EPCOR Power L.P. reports second quarter results



    EDMONTON, July 29 /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 June 30, 2008.
    "Results for the second quarter continued to be in-line with our overall
expectations," said Brian Vaasjo, President, EPCOR Power Services Ltd. "The
Partnership's Ontario plants experienced a decline in waste heat availability
but were able in the period to offset the loss in revenue by capitalizing on
curtailment opportunities brought on by high market prices for natural gas. A
number of scheduled planned outages involving major overhauls at the Williams
Lake, Castleton and Manchief facilities were successfully executed in the
quarter, maintaining the reliability of the fleet. The Partnership also
completed a three-year extension to the energy services agreement for the
Kenilworth facility. These initiatives align with the Partnership's goal of
providing unitholders with long-term stability and sustainable cash
distributions."

    
    Highlights of EPCOR Power L.P.'s operational and financial performance
included:

    -------------------------------------------------------------------------
    Operational and
    Financial Highlights                  Three months            Six months
    (unaudited)                          ended June 30         ended June 30
    -------------------------------------------------------------------------
    (millions of dollars except per
     unit and operational amounts)     2008       2007       2008       2007
    -------------------------------------------------------------------------
    Power generated (GWh)             1,069      1,224      2,363      2,453
    -------------------------------------------------------------------------
    Weighted average plant
     availability                       83%        92%        90%        92%
    -------------------------------------------------------------------------
    Revenue                           147.3      165.3      268.7      308.2
    -------------------------------------------------------------------------
    Net income(loss)                  104.9      (68.0)     158.3        1.5
    -------------------------------------------------------------------------
      Per unit                      $  1.95    $ (1.33)   $  2.94    $  0.03
    -------------------------------------------------------------------------
    Comprehensive income (loss)       103.9      (68.9)     156.4       (0.3)
    -------------------------------------------------------------------------
    Cash provided by operating
     activities                        40.4        7.8       83.3       68.5
    -------------------------------------------------------------------------
      Per unit(1)                   $  0.75    $  0.15    $  1.55    $  1.35
    -------------------------------------------------------------------------
    Cash distributions                 33.9       34.0       67.9       65.4
    -------------------------------------------------------------------------
      Per unit                      $  0.63    $  0.63    $  1.26    $  1.26
    -------------------------------------------------------------------------
    Capital expenditures               11.7        4.2       15.5        5.3
    -------------------------------------------------------------------------
    Weighted average units
     outstanding (millions)            53.9       51.2       53.9       50.6
    -------------------------------------------------------------------------

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

    The June 30, 2008 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 Six Months Ended June 30, 2008
    -------------------------------------------------------------------------

    This management's discussion and analysis (MD&A), dated July 29, 2008,
should be read in conjunction with the unaudited interim consolidated
financial statements of EPCOR Power L.P. (the Partnership) for the six months
ended June 30, 2008 and the audited consolidated financial statements and MD&A
of the Partnership for the year ended December 31, 2007. Additional
information relating to the Partnership, including the 2007 Annual Information
Form (AIF) and continuous disclosure documents are available on SEDAR at
www.sedar.com.
    EPCOR Power Services Ltd., the General Partner of the Partnership, a
wholly-owned subsidiary of EPCOR Utilities Inc. (collectively with its
subsidiaries, EPCOR), is responsible for management of the Partnership. The
Board of Directors of the General Partner declares the cash distributions to
the Partnership's unitholders. The General Partner has engaged certain other
EPCOR subsidiaries (collectively, 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 of Directors of the General Partner 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.

    FORWARD-LOOKING STATEMENTS

    Certain information in this MD&A is forward-looking and related to
anticipated financial performance, events and strategies. When used in this
context, words such as "will", "anticipate", "believe", "plan", "intend",
"target" and "expect" or similar words suggest future outcomes. By their
nature, such statements are subject to significant risks, assumptions and
uncertainties, which could cause the Partnership's actual results and
experience to be materially different than the anticipated results. Such
risks, assumptions and uncertainties include, but are not limited to, the
ability of the Partnership to successfully integrate and realize the financial
benefits of its acquisitions, the ability of the Partnership to implement its
strategic initiatives and whether such strategic initiatives will yield the
expected benefits, the availability and price of energy commodities, plant
availability, waste heat availability and water flows, regulatory and
government decisions, the renewal and terms of power purchase contracts
(PPAs), competitive factors in the power industry, the current and future
economic conditions in North America and the performance of contractors and
suppliers.
    Readers are cautioned not to place undue reliance on forward-looking
statements as actual results could differ materially from the plans,
expectations, estimates or intentions expressed in the forward-looking
statements. Except as required by law, the Partnership disclaims any intention
and assumes no obligation to update any forward-looking statement even if new
information becomes available, as a result of future events or for any other
reason.

    
    CONSOLIDATED RESULTS OF OPERATIONS

    -------------------------------------------------------------------------
                                                            Three        Six
    (millions of dollars) (unaudited)                      months     months
    -------------------------------------------------------------------------
    Cash provided by operating activities for the three
     and six months ended June 30, 2007                       7.8       68.5
    -------------------------------------------------------------------------
    Changes in operating working capital                     22.9       10.6
    Net realized losses on foreign exchange
     and interest rate contracts in 2007                     15.4        9.8
    Lower interest expenses                                   3.4        8.0
    Mamquam maintenance outage in 2007                        2.3        2.4
    Williams Lake major overhaul and higher
     maintenance costs in 2008                               (3.2)      (3.2)
    Lower operating margin at the Ontario plants             (2.5)      (5.9)
    Mamquam and Queen Charlotte arbitration award            (2.3)      (1.8)
    Lower revenue due to lower water
     volumes at hydro facilities                             (1.3)      (2.7)
    Preferred share dividends                                (1.1)      (2.7)
    Other                                                    (1.0)       0.3
    -------------------------------------------------------------------------
    Cash provided by operating activities for the three
     and six months ended June 30, 2008                      40.4       83.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Partnership reported cash provided by operating activities of
$40.4 million or $0.75 per unit for the quarter ended June 30, 2008 compared
to $7.8 million or $0.15 per unit for the same period in 2007. Cash provided
by operating activities per unit is defined below under non-GAAP measures. The
$32.6 million increase in cash provided by operating activities compared to
the second quarter of 2007 is primarily due to the following:

    -   A $9.2 million decrease in working capital in the second quarter of
        2008 compared to a $13.7 million increase in same period in 2007. The
        three months ended June 30, 2008 include the receipt of four months
        of sales from the Ontario Electricity Financial Corporation compared
        to the receipt of three months of sales in the same period of 2007;
    -   In the second quarter of 2007, net losses of $15.4 million were
        realized on foreign exchange and interest rate contracts that were
        entered into in anticipation of permanent financing of acquisitions
        completed in 2006;
    -   Lower interest expenses of $3.4 million primarily due to the pay down
        of debt with the proceeds from the issue of Partnership units and
        preferred shares in the second quarter of 2007 and the replacement of
        capital lease obligations with lower cost long-term debt in the third
        quarter of 2007; and
    -   A maintenance outage at the Mamquam facility to effect tunnel repairs
        in the second quarter of 2007 resulted in higher maintenance costs of
        approximately $2.3 million compared to the same period in 2008.

    Increases were partially offset by:

    -   A planned outage to complete a major overhaul and higher major
        maintenance costs at Williams Lake during the annual maintenance
        outage in the second quarter of 2008 resulted in a decline in
        operating margin of $3.2 million;
    -   Operating margin at the Ontario plants was $2.5 million lower
        compared to the prior year's quarter due to higher fuel costs, lower
        waste heat availability and lower generation and revenue at Calstock,
        partially offset by higher enhancement sales as the result of
        relatively high natural gas prices. Fuel costs at the Ontario plants
        were higher due to (i) the settlement of natural gas supply contract
        disputes at Tunis in July 2007 and January 2008; (ii) a 19% increase
        in the natural gas prices in 2008 at Kapuskasing and North Bay under
        the 20 year supply agreements; (iii) an increase in waste heat
        optimization costs due to lower throughput on TransCanada
        Corporation's (TransCanada) Canadian Mainline, and (iv) greater use
        of natural gas to meet Calstock's minimum generation requirements due
        to high moisture levels in the waste wood inventory which caused
        Calstock to scale back production in the first two quarters of 2008
        to optimize available waste wood;
    -   Arbitration awards against the previous owners of Mamquam and Queen
        Charlotte in respect of claims by the Partnership in the purchase and
        sale agreement of $2.3 million in the second quarter of 2007;
    -   Revenue at Queen Charlotte, Mamquam and Curtis Palmer was lower for
        the three months ended June 30, 2008 compared to the same period in
        the prior year due to lower water volumes. Water volumes at Curtis
        Palmer were above historic levels in the second quarter of 2008 but
        were lower than in the second quarter of 2007. Water volumes at
        Mamquam and Queen Charlotte were below historic levels due to a
        colder than normal spring; and
    -   Dividends on preferred shares issued in May 2007 by a subsidiary
        company of the Partnership were $0.6 million in the second quarter of
        2007 compared to $1.7 million for the same period in 2008.
    

    The Partnership reported cash provided by operating activities of  $83.3
million or $1.55 per unit for the six months ended June 30, 2008 compared with
$68.5 million or $1.35 per unit for the same period in 2007. Cash provided by
operating activities per unit is defined below under non-GAAP measures. The
$14.8 million increase in cash provided by operating activities compared to
2007 is primarily due to the items described above for the current quarter.

    
    -------------------------------------------------------------------------
                                                            Three        Six
    (millions of dollars) (unaudited)                      Months     Months
    -------------------------------------------------------------------------
    Net (loss) income for the three and six months
     ended June 30, 2007                                    (68.0)       1.5
    -------------------------------------------------------------------------
    Fair value changes on natural gas supply,
     foreign exchange and interest rate contracts           161.1      169.9
    Decrease in income tax expense                           62.3       57.0
    Lower interest expenses(1)                                3.4        8.0
    Mamquam maintenance outage in 2007                        2.3        2.4
    Lower foreign exchange gains compared to 2007(1)        (42.7)     (62.4)
    Williams Lake major overhaul and higher
     maintenance costs in 2008                               (3.2)      (3.2)
    Lower operating margin at the Ontario plants             (2.5)      (5.9)
    Mamquam and Queen Charlotte arbitration award            (2.3)      (1.8)
    Lower revenue due to lower water
     volumes at hydro facilities                             (1.3)      (2.7)
    Preferred share dividends                                (1.1)      (2.7)
    Other                                                    (3.1)      (1.8)
    -------------------------------------------------------------------------
    Net income for the three and six months
     ended June 30, 2008                                    104.9      158.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excluding changes in the fair value of foreign exchange and interest
        rate contracts.

    Net income was $104.9 million or $1.95 per unit for the three months ended
June 30, 2008 compared to a net loss of $68.0 million or $1.33 per unit for
the same period in 2007. In addition to the items described above for the
change in cash provided by operating activities, the increase in net income of
$172.9 million was the result of:

    -   A net gain of $108.5 million recorded in the second quarter of 2008
        on the change in the fair value of the natural gas supply and foreign
        exchange contracts compared to a net loss of $52.6 million on natural
        gas supply, foreign exchange and interest rate contracts in the
        second quarter of 2007 (see Gains (Losses) on Derivative
        Instruments). The majority of the changes in fair value are the
        result of an increase in the future market prices for natural gas in
        the second quarter of 2008 compared to a decrease in the second
        quarter of 2007; and

    -   A decrease in income tax expense due to a change in tax law in
        respect of Specified Investment Flow Through (SIFT) entities in the
        second quarter of 2007, which will result in the Partnership's
        Canadian operations becoming taxable in 2011 and resulted in the
        recording of a future income tax expense of $75.5 million. The income
        tax expense of $15.1 million recorded in the second quarter of 2008
        primarily relates to the future income taxes resulting from changes
        in the temporary differences expected to reverse after 2010 that will
        be subject to the SIFT taxes.

    Increases were partially offset by:

    -   Foreign exchange gains of $2.8 million in the second quarter of 2008
        compared to $45.5 million in the same period of 2007, excluding fair
        value changes on foreign exchange contracts. The foreign exchange
        gains recorded in 2008 were the result of a strengthening of the
        Canadian dollar of $0.007 relative to the United States (US) dollar
        during the second quarter of 2008 on the translation of US dollar-
        denominated debt, compared to $0.089 in the same period in 2007.

    Net income was $158.3 million or $2.94 per unit for the six months ended
June 30, 2008 compared to $1.5 million or $0.03 per unit for the same period
in 2007. The increase in net income of $156.8 million is primarily due to the
items described above for the current quarter.

    Operating Margin(1)
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------
    Ontario                            12.2       14.7       33.7       39.6
    Williams Lake                       2.7        5.3       11.1       12.6
    Mamquam and Queen Charlotte         4.4        2.6        5.7        4.1
    Northwest US plants                 8.3        9.8       16.9       18.5
    California plants                   9.7        9.5       12.6       12.0
    Curtis Palmer                       7.0        7.9       16.4       18.1
    Northeast US gas plants             2.8        2.8        5.7        6.1
    North Carolina plants               0.4        1.0        1.1        0.3
    PERC management fee                 0.6        0.6        1.2        1.3
    -------------------------------------------------------------------------
                                       48.1       54.2      104.4      112.6

    Fair value changes in foreign
     exchange contracts                 5.9       21.8       (9.3)      23.1
    Fair value changes in natural
     gas supply contracts             102.8      (59.8)     170.3      (15.5)
    -------------------------------------------------------------------------
                                      156.8       16.2      265.4      120.2
    -------------------------------------------------------------------------
    (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.
    

    Operating margin excluding fair value changes in foreign exchange and
natural gas supply contracts for the three and six months ended June 30, 2008
decreased by $6.1 million and $8.2 million compared to the same periods in
2007. The decrease in operating margin was primarily due to a planned outage
to complete a major overhaul and higher major maintenance costs at Williams
Lake during the annual maintenance outage in the second quarter of 2008
leading to a decline in operating margin of $3.2 million and lower operating
margin at the Ontario plants of $2.5 million and $5.9 million for the three
and six months ended June 30, 2008. Under the terms of the Williams Lake PPA,
in years where major overhauls are performed, the pricing for electricity
output is adjusted up to effectively keep revenues consistent with non-major
maintenance years. Based on this pricing formula and the major maintenance
that was completed in the second quarter of 2008, the Partnership expects
overall 2008 revenue from Williams Lake to be consistent with prior year
levels with higher revenue in the first, third and fourth quarters and lower
revenue in the second quarter. The decrease in operating margin at the Ontario
plants was due to higher fuel costs (see Cost of Fuel), lower waste heat
availability resulting in a decline in revenue of $1.3 million and $2.6
million for the three and six months ended June 30, 2008 and lower generation
and revenue at Calstock resulting in a decline in operating margin of $1.8
million and $2.9 million for the three and six months ended June 30, 2008
partially offset by an increase in enhancement activity due to relatively high
natural gas prices in the second quarter of 2008 resulting in an increase in
operating margin of $2.3 million in the second quarter of 2008.
    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.

    NON-GAAP MEASURES

    The Partnership uses operating margin as a performance measure and cash
provided by operating activities 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 before tax and preferred share dividends is as follows:

    
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------
    Operating margin                  156.8       16.2      265.4      120.2
    Deduct (Add):
      Depreciation and amortization    23.2       22.6       46.9       45.8
      Management and administration     5.0        2.1        8.5        5.9
      Foreign exchange (gains) losses  (2.6)     (26.7)      10.4      (32.2)
      Equity losses (income) in PERH    0.4       (0.1)       2.1        1.0
      Financial charges and other       9.1        8.3       18.2       22.9
    -------------------------------------------------------------------------
    Net income before tax and
     preferred share dividends        121.7       10.0      179.3       76.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash provided by operating activities per unit is cash provided by
operating activities (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, 2007 reporting.
    

    SIGNIFICANT EVENTS

    Kenilworth PPA extension

    The Partnership reached an agreement with Schering Corporation (Schering)
to amend the Kenilworth PPA effective July 1, 2008 and extend it to July,
2012. The previous PPA under which the Kenilworth facility sold electrical
energy and steam to Schering was due to expire in June, 2009. Future operating
margins are expected to be similar to current levels under the terms of the
revised agreement, which includes amendments that eliminate early termination
provisions and provide for the sharing of potential cost saving benefits by
both parties.

    CHANGES IN ACCOUNTING POLICIES

    Commencing January 1, 2008, the Partnership adopted new accounting
standards as issued by the Canadian Institute of Chartered Accountants (CICA)
for Capital Disclosures, Financial Instruments - Disclosures and Presentation
and Inventories. The changes and the impact of these changes on the
Partnership's consolidated financial statements are described in Note 2 to the
interim consolidated financial statements. The new accounting standards have
been applied prospectively and the comparative financial statements have not
been restated.

    Capital disclosures

    The new accounting standard requires qualitative information about the
Partnership's objectives, policies and processes for managing capital and
quantitative data on the Partnership's capital, as discussed in Note 7 -
Capital management of the Partnership's interim consolidated financial
statements.

    Financial instruments - presentation and disclosures

    These new standards establish requirements for the reporting and
presentation of quantitative and qualitative information that are intended to
provide users of the financial statements with additional insight into the
Partnership's risks associated with financial instruments and how these risks
are managed. These risks include credit, liquidity and market risks. The
additional disclosures required under these new standards have been
incorporated into the interim consolidated financial statements and discussed
in Note 5 - Financial instruments and Note 6 - Risk management. Included in
the financial statement disclosure is a sensitivity analysis of the impact on
net income of changes in the underlying risk factors, primarily natural gas
prices and foreign exchange rates, on the change in the fair value of
financial instruments. Changes in the fair value of the natural gas contracts
has limited economic impact on the Partnership as the majority of the gas
supplied under long term contracts is used for power generation. Changes in
the value of the foreign exchange contracts are offset by changes in the value
of expected foreign currency cash flows. Therefore, readers should be cautious
in assessing the disclosed sensitivities on the interim financial statements.

    Inventories

    The new standard requires inventories to be measured at the lower of cost
and net realizable value and did not materially impact the interim
consolidated financial statements. The additional disclosures required under
the new standard have been incorporated into the interim consolidated
financial statements and discussed in Note 4 - Inventories.

    
    REVENUE AND PLANT OUTPUT

    (millions of dollars
     except GWh)              Three months ended        Six months ended
    (unaudited)                     June 30                 June 30
    -------------------------------------------------------------------------
                           GWh   2008   GWh   2007   GWh   2008   GWh   2007
                        -----------------------------------------------------
    Ontario plants
      - Power              272  $26.3   316  $26.6   622  $66.2   697  $65.9
      - Enhancements              8.0          3.2         10.7          5.9
      - Gas diversions            4.4          4.1          5.0          4.9
                                ------       ------       ------       ------
                                 38.7         33.9         81.9         76.7

    Williams Lake
      - Firm energy         79    6.9   115    8.8   209   17.5   241   18.3
      - Excess energy        6    0.3    10    0.4    13    0.6    24    1.0
                        -----------------------------------------------------
                            85    7.2   125    9.2   222   18.1   265   19.3

    Mamquam and Queen
     Charlotte              86    5.6    92    6.0   114    8.1   124    8.8
    Northwest US plants    111   14.0    94   14.8   305   28.8   169   29.3
    California plants      222   41.3   259   37.0   465   70.9   505   67.8
    Curtis Palmer           84    8.3    88    9.2   192   18.9   199   20.9
    Northeast US gas
     plants                 48   10.4    74   17.8   127   21.7   187   32.8
    North Carolina plants  161   15.0   176   14.7   316   27.9   307   27.7
    PERC management fees          0.9          0.9          1.7          1.8
    Fair value changes            5.9         21.8         (9.3)        23.1
                        -----------------------------------------------------
                         1,069 $147.3 1,224 $165.3 2,363 $268.7 2,453 $308.2
    -------------------------------------------------------------------------


    Weighted average plant      Three months ended          Six months ended
    availability(1)                   June 30                   June 30
    -------------------------------------------------------------------------
                                 2008         2007         2008         2007
                        -----------------------------------------------------
    Ontario plants                93%          90%          96%          95%
    Williams Lake                 62%          88%          81%          93%
    Mamquam and Queen
     Charlotte                    87%          85%          83%          69%
    Northwest US plants           80%          95%          90%          91%
    California plants             93%          89%          91%          90%
    Curtis Palmer                 99%          86%         100%          93%
    Northeast US gas plants       44%          88%          67%          93%
    North Carolina plants         95%          98%          97%          98%
    -------------------------------------------------------------------------
    Weighted average total        83%          92%          90%          92%
    -------------------------------------------------------------------------
    (1) 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.
    

    Revenues were $147.3 million and $268.7 million for the three and six
months ended June 30, 2008 respectively compared to $165.3 million and
$308.2 million for the same periods in 2007. The decreases were primarily due
to changes in the fair value of foreign exchange contracts and lower natural
gas sales at Castleton to utilize excess natural gas transmission capacity,
partially offset by higher revenue at the California facilities as higher
natural gas costs were passed on to PPA counterparties. Overall, the plants in
the US realized higher US dollar revenue for the three and six months ended
June 30, 2008 compared to the same periods in 2007, however lower Canadian to
US dollar exchange rates resulted in a smaller increase in Canadian dollars. A
portion of the impact of the lower Canadian to US dollar exchange rate was
offset by higher gains realized on foreign exchange contracts used to hedge
exposure to changes in the exchange rate. The realized gains were reflected in
the revenues of the US plants.

    Ontario Plants
    The Ontario plants reported revenues of $38.7 million and $81.9 million
for the three and six months ended June 30, 2008 compared to $33.9 million and
$76.7 million for the same periods in the prior year. The increase was due to
built-in annual price escalators partially offset by lower generation and
revenue at Calstock due to high moisture levels in the waste wood inventory at
the plant. As a result, the plant scaled back production to optimize available
waste wood and used natural gas to meet minimum generation requirements. While
wetter than normal conditions continued to have an impact on Calstock fuel
quality, warmer temperatures and operational changes are expected to resolve
the wet wood issues in the third quarter.
    Revenues at the Ontario facilities were also adversely impacted by lower
waste heat availability which declined 19% and 21% for the three and six
months ended June 30, 2008 compared to the same periods in 2007. Lower
throughput on the TransCanada Canadian Mainline, the natural gas transmission
line to Northern Ontario, was the cause of the decline. This decrease was due
to lower natural gas demand in Northern Ontario in part due to lower forestry
industry activity, lower natural volumes leaving Alberta due to lower levels
of natural gas supply from the Western Canadian Sedimentary Basin due to lower
drilling activity combined with increasing demand in Alberta, structural
changes in the nature of long haul transportation agreements on the
TransCanada Canadian Mainline and the conversion of an upstream section on the
TransCanada Canadian Mainline west of the Manitoba border from a high pressure
natural gas line to an oil line. Future throughput will continue to be subject
to supply and demand variances, however forecasts from independent third
parties suggest a 10% to 20% decline in throughput in 2008 and 2009 from
recent levels and marginal further declines after 2009 with potential for
recovery of volumes beginning as early as 2012. Lower throughput on this
natural gas transmission line also has an impact on natural gas transportation
costs to the Partnership's Ontario natural gas facilities (see Cost of Fuel).
    Enhancement revenues at the Ontario plants were higher in 2008 due to an
increase in natural gas prices.
    In early April 2008, the Nipigon facility experienced a six day unplanned
outage due to a bearing failure in its gas turbine. The cost of the outage
reduced operating margin by $0.2 million in the second quarter of 2008.

    Williams Lake
    Revenues at Williams Lake were $7.2 million and $18.1 million for the
three and six months ended June 30, 2008, compared with $9.2 million
and $19.3 million for the same periods in 2007. The decrease in generation and
revenue during the second quarter of 2008 was primarily due to a planned
outage to complete a major overhaul in May and June. Revenues in the third and
fourth quarters of 2008 are expected to offset the lower revenue in the second
quarter under terms of the PPA.

    Mamquam and Queen Charlotte
    Revenues at Mamquam and Queen Charlotte were $5.6 million and
$8.1 million for the three and six months ended June 30, 2008, compared with
$6.0 million and $8.8 million for the same periods in 2007. The decrease in
generation and revenue during the period was the result of below normal water
flows in the first five months of 2008 partially offset by tunnel maintenance
completed in 2007, which resulted in lower revenue, generation and
availability at Mamquam. Snow pack levels in British Columbia are above
normal, which is expected to have a positive impact on generation and revenue
in the third quarter of 2008.

    Northwest US Plants
    Availability for the Northwest US plants was lower in the second quarter
of 2008 compared to 2007 due to planned outages at Manchief and Frederickson.
    Revenues from Frederickson were $5.4 million and $11.3 million for the
three and six months ended June 30, 2008 compared to $5.6 million and
$11.6 million for the same periods in 2007. The decreases were due to lower
Canadian to US dollar exchange rates partially offset by increased US dollar
revenue from higher generation.
    Revenues from Greeley were $2.4 million and $5.0 million for the three
and six months ended June 30, 2008 compared to $2.3 million and $4.7 million
for the same periods in 2007. The increases were due to increased US dollar
capacity revenue partially offset by lower Canadian to US dollar exchange
rates. Capacity revenues were higher in 2008 compared to 2007 as the plant
achieved its rolling 12 month capacity targets for 2008.
    Revenues from Manchief were $6.2 million and $12.5 million for the three
and six months ended June 30, 2008 compared to $6.9 million and $13.0 million
for the same periods in 2007. The decreases were due to lower generation and
lower Canadian to US dollar exchange rates.

    California Plants
    Revenues from the Naval facilities were $33.2 million and $58.4 million
for the three and six months ended June 30, 2008 compared to $30.8 million and
$56.6 million for the same periods in 2007. The increases were due to
increased US dollar electricity prices driven by higher natural gas prices
partially offset by lower Canadian to US dollar exchange rates.
    Revenues from Oxnard were $8.1 million and $12.5 million for the three
and six months ended June 30, 2008 compared to $6.2 million and $11.2 million
for the same periods in 2007. The increases were due to increased US dollar
electricity prices driven by higher natural gas prices partially offset by
lower Canadian to US dollar exchange rates.

    Curtis Palmer
    Revenues at Curtis Palmer were $8.3 million and $18.9 million for the
three and six months ended June 30, 2008, compared with $9.2 million and
$20.9 million for the same periods in 2007. Generation and revenues for the
three and six months ended June 30, 2008 were both above normal levels due to
strong water flows which, however, were lower than in 2007. As well, revenues
were lower due to lower Canadian to US dollar exchange rates.

    Northeast US Gas Plants
    Revenues of $3.6 million and $7.3 million for Castleton for the three and
six months ended June 30, 2008 were $7.7 million and $10.4 million lower than
the same periods in 2007 mainly due to lower natural gas sales to utilize
excess natural gas transmission capacity and lower Canadian to US dollar
exchange rates. The decrease in revenue was mostly offset by lower fuel costs
(see Cost of Fuel). A major overhaul was completed at Castleton in the second
quarter of 2008, which reduced generation and availability but did not impact
capacity revenues.
    Effective July 1, 2008 the PPA for Castleton expired and the Partnership
began running the plant on a merchant basis. The Partnership is evaluating its
longer term options for the facility including continuing to run the plant on
a merchant basis as well as selling the facility. Under a merchant scenario,
operating margins are expected to both decline and be more volatile then they
were under the pre-existing PPA.
    Revenues from Kenilworth were $6.8 million and $14.4 million for the
three and six months ended June 30, 2008 compared to $6.5 million and
$15.1 million for the same periods in 2007. The increase during the three
months ended June 30, 2008 compared to the same period in the prior year was
due to weather related forced outages in April 2007 partially offset by lower
Canadian to US dollar exchange rates. Year to date results were lower due to
lower Canadian to US dollar exchange rates.

    North Carolina Plants
    Revenues from the North Carolina plants were $15.0 million and
$27.9 million for the three and six months ended June 30, 2008 compared to
$14.7 million and $27.7 million for the same periods in 2007. The increases
were the result of increased US dollar electricity prices driven by higher
coal prices partially offset by lower Canadian to US dollar exchange rates.

    Fair value changes on foreign exchange contracts
    Unrealized gains on foreign exchange contracts were $5.9 million and
unrealized losses were $9.3 million for the three and six months ended
June 30, 2008 respectively compared to unrealized gains of $21.8 million and
$23.1 million reported in the same periods in 2007. The changes in fair value
were primarily due to changes in the forward prices for Canadian dollars
relative to US dollars which decreased $0.030 and increased $0.020 for the
three and six months ended June 30, 2008 respectively compared to decreases of
$0.079 and $0.082 in the same periods of 2007.

    
    COST OF FUEL
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------

    Ontario Plants
      Natural gas                      17.4       14.8       34.1       27.5
      Waste heat                        4.4        0.2        4.9        1.0
      Wood waste                        0.9        0.5        1.5        1.1
                                     -------    -------    -------    -------
                                       22.7       15.5       40.5       29.6

    Williams Lake - wood waste          0.7        0.9        1.3        1.8

    Northwest US Plants -
     natural gas                        2.9        2.1        6.0        5.3

    California Plants -
     natural gas                       25.6       21.9       47.1       45.0

    Northeast US Gas Plants -
     natural gas                        6.0       13.1       12.6       22.8

    North Carolina Plants -
     coal, tire-derived fuel &
     wood waste                        10.4        9.6       19.1       18.7

    Fair value changes on
     natural gas contracts           (102.8)      59.8     (170.3)      15.5
                                     -------    -------    -------    -------
                                      (34.5)     122.9      (43.7)     138.7
                                     -------    -------    -------    -------
    

    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. Virtually all the fuel for Ontario
and Williams Lake is supplied under fixed price, long-term supply agreements
with built-in price escalators that generally correspond to price increases
under the related PPAs.
    For the three and six months ended June 30, 2008, fuel costs, excluding
fair value changes on natural gas contacts, were $68.3 million and
$126.6 million compared with $63.1 million and $123.2 million for the same
periods in 2007. The Partnership recorded fair value gains on the natural gas
supply contracts of $102.8 million and $170.3 million for the three and six
months ended June 30, 2008 compared to fair value losses of $59.8 million and
$15.5 million in the same periods in 2007. The changes in the fair value of
the natural gas contracts were primarily due to changes in natural gas forward
prices which increased $1.85/gigajoule (GJ) and $2.95/GJ for the three and six
months ended June 30, 2008 compared to a decrease of $0.49/GJ and an increase
of $0.25/GJ in the same periods of 2007. Fair value changes were also impacted
by the receipt of natural gas under the contracts and increases in the pricing
applied to natural gas supply at the Tunis plant in the second quarter of
2007.
    Fuel costs at the Ontario plants for the three and six months ended
June 30, 2008 were $22.7 million and $40.5 million compared to $15.5 million
and $29.6 million for the same periods in 2007. The increase was due to (i)
higher fuel supply costs at Tunis as a result of supply contract dispute
settlements in July 2007 and January 2008; (ii) a 19% increase in the fuel
supply price in 2008 at Kapuskasing and North Bay under the 20 year natural
gas supply agreements; (iii) an increase in waste heat optimization costs in
the second quarter of 2008 due to continued decreases in natural gas flow on
the TransCanada Canadian Mainline; (iv) a $1.2 million refund of natural gas
transportation costs recorded in the first quarter of 2007 relating to prior
periods; and (v) higher natural gas consumption at Calstock in 2008 to ensure
minimum generation requirements were met.
    On March 28, 2008, the National Energy Board of Canada approved an
increase in the tariff for natural gas transportation costs on the TransCanada
Canadian Mainline from $1.03/GJ to $1.38/GJ effective April 1, 2008. On
July 27, 2008, a further increase to $1.40/GJ was approved effective July 1,
2008. These changes are expected to increase the fuel costs at the Ontario
natural gas facilities by approximately $2 million in 2008.
    Williams Lake incurred fuel costs of $0.7 million and $1.3 million for
the three and six months ended June 30, 2008, compared to $0.9 million and
$1.8 million for the same periods in 2007. The decreases were due primarily to
lower waste wood consumption during a planned outage in 2008.
    The Northwest US plants incurred fuel costs of $2.9 million and
$6.0 million for the three and six months ended June 30, 2008, compared to
$2.1 million and $5.3 million for the same periods in 2007. The increases were
due to an increase in fuel costs at Greeley to meet capacity targets partially
offset by lower Canadian to US dollar exchange rates.
    Fuel costs at the California facilities were $25.6 million and
$47.1 million for the three and six months ended June 30, 2008 compared to
$21.9 million and $45.0 million for the same periods in 2007. The increases
were due to higher natural gas prices partially offset by lower Canadian to US
dollar exchange rates.
    The Northeast US gas plants incurred fuel costs of $6.0 million and
$12.6 million for the three and six months ended June 30, 2008, compared to
$13.1 million and $22.8 million for the same periods in 2007. The decreases
were due to lower sales of natural gas to utilize excess natural gas
transmission capacity at Castleton and lower Canadian to US dollar exchange
rates.
    The North Carolina plants incurred fuel costs of $10.4 million and
$19.1 million for the three and six months ended June 30, 2008, compared to
$9.6 million and $18.7 million for the same periods in 2007. The increases
were due to higher coal prices partially offset by lower Canadian to US dollar
exchange rates.
    The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric plants do
not have fuel costs.

    
    OPERATING AND MAINTENANCE EXPENSE
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------

    Ontario                             3.4        3.4        6.9        6.8
    Williams Lake                       1.5        1.5        3.0        2.8
    Mamquam and Queen Charlotte         0.3        0.3        0.7        0.6
    Northwest US plants                 2.0        2.0        4.3        4.1
    California plants                   3.2        3.4        6.5        7.2
    Curtis Palmer                       0.4        0.3        0.7        0.6
    Northeast US gas plants             1.2        1.3        2.5        2.8
    North Carolina plants               3.1        2.8        6.1        5.8
    PERC management expenses            0.2        0.2        0.4        0.5
    -------------------------------------------------------------------------
                                       15.3       15.2       31.1       31.2
    -------------------------------------------------------------------------
    

    Operating and maintenance expenses are payable to the Manager for the
operation and routine maintenance of the plants. Fees are based on fixed
charges adjusted annually for inflation for the Canadian plants, Curtis
Palmer, Manchief and Castleton and a flow through of costs for the remaining
US plants. Operating and maintenance expenses were $15.3 and $31.1 million for
the three and six months ended June 30, 2008, consistent with the same periods
in 2007.

    OTHER PLANT OPERATING EXPENSES

    Other plant operating expenses, which include insurance, property taxes
and major maintenance expenses, were $9.7 million and $15.9 million for the
three and six months ended June 30, 2008 compared to $11.0 million and
$18.1 million for the same periods in 2007. The decreases were mainly due to
the Mamquam tunnel repairs in 2007, partially offset by an increase in major
maintenance costs at Williams Lake during the annual maintenance overhaul
completed in the second quarter of 2008.

    DEPRECIATION AND AMORTIZATION

    Depreciation and amortization expense for the three and six months ended
June 30, 2008 was $23.2 million and $46.9 million compared to $22.6 million
and $45.8 million for the same periods in 2007.

    MANAGEMENT AND ADMINISTRATION

    Management and administration costs, which include fees payable to EPCOR
and general and administrative costs, were $5.0 million and $8.5 million for
the three and six months ended June 30, 2008 compared to $2.1 million and
$5.9 million for the same periods in 2007. The increases were due to
arbitration awards against the previous owners of Mamquam and Queen Charlotte
in respect of claims by the Partnership in the purchase and sale agreement of
$2.3 million in the second quarter of 2007 partially offset by $0.5 million
awarded in the first quarter of 2008.

    
    FOREIGN EXCHANGE (GAINS) LOSSES
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------

    Realized foreign exchange
     (gains) losses                    (0.2)       0.9       (0.7)       1.0
    Unrealized foreign exchange
     (gains) losses on US
     dollar-denominated debt           (2.6)     (46.4)      10.9      (53.2)
    Realized losses on foreign
     exchange contracts                 0.2       20.9        0.2       15.3
    Fair value changes on foreign
     exchange contracts                   -       (2.1)         -        4.7
    -------------------------------------------------------------------------
                                       (2.6)     (26.7)      10.4      (32.2)
    -------------------------------------------------------------------------
    

    The Partnership reported net foreign exchange gains of $2.6 million and
losses of $10.4 million for the three and six months ended June 30, 2008
compared to gains of $26.7 million and $32.2 million for the same periods in
2007. The foreign exchange gains recorded in the second quarter of 2008 were
the result of a strengthening of the Canadian dollar of $0.007 relative to the
US dollar during the quarter on the translation of US dollar-denominated debt,
compared to a strengthening $0.089 in the same period in 2007. The foreign
exchange losses recorded in the six months ended June 30, 2008 were the result
of a weakening of the Canadian dollar of $0.028 relative to the US dollar
during the period, compared to a strengthening $0.100 in the same period in
2007.
    During the second quarter of 2007, the Partnership realized losses of
$20.9 million on settlement of foreign exchange contracts entered into in
anticipation of the issuance of Canadian equity to replace a portion of the
US dollar bridge acquisition facility. These losses were partially offset by
gains of $5.6 million in the first quarter of 2007.

    EQUITY LOSSES (INCOME) IN PERH

    Equity losses (income) in PERH were from the Partnership's 17.0% common
ownership interest in PERH, which is accounted for on an equity basis. For the
three and six months ended June 30, 2008, the Partnership received dividends
on its 14.2% preferred ownership interest of $0.4 million and $0.9 million
respectively ($0.4 million and $0.8 million for the same periods in 2007) and
dividends from its common interest in PERH of $0.8 million and $1.6 million
respectively ($1.0 million and $2.3 million for the same periods in 2007).

    
    FINANCIAL CHARGES AND OTHER, NET
                                          Three months            Six months
                                         ended June 30         ended June 30
    (millions of dollars)(unaudited)   2008       2007       2008       2007
    -------------------------------------------------------------------------

    Interest on long-term debt          9.4        8.8       18.7       18.1
    Interest on short-term debt         0.2        1.8        0.3        4.9
    Interest on capital lease
     obligations                          -        1.5          -        3.1
    Dividend income from Class B
     preferred share interests in
     PERH                              (0.4)      (0.4)      (0.9)      (0.8)
    Realized gains on interest
     rate contracts                       -       (5.5)         -       (5.5)
    Fair value changes on
     interest rate contracts              -        1.3          -        2.2
    Other                              (0.1)       0.8        0.1        0.9
    -------------------------------------------------------------------------
                                        9.1        8.3       18.2       22.9
    -------------------------------------------------------------------------
    

    Financial charges and other expenses, excluding realized gains and fair
value changes on interest rate contracts, were $9.1 million and $18.2 million
for the three and six months ended June 30, 2008 compared to $12.5 million and
$26.2 million for same periods in 2007. The decreases were primarily due to
the repayment of short-term and long-term debt with the proceeds from
Partnership unit and preferred share issues in the second quarter of 2007 and
the buy-out of capital lease obligations with lower cost long-term debt in the
third quarter of 2007. In addition, the Partnership recorded declines in the
fair value of interest rate contracts for the three and six months ended
June 30, 2007.

    INCOME TAX EXPENSE

    Income tax expense was $15.1 million and $17.7 million for the three and
six months ended June 30, 2008 compared to $77.4 million and $74.7 million for
the same periods in 2007. A change in tax law in the second quarter of 2007,
which will result in the Partnership's Canadian operations becoming taxable in
2011, resulted in the recording of a future income tax expense of
$75.5 million. Income tax expense recorded for the three and six months ended
June 30, 2008 primarily relate to the future income taxes resulting from
changes in the temporary differences expected to reverse after 2010 that will
be subject to the SIFT taxes. Income taxes also relate to the income taxes of
the Partnership's US subsidiaries and withholding taxes on distributions from
the US subsidiaries.

    PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY

    A subsidiary of the Partnership issued preferred shares in the second
quarter of 2007, which pay dividends at a rate of 4.85% per annum. For the
three and six months ended June 30, 2008, dividends of $1.5 million and
$3.0 million were paid to shareholders and net income tax expenses of
$0.2 million and $0.3 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
    Three months                             Recorded In
     ended June 30          Income      Income Statement    Amounts Realized
    (millions of dollars)  Statement   ------------------  ------------------
    (unaudited)            Category       2008      2007      2008      2007
    -------------------------------------------------------------------------
    Foreign exchange
     contracts(1)       Revenues           5.9      21.8         -         -
    Natural gas
     contracts          Cost of fuel     102.8     (59.8)        -         -
    Foreign exchange    Foreign
     contracts           exchange
                         (gains) losses   (0.2)    (18.8)     (0.2)    (20.9)
    Interest rate       Financial
     contracts           charges
                         and other, net      -       4.2         -       5.5
    -------------------------------------------------------------------------
                                         108.5     (52.6)     (0.2)    (15.4)
    -------------------------------------------------------------------------


                                                 Amounts
    Six months                               Recorded In
     ended June 30          Income      Income Statement    Amounts Realized
    (millions of dollars)  Statement   ------------------  ------------------
    (unaudited)            Category       2008      2007      2008      2007
    -------------------------------------------------------------------------
    Foreign exchange
     contracts(1)       Revenues          (9.3)     23.1         -         -
    Natural gas
     contracts          Cost of fuel     170.3     (15.5)        -         -
    Foreign exchange    Foreign
     contracts           exchange
                         (gains) losses   (0.2)    (20.0)     (0.2)    (15.3)
    Interest rate       Financial
     contracts           charges
                         and other, net      -       3.3         -       5.5
    -------------------------------------------------------------------------
                                         160.8      (9.1)     (0.2)     (9.8)
    -------------------------------------------------------------------------
    (1) Amounts realized on foreign exchange contracts for operating cash
        flow are included in plant revenue.
    

    Discussion of changes in fair value amounts is included in the respective
income statement categories. The amounts realized are included in cash
provided by operating activities.

    LIQUIDITY AND CAPITAL RE

SOURCES Cash distributions Cash distributions of $0.63 per unit were declared for the second quarter of 2008, consistent with the same period in 2007. 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. Three months Six months ended June 30 ended June 30 (millions of dollars)(unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Cash distributions 33.9 34.0 67.9 65.4 Cash provided by operating activities 40.4 7.8 83.3 68.5 Net income (loss) 104.9 (68.0) 158.3 1.5 Dividend from PERH 0.8 1.0 1.6 2.3 Additions to property, plant and equipment 11.7 4.2 15.5 5.3 Excess (shortfall) of cash provided by operating activities over cash distributions 6.5 (26.2) 15.4 3.1 Excess (shortfall) of net income over cash distributions 71.0 (102.0) 90.4 (63.9) ------------------------------------------------------------------------- Cash provided by operating activities exceeded cash distributions by $6.5 million and $15.4 million for the three and six months ended June 30, 2008. The Partnership also incurred capital expenditures of $11.7 million and $15.5 million during the three and six months ended June 30, 2008. Net income is not necessarily comparable to cash distributions as net income includes items such as unrealized gains and losses on translation of US dollar-denominated debt and 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 and maturing in 2010. 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. The second quarter 2008 cash distribution of $0.63 per unit will be paid on July 30, 2008 to unitholders of record on June 30, 2008. Capital expenditures Capital expenditures for the three and six months ended June 30, 2008 totalled $11.7 million, and $15.5 million respectively, compared with $4.2 million and $5.3 million for the same periods in 2007. Capital spending for the three and six months ended June 30, 2008 included $1.1 million and $1.6 million invested in the enhancement of the Southport and Roxboro coal plants. Total maintenance capital spending for 2008 is expected to be in the $23 million to $25 million range, in line with earlier expectations. In addition, the Partnership plans to invest up to US$80 million in 2008 and 2009 for the enhancement of the Southport and Roxboro coal plants to reduce environmental emissions and improve the economic performance. This represents a US$15 million increase in capital costs from amounts previously estimated due to planned changes in emissions control equipment, further engineering work that has refined our cost estimates and scope increases to the project. The changes to the emissions control equipment are also expected to reduce future operating costs compared with previous estimates. The combination of expected increases in capital costs and decreases in future operating costs results in targeted accretion for the project remaining in line with past guidance of approximately 10 cents per unit. FOREIGN EXCHANGE RISK MANAGEMENT The Partnership manages the foreign exchange risk of its future 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 June 30, 2008, $357.1 million (US$325.6 million) or approximately 76% of expected future cash flows were economically hedged for 2008 to 2014 at a weighted average exchange rate of $1.10 to US $1.00. TRANSACTIONS WITH RELATED PARTIES Three months Six months ended June 30 ended June 30 (millions of dollars)(unaudited) 2008 2007 2008 2007 ------------------------------------------------------------------------- Transactions with the Manager ----------------------------- Cost of fuel - Castleton gas demand charge 0.5 0.5 1.0 1.1 Operating and maintenance expense 13.2 12.5 26.2 25.9 Management and administration Base fee 0.4 0.4 0.7 0.7 Incentive fee 0.6 0.6 1.2 1.1 Enhancement fee 1.2 0.4 1.4 0.6 Administration fee 0.3 0.2 0.5 0.4 ------------------------------------------------------------------------- 2.5 1.6 3.8 2.8 ------------------------------------------------------------------------- Transactions with PERC ---------------------- Revenue Base management fees 0.9 0.9 1.7 1.8 ------------------------------------------------------------------------- In operating the Partnership's 20 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 and six months ended June 30, 2008 and 2007. The Partnership makes quarterly cash distributions to EPCOR in the amount proportionate to their ownership interest. At June 30, 2008, EPCOR owned 30.6% of the Partnership's units (June 30, 2007 - 30.6%). CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES The Partnership has committed up to US$80 million for the enhancement of the Southport and Roxboro facilities, to be spent over 2008 and 2009. There were no other material changes to the Partnership's purchase obligations, commitments or contingencies during the second quarter, including payments for the next five years and thereafter. For further information on these obligations, refer to the Partnership's 2007 Annual 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 2007 Annual MD&A. The fair value of non-financial derivatives reflects changes in the commodity market prices, interest rates and foreign exchange rates. Fair value amounts reflect management's best estimates considering various factors including closing exchange or over-the-counter quotations, estimates of futures prices and foreign exchange rates, time value and volatility. It is possible that the assumptions used in establishing fair value amounts will differ from actual prices and the impact of such variations could be material. INTERNAL CONTROL OVER FINANCIAL REPORTING There were no changes made to the Partnership's internal controls over financial reporting during the interim period ended June 30, 2008 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, 2007. Recent developments on risk are described below. For further information on business risks, refer to the Partnership's December 31, 2007 MD&A. Proposed emissions regulations On March 10, 2008, the Canadian Environment Minister released further information on the proposed new regulatory framework to reduce greenhouse gas emissions and air pollution in Canada that was originally announced on April 26, 2007. These changes do not materially alter the Partnership's expectations for the costs of compliance estimated in December 31, 2007 MD&A. The Partnership estimates the cost to meet the proposed regulations for carbon dioxide emissions to be approximately $1 million annually starting in 2010 escalating to $2 million annually by 2020. The Partnership estimates the costs to comply with anticipated legislation for nitrogen oxide emissions to be $3 to $4 million in one-time capital costs. On July 11, 2008, the U.S. Washington District Court vacated the Clean Air Interstate Rule (CAIR) in its entirety. CAIR regulations were to take effect the beginning of 2009, setting required reductions in nitrogen oxide (NOx) and sulphur dioxide (SO2) emissions which would have impacted the Southport and Roxboro facilities. The Partnership had planned to address the CAIR regulations through capital upgrades to its emissions control equipment at these facilities. The Partnership intends to continue with these capital improvements despite the CAIR decision because: - The capital improvements include changes to the fuel handling system and boiler modifications that allow for increased use of wood waste and tire derived fuels which improve the economics for Southport and Roxboro; - The new emission control equipment substantially reduces SO2 and NOx emissions which is beneficial for the environment; and - The Partnership expects that the CAIR regulation will be replaced at some point in the future with similar legislation to limit SO2 and NOx emissions. PERH distributions An amendment to the Harbor Coal agreement was executed on April 3, 2008, which is expected to provide more stable and predictable cash flow. As a result, the terms of the senior lending agreement subjecting PERH to increased interest costs and the possibility of cash sweeps have been eliminated. The Partnership is in discussions with the advisors to the Primary Energy Recycling Corporation (PERC) Board regarding strategic alternatives for PERH. The Partnership has determined that while it may continue to hold its 15.4% interest in PERH, it is not a buyer of the remaining 84.6% interest in PERH currently owned by PERC nor would the Partnership pursue an acquisition of PERC because the transactions would not be accretive. FUTURE ACCOUNTING STANDARDS International financial reporting standards In February 2008, the CICA confirmed that Canadian reporting issuers will be required to report under International Financial Reporting Standards (IFRS) effective January 1, 2011, including comparative figures for the prior year. In April 2008, the CICA released an exposure draft of the coming standards. A high level IFRS implementation plan has been developed and an assessment of the impact of the accounting standard differences to the financial statements is currently in progress. Based on our analysis to date, the most significant differences for the Partnership are anticipated to be related to property, plant and equipment, joint arrangements, financial instruments and hedges, foreign currency translation, 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 to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes on the required implementation date. 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 IFRS provisions. The provisions relating to goodwill are unchanged from those of the replaced Section 3062 - Goodwill and Other Intangible Assets. These amendments are effective January 1, 2009. The Partnership does not expect the adoption of the new standard to result in a material transition adjustment to its financial statements. OUTLOOK The Partnership's longer term outlook remains substantially unchanged since December 31, 2007. For further information on our outlook, refer to the Partnership's December 31, 2007 MD&A. An update to those items previously disclosed includes: - Natural gas transportation costs for the Ontario plants are expected to increase by $2 million in 2008 due to increases in natural gas transportation tariffs. There may be further tariff increases as a result of continued decreases in natural gas flow on the TransCanada Canadian Mainline and relatively high natural gas prices; - PERH distributions should be more stable in the future due to the amendment to the Harbor Coal agreement, which is expected to provide more predictable cash flow; - Above normal snow pack levels are expected to favorably impact generation and revenue at Mamquam during the third quarter of 2008; - Lower pipeline volumes resulted in lower waste heat revenues and higher waste heat optimization costs at the Ontario plants in the first six months of 2008 compared to the same period in 2007. Throughput on the TransCanada Canadian Mainline is expected to continue to be lower for the remainder of 2008 compared to 2007 with recoveries in volumes not expected prior to 2012. Management is actively working with TransCanada to address opportunities to mitigate the financial impact of lower waste heat availability; and - Higher natural gas prices may increase the opportunities for enhancement revenue at the Ontario facilities as well as the operating margin at the California facilities which may be partially offset by reduced margins at the Greeley facility. Based on the Partnership's 2008 operating and capital plan and taking into consideration the points noted above, cash distributions are expected to remain at the current annual level of $2.52 per unit in 2008, subject to any material changes that may occur during the year. SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA (unaudited) (millions of dollars 2008 2007 except per unit amounts) Second First Fourth Third ------------------------------------------------------------------------- Revenues 147.3 121.4 117.6 153.4 Operating margin(1) 156.8 108.6 83.1 20.6 Net income (loss) 104.9 53.4 45.3 (15.9) Cash provided by operating activities 40.4 42.9 38.0 26.5 Capital expenditures 11.7 3.8 4.6 2.6 Cash distributions 33.9 34.0 34.0 33.9 Per unit statistics Net income (loss) $ 1.95 $ 0.99 $ 0.84 $ (0.29) Cash provided by operating activities(1) $ 0.75 $ 0.80 $ 0.71 $ 0.49 Cash distributions $ 0.63 $ 0.63 $ 0.63 $ 0.63 ------------------------------------------------------------------------- 2007 2006 Second First Fourth Third ------------------------------------------------------------------------- Revenues 165.3 142.9 105.3 72.6 Operating margin(1) 16.2 103.9 43.3 38.2 Net income (loss) (68.0) 69.4 (12.9) 10.8 Cash provided by operating activities 7.8 60.7 34.4 28.8 Capital expenditures 4.2 1.1 9.0 2.2 Cash distributions 34.0 31.4 31.4 31.4 Per unit statistics Net income (loss) $ (1.33) $ 1.39 $ (0.26) $ 0.22 Cash provided by operating activities(1) $ 0.15 $ 1.22 $ 0.69 $ 0.59 Cash distributions $ 0.63 $ 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 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 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 anticipated to be 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 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 the 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 accruals of $3.1 million related to periods ending before December 31, 2006. As a result of the settlement, fuel costs for the last two quarters of 2007 were approximately $2.6 million higher than in 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 first quarter of 2007, the Partnership began reporting natural gas supply contracts for the Ontario plants at fair value. The Partnership recorded gains on the change in the fair value of the natural gas supply contracts in the first and fourth quarters of 2007 and the first and second quarters of 2008 and losses in the second and third quarters of 2007. Unrealized foreign exchange gains on US dollar-denominated debt were recorded in all four quarters of 2007 and the second quarter of 2008. Losses were recorded in the third and fourth quarters of 2006 and the first quarter of 2008. The gains and losses are due to fluctuations in the US dollar relative to the Canadian dollar. Unrealized fair value changes on foreign exchange contracts resulted in gains in the first three quarters of 2007 and the second quarter of 2008. Losses were recorded in the third and fourth quarters of 2006, in the fourth quarter of 2007 and in the first quarter of 2008. The fourth quarter of 2006 and the first quarters of 2007 and 2008 had unseasonably high water flows at Curtis Palmer, while the fourth quarter of 2007 had unseasonably low water flows. In the third quarter of 2006 the Partnership acquired Frederickson Power L.P. In the fourth quarter of 2006 the Partnership acquired Primary Energy Ventures LLC (now EPCOR Ventures USA LLC). QUARTERLY UNIT TRADING INFORMATION The Partnership units trade on the Toronto Stock Exchange under the symbol EP.UN. For the three months ended Jun. 30 Mar. 31 Dec. 31 Sep. 30 Jun. 30 (unaudited) 2008 2008 2007 2007 2007 ------------------------------------------------------------------------- Unit price High $24.70 $23.78 $25.29 $27.90 $27.29 Low $21.52 $19.65 $20.11 $22.10 $25.38 Close $22.41 $21.90 $23.37 $24.64 $26.30 Volume traded (millions) 4.5 4.8 6.3 4.5 5.5 ------------------------------------------------------------------------- As at June 30, 2008, the Partnership had 53.9 million units outstanding. The weighted average number of units outstanding for the three and six months ended June 30, 2008 was 53.9 million which is higher than the same period in 2007 due to the issue of 4.0 million units in the second quarter of 2007 related to an acquisition completed in 2006. 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 Six months ended June 30 June 30 (unaudited) 2008 2007 2008 2007 --------------------------------- --------- --------- --------- --------- (In millions of dollars except units and per unit amounts) Revenues $ 147.3 $ 165.3 $ 268.7 $ 308.2 Cost of fuel (34.5) 122.9 (43.7) 138.7 Operating and maintenance expense 15.3 15.2 31.1 31.2 Other plant operating expenses 9.7 11.0 15.9 18.1 --------- --------- --------- --------- 156.8 16.2 265.4 120.2 Other costs (income) Depreciation and amortization 23.2 22.6 46.9 45.8 Management and administration 5.0 2.1 8.5 5.9 Foreign exchange (gains) losses (2.6) (26.7) 10.4 (32.2) Equity losses (income) in PERH 0.4 (0.1) 2.1 1.0 Financial charges and other, net (Note 3) 9.1 8.3 18.2 22.9 --------- --------- --------- --------- 35.1 6.2 86.1 43.4 --------- --------- --------- --------- Net income before income tax and preferred share dividends 121.7 10.0 179.3 76.8 Income tax expense 15.1 77.4 17.7 74.7 --------- --------- --------- --------- Net income (loss) before preferred share dividends 106.6 (67.4) 161.6 2.1 Preferred share dividends of a subsidiary company 1.7 0.6 3.3 0.6 --------- --------- --------- --------- Net income (loss) $ 104.9 $ (68.0) $ 158.3 $ 1.5 --------- --------- --------- --------- --------- --------- --------- --------- Net income (loss) per unit $ 1.95 $ (1.33) $ 2.94 $ 0.03 --------- --------- --------- --------- --------- --------- --------- --------- Weighted average units outstanding (millions) 53.9 51.2 53.9 50.6 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF CASH FLOW Three months ended Six months ended June 30 June 30 (unaudited) 2008 2007 2008 2007 --------------------------------- --------- --------- --------- --------- (In millions of dollars) Operating activities Net income (loss) $ 104.9 $ (68.0) $ 158.3 $ 1.5 Items not affecting cash: Depreciation and amortization 23.2 22.6 46.9 45.8 Future income tax 13.8 76.1 15.1 71.5 Fair value changes on derivative instruments (108.7) 37.1 (161.0) (0.8) Unrealized foreign exchange (gains) losses (2.8) (45.5) 10.2 (52.2) Other 0.8 (0.8) 2.3 1.8 --------- --------- --------- --------- 31.2 21.5 71.8 67.6 Change in non-cash operating working capital 9.2 (13.7) 11.5 0.9 --------- --------- --------- --------- Cash provided by operating activities 40.4 7.8 83.3 68.5 --------- --------- --------- --------- Investing activities Additions to property, plant and equipment (11.7) (4.2) (15.5) (5.3) Change in non-cash working capital 5.8 2.2 5.7 1.0 Dividends from PERH 0.8 1.0 1.6 2.3 --------- --------- --------- --------- Cash used in investing activities (5.1) (1.0) (8.2) (2.0) --------- --------- --------- --------- Financing activities Distributions paid (34.0) (31.4) (67.9) (62.8) Net proceeds from preferred share offering - 120.8 - 120.8 Net proceeds from unit offering - 101.3 - 101.3 Short-term debt repaid - (200.5) - (200.5) Long-term debt repaid - (18.1) (0.5) (33.0) --------- --------- --------- --------- Cash used in financing activities (34.0) (27.9) (68.4) (74.2) --------- --------- --------- --------- Foreign exchange gains (losses) on cash held in a foreign currency 0.2 (0.9) 0.7 (1.0) Increase (decrease) in cash and cash equivalents 1.5 (22.0) 7.4 (8.7) Cash and cash equivalents, beginning of period 26.0 45.3 20.1 32.0 --------- --------- --------- --------- Cash and cash equivalents, end of period $ 27.5 $ 23.3 $ 27.5 $ 23.3 --------- --------- --------- --------- --------- --------- --------- --------- Supplementary cash flow information Income taxes paid $ 1.5 $ 1.0 $ 4.5 $ 2.5 Interest paid $ 5.6 $ 14.4 $ 17.5 $ 28.7 --------- --------- --------- --------- --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED BALANCE SHEETS June 30, December 31, (unaudited) 2008 2007 --------------------------------------------- ------------ ------------ (In millions of dollars) ASSETS Current assets Cash and cash equivalents $ 27.5 $ 20.1 Accounts receivable 66.3 75.1 Inventories (Note 4) 13.2 13.6 Prepaids and other 6.7 4.7 Future income taxes 1.8 1.9 Derivative instruments assets (Note 5) 83.2 35.0 ------------ ------------ 198.7 150.4 Property, plant and equipment 1,037.1 1,052.9 Power purchase arrangements 436.4 453.2 Long-term investments 45.9 49.6 Goodwill 50.9 50.9 Future income taxes 2.2 - Derivative instruments assets (Note 5) 175.6 65.2 Other assets 29.5 30.2 ------------ ------------ $ 1,976.3 $ 1,852.4 ------------ ------------ ------------ ------------ LIABILITIES AND PARTNERS' EQUITY Current liabilities Accounts payable $ 66.7 $ 59.1 Distributions payable 33.9 33.9 Long-term debt due within one year 1.2 1.1 Derivative instruments liabilities (Note 5) 1.2 0.3 ------------ ------------ 103.0 94.4 Asset retirement obligations 24.0 23.2 Long-term debt 630.0 618.6 Derivative instruments liabilities (Note 5) 1.6 2.9 Contract liabilities 4.6 6.0 Future income taxes 96.9 79.6 Preferred shares issued by a subsidiary company 122.0 122.0 Partners' equity 994.2 905.7 Commitments (Note 9) ------------ ------------ $ 1,976.3 $ 1,852.4 ------------ ------------ ------------ ------------ See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Six months ended June 30 (unaudited) 2008 2007 --------------------------------------------- ------------- ------------ (In millions of dollars) Partnership capital Balance, beginning of period $ 1,197.1 $ 1,095.5 Issue of partnership units - 101.6 ------------- ------------ Balance, end of period $ 1,197.1 $ 1,197.1 ------------- ------------ ------------- ------------ Deficit Balance, beginning of period: As previously reported $ (296.5) $ (290.1) Adjustment for changes in accounting policies - 96.1 ------------- ------------ As restated (296.5) (194.0) Net income 158.3 1.5 Cash distributions (67.9) (65.4) ------------- ------------ Balance, end of period $ (206.1) $ (257.9) ------------- ------------ Accumulated other comprehensive income Balance, beginning of period $ 5.1 $ - Cumulative effect of adopting new accounting policies - 8.6 Other comprehensive loss (1.9) (1.8) ------------- ------------ Balance, end of period $ 3.2 $ 6.8 ------------- ------------ ------------- ------------ Total of deficit and accumulated other comprehensive income $ (202.9) $ (251.1) ------------- ------------ ------------- ------------ Partners' equity $ 994.2 $ 946.0 ------------- ------------ ------------- ------------ See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND LOSS Three months ended Six months ended June 30 June 30 (unaudited) 2008 2007 2008 2007 --------------------------------- --------- --------- --------- --------- (In millions of dollars) Net income (loss) $ 104.9 $ (68.0) $ 158.3 $ 1.5 Other comprehensive loss, net of income taxes Amortization of deferred gains on derivatives de-designated as cash flow hedges to income(1) (1.0) (0.9) (1.9) (1.8) --------- --------- --------- --------- Comprehensive income (loss) $ 103.9 $ (68.9) $ 156.4 $ (0.3) --------- --------- --------- --------- --------- --------- --------- --------- (1) Net of income tax of nil. See accompanying notes to the consolidated financial statements. EPCOR Power L.P. Notes to the Interim Consolidated Financial Statements June 30, 2008 (Unaudited) 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, 2007, except for the changes described in Note 2. These consolidated financial statements reflect all normal recurring adjustments that are, in management's opinion, necessary to present fairly the financial position and results of operations for the respective periods. These consolidated financial statements for the six months ended June 30, 2008 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 2007 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 on the Partnership's US dollar-denominated monetary assets and liabilities 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 management's opinion, 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 Commencing January 1, 2008, the Partnership adopted new accounting standards as issued by the Canadian Institute of Chartered Accountants (CICA) for Capital Disclosures, Financial Instruments - Disclosures and Presentation and Inventories. The new accounting standards have been applied prospectively and the comparative financial statements have not been restated. Capital disclosures The new standards require qualitative information about the Partnership's objectives, policies and processes for managing capital and quantitative data on the Partnership's capital, as discussed in Note 7 - Capital management. Financial instruments - presentation and disclosures These new standards establish requirements for the reporting and presentation of quantitative and qualitative information that is intended to provide users of the financial statements with additional insight into the Partnership's risks associated with financial instruments and how these risks are managed. These risks include credit, liquidity and market risks. The additional disclosures required under these new standards have been incorporated into these interim consolidated financial statements and discussed in Note 5 - Financial instruments and Note 6 - Risk management. Inventories The new standard requires inventories to be measured at the lower of cost and net realizable value and did not materially impact these consolidated financial statements. The additional disclosures required under the new standard have been incorporated into these consolidated financial statements and discussed in Note 4 - Inventories. Future accounting changes International financial reporting standards In February 2008, the CICA confirmed that Canadian reporting issuers will be required to report under International Financial Reporting Standards (IFRS) effective January 1, 2011, including comparative figures for the prior year. In April 2008, the CICA released an exposure draft of the coming standards. A high level IFRS implementation plan has been developed and an assessment of the impact of the accounting standard differences to the financial statements is currently in progress. Based on our analysis to date, the most significant differences for the Partnership are anticipated to be related to property, plant and equipment, joint arrangements, financial instruments and hedges, foreign currency translation, 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 to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes on the required implementation date. 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 IFRS provisions. The provisions relating to goodwill are unchanged from those of the replaced Section 3062 - Goodwill and Other Intangible Assets. These amendments are effective January 1, 2009. Note 3. Financial charges and other, net Three months ended Six months ended June 30 June 30 (millions of dollars) 2008 2007 2008 2007 ---------------------------------------- ---------- ---------- ---------- Interest on long-term debt $ 9.4 $ 8.8 $ 18.7 $ 18.1 Interest on short-term debt 0.2 1.8 0.3 4.9 Interest on capital lease obligations - 1.5 - 3.1 Dividend income from Class B preferred share interests in PERH (0.4) (0.4) (0.9) (0.8) Realized gains on interest rate contracts - (5.5) - (5.5) Fair value changes on interest rate contracts - 1.3 - 2.2 Other (0.1) 0.8 0.1 0.9 ---------- ---------- ---------- ---------- $ 9.1 $ 8.3 $ 18.2 $ 22.9 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Note 4. Inventories Inventories represent general stock and fuel, the majority of which are consumed by the Partnership in provision of its goods and services, and are valued at the lower of cost and net realizable value. Cost includes the purchase price, transportation costs and other costs to bring the inventories to their present location and condition. The cost of inventory items that are interchangeable are determined on an average cost basis. For inventory items that are not interchangeable, cost is assigned using specific identification of their individual costs. The carrying value of the Partnership's inventory is summarized below: June 30 December 31 (millions of dollars) 2008 2007 ----------------------------------------------------------- ------------- General stock $ 7.7 $ 5.6 Fuel 5.5 8.0 ------------- ------------- $ 13.2 $ 13.6 ------------- ------------- ------------- ------------- Inventories expensed in cost of fuel and other plant operating expenses were $10.4 million and $19.2 million for the three and six months ended June 30, 2008 ($9.4 million and $18.5 million for the three and six months ended June 30, 2007). No write-down of inventory or reversal of a previous write-down was recognized in the three and six months ended June 30, 2008 or in the same periods of 2007. As at June 30, 2008, no inventories were pledged as security for liabilities (December 31, 2007 - nil). Note 5. Financial instruments Fair values and classification of financial assets and liabilities The Partnership classifies its cash and cash equivalents and current and non-current derivative instruments assets and liabilities as held for trading and measures them at fair value. Accounts receivable are classified as loans and receivables and accounts payable and distributions payable are classified as other financial liabilities and are measured at amortized cost. The fair values of accounts receivable, accounts payable and distributions payable are not materially different from their carrying values due to their short-term nature. The preferred share interest in Primary Energy Recycling Holdings LLC (PERH) is classified as available for sale and the net investment in lease is classified as loans and receivables. The net investment in lease relates to the Oxnard PPA, which is considered a direct financing lease for accounting. The classification, carrying values and fair values of the Partnership's other financial instruments are summarized as follows: (millions of dollars) June 30, 2008 ------------------------------------------------------------------------- Carrying amount -------------------------------------------------------------- ---------- Other Total Loans and financial fair receivables liabilities Total value ------------------------------------- ---------- Other assets - net investment in lease $ 28.6 $ - $ 28.6 $ 27.9 Long-term debt (including current portion) - (631.2) (631.2) (588.6) ------------------------------------- ---------- (millions of dollars) December 31, 2007 ------------------------------------------------------------------------- Carrying amount -------------------------------------------------------------- ---------- Other Total Loans and financial fair receivables liabilities Total value ------------------------------------- ---------- Other assets - net investment in lease $ 28.6 $ - $ 28.6 $ 27.8 Long-term debt (including current portion) - (619.7) (619.7) (612.2) ------------------------------------- ---------- The fair value of the Partnership's long-term debt is based on determining an appropriate yield for the Partnership's debt as at June 30, 2008 and December 31, 2007. This yield is based on an estimated credit spread for the Partnership over the yields of long-term Government of Canada and US Government bonds that have similar maturities to the Partnership's debt. The estimated credit spread is based on the Partnership's indicative spread as published by independent financial institutions. The Partnership has used the carrying value of its common and preferred share interests held in PERH as their fair value as the shares are not quoted in an active market and their fair values therefore cannot be measured reliably. The shares have not been offered for sale and in the event the Partnership elected to dispose of the shares, they would most likely be sold in a private transaction. The fair value of the Partnership's net investment in the financing lease is based on the estimated interest rate implicit in a comparable lease arrangement plus an estimated credit spread based on the counterparty risk as at June 30, 2008 and December 31, 2007. Derivative instruments Derivative instruments are generally 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 instrument assets and derivative instrument 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 as described in Note 6 - Risk management consist of the following: (millions of dollars) June 30, 2008 ------------------------------------------------------------------------- Natural Foreign gas exchange non-hedges non-hedges Total -------------------------------------- Derivative instruments assets: Current $ 71.9 $ 11.3 $ 83.2 Non-current 162.0 13.6 175.6 Derivative instruments liabilities: Current - (1.2) (1.2) Non-current - (1.6) (1.6) -------------------------------------- $ 233.9 $ 22.1 $ 256.0 -------------------------------------- -------------------------------------- Net notional amounts: Gigajoules (GJs)(millions) 70 US foreign exchange (US dollars in millions) 325.6 Contract terms (years) 2 to 8 1 to 6 -------------------------------------- (millions of dollars) December 31, 2007 ------------------------------------------------------------------------- Natural Foreign gas exchange non-hedges non-hedges Total -------------------------------------- Derivative instruments assets: Current $ 20.7 $ 14.3 $ 35.0 Non-current 42.9 22.3 65.2 Derivative instruments liabilities: Current - (0.3) (0.3) Non-current - (2.9) (2.9) -------------------------------------- $ 63.6 $ 33.4 $ 97.0 -------------------------------------- -------------------------------------- Net notional amounts: Gigajoules (GJs)(millions) 75 US foreign exchange (US dollars in millions) 280.6 Contract terms (years) 3 to 9 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. The extent to which fair value of derivatives are based on observable market data is determined by the extent to which the market for the underlying commodity is judged to be active. With respect to natural gas, the Partnership has determined the market is active within five years. As the natural gas supply contracts extend beyond the active period of the market, fair value is determined by reference in part to published price quotations where there is observable market data and in part by relying on price forecasts prepared by an independent third party where there are limited observable natural gas prices. While external market forecasts outside the active period of the market reasonably reflect all factors that market participants would consider in setting a price, these expectations are not currently supportable by active forward market quotes. The fair values of these contracts could change significantly if the assumptions were changed to reasonably possible alternatives. The natural gas prices forecasts for the period where limited observable natural gas prices are available range from $9.80/GJ to $10.18/GJ. The Partnership has determined that a reasonably possible increase (decrease) of a $1.00/GJ in the natural gas price forecast where there are limited observable natural gas prices would have a $19.3 million impact on the fair value estimate of these contracts compared to a $60 million impact of $1.00/GJ increase (decrease) over the entire forecast period. This valuation technique resulted in unrealized pre-tax fair value gains of $32.8 million and $50.5 million recognized in fuel expense for the three and six months ended June 30, 2008 ($4.8 million fair value losses and $16.1 million fair value gains for the three and six months ended June 30, 2007). Unrealized and realized pre-tax gains and losses on derivative instruments recognized in net income were: Net gains Net gains (losses) for (losses) for the three months the six months (millions of dollars) ended June 30 ended June 30 --------------------------------------------------- --------------------- Income statement category 2008 2007 2008 2007 --------------------------------- --------------------- Foreign exchange non-hedges Revenue $ 9.0 $ 23.9 $ (2.2) $ 26.1 Natural gas Cost of non-hedges fuel 102.8 (59.8) 170.3 (15.5) Foreign exchange Foreign non-hedges exchange (gains) losses (0.2) (18.8) (0.2) (20.0) Interest rate Financial non-hedges charges and other, net - 4.2 - 3.3 --------------------------------- --------------------- Note 6. Risk management Risk management overview The Partnership is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments which include market, counterparty credit and liquidity risks. The Partnership's overall risk management process is designed to identify, manage and mitigate business risk which includes financial risk, among others. Financial risk is managed according to objectives, targets and policies set forth by the Board of Directors. Risk management strategies, policies and limits are designed to ensure the risk exposures are managed within the Partnership's business objectives and risk tolerance. The Partnership's risk management objective is to protect and minimize volatility in cash provided by operating activities and distributions therefrom. Market risk Market risk is the risk of loss that results from changes in market factors such as commodity prices, foreign currency exchange rates, interest rates and equity prices. The level of market risk to which the Partnership is exposed at any point in time varies depending on market conditions, expectations of future price or market rate movements and composition of the Partnership's financial assets and liabilities held, non-trading physical assets and contract portfolios. Commodity price risk management and the associated credit risk management are carried out in accordance with Partnership's financial risk management policies, as approved by the Board of Directors. To manage the exposure related to changes in market risk, the Partnership uses various risk management techniques including the use of derivative instruments. Derivative instruments may include financial and physical forward contracts. Such instruments may be used to establish a fixed price for an energy commodity, an interest-bearing obligation or an obligation denominated in a foreign currency. Market risk exposures are monitored regularly against approved risk limits and control process are in place to monitor that only authorized activities are undertaken. The sensitivities provided in each of the following risk discussions disclose the effect of reasonably possible changes in relevant prices and rates on net income at the reporting date. The sensitivities are hypothetical and should not be considered to be predictive of future performance or indicative of earnings on these contracts. The Partnership's actual exposure to market risks is constantly changing as the Partnership's portfolio of debt, foreign currency and commodity contracts change. Changes in fair value based on market variable fluctuations cannot be extrapolated as the relationship between the change in the market variable and the change in fair value may not be linear. In addition, the effect of a change in a particular market variable on fair values or cash flows is calculated without considering interrelationships between the various market rates or mitigating actions that would be taken by the Partnership. Commodity price risk The Partnership is exposed to commodity price risk as part of its normal business operations, particularly in relation to the prices of electricity, natural gas and coal. The Partnership actively manages commodity price risk by optimizing its asset and contract portfolios in the following manner: - The Partnership commits substantially all of its power supply to long-term fixed price PPAs with investment grade power buyers, which limits the exposure to electricity prices; - The Partnership purchases natural gas under long-term fixed price supply contracts to reduce the exposure to natural gas prices on its natural gas-fired generation plants; and - The Partnership has entered into PPAs whereby the counterparty is responsible for providing the natural gas or variable costs linked to the price of natural gas or coal are born by the counterparty. The fair value of the Partnership's commodity related derivatives as at June 30, 2008, that are required to be measured at fair value with the respective changes in fair value recognized in net income, are disclosed in Note 5 - Financial instruments. The following represents the sensitivity of net income to derivative instruments that are accounted for on a fair value basis. As at June 30, 2008, with all other variables unchanged, a $1.00/GJ increase (decrease) of the natural gas price is estimated to increase (decrease) net income by approximately $51 million after tax. This assumption is based on the volumes or position held at June 30, 2008. There would be no impact to other comprehensive income. Foreign exchange risk The Partnership is exposed to foreign exchange risk on foreign currency denominated forecasted transactions, firm commitments and monetary assets and liabilities (transactional exposure). The Partnership operates in the US and therefore, foreign exchange risk exposures arise from transactions denominated in US dollars. The risk is that the Canadian dollar value of US dollar cash flows will vary as a result of the movements in exchange rates. The Partnership's foreign exchange management policy is to minimize economic and material transactional exposures arising from movements in the Canadian dollar against the US dollar. The Partnership's foreign currency exposure arises from future anticipated US dollar denominated cash flows from its US energy operations and from debt service obligations on US dollar borrowings. The Partnership coordinates and manages foreign currency risk through the General Partner's central Treasury function. Foreign exchange risk is managed by considering naturally occurring opposite movements wherever possible and then managing any material residual foreign currency exchange risks according to the policies approved by the Board of Directors. The Partnership primarily uses foreign currency forward contracts to fix the Canadian currency equivalent of its US currency cash flows thereby reducing its anticipated US denominated transactional exposure. The Partnership's foreign currency risk management practice is to ensure a majority of the net currency exposure on anticipated transactions within 7 years be economically hedged. At June 30, 2008, US$325.6 million or approximately 76% of future anticipated net cash flows from its US plants were economically hedged for 2008 to 2014 at a weighted average rate of $1.10 to US $1.00. The following table summarizes the non-derivative and derivative financial instruments denominated in US dollars: June 30 December 31 (millions of US dollars) 2008 2007 ----------------------------------------------------------- ------------- Non-derivative financial instruments: Cash and cash equivalents 24.9 11.0 Accounts receivable 48.7 41.9 Accounts payable (37.8) (37.6) Other assets - net investment in lease 28.0 28.8 Long-term debt (415.0) (415.0) ------------- ------------- $ (351.2) $ (370.9) ------------- ------------- ------------- ------------- Derivative financial instruments: Forward foreign exchange sales (395.5) (352.2) Forward foreign exchange purchases 69.9 71.6 ------------- ------------- $ (325.6) $ (280.6) ------------- ------------- ------------- ------------- Net exposure (676.8) (651.5) --------------------------- --------------------------- Significant exchange rates in Canadian dollars per US dollar: Average reporting date closing 1.02 0.99 Average forward rate inherent in sales contracts 1.09 0.90 Average forward rate inherent in purchase contracts 1.05 0.96 --------------------------- --------------------------- As at June 30, 2008, holding all other variables constant, a $0.10 strengthening (weakening) of the Canadian dollar against the US dollar would increase (decrease) net income by approximately $59 million after tax. There would be no impact to other comprehensive income. Interest rate risk The Partnership is exposed to changes in interest rates on its cash and cash equivalents and floating rate short-term and long-term obligations. The Partnership is exposed to interest rate risk from the possibility that changes in the interest rates will affect future cash flows or the fair values of its financial instruments. In some circumstances, floating rate funding may be used for short-term borrowings and other liquidity requirements. The Partnership may also use derivative instruments to manage interest rate risk. At June 30, 2008 the Partnership did not hold any floating rate debt or interest rate derivative instruments. Holding all other variables constant and assuming that the amount and mix of floating rate debt remains unchanged from that held at June 30, 2008, a 1% change to interest rates would not have an impact on net income or other comprehensive income. Equity price risk The Partnership is exposed to changes in equity prices arising from its 14.2% preferred share interest in PERH which is classified as an available for sale financial asset. The investment in PERH is carried at the original exchange amount less any impairment because the PERH shares are not quoted in an active market and therefore fair value cannot be measured reliably. Refer to Note 5 - Financial instruments for disclosures on available for sale financial assets. Counterparty credit risk The Partnership has exposure to credit risk associated with counterparty default under the Partnership's power and steam sales contracts, energy supply agreements and foreign currency hedges. In the event of a default by a counterparty, existing PPAs and energy supply agreements may not be replaceable on similar terms as pricing in many of these agreements is favourable relative to their current markets. Counterparty credit risk is associated with the ability of counterparties to satisfy their contractual obligations to the Partnership, including payment and performance. Counterparty credit risk is managed by making appropriate credit assessments of counterparties on an ongoing basis, dealing with creditworthy counterparties, diversifying the risk by using several counterparties and where appropriate and contractually allowed, requiring the counterparty to provide appropriate security. Maximum credit risk exposure The Partnership has the following financial assets that are exposed to credit risk: (millions of dollars) June 30, 2008 ------------------------------------------------------------------------- Canada US Total -------------------------------------- Trade receivables $ 19.8 $ 46.5 $ 66.3 Other assets - net investment in lease - 28.6 28.6 Derivative instrument assets - current 83.2 - 83.2 Derivative instrument assets - non-current 175.6 - 175.6 -------------------------------------- $ 278.6 $ 75.1 $ 353.7 -------------------------------------- -------------------------------------- The maximum credit exposure of these assets is their carrying value. No amounts were held as collateral at June 30, 2008. Accounts receivable Accounts receivable consist primarily of amounts due from customers including industrial and commercial customers, government-owned or sponsored entities, regulated public utility distributors and other counterparties. Historically the Partnership has not experienced credit losses and accordingly has not provided for an allowance for doubtful accounts. The Partnership evaluates the need for an allowance for potential credit losses by reviewing any overdue accounts and monitoring changes in the credit profiles of counterparties. The Partnership mitigates its credit risk exposures by dealing with creditworthy counterparties and, where appropriate, taking back appropriate security from the counterparty. At June 30, 2008, no material accounts receivable were past due and there was no provision for credit losses associated with receivables and financial derivative instruments as all balances are considered to be fully recoverable. Liquidity risk Liquidity risk is the risk that the Partnership will not be able to meet its financial obligations as they come due. The Partnership's liquidity is managed centrally through the General Partner's central Treasury function. The Partnership manages liquidity through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and matching the maturity profiles of financial assets and liabilities to identify financing requirements. The financing requirements are addressed through a combination of committed and demand, revolving credit facilities and access to capital markets. As at June 30, 2008, the Partnership had undrawn, committed bank borrowing facilities of $300.0 million with remaining terms of approximately two years. The Partnership also has a long-term debt rating of BBB+ and BBB (high), assigned by Standard and Poor's (S&P) and DBRS Limited (DBRS) respectively. In addition, on July 10, 2008, the Partnership renewed its Canadian shelf prospectus under which it may raise up to $1.0 billion in partnership units or debt securities, of which a maximum of $600.0 million can be medium term notes. The Canadian shelf prospectus expires in August 2010. The following are the undiscounted cash flow requirements and contractual maturities of the Partnership's financial liabilities, including interest payments as at June 30, 2008: ------------------------------------------------------------------------- Between Between Between Between (millions Within 1 & 2 2 & 3 3 & 4 4 & 5 Beyond of dollars) 1 year years years years years 5 years Total ------------------------------------------------------------------------- Non-derivative financial liabilities: Long-term debt(1) $ 1.2 $ 1.3 $ 0.7 $ - $ - $ 633.2 $ 636.4 Interest payments on long-term debt 37.8 37.7 37.5 37.5 37.5 363.5 551.5 Accounts payable and accrued liabilities(2) 54.7 - - - - - 54.7 Distributions payable 33.9 - - - - - 33.9 Derivative financial liabilities: Net forward exchange contracts $ 1.2 $ 0.9 $ 0.1 $ 0.3 $ 0.2 $ 0.1 $ 2.8 ------------------------------------------------------------------------- Total $ 128.8 $ 39.9 $ 38.3 $ 37.8 $ 37.7 $ 996.8 $1,279.3 --------------------------------------------------------- --------------------------------------------------------- (1) Excluding deferred financing charges of $5.2 million. (2) Excluding interest on long-term debt of $10.8 million and non-cash accruals of $1.2 million. Note 7. Capital management The Partnership's primary objectives when managing capital are to safeguard the Partnership's ability to continue as a going concern, provide stable distributions to unitholders, to maintain an investment grade credit rating and to facilitate the acquisition or development of power projects in Canada and the United States consistent with the growth strategy of the Partnership. The Partnership manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. This overall objective and policy for managing capital remained unchanged in the second quarter of 2008 from the prior comparative period. The Partnership considers its capital structure to consist of long-term debt, preferred shares and partners' equity. The following table represents the total capital of the Partnership: June 30 December 31 (millions of dollars) 2008 2007 ----------------------------------------------------------- ------------- Long-term debt $ 631.2 $ 619.7 Preferred shares 122.0 122.0 Partners' equity 994.2 905.7 ------------- ------------- Total capital $ 1,747.4 $ 1,647.4 ------------- ------------- The Partnership's credit and stability ratings are presented in the following table: June 30 December 31 2008 2007 ----------------------------------------------------------- ------------- Credit rating S&P BBB+ BBB+ DBRS BBB(high) BBB(high) Stability rating S&P SR-2 SR-2 DBRS STA-2 STA-2 ------------- ------------- The Partnership has the following externally imposed requirements on its capital: - The Partnership must maintain a debt to total capitalization ratio, as defined in the debt agreements, of not more than 65%; and - In the event the Partnership is assigned a rating of less than BBB+ by S&P and BBB(high) by DBRS, the Partnership also would be required to maintain a ratio of earnings before interest, income taxes, depreciation and amortization to interest expense of not less than 2.5 to 1. During the period the Partnership complied with all externally imposed capital restrictions. In order to manage the capital structure, the Partnership may adjust the amount of distributions paid to unitholders, issue or redeem preferred shares, issue or repay debt or issue or buy back partnership units. Note 8. 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, New Jersey, New York, North Carolina and Washington. Geographic information (millions of Three months ended June 30 Three months ended June 30 dollars) 2008 2007 ------------------------------------------- ----------------------------- Canada US Total Canada US Total ------------------------------------------- ----------------------------- Revenue $ 60.5 $ 86.8 $ 147.3 $ 73.1 $ 92.2 $ 165.3 ----------------------------- ----------------------------- ----------------------------- ----------------------------- (millions of Six months ended June 30 Six months ended June 30 dollars) 2008 2007 ------------------------------------------- ----------------------------- Canada US Total Canada US Total Revenue $ 105.8 $ 162.9 $ 268.7 $ 130.9 $ 177.3 $ 308.2 ----------------------------- ----------------------------- ----------------------------- ----------------------------- (millions of dollars) As at June 30, 2008 As at December 31, 2007 ------------------------------------------- ----------------------------- Canada US Total Canada US Total ------------------------------------------- ----------------------------- Assets PP&E $ 569.1 $ 468.0 $1,037.1 $ 581.3 $ 471.6 $1,052.9 PPAs 41.2 395.2 436.4 42.8 410.4 453.2 Other assets - 29.5 29.5 - 30.2 30.2 Goodwill - 50.9 50.9 - 50.9 50.9 ----------------------------- ----------------------------- Total assets $ 610.3 $ 943.6 $1,553.9 $624.1 $ 963.1 $1,587.2 ----------------------------- ----------------------------- ----------------------------- ----------------------------- Note 9. Commitments The Partnership has committed up to US$80 million for the enhancement of the Southport and Roxboro facilities, to be spent over 2008 and 2009. Note 10. 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: Mike Gibbs, (780) 412-8877; Unitholder & Analyst
Inquiries: Randy Mah, (780) 412-4297; Toll Free, (866) 896-4636

Organization Profile

EPCOR POWER L.P.

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