrease) Explanation ------------------------------------------- ---------------------------- Derivative instruments assets (1.5) Impact to fair value of foreign exchange and natural gas contracts from Derivative instruments liabilities (6.3) incorporating credit risk of counterparties of the Partnership. Future income taxes liabilities 0.9 Tax impact from adoption of - non-current new standard. Opening deficit After tax impact to opening deficit resulting from (3.9) adoption of new standard. ----------- ---------------------------- Goodwill and intangible assets In February 2008, the CICA issued Handbook Section 3064 - Goodwill and Intangible Assets and consequential amendments to Section 1000 - Financial Statement Concepts. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The provisions relating to the definition and initial recognition of intangible assets, including internally generated intangible assets, are equivalent to the corresponding provisions of International Financial Reporting Standards (IFRS). The Partnership adopted these amendments January 1, 2009 which did not result in a material transition adjustment to the financial statements. The new accounting standard has been applied prospectively and the comparative financial statements have not been restated. Future accounting changes International financial reporting standards In 2005, the CICA announced plans to converge Canadian GAAP with IFRS over a transition period from 2006 to 2011. The CICA indicated that Canadian entities will be required to begin reporting under IFRS effective the first quarter of 2011 including comparative figures. A high level IFRS implementation plan has been developed and an assessment of the financial statement impact of the accounting standard differences is currently in progress. Based on the analysis to date, the most significant differences for the Partnership are anticipated to be related to property, plant and equipment, leases, joint arrangements, financial instruments and hedges, income taxes, impairments, business combinations, emission credits, asset retirement obligations and financial statement disclosure. The Partnership also expects to make changes to certain processes and systems before 2010, in time to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes at the required implementation date. 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 IFRS IAS 27 - Consolidated and Separate Financial Statements. Sections 1601 and 1602 will apply to the Partnership'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 the Partnership's IFRS 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 IFRS 3 - Business Combinations. The section will apply on a prospective basis to the Partnership's future 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 the Partnership's IFRS project. Note 3. Discontinued operations On December 4, 2008 the Partnership signed a definitive agreement to sell its Castleton facility (Castleton), located in the state of New York for approximately US$10 million, subject to closing adjustments. The sale is expected to close in the second quarter of 2009, subject to certain regulatory approvals. The Partnership will not have any continuing involvement in the facility after the disposal transaction. Accordingly, the results of operations, cash flows and financial position of Castleton have been segregated and presented as discontinued operations. For the three months ended March 31, 2009 and 2008, revenues and expenses of Castleton were as follows: Three months ended March 31 (millions of dollars) 2009 2008 ------------------------------------------------------------- ----------- Revenues $ 1.5 $ 3.3 Expenses Cost of fuel 1.5 0.4 Operating and maintenance expense 1.3 1.1 Depreciation and amortization - 1.6 Foreign exchange gains - (0.2) ----------- ----------- (Loss) income from discontinued operations before income tax (1.3) 0.4 Income tax (recovery) expense (0.6) 0.3 ----------- ----------- (Loss) income from discontinued operations, net of income tax $ (0.7) $ 0.1 ----------- ----------- ----------- ----------- The carrying amounts of the assets and liabilities of the discontinued operations at March 31, 2009 and December 31, 2008 were as follows: March 31, December (millions of dollars) 2009 31, 2008 ------------------------------------------------------------- ----------- Assets of the discontinued operations Accounts receivable $ 0.3 $ 0.7 Inventories 1.1 1.0 Prepaids and other 0.6 0.6 ----------- ----------- Current assets of the discontinued operations 2.0 2.3 Property, plant and equipment 11.4 11.2 Future income taxes 0.9 0.8 ----------- ----------- Long-term assets of the discontinued operations 12.3 12.0 ----------- ----------- Total assets of the discontinued operations $ 14.3 $ 14.3 ----------- ----------- ----------- ----------- Liabilities of the discontinued operations Accounts payable $ 0.7 $ 1.2 Asset retirement obligations 2.3 2.1 Future income taxes 2.2 2.1 ----------- ----------- Long-term liabilities of the discontinued operations 4.5 4.2 ----------- ----------- Total liabilities of the discontinued operations $ 5.2 $ 5.4 ----------- ----------- ----------- ----------- Note 4. Financial charges and other, net Three months ended March 31 (millions of dollars) 2009 2008 ------------------------------------------------------------- ----------- Interest on long-term debt $ 11.1 $ 9.3 Interest on short-term debt 0.2 0.1 Dividend income from Class B preferred share interests in PERH (0.4) (0.5) Other - 0.2 ----------- ----------- $ 10.9 $ 9.1 ----------- ----------- ----------- ----------- Note 5. Financial instruments Derivative instruments Derivative instruments are held for the purpose of energy procurement or treasury management. All derivative instruments, including embedded derivatives, are classified as held for trading and are recorded at fair value on the balance sheet as derivative instruments assets and derivative instruments liabilities unless exempted from derivative treatment as a normal purchase, sale or usage. All changes in their fair value are recorded in net income. The derivative instruments assets and liabilities used for risk management purposes consist of the following: (millions of dollars) March 31, 2009 ------------------------------------------------------------------------- Foreign Natural gas exchange non-hedges non-hedges Total ------------------------------------ Derivative instruments assets: Current $ - $ 6.2 $ 6.2 Non-current 9.7 1.3 11.0 Derivative instruments liabilities: Current (7.6) (13.5) (21.1) Non-current (0.5) (43.1) (43.6) ------------------------------------ $ 1.6 $ (49.1) $ (47.5) ------------------------------------ ------------------------------------ Net notional amounts: Gigajoules (GJs)(millions) 66 US foreign exchange (US dollars in millions) 488.3 Contract terms (years) 2 to 8 1 to 7 ------------------------------------ (millions of dollars) December 31, 2008 ------------------------------------------------------------------------- Foreign Natural gas exchange non-hedges non-hedges Total ------------------------------------ Derivative instruments assets: Current $ 15.5 $ 7.3 $ 22.8 Non-current 23.5 3.6 27.1 Derivative instruments liabilities: Current (1.5) (11.5) (13.0) Non-current (0.6) (37.9) (38.5) ------------------------------------ $ 36.9 $ (38.5) $ (1.6) ------------------------------------ ------------------------------------ Net notional amounts: Gigajoules (GJs)(millions) 69 US foreign exchange (US dollars in millions) 456.9 Contract terms (years) 1 to 8 1 to 6 ------------------------------------ The fair value of derivative instruments are determined, where possible, using exchange or over-the-counter price quotations by reference to quoted bid, ask, or closing market prices, as appropriate in active markets. Where there are limited observable prices due to illiquid or inactive markets, the Partnership uses appropriate valuation and price modeling commonly used by market participants to estimate fair value. Fair value determined using valuation models requires the use of assumptions concerning the amount and timing of future cash flows. In general, fair value amounts reflect management's best estimates using external readily observable market data such as future prices, interest rate yield curves, foreign exchange rates, quoted Canadian dollar swap rates as the discount rates for time value, and volatility for all of the Partnership's financial instruments. It is possible that the assumption used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. With respect to natural gas the Partnership has determined the market is active to the end of the contract terms, a change from its previous assessment that the market was active within five years. In changing its assessment the Partnership considered market activity and the short period of time that the contracts extend beyond five years. Unrealized and realized pre-tax gains and (losses) on derivative instruments recognized in net income were: Three months ended Income statement March 31 (millions of dollars) category 2009 2008 --------------------------------------------------------------- --------- Foreign exchange non-hedges Revenue $ (19.9) $ (11.2) Natural gas non-hedges Cost of fuel (34.1) 67.6 Foreign exchange non-hedges Foreign exchange losses (0.6) - --------------------------------- --------- Note 6. Segment disclosures The Partnership operates in one reportable business segment involved in the operation of electrical generation plants within British Columbia, Ontario, and in the US in California, Colorado, Illinois, New Jersey, New York, North Carolina and Washington. Geographic information (millions of Three months ended Three months ended dollars) March 31, 2009 March 31, 2008 ------------------------------------------- ----------------------------- Canada US Total Canada US Total ------------------------------------------- ----------------------------- Revenue $ 37.2 $ 90.4 $ 127.6 $ 45.3 $ 72.8 $ 118.1 ----------------------------- ----------------------------- ----------------------------- ----------------------------- (millions of dollars) As at March 31, 2009 As at December 31, 2008 ------------------------------------------- ----------------------------- Canada US Total Canada US Total ------------------------------------------- ----------------------------- Assets PP&E $ 551.5 $ 576.9 $1,128.4 $ 559.3 $ 546.7 $1,106.0 PPAs 38.9 373.1 412.0 39.7 368.9 408.6 Other assets - 47.2 47.2 - 45.2 45.2 Goodwill - 57.1 57.1 - 55.1 55.1 ----------------------------- ----------------------------- Total assets $ 590.4 $1,054.3 $1,644.7 $ 599.0 $1,015.9 $1,614.9 ----------------------------- ----------------------------- ----------------------------- ----------------------------- Note 7. Comparative figures Certain comparative figures have been reclassified to conform to the current year's presentation.

For further information:

For further information: on the Partnership visit www.epcorpowerlp.ca or
contact: Media Inquiries: Tim le Riche, (780) 969-8238; Unitholder & Analyst
Inquiries: Randy Mah, (780) 412-4297, Toll Free(866) 896-4636

Organization Profile

EPCOR POWER L.P.

More on this organization


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890