EPCOR Power L.P. reports fourth quarter and year-end results



    EDMONTON, March 6 /CNW/ - (TSX: EP.UN) - EPCOR Power Services Ltd., the
general partner of EPCOR Power L.P. (the Partnership), today released the
Partnership's quarterly and year-end results for the period ended December 31,
2007.
    "Financial performance for 2007, as measured by cash provided by
operating activities, was generally in line with our expectations, excluding
the one-time forward contract losses that were realized to hedge the foreign
exchange and interest rate risks on the Primary Energy Ventures LLC (Ventures)
acquisition," said Brian Vaasjo, President of EPCOR Power Services Ltd. "In
the fourth quarter, cash provided by operating activities was slightly behind
plan due to lower water flows at our Curtis Palmer facility and lower than
forecast natural gas prices which reduced the opportunities to curtail
electricity production and re-sell the natural gas at our Ontario facilities."
    "While 2007 has been a difficult year for both the Partnership and the
power trust sector generally due to the federal government's tax legislation
on specified investment flow-through entities and the resulting impact on unit
values and consolidation of industry peers, I am satisfied with the steps we
have taken to improve our competitive position over the long-term. During the
past year, the Partnership completed a number of initiatives to reduce
potential risks on future cash flows. This includes positioning the
organization to be competitive in a post-2010 tax environment and securing
permanent financing for acquisitions made in 2006. The Partnership also
removed litigation risk by successfully negotiating settlements with two
natural gas suppliers relating to the Tunis power plant. Finally, we completed
the integration of Ventures, giving us a platform for growth in the U.S."
    "As we enter 2008, there a number of exciting opportunities for both
organic earnings growth from existing facilities as well as new project
developments that we are continuing to pursue that we believe can provide
meaningful financial upside for the Partnership."
    The Partnership reported cash provided by operating activities of
$39.0 million or $0.72 per unit(1) for the three months ended December 31,
2007 compared with $36.2 million or $0.73 per unit for the same period in
2006. The increase reflects a $7.9 million decrease in working capital
requirements primarily due to the seasonal nature of Ventures operations
acquired in the fourth quarter last year, partially offset by lower earnings
from the Curtis Palmer and Ontario facilities.
    Cash provided by operating activities of $132.2 million or $2.53 per unit
for the twelve months ended December 31, 2007 was lower than the
$153.9 million or $3.17 per unit for the same period in 2006. In addition to
reduced cash flow from Curtis Palmer, the decrease reflects net realized
losses on foreign exchange and interest rate contracts. These contracts were
used to hedge changes in interest rates and foreign exchange rates on the
Ventures US dollar bridge acquisition facilities that were replaced by a US
private placement in August 2007. The losses were primarily driven by the
declining US treasury rates and the strengthening of the Canadian dollar
versus the US dollar. However, consistent with the nature of a hedge, this
allowed for a reduced fixed term rate on the new long-term debt financing and
a larger pay down on the bridge acquisition facilities from the Canadian
dollar equity offerings. As a result, the net realized losses will be offset
by lower financing charges and debt repayments in future periods.
    Highlights of EPCOR Power L.P.'s operational and financial performance
included:

    
    -------------------------------------------------------------------------
    Operational and
    Financial Highlights              Three months ended  Twelve months ended
    (unaudited)                           December 31         December 31
    -------------------------------------------------------------------------
    (millions of dollars except per
     unit and operational amounts)        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Power generated (GWh)                1,378     1,124     5,456     3,399
    -------------------------------------------------------------------------
    Weighted average plant
     availability                          95%       97%       94%       95%
    -------------------------------------------------------------------------
    Revenue                              117.6     105.3     579.2     350.2
    -------------------------------------------------------------------------
    Net income (loss)                     45.3     (12.9)     30.8      62.1
    -------------------------------------------------------------------------
      Per unit                           $0.89    $(0.26)    $0.59     $1.28
    -------------------------------------------------------------------------
    Comprehensive income                  44.4         -      27.3         -
    -------------------------------------------------------------------------
    Cash provided by operating
     activities                           39.0      36.2     132.2     153.9
    -------------------------------------------------------------------------
      Per unit(1)                        $0.72     $0.73     $2.53     $3.17
    -------------------------------------------------------------------------
    Cash distributions                    34.0      31.4     133.3     124.2
    -------------------------------------------------------------------------
      Per unit                           $0.63     $0.63     $2.52     $2.52
    -------------------------------------------------------------------------
    Capital expenditures                   4.6       9.0      12.5      13.2
    -------------------------------------------------------------------------
    Weighted average units
     outstanding (millions)               53.9      49.9      52.2      48.5
    -------------------------------------------------------------------------

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

    The December 31, 2007 annual report is shown below. The management's
discussion and analysis and consolidated financial statements are available on
the EPCOR Power L.P. website (www.epcorpowerlp.ca) and will be available on
SEDAR (www.sedar.com).


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    This management's discussion and analysis (MD&A), dated March 4, 2008
should be read in conjunction with the accompanying audited consolidated
financial statements of EPCOR Power L.P. (the Partnership) for the years ended
December 31, 2007 and 2006. In accordance with its terms of reference, the
Audit Committee of the General Partner's Board of Directors reviews the
contents of the MD&A and recommends its approval by the Board of Directors.
The Board of Directors has approved this MD&A.

    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,
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.

    OPERATION OF THE PARTNERSHIP

    EPCOR Power Services Ltd., the General Partner of the Partnership and 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 Partnership's power plants use natural gas, fuel oil, waste heat,
wood waste, coal, tire derived fuel, water flows or a combination of these
energy sources to produce electricity.

    STRATEGY

    The Partnership's strategic plan continues to be focused on providing
stable and sustainable distributions to unitholders. Where opportunities
arise, the Partnership will also seek to grow its asset base by expanding
capacity at existing plants and pursuing acquisition or development
opportunities that meet the Partnership's investment criteria. These criteria
include generation assets that have relatively stable and predictable cash
flows, contracts with creditworthy counterparties, risk profiles similar to
the assets already owned by the Partnership with predictable capital
expenditures and long operating lives.

    SIGNIFICANT EVENTS

    NAL and Devon claims

    Settlements were reached with Devon Canada Corporation (Devon) in July
2007 and NAL Resources Ltd. (NAL) in January 2008 in respect of their claims
of frustration of the contract pursuant to which they supply natural gas to
the Partnership's Tunis, Ontario plant. Based on the settlements reached with
NAL and Devon, the Partnership made payments of $7.8 million over what it
would have otherwise made under the previous contract terms, of which
$3.1 million was accrued at the end of 2006. Under amended terms of the
natural gas supply contracts for Tunis, natural gas prices are at fixed rates
that escalate 4% per annum. The Partnership expects that its cost for natural
gas for Tunis will increase by approximately $6 million in each of 2008 and
2009 and by $3 million in 2010 from what it would otherwise have been under
the previous contract terms. The Partnership has incorporated anticipated
increases in fuel supply prices into the determination of the fair value of
derivative instruments at December 31, 2007. Had claims by NAL and Devon been
successful, natural gas supplying the Partnership's Tunis plant would have
been purchased at prevailing market prices for the period 2003 to 2010 and the
Partnership estimates that the total resulting incremental cost would have
been in excess of $100 million.

    Change in tax law

    Canadian tax legislation (referred to hereafter as SIFT Legislation)
related to specified investment flow-through entities (SIFTs) included in
Bill C-52 was enacted in 2007 and will result in changes to how certain
publicly traded trusts and partnerships, including the Partnership, are taxed.
Enactment of the SIFT Legislation resulted in the recognition of future income
tax amounts based on estimated net taxable temporary differences of
$186 million which are expected to reverse after 2010 and for which no tax had
previously been recorded in the Partnership's financial statements.
Accordingly, an estimated future income tax expense and a net future income
tax liability of $78.2 million were recognized in 2007.
    Revised Canadian tax legislation, including the reduction in federal tax
rates, was enacted on the passing of Bill C-28 on December 13, 2007. The
federal rates will reduce from 19.5% in 2008 to 15.0% by 2012. These federal
tax rate reductions also reduce the tax rate applicable to SIFTs from 31.5% to
29.5% starting in 2011 and to 28.0% in 2012 and future years. The total impact
of the tax rate reductions on the Partnership was a decrease to future income
tax liability and income tax expense of $8.7 million.
    The Canadian 2008 federal budget (Budget) tabled February 26, 2008
includes a change in the calculation of the SIFT rate. Previously, the SIFT
rate was calculated as the federal rate plus a notional 13% provincial rate.
The Budget proposes to replace the notional provincial component of the SIFT
rate with the applicable provincial rates. The adjustment to the SIFT rate
combined with the change proposed by the 2008 BC budget tabled February 19,
2008 to reduce the Provincial corporate rate from 12% to 10% by 2011 will
reduce the Partnership's future income tax liability and income tax expense by
a range of approximately $5 million to $7 million if enacted.

    Issue of preferred shares

    In May 2007, a subsidiary of the Partnership issued 5 million of 4.85%
cumulative, redeemable Preferred Shares, Series 1 priced at $25.00 per share
with dividends payable on a quarterly basis at the annual rate of $1.2125 per
share. Net proceeds of $120.8 million were used to repay amounts outstanding
under the bridge acquisition credit facility, due in October 2007, incurred in
conjunction with the Partnership's acquisition of Primary Energy Ventures LLC
(now EPCOR Ventures USA LLC) (Ventures) in November 2006. On or after June 30,
2012, the shares are redeemable, at $26.00 per share, declining by $0.25 each
year to $25.00 per share after June 30, 2016, by the subsidiary company. The
shares are not retractable by the shareholders.

    Unit offering

    In May 2007, the Partnership issued 4,015,297 units, priced at $26.15 per
unit, to the public and EPCOR for net proceeds of $101.6 million, to repay
amounts outstanding under the bridge acquisition credit facility which was
otherwise due in October 2007, and a portion of the bridge acquisition credit
facility which was otherwise due in October 2009, all incurred in conjunction
with the Partnership's acquisition of Ventures in November 2006.

    Long-term debt issued

    On August 15, 2007, the Partnership completed a private placement in the
United States (US) of senior unsecured notes in the aggregate principal amount
of $240.0 million (US$225.0 million). The notes were issued in two tranches
consisting of 10 and 12 year maturities. The $160.0 million (US$150.0 million)
in 10-year notes have a coupon rate of 5.87% and the $80.0 million
(US$75.0 million) in 12-year notes have a coupon rate of 5.97%. Net proceeds
of the offering were used primarily to repay existing long-term debt,
including the amounts initially borrowed as part of the Ventures and
Frederickson Power L.P. (Frederickson) acquisitions and capital lease
obligations assumed as part of the Ventures acquisition.

    Capital lease obligations

    On August 24, 2007, the Partnership paid down its capital lease
obligations on North Island, Naval Training Center and Naval Station in
California with proceeds from the August 15, 2007 US private placement of
senior unsecured notes. Extinguishment of the leases is expected to provide
the Partnership more flexibility in making operational changes at the
facilities without consent of the lessor and provides the Partnership the
economic benefits of the assets past the lease term. Additionally, it replaces
lease payments of approximately $10.0 million per annum to the end of 2010 and
an average of $6.0 million per annum from the start of 2011 to 2020 with
interest payments of $4.2 million per annum and principal payments of
$71.7 million in 2019.

    Asset impairment charge

    On the acquisition of Ventures, the Partnership allocated $13.6 million
of the purchase price to management agreements with the expectation that it
would receive incentive payments from Primary Energy Recycling Holdings LLC
(PERH) based on forecasted PERH cash distributions. In the third quarter, the
Partnership made a downward revision to its estimate of future incentive
payments under the management agreement attributed to expectations of lower
cash distributions from PERH, resulting in the write-off of this management
agreement asset. Accordingly, a $13.0 million asset impairment charge was
recorded in the third quarter of 2007.

    
    POWER AND STEAM GENERATION CAPACITY                      POWER     STEAM
                                          Energy Source        (MW) (MLBS/HR)
    -------------------------------------------------------------------------
    Ontario Plants
      Nipigon(1)                     Natural gas/waste heat     40         -
      North Bay(1)                   Natural gas/waste heat     40         -
      Kapuskasing(1)                 Natural gas/waste heat     40         -
      Tunis(1)                       Natural gas/waste heat     43         -
      Calstock(1)(2)                 Wood waste/waste heat      35         -
    Williams Lake(2)                       Wood waste           66         -
    Mamquam and Queen Charlotte(3)         Water flows          56         -
    Northwest U.S. Plants
      Manchief(4)                          Natural gas         300         -
      Greeley(6)(9)                        Natural gas          72       170
      Frederickson(5)                      Natural gas         125         -
    California Plants
      Naval Station(7)(9)             Natural gas/fuel oil      47       479
      North Island(6)(9)                   Natural gas          40       390
      Naval Training Center(7)(9)     Natural gas/fuel oil      25       220
      Oxnard(6)(9)                         Natural gas          49       120
    Curtis Palmer(3)                       Water flows          60         -
    Northeast U.S Gas Plants
      Castleton(5)                         Natural gas          64         -
      Kenilworth(6)(9)                     Natural gas          30        78
    North Carolina Plants
      Southport(8)(9)               Coal/tire derived fuel/
                                           wood waste          103     1,080
      Roxboro(8)(9)                 Coal/tire derived fuel/
                                           wood waste           52       540
    -------------------------------------------------------------------------

    (1) The Ontario natural gas plants use a process called enhanced combined
        cycle generation that uses both natural gas and waste heat as energy
        sources. These plants and the Calstock plant are located adjacent to
        TransCanada's Canadian Mainline gas compressor stations.
    (2) The Williams Lake and Calstock plants use wood waste from local mills
        as their primary source of energy.
    (3) The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric
        facilities rely on water flows to produce electricity.
    (4) The Manchief plant is a simple-cycle, natural gas generating
        facility.
    (5) The Castleton and Frederickson facilities are combined cycle natural
        gas plants. Capacity for Frederickson is the Partnership's 50.15%
        interest.
    (6) The Greeley, North Island, Oxnard and Kenilworth facilities are
        natural gas combined heat and power facilities.
    (7) The Naval Station and Naval Training Center facilities are dual fuel
        (natural gas and No. 2 distillate fuel oil) fired combined heat and
        power facilities.
    (8) The Southport and Roxboro combined heat and power facilities are
        fueled by coal, tire derived fuel and waste wood.
    (9) The following facilities were acquired as part of the Ventures
        transaction: Greeley, Naval Station, North Island, Naval Training
        Center, Oxnard, Kenilworth, Southport and Roxboro.

    Each of the Partnership's 20 power plants has long-term Power Purchase
Arrangements (PPAs) with contract expiry dates ranging from June 2008 to
approximately 2027. Seven of these power plants also have steam purchase
agreements (SPAs) with expiry dates ranging from 2009 to 2020. The existence
of long-term sales contracts combined with long-term energy supply and
operating contracts reduces the financial risk to unitholders, minimizes
commodity price risk and increases the stability and security of long-term
cash flows.

    Consolidated Results-at-a-Glance (1)

    Years ended December 31                       2007       2006       2005
    -------------------------------------------------------------------------
    (millions of dollars except unit and per
     unit amounts)
    Revenues
      Ontario Plants                             152.3      155.7      148.8
      Williams Lake                               38.1       39.5       36.5
      Mamquam and Queen Charlotte                 18.0       15.7       15.4
      Northwest US Plants(2)                      60.7       38.7       26.6
      California Plants(2)                       130.6       20.5          -
      Curtis Palmer                               31.7       50.9       53.5
      Northeast US Gas Plants(2)                  57.7       28.6       14.9
      North Carolina Plants(2)                    52.3        5.6          -
      PERC management and incentive fees(2)        3.4        0.6          -
      Fair value changes on foreign
       exchange contracts                         34.4       (5.6)         -
                                              ---------  ---------  ---------
                                                 579.2      350.2      295.7

    Operating margin(1)
      Ontario Plants                              74.4       82.9       82.8
      Williams Lake                               24.9       25.5       23.6
      Mamquam and Queen Charlotte                 11.2       11.1       10.7
      Northwest US Plants(2)                      39.7       25.9       20.2
      California Plants(2)                        29.0        2.1          -
      Curtis Palmer                               26.5       45.0       47.1
      Northeast US Gas Plants(2)                  11.8        7.8        8.0
      North Carolina Plants(2)                     2.5       (2.0)         -
      PERC management and incentive fees(2)        1.8        0.5          -
                                              ---------  ---------  ---------
                                                 221.8      198.8      192.4

      Fair value changes on foreign
       exchange contracts                         34.4       (5.6)         -
      Fair value changes on natural gas
       contracts                                 (32.4)         -          -
                                              ---------  ---------  ---------
                                                 223.8      193.2      192.4

    Net income                                    30.8       62.1       86.5
      Per unit                                   $0.59      $1.28      $1.83

    Cash provided by operating activities        132.2      153.9      146.7
      Per unit(1)                                $2.53      $3.17      $3.09

    Capital expenditures                          12.5       13.2       14.4

    Long-term debt                               619.7      718.1      436.7

    Cash distributions(3)                        133.3      124.2      119.5
      Per unit                                   $2.52      $2.52      $2.52

    Total assets                               1,852.4    1,883.4    1,316.3

    Weighted average units outstanding
     (millions)                                   52.2       48.5       47.4
    -------------------------------------------------------------------------

    (1) The selected three-year annual financial data has been prepared in
        accordance with Canadian generally accepted accounting principles
        except for operating margin and cash provided by operating activities
        per unit. See "Non-GAAP measures".
    (2) From the dates of acquisition: Frederickson - August 1, 2006;
        Ventures - November 1, 2006.
    (3) Cash distributions for the year ended December 31, 2006 include a
        $1.5 million payment in August 2006 on the subscription receipts
        issued in the acquistion of Frederickson.
    

    Operating margin excluding fair value changes in foreign exchange and
natural gas supply contracts for the year ended December 31, 2007 increased by
$23.0 million. The increase is primarily due to additional operating margin of
$46.7 million for the year from the Frederickson and Ventures operations,
acquired in the third and fourth quarters of 2006 respectively. Offsetting
these increases are lower generation and pricing at Curtis Palmer resulting in
a decline in operating margin of $18.5 million for the year ended December 31,
2007 compared to the prior year. In addition, an Ontario Electricity Financial
Corporation (OEFC) settlement, net of related accruals for additional costs on
the natural gas supply contracts, recorded in 2006 resulted in a decrease of
$6.2 million in the year ended December 31, 2007 compared to the prior year.
    On January 1, 2007 the Partnership implemented new accounting standards
which resulted in the Partnership's long-term natural gas supply contracts
being recorded at fair value (see Changes in Accounting Policies). The
Partnership recorded a decline in the fair value of the natural gas supply
contracts for the year ended December 31, 2007. 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.

    
    CONSOLIDATED RESULTS OF OPERATIONS

    -------------------------------------------------------------------------
    (millions of dollars)
    -------------------------------------------------------------------------
    Cash provided by operating activities for the year
     ended December 31, 2006                                           153.9
    -------------------------------------------------------------------------
    Contribution of the Ventures facilities, acquired
     November 1, 2006, excluding interest paid and foreign
     exchange contract losses                                           34.7
    Contribution of Frederickson, acquired August 1, 2006,
     excluding interest paid                                             8.4
    Increase in generation and revenue at Manchief                       2.6
    Mamquam and Queen Charlotte arbitration award                        2.3
    Net realized losses upon settlement of foreign exchange
     and interest rate contracts                                       (17.9)
    Higher financial charges due to acquisitions in 2006               (14.5)
    Decrease in cash flow from Curtis Palmer                           (11.7)
    Changes in operating working capital                                (7.4)
    One-time OEFC settlement, net of natural gas contract
     accruals, in 2006                                                  (6.2)
    Increase in cash taxes                                              (5.2)
    Preferred share dividends                                           (4.0)
    Tunis fuel supply settlement                                        (2.3)
    Other                                                               (0.5)
    -------------------------------------------------------------------------
    Cash provided by operating activities for the year ended
     December 31, 2007                                                 132.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Partnership reported cash provided by operating activities of
$132.2 million or $2.53 per unit for the year ended December 31, 2007 compared
to $153.9 million or $3.17 per unit in 2006. Cash provided by operating
activities per unit is defined below under non-GAAP measures. The
$21.7 million decrease in cash provided by operating activities compared to
2006 is primarily due to the following:

    -   Net realized losses of $17.9 million on foreign exchange and interest
        rate contracts that were entered in anticipation of permanent
        financing of the Ventures bridge acquisition facilities. The foreign
        exchange hedges were used to hedge changes in foreign exchange rates
        on the portion of the US dollar credit and bridge facilities that
        were replaced with Canadian dollar equity offerings. Losses on the
        foreign exchange contracts were primarily driven by the strengthening
        of the Canadian dollar versus the US dollar. The stronger Canadian
        dollar allowed for a larger pay down of US dollar bridge acquisition
        financing from the Canadian dollar equity offerings. The interest
        rate contracts were used to hedge changes in interest rates on the
        portion of the credit facilities and bridge facilities that were
        replaced by long-term fixed rate debt. Declining long-term US
        treasury rates resulted in a loss on the interest rate contracts but
        also reduced the fixed term rate that was entered into on the US
        private placement in August 2007, consistent with the nature of a
        hedge. As a result, net realized losses will be offset by lower
        financing charges and debt repayments in future periods;
    -   Higher interest expense of $14.5 million compared to the prior year
        was due to additional debt incurred to finance the purchases of
        Ventures and Frederickson and the assumption of capital leases on the
        Ventures acquisition, which were repaid during 2007;
    -   Lower generation at Curtis Palmer due to the return to historic
        annual average water volumes was the primary cause of the
        $11.7 million decrease in the plant's operating cash flow;
    -   A $5.9 million increase in working capital requirements in 2007
        compared to a $1.5 million decrease in 2006 in part due to the
        payment in 2007 of accrued amounts to Devon in respect of a gas
        contract settlement agreement;
    -   The one-time settlement with OEFC of $9.8 million in the first
        quarter of 2006 partially offset by accruals for natural gas
        contracts;
    -   Cash taxes increased by $5.2 million primarily due to an increase in
        US withholding taxes;
    -   Dividends of $4.0 million paid on preferred shares issued by a
        subsidiary company in May 2007; and
    -   Settlements reached with the natural gas suppliers at Tunis in 2007
        resulting in an increase in fuel costs of $2.3 million.

    Decreases were partially offset by:

    -   An increase of $34.7 million in the contribution from Ventures,
        acquired on November 1, 2006, excluding financing costs and realized
        losses on foreign exchange contracts;
    -   An increase of $8.4 million in the contribution from Frederickson,
        acquired on August 1, 2006, excluding financing costs;
    -   An increase in generation and revenue at Manchief due to low natural
        gas prices in Colorado; and
    -   A $2.3 million arbitration award against the previous owners of Queen
        Charlotte and Mamquam in respect of claims by the Partnership in the
        purchase and sale agreement.


    -------------------------------------------------------------------------
    (millions of dollars)
    -------------------------------------------------------------------------
    Cash provided by operating activities for the year ended
     December 31, 2005                                                 146.7
    -------------------------------------------------------------------------
    Changes in operating working capital                                12.1
    Contribution of Frederickson excluding interest paid                 6.7
    One-time OEFC settlement, net of natural gas contract
     accruals, in 2006                                                   6.2
    Decrease in cash flow from Curtis Palmer                           (13.5)
    Higher financial charges due to acquisitions in 2006                (4.6)
    Other                                                                0.3
    -------------------------------------------------------------------------
    Cash provided by operating activities for the year ended
     December 31, 2006                                                 153.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Partnership reported cash provided by operating activities of
$153.9 million or $3.17 per unit for the year ended December 31, 2006 compared
to $146.7 million or $3.09 per unit in 2005. Cash provided by operating
activities per unit is defined below under non-GAAP measures. The $7.2 million
increase in cash provided by operating activities compared to 2005 is
primarily due to the following:
    -   A $1.5 million decrease in working capital requirements in 2006
        compared to a $10.6 million increase in 2005 due to timing of
        payments and receipts;
    -   The contribution of Frederickson acquired on August 1, 2006 of
        approximately $6.7 million excluding financing costs; and
    -   The one-time settlement with OEFC of $9.8 million in the first
        quarter of 2006 partially offset by accruals for natural gas
        contracts.

    Increases were partially offset by:

    -   Lower pricing in 2006 at Curtis Palmer, partially offset by higher
        generation resulting in a $13.5 million decrease in the plant's
        operating cash flow; and
    -   Higher interest expense of $4.6 million compared to the prior year
        due to additional debt incurred to finance the purchases of Ventures
        and Frederickson and the assumption of capital leases on the Ventures
        acquisition.

    -------------------------------------------------------------------------
    (millions of dollars)
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2006                     62.1
    -------------------------------------------------------------------------
    Higher foreign exchange gains compared to losses in 2006,
     mainly unrealized(1)                                               93.2
    Contribution of the acquired Ventures facilities excluding
     interest and depreciation                                          30.6
    Contribution of Frederickson excluding interest and depreciation     8.4
    Decrease in income tax expense                                       8.6
    Increase in generation and revenue at Manchief                       2.6
    Mamquam and Queen Charlotte arbitration award                        2.3
    Future income tax expenses due to enactment of SIFT Legislation    (78.2)
    Fair value change on natural gas supply, foreign exchange and
     interest rate contracts                                           (21.7)
    Higher depreciation and amortization mainly due to the
     acquisitions in 2006                                              (19.8)
    Lower pricing and generation at Curtis Palmer                      (18.5)
    Higher financial charges due to acquisitions in 2006(1)            (14.5)
    Asset impairment charge                                            (13.0)
    One-time OEFC settlement, net of natural gas contract accruals,
     in 2006                                                            (6.2)
    Preferred share dividends                                           (4.0)
    Tunis fuel supply settlement                                        (2.3)
    Other                                                                1.2
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2007                     30.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excluding changes in the fair value of foreign exchange and interest
        rate contracts.

    Net income was $30.8 million or $0.59 per unit for the year ended December
31, 2007 compared to $62.1 million or $1.28 per unit in 2006. In addition to
the items described above for the change in cash provided by operating
activities, the decrease in net income of $31.3 million is the result of:
    -   Enactment of the SIFT Legislation resulted in the recognition of
        future income tax expense of $78.2 million (see Significant Events -
        Change in tax law).
    -   Adoption of new accounting standards which required the recording of
        natural gas supply contracts at their fair value (see Changes in
        Accounting Policies). The Partnership recorded a loss of
        $32.4 million in 2007 on the change in the fair value of the natural
        gas supply contracts for the Ontario plants. The majority of the
        changes in the fair value during the year are the result of lower
        forward natural gas prices and to a lesser extent the result of the
        receipt of natural gas under the contracts. These losses were
        partially offset by a net gain of $10.8 million on foreign exchange
        and interest rate contracts. In 2006, the Partnership recorded a fair
        value loss on foreign exchange and interest rate contracts of
        $0.1 million;
    -   Lower revenue at Curtis Palmer as a result of lower generation due to
        lower water volumes and the recognition of $6.8 million of previously
        deferred revenue in the first six months of 2006; and
    -   An asset impairment charge of $13.0 million attributed to the
        management agreement between a subsidiary of the Partnership and
        PERH, Primary Energy Recycling Corporation (PERC) and Primary Energy
        Operations LLC.

    Decreases were partially offset by:

    -   Foreign exchange gains of $76.8 million in 2007 compared to losses of
        $16.4 million in 2006, excluding fair value changes on foreign
        exchange contracts; and,
    -   An income tax recovery of $3.0 million in 2007 excluding the future
        income tax expense recorded on enactment of the SIFT Legislation
        compared to an income tax expense of $5.6 million in 2006. The change
        is mainly the result of future income tax recoveries related to
        losses in the US operations in 2007.

    -------------------------------------------------------------------------
    (millions of dollars)
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2005                     86.5
    -------------------------------------------------------------------------
    Contribution of Frederickson excluding interest and
     depreciation                                                        6.7
    One-time OEFC settlement, net of natural gas contract
     accruals, in 2006                                                   6.2
    Foreign exchange losses compared to gains in 2005, mainly
     unrealized(1)                                                     (22.8)
    Higher financial charges due to acquisitions in 2006(1)             (4.6)
    Higher depreciation and amortization mainly due to the
     acquisitions in 2006                                               (4.5)
    Other                                                               (5.4)
    -------------------------------------------------------------------------
    Net income for the year ended December 31, 2006                     62.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excluding changes in the fair value of foreign exchange and interest
        rate contracts.

    Net income was $62.1 million or $1.28 per unit for the year ended December
31, 2006 compared to $86.5 million or $1.83 per unit in 2005. In addition to
the items described above for the change in cash provided by operating
activities, the decrease in net income of $24.4 million is the result of:
    -   Foreign exchange losses of $16.4 million in 2006 compared to gains of
        $6.4 million in 2005, excluding fair value changes on foreign
        exchange contracts.
    

    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 or groups of plants. A reconciliation from operating
margin to net income before tax and preferred share dividends is as follows:

    
    Years ended December 31
     (millions of dollars)                        2007       2006       2005
    -------------------------------------------------------------------------
    Operating margin                             223.8      193.2      192.4
    Deduct (add):
      Depreciation and amortization               92.0       72.2       67.7
      Management and administration               13.2       11.1        8.9
      Foreign exchange losses (gains)            (56.8)      11.7       (6.4)
      Equity losses in PERH                        4.0        1.2          -
      Financial charges and other                 48.4       29.3       25.7
      Asset impairment charge                     13.0          -          -
    -------------------------------------------------------------------------
    Net income before income tax and
     preferred share dividends                   110.0       67.7       96.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 year. The composition of these measures is
consistent with December 31, 2006 reporting.

    REVENUES AND PLANT OUTPUT

    Years ended December 31                         2007                2006
    -------------------------------------------------------------------------
                                               (millions           (millions
                                                      of                  of
                                           GWh   dollars)      GWh   dollars)
    Ontario Plants(2)
      Power                              1,412     134.5     1,368     134.7
      Enhancements                                   8.4                12.3
      Gas Diversions                                 9.4                 8.7
                                                  -------             -------
                                                   152.3               155.7

    Williams Lake
      Firm energy                          445      33.8       445      33.7
      Excess energy                        100       4.3       108       5.8
                                        -------   -------   -------   -------
                                           545      38.1       553      39.5

    Mamquam and Queen Charlotte            267      18.0       232      15.7
    Northwest US Plants(3)                 910      60.7       456      38.7
    California Plants(3)                 1,004     130.6       170      20.5
    Curtis Palmer                          307      31.7       416      50.9
    Northeast US Gas Plants(3)             398      57.7       153      28.6
    North Carolina Plants(3)               613      52.3        51       5.6
    PERC management fees(3)                  -       3.4         -       0.6
    Fair value changes on foreign
     exhange contracts                       -      34.4         -      (5.6)
                                        -------   -------   -------   -------
                                         5,456     579.2     3,399     350.2
                                        -------   -------   -------   -------

    Weighted average plant
     availability(1)
      Ontario Plants                                 95%                 98%
      Williams Lake                                  96%                 95%
      Mamquam and Queen Charlotte                    81%                 83%
      Northwest US Plants(3)                         94%                 96%
      California Plants(3)                           91%                 94%
      Curtis Palmer                                  96%                 97%
      Northeast US Gas Plants(3)                     96%                 96%
      North Carolina Plants(3)                       94%                 92%
                                                  -------             -------
    Total weighted average availability              94%                 95%
                                                  -------             -------
    Average price per MWh
      Ontario Plants(2)                              $95                 $98
      Williams Lake                                  $70                 $71
      Mamquam and Queen Charlotte                    $67                 $68
      California Plants(3)                          $130                $121
      Curtis Palmer                                 $103                $122
      North Carolina Plants(3)                       $85                $110
    -------------------------------------------------------------------------

    (1) Plant availability represents the percentage of time in the year that
        the plant is available to generate power, whether actually running or
        not, and is reduced by planned and unplanned outages.
    (2) Ontario power revenue includes the retroactive portion of the
        settlement with OEFC of $9.8 million in 2006. Average price would
        decline to $91/MWh in 2006 if the settlement was excluded from
        revenue.
    (3) From the dates of acquisition: Frederickson - August 1, 2006;
        Ventures - November 1, 2006
    


    Revenues of $579.2 million for year ended December 31, 2007 were
$229.0 million higher than in 2006. The increase was primarily due to the
acquisition of Ventures and Frederickson on November 1, 2006 and August 1,
2006 respectively, which contributed an additional $202.2 million to revenues
in the year ended December 31, 2007 compared to 2006, as well as changes in
the fair value of foreign exchange contracts. Offsetting the increase were the
non-recurrence of the $9.8 million settlement received from OEFC in the first
quarter of 2006 and lower generation and pricing at Curtis Palmer.

    Ontario Plants

    All the power output from the Ontario plants is sold to OEFC under
long-term PPAs with expiry dates ranging from 2012 to 2020. In addition, the
Partnership has agreed to sell incremental power from Calstock to OEFC at
market based prices to the end of 2009. The Ontario plants reported revenues
of $152.3 million for the year ended December 31, 2007 compared to
$155.7 million in 2006. Excluding the impact of the one-time settlement with
OEFC of $9.8 million in 2006, revenue from power sales increased by $9.6
million in 2007. The increase was due to increased generation resulting from
higher waste heat availability, built-in annual price escalators in these
contracts and more natural gas being available for power generation due to
lower enhancement and diversion sales. These increases were partially offset
by lower generation and revenue at Kapuskasing. On May 12, 2007, during a
regular maintenance outage at Kapuskasing, the rotor used by the steam turbine
generator sustained damage as a result of a serious transport accident.
Kapuskasing continued to operate but at a reduced capacity of approximately 20
megawatts (approximately 50% capacity) until late August 2007 when a partially
refurbished steam turbine generator rotor was installed allowing the plant to
return to full capacity. A new steam turbine generator rotor is expected to be
installed in 2008. The financial loss, net of insurance claims, resulting from
this incident was under $1.0 million.
    In 2006, the Partnership reached an agreement with OEFC on a replacement
for the Direct Customer Rate index that was discontinued in 2002. The OEFC
settlement adjusts the amount owed to the Partnership under the PPAs for the
Ontario plants for the period from 2002 through to the end of the respective
PPAs. The retroactive portion of the settlement was received in the first
quarter of 2006 and positively impacted revenue by $9.8 million.
    Enhancement revenues at the Ontario plants were lower in 2007 due to
price increases in the PPAs and a small decline in natural gas prices.
    Power output from the Ontario plants for the year ended December 31, 2007
was 44 gigawatt hours (GWh) higher year-over-year as more natural gas was
available for power generation due to lower enhancement and diversion sales in
2007. Weighted average plant availability for the Ontario plants declined in
2007 to 95% compared to 98% in 2006 primarily due to the outage at
Kapuskasing.

    Williams Lake

    Revenues at Williams Lake consist of firm energy sales including cost
recovery components, and excess energy sales under the power sales contract
with British Columbia Hydro and Power Authority (BC Hydro) expiring in 2018.
The amount of firm energy sold to BC Hydro on an annual basis is fixed at
445 GWh, except in years when major overhauls are performed (approximately
every five years). Revenues remain constant in major overhaul years and the
firm energy commitment to BC Hydro is reduced to 401 GWh. Cost recovery
components are escalated annually for inflation.
    For the year ended December 31, 2007, firm energy revenues of
$33.8 million were slightly higher than $33.7 million reported for 2006.
Excess energy sales for the year ended December 31, 2007 were $4.3 million
compared with $5.8 million for 2006. Excess energy sales result when a surplus
of energy is generated above the annual firm amount. The decrease in excess
energy sales reflected a decrease in generation and in the market-based price
(2007 - $43 per megawatt hour (MWh); 2006 - $54 per MWh). The market based
price for 2008 is set at $49 per MWh.

    Mamquam and Queen Charlotte

    Mamquam and Queen Charlotte have long-term PPAs with BC Hydro that expire
in 2027 and 2022, respectively. The PPAs consist of a fixed energy component
per MWh up to certain output thresholds, an operations and maintenance
component adjusted annually for inflation and a reimbursable cost component.
All electricity generated at Mamquam and substantially all electricity
generated at Queen Charlotte is sold to BC Hydro. A small amount of
electricity from Queen Charlotte is sold to two local industrial customers.
    Revenues at Mamquam and Queen Charlotte were $18.0 million for the year
ended December 31, 2007, compared with $15.7 million in 2006. The increase in
generation and revenue in the year was the result of above normal water flows,
which more than offset the lost revenue in 2007 due to tunnel repair work
completed at Mamquam. The tunnel repairs also resulted in lower availability
in 2007.

    Northwest US Plants

    Manchief has two separate tolling agreements covering the sale of
capacity and incremental energy to Public Service Company of Colorado (PSCo)
that expire in 2022. PSCo controls the dispatch of electricity from Manchief,
including start-ups, shut-downs and generation loading levels. Capacity
payments are generally unaffected by output levels but vary depending upon
changes in plant availability. Capacity payments will decline by approximately
15% starting in May 2012. PSCo pays for incremental energy generated at the
plant based upon a fixed price per MWh, escalated annually for inflation. PSCo
also pays for turbine start-up fees, heat rate adjustments and gas
transportation charges. Revenues from Manchief of $27.6 million for the year
ended December 31, 2007 were $1.5 million higher than in 2006 mainly due to
higher generation as the result of low natural gas prices in Colorado.
    Greeley provides all of its electrical output to PSCo under a PPA which
expires in 2013. PSCo pays a monthly capacity payment and an energy payment
pursuant to the PPA. Greeley sells hot water to the University of Northern
Colorado (UNC) pursuant to a Thermal Supply Agreement which expires in August
2013. Under the agreement, Greeley is obligated to deliver for sale to UNC
only such heat energy as is generated during the production of electrical
capacity and energy for sale to PSCo. Revenues from Greeley were $9.6 million
for the year ended December 31, 2007 compared to $1.4 million for the two
month period from the date of acquisition to December 31, 2006. Greeley's
revenues and operating margin were above the Partnership's expectations for
the year due to lower natural gas prices.
    The Partnership's portion of the capacity of Frederickson has been sold
under tolling arrangements expiring in 2022 to three Washington State public
utility districts (the PUDs). The remaining interest in Frederickson is held
by Puget Sound Energy, Inc. which works cooperatively with the PUDs to
economically dispatch Frederickson. The PUDs pay capacity and fixed operating
and maintenance charges as well as all fuel related costs and commercial
start-up costs. Revenues from the plant were $23.4 million for year ended
December 31, 2007 compared to $11.1 million for the five month period from the
date of acquisition to December 31, 2006. Frederickson revenues for 2007 were
in line with the Partnership's expectations, even though the plant experienced
a two week outage due to a transmission cable failure in the first quarter.

    California Plants

    The three US Naval facilities (the Naval facilities) sell power to San
Diego Gas and Electric Company (SDG&E) under long-term PPAs which expire in
2019, except for a 4 megawatt steam turbine at North Island which sells power
to the United States Navy (the Navy) under its SPA which expires in 2018. The
price paid under the PPAs includes a capacity payment and an energy payment
based on SDG&E's full Short Run Avoided Cost (SRAC). Each of the Naval
facilities sells steam to the Navy pursuant to long-term SPAs, each of which
expires in February 2018. The SPAs also give the Navy a right to purchase
electrical energy from the Naval facilities at prices comparable to those
under the PPAs. The Navy has an obligation to consume enough thermal energy
for the Naval facilities to maintain their Qualifying Facility (QF) status.
The Navy pays a combination of steam commodity charges, fixed charges and
water cost pass through provisions. Steam pricing is linked to the cost of
natural gas and SDG&E's SRAC by an energy sharing formula. Revenues from the
Naval facilities were $105.9 million for the year ended December 31, 2007
compared to $17.2 million for the two month period from the date of
acquisition to December 31, 2006. Availability for the Naval facilities was
lower than plan during 2007 due to two unplanned outages at North Island in
the first quarter due to auxiliary gear box and turbine compressor failures.
The second outage required the engine to be removed from service and replaced
temporarily with a leased engine.
    All power output from Oxnard is sold to Southern California Edison
Company (SCE) under a PPA which expires in 2020. The price paid under the PPA
includes a capacity payment and an energy payment based on SCE's SRAC. Steam
from Oxnard is used to provide refrigeration services to Boskovich Farms, a
food processing and cold storage facility, thereby maintaining Oxnard's QF
status. Revenues from Oxnard were $24.7 million for the year ended
December 31, 2007 compared to $3.3 million for the two month period from the
date of acquisition to December 31, 2006. Oxnard suffered an engine failure in
August 2007, but through the use of the lease engine fleet pool maintained
operations in line with the Partnership's expectations for the year.
    The California Public Utilities Commission (CPUC) approved a decision on
SRAC in September 2007 to include forward market heat rates in the
determination of SRAC and to increase the amount of variable operating cost
included in SRAC from US$2.00 to $2.65 per MWh. The decision modifies the
application of Time of Use (TOU) factors to the energy portion of the SRAC.
Historically, TOU factors have been volatile in the regions in which the
Oxnard and Naval facilities operate. The changes are expected to be
implemented at the end of the second quarter of 2008 and could have a small
negative impact on operating margin at these plants.
    Revenues and operating margins for the California facilities are very
seasonal. Approximately 75% of capacity revenue at the Naval facilities is
earned during the summer peak demand months. For all the California plants,
performance bonuses can be earned during these months if forced outage rates
are below 15%.

    Curtis Palmer

    Output from Curtis Palmer is sold to Niagara Mohawk Power Corporation
(Niagara Mohawk) under a PPA which expires the earlier of 2027 and the
delivery to Niagara Mohawk of a cumulative 10,000 GWh of electricity. The PPA
sets out eleven pricing blocks over the contract term for electricity sold to
Niagara Mohawk and the price is dependent on the cumulative GWh of electricity
delivered. A cumulative GWh threshold was reached in January 2006 when a
cumulative total of 3,344 GWh was delivered, at which point the price for
electricity dropped by approximately 33%. Over the remaining term of the PPA,
the price increases with each additional 1,000 GWh of electricity delivered by
an average of 10%. At December 31, 2007, 4,049 cumulative GWh had been
delivered. Pricing will increase 18% after a cumulative 4,344 GWh is
delivered.
    Revenues at Curtis Palmer were $31.7 million for the year ended
December 31, 2007, compared with $50.9 million in 2006. The decrease in
revenues was due to the recognition of previously deferred revenue of $6.8
million in the first six months of 2006 and the reduction in the PPA pricing
that began in late January 2006. In addition, generation was lower resulting
from a maintenance outage in 2007 and lower water flow in the second half of
2007 compared to the above average water flows experienced in 2006.

    Northeast US Gas Plants

    Revenues at Castleton, which are adjusted annually for contractual
increases, are earned through fixed monthly capacity payments from TransCanada
Power Marketing Ltd. (TCPM) in return for providing the power plant's entire
operating capacity. As a result, Castleton revenues are generally unaffected
by the amount of electricity generated at the plant, which increased
significantly in 2007 compared to 2006 due to increased dispatch by TCPM. The
PPA with TCPM expires in June 2008. Revenues of $30.4 million for Castleton
for the year ended December 31, 2007 were $7.1 million higher than in 2006
mainly due to natural gas sales to utilize excess natural gas transmission
capacity. The increase in revenue is mostly offset by higher fuel costs
generated from these transactions (see Cost of Fuel).
    Kenilworth sells electrical energy and steam to Schering Corporation
(Schering) under an Energy Services Agreement (ESA) that expires in June 2009.
Pursuant to the ESA, Schering pays an energy rate that escalates annually. Any
power produced in excess of Schering's requirements is sold to Jersey Central
Power & Light Company under a PPA ending in June 2009. Revenues from steam are
calculated as a function of the delivered cost of fuel. The ESA provides a
fuel price cap, with Schering paying any amount above the cap. Kenilworth was
acquired on November 1, 2006 as part of the Ventures acquisition. Revenues
from Kenilworth were $27.3 million for the year ended December 31, 2007
compared to $5.3 million for the two month period from the date of acquisition
to December 31, 2006. Results for 2007 were slightly below the Partnership's
expectations due to weather related forced outages in April.

    North Carolina Plants

    The North Carolina plants provide all of their electrical output to
Carolina Power & Light Company (CP&L) under PPAs which expire in December
2009. Dispatch from the plants is controlled by CP&L. The PPAs have been
amended to allow the plants to bid for additional dispatch. The price paid
under the PPAs includes capacity payments and energy payments that reflect the
price paid for coal and cycling charges. Southport sells steam pursuant to a
SPA which expires in December 2014. The Southport SPA provides for a change in
pricing commencing in July 2008 that more appropriately reflects the value of
the steam if it was used for electrical generation. Roxboro does not currently
have a SPA. Revenues from the North Carolina plants were $52.3 million for
year ended December 31, 2007 compared to $5.6 million for the two month period
from the date of acquisition to December 31, 2006. Revenues in 2007 were
higher than expected, due to higher than forecast dispatch as a result of
supply shortages caused by outages at non-Partnership plants in the region.

    Fair value changes on foreign exchange contracts

    Unrealized gains on foreign exchange contracts were $34.4 million for the
year ended December 31, 2007 compared to an unrealized loss of $5.6 million
reported in 2006. The unrealized gain in 2007 was primarily due to an increase
in the Canadian dollar relative to the US dollar in 2007 compared to a decline
in 2006 from the date of de-designation to December 31, 2006. In the second
quarter of 2006, the Partnership voluntarily de-designated certain hedge
relationships for accounting purposes on foreign exchange contracts. In
addition, the Partnership has acquired more foreign exchange contracts as a
result of acquiring the Frederickson and Ventures operations.

    
    COST OF FUEL

    Years ended December 31                                2007         2006
    -------------------------------------------------------------------------
    (millions of dollars except average cost per MWh)

    Ontario Plants
      Natural gas(1)                                       58.0         55.7
      Waste heat                                            3.3          1.1
      Wood waste                                            1.7          1.1
                                                     -----------  -----------
                                                           63.0         57.9

    Williams Lake - wood waste                              3.5          4.3

    Northwest US Plants - natural gas(2)                    9.8          3.9

    California Plants - natural gas(2)                     81.1         15.3

    Northeast US Gas-Fired Plants - natural gas(2)         38.9         15.7

    North Carolina Plants - coal, tire-derived
     fuel & wood waste(2)                                  34.5          4.4

    Fair value changes on gas contracts                    32.4            -
                                                     -----------  -----------
                                                          263.2        101.5
                                                     -----------  -----------

    Average cost per MWh
      Ontario(1)                                            $45          $42
      Williams Lake                                          $6           $8
      California Plants                                     $81          $90
      North Carolina Plants                                 $56          $87
    -------------------------------------------------------------------------
    (1) Ontario gas costs include the retroactive portion of the estimated
        settlement of a natural gas price escalation dispute with NAL and
        Devon in 2006.
    (2) From the dates of acquisition: Frederickson - August 1, 2006;
        Ventures - November 1, 2006
    

    Fuel costs, which are the Partnership's most significant cost of
operations, include commodity price, 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 year ended December 31, 2007, fuel costs were $263.2 million
compared with $101.5 million in 2006. The increase was primarily due to the
acquisitions of Ventures and Frederickson on November 1, 2006 and August 1,
2006 respectively, which resulted in an increase in fuel costs of
$119.2 million in the year ended December 31, 2007 as well as a decline
recorded in 2007 on the fair value of natural gas contracts.
    Fuel costs at the Ontario plants for the year ended December 31, 2007
were $63.0 million compared to $57.9 million in 2006. The increase was due to
higher fuel supply costs at Tunis as a result of the settlement of a supply
contract dispute (see Significant Events - NAL and Devon claims), higher waste
heat optimization costs and annual price increases in the natural gas supply
contracts. These increases were partially offset by retroactive charges for
estimated additional fuel charges of $4.1 million in 2006 and a $1.2 million
refund in 2007 of transportation charges related to prior years.
    Fuel costs at the Northwest US plants increased by $5.9 million for the
year ended December 31, 2007 due to the acquisition of Frederickson on
August 1, 2006 and Greeley on November 1, 2006. Fuel costs for year ended
December 31, 2007 at Frederickson were $4.1 million compared to $2.2 million
for the five month period from the date of acquisition to December 31, 2006.
Fuel costs for year ended December 31, 2007 at Greeley were $5.5 million
compared to $1.3 million for the two month period from the date of acquisition
to December 31, 2006. The Partnership pays for demand charges associated with
the transportation of natural gas to Manchief, which were $0.2 million for the
year ended December 31, 2007 compared to $0.4 million in 2006.
    Fuel costs at the California plants were $81.1 million for the year ended
December 31, 2007 compared to $15.3 million for the two month period from the
date of acquisition to December 31, 2006. Lower gas prices through the middle
part of the year resulted in lower than expected fuel costs for the year ended
December 31, 2007.
    The Northeast US gas plants incurred fuel costs of $38.9 million for the
year ended December 31, 2007 compared to $15.7 million in 2006. Fuel supply
costs at Castleton increased by $6.0 million for the year as the result of the
higher sale of natural gas in 2007 to utilize excess natural gas transmission
capacity. Fuel costs at Kenilworth were $21.3 million for the year ended
December 31, 2007 compared to $4.1 million for the two month period from the
date of acquisition to December 31, 2006, slightly lower than expectations due
to lower generation during the year.
    Fuel costs at the North Carolina plants were $34.5 million for the year
ended December 31, 2007 compared to $4.4 million for the two month period from
the date of acquisition to December 31, 2006. An unfavourable fuel blend (a
greater amount of coal burned compared to wood waste and tire derived fuel)
and higher dispatch rates led to higher fuel costs than expected.
    The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric plants do
not have fuel costs.

    
    OPERATING AND MAINTENANCE EXPENSE

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Ontario Plants                                         13.5         13.4
    Williams Lake                                           5.8          5.7
    Mamquam and Queen Charlotte                             1.3          1.3
    Northwest US Plants(1)                                  8.5          6.0
    California Plants(1)                                   12.6          2.4
    Curtis Palmer                                           1.1          1.1
    Northeast US Gas Plants(1)                              5.0          3.6
    North Carolina Plants(1)                               11.2          2.9
    PERC management expenses(1)                             0.9            -
    -------------------------------------------------------------------------
                                                           59.9         36.4
    -------------------------------------------------------------------------
    (1) From the dates of acquisition: Frederickson - August 1, 2006;
        Ventures - November 1, 2006.

    Operating and maintenance expenses are based on fixed charges adjusted
annually for inflation as well as flow through of costs for plants acquired in
2006, and are payable to the Manager for the operation and routine maintenance
of the plants. The acquisitions of Ventures and Frederickson in 2006 were the
primary cause of the year-over-year increases.

    OTHER PLANT OPERATING EXPENSES

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Property taxes                                         11.4         11.2
    Insurance                                               5.2          4.9
    Major maintenance                                      15.7          3.0
    -------------------------------------------------------------------------
                                                           32.3         19.1
    -------------------------------------------------------------------------

    Other plant operating expenses, which include insurance, property taxes
and major maintenance expenses, were $32.3 million for the year ended
December 31, 2007 compared to $19.1 million in 2006. The increase was mainly
due to the acquisitions of Ventures and Frederickson in 2006 and the Mamquam
tunnel repairs in 2007.

    DEPRECIATION AND AMORTIZATION

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Depreciation of property, plant and equipment          57.1         46.5
    Accretion of asset retirement obligations               1.5          1.2
    Amortization of PPAs                                   33.6         24.5
    Amortization of other assets                            2.5          0.5
    Amortization of contract liabilities                   (2.7)        (0.5)
    -------------------------------------------------------------------------
                                                           92.0         72.2
    -------------------------------------------------------------------------

    Depreciation and amortization expense for the year ended December 31, 2007
was $92.0 million compared to $72.2 million in 2006. The higher depreciation
charges for the year ended December 31, 2007 compared to the prior year are
mainly due to the Ventures and Frederickson acquisitions in 2006.

    MANAGEMENT AND ADMINISTRATION

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Base fee                                                1.3          1.2
    Incentive fee                                           2.2          2.1
    Enhancement fee                                         0.7          1.1
    General and administrative costs                        9.0          6.7
    -------------------------------------------------------------------------
                                                           13.2         11.1
    -------------------------------------------------------------------------

    Management and administration costs, which include fees payable to EPCOR
and general and administrative costs, were $13.2 million for the year ended
December 31, 2007 compared to $11.1 million in 2006. Management and
administration costs have increased due to the additional plants acquired in
2006. This increase for the year ended December 31, 2007 was partially offset
by a $2.3 million arbitration award against the previous owners of Queen
Charlotte and Mamquam in respect of claims in the purchase and sale agreement.

    FOREIGN EXCHANGE (GAINS) LOSSES

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Effect of translation on US dollar cash balances        4.5         (0.5)
    Unrealized foreign exchange losses (gains) on
     US dollar-denominated monetary assets and
     liabilities                                          (81.3)        16.9
    Realized losses on foreign exchange contracts          15.3            -
    Fair value changes on foreign exchange contracts        4.7         (4.7)
    -------------------------------------------------------------------------
                                                          (56.8)        11.7
    -------------------------------------------------------------------------
    

    The Partnership reported net foreign exchange gains of $56.8 million for
the year ended December 31, 2007 compared to losses of $11.7 million in 2006.
The foreign exchange gains recorded in 2007 are the result of a strengthening
of the Canadian dollar during the year. The foreign exchange losses in 2006
were due to the issuance of US dollar-denominated debt in 2006 and subsequent
weakening of the Canadian dollar during the relevant period to December 31,
2006. Realized foreign exchange losses on translation of US dollar cash
balances were $4.5 million for the year ended December 31, 2007 compared to a
gain of $0.5 million in 2006. The loss in 2007 was due to the Partnership
holding US cash as the US dollar weakened. The gain in 2006 was the result of
carrying larger US cash balances after the acquisition of Frederickson and
Ventures and the subsequent strengthening of the US dollar in that year.
    The foreign exchange contracts were entered into in anticipation of the
issuance of Canadian equity to replace a portion of the US dollar bridge
acquisition facility. During the year ended December 31, 2007, the Partnership
realized losses on settlement of these contracts of $15.3 million. Although
the Partnership realized a loss on the US dollar hedges in the current year,
the stronger Canadian dollar allowed for a larger pay down of the US dollar
bridge acquisition financing from the Canadian dollar equity offering which
will translate into lower interest costs and debt repayments in future years.

    
    EQUITY LOSSES IN PERH

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    PERH                                                    4.0          1.2
    -------------------------------------------------------------------------
    

    Equity losses in PERH are from the Partnership's 17.0% common ownership
interest in PERH acquired on November 1, 2006, which is accounted for on an
equity basis.
    In the year ended December 31, 2007, the Partnership received dividends
on its 14.2% preferred ownership interest of $1.8 million and dividends of
$3.3 million from its common interest in PERH. In the second quarter of 2007,
the monthly cash dividend on the common interest in PERH was reduced by 40%
and the September 2007 dividend was deferred in anticipation of the possible
violation of certain debt covenants by PERH. The financial statements of PERH
for the nine months ended September 30, 2007 confirmed that certain debt
covenants had been violated. In November 2007, a waiver of covenant defaults
and an amended credit agreement were executed by PERH and its subsidiaries
allowing dividends to resume. The Partnership received dividends of
$0.4 million per month on its common and preferred interests in the first two
months of 2008. The results for PERH were adversely impacted by an outage at
PERH's North Lake Energy Facility and unfavourable results at PERH's Harbor
Coal joint venture as a result of negative inventory adjustments in 2007.

    
    FINANCIAL CHARGES AND OTHER, NET

    Years ended December 31 (millions of dollars)          2007         2006
    -------------------------------------------------------------------------
    Interest on long-term debt                             36.3         27.4
    Interest on short-term debt                             4.9          1.8
    Interest on capital lease obligations                   4.5          1.2
    Dividend income from Class B preferred share
     interests in PERH                                     (1.8)        (0.3)
    Realized losses on interest rate contracts              2.6            -
    Fair value changes on interest rate contracts           1.0         (1.0)
    Other                                                   0.9          0.2
    -------------------------------------------------------------------------
                                                           48.4         29.3
    -------------------------------------------------------------------------
    

    Financial charges and other expenses of $48.4 million for the year ended
December 31, 2007 were $19.1 million higher compared to 2006. The increase was
primarily due to interest on short-term debt and long-term debt used to
finance the Ventures and Frederickson acquisitions. Contributing to the
increase was interest on capital lease obligations (which were paid down in
the third quarter of 2007) assumed in the Ventures acquisition and realized
losses and declines in the fair value of interest rate contracts. The
increases were partially offset by dividends earned on the investment in PERH
Class B preferred shares.

    INCOME TAX EXPENSE

    Income tax expense of $75.2 million for the year ended December 31, 2007
was $70.4 million higher than in 2006. The increase is due to enactment of the
SIFT Legislation in 2007 which will result in the Partnership's Canadian
operations becoming taxable in 2011. Accordingly, a future income tax expense
of $78.2 million was recognized in 2007. Income taxes also relate to taxes of
the Partnership's US subsidiaries and withholding taxes on distributions from
the US subsidiaries. Cash taxes increased during the year primarily due to an
increase in US withholding taxes.

    PREFERRED SHARE DIVIDENDS OF A SUBSIDIARY COMPANY

    In May 2007, a subsidiary of the Partnership issued preferred shares
which pay dividends at a rate of 4.85% per annum. The first and second
dividends of $2.1 million and $1.5 million were paid to shareholders on
September 28, 2007 and December 31, 2007 respectively. Dividends of
$1.5 million are expected to be paid in future quarters. 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.
    The preferred shares are guaranteed by the Partnership on a subordinated
basis as to (i) payment of dividends, as and when declared, (ii) payment of
amounts due on redemption of the preferred shares, and (iii) payment of
amounts due on liquidation, dissolution or winding up of the issuer of the
preferred shares. As long as the declaration or payment of dividends on the
Series 1 Shares are in arrears, the Partnership will not make distributions on
the units.

    
    GAINS (LOSSES) ON DERIVATIVE INSTRUMENTS

                                                  Amounts
                                              Recorded In
    Years ended                Income    Income Statement   Amounts Realized
     December 31            Statement    -----------------  -----------------
    (millions of dollars)    Category      2007      2006      2007     2006
    -------------------------------------------------------------------------
    Foreign exchange
     contracts(1)             Revenue      34.4      (5.6)        -        -
    Natural gas contracts        Fuel     (32.4)        -         -        -
    Foreign exchange          Foreign
     contracts               exchange     (20.0)      4.7     (15.3)       -
    Interest rate
     contracts              Financing      (3.6)      1.0      (2.6)       -
    -------------------------------------------------------------------------
                                          (21.6)      0.1     (17.9)       -
    -------------------------------------------------------------------------
    (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 The Partnership makes quarterly cash distributions to Limited Partners in accordance with the Partnership Agreement and subject to Board approval. Cash distributions are made in respect of the quarters ending March, June, September and December in each year to unitholders of record on the last day of such quarters. Payments are made on or about the 30th day after each record date. Distributions are prohibited by certain loan agreement covenants if an uncured default exists. Additionally, distributions are prohibited if declaration or payment of dividends on the preferred shares is in arrears. A portion of cash distributions are taxable to unitholders in the year received. Cash distributions of $0.63 per unit were declared for each of the quarters of 2007, consistent with the same periods in 2006. 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. Years ended December 31 (millions of dollars) 2007 2006 ------------------------------------------------------------------------- Cash distributions(1) 133.3 124.2 Cash provided by operating activities 132.2 153.9 Net income 30.0 62.1 Dividends from PERH 3.3 1.0 Additions to property, plant and equipment 12.5 13.2 Excess (shortfall) of cash provided by operating activities over cash distributions (1.1) 29.7 Shortfall of net income over cash distributions (103.3) (62.1) ------------------------------------------------------------------------- (1) Cash distributions for the year ended December 31, 2006 include a $1.5 million payment in August 2006 on the subscription receipts issued in the acquisition of Frederickson. Cash distributions exceeded cash provided by operating activities by $1.1 million for the year ended December 31, 2007. The Partnership also incurred capital expenditures of $12.5 million during the year ended December 31, 2007. Excluding realized losses on interest rate and foreign exchange contracts that were entered into in anticipation of the Ventures acquisition financing, cash provided by operating activities exceeded cash distributions for the year ended December 31, 2007 by $16.8 million. The net realized losses on interest rate and foreign exchange contracts that were entered into in anticipation of the permanent financing of the Ventures acquisition were primarily driven by the strengthening of the Canadian dollar and reduction of long-term interest rates. These events created a loss but consistent with the nature of a hedge, will reduce future interest and debt payments. Cash provided by operating activities (excluding any realized losses or gains on interest rate and foreign exchange contracts and any changes in working capital requirements) is expected to decline in 2008 due to factors outlined under "Outlook", subject to variable factors including those outlined in our forward looking statements at the beginning of this MD&A. In addition, capital expenditures in 2008 are expected to exceed the $12.5 million of capital expenditure in 2007 as outlined under "Capital Expenditures". While the Partnership anticipates seasonal fluctuations in its working capital, it does not expect a significant increase in working capital requirements over the long term for existing operations. The shortfall between cash distributions plus capital expenditures and cash provided by operating activities has been funded from cash on hand. 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, changes in the fair value of derivative instruments and future income tax expense related to changes in tax legislation. Aside from these items, management expects that distributions will continue to 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 $100 million revolving credit facilities, 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. Beginning in 2006, the Partnership deferred utilizing elective deductions, including capital cost allowance, for Canadian income tax purposes in response to the Partnership's Canadian operations becoming taxable in 2011. As a result, the taxable amount of cash distributions per unit increased from $1.44, had the Partnership claimed full elective deductions in the year, to the actual amount of $1.88 per unit. The use of elective deductions in 2007 for Canadian income tax purposes would not benefit a tax deferred individual investor whereas the deferral of these elective deductions is expected to benefit individual investors. The following table summarizes the tax pools the Partnership has available to deduct against future taxable income. Tax pools are comprised primarily of undepreciated capital costs and accumulated tax losses. As at December 31 (millions of dollars) 2007 2006 ------------------------------------------------------------------------- Canadian tax pools 304.6 282.9 US tax pools (US$) 749.0 718.9 ------------------------------------------------------------------------- Capital expenditures Capital expenditures are primarily comprised of maintenance capital and additions to, or replacements of, equipment required to maintain or increase current output capacity. Major overhauls are performed periodically at each of the plants based on the number of operating hours and type of equipment. Major overhauls at the Ontario, Kenilworth and Naval plants are performed approximately every 25,000 operating hours or roughly every three years for hot section refurbishments on the gas turbines to approximately 50,000 operating hours or every six years for turbine overhauls. Hot section refurbishments and turbine overhauls are performed at Frederickson and Oxnard at the same number of operating hours, however these plants are normally dispatched only during periods of peak power demand reducing operating hours each year and consequently increasing the interval between major overhauls. Similarly, major overhauls are performed at Castleton and Greeley depending on plant usage. When the recent SRAC changes are implemented, the Partnership may choose to dispatch the Naval facilities only during peak periods, thus increasing the interval between major overhauls. It is expected that the heat recovery steam generators will require re-tubing approximately once in 20 years. A major overhaul is completed at the Williams Lake, Calstock and North Carolina plants approximately every five to six years. Major overhauls for Manchief are expected to be performed approximately every 25,000 equivalent operating hours. The plant currently operates between 500 and 1,500 hours per year. Inspections are performed at the plant on a more regular basis. Maintenance capital expenditures for the hydroelectric facilities are expected to be at longer intervals and are condition based. Capital expenditures for the year ended December 31, 2007 totalled $12.5 million and primarily consisted of plant upgrades, reliability and safety controls and maintenance capital at each of the plants. The Partnership has completed its technical and economic feasibility review of enhancing the Southport and Roxboro coal plants with a newer technology in order to reduce environmental emissions and improve the economic performance. The Partnership spent $0.7 million on this feasibility study in 2007. Current cost estimates for the new technology are up to $65 million for both plants. Capital spending on this project will start in the second half of 2008 and continue through 2009. Aside from the installation of new technology at Southport and Roxboro, capital maintenance spending is expected to increase to between $23 million and $25 million in 2008. The primary drivers for this expected increase in spending in 2008 include: - Carryover of $2.5 million of overhauls of the gas and steam turbines at North Bay originally scheduled in 2007 to 2008. Similar overhauls completed at Kapuskasing in 2007, a sister plant to North Bay, indicated that the overhauls at North Bay could be safely deferred to 2008; - Manchief was dispatched at higher rates in the third quarter of 2007 due to low natural gas prices. As a result, the scheduled overhaul for one of its gas turbines was accelerated from 2009 to 2008 with an expected cost of approximately $3 million; and - The Partnership has committed $4 million in capital maintenance expenditures at Castleton for a major overhaul to extend the life of Castleton beyond its PPA expiry in June 2008. The Partnership expects that over its five year planning cycle maintenance capital expenditures will average $18 million annually for its existing facilities. Financing The following table summarizes the long-term debt of the Partnership. As at December 31 (millions of dollars) 2007 2006 ------------------------------------------------------------------------- Senior unsecured notes, due 2036 210.0 210.0 Senior unsecured notes (2007 - US$415.0; 2006 - US$190.0) due 2014 to 2019 411.3 221.4 Secured term loan, due 2010 3.8 4.8 Revolving credit facilities - 149.4 Bridge acquisition credit facility - 51.3 Obligations under capital leases - 81.2 ------------------------------------------------------------------------- 625.1 718.1 ------------------------------------------------------------------------- The Partnership's debt to total capitalization ratio as at December 31, 2007 decreased to 41% from 54% at the end of 2006 due to the repayment of debt with proceeds from the issue of partnership units and preferred shares. Under terms of its debt agreements, the Partnership must maintain a debt to capitalization ratio of not more than 65% at the end of each fiscal quarter. In addition, under the revolving credit facilities, in the event the Partnership is assigned a rating of less than BBB+ by Standard and Poors (S&P) and BBB(high) by DBRS Limited (DBRS), the Partnership also would be required to maintain a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization as defined in the credit facilities) to interest expense of not less than 2.5 to 1, measured quarterly. Although the Partnership is not currently required to meet the EBITDA to interest ratio, it was 4.2 as at December 31, 2007. The Partnership was compliant with all of its debt covenants under its debt agreements for the years ended December 31, 2007 and 2006. During 2007 the Partnership issued 4.0 million units for net proceeds of $101.6 million, 5.0 million preferred shares for net proceeds of $120.8 million and completed a US$225.0 million private placement of senior unsecured notes. The proceeds of these offerings were used to repay capital lease obligations and amounts initially borrowed as part of the Frederickson and Ventures acquisitions. At January 1, 2007, in accordance with new accounting standards on financial instruments, the Partnership reclassified its deferred debt issue costs on its loans from other assets to long-term debt. Deferred transaction costs are amortized using the effective interest rate method. At December 31, 2007 transaction costs were $7.9 million, net of accumulated amortization of $2.5 million. DBRS and S&P rate the Partnership's senior note debt as BBB(high) and BBB+ respectively and the Partnership's stability ratings of STA-2 (high) and SR-2 respectively. DBRS' BBB(high) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The "BBB" rating is DBRS' fourth highest of 10 categories. The high classification shows the relative standing within the major rating categories. The BBB+ debt rating by S&P is the fourth highest rating out of 10 rating categories. The plus sign shows the relative standing within the major rating categories. Maintaining an investment grade credit rating is important to the Partnership to re-finance existing debt as it matures and to access cost competitive capital for future growth. The STA-2 (high) stability rating by DBRS is the second highest of seven categories in their rating system for income fund stability. DBRS further subcategorizes each rating by the designation of "high", "middle" and "low" to indicate where an entity falls within the rating category. The stability ratings of SR-2 by S&P is the second highest rating of seven categories and indicates that the Partnership has a high level of distributable cash generation stability relative to other rated Canadian income funds. Year end working capital requirements are expected to remain at levels consistent with December 31, 2007 balances, with higher balances in the second and third quarters and lower balances in the first and fourth quarters. There are no significant liquidity risks associated with the Partnership's financial instruments, including its foreign exchange contracts. The collapse of the asset backed commercial paper market in Canada was illustrative of the broader issues that have developed in the US housing markets and global credit markets generally. This has resulted in reduced debt market liquidity and widening credit spreads. The existing operations of the Partnership are not impacted by these changes as the Partnership's debt is under long-term fixed rate agreements with no significant near term maturities and the Partnership continues to roll forward $300.0 million in available credit facilities. The Partnership believes it can continue to access capital markets in the event that new financing is required for an acquisition or major capital project. TRANSACTIONS WITH RELATED PARTIES Years ended December 31 (millions of dollars) 2007 2006 ------------------------------------------------------------------------- Transactions with EPCOR ----------------------- Revenue - Frederickson duct firing capacity fees 0.1 - Cost of fuel - Castleton gas demand charge 2.1 2.2 Operating and maintenance expense 49.4 32.0 Management and administration Base fee 1.3 1.2 Incentive fee 2.2 2.1 Enhancement fee 0.7 1.1 Administration fee 0.8 0.7 ------------------------------------------------------------------------- 5.0 5.1 ------------------------------------------------------------------------- Acquisition fees - 7.9 ------------------------------------------------------------------------- Transactions with PERC ---------------------- Revenue - base management fees 3.4 0.6 ------------------------------------------------------------------------- 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 years ended December 31, 2007 and 2006 (see Note 16 to the consolidated financial statements for further details). Operating and maintenance expense, cost of fuel, base fees and administration fees represent fees that are intended to reimburse EPCOR for the provision of operating and maintenance services and materials or commodities. Incentive and enhancement fees are intended to provide EPCOR with an incentive to maximize cash provided by operating activities that in turn are used to make distributions. Acquisition fees are intended to both reimburse EPCOR for its costs associated with acquiring and integrating new assets and to provide EPCOR with an incentive to grow the Partnership and related cash flows. The Partnership distributes cash to EPCOR in the amount proportionate to their ownership interest. At December 31, 2007, EPCOR owned 30.6% of the Partnership's units (2006 - 30.6%). CONTRACTUAL OBLIGATIONS AND CONTINGENCIES At December 31, 2007, the Partnership's future purchase obligations were estimated based on existing contract terms, estimated inflation and foreign exchange rates as at December 31, 2007: Contractual Obligations Years ended December 31 ------------------------------------------------------------------------- Later (millions of dollars) Note 2008 2009 2010 2011 2012 years ------------------------------------------------------------------------- Gas purchase contracts (1) 53.9 56.6 57.5 56.1 60.4 195.4 Gas transportation contracts (2) 11.8 12.1 12.5 12.9 10.9 38.9 Operating and maintenance contracts (3) 27.7 27.3 28.1 29.0 29.8 171.0 Waste heat contracts (4) 0.8 0.9 0.9 0.9 0.9 9.9 Long-term debt (5) 1.1 1.3 1.4 - - 621.3 Interest payments on long-term debt 37.1 37.0 36.8 36.8 36.8 380.6 ------------------------------------------ Total 132.4 135.2 137.2 135.7 138.8 1,417.1 ------------------------------------------------------------------------- (1) Gas purchase contracts have expiry dates ranging from 2010 to 2016 with built-in escalators. (2) Gas transportation contracts are based on estimates subject to changes in regulated rates for transportation and have expiry dates ranging from 2011 to 2017. (3) Operating and maintenance contracts for the Ontario Plants, Mamquam, Queen Charlotte, Williams Lake, Castleton, Curtis Palmer and Manchief are based on fixed fees escalated annually by inflation and have expiry terms ranging from 2008 to 2018. Operating and maintenance contracts for the remaining power plants flow-through expenses. (4) Waste heat contracts continue while the plants are in operation. Prices are escalated yearly by the prior year's CPI. (5) Includes principal repayments under the term debt of $3.8 million in aggregate, the US$190.0 million debt in 2014, the US$150.0 million debt in 2017, the US$75.0 million debt in 2019 and the $210.0 million debt in 2036. The SRAC at the California plants may be retroactively adjusted by the CPUC. The Partnership estimates that its maximum exposure would be approximately US$28 million. The Partnership can recover payments related to the Naval facilities from the US Navy under the terms of the SPAs. Additionally, the previous owners of the facilities will reimburse the Partnership for up to 80% of any payments net of recoveries through November 25, 2008. The Partnership has not recorded a liability as it estimates that an unfavourable outcome is unlikely. The Partnership is legally required to remove a majority of its power generation facilities at the end of their useful lives and restore the plant sites to their original condition. The Partnership estimates that the undiscounted amount of cash flow required to settle its asset retirement obligations is approximately $139.1 million, calculated using an inflation rate of 3%. The expected timing for settlement of the obligations is between 2012 and 2090. The majority of the payments to settle the obligations are expected to occur between 2022 and 2070. OFF-BALANCE SHEET ARRANGEMENTS At December 31, 2007 the Partnership did not have any off balance sheet arrangements. CRITICAL ACCOUNTING ESTIMATES Since a determination of many assets, liabilities, revenues and expenses is dependent on future events, the preparation of the Partnership's consolidated financial statements requires the use of estimates and assumptions which are made using careful judgment. The Partnership's most significant accounting estimate relates to its calculation of depreciation and amortization expense. Useful lives of assets The useful lives of the Partnership's property, plant and equipment and PPA assets are estimated for purposes of determining depreciation and amortization expense, in determining asset retirement obligations and in testing for potential impairment of long-lived assets. The estimated useful lives of assets are determined based on judgment, current facts, past experience, designed physical life, potential technological obsolescence and contract periods. The Partnership depreciates and amortizes its property, plant, equipment and PPA assets over their estimated useful lives. The Partnership amortizes its power generation plant and equipment, less estimated residual value, on a straight-line basis over their estimated remaining useful lives. Other equipment is capitalized and amortized over estimated service lives. PPAs are amortized on a straight line basis over the remaining lives of the contracts. Fair values Fair values are estimated to measure asset retirement obligations, to measure impairment, if any, of long-lived assets and goodwill, to determine purchase price allocations and to value derivative instruments. Expected demolition, restoration and other related costs to settle the Partnership's asset retirement obligations are estimated and discounted at an appropriate credit-adjusted risk-free rate to determine the fair value of the asset retirement obligations. Undiscounted cash flows are used to test for asset impairment. If the carrying value of the asset is more than the undiscounted cash flows, an impairment loss is recognized to the extent the carrying value exceeds fair value. For determining purchase price allocations for business combinations, the Partnership is required to estimate the fair value of certain assets and liabilities. Goodwill arising on a business combination is tested for impairment at least annually or more frequently if events and circumstances indicate that a possible impairment may arise earlier. To test for impairment, the fair value of the reporting unit is compared to the carrying value, including goodwill, of the reporting unit. If the carrying value of the reporting unit exceeds its fair value, the fair value of the reporting unit's goodwill is compared with its carrying amount to measure the impairment loss, if any. Estimates of fair value for asset retirement obligations, purchase price allocations and long-lived asset and goodwill impairment testing are based on discounted cash flow techniques employing management's best estimates of future cash flows based on specific assumptions and using an appropriate discount rate. Fair values of derivative instruments including foreign exchange contracts and natural gas supply contracts are based on quoted market prices, except for natural gas prices for periods after 2012. There are limited observable natural gas prices beyond 2012 after which the Partnership relies on price forecasts prepared by a third party market expert. Changes in fair values are recorded in revenue, cost of fuel, foreign exchange gains/losses and financial charges and other in the income statement and in derivative instruments asset/liability on the balance sheet. Because useful lives and fair values are used in determining potential impairments for each long-lived asset, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers. SIGNIFICANT ACCOUNTING POLICIES Revenue recognition Revenue is recognized when energy is delivered under various long-term contracts. Revenue under the Curtis Palmer PPA is recognized at the lower of (1) the MWhs made available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh over the term of the contract from the date of acquisition. Any excess of the current period contract price over the average price is recorded as deferred revenue. Finance income related to leases accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The investment in the lease for purposes of income recognition is composed of net minimum lease payments and unearned finance income. Unearned finance income, being the difference between the total minimum lease payments and the carrying value of the leased property, is deferred and recognized in earnings over the lease term. Foreign currency translation The Partnership indirectly owns US subsidiaries, the accounts of which are integrated with those of the Partnership and translated into Canadian dollars using the temporal method. Under this method, monetary assets and liabilities and non-monetary assets carried at market are translated at the exchange rate in effect at the balance sheet date. Non-monetary assets and liabilities carried at cost are translated at historic exchange rates. Revenues and expenses are translated at rates in effect at the time of the transactions. The resulting foreign exchange gains and losses are included in the consolidated statements of income. Long-term investments The Partnership owns 17.0% of the common interests and 14.2% of the preferred interests in PERH. The Class B common interest has been accounted for using the equity method of accounting. The Class B preferred interest has been accounted for using the cost method of accounting. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2007, the Partnership adopted new Canadian Institute of Chartered Accountants (CICA) accounting standards: Financial Instruments - Recognition and Measurement, Financial Instruments - Disclosure and Presentation, Hedges, Comprehensive Income and changes to the Equity standard (collectively the new accounting standards). The changes and the impact of these changes on the Partnership's consolidated financial statements are described in Note 3 to the consolidated financial statements. In accordance with the requirements of the new accounting standards, the Partnership has not restated any prior year as a result of adopting the accounting changes but has recorded certain transitional amounts that represent the cumulative effect of adjustments relating to prior years in opening deficit and in opening accumulated other comprehensive income. On January 1, 2007, the Partnership made the following adjustments to its balance sheet to adopt the new accounting standards: Balance Sheet Category As at Increase (Decrease) January (millions of dollars)(unaudited) 1, 2007 Explanation ------------------------------------------- ----------------------------- Other Assets (4.5) To no longer record deferred financing costs as other assets using straight-line amortization Derivative instruments - asset 96.0 To record natural gas supply contracts at fair value Derivative instruments - net liability (8.6) To no longer record deferred unrealized gains as derivative instruments Long-term debt (4.6) To record deferred financing costs as debenture discounts using effective interest method Opening deficit (96.1) After tax impact to opening deficit resulting from adoption of new standards Opening accumulated other 8.6 To record deferred comprehensive income unrealized gains as accumulated other comprehensive income ------------------------------------------- ----------------------------- The financial instrument accounting standard requires that interest income and expense be allocated over the relevant year using the effective interest method (EIM). Under the EIM, interest income and expense is calculated and recorded using an effective interest rate, which is the rate that discounts estimated future cash payments or receipts through the expected life of the financial instrument or, when appropriate, a shorter year, to the initial net carrying amount of the financial asset or liability. Transaction costs that are directly attributable to the acquisition or issue of financial instruments classified as other than "held for trading" are either included in the initial carrying value of such instruments and amortized using the EIM or expensed. The Partnership has chosen as its accounting policy to include transaction costs as part of the initial carrying amount of the debt and as a result deferred financing costs have been reclassified against long-term debt and the method of amortization of deferred financing costs has been changed to the EIM from the straight-line method. Transaction costs on financial instruments classified as "held for trading" are expensed. The Partnership has no transaction costs relating to financial instruments that are classified as held for trading. Upon implementation, the Partnership's opening deficit was reduced by $0.1 million. A new financial statement entitled "Consolidated Statement of Comprehensive Income" has been added to the set of consolidated financial statements. Each component of the Consolidated Statement of Comprehensive Income has been recorded net of income taxes. The balance of deferred gains on derivatives (cash-flow hedges) that were previously de-designated will be reclassified to the income statement in the year that the corresponding unrealized foreign exchange gain or loss is realized or the corresponding hedged item of the de-designated cash flow hedge affects net income. The cumulative amount of these other comprehensive income components is called "accumulated other comprehensive income" and is included as a new category in partners' equity. Opening accumulated other comprehensive income was $8.6 million upon implementation of the new accounting standards. Non-financial derivatives that are designated as contracts for the purpose of receipt of or delivery of a non-financial item in accordance with expected purchase, sale or usage requirements are excluded from the requirements of the new accounting standards. Accordingly, revenues and expenses incurred on these contracts are recorded in the income statement at the contract settlement date as they have in the past. Non-financial derivatives that are not designated as contracts for the purpose of receipt of or delivery of a non-financial item are recorded at fair value at each balance sheet date, with any corresponding changes in fair value recognized in net income in the year. Upon the implementation of the new accounting standards, the Partnership was required to treat its Ontario long-term natural gas supply contracts as non-financial derivatives as they did not meet the criteria for the normal usage exception for executory contracts. The natural gas supplied under contract to its Ontario facilities is at times re-sold in the market and not entirely used to produce electricity. As a result, these contracts did not meet the requirements for the normal usage exception. Previously, the contracts were accounted for by the accrual method and were not recorded at fair value. The fair value of the contracts at January 1, 2007 was $96.0 million and was recorded as an adjustment to the opening deficit. Subsequent changes in the fair value of these contracts are reported in the Partnership's income statement. The adoption of the new accounting standards will result in increased variability in net income although it will have no impact on cash flows. During the year ended December 31, 2007 these new financial instrument accounting standards impacted the financial statements in the following manner: For the year ended or as at Financial Statement Category December Increase (Decrease) - $ millions 31, 2007 Explanation ------------------------------------------------------------------------- Accumulated other comprehensive loss (3.5) To reclassify accumulated other comprehensive income related to de-designated cash flow hedges to income Cost of fuel 32.4 To record change in the fair value of natural gas contracts from January 1, 2007 to December 31, 2007 Derivative instruments - asset (32.4) ------------------------------------------------------------------------- Losses of $32.4 million were recorded in the year ended December 31, 2007 to reflect the change in fair value of natural gas supply contracts and were included in cost of fuel. Accumulated other comprehensive income was decreased by $3.5 million for the year ended December 31, 2007 due to the reclassification of gains on de-designated hedges to revenue. Under the Partnership's previous accounting policy, the reclassification to revenue would have been from derivative financial instruments net liability. The impact of the EIM was insignificant in the year. FUTURE ACCOUNTING STANDARDS International financial reporting standards In 2005, the CICA announced plans to converge Canadian GAAP with International Financial Reporting Standards (IFRS) over a transition period from 2006 to 2011. The CICA indicated that Canadian entities will be required to begin reporting under IFRS effective the first quarter of 2011 including comparative figures. A high level IFRS implementation plan has been developed and an assessment of the financial statement impact of the accounting standard differences is currently in progress. Based on the analysis to date, the most significant differences for the Partnership are anticipated to be related to property, plant and equipment, 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, in time to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes at the required implementation date. Capital disclosures and financial instruments - presentation and disclosures On December 1, 2006, the CICA issued the new CICA Handbook Sections 1535, 3862 and 3863 for Capital Disclosures and Financial Instruments - Disclosures and Presentation. Effective January 1, 2008, the Partnership will adopt these new accounting standards. As required by the new standards, the Partnership will disclose 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 disclosures will also include information on how the Partnership manages its capital. Inventories Effective January 1, 2008 the new CICA Handbook Section 3031 - Inventories will replace Section 3030 to be consistent with the international accounting standard for inventories. The new section requires inventories to be measured at the lower of cost and net realizable value. The Partnership currently measures inventories at the lower of cost and replacement cost. The Partnership does not expect the adoption of the new standard to result in a material transition adjustment to its financial statements. 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. INTERNAL CONTROL OVER FINANCIAL REPORTING As of December 31, 2007, management conducted an evaluation of the design and effectiveness of the Partnership's disclosure controls and procedures. The evaluation took into consideration the Partnership's Disclosure Policy, the sub-certification process that has been implemented, and the functioning of its Disclosure Committee. In addition, the evaluation covered the Partnership's processes, systems and capabilities relating to public disclosures, and the identification and communication of material information. Based on that evaluation, the President (acting as Chief Executive Officer) and the Chief Financial Officer of the General Partner have concluded that the Partnership's disclosure controls and procedures are appropriately designed and effective. Also as of December 31, 2007, management conducted an evaluation of the design of internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting. Based on that evaluation, the President and the Chief Financial Officer have concluded that the Partnership's internal controls over financial reporting are appropriately designed. These evaluations were conducted in accordance with the standards of the Committee of Sponsoring Organizations, a recognized control model, and the requirements of the Canadian Securities Administrators' Multilateral Instrument 52-109. There were no changes in the Partnership's internal controls over financial reporting that occurred during the year ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect the Partnership's internal control over financial reporting. BUSINESS RISKS The Partnership operates assets under long-term power and steam sales and energy supply contracts, which combined with an excellent ongoing maintenance program, minimize exposures to operational risk and commodity price and supply fluctuations. The most significant risks to the Partnership are those noted below. Operational risk The Partnership's plant operations are susceptible to outages due to equipment failure, which could make plants unavailable to provide service. Plant personnel have developed procedures to minimize the plant downtime required for both scheduled and unscheduled maintenance. The Partnership's maintenance practices are supported by the maintenance of an inventory of strategic spare parts, which can reduce downtime considerably in the event of failure. Strict safety standards are in place at all plants. In addition, the Partnership maintains reasonable insurance to cover losses resulting from equipment breakdown and business interruption, although there can be no assurance it will cover all losses. The Partnership's combination of strong operating history and preventative maintenance programs has minimized the impact to the Partnership of significant increases in power plant insurance premiums that have been experienced throughout the power industry in recent years, although it may not be able to do so in the future. Contract expiry risk The Partnership's 20 plants have PPAs that expire between June, 2008 and 2027 and fuel supply agreements that expire between 2009 and 2019. In order to stabilize future cash flows, the Partnership will seek to re-contract its existing plants under new or extended contracts and acquire new plants that meet its investment criteria. The commercial environment for North American power generation is very competitive and therefore there is no assurance that the Partnership will be successful in recontracting its existing plants or acquiring new plants. PPA contracts The Castleton PPA expires in June 2008. Operating margin from the facility is expected to be lower after the PPA expires and may be more volatile if the Partnership is not successful in recontracting. If the plant is not recontracted, unfavourable market conditions could result in negative operating margins. The PPAs for the North Carolina facilities and the Kenilworth facility expire in 2009. The Partnership expects to be able to replace the PPAs with similar new agreements, however there is no assurance that the new agreements will provide a similar level of operating margin and it could be lower. The Navy has the right to terminate the Naval Facility Negotiated Utility Service Contracts for convenience on one year's notice. These agreements grant the Partnership access rights to the Naval Facilities that are operated to produce and sell electricity under the Naval Facility PPAs. The termination would result in the loss of the Naval Facilities' steam host and subsequently its QF status which in turn would allow SDG&E to terminate the Naval Facility PPAs. The terms of the Kenilworth Energy Supply Agreement provide Schering the right to terminate the agreement when the price of natural gas exceeds a certain threshold. Although the Partnership does not expect that this termination right will be exercised, there can be no assurance that this will not occur. Fuel supply Wood waste is required to fuel the Partnership's two Canadian biomass wood waste plants, Williams Lake and Calstock, which expose the Partnership to increasing price and supply risk for wood waste as demand for wood waste increases. At Williams Lake, the cost of delivered wood waste for the firm energy component (approximately 80%) is flowed through to BC Hydro. The Partnership is at risk for the wood waste price escalation for the remaining 20% of the fuel supply. The pine beetle infestation in the area is expected to continue to have a positive impact on the fuel supply for the plant in the short to medium term, but may adversely impact the long term availability of waste wood. At Calstock, the Partnership procures its wood waste from a number of suppliers. In 2006, a fire temporarily impacted one supplier while another supplier closed its mill. Combined, these two suppliers represented approximately 40% of Calstock's fuel supply. These volumes have since been replaced through a combination of mill re-openings and procurement of new supply. The high Canadian dollar and a depressed US housing market have placed economic hardships on Ontario forestry mills which may impact future wood supply at Calstock. In August 2007, the Partnership was successful in negotiating a two year agreement with a new wood supplier to provide up to 25% of Calstock's annual requirements. Existing coal supply contracts will meet the 2008 requirements and half of the 2009 requirements for Roxboro and Southport. While the Partnership believes that coal supply will be available for these facilities, there can be no assurance of when or upon what terms, including pricing, the existing supply agreements will be renewed or replaced. Commodity Price Risk Risks associated with the uncertainty of the competitive marketplace, especially volatility in market prices for electricity, have been managed by fixed-price, long-term power sales contracts in place with investment grade power and steam buyers. In addition, risks associated with volatility of market prices for natural gas for supply of substantially all the natural gas requirements of the Partnership's gas plants have been managed by a combination of fixed-price long-term contracts, tolling arrangements and variable charges that are linked to the price of natural gas. For Tunis, the Partnership is exposed to commodity price risk on its natural gas purchases beginning in 2010 when its energy supply agreements end prior to expiry of the OEFC PPA in 2014. Certain natural gas-fired facilities in the US have PPAs extending for terms which extend beyond existing supply contracts. Failure to contract for additional fuel supply at the end of existing contract terms may lead to a disruption in operations and an inability to perform under the power and steam purchase agreements. Natural gas prices also impact the economic viability of the Partnership's ability to earn enhancement revenue and diversion sales from the curtailment of electricity production in favour of selling the unused natural gas at prevailing market prices. Electricity prices under the PPAs for the Naval facilities and Oxnard are based on the purchasing utilities' SRAC. The SRAC formula is set by the CPUC and is subject to adjustment. In the future, the CPUC may make adjustments to the SRAC formula to change the basis on which future electricity prices will be determined for these facilities. The Partnership's investment in PERH and the related management agreement are influenced by the performance of PERH. PERH owns a 50% interest in the Harbor Coal facility, a coal pulverizing facility located at a steel mill in Indiana, which is exposed to commodity price risk related to the cost of coke, coal, natural gas and oil. Environment, health and safety risk The Partnership's operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines. If the Partnership fails to comply with environmental requirements, regulators could impose penalties and fines on the Partnership or curtail its operations. As environmental laws, regulations and guidelines change, the Partnership may incur unforeseen capital expenditures and operating costs of in order to comply or may be unable to comply with more stringent standards causing the Partnership to close certain facilities. As the Partnership's electricity generation business emits carbon dioxide (CO(2)), it must comply with emerging federal, state and provincial requirements including programs to offset emissions. The Partnership complies, in all material respects, with current federal, provincial, state and local environmental legislation and guidelines. The Partnership has implemented health and safety management programs designed to continuously improve health and safety performance and is in the process of aligning with the requirements of Occupational Health and Safety Assessment Series 18001. Canada On April 26, 2007, the Canadian Environment Minister announced a new regulatory framework to reduce greenhouse gas emissions and air pollution in Canada. The Canadian government has set targets of a 20% reduction in greenhouse gases by 2020 and a 50% reduction in air pollution by 2015. The Partnership is an emitter of CO(2) (a greenhouse gas), nitrogen oxide (NOx) and sulphur dioxide (SO(2)), which are all targeted for reduction under the proposed new legislation. Under the proposed legislation, the Ontario natural gas plants would be required to reduce or offset CO(2) emissions by 18% in 2010 increasing by 2% annually to a cumulative total of 33% by 2020. The Ontario natural gas plants' emission intensity of approximately 0.34 tonnes per MWh produced cannot be economically reduced with currently available technology and the Partnership may be required to purchase CO(2) offsets. The proposed legislation has a cap on the price of CO(2) offsets of $20 per tonne, which could result in additional cost to the Partnership of approximately $1 million annually beginning in 2010 escalating to $2 million annually by 2020 if there is no mechanism for recovery from OEFC. The existing PPAs for these facilities expire between 2012 and 2017 and the Partnership expects that at least some portion of these costs would be factored into any new PPA terms. It remains unclear whether the Canadian federal government will also introduce minimum emission thresholds to which these proposed standards will apply. Currently, three of the four Ontario natural gas-fired power facilities emit less than 100,000 tonnes of CO(2) annually. The Partnership estimates its costs to comply with anticipated legislation for NOx emission to be in the range of $3 to $4 million in additional one-time capital costs for low NOx burners at Nipigon and Tunis. The wood waste plants may also be subject to SO(2) and mercury reduction requirements within the next five to seven years. United States The Partnership continually assesses the potential impact of future legislation and regulatory requirements for certain air emissions under the United States' Clean Air Act (US CAA). The CAA Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR) will affect Roxboro and Southport beginning in 2009. The North Carolina plants were pulled into the CAIR program, but did not receive NOx and SO(2) allocations. The costs associated with purchasing the required offset allocations are projected at approximately $1.5 million per year. Engineering and operating solutions are being pursued which will combine operating methods, such as alteration to the fuel mix, and emissions controls to reduce the annual cost. The North Carolina plants are classified as low emitters of mercury as they emit less than nine pounds per year at each plant. The plants will be required to install mercury emission monitoring equipment in order to comply with the CAMR. The cost of the monitoring equipment is estimated at less than $0.2 million. The enhancements to the boilers at Southport and Roxboro, if undertaken, will result in reductions of environmental emissions (see Liquidity and Capital Resources - Capital expenditures). Kenilworth in New Jersey and Castleton in New York are potentially affected by the Regional Greenhouse Gas Initiative applicable in seven New England states. The regulations are implemented on a state-by-state basis and the Partnership is monitoring the state proposals and evaluating their impact on operations. California has recently enacted stringent limits on greenhouse gas emissions, and is currently developing regulations to implement the program. The Partnership is monitoring the state's progress and the features of the program to assess the financial and operational implications on its facilities. Compliance with new requirements may require additional significant capital expenditures and cause the Partnership to incur additional operating expenses, although the Partnership is unable to quantify these amounts until the requirements, in the context of the Partnership's facilities, become clearer. Government risk The Partnership is subject to risks associated with changes in federal, provincial, state or local laws, regulations and permitting requirements. It is not possible to predict changes in laws or regulations that could impact the Partnership's operations, income tax status or ability to renew permits as required. The Partnership monitors the development of any potential changes in laws or regulations in order to manage the risks by proactively planning for any changes and working with governments and regulators to mitigate issues. Tax risk The SIFT Legislation included in Bill C-52 was enacted in 2007 and will result in changes to how certain publicly traded trusts and partnerships, including the Partnership, are taxed. The SIFT Legislation generally operates to apply a tax at the SIFT level on certain income at tax rates comparable to the combined federal and provincial corporate tax and then re-characterize that income net of tax payable pursuant to the SIFT Legislation as taxable dividends in the hands of unitholders. The SIFT Legislation will apply to the Partnership starting the earlier of January 1, 2011 or January 1 of the year following the date at which the Partnership exceeds the normal growth guidelines (Guidelines) issued by the Department of Finance (Canada) on December 15, 2006. The Guidelines indicate that no change will be recommended to the 2011 date if the issuances of new equity before 2011 does not exceed an objective "safe harbour" amount based on a percentage of the SIFTs market capitalization as of the end of trading on October 31, 2006. The Partnership expects that it can issue up to $1.7 billion of additional equity before 2011 without accelerating the date that it becomes subject to the SIFT Legislation. Canadian rules (Anti-Tax Haven Provisions) restricting interest deductibility effective 2012 in respect of "double dip" financing structures as defined by the Interest Deductibility Provisions and amending foreign affiliate rules were included in Bill C-28 and enacted in 2007. As currently enacted, the Partnership does not expect to be materially impacted by the Anti-Tax Haven Provisions but there is no assurance that the Anti-Tax Haven Provisions will not change to apply to the Partnership in the future. On September 21, 2007, the US and Canada signed the fifth protocol to the US - Canada Income Tax Treaty (Treaty), which contains extensive changes to the current Treaty. Although the Treaty contains positive changes such as the elimination (over a 3 year phase-out period in the case of interest payable to a related party) of non-resident withholding tax on interest, it also included the addition of a treaty denial provision applicable to payments obtained from or through certain hybrid entities. The Treaty has not been ratified yet and the treaty denial provision is not effective earlier than 2010. The Partnership is continuing to evaluate the potential impact, if any, that the treaty denial provisions will have but expects to address the treaty denial provisions without realizing any material adverse consequences. In the last five years, numerous proposals have been made to tighten the US rules (Earnings Stripping Rules) with respect to the deductibility of interest paid by US corporations to, or guaranteed by related parties, who do not fully pay US tax on such interest income. On November 28, 2007, the US Treasury Department issued a report on three international tax issues including the Earnings Stripping Rules that concluded that broad based tightening of the Earnings Stripping Rules was warranted. If tightening were to occur, it would negatively impact the Partnership. Changes in tax legislation, not limited to changes or potential changes discussed above, may have an adverse impact on the Partnership, its unitholders and the value of the units. The Partnership monitors the development of any potential changes in tax legislation in order to manage the risks by proactively planning for any changes. Foreign exchange risk management The Partnership owns and operates 12 facilities in the US and has borrowings outstanding that are denominated in US dollars and accordingly, the associated net cash flows are subject to foreign currency gains and losses based on changes in the US to Canadian dollar exchange rate. The Partnership manages the foreign exchange risk of its future anticipated US dollar-denominated cash flows from its US plants net of debt service obligations on US dollar borrowings through the use of foreign exchange contracts for periods up to seven years. At December 31, 2007, US$280.6 million or approximately 83% of future net cash flows had been economically hedged for 2008 to 2013 at a weighted average exchange rate of 1.13. By year, the amounts hedged and average rates are as follows: ------------------------------------------------------------------------- (millions of US dollars except average exchange rate) 2008 2009 2010 2011 2012 2013 ------------------------------------------------------------------------- Forward foreign exchange sales 49.6 45.3 41.6 47.6 50.9 45.6 Average exchange rate (US / CDN) 1.28 1.16 1.09 1.09 1.08 1.09 ------------------------------------------------------------------------- Waste heat supply risk The Partnership's Ontario natural gas-fired plants also generate electricity from the waste heat gases of adjoining natural gas compressor stations. Supply of the waste heat gases is secured under long term contracts; however the availability of the waste heat gases varies depending on the output of the compressor stations along the pipeline system, and the host altering those operations under the terms of a Waste Heat Optimization Agreement with the Partnership. In addition, the availability of waste heat gases is also dependent on the compressor stations remaining in use and their ability to supply the waste heat gases. In 2007, waste heat contributed approximately 20% of power revenue at the Ontario plants. In January 2007, the Partnership was advised that changes to the pipeline may reduce the availability of waste heat to the North Bay facility. Over 2007, throughput on the mainline continued to decline because of decreasing market demand in Northern Ontario, structural changes in the underlying long haul transportation agreements with its shippers, the conversion of an upstream high pressure natural gas line to oil, and the addition of looping in and around the North Bay shortcut. It is expected that the Partnership will see both increased costs and decreased waste heat availability from those levels experienced in prior years. The Partnership continues to work with the host to better understand the potential impact with a goal of mitigating any negative impacts. 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 SPAs 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. Qualifying facility status risk Certain US facilities are dependent on steam counterparties for steam sales and their QF status. In certain cases, the impact of the loss of a steam counterparty, or the termination of a steam purchase arrangement, on a facility's QF status could be mitigated either through contractual terms or operational changes. However, the loss of QF status could have adverse consequences to the Partnership. As a result of the loss of QF status, the facility could become subject to rate regulation by the Federal Energy Regulatory Commission under the US Federal Power Act and additional state regulation. Loss of QF status could also trigger defaults under covenants to maintain QF status in the facilities' PPAs, SPAs and financing agreements and result in termination, penalties or acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and paying for electricity, or were to seek to obtain refunds of past amounts paid because of the loss of QF status, the Partnership cannot provide assurance that the costs incurred in connection with the facility could be recovered through sales to other purchasers. Hydrology, weather and catastrophic event risk Performance of the Partnership's hydroelectric facilities is partly dependent upon the availability of water. Variances in water flows are caused by non-controllable weather related factors affecting precipitation and could result in volatility of hydroelectric plant revenues. In addition, the Partnership's hydroelectric facilities are exposed to potential dam failure, which could also effect water flows and have an impact on revenues from the associated plants. The Partnership's maintenance practices comply with national standards, limiting the risk of a dam failure. Weather conditions and other unforeseen natural events can force the Partnership's facilities to cease operations which can adversely affect the Partnership. A natural disaster or other catastrophic event, such as an earthquake, hurricane, fire, flood, severe storm, terrorist attack or other comparable event at any of the Partnership's facilities, could disrupt operations at or cause substantial damage to such facilities. The Partnership has obtained insurance, including earthquake insurance to mitigate any financial costs arising from such events, however, there can be no assurance that it is adequate to cover all losses. Credit facilities The Partnership will need to refinance its indebtedness under its various credit facilities outstanding at their maturity dates. Future cash distributions of the Partnership may be adversely affected if the Partnership is unable to refinance its indebtedness on terms and conditions at least as favourable as the existing terms and conditions of such indebtedness. If the Partnership is unable to refinance its indebtedness then at maturity the Partnership will have to use available cash to repay the indebtedness. This may adversely affect the ability of the Partnership to make distributions. The Partnership's revolving credit facilities with Canadian chartered banks provide that the Partnership may not declare, make or pay distributions if (subject to certain limited exceptions) a default or event of default has occurred and is continuing under such facilities. PERH distributions The credit facilities provided by senior lenders to PERH provide that specified amendments to the Harbor Coal contract be signed by February 29, 2008. While PERH is progressing on an amendment to the Harbor Coal contract, an amendment was not executed by this date. As a result, PERH is subject to increased interest costs and may be subject to cash sweeps if certain leverage ratios are not met, both of which could adversely impact PERH's ability to continue making its distributions to the Partnership. If the Harbor Coal amendment is completed, the increased interest and cash sweep provisions terminate. Conflict of interest risk Certain conflicts of interest could arise as a result of the Partnership's relationship with EPCOR. Management and the Board of Directors have procedures in place which seek to ensure any conflict which surfaces between the Partnership and EPCOR is appropriately addressed. This includes the requirement for approval by a majority of independent board members of transactions between the Partnership and EPCOR. In addition, certain conflicts of interest could arise as a result of the Partnership's relationship with PERC. Ventures, an indirect subsidiary of the Partnership, provides management and administrative services to PERC, PERH and PERH's subsidiaries under the PERC Management Agreement. PERC, through PERH and its subsidiaries, engages in activities similar to those of the Partnership and certain directors and senior officers of the Partnership are directors and managers of PERC, PERH and PERH's subsidiaries. In connection with the closing of the Ventures acquisition, the Partnership and PERC entered in to an Allocation Agreement which is designed to allocate certain power project opportunities amongst themselves and clarify development and acquisition rights. General economic conditions and business environment Changes in general economic conditions in the markets within which the Partnership operates could impact product demand, revenue, operating costs, and credit and counterparty risk, as well as the timing and amount of capital expenditures made by the Partnership. Changes in general economic conditions may also affect the Partnership's financing costs and access to capital markets. Moreover, the Partnership is subject to changes to policies, statutes and regulations, as well as technological change, that could alter the business environment in which the Partnership operates. Such changes could reduce the ability of the Partnership to compete or reduce the profitability of its business. The Partnership's ability to mitigate these risks is dependent, to some degree, on EPCOR's ability, as the manager, to anticipate such risks and, where possible, to develop appropriate mitigation plans. Limited liability A unitholder may lose the protection of limited liability if it takes part in the management or control of the business of the Partnership or does not comply with applicable legislation governing limited partnerships. Structural subordination The right of the Partnership, as a shareholder of any of its subsidiaries, to realize on the assets of a subsidiary in the event of the bankruptcy or insolvency of the subsidiary would be subordinate to the rights of unsubordinated creditors of such subsidiary, holders of unsubordinated preferred shares of such subsidiary and claimants preferred by statute. Preferred Share distribution guarantee The Preferred Shares of EPCOR Power Equity Ltd. are fully and unconditionally guaranteed by the Partnership on a subordinated basis as to (i) payment of dividends, as and when declared, (ii) payment of amounts due on redemption of the Series 1 Shares, and (iii) payment of amounts due on liquidation, dissolution or winding up of EPCOR Power Equity Ltd. The Partnership has agreed that as long as the declaration or payment of dividends on the Preferred Shares is in arrears, the Partnership will not make any distributions on the units. There is no assurance that risk management or mitigation steps taken will avoid future loss due to the occurrence of the above described or unforeseen risks. OUTLOOK 2007 was a challenging year for both the Partnership and Canada's power trust sector as a whole. The Canadian federal government's SIFT Legislation has adversely affected the unit price of the Partnership and the unit prices of most of our power trust peers. There has been significant consolidation within the sector in 2007 as many trusts were acquired. We expect there will be further consolidation as we approach 2011. The Partnership is well positioned to compete in the face of this changing landscape. Unlike many income trusts that will convert to a corporate form by 2011, our partnership structure provides us with significant flexibility to address the forthcoming tax changes. In addition, our asset base provides relatively stable and sustainable cash flows. This suggests the Partnership's current position as a high yield flow through entity may continue to be appropriate for some time after 2010. This is further supported by the following considerations: - Based on our long-term forecast and current tax legislation, we do not expect to pay cash taxes on income in Canada until at least 2013 and in the US until at least 2014; - The Partnership's combination of assets in Canada and the US provides additional tax planning opportunities; - We have maintained a fiscally conservative profile with foreign currency hedges in place through 2013 and fixed rate debt whose maturities are well spread with no significant near term debt maturities; - The structure of our PPAs and fuel contracts and the nature and age of our assets provide long-term stable cash flows; - We have a strong balance sheet with good access to capital markets; - EPCOR is a strong sponsor with excellent operating and development expertise; - We operate in growth markets with excellent assets; - There is a growing demand for power infrastructure across North America with declining reserve margins (the excess of power generating capacity over peak demand); and - There continues to be demand in the Canadian investor base for high yielding investments. Cash provided by operating activities, excluding realized losses on interest rate and foreign exchange contracts that were entered into on the Ventures acquisition, plus PERH dividends less maintenance capital spending, exceeded distributions by $7 million in 2007. This follows surpluses of $19 million in 2006, $13 million in 2005 and $15 million in 2004. In 2008, in part due to forecasted high maintenance capital spending, we expect distributions at $2.52 per unit will exceed cash provided by operating activities plus dividends from PERH less maintenance capital spending. In addition to the higher capital spending discussed earlier in this MD&A, the items that are expected to give rise to the drop in cash provided by operating activities from 2007 to 2008 are: - The expiry of the Castleton PPA in June 2008. This facility currently provides approximately $8 million of operating margin annually. Operating margin after the PPA expires is expected to be positive but at a lower level; - A milestone maintenance payment at Frederickson. Frederickson was dispatched at higher rates in the third quarter of 2007 due to low natural gas prices. As a result, under its long-term service agreement with the turbine manufacturer, a milestone payment of $4 million is expected to be paid in 2008 as opposed to earlier estimates of 2009; - Higher fuel prices in Ontario. North Bay and Kapuskasing fuel supply pricing is set to increase 18% from 2007 to 2008 under the 20 year agreements. Over the life of the agreements, fuel supply pricing increases an average of 9%. The increase from 2008 to 2009 is set to increase 6%. These fuel supply increases are expected to be mostly offset by revenue increases under the PPAs; - Arbitration award in 2007. The Mamquam and Queen Charlotte arbitration resulted in an award of $2.3 million in 2007. A further award of $0.3 million will be recorded and received in 2008; and - Higher preferred share dividends and Part VI.1 tax due to a full year of dividends in 2008. Partially offsetting these items are expected lower financing costs in 2008 due to the equity offerings in 2007, expected lower maintenance at Mamquam and improved operating margins at Kapuskasing based on no forecast impacts in 2008 from the transport accident incurred in 2007. In determining per unit distributions, expectations of long-term cash flow to support such distributions are considered as well as existing liquidity to support possible short-term cash shortfalls. Based on current expectations and subject to any material changes that may occur during the year, we expect that 2008 Partnership distributions will be maintained at the current annual level of $2.52 per unit. Contractual items that are expected to impact 2009 cash provided by operating activities relative to 2008 include the expected increase in Curtis Palmer PPA pricing of 18%, subject to meeting cumulative production thresholds, the non-recurrence of the milestone maintenance payment on Frederickson, a full year of Castleton operations without the existing PPA, and lower settlements on the foreign currency contracts which have an average settlement rate of 1.28 in 2008 and 1.16 in 2009. There are four PPAs that expire over the next two years. The Castleton PPA expires in June 2008 and will not be extended. The facility currently generates approximately $8 million in operating margin annually and we expect the contribution to decline by over 50% going forward. We expect electricity demand growth in the region to reduce existing reserve margins for power which should improve the capacity market for facilities like Castleton going forward. We have had expressions of interest from several parties in either purchasing or contracting the plant and are continuing to evaluate these options. The Kenilworth facility's PPA expires at the end of 2009 and we are in active discussions with the existing power and steam counterparty to amend and extend the contract to 2012. Under the terms currently contained in the draft amendments, operating margins are forecast to remain at current levels. Demand growth in North Carolina coupled with the delay of several proposed large power developments has improved the outlook for Southport and Roxboro. Current discussions to amend and extend the PPAs are proceeding. The Board has approved capital spending at Roxboro and Southport that will both improve their economics and meet new more stringent environmental requirements. Capital expenditures through 2009 are expected to be up to $65 million to increase both plants' capability to utilize wood waste and tire-derived fuels, thereby reducing fuel costs as well as increasing dispatch. In addition, these capital funds would be used to modify the facilities to reduce SO(2) and NOx emissions. Our preliminary view is that these additions in conjunction with the corresponding negotiation of new PPAs for both plants would be accretive by approximately ten cents per unit depending on financing assumptions. The rise of the Canadian dollar relative to the US dollar was one of the more significant events in 2007 for Canadian businesses. With 50% of our operating margin originating from US plants in US dollars, and with use of this cash flow to support Canadian dollar distributions, this clearly has implications for the Partnership. Part of our foreign currency hedging strategy involves the issue of US dollar denominated debt to provide a natural hedge of US dollar interest payments against US dollar cash flows. In 2007, as part of the Ventures financing we issued $225 million US in debt in line with this strategy. In addition, we continue to purchase foreign currency hedges in compliance with our foreign exchange risk management policy. We have currently hedged 83% of our anticipated US cash flows out to 2013 at an average rate of 1.13 Canadian to US. If the Canadian dollar remains at current levels or continues to climb, it will however have a long-term impact on the Partnership's cash flows. The outlook for the forestry industry in Canada continues to be challenged given the rise in the Canadian dollar and the slow down in housing construction in North America. In particular this has impacted the Ontario mills that supply wood waste to Calstock. In 2007 we changed the mode of operation to reduce the impact of rising biomass costs. As well an associated two year amendment to our current PPA with the OEFC for this facility has helped alleviate some of the risk around mill closures as it has allowed us to economically expand the area over which we transport wood waste to Calstock. We continue to address the risks associated with wood waste supply and this remains an area of concern. In British Columbia the Williams Lake facility is in an area infested with pine beetles which adds to the already adequate supply of biomass. In general any increase in cost of fuel is flowed through to BC Hydro. Environmental legislation has and will continue to change, placing more stringent requirements on the power industry to reduce CO(2), SO(2), NOx and other particulate emissions. However with these challenges, there will be opportunities. The Canadian federal government may announce in the near term their proposed legislation on new emission standards. We will evaluate any proposed changes and will seek to ensure that we are compliant with any new standards as required. Overall, we are very proud of our fleet of power plants and their environmental footprint. Our biomass facilities significantly reduce the release of CO(2) that would otherwise occur with the decomposition of wood waste. Our hydro facilities are not emitters. The Ontario natural gas facilities utilize waste heat from adjacent gas compressor stations that reduce the use of natural gas by up to 20%. Our combined heat and power facilities in the US maximize the use of energy by exporting steam to site hosts as a by-product of power generation. As noted above, steps are currently underway to ensure compliance with tighter emission standards at our North Carolina facilities. As well, wind generation continues to be a good opportunity for future acquisition and development which is a natural addition to the fleet. We continue to review opportunities for accretive transactions, particularly in light of the consolidation in the power trust market. We have maintained our disciplined approach of pursuing opportunities that meet internal rate of return requirements, are consistent with our risk profile and are accretive to unitholders. While none of the opportunities reviewed in 2007 met all of our investment criteria we continue to assess investment opportunities including those from our existing assets as well as greenfield development opportunities. 2007 has been a challenging year for our investment in PERH. If and when a new contract is negotiated for the Harbor coal facility, the Partnership will assess its options. In summary, 2007 was a year in which we addressed uncertainty. As part of the acquisition of Ventures and subsequent financing, we took the opportunity to structure ourselves to be competitive in a post 2010 taxable environment. We removed financing risk through the successful execution of three financing transactions including the first issue of publicly traded perpetual preferred shares by a Canadian publicly traded trust or limited partnership. We also removed litigation risk by successfully negotiating settlement of the NAL and Devon fuel supply claims. Finally, we completed the integration of Ventures, giving us a platform to grow in the US. Having solidified our base in 2007, our focus in 2008 continues to be improving the commercial and operational performance of our facilities and identifying new growth opportunities. QUARTERLY INFORMATION Selected Quarterly and Annual Consolidated Financial Data 2007 ------------------------------------------------------------------------- Three months ended Mar. 31 Jun. 30 Sep. 30 Dec. 31 Total ------------------------------------------------------------------------- (millions of dollars except unit and per unit amounts) Revenues Ontario Plants 42.7 33.9 34.3 41.4 152.3 Williams Lake 10.1 9.2 10.2 8.6 38.1 Mamquam and Queen Charlotte 2.8 6.0 4.2 5.0 18.0 Northwest US Plants 14.5 14.8 16.9 14.5 60.7 California Plants 30.7 37.0 37.9 25.0 130.6 Curtis Palmer 11.7 9.2 4.2 6.6 31.7 Northeast US Gas Plants 15.2 17.8 14.6 10.1 57.7 North Carolina Plants 13.0 14.7 15.8 8.8 52.3 PERC management fees 0.9 0.9 0.8 0.8 3.4 Fair value changes on foreign exchange contracts 1.3 21.8 14.5 (3.2) 34.4 ------------------------------------------------ 142.9 165.3 153.4 117.6 579.2 ------------------------------------------------ Operating Margin(1) Ontario Plants 24.7 14.7 14.2 20.8 74.4 Williams Lake 7.2 5.3 6.9 5.5 24.9 Mamquam/Queen Charlotte 1.5 2.6 3.3 3.8 11.2 Northwest US Plants 8.8 9.8 11.8 9.3 39.7 California Plants 2.5 9.5 13.9 3.1 29.0 Curtis Palmer 10.3 7.9 2.9 5.4 26.5 Northeast US Gas Plants 3.3 2.8 2.9 2.8 11.8 North Carolina Plants (0.7) 1.0 2.7 (0.5) 2.5 PERC management fees 0.7 0.6 0.2 0.3 1.8 Fair value changes in natural gas supply contracts 44.3 (59.8) (52.7) 35.8 (32.4) Fair value changes in foreign exchange contracts 1.3 21.8 14.5 (3.2) 34.4 ------------------------------------------------ 103.9 16.2 20.6 83.1 223.8 Other costs Depreciation and amortization 23.2 22.6 23.0 23.2 92.0 Management and administration 3.8 2.1 3.8 3.5 13.2 Foreign exchange gains (5.5) (26.7) (24.1) (0.5) (56.8) Equity (income) losses in PERH 1.1 (0.1) 1.7 1.3 4.0 Financial charges and other, net 14.7 8.3 16.7 8.7 48.4 Asset impairment charge - - 13.0 - 13.0 ------------------------------------------------ 37.3 6.2 34.1 36.2 113.8 ------------------------------------------------ Net income (loss) before income tax and preferred share dividends 66.6 10.0 (13.5) 46.9 110.0 Income tax expense (recovery) (2.8) 77.4 0.8 (0.2) 75.2 Preferred share dividends of a subsidiary company - 0.6 1.6 1.8 4.0 ------------------------------------------------ Net income (loss) 69.4 (68.0) (15.9) 45.3 30.8 ------------------------------------------------ Per unit $1.39 ($1.33) ($0.29) $0.84 $0.59 ------------------------------------------------ Cash provided by operating activities 59.5 10.0 23.7 39.0 132.2 Per unit(1) $1.19 $0.20 $0.44 $0.72 $2.53 Cash Distributions 31.4 34.0 33.9 34.0 133.3 Per unit $0.63 $0.63 $0.63 $0.63 $2.52 Capital Expenditures 1.1 4.2 2.6 4.6 12.5 Weighted Average Units Outstanding (millions) 49.9 51.2 53.9 53.9 52.2 ------------------------------------------------------------------------- (1) The selected quarterly and annual consolidated financial data has been prepared in accordance with Canadian generally accepted accounting principles except for operating margin and cash provided by operating activities per unit. See "Non-GAAP measures". QUARTERLY INFORMATION Selected Quarterly and Annual Consolidated Financial Data 2006 ------------------------------------------------------------------------- Three months ended Mar. 31 Jun. 30 Sep. 30 Dec. 31 Total ------------------------------------------------------------------------- (millions of dollars except unit and per unit amounts) Revenues Ontario Plants 51.1 33.1 31.6 39.9 155.7 Williams Lake 10.3 9.4 10.1 9.7 39.5 Mamquam and Queen Charlotte 3.5 5.6 3.3 3.3 15.7 Northwest US Plants(3) 6.4 6.4 11.4 14.5 38.7 California Plants(3) - - - 20.5 20.5 Curtis Palmer 16.4 14.1 8.1 12.3 50.9 Northeast US Gas Plants(3) 3.6 6.9 8.3 9.8 28.6 North Carolina Plants(3) - - - 5.6 5.6 PERC management fees(3) - - - 0.6 0.6 Fair value changes on foreign exchange contracts - 5.5 (0.2) (10.9) (5.6) ------------------------------------------------ 91.3 81.0 72.6 105.3 350.2 ------------------------------------------------ Operating Margin(1) Ontario Plants 32.2 13.5 14.1 23.1 82.9 Williams Lake 7.2 5.5 6.1 6.7 25.5 Mamquam/Queen Charlotte 2.3 4.5 2.3 2.0 11.1 Northwest US Plants(3) 4.8 4.5 7.7 8.9 25.9 California Plants(3) - - - 2.1 2.1 Curtis Palmer 15.0 13.0 6.7 10.3 45.0 Northeast US Gas Plants(3) 1.9 1.8 1.5 2.6 7.8 North Carolina Plants(3) - - - (2.0) (2.0) PERC management fees(3) - - - 0.5 0.5 Fair value changes on natural gas supply contracts - - - - - Fair value changes on foreign exchange contracts - 5.5 (0.2) (10.9) (5.6) ------------------------------------------------ 63.4 48.3 38.2 43.3 193.2 Other costs Depreciation and amortization 17.0 16.4 17.3 21.5 72.2 Management and administration 2.0 2.1 2.5 4.5 11.1 Foreign exchange (gains) losses 0.7 (9.5) 0.5 20.0 11.7 Equity losses in PERH - - - 1.2 1.2 Financial charges and other, net 5.9 6.0 6.6 10.8 29.3 Asset impairment charge - - - - - ------------------------------------------------ 25.6 15.0 26.9 58.0 125.5 ------------------------------------------------ Net income (loss) before income tax and preferred share dividends 37.8 33.3 11.3 (14.7) 67.7 Income tax expense (recovery) 3.9 3.0 0.5 (1.8) 5.6 Preferred share dividends of a subsidiary company - - - - - ------------------------------------------------ Net income (loss) 33.9 30.3 10.8 (12.9) 62.1 ------------------------------------------------ Per unit $0.72 $0.64 $0.22 ($0.26) $1.28 ------------------------------------------------ Cash provided by operating activities 54.4 34.1 29.2 36.2 153.9 Per unit(1) $1.15 $0.72 $0.59 $0.73 $3.17 Cash Distributions(2) 29.9 29.9 31.4 31.4 124.2 Per unit $0.63 $0.63 $0.63 $0.63 $2.52 Capital Expenditures 0.8 1.2 2.2 9.0 13.2 Weighted Average Units Outstanding (millions) 47.4 47.4 49.1 49.9 48.5 ------------------------------------------------------------------------- (1) The selected quarterly and annual consolidated financial data has been prepared in accordance with Canadian generally accepted accounting principles except for operating margin and cash provided by operating activities per unit. See "Non-GAAP measures". (2) Total cash distributions include a $1.5 million payment in August 2006 on the subscription receipts issued in the Frederickson acquisition. (3) From the dates of acquisition: Frederickson - August 1, 2006; Ventures - November 1, 2006. Revenue and Plant Output Three months ended December 31 Year ended December 31 ------------------------------------------------------------------------- (millions of dollars except GWh) GWh 2007 GWh 2006 GWh 2007 GWh 2006 ------------------------------------------------------- Ontario Plants(2) - Power 390 39.5 355 35.3 1,412 134.5 1,368 134.7 - Enhancements 0.6 3.2 8.4 12.3 - Gas diversions 1.3 1.4 9.4 8.7 ------- ------- ------- ------- 41.4 39.9 152.3 155.7 Williams Lake - Firm energy 72 5.6 77 6.1 445 33.8 445 33.7 - Excess energy 67 3.0 68 3.6 100 4.3 108 5.8 ------------------------------------------------------- 139 8.6 145 9.7 545 38.1 553 39.5 Mamquam and Queen Charlotte 74 5.0 45 3.3 267 18.0 232 15.7 Northwest US Plants(3) 258 14.5 180 14.5 910 60.7 456 38.7 California Plants(3) 236 25.0 170 20.5 1,004 130.6 170 20.5 Curtis Palmer 71 6.6 114 12.3 307 31.7 416 50.9 Northeast US Gas Plants(3) 104 10.1 64 9.8 398 57.7 153 28.6 North Carolina Plants(3) 106 8.8 51 5.6 613 52.3 51 5.6 PERC management fees(3) - 0.8 - 0.6 - 3.4 - 0.6 Fair value changes - (3.2) - (10.9) - 34.4 - (5.6) ------------------------------------------------------- 1,378 117.6 1,124 105.3 5,456 579.2 3,399 350.2 ------------------------------------------------------------------------- Weighted Average Plant Availability(1) Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- 2007 2006 2007 2006 ------------------------------------ Ontario Plants 99% 98% 95% 98% Williams Lake 97% 99% 96% 95% Mamquam/Queen Charlotte 97% 80% 81% 83% Northwest US Plants(3) 97% 100% 94% 96% California Plants(3) 87% 94% 91% 94% Curtis Palmer 100% 98% 96% 97% Northeast US Gas Plants(3) 99% 99% 96% 96% North Carolina Plants(3) 83% 92% 94% 92% ------------------------------------------------------------------------- Weighted Average Total 95% 97% 94% 95% ------------------------------------------------------------------------- (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. (2) Ontario power revenue includes the retroactive portion of the settlement with OEFC of $9.8 million in 2006. (3) From the dates of acquisition: Frederickson - August 1, 2006; Ventures - November 1, 2006. 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 MWh 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 first quarter of 2007, the Partnership began reporting natural gas supply contracts for the Ontario plants at their 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 losses in the second and third quarters. Unrealized foreign exchange gains on US dollar-denominated debt were recorded in the second quarter of 2006 and all four quarters of 2007. Losses were recorded in the first, third and fourth quarters of 2006. The gains and losses are due to fluctuations in the US dollar relative to the Canadian dollar. The first, second and fourth quarters of 2006 and the first quarter of 2007 had unseasonably high water flows at Curtis Palmer, while the fourth quarter of 2007 had unseasonably low water flows. Lower pricing for electricity produced at Curtis Palmer started in the first quarter of 2006 when a cumulative MWh threshold was reached. Enhancement and diversion revenues at the Ontario plants increased due to higher natural gas prices in the first quarter of 2006. In the first quarter of 2006, the Partnership reached a settlement with OEFC on a replacement for the Direct Customer Rate index. The retroactive portion of the settlement was recorded in the quarter and increased revenues, net income and cash provided by operating activities. In the second quarter of 2006, the Partnership de-designated all of the foreign exchange contracts existing at April 1, 2006. Unrealized fair value changes in these contracts and amortization of the deferred gain resulted in a gain in the second quarter of 2006 and in the first three quarters of 2007. Losses were recorded in the third and fourth quarters of 2006 and in the fourth quarter of 2007. A $2.3 million fuel charge was accrued in the second quarter of 2006 for the potential payments to natural gas suppliers, which impacted net income. 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 on terms anticipated in the second quarter of 2007. In the third and fourth quarters of 2006, the Partnership acquired Frederickson and Ventures, respectively. Factors Impacting the Fourth Quarter Financial Results The Partnership reported cash provided by operating activities of $39.0 million or $0.72 per unit for the three months ended December 31, 2007 compared to $36.2 million or $0.73 per unit for the same period in 2006. Cash provided by operating activities per unit is defined above under non-GAAP measures. The $2.8 million increase in cash provided by operating activities is primarily due to the following: - A $3.2 million decrease in working capital requirements in 2007 compared to a $4.7 million increase in 2006; - An increase of $3.6 million in the contribution from Ventures, acquired on November 1, 2006, excluding financing costs; and - Lower interest expense of $3.1 million compared to 2006 was primarily due to replacement of bridge acquisition financing for the PEV acquisition with the proceeds from the issue of preferred shares and units. Increases were partially offset by: - $4.9 million decrease in operating cash flow at Curtis Palmer primarily due to lower generation resulting from a drop to lower than historic average water volumes; - Cash taxes increased by $3.0 million primarily due to an increase in US withholding taxes; - Dividends of $1.8 million paid on preferred shares issued by a subsidiary company in May 2007; and - Settlements reached with the natural gas suppliers at Tunis in 2007 resulting in an increase in fuel costs of $1.2 million. Revenue for the three month period ended December 31, 2007 was $117.6 million compared to $105.3 for the same period in 2006. The increase was primarily due to the acquisition of Ventures on November 1, 2006, which contributed an additional $10.1 million to revenues in the three months ended December 31, 2007 compared to 2006, as well as a smaller decline in the fair value of foreign exchange contracts. Offsetting the increase was lower revenue at Curtis Palmer as a result of lower generation. The Partnership reported net income of $45.3 million or $0.84 per unit for the three months ended December 31, 2007 compared to a loss of $12.9 million or $0.26 per unit for the same period in 2006. Net income increased by $58.2 million primarily due to net fair value gains of $32.6 million on foreign exchange and natural gas contracts in the three months ended December 31, 2007 compared to net fair value losses of $5.2 million on foreign exchange and interest rate contracts in the same period in 2006. Also contributing to the increase were unrealized foreign exchange gains of $0.5 million in the three month period ended December 31, 2007 compared to unrealized foreign exchange losses of $24.7 million in the same period in 2006. These increases are partially offset by a decline in operating margin from Curtis Palmer of $4.9 million due to lower generation. QUARTERLY AND ANNUAL UNIT TRADING INFORMATION The Partnership units trade on the Toronto Stock Exchange under the symbol EP.UN. 2007 ------------------------------------------------------------------------- Three months ended (unaudited) Mar. 31 Jun. 30 Sep. 30 Dec. 31 Annual ------------------------------------------------------------------------- Unit Price High $29.00 $27.29 $27.90 $25.29 $29.00 Low $25.27 $25.38 $22.10 $20.11 $20.11 Close $25.60 $26.30 $24.64 $23.37 $23.37 ------------------------------------------------------------------------- Volume traded (millions) 5.1 5.5 4.5 6.3 21.4 ------------------------------------------------------------------------- 2006 ------------------------------------------------------------------------- Three months ended (unaudited) Mar. 31 Jun. 30 Sep. 30 Dec. 31 Annual ------------------------------------------------------------------------- Unit Price High $36.00 $33.90 $33.60 $33.74 $36.00 Low $33.05 $30.30 $30.76 $22.51 $22.51 Close $33.75 $33.00 $32.27 $26.75 $26.75 ------------------------------------------------------------------------- Volume traded (millions) 4.9 4.6 5.1 9.7 24.3 ------------------------------------------------------------------------- As at December 31, 2007, the Partnership had 53.9 million units outstanding. The weighted average number of units outstanding for the year ended December 31, 2007 was 52.2 million which is higher than in 2006 due to the issue of 4.0 million units related to the Ventures acquisition. 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 Years ended December 31 2007 2006 ----------------------------------------------- ------------ ------------ (In millions of dollars except units and per unit amounts) Revenues $ 579.2 $ 350.2 Cost of fuel 263.2 101.5 Operating and maintenance expense 59.9 36.4 Other plant operating expenses 32.3 19.1 ------------ ------------ 223.8 193.2 Other costs (income) Depreciation and amortization (Note 4) 92.0 72.2 Management and administration 13.2 11.1 Foreign exchange (gains) losses (56.8) 11.7 Equity losses in PERH 4.0 1.2 Financial charges and other, net (Note 9) 48.4 29.3 Asset impairment charge (Note 12) 13.0 - ------------ ------------ 113.8 125.5 ------------ ------------ Net income before income tax and preferred share dividends 110.0 67.7 Income tax expense (Note 13) 75.2 5.6 ------------ ------------ Net income before preferred share dividends 34.8 62.1 Preferred share dividends of a subsidiary company (Note 10) 4.0 - ------------ ------------ Net income $ 30.8 $ 62.1 ------------ ------------ ------------ ------------ Net income per unit $ 0.59 $ 1.28 ------------ ------------ ------------ ------------ Weighted average units outstanding (millions) 52.2 48.5 ------------ ------------ ------------ ------------ See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF CASH FLOW Years ended December 31 2007 2006 ----------------------------------------------- ------------ ------------ (In millions of dollars) Operating activities Net income $ 30.8 $ 62.1 Items not affecting cash: Depreciation and amortization (Note 4) 92.0 72.2 Asset impairment charge (Note 12) 13.0 - Future income tax 69.1 4.7 Fair value changes on derivative instruments 3.7 (0.1) Unrealized foreign exchange (gains) losses (76.8) 16.4 Other 6.3 (2.9) ------------ ------------ 138.1 152.4 (Increase) decrease in operating working capital (5.9) 1.5 ------------ ------------ Cash provided by operating activities 132.2 153.9 ------------ ------------ Investing activities Additions to property, plant and equipment (12.5) (13.2) Dividends from PERH 3.3 1.0 Acquisition of Primary Energy Ventures LLC, net of cash (Note 20) (0.4) (359.2) Acquisition of interest in Frederickson Power L.P. (Note 20) - (137.8) ------------ ------------ Cash used in investing activities (9.6) (509.2) ------------ ------------ Financing activities Distributions paid (130.8) (122.6) Net proceeds from preferred share offering (Note 10) 120.8 - Net proceeds from unit offering (Note 11) 101.6 79.9 Short-term debt repaid (200.5) - Issue of short-term debt - 208.5 Long-term debt repaid (185.9) (223.6) Capital lease obligation repaid (74.4) - Proceeds from long-term debt 239.2 415.9 Deferred debt issue costs - (3.5) ------------ ------------ Cash (used in) provided by financing activities (130.0) 354.6 ------------ ------------ Foreign exchange (loss) gain on cash held in a foreign currency (4.5) 0.5 Decrease in cash and cash equivalents (11.9) (0.2) Cash and cash equivalents, beginning of year 32.0 32.2 ------------ ------------ Cash and cash equivalents, end of year $ 20.1 $ 32.0 ------------ ------------ ------------ ------------ Supplementary cash flow information Income taxes paid $ 1.1 $ 4.4 Interest paid $ 44.6 $ 28.4 ------------ ------------ ------------ ------------ See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED BALANCE SHEETS As at December 31 2007 2006 ----------------------------------------------- ------------ ------------ (In millions of dollars) ASSETS Current assets Cash and cash equivalents $ 20.1 $ 32.0 Accounts receivable 75.1 66.8 Inventories 13.6 15.3 Prepaids and other 4.7 5.9 Future income taxes (Note 13) 1.9 2.8 Derivative instruments asset (Note 14) 35.0 9.2 ------------ ------------ 150.4 132.0 Property, plant and equipment (Note 4) 1,052.9 1,093.7 Power purchase arrangements (Note 5) 453.2 486.8 Long-term investments (Note 6) 49.6 56.9 Goodwill 50.9 50.1 Derivative instruments asset (Note 14) 65.2 6.1 Other assets (Note 7) 30.2 57.8 ------------ ------------ $ 1,852.4 $ 1,883.4 ------------ ------------ ------------ ------------ LIABILITIES AND PARTNERS' EQUITY Current liabilities Short-term debt $ - $ 216.3 Accounts payable 59.1 53.5 Distributions payable 33.9 31.4 Long-term debt due within one year (Note 9) 1.1 18.0 Derivative instruments liability (Note 14) 0.3 1.0 ------------ ------------ 94.4 320.2 Asset retirement obligations (Note 15) 23.2 21.7 Long-term debt (Note 9) 618.6 700.1 Derivative instruments liability (Note 14) 2.9 15.1 Contract liabilities (Note 8) 6.0 8.3 Future income taxes (Note 13) 79.6 12.6 Preferred shares issued by subsidiary company (Note 10) 122.0 - Partners' equity (Note 11) 905.7 805.4 Commitments and contingencies (Note 21) Subsequent events (Note 22) ------------ ------------ $ 1,852.4 $ 1,883.4 ------------ ------------ ------------ ------------ See accompanying notes to the consolidated financial statements. Approved by EPCOR Power Services Ltd., as General Partner of EPCOR Power L.P. Donald J. Lowry Brian A. Felesky Director and Director and Chairman of the Board Chairman of the Audit Committee EPCOR Power L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Years ended December 31 2007 2006 ----------------------------------------------- ------------ ------------ (In millions of dollars) Partnership capital Balance, beginning of year $ 1,095.5 $ 1,015.6 Issue of partnership units (Note 11) 101.6 79.9 ------------ ------------ Balance, end of year $ 1,197.1 $ 1,095.5 ------------ ------------ ------------ ------------ Deficit Balance, beginning of year: As previously reported $ (290.1) $ (228.0) Adjustment for changes in accounting policies (Note 3) 96.1 - ------------ ------------ As restated (194.0) (228.0) Net income 30.8 62.1 Cash distributions (133.3) (124.2) ------------ ------------ Balance, end of year $ (296.5) $ (290.1) ------------ ------------ Accumulated other comprehensive income Balance, beginning of year $ - $ - Cumulative effect of adopting new accounting policies (Note 3) 8.6 - Other comprehensive loss (3.5) - ------------ ------------ Balance, end of year $ 5.1 $ - ------------ ------------ ------------ ------------ Total of deficit and accumulated other comprehensive income $ (291.4) $ (290.1) ------------ ------------ ------------ ------------ Partners' equity $ 905.7 $ 805.4 ------------ ------------ ------------ ------------ See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Year ended December 31 2007 ------------------------------------------------------------ ------------ (In millions of dollars) Net income $ 30.8 Other comprehensive loss, net of income taxes Amortization of deferred gains on derivatives de-designated as cash flow hedges to income(1) (3.5) ------------ Comprehensive income $ 27.3 ------------ ------------ (1) Net of income tax of nil. See accompanying notes to the consolidated financial statements. EPCOR Power L.P. Notes to the Consolidated Financial Statements (Tabular amounts in millions of dollars) Years ended December 31, 2007 and 2006 Note 1. Description of the Partnership EPCOR Power L.P. (the Partnership) is a limited partnership created under the laws of the Province of Ontario pursuant to a Partnership Agreement dated March 27, 1997, as amended and restated August 31, 2005. The Partnership commenced operations on June 18, 1997 and currently has independent power generating facilities in British Columbia, Ontario, California, Colorado, New Jersey, New York, North Carolina and Washington State. EPCOR Power Services Ltd., (the General Partner), is an indirect wholly- owned subsidiary of EPCOR Utilities Inc., (collectively with its subsidiaries, EPCOR) and has the responsibility for overseeing the management of the Partnership and cash distributions to unitholders. The General Partner has engaged certain other EPCOR subsidiaries (collectively, the Manager) to perform management and administrative services on behalf of the Partnership and to operate and maintain the power plants pursuant to management and operations agreements. Note 2. Significant accounting policies Basis of presentation The consolidated financial statements of the Partnership have been prepared by the management of the General Partner in accordance with Canadian generally accepted accounting principles (GAAP) and include the accounts of the Partnership and of its subsidiaries. All significant intercompany transactions and balances have been eliminated. Measurement uncertainty The preparation of the Partnership's financial statements, in accordance with GAAP requires management to make estimates that affect the reported amounts of revenues, expenses, assets and liabilities as well as the disclosure of contingent assets and liabilities at the financial statement date. For determining asset impairments, purchase price allocations for business combinations, recording financial assets and liabilities and for certain disclosures, the Partnership is required to estimate the fair value of certain assets or obligations. Estimates of fair value are based on depreciable replacement cost or determined using discounted cash flow techniques. The estimated future cash flows are based on a number of assumptions including an appropriate discount rate. Financial instruments are recorded at fair value, which requires the use of estimated future prices. Measurement of the Partnership's asset retirement obligations and the related accretion expense requires the use of estimates with respect to the amount and timing of asset retirements, the extent of site remediation required, and related future cash flows. Depreciation and amortization is an estimate to allocate the cost of an asset over its estimated useful life on a systematic and rational basis. Estimating the appropriate useful lives of assets requires significant judgment and is generally based on estimates of common life characteristics of common assets. Income taxes are determined based upon estimates of the Partnership's future income taxes resulting from temporary tax differences. Future income tax assets are assessed to determine the likelihood that they will be realized from future taxable income. To the extent that realization is not considered likely, a valuation allowance is recorded and charged against income in the period that the allowance is created or revised. Adjustments to previous estimates, which may be material, will be recorded in the period they become known. Foreign currency translation The Partnership indirectly owns United States (US) subsidiaries, the accounts of which are integrated with those of the Partnership and translated into Canadian dollars using the temporal method. Under this method, monetary assets and liabilities and non-monetary assets carried at market are translated at the exchange rate in effect at the balance sheet date. Non-monetary assets and liabilities carried at cost are translated at historic exchange rates. Revenues and expenses are translated at rates in effect at the time of the transactions. The resulting foreign exchange gains and losses are included in the consolidated statements of income. Cash and cash equivalents Cash and cash equivalents include cash or highly liquid, investment- grade, short-term investments and are recorded at cost, which approximates fair market value. Inventories Inventories held for consumption are recorded at the lower of cost and replacement cost. Property, plant and equipment Property, plant and equipment are recorded at cost. Power generation plant and equipment, less estimated residual value, is depreciated on a straight-line basis over estimated service lives of one to fifty one years. Other equipment, which includes the costs of major overhauls, is capitalized and depreciated over estimated service lives of three to ten years. Property, plant and equipment, including asset retirement costs, are periodically reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset's fair value is recognized during the period, with a charge to income. Power purchase arrangements and steam purchase arrangements Power purchase arrangements and steam purchase arrangements (collectively referred to as power purchase arrangements or PPAs) are long-term contracts to purchase power and steam from the Partnership on a predetermined basis. The PPAs are amortized over the remaining terms of the contracts, which range from one to twenty years. Other intangible assets Other intangible assets consist primarily of emissions allowances at the facilities located in North Carolina. Other intangible assets are amortized over the remaining term of the allowances of one year. Contract liabilities Contract liabilities consist of fair value adjustments primarily related to PPAs in connection with the Primary Energy Ventures LLC, now EPCOR Ventures USA LLC (Ventures) acquisition in 2006. Contract liabilities are amortized over the term of the contracts, which range from two to seven years. Long-term investments Investments that are not controlled by the Partnership, but over which it has significant influence are accounted for using the equity method and recorded at original cost and adjusted periodically to recognize the Partnership's proportionate share of the investee's net income or losses after the date of investment, additional contributions made and dividends received. Other investments are stated at cost. When there has been a decline in value that is other than temporary, the carrying value of an investment recorded on a cost basis is reduced to its fair value. Dividends received from the equity investee which do not exceed cumulative equity in earnings subsequent to the date of investment are considered a return on investment and are classified as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative dividends received in excess of cumulative equity in earnings subsequent to the date of investment are considered a return of investment and are classified as investing activities within the accompanying Consolidated Statements of Cash Flows. Investment in joint venture The investment in a joint venture is accounted for using the proportionate consolidation method. Under this method, the Partnership records its proportionate share of assets, liabilities, revenue and expenses of the joint venture. Goodwill Goodwill is the residual amount that results when the purchase price of an acquired business exceeds the sum of the amounts allocated to the net assets acquired based on their fair values. Goodwill is not amortized, but rather is tested for impairment at least annually or more frequently if events and circumstances indicate that a possible impairment may arise earlier. Deferred debt issue costs The Partnership incurs placement fees and other costs in connection with issuing debt. These amounts are included in long-term debt and amortized over the term of the related debt using the effective interest method (EIM). Revenue recognition Revenue is recognized when energy is delivered under various long-term contracts. Revenue under the Curtis Palmer PPA is recognized at the lower of (1) the megawatt hours (MWhs) made available during the period multiplied by the billable contract price per MWh and (2) an amount determined by the MWhs made available during the period multiplied by the average price per MWh over the term of the contract from the date of acquisition. Any excess of the current period contract price over the average price is recorded as deferred revenue. Finance income related to leases accounted for as direct financing leases is recognized in a manner that produces a constant rate of return on the net investment in the lease. The investment in the lease for purposes of income recognition is composed of net minimum lease payments and unearned finance income. Unearned finance income, being the difference between the total minimum lease payments and the carrying value of the leased property, is deferred and recognized in earnings over the lease term. Asset retirement obligations The Partnership recognizes asset retirement obligations for its power plants. The fair value of the liability is added to the carrying value of the associated plant asset and depreciated accordingly. The liability is accreted at the end of each period through charges to depreciation and amortization. The Partnership has recorded these asset retirement obligations, as it is legally required to remove the facilities at the end of their useful lives and restore the plant sites to their original condition. Income taxes The Partnership is not currently subject to Canadian income taxes and accordingly those taxes which are the responsibility of individual partners have not been reflected in these financial statements. Certain subsidiary corporations are taxable and applicable income, withholding and other taxes have been reflected in these consolidated financial statements. However, the Partnership will be subject to Canadian income taxes after 2010. As a result, the Partnership recognized future income taxes based on the estimated net taxable timing differences which are expected to reverse after 2010. Future income tax assets and liabilities are determined based on temporary differences between the tax basis of assets and liabilities of subsidiary corporations and their carrying values for accounting purposes. Future income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. Net income per unit Net income per unit is calculated by dividing net income by the weighted average number of units outstanding, including those held by EPCOR. Note 3. Changes in accounting policies Commencing January 1, 2007, the Partnership adopted new accounting standards as issued by the Canadian Institute of Chartered Accountants (CICA) for Comprehensive Income, Equity and Financial Instruments. The new accounting standards have been applied prospectively and the comparative financial statements have not been restated. Comprehensive income and equity These new standards establish requirements for the reporting and presentation of comprehensive income which is composed of net income and other comprehensive income and for the presentation of equity and changes in equity due to the comprehensive income requirements. The Partnership's other comprehensive income includes amortization of deferred unrealized gains from previously de-designated cash flow hedges. Each component of the statement of comprehensive income is recorded net of income taxes. Accumulated other comprehensive income is a new component of partners' equity. Financial instruments - recognition and measurement The new standards require that financial assets be identified and classified as either available-for-sale, held for trading, held-to- maturity, other liabilities or loans and receivables. Financial liabilities are classified as either held for trading or other liabilities. Initially, all financial assets and financial liabilities must be recorded in the balance sheet at fair value with subsequent measurement determined by the classification of each financial asset and liability. Financial assets and financial liabilities held for trading are measured at fair value with the changes in fair value reported in earnings. Financial assets held to maturity, loans and receivables and financial liabilities other than those held for trading are measured at amortized cost. Available-for-sale financial assets are measured at fair value with changes in fair value reported in other comprehensive income until the financial asset is disposed of, or becomes impaired. Investments in equity instruments classified available for sale that do not have quoted market prices in an active market are measured at cost. Except for instruments that meet the definition of a derivative, the new standards provide the option to irrevocably designate any financial instrument as held for trading (the fair value option) on initial recognition or upon adoption of the standard. An instrument that is classified as held for trading by way of this fair value option must have a reliably determinable fair value. This option reduces the measurement or recognition inconsistencies that would otherwise arise from measuring assets and liabilities. Currently the Partnership has designated any cash and cash deposits and short-term financial investments as held for trading. Financial assets purchased or sold, where the contract requires the asset to be delivered within an established timeframe, are recognized on a settlement date basis. All derivative instruments, including embedded derivatives, are recorded at fair value in the balance sheet as derivative instruments asset and derivative instruments liability unless exempted from derivative treatment as an expected purchase, sale or usage. All changes in their fair value are recorded in net income unless cash flow hedge accounting is used, in which case changes in fair value of the effective portion of the derivatives are recorded in other comprehensive income. The Partnership has elected to apply normal purchase and sale accounting to all of its host contracts that qualified under the new accounting standards. Because the natural gas supplied under long-term contracts is at times re-sold in the market and not entirely used to produce electricity, these contracts did not meet the requirements for a normal purchase election. Accordingly the natural gas contracts at the Ontario plants have been recorded at fair value at January 1, 2007 as a derivative instrument asset with a corresponding adjustment to opening deficit. Subsequent changes in the fair value of these contracts are reported in the Partnership's income statement. Other significant accounting implications arising on the adoption of this accounting standard include the use of the EIM. EIM is used to amortize transaction costs related to loans issued by the Partnership and attributing transaction costs to the related financial liability. Prior to January 1, 2007 the transaction costs were amortized to income on a straight-line basis over the life of the related loan. The new standard requires that the Partnership use the EIM to recognize the transaction costs whereby the amount recognized varies over the life of the loan based on the principal outstanding. At January 1, 2007, the Partnership reclassified its deferred transaction costs on its loans from other assets to long-term debt and adjusted the balance to reflect the use of the EIM. Certain commodity purchase and sale contracts are non-financial derivatives, but are not within the scope of derivative accounting standards, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Partnership's expected purchase, sale, or usage requirements. In addition, certain other contracts are also not within the scope of derivative accounting standards as they are considered to be executory contracts or meet other exemption criteria. These contracts are not recognized in the financial statements until they are settled. The change in accounting policy did not result in a change in the future income tax liability of the Partnership based on the tax laws applicable to the Partnership as at January 1, 2007. The tax status of the Partnership changed on June 12, 2007 when specified investment flow- through (SIFT) legislation announced by the Canadian Finance Minister became enacted as discussed in Note 13. Financial statement impact Certain physical natural gas purchase contracts are not designated as contracts used in accordance with the Partnership's normal purchase and sale requirements and, therefore are determined to be derivative instruments that are measured at fair value. An opening adjustment to retained earnings to reflect the fair value of these contracts at January 1, 2007 has been recorded. Subsequent changes in the fair value of these contracts are reported in net income. Prior to the adoption of these new standards, the net unrealized losses on certain derivative instruments which did not satisfy all the required conditions for hedge accounting were recorded as a net derivative instruments liability in the balance sheet. As required by the new standards, these unrealized losses were reclassified to opening retained earnings. Also prior to the adoption of these new standards, the unrealized gains associated with hedges which were voluntarily discontinued by the Partnership in prior periods were included in derivative instruments liability in the balance sheet. These gains are recognized into net income in the same periods as the cash flows of the related hedged item is realized in net income. Consistent with the requirements of the new standards, these unrealized gains were reclassified to accumulated other comprehensive income as a cumulative opening adjustment. On January 1, 2007, the Partnership made the following adjustments to its balance sheet to adopt the new standards: As at Balance Sheet Category January 1, Increase (Decrease) 2007 Explanation ------------------------------------------- ---------------------------- Other assets $ (4.5) To no longer record deferred financing costs as other assets using straight-line amortization. Derivative instruments - asset 96.0 To record natural gas supply contracts at fair value. Derivative instruments (8.6) To no longer record deferred - net liability unrealized gains as derivative instruments. Long-term debt (4.6) To record deferred debt issue costs as debenture discounts using effective interest method. Opening deficit (96.1) After tax impact to opening deficit resulting from adoption of new standards. Opening accumulated other 8.6 To record deferred comprehensive income unrealized gains as accumulated other comprehensive income. ---------------- ---------------------------- During the year ended December 31, 2007 these new financial instruments accounting standards impacted the financial statements as follows: For the year Financial ended or as Statement Category at December 31, Increase (Decrease) 2007 Explanation ------------------------------------------- ---------------------------- Accumulated other $ (3.5) To reclassify accumulated comprehensive loss other comprehensive income related to de-designated Cost of fuel 32.4 To record change in the fair value of natural gas contracts from January 1, 2007 to December 31, 2007. Derivative instruments (32.4) - asset ---------------- ---------------------------- Losses of $32.4 million have been recorded in the year ended December 31, 2007 to reflect the change in fair value of natural gas supply contracts and were included in cost of fuel. Accumulated other comprehensive income decreased by $3.5 million for the year ended December 31, 2007 due to the reclassification of gains on de-designated hedges to revenue. Under the Partnership's previous accounting policy the reclassification to revenue would have been from derivative financial instruments - net liability. The impact of the EIM was insignificant in the year. Future accounting changes International financial reporting standards In 2005, the CICA announced plans to converge Canadian GAAP with International Financial Reporting Standards (IFRS) over a transition period from 2006 to 2011. The CICA indicated that Canadian entities will be required to begin reporting under IFRS effective the first quarter of 2011 including comparative figures. The Partnership has developed a high level IFRS implementation plan and is currently assessing the financial statement impact of the accounting standard differences. Based on the Partnership's 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, in time to ensure transactions are recorded in accordance with IFRS for comparative reporting purposes at the required implementation date. Capital disclosures and financial instruments - presentation and disclosures On December 1, 2006, the CICA issued the new CICA Handbook Sections 1535, 3862 and 3863 for Capital Disclosures and Financial Instruments - Disclosures and Presentation. Effective January 1, 2008, the Partnership will adopt these new accounting standards. As required by the new standards, the Partnership will disclose 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 disclosures will also include information on how the Partnership manages its capital. Inventories Effective January 1, 2008 the new CICA Handbook Section 3031 - Inventories will replace Section 3030 to be consistent with the international accounting standard for inventories. The new section requires inventories to be measured at the lower of cost and net realizable value. The Partnership currently measures inventories at the lower of cost and replacement cost. The Partnership does not expect the adoption of the new standard to result in a material transition adjustment to its financial statements. 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 4. Property, plant and equipment 2007 2006 ------------------------------------------ ----------------------------- Net Net Accumulated Book Accumulated Book Cost Depreciation Value Cost Depreciation Value ------------------------------------------ ----------------------------- Land $ 5.4 $ - $ 5.4 $ 5.4 $ - $ 5.4 Plant and equipment 1,367.2 346.9 1,020.3 1,293.1 296.7 996.4 Plant and equipment under capital lease - - - 69.2 0.7 68.5 Other equipment 12.7 7.0 5.7 11.7 5.6 6.1 Work in progress 21.5 - 21.5 17.3 - 17.3 ---------------------------- ----------------------------- $1,406.8 $353.9 $1,052.9 $1,396.7 $303.0 $1,093.7 ---------------------------- ----------------------------- ---------------------------- ----------------------------- Depreciation, amortization and asset retirement accretion expense consists of: 2007 2006 --------------------------------------------------------------- --------- Depreciation of property, plant and equipment $ 57.1 $ 46.5 Accretion of asset retirement obligations 1.5 1.2 Amortization of PPAs 33.6 24.5 Amortization of other assets 2.5 0.5 Amortization of contract liabilities (2.7) (0.5) --------- --------- $ 92.0 $ 72.2 --------- --------- --------- --------- Note 5. Power purchase arrangements 2007 2006 ------------------------------------------ ----------------------------- Net Net Accumulated Book Accumulated Book Cost Amortization Value Cost Amortization Value ------------------------------------------ ----------------------------- Power purchase arrangements $ 549.2 $ 96.0 $ 453.2 $ 549.2 $ 62.4 $ 486.8 ---------------------------- ----------------------------- ---------------------------- ----------------------------- Note 6. Long-term investments In connection with the acquisition of Ventures, the Partnership acquired 17.0% of the common interests and 14.2% of the preferred interests in Primary Energy Recycling Holdings LLC (PERH). The Class B Common interest has been accounted for using the equity method of accounting. The Class B Preferred interest has been accounted for using the cost method of accounting. Upon acquisition, the excess of the Partnership's share of the book value of PERH net assets over the carrying value of the Class B Common interest was $18.9 million. Note 7. Other assets 2007 2006 --------------------------------------------------------------- --------- Cost Net investment in lease $ 28.6 $ 35.1 Other intangible assets 4.6 17.5 Deferred debt issue costs and other - 6.6 --------- --------- 33.2 59.2 --------- --------- Accumulated Amortization Other intangible assets 3.0 0.5 Deferred debt issue costs and other - 0.9 --------- --------- 3.0 1.4 --------- --------- $ 30.2 $ 57.8 --------- --------- --------- --------- Net investment in lease The PPA under which the power generation facility located in Oxnard, California (Oxnard) operates is considered to be a direct financing lease for accounting. The PPA expires in 2020. The current portion of the net investment in lease of $1.4 million is included in accounts receivable (2006 - $1.4 million). Financing income for the year ended December 31, 2007 of $3.0 million is included in revenues (2006 - $0.5 million). Note 8. Contract liabilities 2007 2006 ------------------------------------------ ----------------------------- Net Net Accumulated Book Accumulated Book Cost Amortization Value Cost Amortization Value ------------------------------------------ ----------------------------- Contract liabilities $ 9.2 $ 3.2 $ 6.0 $ 8.8 $ 0.5 $ 8.3 ---------------------------- ----------------------------- ---------------------------- ----------------------------- Note 9. Long-term debt Effective Interest Rate 2007 2006 --------------------------------------------------------------- --------- Senior unsecured notes, due in 2036 at 5.95% 6.12% $ 210.0 $ 210.0 Senior unsecured notes (US$190.0 million), due in 2014 at 5.90% 6.16% 188.3 221.4 Senior unsecured notes (US$150.0 million), due in 2017 at 5.87% 6.01% 148.7 - Senior unsecured notes (US$75.0 million), due in 2019 at 5.97% 6.11% 74.3 - Secured term loan, due in 2010 at 11.25% 11.57% 3.8 4.8 Revolving credit facilities at 5.60% - 149.4 Bridge acquisition credit facility at 5.80% - 51.3 Obligations under capital leases at 9.10% - 81.2 --------------------------------------------------------------- --------- 625.1 718.1 Less: Current portion of long-term debt 1.1 18.0 Deferred debt issue costs 5.4 - --------- --------- $ 618.6 $ 700.1 --------- --------- --------- --------- Senior unsecured notes The notes are unsecured direct obligations of the Partnership and, subject to statutory preferred exemptions, rank equally with all other unsecured and unsubordinated indebtedness of the Partnership. The senior unsecured notes due in 2036 have a coupon rate of 5.95% payable semi-annually in June and December and mature on June 23, 2036. The senior unsecured notes due in 2014 mature in July 2014. Interest on the notes accrues at 5.90% per annum and is payable semi-annually in January and July. On August 15, 2007, the Partnership completed a private placement of senior unsecured notes for aggregate proceeds of $240.0 million (US$225.0 million), less issue costs of $0.8 million (US$0.7 million). The notes were issued in two tranches consisting of 10 and 12 year maturities. The $160.0 million (US$150.0 million) in 10-year notes have a coupon rate of 5.87% and the $80.0 million (US$75.0 million) in 12-year notes have a coupon rate of 5.97%. The proceeds from the private placement were used to repay the capital lease obligations of $71.7 million (US$68.3 million) and amounts initially borrowed as part of the Frederickson Power L.P. (Frederickson) and Ventures acquisitions of $155.6 million (US$145.3 million). Secured term loan The secured term loan is secured by a first fixed and specific mortgage over the Queen Charlotte plant. The loan bears interest at an annual rate of approximately 11.25% and matures on July 15, 2010. Revolving credit facilities Under the terms of the revolving credit facilities, the Partnership may obtain advances by way of prime loans, US Base Rate loans, LIBOR loans and Bankers' Acceptances. There are three $100.0 million revolving credit facilities with three year terms maturing in June, September and October 2010, subject to extension. At December 31, 2007, none of these facilities were drawn. The Partnership's revolving credit facilities may be used for general partnership purposes including working capital support. Obligations under capital leases On August 24, 2007, the Partnership paid off its capital lease obligations for the Naval Station, North Island and Naval Training Centers for $71.7 million (US$68.3 million). The $1.0 million difference between the purchase price and the carrying amount of the lease obligation has been recorded as an increase in the cost of the acquired property, plant and equipment. Deferred debt issue costs At January 1, 2007, the Partnership reclassified its deferred debt issue costs on its loans from other assets to long-term debt. Deferred debt issue costs are amortized using the EIM method. At December 31, 2007 deferred debt issue costs were $7.9 million, net of accumulated amortization of $2.5 million. Principal repayments Principal repayments on the long-term debt of the Partnership for the next five years and thereafter are estimated as follows: Long-term debt ------------------------------------------------------------------------- 2008 $ 1.1 2009 1.3 2010 1.4 2011 - 2012 - Later Years 621.3 ---------- Total Payments $ 625.1 ---------- ---------- Financial charges and other, net 2007 2006 -------------------------------------------------------------- --------- Interest on long-term debt $ 36.3 $ 27.4 Interest on short-term debt 4.9 1.8 Interest on capital lease obligations 4.5 1.2 Dividend income from Class B preferred share interests in PERH (1.8) (0.3) Realized losses on interest rate contracts 2.6 - Fair value changes on interest rate contracts 1.0 (1.0) Other 0.9 0.2 --------- --------- $ 48.4 $ 29.3 --------- --------- --------- --------- Note 10. Preferred shares issued by a subsidiary company In May 2007, a subsidiary of the Partnership issued 5 million of 4.85% Cumulative Redeemable Preferred Shares, Series 1 priced at $25.00 per share with dividends payable on a quarterly basis at the annual rate of $1.2125 per share. Proceeds of $120.8 million, net of issue costs of $4.2 million were used to repay amounts outstanding under the bridge acquisition credit facility due in October 2007 incurred in conjunction with the Partnership's acquisition of Ventures in November 2006. Future income tax assets of $1.2 million on the share issue costs are recorded in the preferred share balance. On or after June 30, 2012, the shares are redeemable by the subsidiary company at $26.00 per share, declining by $0.25 each year to $25.00 per share after June 30, 2016. The shares are not retractable by the holders. Under the terms of the preferred share issue, the Partnership will not make any distributions on the units if the declaration or payment of dividends on the preferred shares is in arrears. Dividends will not be paid on the preferred shares if the senior unsecured notes of the Partnership are in default. The Partnership paid dividends of $3.6 million in 2007 and incurred net current and future income taxes of $0.4 million. Note 11. Partners' equity 2007 2006 ------------------------------------------------ ----------------------- Number Millions Number Millions of Units of Dollars of Units of Dollars ------------------------------------------------ ----------------------- Partnership capital, beginning of year 49,881,982 $ 1,095.5 47,421,982 $ 1,015.6 Issue of partnership units 4,015,297 101.6 2,460,000 79.9 ---------------------- ----------------------- Partnership capital, end of year 53,897,279 $ 1,197.1 49,881,982 $ 1,095.5 ---------------------- ----------------------- ---------------------- ----------------------- The Partnership is authorized to issue an unlimited number of limited partnership units. Each unit represents an equal, undivided limited partnership interest in the Partnership and entitles the holder to participate equally in distributable cash and net income, except for the subscription receipt issuance in April 2006 as noted below. Units are not subject to future calls or assessments and entitle the holder to limited liability. Each unit is transferable, subject to the requirements referred to in the Partnership Agreement. In May 2007, the Partnership issued 4,015,297 units, priced at $26.15 per unit, to the public and EPCOR for net proceeds of $101.6 million. The proceeds were used to repay the remaining amount outstanding under the bridge acquisition credit facility due in October 2007, and a portion of the bridge acquisition credit facility due in October 2009. Both facilities were incurred in conjunction with the Partnership's acquisition of Ventures in November 2006. In April 2006, the Partnership issued 2,460,000 subscription receipts, priced at $33.35 per subscription receipt, to the public and EPCOR for net proceeds of $79.9 million to finance part of the Frederickson acquisition. Upon closing of the acquisition, each subscription receipt was exchanged for one limited partnership unit. In 2007, the weighted average number of units outstanding was 52,247,157 (2006 - 48,453,160). Note 12. Asset impairment charge Changes in outlook for incentives that were expected to be earned under the management agreement between a subsidiary of the Partnership and PERH, Primary Energy Operations LLC and Primary Energy Recycling Corporation (PERC) based on expected future cash distributions from PERH resulted in the determination that the full book value of this management agreement was unlikely to be recovered from future cash flows. As a result, the Partnership recorded a $13.0 million pre-tax impairment charge to write off this asset based on its fair value. The asset was previously recorded in other assets. Note 13. Income taxes Components of income tax expense 2007 2006 --------------------------------------------------------------- --------- Current income taxes $ 4.1 $ 0.9 Future income taxes 71.1 4.7 ---------- --------- $ 75.2 $ 5.6 ---------- --------- ---------- --------- Reconciliation of income tax expense 2007 2006 --------------------------------------------------------------- --------- Income before taxes and preferred share dividends $ 110.0 $ 67.7 Combined federal and provincial tax rate 34.1% 34.1% ---------- --------- Expected income tax expense 37.5 23.1 Change due to enactment of SIFT Legislation 78.2 - Amounts related to non-deductible (non-taxable) foreign exchange (27.3) 8.3 Changes due to enactment of rate changes (8.7) - Income allocated to Partnership unitholders (5.0) (27.3) Income from partnerships and flow-through entities 3.4 - Other (2.9) 1.5 ---------- --------- Actual income tax expense $ 75.2 $ 5.6 ---------- --------- ---------- --------- Future income tax assets and liabilities 2007 2006 --------------------------------------------------------------- --------- Loss carryforwards $ 17.6 $ 8.6 Difference in accounting and tax basis of intangible assets 9.1 - Asset retirement obligations 4.0 0.3 Deferred financing charges 2.1 - Non-deductible accrued amounts 1.9 2.5 Other 0.1 1.0 ---------- --------- Future income tax assets $ 34.8 $ 12.4 ---------- --------- ---------- --------- Difference in accounting and tax basis of plant, equipment and PPAs $ 99.7 $ 20.4 Unrealized foreign exchange gains 7.6 - Unrealized gains on derivatives 3.9 - Other 1.3 1.8 ---------- --------- Future income tax liabilities $ 112.5 $ 22.2 ---------- --------- ---------- --------- Net future income tax liabilities $ (77.7) $ (9.8) ---------- --------- ---------- --------- Presented on the balance sheet as follows: 2007 2006 --------------------------------------------------------------- --------- Current assets $ 1.9 $ 2.8 Non-current liabilities (79.6) (12.6) ---------- --------- $ (77.7) $ (9.8) ---------- --------- ---------- --------- Tax on flow-through entities Currently, the taxable income of the Partnership and its subsidiary partnerships is expected to be taxed in the hands of its unitholders. Canadian tax legislation (referred to hereafter as SIFT Legislation) related to SIFTs included in Bill C-52 was enacted in 2007 and will result in changes to how certain publicly traded trusts and partnerships, including the Partnership, are taxed. The Partnership and its Canadian subsidiary limited partnerships have net taxable temporary differences of $357.9 million (2006 - $339.5 million) of which the tax effects of $186.4 million (2006 - nil) are reflected in these financial statements due to the enactment of the SIFT Legislation during the period. The SIFT Legislation generally operates to apply a tax at the SIFT level on certain income at tax rates comparable to the combined federal and provincial corporate tax and then re-characterize that income net of tax payable pursuant to the SIFT Legislation as taxable dividends in the hands of unitholders. The SIFT Legislation will apply to the Partnership starting the earlier of January 1, 2011 or January 1 of the year following the date at which the Partnership exceeds the normal growth guidelines (Guidelines) issued by the Department of Finance (Canada) on December 15, 2006. The Guidelines indicate that no change will be recommended to the 2011 date if the issuances of new equity before 2011 does not exceed an objective "safe harbour" amount based on a percentage of the SIFTs market capitalization as of the end of trading on October 31, 2006. The Partnership expects that it can issue up to $1.7 billion of additional equity before 2011 without accelerating the date that it becomes subject to the SIFT Legislation. Enactment of the SIFT Legislation resulted in the recognition of future income tax expense and net future tax liabilities of $78.2 million, after taking into consideration $8.8 million in respect of deductible temporary differences. No tax benefit has been recognized in 2007 for the estimated net taxable temporary differences which are expected to reverse after 2010 and for which no tax has previously been recorded in the Partnership's year-end financial statements. Taxation of subsidiaries Canadian based corporate subsidiaries of the Partnership are subject to tax on their taxable income at a rate of approximately 34.1% (2006 - 34.1%) while US corporate subsidiaries are subject to tax on their taxable income at rates varying from 34% to 41% (2006 - 34% to 41%). Future income taxes relating to corporate subsidiaries have been reflected in these consolidated financial statements except for $4.4 million of income tax loss carryforwards for which no income tax benefit has been recognized. Income tax loss carryforwards At December 31, 2007, for US income tax purposes, net operating losses of $36.4 million (US$36.7 million) are available for carryforward to reduce future US taxable income. Of the total available losses, $21.6 million (US$21.8 million) expire between 2022 and 2025, with the balance expiring thereafter. Losses of $21.6 million (US$21.8 million) are restricted under Section 382 of the Internal Revenue Code and can be used to offset future taxable income. Under Section 382 of the Internal Revenue Code of 1986, as amended, the utilization of the restricted losses is limited to an annual amount equal to $4.7 million (US$4.7 million). Also, for Canadian income tax purposes there are non-capital loss carryforwards of $12.0 million and capital loss carryforwards of $14.9 million. The non-capital losses will expire after 2025 and the capital losses carry forward indefinitely. Change in federal rates Revised Canadian tax legislation, including the reduction in federal tax rates, was enacted on the passing of Bill C-28 on December 13, 2007. The federal rates will reduce from 19.5% in 2008 to 15.0% by 2012. These federal tax rate reductions also reduce the tax rate applicable to SIFTs from 31.5% to 29.5% starting in 2011 and to 28.0% in 2012 and future years. The total impact of the tax rate reductions on the Partnership was a decrease to future income tax liability and income tax expense of $8.7 million. Note 14. Financial instruments Fair values 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 accrued liabilities are classified as other financial liabilities and are measured at amortized cost. The fair values of accounts receivable and accounts payable and accrued liabilities are not materially different from their carrying values due to their short-term nature. The preferred share interest in PERH is classified as available for sale and the net investment in lease is classified as held-to-maturity. The classification of fair values and carrying values of the Partnership's other financial instruments are summarized as follows: December 31, 2007 ------------------------------------------------------------------------- Carrying Amount ----------------------------------------------------------------- ------- Loans Other Avail- and financial Total Held-for- able receiv- liabil- Held-to- fair trading for sale ables ities maturity Total value ------------------------------------------------- ------- Derivative instruments asset - current $ 35.0 $ - $ - $ - $ - $ 35.0 $ 35.0 Derivative instruments asset - non-current 65.2 - - - - 65.2 65.2 Derivative instruments liability - current (0.3) - - - - (0.3) (0.3) Derivative instruments liability - non-current (2.9) - - - - (2.9) (2.9) Accounts receivable - - 75.1 - - 75.1 75.1 Other assets - net investment in lease - - 28.6 - - 28.6 27.8 Long-term investments - 49.6 - - - 49.6 49.6 Accounts payable and accrued liabilities - - - (59.1) - (59.1) (59.1) Distributions payable - - - (33.9) - (33.9) (33.9) Long-term debt (including current portion) - - - (619.7) - (619.7) (612.2) ------------------------------------------------- ------- December 31, 2006 ------------------------------------------------------------------------- Carrying Amount ----------------------------------------------------------------- ------- Loans Other Avail- and financial Total Held-for- able receiv- liabil- Held-to- fair trading for sale ables ities maturity Total value ------------------------------------------------- ------- Derivative instruments asset - current $ 9.2 $ - $ - $ - $ - $ 9.2 $ 9.2 Derivative instruments asset - non-current 6.1 - - - - 6.1 6.1 Derivative instruments liability - current (1.0) - - - - (1.0) (1.0) Derivative instruments liability - non-current (15.1) - - - - (15.1) (15.1) Accounts receivable - - 66.8 - - 66.8 66.8 Other assets - net investment in lease - - 35.1 - - 35.1 35.1 Long-term investments - 56.9 - - - 56.9 56.9 Accounts payable and accrued liabilities - - - (53.5) - (53.5) (53.5) Distributions payable - - - (31.4) - (31.4) (31.4) Long-term debt (including current portion) - - - (718.1) - (718.1) (732.0) ------------------------------------------------- ------- The fair value of financial instruments are determined by reference to quoted bid or ask prices, as appropriate in active markets. In illiquid or inactive markets, the Partnership uses appropriate price modeling commonly used by market participants to estimate fair value. Such modeling includes option pricing models and discounted cash flow analysis, using observable market based inputs to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows. 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, discount rates for time value and volatility for all of the Partnership's financial instruments except its natural gas supply contracts. The Partnership's natural gas supply contracts run from 2008 to 2016 and market based pricing has been used for periods up to 2012. There are limited observable natural gas prices beyond 2012 after which the Partnership relies on price forecasts prepared by a third party market expert. The natural gas price forecasts for this period range from $7.26/gigajoule (GJ) to $7.35/GJ. A $1.00/GJ change in the natural gas price forecast for the period from 2013 to 2016 would have an $18.5 million impact on the fair value estimate of these contracts. 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. The Partnership has used the carrying value of its common and preferred share interests held in PERH as their fair values since the fair values cannot be measured reliably as they are not quoted in an active market. During the year, the Partnership recorded gains of $34.4 million and losses of $38.2 million, in net income, related to changes in fair value of financial instruments designated as held for trading. Risk management and hedging activities The Partnership is exposed to changes in commodity prices, foreign currency exchange rates and interest rates, of which the Partnership uses various risk management techniques including derivative instruments to reduce its exposure. Derivative instruments may include forward contracts, fixed-for-floating swaps and option contracts. Such instruments may be used to establish a fixed price for physical commodity requirements, interest-bearing obligations, anticipated obligation requirements or obligations denominated in a foreign currency. The Partnership periodically enters into interest rate swap contracts and interest rate cap contracts as part of its risk management strategy to manage its exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the Partnership and investment grade counterparties. The differentials of periodic interest payments are recognized in the accounts as an adjustment to interest expense. As at December 31, 2007, the Partnership did not have any interest rate swaps contracts or interest rate cap contracts. The Partnership has a hedging program to manage its exposure to changes in foreign currency exchange rates that result from future anticipated US dollar-denominated cash flows from its US power plants. Up to April 1, 2006 the Partnership elected to apply hedge accounting to these foreign exchange contracts where accounting hedge criterion were met. On April 1, 2006 the Partnership voluntarily de-designated these hedging relationships for accounting purposes on all outstanding foreign exchange contracts. As a result a net derivative financial instrument asset of $12.0 million was recognized which will be recorded into comprehensive income in the same periods that the related previously hedged US revenue occurs. As the hedged item is still considered highly probable to occur, the previously deferred unrealized gains on the hedging of US dollar-denominated cash flows are deferred and carried forward for subsequent recognition in comprehensive earnings as or when the hedged item occurs. The unamortized portion of the deferred unrealized gains was $5.1 million at December 31, 2007 (2006 - $8.6 million). Changes in the fair value of these foreign exchange contracts from April 1, 2006 forward are recorded in revenue. The derivative assets and liabilities used for risk management purposes comprise the following: December 31, 2007 ------------------------------------------------------------------------- Foreign Natural exchange Interest gas non- non rate hedges 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 ------------------------------------------------------------------------- ------------------------------------------------------------------------- December 31, 2006 ------------------------------------------------------------------------- Foreign Natural exchange Interest gas non- non rate hedges hedges non-hedges Total ---------------------------------------- Derivative instruments assets: Current $ - $ 8.2 $ 1.0 $ 9.2 Non-current - 6.1 - 6.1 Derivative instruments liabilities: Current - (1.0) - (1.0) Non-current - (15.1) - (15.1) ------------------------------------------------------------------------- $ - $ (1.8) $ 1.0 $ (0.8) ------------------------------------------------------------------------- Unrealized and realized gains and losses on foreign exchange derivatives and interest rate derivatives are recorded in energy revenues, foreign exchange gains and losses, or financial charges and other, respectively. Of the $5.1 million recorded in accumulated other comprehensive income at December 31, 2007, $3.8 million is expected to be reclassified to net income over the next twelve months. Credit risk The electricity and steam generated at the Partnership's facilities are sold under long-term contracts to eighteen customers. Customers accounting for more than 10% of the Partnership's revenue in 2007 were as follows: 2007 2006 --------------------------------------------------------------- --------- Ontario Electricity Financial Corporation 26% 39% San Diego Gas & Electric Company 15% 4% British Columbia Hydro and Power Authority 10% 16% -------- --------- Note 15. Asset retirement obligations 2007 2006 --------------------------------------------------------------- --------- Asset retirement obligations, beginning of year $ 21.7 $ 17.1 Assumption of Frederickson and PEV obligations - 1.8 Liabilities incurred - 1.4 Accretion of asset retirement obligations 1.5 1.2 Impact of changes in foreign exchange rates - 0.2 ---------- --------- Asset retirement obligations, end of period $ 23.2 $ 21.7 ---------- --------- ---------- --------- At December 31, 2007, the estimated cost to settle the Partnership's asset retirement obligations was $139.1 million (2006 - $139.6 million) calculated using an inflation rate of 3.0% per annum (2006 - 3.0%). The estimated cash flows were discounted at rates ranging from 6.4% to 6.7% (2006 - 6.4% to 6.7%). At December 31, 2007, the expected timing of payment for settlement of the obligations ranges from five to eighty three years. Note 16. Related party transactions EPCOR 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. Amounts paid or charged to the Partnership under contracts with EPCOR were as follows: 2007 2006 --------------------------------------------------------------- --------- Revenue - Frederickson duct firing capacity fees $ 0.1 $ - Cost of fuel - Castleton gas demand charge 2.1 2.2 Operating and maintenance expense 49.4 32.0 Management and administration Base fee 1.3 1.2 Incentive fee 2.2 2.1 Enhancement fee 0.7 1.1 Administration fee 0.8 0.7 ---------- --------- $ 5.0 $ 5.1 ---------- --------- Acquisition fees - 7.9 ---------- --------- Operating and maintenance EPCOR is entitled to receive a fee for services related to the operation and maintenance of the power plants under the Management and Operations Agreements. The annual fees are payable on an equal monthly basis and are adjusted annually with changes to the Consumer Price Index. EPCOR also provides operational and maintenance services for the Frederickson and Ventures facilities on a cost recovery basis. Base and incentive fee EPCOR is also entitled to a base fee and an incentive fee under the Management and Operations Agreements in each fiscal year of the Partnership. The base fee is equal to 1% of the Partnership's annual cash distributions. The incentive fee is equal to 20% of annual cash distributions which exceed $2.31 per unit and are less than $2.52 per unit; and 30% of annual cash distributions in excess of $2.51 per unit. Enhancement transactions EPCOR can curtail operations of the Ontario power plants and re-sell contracted natural gas at high market prices, rather than produce off- peak power at lower rates. EPCOR is entitled to receive an enhancement fee equivalent to 35% of the incremental profit. Acquisition fees EPCOR is also entitled to acquisition fees under the Transaction Fees and Costs Agreements. The fee is based on the transaction value of the acquisition or disposition. In 2006 the acquisition fees related to the Frederickson and Ventures acquisitions discussed in Note 20. Included in accounts payable at December 31, 2007 are amounts owing to EPCOR of $18.0 million (2006 - $15.1 million). Distributions The Partnership distributes cash to EPCOR in the amount proportionate to their ownership interest. At December 31, 2007, EPCOR owned 30.6% of the Partnership's units (2006 - 30.6%). PERC 2007 2006 --------------------------------------------------------------- --------- Revenue - base management fees $ 3.4 $ 0.6 ---------- --------- PERC base management fees The Partnership receives base management fees for management of PERC under a long term management agreement. The base fee is an escalated annual amount. Included in accounts receivable at December 31, 2007 are amounts owing from PERC of $0.5 million (2006 - $0.3 million). Note 17. Operating leases From the point of view of a lessor, the terms of the Manchief, Mamquam, Queen Charlotte, Southport, Roxboro, Greeley and Kenilworth PPAs are operating leases. At December 31, 2007, the carrying value of the property, plant and equipment of these facilities was $306.4 million less accumulated depreciation of $29.2 million (2006 - $301.4 million and $18.1 million respectively). The Partnership's revenues for the year ended December 31, 2007 include $132.5 million with respect to the PPAs for these plants (2006 - $53.3 million). Note 18. Segmented disclosures The Partnership operates in one reportable business segment involved in the operation of electrical generation plants within British Columbia (BC), Ontario and in the US in California, Colorado, New Jersey, New York, North Carolina and Washington. Geographic information 2007 2006 ------------------------------------------ ------------------------------ Canada US Total Canada US Total ------------------------------------------ ------------------------------ Revenue $ 249.7 $ 329.5 $ 579.2 $ 209.8 $ 140.4 $ 350.2 ----------------------------- ------------------------------ ----------------------------- ------------------------------ Assets PP&E $ 581.3 $ 471.6 $1,052.9 $ 601.8 $ 491.9 $1,093.7 PPAs 42.8 410.4 453.2 45.8 441.0 486.8 Other assets - 30.2 30.2 3.3 54.5 57.8 Goodwill - 50.9 50.9 - 50.1 50.1 ----------------------------- ------------------------------ Total assets $ 624.1 $ 963.1 $1,587.2 $ 650.9 $1,037.5 $1,688.4 ----------------------------- ------------------------------ ----------------------------- ------------------------------ Note 19. Joint venture A financial summary of the Partnership's investments in the Frederickson joint venture is as follows: 2007 2006 --------------------------------------------------------------- --------- Current Assets $ 2.0 $ 2.6 Long-term assets 140.4 145.8 Current liabilities 0.7 0.7 Long term liabilities 0.5 0.4 Revenues 21.3 10.8 Expenses 17.2 6.7 Net Income 4.1 4.1 Cash provided by operating activities 10.1 5.8 Cash used in investing activities - (0.1) Cash used in financing activities (10.1) (5.7) --------------------------------------------------------------- --------- Note 20. Acquisitions Acquisition of interest in Frederickson Power L.P. On August 1, 2006, the Partnership acquired from EPCOR a 100% interest in Frederickson which owns a 50.15% interest in the Frederickson power facility located in Washington State. The total consideration paid was $134.1 million (US$117.8) million in cash plus acquisition costs of approximately $3.7 million for a total purchase price of $137.8 million. The financial results of Frederickson are included in the Partnership's Consolidated Statement of Income from the date of acquisition. Acquisition of Primary Energy Ventures LLC On November 1, 2006, the Partnership acquired 100% of the outstanding shares representing membership interests of Ventures. Ventures owns eight combined heat and power facilities located in the United States and 17.0% of the common interests and 14.2% of the preferred interests in PERH. PERH owns four waste heat recovery power facilities and a 50% interest in a coal pulverization facility in the United States. In addition, Ventures provides management and administrative services to PERH and PERC. PERC owns the balance of PERH not owned by Ventures. The total consideration paid was $366.0 million (US$325.9 million) in cash plus acquisition costs of approximately $10.2 million for a total purchase price of $376.2 million. Of the total consideration paid, $375.8 million was paid in 2006 and $0.4 million was paid in 2007. The financial results of Ventures are included in the Partnership's Consolidated Statement of Income from the date of acquisition. The purchase prices for the acquisition of Frederickson and Ventures respectively were allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows: Frederickson Ventures Total ------------------------------------------------------------------------- Current assets excluding cash $ 2.4 $ 26.4 $ 28.8 Property, plant and equipment 111.5 139.6 251.1 Net investment in lease - 35.5 35.5 Power purchase arrangements 25.0 138.4 163.4 Goodwill 11.5 39.4 50.9 Other intangible assets - 17.5 17.5 Investments - 59.3 59.3 Other assets - 0.1 0.1 Future income tax asset, non-current - 8.3 8.3 Current liabilities (1.4) (15.4) (16.8) Asset retirement obligations (0.4) (1.4) (1.8) Capital lease obligations - (78.9) (78.9) Contract liabilities - (9.2) (9.2) Future income tax liability, non-current (10.8) - (10.8) ------------------------------ 137.8 359.6 497.4 Cash and cash equivalents - 16.6 16.6 ------------------------------ Fair value of net assets acquired $ 137.8 $ 376.2 $ 514.0 ------------------------------ ------------------------------ Consideration Cash $ 134.1 $ 366.0 $ 500.1 Acquisition costs 3.7 10.2 13.9 ------------------------------ $ 137.8 $ 376.2 $ 514.0 ------------------------------ ------------------------------ The amount allocated to goodwill in the Frederickson acquisition is not deductible for income tax purposes. The amount allocated to goodwill in the Ventures acquisition is deductible for income tax purposes. Note 21. Commitments and contingencies Commitments The Ontario plants operate under fixed long-term natural gas supply contracts and natural gas transportation contracts with built-in annual escalators. Expiry dates for the contracts vary in length with an average remaining contract life of six years as at December 31, 2007. The remaining fuel requirements, which account for approximately 3% of the power plants' fuel costs, are purchased at current market prices. The operating and maintenance contracts are based on fixed fees escalated annually by inflation and have expiry terms ranging from 2008 to 2018. 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. As of December 31, 2007 the Partnership's future purchase obligations were estimated as follows, based on existing contract terms and estimated inflation. ------------------------------------------------------------------------- Total Later pay- 2008 2009 2010 2011 2012 years ments ------------------------------------------------------------------------- Natural gas purchase contracts $ 53.9 $ 56.6 $ 57.5 $ 56.1 $ 60.4 $195.4 $479.9 Natural gas transportation contracts 11.8 12.1 12.5 12.9 10.9 38.9 99.1 Operating and maintenance contracts 27.7 27.3 28.1 29.0 29.8 171.0 312.9 ------------------------------------------------------------------------- Contingencies The formula for determining energy pricing at the California plants may be retroactively adjusted by the California Public Utilities Commission. The Partnership estimates that its maximum exposure would be approximately US$28 million. The Partnership can recover payments related to the Naval facilities from the US Navy under the terms of the steam purchase arrangements. Additionally, the previous owners of the facilities will reimburse the Partnership for any payments net of recoveries through November 25, 2008. The Partnership has not recorded a liability as it estimates that an unfavourable outcome is unlikely. Other The US Navy may terminate, for convenience, the power sales agreements at the Partnership's facilities located on their naval bases upon one year's advance notice and payment of certain specified termination charges if it determines that termination is in the Navy's interest. The Navy's failure to purchase the minimum amount of steam necessary for Qualifying Facility status, revocation of the utility site permits or denial of access to the plant site would constitute constructive termination for convenience by the Navy. Note 22. Subsequent events In January 2008, a settlement agreement was reached with NAL Resources Ltd. in respect of its claim of frustration of the contract pursuant to which it supplies gas to the Partnership at the Tunis, Ontario plant. Based on the settlement reached, the Partnership made payments of $4.2 million over what they would have otherwise been under the previous contract terms, all of which was accrued for at December 31, 2007. The Partnership accrued for additional payments and incorporated increases in fuel supply prices into the determination of the fair value of derivative instruments at December 31, 2007. The Canadian 2008 federal budget (Budget) tabled February 26, 2008 includes a change in the calculation of the SIFT rate. Previously, the SIFT rate was calculated as the federal rate plus a notional 13% provincial rate. The Budget proposes to replace the notional provincial component of the SIFT rate with the applicable provincial rates. The adjustment to the SIFT rate combined with the change proposed by the 2008 BC budget tabled February 19, 2008 to reduce the Provincial corporate rate from 12% to 10% by 2011 will reduce the Partnership's future income tax liability and income tax expense by a range of approximately $5 million to $7 million if enacted. Note 23. Comparative figures Certain comparative figures have been reclassified to conform to the current year's presentation.

For further information:

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

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EPCOR POWER L.P.

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