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



    EDMONTON, AB, March 14 /CNW/ - (TSX: EP.UN) - EPCOR Power Services Ltd.,
the general partner of EPCOR Power L.P. ("the Partnership"), today released
the Partnership's quarterly results for the period ended December 31, 2006.
    "I'm pleased to report that in 2006, the Partnership delivered on a
targeted growth strategy, which included the completion of two key U.S.
acquisitions that strengthened and diversified our overall power generation
asset base," said Brian Vaasjo, President of EPCOR Power Services Ltd.
"Together with our ongoing commitment to operational excellence and
conservative fiscal management, this led to a solid first full year under
EPCOR as the general partner. The Partnership continued its track record of
strong operating performance where the power plants' availability was at 95%
while generating 3,400 gigawatt hours, a 26% increase from the prior year.
Revenues of $350 million in 2006 increased 18% from the prior year while cash
flow from operating activities grew by 5%. Our 2006 results included two
months of operations from the Primary Energy Ventures acquisition and we look
forward to adding full year contributions going forward. Our focus remains on
providing unitholders with stable and sustainable cash distributions by
capitalizing on further earnings enhancements where possible and through plant
expansions and acquisitions of new generating assets in Canada and the U.S."

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

    Cash provided by operating activities was $37.4 million or $0.75 per unit
and $154.4 million or $3.18 per unit respectively for the three and twelve
months ended December 31, 2006 compared with $45.5 million or $0.96 per unit
and $146.7 million or $3.09 per unit for the same periods in 2005. The fourth
quarter decrease in cash provided by operating activities reflects operating
working capital changes which increased by $4.7 million in 2006 compared with
a decrease of $2.6 million for the same period in 2005. The year over year
increase in cash provided by operating activities in total and on a per unit
basis was primarily due to an agreement with the Ontario Electricity Financial
Corporation ("OEFC") on a replacement for the Direct Customer Rate ("DCR")
index that was discontinued in 2002, working capital changes and the third
quarter acquisition of Frederickson Power LP which is partly offset by lower
enhancement and diversion fees at the Ontario plants.
    Net income /(loss) was $(12.9) million or $(0.26) per unit and
$62.1 million or $1.28 per unit respectively for the three and twelve months
ended December 31, 2006 compared to $21.2 million or $0.45 per unit and
$86.5 million or $1.83 per unit for the same periods in 2005. The decrease in
net income for the three and twelve months ended December 31, 2006 compared to
the same prior year periods was primarily due to unrealized foreign exchange
losses on the translation of the Partnership's U.S. dollar denominated debt in
2006 compared with unrealized foreign exchange gains in 2005.
    Cash distributions of $31.4 million or $0.63 per unit were declared for
the fourth quarter of 2006, compared with $29.9 million and $0.63 per unit for
the same period in 2005. The increase in cash distributions reflects the
addition of 2,460,000 Limited Partnership units which were issued in respect
of the Frederickson Power L.P. acquisition in August 2006.

    
    -------------------------------------------------------------------------
    Operational and
    Financial Highlights              Three months ended Twelve months ended
    (unaudited)                              December 31        September 30
    -------------------------------------------------------------------------
    (millions of dollars except
     per unit and operational amounts)    2006      2005      2006      2005
    -------------------------------------------------------------------------
    Power generated (GWh)                1,124       659     3,399     2,698
    -------------------------------------------------------------------------
    Weighted average plant availability     97%       95%       95%       94%
    -------------------------------------------------------------------------
    Revenue                              105.3      81.5     350.2     295.7
    -------------------------------------------------------------------------
    Cash provided by operating
     activities                           37.4      45.5     154.4     146.7
    -------------------------------------------------------------------------
      Per unit (1)                      $ 0.75    $ 0.96    $ 3.18    $ 3.09
    -------------------------------------------------------------------------
    Net income/(loss)                    (12.9)     21.2      62.1      86.5
    -------------------------------------------------------------------------
      Per unit                          $(0.26)   $ 0.45    $ 1.28    $ 1.83
    -------------------------------------------------------------------------
    Cash distributions                    31.4      29.9     124.2     119.5
    -------------------------------------------------------------------------
      Per unit                          $ 0.63    $ 0.63    $ 2.52    $ 2.52
    -------------------------------------------------------------------------
    Capital expenditures                   9.0       9.2      13.2      14.4
    -------------------------------------------------------------------------
    Weighted average units
     outstanding (millions)               49.9      47.4      48.5      47.4
    -------------------------------------------------------------------------
    (1) Cash provided by operating activities per unit is a non-GAAP
        financial measure that is defined in the annual MD&A.
    

    The December 31, 2006 annual report is shown below. The management
discussion and analysis and consolidated financial statements are available on
the EPCOR Power L.P. website (www.epcorpowerlp.ca) and will be available at
SEDAR (www.sedar.com).

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    This management's discussion and analysis ("MD&A") dated March 13, 2007
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, 2006 and 2005. 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 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 including the final form of the proposed tax measures
related to specified investment flow-through entities, 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, 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. The acquisitions in 2006,
as described in the following significant events discussion, provide
additional sources of cash flows which will primarily be used to fund
maintenance capital expenditures and to enhance the stability and
sustainability of cash distributions into the future. Where opportunities
arise, the Partnership will also seek to grow its asset base by expanding
capacity at existing plants and pursuing acquisition opportunities that meet
the Partnership's investment criteria. These criteria include generation
assets that have 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

    2006 acquisitions

    On November 1, 2006, the Partnership acquired a 100% interest in Primary
Energy Ventures LLC ("PEV"). The total consideration paid was $366 million
(US$326 million) in cash plus acquisition costs of approximately $10 million
for a total purchase price of $376 million. In addition, the Partnership
assumed $79 million (US$70 million) of capital lease obligations. PEV's
business is comprised of three principal components:

    
    (i)   PEV owns eight combined heat and power facilities in the United
          States, having an aggregate electric generating capacity of
          approximately 418 megawatts ("MW") and a thermal energy capacity of
          approximately 3 million pounds per hour;

    (ii)  PEV owns 17.0% of the outstanding common interests and 14.2% of the
          outstanding preferred interests in Primary Energy Recycling
          Holdings LLC ("PERH") which owns four energy facilities in the
          United States having an aggregate electric generating capacity of
          approximately 284 MW and a thermal energy capacity of approximately
          2 million pounds per hour and a 50% interest in a pulverized coal
          facility; and

    (iii) PEV provides management and administrative services to PERH,
          certain subsidiaries of PERH and Primary Energy Recycling
          Corporation ("PERC") under a long-term management agreement. PERC
          owns the balance of PERH not owned by PEV.
    

    On August 1, 2006 the Partnership acquired from EPCOR a 100% interest in
Frederickson Power L.P. ("FPLP") for an aggregate purchase price of
$134 million (US$118 million) plus acquisition costs of approximately
$4 million. FPLP owns a 50.15% interest in the Frederickson power facility, a
249 MW (nominal) single unit, natural gas-fired combined cycle generating
facility located in Pierce County, Washington State, U.S.A. In addition, at
the closing of the acquisition, EPCOR granted to the Partnership an option to
acquire a 49% interest in the development rights for a second generating unit
adjacent to the Frederickson facility site. This option was not exercised and
has expired.
    The Partnership now owns a portfolio of 20 power generation assets. The
Partnership's total generating capacity increased to 1,287 MW at the end of
2006 from 744 MW at the end of 2005. The Partnership has added thermal energy
capacity of approximately 3 million pounds per hour. With the addition of
these plants, the Partnership increased the energy supply, counterparty and
geographic diversity of its portfolio of assets.

    Proposed tax measures

    On October 31, 2006, Canada's Minister of Finance proposed tax measures
related to publicly traded income trusts and partnerships. In broad terms,
these measures, when implemented, would result in the application of a tax to
the Partnership similar to that on corporations and would treat a portion of
cash distributions received by unitholders similar to taxable dividends for
tax purposes. Under these measures, the Partnership would be classified as a
specified investment flow-through entity. See the Business Risks section of
this MD&A for further discussion.

    Settlement with Ontario Electricity Financial Corporation

    In 2006 the Partnership reached an agreement with the Ontario Electricity
Financial Corporation ("OEFC") on a replacement for the Direct Customer Rate
("DCR") index that was discontinued in 2002. The OEFC settlement adjusts the
amount owed to the Partnership under the power purchase arrangements ("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 and positively impacted cash provided by operating activities
and net income by $9.8 million. The impact of the settlement on the current
year was approximately $4 million in increased net income. Both the
retroactive and current year amounts are partially offset by accrued fuel
expenses relating to the NAL Resources Ltd. ("NAL") and Devon Canada
Corporation ("Devon") claims as discussed below.

    NAL and Devon Claims

    In July 2004 NAL and Devon, (collectively the "Plaintiffs'") commenced
actions against the Partnership claiming that the gas supply contracts under
which the Plaintiffs sell gas to the Partnership for its Tunis, Ontario power
plant have been frustrated as of January 1, 2003. The frustration claims are
premised on an alleged inability to determine escalations in the commodity
charge for gas under the agreements.
    In March 2006, the Partnership determined that price escalations
respecting power sales from the Tunis plant would appropriately be premised
upon a calculation termed DCR(new) as put forth by one of Ontario Hydro's
successors, the OEFC, and as posted on the OEFC website, with potential for
adjustments and reconciliations as the DCR(new) is updated. One feature of the
DCR(new) is "three year averaging" which has the effect of lengthening the
time over which volatility in the electricity market impacts current prices.
In the second quarter of 2006, the Partnership accrued for potential
additional payments to gas suppliers, including NAL and Devon, based on the
ongoing and publicly available OEFC price escalation information but without
the added feature of three year averaging. As of the end of 2006, the
Partnership has accrued a total of approximately $6 million for potential
additional payments of which $4 million relates to periods prior to 2006.

    Calstock PPA and Fuel Supply

    In July 2006, one of the wood suppliers of the Calstock plant suffered a
fire. The fire shut down the supplier's mill, which is not expected to be back
in production until the second quarter of 2007. Another wood supplier closed
its mill in October 2006. Combined, these two suppliers represented
approximately 40% of the Calstock wood supply. The Partnership has temporarily
replaced a portion of this wood supply with one new supplier and is actively
pursuing long-term replacements for the remaining displaced supply. In
December 2006, the Partnership reached an agreement with the OEFC for the sale
of incremental power from the Calstock plant at market based prices. The
combination of these events is expected to keep 2007 operating margins (see
Non-GAAP measures) of the Calstock plant at levels consistent with those
experienced in 2005 and 2006.

    
    POWER AND STEAM GENERATION                               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 a 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.
    (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 PEV
        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 PPAs with
contract expiry dates ranging from 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                         2006      2005      2004
    -------------------------------------------------------------------------
    (millions of dollars except unit and
     per unit amounts)

    Revenues
      Ontario Plants                               155.7     148.8     136.9
      Williams Lake                                 39.5      36.5      35.9
      Mamquam and Queen Charlotte(2)                15.7      15.4       4.1
      Northwest US Plants (2)                       38.7      26.6      18.4
      California Plants (2)                         20.5         -         -
      Curtis Palmer (2)                             50.9      53.5      31.2
      Northeast US Gas Plants (2)                   28.6      14.9      15.3
      North Carolina Plants (2)                      5.6         -         -
      PERC management and incentive fees (2)         0.6         -         -
      Fair value changes on foreign
       exchange contracts                           (5.6)        -         -
                                                --------- --------- ---------
                                                   350.2     295.7     241.8

    Operating Margin (1)
      Ontario Plants                                82.9      82.8      74.4
      Williams Lake                                 25.5      23.6      23.9
      Mamquam and Queen Charlotte(2)                11.1      10.7       3.4
      Northwest US Plants (2)                       25.9      20.2      13.0
      California Plants (2)                          2.1       -         -
      Curtis Palmer (2)                             45.0      47.1      26.9
      Northeast US Gas Plants (2)                    7.8       8.0       8.2
      North Carolina Plants (2)                     (2.0)        -         -
      PERC management and incentive fees (2)         0.5         -         -
      Fair value changes on foreign
       exchange contracts                           (5.6)        -         -
                                               ---------- --------- ---------
                                                   193.2     192.4     149.8

    Net Income                                      62.1      86.5     100.7
      Per unit                                  $   1.28  $   1.83  $   2.25

    Cash provided by operating activities          154.4     146.7     143.6
      Per unit (1)                              $   3.18  $   3.09  $   3.21

    Capital Expenditures                            13.2      14.4      14.6

    Long Term Debt                                 718.1     436.7     445.2

    Cash Distributions                             124.2     119.5     114.4
      Per unit                                  $   2.52  $   2.52  $   2.52

    Total Assets                                 1,880.6   1,316.3   1,339.7

    Weighted Average Units
     Outstanding (millions)                         48.5      47.4      44.7
    -------------------------------------------------------------------------
    (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 measure".
    (2) From the dates of acquisition: PEV - November 1, 2006; FPLP -
        August 1, 2006; Mamquam and Queen Charlotte - July 23, 2004; Curtis
        Palmer and Manchief - April 20, 2004.
    

    CONSOLIDATED RESULTS

    Revenues of $350.2 million for the year ended December 31, 2006 were
$54.5 million and $108.4 million higher than for 2005 and 2004, respectively.
The increase in 2006 was due to the acquisitions of PEV and FPLP during 2006,
the settlement reached with OEFC for a replacement for the DCR index, the sale
of natural gas at the Castleton plant and an increase of 47 gigawatt hours
("GWh") in electricity production offset by lower enhancement and diversion
sales at the Ontario plants. The plants acquired during 2006 contributed
revenues of $44.5 million in 2006. Revenues at the Castleton plant for the
year ended December 31, 2006 were $8.4 million higher than for 2005 as the
result of sale of natural gas in 2006 to utilize excess gas transmission
capacity. The increase in revenue from 2004 to 2005 was due to the full year
impact of the acquisitions of the Curtis Palmer, Manchief, Mamquam and Queen
Charlotte plants in 2004 as well as higher enhancement and diversion revenues
at the Ontario plants.
    The Partnership reported net income of $62.1 million or $1.28 per unit
for the year ended December 31, 2006 compared with $86.5 million or $1.83 per
unit in 2005 and $100.7 million or $2.25 per unit in 2004. The $24.4 million
decrease in net income from 2005 to 2006 was primarily due to unrealized
foreign exchange losses on translation of the Partnership's U.S. dollar-
denominated debt compared with unrealized foreign exchange gains in 2005. The
decrease in net income from 2004 to 2005 was primarily due to lower unrealized
foreign exchange gains.
    Cash distributions for the year ended December 31, 2006 were 
$124.2 million compared to $119.5 million and $114.4 million in 2005 and 2004,
respectively, reflecting the issue of 2.5 million Partnership units in 2006
and 8.1 million Partnership units in 2004. Cash distributions per unit
remained at $2.52 over the three years.

    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 is as follows:

    
    Years ended December 31 (millions of dollars)   2006      2005      2004
    -------------------------------------------------------------------------
    Operating margin                               193.2     192.4     149.8
    Deduct:
      Depreciation and amortization                 72.2      67.7      55.0
      Management and administration                 11.1       8.9       6.9
      Foreign exchange (gain)/loss                  11.7      (6.4)    (30.8)
      Equity in loss of investment                   1.2         -         -
      Financial charges and other                   29.3      25.7      14.1
    -------------------------------------------------------------------------
      Net income before income tax                  67.7      96.5     104.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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.

    CASH FLOW MEASURE

    In December 2006, the Partnership changed its cash flow measure from cash
available for distributions to cash provided by operating activities. Cash
provided by operating activities is a GAAP defined term and therefore may
provide readers with a more industry comparable cash flow measure than the
previously used cash available for distributions. The Partnership uses cash
provided by operating activities and the dividends from PERH as a measure of
its ability to fund unitholder distributions, maintenance capital expenditures
and debt repayments. Cash provided by operating activities for the year ended
December 31, 2006 was $154.4 million compared to $146.7 million and
$143.6 million in 2005 and 2004 respectively. The increase in 2006 was
primarily due to the settlement with OEFC, changes in working capital and the
acquisition of FPLP which was partly offset by lower enhancement and diversion
revenues at the Ontario plants. Due to seasonal fluctuations, the plants
acquired in the PEV acquisition had a negative impact on cash provided from
operating activities for the two months of ownership.

    
    Years ended December 31 (millions of dollars)   2006      2005      2004
    -------------------------------------------------------------------------
    Cash provided by operating activities          154.4     146.7     143.6
    Cash distributions                             124.2     119.5     114.4
    Additions to property, plant and equipment      13.2      14.4      14.6
    Dividend from PERH                               1.0         -         -


    Revenues and Plant Output

    Years ended December 31                         2006                2005
    -------------------------------------------------------------------------
                                           GWh (millions       GWh (millions
                                                      of                  of
                                                 dollars)            dollars)

    Ontario (2)
      Power                              1,368     134.7     1,321     115.5
      Enhancements                                  12.3                19.9
      Gas Diversions                                 8.7                13.4
                                               ----------           ---------
                                                   155.7               148.8

    Williams Lake
      Firm energy                          445      33.7       441      32.4
      Excess energy/other                  108       5.8       102       4.1
                                    ---------- ---------- --------- ---------
                                           553      39.5       543      36.5

    Mamquam and Queen Charlotte            232      15.7       235      15.4
    Northwest US Plants (3)                456      38.7        83      26.6
    California Plants (3)                  170      20.5         -         -
    Curtis Palmer                          416      50.9       353      53.5
    Northeast US Gas Plants (3)            153      28.6       163      14.9
    North Carolina Plants (3)               51       5.6         -         -
    PERC management and incentive
     fees (3)                                -       0.6         -         -
    Fair value changes on foreign
     exchange contracts                      -      (5.6)        -         -
                                    ---------- ---------- --------- ---------
                                         3,399     350.2     2,698     295.7
                                    ---------- ---------- --------- ---------


    Weighted Average Plant
     Availability (1)
      Ontario                                        98%                 97%
      Williams Lake                                  95%                 94%
      Mamquam and Queen Charlotte                    83%                 76%
      Northwest US Plants (3)                        96%                 93%
      California Plants (3)                          94%                   -
      Curtis Palmer                                  97%                 98%
      Northeast US Gas Plants (3)                    96%                 97%
      North Carolina Plants (3)                      92%                   -
                                               ----------           ---------
    Total weighted average
     availability                                    95%                 94%
                                               ----------           ---------
    Average Price per MWh
      Ontario (2)                                 $   98              $   87
      Williams Lake                               $   71              $   67
      Mamquam and Queen Charlotte                 $   68              $   66
      California Plants (3)                       $  121              $    -
      Curtis Palmer                               $  122              $  152
      North Carolina Plants (3)                   $  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: FPLP - August 1, 2006; PEV -
        November 1, 2006
    

    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. As a result of
increased generation, replacement of the DCR index in 2006 and built-in annual
escalators in these contracts, power revenues of $134.7 million for the year
ended December 31, 2006, were $19.2 million higher than 2005 and the average
price per megawatt hour ("MWh") increased to $98 per MWh in 2006 from $87 per
MWh in 2005. Revenues from enhancement and diversion sales in 2006 decreased
by $12.3 million compared to 2005 due to lower market prices for natural gas.
    Power output from the Ontario plants for the year ended December 31, 2006
was 47 GWh higher year-over-year as more natural gas was available for power
generation due to lower enhancement and diversion sales in 2006. Weighted
average plant availability for the Ontario plants remained strong, increasing
slightly in 2006 to 98% as compared to 97% in 2005.

    Williams Lake

    Revenues at the Williams Lake plant 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 445,000 MWh, 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
401,000 MWh. Cost recovery components are escalated annually for inflation.
For the year ended December 31, 2006, firm energy revenues of $33.7 million
were slightly higher than $32.4 million reported for 2005. The increase in
firm revenues was primarily due to increased energy supply cost recoveries in
2006. Excess energy sales for the year ended December 31, 2006 were
$5.8 million compared with $4.1 million for 2005. Excess energy sales result
when a surplus of energy is generated above the annual firm amount. The
increase in excess energy sales reflected an increase in generation and in the
market- based price (2006 - $54 per MWh; 2005 - $40 per MWh). The market based
price for 2007 is set at $43 per MWh.

    Mamquam and Queen Charlotte

    The Mamquam and Queen Charlotte plants 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 of the electricity generated at the Mamquam plant and
substantially all of the electricity generated at the Queen Charlotte plant is
sold to BC Hydro. A small amount of electricity from the Queen Charlotte plant
is sold to two local industrial customers. These plants contributed 
$15.7 million in revenues during 2006 and $15.4 million in 2005.

    Northwest US Plants

    The Manchief plant has two separate tolling agreements covering the sale
of capacity and incremental energy to Public Service Company of Colorado
("PSCo"). PSCo controls the dispatch of electricity from the Manchief plant,
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. 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. During 2006 the Partnership executed a 10-year
extension on its PPAs with PSCo which previously expired in 2012. The 10-year
extension with substantially similar terms and arrangements to the existing
PPAs, applies to the entire output of the plant under a tolling arrangement.
Under the new terms of the PPA extension, the capacity payments starting in
May 2012 will be approximately 15% lower than the existing PPAs. Revenues were
$26.2 million for the year ending December 31, 2006 compared to $26.6 million
for 2005. The reduction in revenues represented changes in the U.S. dollar
versus the Canadian dollar.
    The Partnership's portion of the capacity of the Frederickson plant has
been sold under tolling arrangements expiring in 2022 to three Washington
State public utility districts (the "PUDs"). The remaining interest in the
Frederickson power facility is held by Puget Sound Energy, Inc. who works
cooperatively with the PUD's to economically dispatch the Frederickson plant.
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 $11.1 million for the five month period from the date of acquisition to
December 31, 2006.
    The Greeley facility 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. During the year, the Greeley facility did
not meet the terms of the PPA that require a rolling six month capacity factor
of 35% be maintained. This could have resulted in the termination of the PPA
or the assumption by PSCo of operation of the Greeley facility (with a
resulting 10% reduction in the capacity payments). At December 31, 2006, the
Greeley facility achieved the six month rolling average requirement which
effectively brought the facility back into compliance under terms of the PPA.
The Greeley facility sells hot water to the University of Northern Colorado
("UNC") pursuant to a Thermal Supply Agreement which expires in August 2013.
Under the agreement, the Greeley facility 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 the Greeley facility were
$1.4 million for the two month period from the date of acquisition to December
31, 2006.

    California Plants

    The three U.S. Naval facilities (the "Naval facilities") sell power to
the San Diego Gas and Electric Company ("SDG&E") under long-term PPAs which
expire in 2019, except for a 4 MW steam turbine at the North Island facility
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 costs ("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 $17.2 million for the two month period from the date of
acquisition to December 31, 2006.
    All the power output from the Oxnard plant is sold to Southern California
Edison Company ("SCE") under a PPA which expires 2020. The price paid under
the PPA includes a capacity payment and an energy payment based on SCE's SRAC.
The steam from the Oxnard facility is used to provide refrigeration services
to Boskovich Farms, a food processing and cold storage facility, thereby
maintaining the Oxnard facility's QF status. Revenues from the Oxnard facility
were $3.3 million for the two month period from the date of acquisition to
December 31, 2006.
    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 the summer peak demand months if
forced outage rates are below 15%.

    Curtis Palmer

    Output from the Curtis Palmer plant is sold to Niagara Mohawk Power
Corporation ("Niagara Mohawk") under a PPA which expires the earlier of 2027
or upon 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%. Thereafter, the price increases
on average by 10% with each additional 1,000 GWh of electricity delivered over
the remaining term of the PPA. The Curtis Palmer plant contributed
$50.9 million in revenues for the year ended December 31, 2006 and
$53.5 million in 2005. The decrease in revenues was primarily due to the step-
down in pricing block that took affect January 2006 offset by increased
generation due to higher water flows in the year. During the first five months
of 2006, the decreased revenue from the price block change was offset by
recognition of previously deferred revenue of $6.8 million.

    Northeast US Gas Plants

    Revenues at the Castleton plant, 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 was down in 2006 compared to 2005 due to reduced dispatch by TCPM. The
PPA with TCPM expires in 2008. The Partnership is currently reviewing options
for this facility once the PPA expires. Revenues of $23.3 million for the year
ended December 31, 2006 were $8.4 million higher than 2005 and included
$9.3 million of natural gas sales in 2006 to utilize excess gas transmission
capacity. The operating margin earned on these natural gas sales was
$0.1 million.
    The Kenilworth facility 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
such cap. Revenues from the Kenilworth plant were $5.3 million for the two
month period from the date of acquisition to December 31, 2006.

    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. The Southport plant sells
steam pursuant to a SPA which expires in December 2014. The Southport SPA
provides for significant increased pricing effective in July 2008 through
2014. The Roxboro plant does not currently have a SPA and is actively looking
for a new steam host. Revenues from the North Carolina plants were
$5.6 million for the two month period from the date of acquisition to December
31, 2006.
    Revenues and operating margins for the North Carolina plants are very
dependent on dispatch rates as a significant component of overall revenue is
from energy payments. Typically the dispatch rates for these plants are
highest during the summer months when regional power demand is high. During
November and December of 2006, the dispatch rates for these plants were lower
than forecast due to unseasonably warm weather in the region and due to
unplanned maintenance at the Southport plant.

    Fair value changes on foreign exchange contracts

    In the second quarter of 2006, the Partnership voluntarily de-designated
certain hedge relationships for accounting purposes on foreign exchange
contracts. The unrealized losses were the result of the change in the fair
value of foreign currency contracts resulting from a strengthening of the U.S
dollar relative to the Canadian dollar during the period from de-designation
to December 31, 2006.

    
    COST OF FUEL

    Years ended December 31                                   2006      2005
    -------------------------------------------------------------------------
    (millions of dollars except average cost per MWh)

    Ontario
      Natural gas (1)                                         55.7      49.9
      Waste heat                                               1.1       1.1
      Wood waste                                               1.1       0.3
                                                          --------- ---------
                                                              57.9      51.3

    Williams Lake - wood waste                                 4.3       3.6

    Northwest US Plants - natural gas (2)                      3.9       0.4

    California Plants - natural gas (2)                       15.3         -

    Northeast US Gas-Fired Plants -
     natural gas (2)                                          15.7       2.3

    North Carolina Plants (2)                                  4.4         -
                                                          --------- ---------
                                                             101.5      57.6
                                                          --------- ---------

    Average cost per MWh
      Ontario (1)                                           $   42    $   39
      Williams Lake                                         $    8    $    7
      California Plants                                     $   90    $    -
      North Carolina Plants                                 $   87    $    -
    -------------------------------------------------------------------------
    (1) Ontario gas costs includes the retroactive portion of the estimated
        settlement of gas escalation dispute with NAL and Devon.
    (2) From the dates of acquisition: FPLP - August 1, 2006; PEV -
        November 1, 2006
    

    Fuel, which is the Partnership's most significant cost of operations,
includes commodity supply and transportation costs. Virtually all the fuel for
the Ontario and Williams Lake plants is supplied under fixed price, long-term
supply agreements with built-in price escalators that generally correspond to
price increases under the related PPAs.
    Fuel costs at the Ontario plants for the year ended December 31, 2006
were $57.9 million compared to $51.3 million in 2005. The increase of
$6.6 million was due to annual price increases in the gas contracts and
$4.1 million relating to the retroactive application of DCR(new) index to the
gas supply agreements at the Tunis and Nipigon plants. Under the fuel supply
agreements for the North Bay and Kapuskasing plants, the natural gas prices
have pre-determined price increases over the 20 year term of the agreements
that average 9% per annum. The increase in price from 2005 to 2006 for these
two plants was approximately 9% with the 2006 to 2007 increase set at 18%.
    The variability in fuel supply costs for the Williams Lake plant has
limited earnings impact as the majority of fuel supply costs related to firm
energy production is recovered through cost recovery mechanisms in the PPA
with BC Hydro.
    Fuel costs at the US Northwest plants increased by $3.5 million to
$3.9 million due to the acquisition of FPLP and Greeley during the year. Fuel
costs at the Frederickson plant were $2.2 million for five months of ownership
for the period ending December 31, 2006 and $1.3 million at Greeley for the
two month period from the date of acquisition to December 31, 2006. Fuel for
the Greeley facility is currently purchased on a month to month basis and the
operating margin of the facility will vary based on changes in the price of
natural gas. Natural gas prices under approximately US $7/million British
thermal unit ("mmbtu") are generally required to generate positive operating
margins, subject to several variables including dispatch rate and maintenance
costs. The Partnership is currently in negotiations with PSCo to amend the PPA
with the objective of reducing the risk associated with natural gas prices. At
Manchief, PSCo is responsible for the gas supply under a tolling agreement.
    Fuel costs at the California plants were $15.3 million for the two month
period from the date of acquisition to December 31, 2006. Fuel for the
California plants is currently purchased on a month to month basis.
Variability in natural gas prices does not have a material impact on the
Partnership under terms of the PPAs and SPAs.
    The US Northeast gas plants incurred fuel costs of $15.7 million for the
year ended December 31, 2006 compared to $2.3 million in the prior year. Fuel
supply costs at the Castleton plant increased by $9.2 million as the result of
sale of natural gas in 2006 to utilize excess gas transmission capacity. The
power buyer at the Castleton facility is responsible for purchasing gas used
for electricity production under a tolling agreement. Fuel costs at the
Kenilworth plants were $4.1 million for the two month period from the date of
acquisition to December 31, 2006. Gas supply costs are capped at the
Kenilworth facility at US$5.50/mmbtu by the power buyer.
    Fuel costs at the North Carolina plants were $4.4 million for the two
month period from the date of acquisition to December 31, 2006. The PPAs for
these plants are structured to substantially pass through fuel commodity risk
to the power buyer. The Partnership does however have an incentive to minimize
its fuel cost relative to its electricity production at these facilities so as
to maximize its dispatch rate. Coal represents approximately 80% of the fuel
used at these facilities with the balance comprised of tire derived fuel and
wood waste. The Partnership has coal supply contracts in place for 2007 and
2008 at fixed prices for the majority of coal that is expected to be used at
these facilities.
    Curtis Palmer, Mamquam and Queen Charlotte, being hydroelectric plants,
do not have fuel costs.

    
    OPERATING AND MAINTENANCE EXPENSE

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Ontario                                                   13.4      13.0
    Williams Lake                                              5.7       5.6
    Mamquam and Queen Charlotte                                1.3       1.2
    Northwest US Plants (1)                                    6.0       3.9
    California Plants (1)                                      2.4         -
    Curtis Palmer                                              1.1       1.2
    Northeast US Gas Plants (1)                                3.6       3.0
    North Carolina Plants (1)                                  2.9         -
    -------------------------------------------------------------------------
                                                              36.4      27.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) From the dates of acquisition: FPLP - August 1, 2006; PEV -
    November 1, 2006.
    

    Operating and maintenance expenses are based on fixed fees 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 acquisition of PEV and FPLP in 2006 was the primary cause
of the $8.5 million year-over-year increase. Additional unplanned maintenance
at the Southport plant of $0.8 million resulted in higher than normal
maintenance for this plant during the two months of ownership.

    
    OTHER PLANT OPERATING EXPENSES

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Property taxes                                            11.2      10.3
    Insurance                                                  4.9       4.5
    Major maintenance                                          3.0       3.0
    -------------------------------------------------------------------------
                                                              19.1      17.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Other plant operating expenses of $19.1 million for the year ended
December 31, 2006 increased by $1.3 million compared to 2005. The increase was
primarily due to the acquisitions of PEV and FPLP in 2006.

    DEPRECIATION AND AMORTIZATION

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Depreciation of property, plant and equipment             46.5      43.2
    Accretion of asset retirement obligations                  1.2       1.0
    Amortization of PPA's                                     24.5      23.5
    Amortization of other assets                               0.5         -
    Amortization of contract liabilities                      (0.5)        -
    -------------------------------------------------------------------------
                                                              72.2      67.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Depreciation and amortization expense for the year ended December 31, 2006
was $72.2 million compared to $67.7 million in 2005. The increase in
depreciation and amortization expense was due to the acquisition of plants in
2006.

    MANAGEMENT AND ADMINISTRATION

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Base fee                                                   1.2       1.2
    Incentive fee                                              2.1       2.0
    Enhancement fee                                            1.1       2.9
    General and administrative costs                           6.7       2.8
    -------------------------------------------------------------------------
                                                              11.1       8.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Management and administration costs consist of fees paid to the Manager
and general and administrative costs. These costs were $11.1 million for the
year ended December 31, 2006 compared to $8.9 million in 2005. Base fees,
which are equal to 1% of the Partnership's annual cash distributions, and
incentive fees, which are based on the level of cash distributions to
unitholders with reference to pre-determined thresholds, increased slightly
reflecting higher aggregate distributions in 2006. Enhancement fees are paid
to the Manager for successfully capturing opportunities, on behalf of the
Partnership, that either increase revenues or reduce costs. In 2006, the
Manager had less opportunity to curtail off-peak power production and sell the
natural gas from the Ontario plants, due to lower market prices for natural
gas, and, as a result, enhancement fees decreased by $1.8 million. General and
administrative costs of $6.7 million were up by $3.9 million compared to 2005
due to higher costs associated with the plants acquired in 2006 and legal and
other professional fees relating to ongoing litigation and evaluation of
potential acquisitions.

    
    FOREIGN EXCHANGE (GAINS)/LOSSES

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Realized foreign exchange (gains) / losses                (0.5)      0.9
    Unrealized foreign exchange losses /
     (gains) on U.S. dollar-denominated debt                  16.9      (7.3)
    Fair value changes on foreign exchange contracts          (4.7)        -
    -------------------------------------------------------------------------
                                                              11.7      (6.4)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Partnership's foreign exchange gains and losses primarily result from
the translation of its U.S. operations. In 2006, the Partnership increased its
U.S. operations and U.S. dollar-denominated borrowings with the acquisitions
of PEV and Frederickson. The realized foreign exchange gain of $0.5 million
for the year end 2006 compared to a loss of $0.9 million in December 31, 2005
resulted from holding net monetary assets during periods when the US dollar
strengthened in 2006. The unrealized foreign exchange losses were
$16.9 million for the year ended December 31, 2006 compared to unrealized
foreign exchange gains of $7.3 million in 2005. This change resulted from the
issuance of U.S. dollar-denominated debt in 2006 and the subsequent
strengthening of the U.S. dollar during the relevant period to
December 31, 2006. The foreign exchange contracts were entered in anticipation
issuance of a Canadian equity financing to replace a portion of the
U.S. dollar bridge acquisition facilities drawn for the PEV acquisition. The
fair value of foreign exchange contracts increased $4.7 million due to the
strengthening of the U.S. dollar.

    
    EQUITY IN LOSSES IN INVESTMENT

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    PERH                                                       1.2         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The equity in losses in investment is from the Partnerships 17.0%
ownership in the common interest in PERH which is accounted for on an equity
basis.
    The Partnership received dividends on its common interest of
$1.0 million, which are included in cash from investing activities, management
fees of $0.6 million from PERC, which are included in revenues, and dividend
income on the Class B preferred interest of $0.3 million, which is included in
financing charges and other below, for the two month period from the date of
acquisition to December 31, 2006.

    
    FINANCIAL CHARGES AND OTHER

    Years ended December 31 (millions of dollars)             2006      2005
    -------------------------------------------------------------------------
    Interest on long-term debt                                27.4      25.3
    Interest on short-term debt                                1.8         -
    Interest on capital lease obligations                      1.2         -
    Dividend income from Class B preferred interests in PERH  (0.3)        -
    Other                                                     (0.8)      0.4
    -------------------------------------------------------------------------
                                                              29.3      25.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Financial charges and other expenses for the year ended December 31, 2006
increased to $29.3 million from $25.7 million in 2005, representing an
increase of $3.6 million as the result of an increase in long and short-term
debt related to the financing of the acquisitions of FPLP and PEV.
    Interest on long-term debt of $27.4 million for the year ended December
31, 2006, compared to $25.3 million in 2005, included interest on the
US$44 million long-term acquisition debt issued in November 2006, interest on
the $149.4 million revolving credit facilities issued during 2006 and slightly
higher interest rates on the $210 million medium-term notes that replaced the
previous $210 million floating rate credit facility. Interest of $1.8 million
on short-term debt for the year ended December 31, 2006 included interest on
the Partnership's operating line and short-term acquisition facilities. Other
financial income of $0.8 million for the year ended December 31, 2006,
compared to other financial charges of $0.4 million in 2005, primarily
consisted of interest income on cash balances and fair value gains on forward
interest rate contracts offset by amortization of deferred debt issue costs.
In November 2006, the Partnership entered into a forward contract to fix U.S.
interest rates in anticipation that it will finance a portion of the PEV
acquisition costs with fixed rate long-term U.S. debt.

    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. The 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. A portion of the cash distributions are taxable to unitholders in the year received. When cash provided by operating activities exceed 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. Cash provided by operating activities of $154.4 million in 2006 and $146.7 million in 2005 exceeded cash distributions and maintenance capital expenditures by $17.0 million in 2006 and $12.8 million in 2005. Years ended December 31 2006 2005 ------------------------------------------------------------------------ Cash provided by operating activities per unit(1) $ 3.18 $ 3.09 Cash distributions per unit(1) $ 2.52 $ 2.52 Taxable amount of cash distributions per unit $ 1.97 $ 1.46 (1) Non-GAAP measures In response to the federal government's proposed tax on publicly traded income trusts and partnerships, the Partnership deferred utilizing elective deductions, including capital cost allowance, for 2006 Canadian income tax purposes. As a result, the taxable amount of cash distributions per unit increased from $1.54, had the Partnership claimed full elective deductions in the year, to the actual amount of $1.97 per unit. The use of elective deductions in 2006 for Canadian income tax purposes would not benefit a tax deferred individual investor whereas the deferral of these elective deductions is expected to benefit all individual investors. The Partnership is also contemplating other changes to its capital structure which may further change the taxable component of its cash distributions in the future. Capital Expenditures Capital expenditures for the power plants are primarily comprised of maintenance capital and additions to, or replacements of, plant equipment required to maintain or increase the power plants' 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, California, Frederickson and Kenilworth 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. 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 years. Similarly, major overhauls are performed at the Castleton and Greeley plants depending on plant usage. Major overhauls for the Manchief plant are expected to be performed approximately every 25,000 equivalent operating hours or approximately every five years. 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, 2006 were $13.2 million and primarily consisted of plant upgrades, reliability and safety controls and maintenance capital at each of the plants. Maintenance capital spending is expected to be slightly higher in 2007 due to the addition of the PEV and FPLP facilities. Financing Activities At December 31, 2006, the Partnership had $718.1 million of long-term debt and $216.3 million of short-term debt outstanding. The long-term debt is comprised of $210.0 million of senior medium term notes due June 2036, $221.4 million (US$190 million) in senior notes due July 2014, a $4.8 million secured term loan due July 2010, a $51.3 million (US$44.0 million) bridge acquisition credit facility due October 2009, $149.4 million drawn on two credit facilities due in 2009 and capital leases of $81.2 million with terms ending in 2019 (2005: $436.7 million comprised of a $210.0 million credit facility due in 2009, a $5.7 million secured term loan due July 2010 and a US$190.0 million senior notes issue due July 2014). The Partnership anticipates replacing a portion of the bridge acquisition financing used for the PEV acquisition with a combination of long-term debt and the issuance of new Partnership units in 2007. The Partnership's debt to total capitalization ratio as at December 31, 2006 increased to 54% from 36% at the end of 2005 due to the acquisition of PEV which has been interim financed with debt. Under terms of its bridge acquisition facility, the Partnership must maintain a debt to capitalization ratio of not more than 60% at the end of each fiscal quarter (65% on all other debt agreements) and a ratio of EBITDA (earnings before interest, income taxes, depreciation and amortization) to interest over the last 12 month period as defined in the respective debt agreements of not less than 2.5 to 1, measured quarterly. The Partnership was compliant with all of its debt covenants under its debt agreements for the years ended December 31, 2006 and 2005. 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 on August 1, 2006, each Subscription Receipt was exchanged for one limited partnership unit. On June 23, 2006, the Partnership completed its first public offering in Canada of senior unsecured medium term notes in the aggregate principal amount of $210.0 million. The net proceeds of the offering were used to repay the Partnership's $210.0 million term loan from a syndicate of banks. On September 22, 2006, the Partnership replaced its existing $50.0 million credit facility with a new $100 million credit facility. The new credit facility is revolving with a three year extendible term committed to September 2009 on substantially the same terms as the prior credit facility. On October 2, 2006, the Partnership arranged an additional $100.0 million credit facility with another Canadian chartered bank. This credit facility has a revolving three-year extendible term committed to October 2009 on substantially the same terms as the other $100 million credit facility. At December 31, 2006 $149.4 million was drawn against these facilities. On November 1, 2006, the Partnership funded a portion of the acquisition of PEV with an aggregate of $257.9 million (US$229.6 million) under two bridge acquisition facilities each with two Canadian chartered banks and $112.3 million (US$100.0 million) on revolving credit facilities. Also, as part of the acquisition of PEV the Partnership assumed $78.9 million of capital lease obligations related to three of PEV's plants. Dominion Bond Rating Service ("DBRS") and Standard & Poor's ("S&P") rate the Partnership's senior note debt as A(low) and A-, respectively and the Partnership's stability ratings of STA-1 (low) and SR-1, respectively. DBRS' A(low) rating designates the Partnership's debt as being of satisfactory credit quality with the protection of interest and principal still substantial. The "A" rating is DBRS' third highest of 10 categories. The A- debt rating by S&P is the third highest rating out of 10 rating categories. The minus sign shows the relative standing within the major rating categories. S&P and DBRS placed Partnership's debt ratings under review with negative implications in August 2006 following the Partnership's announcement of the acquisition of PEV. 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-1 (low) stability rating by DBRS is the 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-1 by S&P is the highest rating of seven categories and indicates the Partnership has the highest level of distributable cash generation stability relative to other rated Canadian income funds. DBRS placed Partnership's stability ratings under review with negative implications in August 2006 following the Partnership's announcement of the acquisition of PEV. S&P placed the Partnership's stability rating under review with negative implications in November 2006 following the federal government announcement that it intends to tax income fund structures. Working capital requirements are expected to remain at levels consistent with December 31, 2006 balances, subject to normal seasonal fluctuations, except for the short-term acquisition facility of $216.3 million. In 2007 the Partnership expects to issue additional Partnership units and fixed rate long- term debt in the U.S. to replace existing PEV acquisition financing. There are no significant liquidity risks associated with the Partnerships financial instruments including its foreign currency and interest rate forward purchases and sales. The Partnership expects that 2007 cash from operating activities will be sufficient to fund cash distributions at existing per unit levels, maintenance capital expenditures and working capital requirements. Over the longer term, the Partnership will need to be successful in negotiating extensions to its existing PPAs and fuel service agreements on similar or more favourable terms as well as acquiring new sources of cash flow to maintain existing cash distributions. If enacted, the federal government's proposed tax on publicly traded income trusts and partnerships will negatively impact the Partnership's cash flow from operating activities on its Canadian source income as early as 2011. The Partnership expects just under 50% of its operating margin in 2007 will be generated from U.S. sources which are not affected by the federal government's proposal. As well, any return of capital, which was $0.55/unit of the $2.52/unit distributed in 2006, would not be subject to the proposed tax. TRANSACTIONS WITH RELATED PARTIES Years ended December 31 2006 2005 ------------------------------------------------------------------------- (millions of dollars except per unit amounts) Transactions with the Manager ----------------------------- Revenues(1) Castleton - capacity payments - 9.8 Ontario - enhancement revenues - 19.9 Ontario - gas diversion sales - 13.4 Ontario - Calstock guarantee fee - 2.1 ------------------------------------------------------------------------- - 45.2 ------------------------------------------------------------------------- Cost of Fuel Ontario - gas fuel supply(1) - 14.9 Ontario - gas transportation(1) - 7.5 Ontario - waste heat(1) - 0.4 Castleton - gas demand charge 2.2 2.3 ------------------------------------------------------------------------- 2.2 25.1 ------------------------------------------------------------------------- Operating and Maintenance Expense 32.0 27.8 ------------------------------------------------------------------------- Management and Administration Base fee 1.2 1.2 Incentive fee 2.1 2.0 Enhancement fee 1.1 2.9 ------------------------------------------------------------------------- 4.4 6.1 ------------------------------------------------------------------------- Acquisition Fees 7.9 - ------------------------------------------------------------------------- Transactions with PERC ---------------------- Revenue Base management fees 0.6 - Incentive fees - - ------------------------------------------------------------------------- 0.6 - ------------------------------------------------------------------------- (1) These transactions were related party transactions only until September 1, 2005 at which time TransCanada sold its interest in the Partnership to EPCOR. In operating the Partnership's 20 power plants, the Partnership and EPCOR (and prior to September 1, 2005, TransCanada) engage in a number of related party transactions. 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, 2006 and 2005 (see Note 15 to the consolidated financial statements for further details). CONTRACTUAL OBLIGATIONS AND CONTINGENCIES At December 31, 2006, the Partnership's future purchase obligations were estimated based on existing contract terms and estimated inflation and expected volumes of waste heat based on historical patterns: Contractual Obligations and Contingencies Years ended December 31 ------------------------------------------------------------------------- Later (millions of dollars) Note 2007 2008 2009 2010 2011 years ------------------------------------------------------------------------- Gas purchase contracts (1) 40.6 45.8 47.9 46.7 51.3 249.4 Gas transportation contracts (2) 13.2 14.0 14.9 15.0 16.0 94.3 Waste heat contracts (3) 0.8 0.8 0.8 0.9 0.9 4.5 Operating and maintenance expense (4) 28.0 28.6 29.1 26.6 27.2 213.3 Long-term debt (5) 14.0 1.1 189.0 1.4 - 431.4 Interest payments on long-term debt (6) 36.7 36.5 27.9 25.6 25.6 338.0 Short term debt (7) 216.3 - - - - - Payments on capital lease obligations (8) 11.2 10.8 10.9 11.8 7.8 59.6 -------------------------------------------- Total 360.8 137.6 320.5 128.0 128.8 1,390.5 ------------------------------------------------------------------------- (1) The gas purchase contracts have fixed and variable components. The variable components are based on estimates subject to variability in plant production. These contracts have expiry dates ranging from 2010 to 2016 with built-in escalators. (2) The gas transportation contracts are based on estimates subject to changes in regulated rates for transportation and have expiry dates ranging from 2010 to 2016. (3) Waste heat contracts continue while the plants are in operation. Prices are escalated yearly by the prior year's CPI. (4) The operating and maintenance contracts are based on fixed fees escalated annually by inflation and have expiry terms ranging from 2008 to 2018. (5) Includes principal repayments under the term debt of $4.8 million in aggregate, the US$44.0 million bridge facility in 2009, the revolving credit facilities in 2009, the US$190.0 million debt in 2014 and the principal repayment on the $210.0 million senior unsecured medium term notes in 2036 (6) Includes interest payments for the term debt of $4.8 million, the US$44.0 million bridge facility and the revolving credit facilities, the US$190.0 million debt, the $210.0 million senior unsecured notes. The year end interest rate has been used to determine the interest charges on the revolving credit facilities. (7) Bridge acquisition facility drawn for PEV acquisition. (8) Capital lease obligations are for the facilities located on Navy bases in California. In July 2004 NAL and Devon commenced actions against the Partnership claiming that the gas supply contracts under which the Plaintiffs sell gas to the Partnership for its Tunis, Ontario power plant have been frustrated as of January 1, 2003. The frustration claims are premised on an alleged inability to determine escalations in the commodity charge for gas under the agreements due to the Ontario government's decision to restructure the Ontario electricity market and the consequent interruption of the former Ontario Hydro's practice of annually determining a DCR. The Plaintiffs additionally seek monetary damages based on referenced spot prices for natural gas deliveries. In March 2006, the Partnership determined that price escalations respecting power sales from the Tunis plant would appropriately be premised upon a calculation termed DCR(new) as put forth by one of Ontario Hydro's successors, the OEFC and as posted on the OEFC website, with potential for adjustments and reconciliations as the DCR(new) is updated. One feature of the DCR(new) is "three year averaging" which has the effect of lengthening the time over which volatility in the electricity market impacts current prices. Utilizing the DCR(new) calculation, the Partnership accrued approximately $2 million for expected additional payments to gas suppliers including NAL and Devon in 2006 and $4 million related to prior periods for potential additional payments to gas suppliers based on the ongoing and publicly available OEFC price escalation information but without the added feature of three year averaging. Discussions toward settlement of the claims have taken place and are expected to continue. Management believes there was no frustration of the contracts and that any amounts claimed above the accrued amounts are without merit. The formula for determining energy pricing at the California plants may be retroactively adjusted by the California Public Utilities Commission ("CPUC"). The Partnership estimates that its maximum exposure would be approximately US$22 million for the three plants located on Navy bases and US$6 million for the Oxnard facility. For the three plants located on Navy bases, any payment made can be recovered from the U.S. Navy under the terms of the steam supply agreements. For the Oxnard facility, the Partnership believes retroactive application of pricing formulas should not be applied as the Partnership has reached a settlement agreement with Southern California Edison (SCE). To the extent that, the Partnership is required to pay any amount for the California plants through November 25, 2008, the previous owner of these facilities is obligated to reimburse the Partnership for 80% of such payments, net of any amounts recovered from third parties. The Partnership has not recorded a liability as it considers an unfavourable outcome to be unlikely. The Partnership has issued letters of credit for $11.6 million (2005 - nil) to meet conditions of certain capital lease agreements. OFF-BALANCE SHEET ARRANGEMENTS At December 31, 2006 the Partnership did not have any off balance sheet arrangements. Up to April 1, 2006 the Partnership elected to apply hedge accounting to the foreign exchange forward 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. 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 judgement. 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 judgement, 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 its estimated remaining useful life. 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 for purposes of measuring asset retirement obligations, to measure impairment, if any, of long-lived assets and goodwill, to determine purchase price allocations and to value derivative financial 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 financial instruments including foreign exchange and interest rate forward contracts are based on quoted market prices. Changes in fair values are recorded in revenue, foreign exchange gains/losses and financial charges and other in the income statement and in derivative financial instrument 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 cumulative 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 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. Long-Term Investments In connection with the acquisition of PEV, the Partnership acquired 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. Foreign Currency Translation The Partnership indirectly owns United States 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 are translated at the exchange rate in effect at the balance sheet date. Non-monetary assets and liabilities 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. FUTURE ACCOUNTING STANDARDS Financial instruments, hedges, and comprehensive income In 2005, the CICA issued four new related accounting standards: Financial Instruments - Recognition and Measurement, Financial Instruments - Disclosure and Presentation, Hedges and Comprehensive Income. These standards apply to the Partnership commencing January 1, 2007 and the significant impacts of the new standards are expected to be as follows. A new statement entitled "Consolidated Statement of Comprehensive Income" will be added to the set of consolidated financial statements. Each component of the statement of comprehensive income will be recorded net of income taxes. These other comprehensive income items will be reclassified to the income statement in the period that the corresponding unrealized foreign exchange gain or loss is realized or the corresponding hedged item of the cash flow hedge affects net income. The cumulative amount of these other comprehensive income components will be called "accumulated other comprehensive income" and included as a new category in partner's equity. 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 standards. Accordingly, revenues and expenses incurred on these contracts will be recorded in the income statement at the contract settlement date. Non-financial derivatives that are not designated as contracts for the purpose of receipt of or delivery of a non-financial item will be fair valued at each balance sheet date, with any corresponding changes in fair value recognized in net income in the period. Loans, receivables and debt will be recorded at amortized cost and amortized using the effective interest rate method. In addition, the cumulative effect of changing the method of amortization of deferred debt issue costs to the effective interest rate method will be recorded in retained earnings as at January 1, 2007. Prior periods' financial statements will not be restated. These changes in accounting standards may result in increased variability in net income. The Partnership is continuing to analyze the impact of adopting these new standards. Financial instrument disclosure and presentation and capital disclosures In December 2006, the CICA issued three new accounting standards that will apply to the Partnership commencing January 1, 2008. They are Financial Instruments - Disclosures, Financial Instruments - Presentation and Capital Disclosures. These standards require increased disclosures with increased emphasis on risks associated with financial instruments The Partnership will adopt these new standards commencing in 2008. International financial reporting standards The CICA plans to move financial reporting for Canadian public companies to International Financial Reporting Standards ("IFRS") over a transition period from 2006 to 2011. The impact on the Partnership's financial statements of transitioning to IFRS cannot yet be determined until detailed convergence plans and recommendations are in place. CONTROLS AND PROCEDURES As of December 31, 2006, 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, 2006, 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, with the exception of those controls that pertain to the PEV business that was acquired in late 2006. Documentation and evaluation of the design of internal control over financial reporting for the PEV business will be finalized in 2007. These evaluations were conducted in accordance with the standards of the Committee of Sponsoring Organizations ("COSO"), a recognized control model, and the requirements of Multilateral Instrument 52-109 of the Canadian Securities Administrators. There were no changes in the Partnership's internal controls over financial reporting that have occurred during the year ended December 31, 2006, other than those that result from the acquisition of the PEV business, 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. These factors, 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 insurance to cover 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. Contract Expiry Risk The Partnership's 20 plants have PPAs that expire between 2008 and 2027 and fuel supply agreements that expire between 2008 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. PPA Contracts 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 thus its QF status which in turn would allow SDG&E to terminate the Naval Facility PPAs, and could result in defaults under the Naval Facility Lease Agreements. 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 biomass wood waste plants, Williams Lake and Calstock, which expose the Partnership to increasing price and supply risk for wood waste as demand increases. At the Williams Lake plant, the cost of delivered wood waste for the firm energy component is flowed through to B.C. Hydro. The pine beetle infestation in the area is not expected to have a detrimental impact on the fuel supply for the plant in the short to medium term. At the Calstock plant, 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 the Calstock plant's fuel supply. The Partnership is actively pursuing long-term replacements for the displaced supply. In December 2006, an Incremental Production agreement was reached with the OEFC to mitigate these costs. It is expected that the revenue from the Incremental Production will allow Calstock to secure wood supplies from further distances. Existing coal supply contracts for the Roxboro facility and Southport facility expire at the end of 2008 and, 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. The commercial environment for North American power generation is very competitive and therefore there is no assurance that the Partnership will be successful in re-contracting its existing plants or acquiring new plants. As discussed earlier, in 2006 the Partnership was successful in negotiating an extension to the Manchief PPA. Commodity Price Risk The risks associated with the uncertainty of the competitive marketplace, especially the volatility in market prices for electricity, have been managed by the fixed-price, long-term power sales contracts in place with investment grade power and steam buyers. In addition, the risks associated with the volatility of market prices for natural gas for the supply of substantially all the natural gas requirements of the Partnership's Canadian 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 the Tunis plant, the Partnership is exposed to commodity price risk on its natural gas purchases beginning in 2010 when its energy supply agreements end prior to the expiry of the OEFC PPA in 2014. Similar exposures exist for shorter periods of time for the Nipigon plant beginning in 2010 and the Kapuskasing and North Bay plants beginning in 2016. Certain natural gas-fired facilities in the U.S. have PPAs extending for terms which extend beyond existing supply contracts. The 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 ability of the Partnership 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. As previously discussed under Contractual Obligations and Contingencies, the Partnership also has commodity risk associated with its Tunis facility if it is unable to successfully defend its position in litigation with NAL and Devon. Electricity prices under the PPAs for the Naval facilities and the Oxnard facility are based on the purchasing utilities' SRAC. The SRAC formula is currently under review by the CPUC and it is unknown how or if the SRAC formula will be adjusted, or when such adjustment might be made. The exact basis on which future electricity prices will be determined for these facilities is therefore unknown at this time. The Partnership's investment in PERH and 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 the cost of coke, coal, natural gas and oil. 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. Proposed Tax Measures On October 31, 2006, the Canadian Minister of Finance ("Finance") announced the "Tax Fairness Plan" which proposed changes to the manner in which certain publicly traded trusts and partnerships ("SIFTs") are taxed. On December 21, 2006, Finance released draft amendments to the Income Tax Act (Canada) (the "Tax Act") to implement these proposed changes (the "2006 Proposed Rules"). The 2006 Proposed Rules generally operate to apply a tax at the limited partnership level on certain income of SIFTs, such as the Partnership, at rates of tax comparable to the combined federal and provincial corporate tax and to re-characterize that income as taxable dividends in the hands of unitholders. The 2006 Proposed Rules indicate that they will apply to SIFTs, the units of which were publicly-traded before November 1, 2006, beginning with the 2011 taxation year of the SIFT. However, Finance indicated in their announcement of the 2006 Proposed Rules that while there was no intention to prevent existing SIFTs from pursuing normal growth prior to 2011, any "undue expansion" could result in an acceleration of the effective date for that SIFT. On December 15, 2006, Finance issued Guidelines on the meaning of "undue expansion" and "normal growth". The Guidelines indicate that no change will be recommended to the 2011 date in respect of any SIFT whose equity capital grows as a result of issuances of new equity before 2011, by an amount that 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 is currently considering the possible impact of the Proposed Rules and appropriate mitigation strategies, however, the Partnership expects that it can issue up to $1,878 million of new equity before 2011 without accelerating the date that it becomes subject to the 2006 Proposed Rules assuming they are enacted in their current form. The 2006 Proposed Rules were not substantively enacted at December 31, 2006, but substantive enactment of the Proposed Rules will require recognition of future income tax amounts based on estimated net taxable temporary differences of $225 million that will reverse after 2010 and for which no tax has been recorded in the Partnership's financial statements for the year ended December 31, 2006. Accordingly, future income tax expense and a net future income tax liability of approximately $71 million are expected to be recognized at the date the 2006 Proposed Rules become substantively enacted. Environment 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. If environmental laws, regulations and guidelines change, the Partnership may incur unforeseen costs of compliance or may be unable to comply with more stringent standards causing the Partnership to close certain facilities. As the Partnership's electricity generation business is a significant emitter of carbon dioxide, it must comply with emerging federal, state and provincial requirements including programs to offset emissions. Canada The greenhouse gas ("GHG") reduction targets embedded in the Kyoto protocol will result in increased Canadian operating costs to the Partnership, but the amounts are uncertain as they will depend on yet to be established policies about how the targets and associated remediation costs are ultimately allocated to industry sectors, emitters and consumers. In October 2006, the federal government announced its intent to pass a Clean Air Act ("CAA") including requirements to reduce GHG emissions. While the requirements under the proposed CAA are not yet known, it is expected that a significant reduction of GHG emissions will be required. 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 the Roxboro and Southport facilities in North Carolina beginning in 2009. Potential CAIR and CAMR compliance strategies are being developed and are expected to be completed by the end of 2007. The Kenilworth facility in New Jersey and the Castleton facility 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 GHGs, 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. 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 owned by TransCanada. 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. In addition, the availability of waste heat gases is also dependent on the compressor stations remaining in use and able to supply the waste heat gases. In 2006, waste heat contributed approximately 20% of power revenue at the Ontario plants. In January 2007, the Partnership was advised that changes to the TransCanada system may reduce the availability of waste heat to the North Bay facility. To date, the Partnership has not received detailed information regarding the expected nature of this change from TransCanada, nor has the Partnership experienced any decrease in waste heat supply. The Partnership continues to work with TransCanada to better understand the potential impact with a goal of mitigating any negative impacts. Qualifying Facility Status Risk Certain U.S. 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 FERC under the U.S. 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. The Roxboro facility's QF status is threatened by the bankruptcy and shut-down of its steam host in 2006 which could impact the future availability of SO(2) allocations needed to off-set future excess emission credit purchase costs. Hydrology 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. Counterparty Credit Risk The Partnership has exposure to credit risk associated with counterparty default under the Partnership's power and steam sales contracts and energy supply agreements and foreign currency hedges. 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. Foreign Exchange and Interest Rate Risk Management The Partnership owns and operates twelve facilities in the U.S. and has borrowings outstanding that are denominated in U.S. dollars and accordingly, the associated net cash flows are subject to foreign currency gains and losses based on changes in the U.S. to Canadian dollar exchange rate. The Partnership manages the foreign exchange risk of its future anticipated U.S. dollar-denominated cash flows from its U.S. plants through the use of forward foreign exchange contracts for periods up to seven years. At December 31, 2006, US$331 million or approximately seventy percent of future net cash flows had been economically hedged for 2007 to 2013 at a weighted average exchange rate of 1.14. The Partnership has entered U.S. dollar foreign exchange contracts in anticipation of an issuance of a Canadian equity financing to replace a portion of the U.S. dollar bridged acquisition facilities drawn for the PEV acquisition. By year, the amounts hedged and average rates are as follows: ------------------------------------------------------------------------- (millions of U.S. dollars except average rate) 2007 2008 2009 2010 2011 2012 2013 ------------------------------------------------------------------------- Forward foreign exchange sales 51.0 48.6 41.1 47.1 52.3 46.9 44.0 Average rate 1.21 1.22 1.12 1.12 1.12 1.09 1.10 Forward foreign exchange purchases 137.9 2.5 Average rate 1.13 1.16 ------------------------------------------------------------------------- PEV Purchase Agreement Terms The agreement pursuant to which the Partnership acquired PEV (the "PEV Purchase Agreement") contains representations, warranties, covenants and indemnities consistent with those that would be used in similar transactions. The ability of the Partnership to seek recourse against the sellers in respect of breaches of representations and warranties regarding PEV and its subsidiaries, including undisclosed liabilities, is limited by provisions of the PEV Purchase Agreement. The majority of the representations and warranties relating to operations will survive for one year from the closing date of the acquisition. In addition, pursuant to the PEV Purchase Agreement, claims by the Partnership based on a breach of representation and warranty for operational matters relating to PEV are generally capped at US$18.8 million. Certain other potential claims relating to power sales arrangements in respect of the Greeley facility are subject to a separate cap of US$5 million. Both such amounts were deposited out of the total purchase price into an escrow account at the closing of the acquisition. Credit Facilities The Partnership will need to refinance its indebtedness under credit facilities outstanding at their maturity dates. The credit facilities 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. 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. Conflict of Interest Risk Conflicts of interest between the Partnership and EPCOR could result in decisions being made which are not in the best interest of the Partnership. 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. PEV, an indirect wholly-owned 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 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 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 and claimants preferred by statute. There is no assurance that risk management steps taken will avoid future loss due to the occurrence of the above described or unforeseen risks. OUTLOOK The Partnership's primary goal is to provide unitholders with stable and sustainable cash distributions. The Partnership will endeavour to accomplish this by an ongoing commitment to operational excellence, capitalizing on further earnings enhancements where possible, as well as through plant expansions and acquisitions of new generating assets in Canada and the U.S. In 2006 the Partnership was successful in executing on a number of initiatives that align with this strategic objective. The PEV and FPLP acquisitions provide greater geographic, fuel and counterparty diversification. They also provide a platform for further U.S. growth. The extension to the Manchief PPA and the agreement for additional power sales from Calstock at market based pricing also align with this strategy. The Partnership is also actively re-negotiating terms under its existing PPAs for Kenilworth and Greeley that will provide improved cash flow stability if successfully completed. In 2007 the Partnership expects to issue additional Partnership units and fixed rate long-term debt in the U.S. to replace existing PEV acquisition financing. The announcement by the federal government on proposed taxation of SIFTs beginning in 2011 has and will continue to impact the Partnership. Partnership unit prices have been adversely affected by the announcement which has increased the cost of capital necessary to finance growth. As a result the Partnership will be re-evaluating its capital structure in 2007 with a view to improve the Partnership's competitive abilities, including the possible use of higher leverage than it employed prior to the PEV acquisition on November 1, 2006. Relative to other power income trust peers, the Partnership believes it is better positioned to respond to the federal government's announcement due to a high proportion of U.S. based income that is not subject to the proposed SIFT taxes, a conservative capital structure that provides flexibility to make necessary competitive changes, the overall size of the Partnership and the long-term stability of its cash flows. Due to the long-term nature of its PPAs and fuel service agreements, the Partnership generates relatively stable cash from operating activities. Changes from 2006 to 2007 in cash provided by operating activities are expected to include: - 2007 will include full year results from the PEV and FPLP acquisitions. - 2007 will include additional financing costs associated with the PEV and FPLP acquisitions. The timing and amount of any equity offering will impact the amount of this increase. - The OEFC settlement in 2006 resulted in a retroactive increase to earnings of $9.8 million that will not re-occur in 2007. - 2006 included historically high water flows on the Hudson River which resulted in above forecast revenue and operating margins at the Curtis Palmer facility. The first quarter of 2007 has also benefited from this trend, although there can no guarantee that this will continue for the balance of 2007. - Natural gas prices at the North Bay and Kapuskasing plants will increase at a rate higher than typical under the 20 year fuel service agreements. These cost increases will be partially offset by revenue increases under the PPAs. There are also a number of other factors that will influence 2007 cash flow from operating activities including natural gas prices, waste heat energy availability, plant operations and water flows. Changes in the value of the U.S. dollar relative to the Canadian dollar can have a material impact on net income but should not have a significant impact on cash from operating activities due to the Partnership's foreign currency hedging program. Maintenance capital spending is expected to be slightly higher in 2007 due to the addition of the PEV and FPLP facilities. The PEV acquisition has also changed the seasonality of Partnership's cash flow and earnings. Historically, operating margins were lowest during the third quarter as revenue for the Ontario plants was calculated using summer PPA rates and hydro-electric production was typically at low levels. By contrast, the third quarter is now expected to be the Partnership's strongest quarter, as the California and North Carolina plants generate the majority of their operating margin during this period. The plants acquired in the PEV acquisition are expected to generate approximately 10% of their 2007 annual operating margin in the first quarter, 30% in the second quarter, 50% in the third quarter and 10% in the fourth quarter. Based on the Partnership's 2007 operating and capital plan and taking into consideration the above noted factors, management estimates that 2007 cash provided by operating activities and PERH dividends will exceed the amounts required to fund cash distributions at existing per unit amounts and maintenance capital spending. 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 6.4 6.4 11.4 14.5 38.7 California Plants - - - 20.5 20.5 Curtis Palmer 16.4 14.1 8.1 12.3 50.9 Northeast US Gas Plants 3.6 6.9 8.3 9.8 28.6 North Carolina Plants - - - 5.6 5.6 PERC management and incentive fees - - - 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 4.8 4.5 7.7 8.9 25.9 California Plants - - - 2.1 2.1 Curtis Palmer 15.0 13.0 6.7 10.3 45.0 Northeast US Gas Plants 1.9 1.8 1.5 2.6 7.8 North Carolina Plants - - - (2.0) (2.0) PERC management and incentive fees - - - 0.5 0.5 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 losses/(gains) 0.7 (9.5) 0.5 20.0 11.7 Equity in losses of investment - - - 1.2 1.2 Financial charges and other 5.9 6.0 6.6 10.8 29.3 ------------------------------------------------ 25.6 15.0 26.9 58.0 125.5 Net income/(loss) before tax 37.8 33.3 11.3 (14.7) 67.7 Income taxes 3.9 3.0 0.5 (1.8) 5.6 ------------------------------------------------ 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 54.3 33.1 29.6 37.4 154.4 Per unit(1) $1.15 $0.70 $0.60 $0.75 $3.18 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 $0.63 per unit special payment on the 2,460,000 Subscription Receipt issued in the FPLP acquisition, paid on August 4, 2006. QUARTERLY INFORMATION Selected Quarterly and Annual Consolidated Financial Data 2005 ------------------------------------------------------------------------- Three months ended Mar. 31 Jun. 30 Sep. 30 Dec. 31 Total ------------------------------------------------------------------------- (millions of dollars except unit and per unit amounts) Revenues Ontario Plants 38.2 32.9 36.0 41.7 148.8 Williams Lake 9.7 8.6 9.9 8.3 36.5 Mamquam and Queen Charlotte 3.4 5.5 2.6 3.9 15.4 Northwest US Plants 6.2 6.5 7.3 6.6 26.6 California Plants - - - - - Curtis Palmer 13.2 14.9 8.1 17.3 53.5 Northeast US Gas Plants 3.8 3.9 3.5 3.7 14.9 North Carolina Plants - - - - - PERC management and incentive fees - - - - - Fair value changes on foreign exchange contracts - - - - - ------------------------------------------------ 74.5 72.3 67.4 81.5 295.7 ------------------------------------------------ Operating Margin(1) Ontario Plants 21.9 16.3 19.8 24.8 82.8 Williams Lake 7.0 4.9 7.5 4.2 23.6 Mamquam/Queen Charlotte 2.7 5.1 1.2 1.7 10.7 Northwest US Plants 4.5 5.1 5.6 5.0 20.2 California Plants - - - - - Curtis Palmer 11.5 13.2 6.5 15.9 47.1 Northeast US Gas Plants 2.0 2.0 2.0 2.0 8.0 North Carolina Plants - - - - - PERC management and incentive fees - - - - - Fair value changes on foreign exchange contracts - - - - - ------------------------------------------------ 49.6 46.6 42.6 53.6 192.4 Other costs Depreciation and amortization 16.5 16.5 16.5 18.2 67.7 Management and administration 1.8 2.2 2.4 2.5 8.9 Foreign exchange losses/(gains) 1.3 2.8 (11.3) 0.8 (6.4) Equity in losses of investment - - - - - Financial charges and other 6.4 6.3 6.2 6.8 25.7 ------------------------------------------------ 26.0 27.8 13.8 28.3 95.9 Net income before tax 23.6 18.8 28.8 25.3 96.5 Income taxes 1.8 3.3 0.8 4.1 10.0 ------------------------------------------------ Net income 21.8 15.5 28.0 21.2 86.5 ------------------------------------------------ Per unit $0.46 $0.33 $0.59 $0.45 $1.83 ------------------------------------------------ Cash provided by operating activities 37.9 37.8 25.5 45.5 146.7 Per unit(1) $0.80 $0.80 $0.54 $0.96 $3.09 Cash Distributions 29.9 29.9 29.9 29.9 119.5 Per unit $0.63 $0.63 $0.63 $0.63 $2.52 Capital Expenditures 0.5 2.6 2.1 9.2 14.4 Weighted Average Units Outstanding (millions) 47.4 47.4 47.4 47.4 47.4 ------------------------------------------------------------------------- (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". Revenues and Plant Output (millions of dollars Three months ended Year ended except GWh) December 31 December 31 ------------------------------------------------------------------------- GWh 2006 GWh 2005 GWh 2006 GWh 2005 ------------------------------------------------------- Ontario(2) - Power 355 35.3 328 30.9 1,368 134.7 1,321 115.5 - Enhancements 3.2 7.9 12.3 19.9 - Gas diversions 1.4 2.9 8.7 13.4 ------ ------ ------ ------ 39.9 41.7 155.7 148.8 Williams Lake - Firm energy 77 6.1 69 5.7 445 33.7 441 32.4 - Excess energy 68 3.6 64 2.6 108 5.8 102 4.1 ------------------------------------------------------- 145 9.7 133 8.3 553 39.5 543 36.5 Mamquam/Queen Charlotte 45 3.3 52 3.9 232 15.7 235 15.4 Northwest US Plants(3) 180 14.5 21 6.6 456 38.7 83 26.6 California Plants(3) 170 20.5 - - 170 20.5 - - Curtis Palmer 114 12.3 123 17.3 416 50.9 353 53.5 Northeast US Gas Plants(3) 64 9.8 2 3.7 153 28.6 163 14.9 North Carolina Plants(3) 51 5.6 - - 51 5.6 - - PERC management and incentive fees(3) - 0.6 - - - 0.6 - - Fair value changes - (10.9) - - - (5.6) - - ------------------------------------------------------- 1,124 105.3 659 81.5 3,399 350.2 2,698 295.7 ------------------------------------------------------------------------- Weighted Average Plant Three months ended Year ended Availability(1) December 31 December 31 2006 2005 2006 2005 ------------------------------------------------------------------------- Ontario Plants 98% 99% 98% 97% Williams Lake 99% 91% 95% 94% Mamquam/Queen Charlotte 80% 69% 83% 76% Northwest US Plants(3) 100% 98% 96% 93% California Plants(3) 94% - 94% - Curtis Palmer 98% 100% 97% 98% Northeast US Gas Plants(3) 99% 100% 96% 97% North Carolina Plants(3) 92% - 92% - Weighted Average Total 97% 95% 95% 94% ------------------------------------------------------------------------- (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: FPLP - August 1, 2006; PEV - November 1, 2006 The Partnership's Selected Quarterly and Annual Consolidated Financial Data, which has been prepared in accordance with GAAP, 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 U.S. 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 on the Partnership's U.S. dollar-denominated long-term debt and fair value changes in forward foreign exchange contracts that are included in revenue. 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, gas prices being equal. Contributions from the Williams Lake plant are usually lower in the fourth quarter once the annual firm energy requirements are met 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. Results for the year ended December 31, 2006 were indicative of these trends. Revenues of $105.3 million for the three months ended December 31, 2006 were $23.8 million higher than revenues in the same periods in 2005 primarily due to the acquisitions of FPLP and PEV offset partly by losses on the change in fair value of foreign exchange contracts and lower production and pricing at the Curtis Palmer facility. The plants acquired during 2006 contributed revenues of $40.1 million in the three months ended December 31, 2006. At Curtis Palmer a cumulative MWh threshold was reached in January 2006, at which point the price for electricity dropped by approximately 33%. Revenue from power sales at the Ontario plants increased by $4.4 million to $35.3 million for the three month period ending December 31, 2006 compared to the same period in 2005 as the result of increased generation and higher selling prices per MWh resulting from the replacement of the Direct Customer Rate index in 2006 and built-in annual escalators in the PPAs. Power output from the Ontario plants for the three months ended December 31, 2006 was 27 GWh higher year-over-year as more natural gas was available for power generation due to lower enhancement and diversion sales in 2006. Revenues from enhancement and diversion sales decreased by $6.2 million for the three months ended December 31, 2006 compared to 2005 due to lower market prices for natural gas. The Partnership reported a net loss of $12.9 million for the three months ended December 31, 2006 compared to net income of $21.2 million for the same period in 2005. The decrease of $34.1 million was primarily due to unrealized foreign exchange losses on translation of the Partnership's U.S. dollar-denominated debt and losses on fair value changes on foreign exchange contracts in 2006. During November and December of 2006, the dispatch rates for the North Carolina plants were lower than expected due to unseasonably warm weather in the region and due to unplanned maintenance at the Southport plant. The Partnership reported cash provided by operating activities of $37.4 million or $0.75 per unit for the three months ended December 31, 2006 compared with $45.5 million or $0.96 per unit for the same period in 2005. The fourth quarter decrease in cash provided by operating activities compared to the prior year period is primarily due changes in operating working capital. In the fourth quarter of 2006, operating working capital increased by $4.7 million, compared to a decrease of $2.6 million in the fourth quarter of 2005. In the third and fourth quarters of 2006, the Partnership acquired Frederickson and PEV, respectively. These acquisitions resulted in increased revenues and operating income. Due to seasonal fluctuations, the plants acquired in the PEV acquisition had a slightly negative impact on cash provided from operating activities for the 2 months of ownership. Significant items which impacted the last eight quarters' net income were as follows: Unrealized foreign exchange gains on U.S. dollar-denominated debt were recorded in quarter three of 2005 and quarter two of 2006. Losses were recorded in the first, second and fourth quarters of 2005 and the first, third and fourth quarters of 2006. The gains and losses are due to fluctuations in the U.S. dollar relative to the Canadian dollar. The fourth quarter of 2005 and the first, second and fourth quarters of 2006 had unseasonably high water flows at the Curtis Palmer facility. Lower pricing for electricity produced at the Curtis Palmer facility started in the first quarter of 2006 when a cumulative MWh threshold was reach. Enhancement and diversion revenues at the Ontario plants increased due to higher natural gas prices in the third and fourth quarters of 2005 and the first quarter of 2006. In the first quarter of 2006, the Partnership reached a settlement with the OEFC on a replacement for the DCR 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 losses in the third and fourth quarters of 2006. A $3.0 million fuel charge was accrued in the first quarter of 2006 for the potential payments to gas suppliers which impacts net income and cash provided by operating activities. In the third and fourth quarters of 2006, the Partnership acquired Frederickson and PEV, respectively. Quarterly and Annual Unit Trading Information (EP.UN on the Toronto Stock Exchange) 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 ------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------- Three months ended (unaudited) Mar. 31 Jun. 30 Sep. 30 Dec. 31 Annual ------------------------------------------------------------------------- Unit Price High $35.90 $37.06 $37.47 $37.00 $37.47 Low $31.60 $33.15 $34.75 $29.41 $29.41 Close $33.60 $36.60 $35.99 $35.25 $35.25 ------------------------------------------------------------------------- Volume traded (millions) 3.5 3.7 3.7 5.4 16.3 ------------------------------------------------------------------------- The announcement of the proposed tax measures related to publicly traded income trusts and partnerships and the uncertainty regarding the nature and timing of permanent financing of the PEV acquisition negatively impacted the Partnership's unit price in the fourth quarter of 2006. ADDITIONAL INFORMATION Additional information relating to EPCOR Power L.P. including the Partnership's Annual Information Form (AIF) and continuous disclosure documents are available on SEDAR at www.sedar.com. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF INCOME Years ended December 31 2006 2005 ----------------------------------------------------- --------- --------- (In millions of dollars except units and per unit amounts) Revenues $ 350.2 $ 295.7 Cost of fuel 101.5 57.6 Operating and maintenance expense 36.4 27.9 Other plant operating expenses 19.1 17.8 --------- --------- 193.2 192.4 Other costs Depreciation and amortization (Note 4) 72.2 67.7 Management and administration 11.1 8.9 Foreign exchange (gains) / losses 11.7 (6.4) Equity in losses of investment 1.2 - Financial charges and other, net (Note 10) 29.3 25.7 --------- --------- 125.5 95.9 --------- --------- Net income before tax 67.7 96.5 Income tax expense (Note 13) 5.6 10.0 --------- --------- Net income $ 62.1 $ 86.5 --------- --------- --------- --------- Net income per unit $ 1.28 $ 1.83 --------- --------- --------- --------- Weighted average units outstanding (millions) 48.5 47.4 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF CASH FLOW Years ended December 31 2006 2005 ----------------------------------------------------- --------- --------- (In millions of dollars) Operating activities Net income $ 62.1 $ 86.5 Items not affecting cash: Depreciation and amortization 72.2 67.7 Future income tax 4.7 5.0 Loss on fair value changes on financial instruments 0.2 - Unrealized foreign exchange (gains)/losses 16.9 (7.3) Other (3.2) 5.4 --------- --------- Funds generated from operations 152.9 157.3 (Increase)/decrease in operating working capital 1.5 (10.6) --------- --------- Cash provided by operating activities 154.4 146.7 --------- --------- Investing activities Acquisition of Primary Energy Ventures LLC, net of cash (Note 3) (359.2) - Acquisition of Frederickson Power L.P. (Note 3) (137.8) - Additions to property, plant and equipment (13.2) (14.4) Dividends received from PERH 1.0 - --------- --------- Cash used in investing activities (509.2) (14.4) --------- --------- Financing activities Distributions paid (122.6) (119.5) Proceeds from short-term debt issued 208.5 - Proceeds from long-term debt issued 415.9 - Long-term debt repaid (223.6) (0.8) Limited partner units issued, net of costs 79.9 - Deferred financing costs (3.5) - --------- --------- Cash provided by financing activities 354.6 (120.3) --------- --------- Increase/(decrease) in cash and cash equivalents (0.2) 12.0 Cash and cash equivalents, beginning of year 32.2 20.2 --------- --------- Cash and cash equivalents, end of year $ 32.0 $ 32.2 --------- --------- --------- --------- Supplementary cash flow information Income taxes paid $ 4.4 $ 2.3 Interest paid $ 28.4 $ 25.2 ----------------------------------------------------- --------- --------- ----------------------------------------------------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED BALANCE SHEETS As at December 31 2006 2005 ----------------------------------------------------- --------- --------- (millions of dollars) ASSETS Current assets Cash and cash equivalents $ 32.0 $ 32.2 Accounts receivable 66.8 46.4 Inventories 15.3 7.2 Prepaids and other 5.9 4.3 Derivative financial instruments asset (Note 12) 9.2 - --------- --------- 129.2 90.1 Property, plant and equipment (Note 4) 1,093.7 873.7 Power purchase arrangements (Note 5) 486.8 347.9 Long-term investments (Note 6) 56.9 - Goodwill 50.1 - Derivative financial instruments asset (Note 12) 6.1 - Other assets (Note 7) 57.8 4.6 --------- --------- $1,880.6 $1,316.3 --------- --------- --------- --------- LIABILITIES AND PARTNERS' EQUITY Current liabilities Short-term debt (Note 9) $ 216.3 $ - Accounts payable 53.5 42.5 Distributions payable 31.4 29.9 Long-term debt due within one year (Note 10) 18.0 0.9 Derivative financial instruments liability (Note 12) 1.0 - --------- --------- 320.2 73.3 Asset retirement obligations (Note 14) 21.7 17.1 Long-term debt (Note 10) 700.1 435.8 Derivative financial instruments liability (Note 12) 15.1 - Contract liabilities (Note 8) 8.3 - Future income taxes (Note 13) 9.8 2.5 Partners' equity (Note 11) 805.4 787.6 Commitments, contingencies and guarantees (Note 19) --------- --------- $1,880.6 $1,316.3 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY Years ended December 31 2006 2005 ----------------------------------------------------- --------- --------- (millions of dollars) Partnership capital, beginning of year $1,015.6 $1,015.6 Issue of Partnership units (Note 11) 79.9 - --------- --------- Partnership capital, end of year $1,095.5 $1,015.6 --------- --------- Accumulated deficit, beginning of year: $ (228.0) $ (195.0) Net income 62.1 86.5 Cash distributions (124.2) (119.5) --------- --------- Accumulated deficit, end of year (290.1) (228.0) --------- --------- Partners' equity $ 805.4 $ 787.6 --------- --------- --------- --------- See accompanying notes to the consolidated financial statements. EPCOR Power L.P. Notes to Consolidated Financial Statements (Tabular amounts in millions of dollars) Years ended December 31, 2006 and 2005 Note 1. DESCRIPTION OF THE PARTNERSHIP EPCOR Power L.P. 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. EPCOR Power L.P. ("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. Accordingly, actual results may differ from estimated amounts as future confirming events occur. For determining potential asset impairments and certain disclosures, the Partnership is required to estimate the fair value of certain assets or obligations. Estimates of fair value are mainly based on discounted cash flow techniques employing estimated future cash flows based on a number of assumptions and using an appropriate discount rate. Financial instruments that do not satisfy the conditions required for hedge accounting are recorded at fair value, which may require the use of estimated future prices. Measurement of the Partnership's asset retirement obligations 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. 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 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 are translated at the exchange rate in effect at the balance sheet date. Non-monetary assets and liabilities 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 the estimated service life of two 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 portion of the purchase price allocated to PPAs is being amortized over the remaining terms of the contracts, which range from three to twenty two years, from the dates of acquisition. Other Intangible Assets Other intangible assets relate primarily to the fair value associated with the Primary Energy Recycling Corp. ("PERC") management and operations agreements and emissions allowances at the facilities located in North Carolina acquired through the Primary Energy Ventures LLC ("PEV") transaction described in Note 3. The portion of the purchase price allocated to other intangible assets is being amortized over the expected useful life of the asset acquired, which range from one to nineteen years, from the date of acquisition. Contract Liabilities In connection with the acquisition of PEV, the Partnership assumed fair value liabilities primarily related to acquired PPAs. The portion of the purchase price allocated to contract liabilities is being amortized over the remaining term of the contracts of three years from the date of acquisition. 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. Investments 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 incurred placement fees and other costs in connection with issuing debt. These amounts are included in other assets and amortized over the term of the related debt. 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 cumulative billable contract price per megawatt hour (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 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 operating expenses. 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 subject to Canadian income taxes and accordingly those taxes which are the responsibility of individual partners have not been reflected in these financial statements. However, certain subsidiary corporations are taxable and applicable income, withholding and capital taxes have been reflected in these consolidated financial statements. 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. ACQUISITIONS Acquisition of Interest in Frederickson Power L.P. On August 1, 2006, the Partnership acquired from EPCOR a 100% interest in Frederickson Power L.P. ("FPLP"). FPLP 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 results of operation of FPLP are included in the Partnerships 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 in PEV. PEV 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 Primary Energy Recycling Holdings LLC ("PERH"). PERH owns four waste heat recovery power facilities and a coal pulverization facility in the United States. In addition, PEV provides management and administrative services to PERH and PERC. PERC owns the balance of PERH not owned by PEV. The total consideration paid was $365.8 million (US$325.7 million) in cash plus acquisition costs of approximately $10.0 million for a total purchase price of $375.8 million. The results of operation of PEV are included in the Partnerships Consolidated Statement of Income from the date of acquisition. The purchase prices for the acquisition of FPLP and PEV respectively were allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows: FPLP PEV Total ------------------------------------------------------------------------- (Preliminary) Current assets excluding cash $ 2.4 $ 26.4 $ 28.8 Property, plant and equipment 111.5 139.7 251.2 Net investment in lease - 35.5 35.5 Power purchase arrangements 25.0 138.4 163.4 Goodwill 11.5 38.6 50.1 Other intangible assets - 17.5 17.5 Investments - 58.9 58.9 Other assets - 0.1 0.1 Future income tax asset, non-current - 8.6 8.6 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 - (8.8) (8.8) Future income tax liability, non-current (10.8) - (10.8) ----------------------------- 137.8 359.2 497.0 Cash and cash equivalents - 16.6 16.6 ----------------------------- Fair value of net assets acquired $ 137.8 $ 375.8 $ 513.6 ----------------------------- ----------------------------- Consideration Cash $ 134.1 $ 365.8 $ 499.9 Acquisition costs 3.7 10.0 13.7 ----------------------------- Due to the short time frame between closing of the PEV transaction and release of the financial statements, the fair value estimates of certain assets and liabilities are preliminary and are anticipated to be finalized during the first quarter of 2007. Finalization of the fair value estimates could result in material adjustments to the fair value purchase price allocation in subsequent periods. The amount allocated to goodwill in the FPLP acquisition is not deductible for income tax purposes. The amount allocated to goodwill in the PEV acquisition is deductible for income tax purposes. Note 4. PROPERTY, PLANT AND EQUIPMENT 2006 2005 ------------------------------------------ ------------------------------ Accum- Accum- ulated ulated Depre- Net Book Depre- Net Book Cost ciation Value Cost ciation Value ------------------------------------------- ----------------------------- Land $ 5.4 $ - $ 5.4 $ 4.7 $ - $ 4.7 Plant and equipment 1,275.6 294.7 980.9 1,082.9 245.5 837.4 Plant and equipment under capital lease 69.2 0.7 68.5 - - - Asset retirement cost 17.5 2.0 15.5 15.8 1.2 14.6 Other equipment 11.7 5.6 6.1 9.2 4.6 4.6 Work in progress 17.3 - 17.3 12.4 - 12.4 ----------------------------- ----------------------------- $1,396.7 $ 303.0 $1,093.7 $1,125.0 $ 251.3 $ 873.7 ----------------------------- ----------------------------- ----------------------------- ----------------------------- Depreciation, amortization, and asset retirement accretion expense is comprised of: 2006 2005 ------------------------------------------------------------ ------------ Depreciation of property, plant and equipment $ 46.5 $ 43.2 Accretion of asset retirement obligations 1.2 1.0 Amortization of PPA's 24.5 23.5 Amortization of other assets 0.5 - Amortization of contract liabilities (0.5) - ------------ ------------ $ 72.2 $ 67.7 ------------ ------------ ------------ ------------ Note 5. POWER PURCHASE ARRANGEMENTS 2006 2005 ------------------------------------------ ------------------------------ Accum- Accum- ulated ulated Amortiz- Net Book Amortiz- Net Book Cost ation Value Cost ation Value ------------------------------------------- ----------------------------- Power purchase arrangements $ 549.2 $ 62.4 $ 486.8 $ 385.8 $ 37.9 $ 347.9 ----------------------------- ----------------------------- ----------------------------- ----------------------------- Note 6. LONG TERM INVESTMENTS In connection with the acquisition of PEV, the Partnership acquired 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. At December 31, 2006, 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 $26.4 million. Note 7. OTHER ASSETS 2006 2005 ------------------------------------------------------------ ------------ Cost Net investment in lease $ 35.1 $ - Other intangible assets 17.5 - Deferred financing costs and other 6.6 5.2 ------------ ------------ 59.2 5.2 ------------ ------------ Accumulated Amortization Other intangible assets 0.5 - Deferred financial costs and other 0.9 0.6 ------------ ------------ 1.4 0.6 ------------ ------------ $ 57.8 $ 4.6 ------------ ------------ ------------ ------------ Net investment in lease The Partnership acquired a power generation facility located in Oxnard, California (the "Oxnard" facility) as part of the acquisition of PEV (Note 3). The PPA under which the Oxnard facility 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. Financing income for the two-month period ended December 31, 2006 of $0.5 million is included in revenues. Note 8. CONTRACT LIABILITIES 2006 2005 ------------------------------------------ ------------------------------ Accum- Accum- ulated ulated Amortiz- Net Book Amortiz- Net Book Cost ation Value Cost ation Value ------------------------------------------- ----------------------------- Contract liabilities $ 8.8 $ 0.5 $ 8.3 $ - $ - $ - ----------------------------- ----------------------------- ----------------------------- ----------------------------- Note 9. SHORT-TERM DEBT Short term debt is comprised of an unsecured, non-revolving $216.3 million (US$185.6 million) bridge acquisition credit facility due on October 27, 2007. At December 31, 2006, the bridge acquisition credit facility had an interest rate of approximately 5.8%. The bridge acquisition credit facility was used for financing the acquisition of PEV. Note 10. LONG-TERM DEBT Interest Interest Rate 2006 Rate 2005 ------------------------------------------------- ----------------------- Senior unsecured medium term notes, due 2036 6.0% $ 210.0 $ - Senior unsecured notes (US$190.0 million), due 2014 5.9% 221.4 5.9% 221.0 Secured term loan, due 2010 11.3% 4.8 11.3% 5.7 Bridge acquisition credit facility (US$44 million) 5.8% 51.3 - Revolving credit facilities 5.6% 149.4 - Credit facility - 3.3% 210.0 Obligations under capital leases (US$69.7) 9.1% 81.2 - ------------------------------------------------- ----------------------- 718.1 436.7 Less: Current portion of long-term debt 18.0 0.9 ------------ ------------ $ 700.1 $ 435.8 ------------ ------------ ------------ ------------ Long Term Debt The senior unsecured medium term 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 net proceeds of the offering were used to repay the Partnership's previous $210.0 million credit facility. The senior unsecured notes due in 2014 are the obligation of Curtis Palmer Inc., an indirect wholly-owned subsidiary of the Partnership. The notes are fully and unconditionally guaranteed as to payment of principal, premium, if any, and interest on a senior unsecured basis by the Partnership. The notes mature in July 2014. Interest on the notes accrues at 5.9% per annum and is payable semi-annually in January and July. 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 11.3% and matures on July 15, 2010. The bridge acquisition credit facility is unsecured and non-revolving and is due on October 27, 2009. At December 31, 2006, the bridge acquisition credit facility had an interest rate of approximately 5.8%. The bridge acquisition credit facility was used for financing the acquisition of PEV. Under the terms of the revolving credit facilities, the Partnership can obtain advances by way of prime loans, US Base Rate loans, LIBOR loans and Bankers' Acceptances. At December 31, 2006, the revolving credit facilities had an average interest rate of approximately 5.6%. There are two $100.0 million revolving credit facilities with three year terms maturing in September 2009 and October 2009, subject to extension. At December 31, 2006, $13.0 million and $136.4 million (US$117.0 million) was drawn against these facilities. The Partnership's revolving credit facilities may be used for general partnership purposes including working capital support. Capital Lease Obligations The capital lease obligations relate to three facilities located on US Naval bases in California. The leases bear interest at 9.1% and are repaid over a term ending in 2020. 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 ------------------------------------------------------------------------- 2007 $ 14.0 2008 1.1 2009 189.0 2010 1.4 2011 - Later Years 431.4 ------------ Total Payments $ 636.9 ------------ ------------ Minimum Lease Payments Future minimum lease payments under capital leases by year and in aggregate are as follows: ------------ 2007 $ 11.2 2008 10.8 2009 10.9 2010 11.8 2011 7.8 Later years 59.6 ------------ Total minimum lease payments 112.1 Less: amount representing interest at 9.1% (30.9) ------------ Present value of net minimum lease payments 81.2 Less: current portion of capital lease obligation (4.0) ------------ Capital lease obligation net of current portion $ 77.2 ------------ ------------ Financial Charges and Other 2006 2005 ------------------------------------------------------------ ------------ Interest on long-term debt $ 27.4 $ 25.3 Interest on short-term debt 1.8 - Interest on capital lease obligations 1.2 - Dividend income from Class B preferred interests in PERH (0.3) - Other (0.8) 0.4 ------------ ------------ $ 29.3 $ 25.7 ------------ ------------ ------------ ------------ Note 11. PARTNERS' EQUITY 2006 2005 ------------------------------------------------- ----------------------- Number Millions Number Millions of Units of Dollars of Units of Dollars ------------------------------------------------- ----------------------- Partnership capital, beginning of year 47,421,982 $ 1,015.6 47,421,982 $ 1,015.6 Issue of Partnership units 2,460,000 79.9 - - ----------------------- ----------------------- Partnership capital, end of year 49,881,982 $ 1,095.5 47,421,982 $ 1,015.6 ----------------------- ----------------------- ----------------------- ----------------------- 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 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 April of 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 FPLP acquisition. Upon closing of the acquisition, each subscription receipt was exchanged for one limited partnership unit. In 2006, the weighted average number of units outstanding was 48,453,160 (2005 - 47,421,982). Note 12. FINANCIAL INSTRUMENTS Fair Values of Financial Instruments The carrying value of the current financial assets and liabilities recognized in the Consolidated Balance Sheets of the Partnership approximate their fair value due to their short period to maturity. The following table summarizes estimated fair value information about the Partnership's financial instruments recognized in the Consolidated Balance Sheets that do not approximate fair value. 2006 2005 ------------------------------------------------- ----------------------- Carrying Carrying Amount Fair Value Amount Fair Value ----------------------- ----------------------- Senior unsecured medium term notes $ 210.0 $ 216.0 $ - $ - Unsecured senior notes (US$190.0 million) 221.4 228.6 221.0 227.2 Secured term loan 4.8 5.5 5.7 6.7 ------------------------------------------------- ----------------------- The estimated fair values of recognized financial instruments have been determined based on the Partnership's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The fair values of all other financial assets and financial liabilities, including capital lease obligations, are not materially different from their carrying values. Fair value of off-balance sheet interest rate hedges 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, 2006, the Partnership did not have any off balance sheet interest rate swaps contracts or interest rate cap contracts. Derivative financial instruments The Partnership has a hedging program to manage its exposure to changes in foreign currency exchange rates that result from future anticipated U.S. dollar-denominated cash flows from its U.S. 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 income in the same periods that the related previously hedged U.S. revenue occurs. As the hedged item is still considered highly probable to occur, the previously deferred unrealized gains on the hedging of U.S. dollar- denominated cash flows are deferred and carried forward for subsequent recognition in earnings as or when the hedged item occurs. The unamortized portion of the deferred unrealized gains was $8.6 million at December 31, 2006. Changes in the fair value of these foreign exchange contracts from April 1, 2006 forward are recorded in the revenue of the U.S. plants. Credit Risk The electricity and steam generated at the Partnership's facilities is sold under long-term contracts to sixteen customers. Customers accounting for more that 10% of the Partnership's revenue in 2006 were as follows: 2006 2005 ------------------------------------------------------------ ------------ Ontario Electricity Financial Corporation 39% 50% British Columbia Hydro and Power Authority 16% 18% Niagara Mohawk Power Corporation 15% 18% ------------ ------------ ------------ ------------ Note 13. INCOME TAXES The provision for income taxes in the consolidated financial statements differs from the result which would have been obtained by applying the combined Canadian federal and provincial tax rate to the Partnership's income before taxes. The difference results from the following: Reconciliation of Income Tax Expense 2006 2005 ------------------------------------------------------------ ------------ Income before taxes $ 67.7 $ 96.5 Combined federal and provincial tax rate 34.1% 34.1% ------------ ------------ Expected income tax expense 23.1 32.9 Income allocated to Partnership unitholders (27.3) (24.9) Non-taxable amounts (1.4) - Amounts related to non-deductible (non-taxable) foreign exchange 8.3 (0.5) Withholding taxes 0.6 1.6 Higher effective foreign tax rates 1.4 1.4 Other 0.9 (0.5) ------------ ------------ Actual income tax expense $ 5.6 $ 10.0 ------------ ------------ ------------ ------------ Future Income Tax Asset 2006 2005 ------------------------------------------------------------ ------------ Non-capital loss carryforwards $ 8.6 $ - Asset retirement obligation 0.3 - Accrued interest 2.5 - Other 1.0 2.4 ------------ ------------ Future income tax assets $ 12.4 $ 2.4 ------------ ------------ ------------ ------------ Future Income Tax Liability 2006 2005 ------------------------------------------------------------ ------------ Difference in accounting and tax basis of plant, equipment and PPAs $ 20.4 $ 4.4 Undistributed foreign earnings 1.3 - Other 0.5 0.5 ------------ ------------ Future income tax liability $ 22.2 $ 4.9 ------------ ------------ ------------ ------------ Net Future Income Tax Liability $ (9.8) $ (2.5) ------------ ------------ ------------ ------------ Canadian based corporate subsidiaries of the Partnership are subject to tax on their taxable income at a rate of approximately 34% (2005 - 34%) while US corporate subsidiaries are subject to tax on their taxable income at rates varying from 34 to 41% (2005 - 38 to 41%). The tax effects of temporary differences relating to corporate subsidiaries have been reflected in these consolidated financial statements with the exception of $2.7 million (2005 - $1.0 million) of non-capital losses in subsidiaries which the Partnership does not believe will be utilized prior to their expiration. Taxable income of the Partnership and its subsidiary limited partnerships will be taxed in the hands of unitholders. The Partnership and its Canadian subsidiary limited partnerships have net taxable temporary differences of $339.5 million (2005 - $366.0 million) which are not reflected in these financial statements. Net Operating Loss Carry Forwards At December 31, 2006, net operating losses of US$21.8 million are available for U.S. income tax purposes that can be carried forward to reduce future U.S. taxable income. Of these losses, US$21.6 million expire between 2022 and 2024, with the balance expiring thereafter. The losses 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 losses is limited to an annual amount equal to US$4.7 million. Therefore, such limitation could have the effect of increasing the Partnership's tax liability and reducing the available cash resources of the Partnership in the future. Tax on Flow-Through Entities On October 31, 2006, the Minister of Finance (Canada) ("Finance") announced the "Tax Fairness Plan" which proposed changes (the "2006 Proposed Rules") to the manner in which certain publicly traded trusts and partnerships ("SIFT's") are taxed. On December 21, 2006, Finance released draft amendments to the Income Tax Act (Canada) (the "Tax Act") to implement the 2006 Proposed Rules. The 2006 Proposed Rules generally operate to apply a tax at the limited partnership level on certain income of SIFT's, like the Partnership, at rates of tax comparable to the combined federal and provincial corporate tax and to re-characterize that income as taxable dividends in the hands of Unitholders. The 2006 Proposed Rules indicate that they will apply to SIFT's, the units of which were publicly-traded before November 1, 2006, beginning with the 2011 taxation year of the SIFT. However, Finance indicated in their announcement of the 2006 Proposed Rules that while there was no intention to prevent existing SIFT's from pursuing normal growth prior to 2011, any "undue expansion" could result in an acceleration of the effective date for that SIFT. On December 15, 2006, Finance issued Guidelines on the meaning of "undue expansion" and "normal growth". The Guidelines indicate that no change will be recommended to the 2011 date in respect of any SIFT whose equity capital grows as a result of issuances of new equity before 2011, by an amount that does not exceed an objective "safe harbour" amount based on a percentage of the SIFT's market capitalization as of the end of trading on October 31, 2006. The Proposed Rules were not substantively enacted at December 31, 2006, but substantive enactment of the Proposed Rules will require recognition of future income tax amounts based on estimated net taxable temporary differences of $225.0 million that will reverse after 2010 and for which no tax has been recorded in these statements in respect of. Accordingly, future income tax expense and a net future income tax liability of approximately $71.0 million are expected to be recognized at the date the Proposed Rules become substantively enacted. Note 14. ASSET RETIREMENT OBLIGATIONS 2006 2005 ------------------------------------------------------------ ------------ Asset retirement obligations, beginning of year $ 17.1 $ 16.0 Assumption of Frederickson and PEV obligations (Note 3) 1.8 - Liabilities incurred 1.4 0.2 Accretion of asset retirement obligations 1.2 0.9 Impact of changes in foreign exchange rates 0.2 - ------------ ------------ Asset retirement obligations, end of period $ 21.7 $ 17.1 ------------ ------------ ------------ ------------ At December 31, 2006, the estimated cost to settle the Partnership's asset retirement obligations was $139.6 million (2005 - $65.0 million) calculated using an inflation rate of 3.0% per annum (2005 - 3.0%). The estimated cash flows were discounted at rates ranging from 6.4% to 6.7% (2005 - 6.6%). At December 31, 2006, the expected timing of payment for settlement of the obligations ranges from three to eighty four years. Note 15. RELATED PARTY TRANSACTIONS EPCOR Amounts charged to the Partnership under contracts with EPCOR (or TransCanada Corporation for the applicable periods) were as follows: 2006 2005 ------------------------------------------------------------ ------------ Revenues(1) Castleton - capacity payments $ - $ 9.8 Ontario - enhancement revenues - 19.9 Ontario - gas diversion sales - 13.4 Ontario - Calstock guarantee fee - 2.1 ------------ ------------ $ - $ 45.2 ------------ ------------ Cost of Fuel Ontario - gas fuel supply(1) $ - $ 14.9 Ontario - gas transportation(1) - 7.5 Ontario - waste heat(1) - 0.4 Castleton - gas demand charge 2.2 2.3 ------------ ------------ $ 2.2 $ 25.1 ------------ ------------ Operating and Maintenance Expense $ 32.0 $ 27.8 ------------ ------------ Management and Administration Base fee $ 1.2 $ 1.2 Incentive fee 2.1 2.0 Enhancement fee 1.1 2.9 ------------ ------------ $ 4.4 $ 6.1 ------------ ------------ Acquisition Fees $ 7.9 $ - ------------ ------------ (1) These transactions were related party transactions up until September 1, 2005 at which time TransCanada sold its interest in the Partnership to EPCOR. Enhancement Transactions Gas sales are included in revenue related to enhancement transactions undertaken by EPCOR at the Ontario power plants to 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 for each enhancement transaction equivalent to 35% of the incremental profit. Gas Diversion Sales EPCOR manages gas fuel supply on behalf of the Partnership and fuel in excess of daily plant requirements is sold on the open market through EPCOR and is recorded as gas diversion sales. 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 PEV facilities on a cost recovery basis. Base and Incentive Fee EPCOR is also entitled to a base fee and an incentive fee under 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. Included in accounts payable at December 31, 2006 are amounts owing to EPCOR of $5.5 million (2005 - $10.9 million). PERC Amounts earned by the Partnership under contracts with PERC were as follows: 2006 2005 ------------------------------------------------------------ ------------ Revenue Base management fees $ 0.6 $ - Incentive fees - - ------------ ------------ $ 0.6 $ - ------------ ------------ ------------ ------------ PERC Base Management Fees and Incentive Fees The Partnership receives base management fees and incentive fees for management of PERC under a long term management agreement. The base fee is an escalated annual amount. The incentive fee is equal to 25% of all distributable cash flow which exceeds $1.10 per enhanced income security unit. Included in accounts receivable at December 31, 2006 are amounts owing from PERC of $0.3 million (2005 - nil). Note 16. 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, 2006, the carrying value of the property, plant and equipment of these facilities was $301.4 million less accumulated depreciation of $18.1 million (2005 - $233.1 million and $10.7 million respectively). The Partnership's revenues for the year ended December 31, 2006 include $53.3 million with respect to the PPA's for these plants (2005 - $41.1 million). Note 17. U.S. OPERATIONS For the year ended December 31, 2006, the Partnership's U.S. operations generated approximately $140.4 million of revenue (2005 - $91.5 million). At December 31, 2006 the net book value of U.S. plant, property and equipment, PPAs, other intangible assets and goodwill was $1,025.6 million (December 31, 2005 - $553.8 million). Note 18. JOINT VENTURE A financial summary of the Partnership's investments in the Frederickson joint venture as at December 31, 2006 and 2005 on a proportionately consolidated basis is as follows: 2006 2005 ------------------------------------------------------------ ------------ Current Assets $ 2.6 $ - Long-term assets 145.8 - Current liabilities 0.7 - Long term liabilities 0.4 - Revenues 10.8 - Expenses 6.7 - Net Income 4.1 - Cash flows from operating activities 5.8 - Cash flows from (used in) investing activities (0.1) - Cash flows (used in) from financing activities (5.7) - ------------------------------------------------------------ ------------ Note 19. COMMITMENTS, CONTINGENCIES AND GUARANTEES Operating Commitments The Ontario plants are under fixed long-term gas supply contracts, gas transportation contracts and waste heat supply contracts with built-in annual escalators. Expiry dates for the contracts vary in length with an average remaining contract life of eight years as at December 31, 2006. The remaining fuel requirements, which account for approximately 5% of the power plants' fuel costs, are purchased at current market prices. As of December 31, 2006 the Partnership's future purchase obligations were estimated as follows, based on existing contract terms, estimated inflation and expected volumes of waste heat based on historical patterns. Gas Transpor- Waste Heat Gas Supply tation Supply Contracts Contracts Contracts ------------------------------------------------------------------------- 2007 $ 40.6 $ 13.2 $ 0.8 2008 45.8 14.0 0.9 2009 47.9 14.9 0.9 2010 46.7 15.0 0.9 2011 51.3 16.0 0.9 Later Years 249.4 94.3 4.5 ----------------------------------- Total Payments $ 481.7 $ 167.4 $ 8.9 ----------------------------------- ----------------------------------- Contingencies (a) In July, 2004 NAL Resources Limited ("NAL") and Devon Canada Corporation ("Devon"), (collectively the "Plaintiffs") commenced actions against the Partnership claiming that the gas supply contracts under which the Plaintiffs sell gas to the Partnership for its Tunis, Ontario power plant have been frustrated as of January 1, 2003. The frustration claims are premised on an alleged inability to determine escalations in the commodity charge for gas under the agreements due to the Ontario government's decision to restructure the Ontario electricity market and the consequent interruption of the former Ontario Hydro's practice of annually determining a "Direct Customer Rate" (DCR). The Plaintiffs additionally seek monetary damages based on referenced spot prices for natural gas deliveries. In March 2006, the Partnership determined that price escalations respecting power sales from the Tunis plant would appropriately be premised upon a calculation termed DCR(new) as put forth by one of Ontario Hydro's successors, the Ontario Electricity Financial Corporation ("OEFC") and as posted on the OEFC website, with potential for adjustments and reconciliations as the DCR(new) is updated. One feature of the DCR(new) is "three year averaging" which has the effect of lengthening the time over which volatility in the electricity market impacts current prices. Utilizing the DCR(new) calculation, the Partnership accrued approximately $2 million for expected additional payments to gas suppliers including NAL and Devon in 2006 and $4 million related to prior periods for potential additional payments to gas suppliers based on the ongoing and publicly available OEFC price escalation information but without the added feature of 3 year averaging. Discussions toward settlement of the claims have taken place and are expected to continue. Management believes there was no frustration of the contracts and that any amounts claimed above the accrued amounts are without merit. (b) The formula for determining energy pricing at the California plants may be retroactively adjusted by the California Public Utilities Commission ("CPUC"). The Partnership estimates that its maximum exposure would be approximately US$22 million for the three plants located on Navy bases and US$6 million for the Oxnard facility. For the three plants located on Naval bases, any payment made can be recovered from the U.S. Navy under the terms of the steam supply agreements. For the Oxnard facility the Partnership believes retroactive application of pricing formulas should not be applied as the Partnership has reached a settlement agreement with Southern California Edison ("SCE"). To the extent that, the Partnership is required to pay any amount for the California plants through November 25, 2008, the previous owner of these facilities is obligated to reimburse the Partnership for 80% of such payments, net of any amounts recovered from third parties. The Partnership has not recorded a liability as it deems an unfavourable outcome unlikely. Guarantees The Partnership has issued letters of credit for $11.6 million (2005 - nil) to meet conditions of certain capital lease agreements. Other The U.S. Navy may terminate the power sales agreements at the Partnership's facilities located on Naval bases for convenience 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 20. 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: Jay Shukin, (250) 882-5188; 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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